Document
CANADIAN NATURAL RESOURCES LIMITED
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MANAGEMENT'S DISCUSSION & ANALYSIS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2023 |
| NOVEMBER 1, 2023 |
MANAGEMENT'S DISCUSSION AND ANALYSIS
ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby thermal oil sands project, the Jackfish thermal oil sands project and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil production, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, continuing effects of the novel coronavirus ("COVID-19") pandemic, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack and other cyber-related crime; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; and other
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| Canadian Natural Resources Limited | 1 | Three and nine months ended September 30, 2023 |
circumstances affecting revenues and expenses. The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.
Special Note Regarding Non-GAAP and Other Financial Measures
This MD&A includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position or cash flow. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided in the "Non-GAAP and Other Financial Measures" section of this MD&A.
Special Note Regarding Currency, Financial Information and Production
This MD&A should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three and nine months ended September 30, 2023, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2022. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three and nine months ended September 30, 2023 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").
Production volumes and per unit statistics are presented throughout this MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.
The following discussion and analysis refers primarily to the Company's financial results for the three and nine months ended September 30, 2023 in relation to the comparable periods in 2022 and the second quarter of 2023. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2022, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated November 1, 2023.
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| Canadian Natural Resources Limited | 2 | Three and nine months ended September 30, 2023 |
FINANCIAL HIGHLIGHTS
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| | | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per common share amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Product sales (1) | | $ | 11,762 | | | $ | 8,846 | | | $ | 12,574 | | | | $ | 30,156 | | | $ | 38,518 | |
| Crude oil and NGLs | | $ | 10,944 | | | $ | 8,115 | | | $ | 11,001 | | | | $ | 27,471 | | | $ | 33,501 | |
| Natural gas | | | $ | 599 | | | $ | 522 | | | $ | 1,342 | | | | $ | 1,972 | | | $ | 3,949 | |
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| Net earnings | | $ | 2,344 | | | $ | 1,463 | | | $ | 2,814 | | | | $ | 5,606 | | | $ | 9,417 | |
| Per common share | – basic | | $ | 2.15 | | | $ | 1.34 | | | $ | 2.52 | | | | $ | 5.12 | | | $ | 8.23 | |
| | – diluted | | $ | 2.13 | | | $ | 1.32 | | | $ | 2.49 | | | | $ | 5.07 | | | $ | 8.12 | |
Adjusted net earnings from operations (2) | | $ | 2,850 | | | $ | 1,256 | | | $ | 3,493 | | | | $ | 5,987 | | | $ | 10,669 | |
| Per common share | – basic (3) | | $ | 2.61 | | | $ | 1.15 | | | $ | 3.12 | | | | $ | 5.47 | | | $ | 9.32 | |
| | – diluted (3) | | $ | 2.59 | | | $ | 1.14 | | | $ | 3.09 | | | | $ | 5.41 | | | $ | 9.20 | |
| Cash flows from operating activities | | $ | 3,498 | | | $ | 2,745 | | | $ | 6,098 | | | | $ | 7,538 | | | $ | 14,847 | |
Adjusted funds flow (2) | | $ | 4,684 | | | $ | 2,742 | | | $ | 5,208 | | | | $ | 10,855 | | | $ | 15,615 | |
| Per common share | – basic (3) | | $ | 4.30 | | | $ | 2.50 | | | $ | 4.66 | | | | $ | 9.91 | | | $ | 13.64 | |
| | – diluted (3) | | $ | 4.26 | | | $ | 2.48 | | | $ | 4.60 | | | | $ | 9.81 | | | $ | 13.47 | |
| Cash flows used in investing activities | | $ | 1,199 | | | $ | 1,560 | | | $ | 1,129 | | | | $ | 3,912 | | | $ | 3,725 | |
Net capital expenditures (2) | | $ | 1,231 | | | $ | 1,669 | | | $ | 1,249 | | | | $ | 4,294 | | | $ | 4,154 | |
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(1)Further details related to product sales are disclosed in note 17 to the financial statements.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
SUMMARY OF FINANCIAL HIGHLIGHTS
Consolidated Net Earnings and Adjusted Net Earnings from Operations
Net earnings for the nine months ended September 30, 2023 were $5,606 million compared with $9,417 million for the nine months ended September 30, 2022. Net earnings for the nine months ended September 30, 2023 included non-operating losses, net of tax, of $381 million compared with non-operating losses of $1,252 million for the nine months ended September 30, 2022 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on the settlement of the cross currency swap, the gain from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2023 were $5,987 million compared with $10,669 million for the nine months ended September 30, 2022.
Net earnings for the third quarter of 2023 were $2,344 million compared with $2,814 million for the third quarter of 2022 and $1,463 million for the second quarter of 2023. Net earnings for the third quarter of 2023 included non-operating losses, net of tax, of $506 million compared with non-operating losses of $679 million for the third quarter of 2022 and non-operating income of $207 million for the second quarter of 2023 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the third quarter of 2023 were $2,850 million compared with $3,493 million for the third quarter of 2022 and $1,256 million for the second quarter of 2023.
The decrease in net earnings and adjusted net earnings from operations for the nine months ended September 30, 2023 from the nine months ended September 30, 2022 primarily reflected:
▪lower realized crude oil and NGLs pricing (1) in the North America segment;
▪lower realized SCO sales pricing (1) in the Oil Sands Mining and Upgrading segment; and
▪lower realized natural gas pricing in the Exploration and Production segments;
partially offset by:
▪higher crude oil and NGLs sales volumes in the North America segment; and
▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
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| Canadian Natural Resources Limited | 3 | Three and nine months ended September 30, 2023 |
The decrease in net earnings and adjusted net earnings from operations for the third quarter of 2023 from the third quarter of 2022 primarily reflected:
▪lower realized natural gas pricing in the North America segment; and
▪lower realized SCO sales pricing in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪higher crude oil and NGLs sales volumes and netbacks in the North America segment.
The increase in net earnings and adjusted net earnings from operations for the third quarter of 2023 from the second quarter of 2023 primarily reflected:
▪higher SCO sales volumes and realized SCO sales pricing in the Oil Sands Mining and Upgrading segment;
▪higher crude oil and NGLs sales volumes and netbacks in the North America segment; and
▪higher natural gas sales volumes and realized natural gas pricing in the North America segment.
The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, and the gain from investments, also contributed to the movements in net earnings. These items are discussed in detail in the relevant sections of this MD&A.
Cash Flows from Operating Activities and Adjusted Funds Flow
Cash flows from operating activities for the nine months ended September 30, 2023 were $7,538 million compared with $14,847 million for the nine months ended September 30, 2022. Cash flows from operating activities for the third quarter of 2023 were $3,498 million compared with $6,098 million for the third quarter of 2022 and $2,745 million for the second quarter of 2023. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.
Adjusted funds flow for the nine months ended September 30, 2023 was $10,855 million compared with $15,615 million for the nine months ended September 30, 2022. Adjusted funds flow for the third quarter of 2023 was $4,684 million compared with $5,208 million for the third quarter of 2022 and $2,742 million for the second quarter of 2023. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above related to the fluctuations in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program.
Production Volumes
Crude oil and NGLs production before royalties for the third quarter of 2023 of 1,035,153 bbl/d increased 5% from 983,678 bbl/d for the third quarter of 2022, and increased 22% from 846,909 bbl/d for the second quarter of 2023. Record natural gas production before royalties for the third quarter of 2023 of 2,151 MMcf/d was comparable with 2,132 MMcf/d for the third quarter of 2022, and increased 3% from 2,085 MMcf/d for the second quarter of 2023. Total production before royalties for the third quarter of 2023 of 1,393,614 BOE/d increased 4% from 1,338,940 BOE/d for the third quarter of 2022, and increased 17% from 1,194,326 BOE/d for the second quarter of 2023. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.
Product Prices
In the Company's Exploration and Production segments, realized crude oil and NGLs prices averaged $87.83 per bbl for the third quarter of 2023, an increase of 3% from $84.91 per bbl for the third quarter of 2022, and an increase of 22% from $72.06 per bbl for the second quarter of 2023. The realized natural gas price decreased 57% to average $2.81 per Mcf for the third quarter of 2023 from $6.57 per Mcf for the third quarter of 2022, and increased 11% from $2.53 per Mcf for the second quarter of 2023. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 10% to average $108.55 per bbl for the third quarter of 2023 from $120.91 per bbl for the third quarter of 2022, and increased 14% from $95.08 per bbl for the second quarter of 2023. The Company's realized pricing reflected prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the "Business Environment", "Realized Product Prices – Exploration and Production", and the "Oil Sands Mining and Upgrading" sections of this MD&A.
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| Canadian Natural Resources Limited | 4 | Three and nine months ended September 30, 2023 |
Production Expense
In the Company's Exploration and Production segments, crude oil and NGLs production expense (1) averaged $14.40 per bbl for the third quarter of 2023, a decrease of 15% from $16.86 per bbl for the third quarter of 2022, and a decrease of 22% from $18.38 per bbl for the second quarter of 2023. Natural gas production expense (1) averaged $1.25 per Mcf for the third quarter of 2023, an increase of 8% from $1.16 per Mcf for the third quarter of 2022, and a decrease of 9% from $1.37 per Mcf for the second quarter of 2023. In the Oil Sands Mining and Upgrading segment, production expense (1) averaged $22.12 per bbl for the third quarter of 2023, comparable with $22.35 per bbl for the third quarter of 2022, and a decrease of 29% from $31.28 per bbl for the second quarter of 2023. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:
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| ($ millions, except per common share amounts) | | Sep 30
2023 | | Jun 30
2023 | | Mar 31
2023 | | Dec 31
2022 |
Product sales (1) | | $ | 11,762 | | | $ | 8,846 | | | $ | 9,548 | | | $ | 11,012 | |
| Crude oil and NGLs | | $ | 10,944 | | | $ | 8,115 | | | $ | 8,412 | | | $ | 9,508 | |
| Natural gas | | $ | 599 | | | $ | 522 | | | $ | 851 | | | $ | 1,287 | |
| Net earnings | | $ | 2,344 | | | $ | 1,463 | | | $ | 1,799 | | | $ | 1,520 | |
| Net earnings per common share | | | | | | | | |
| – basic | | $ | 2.15 | | | $ | 1.34 | | | $ | 1.63 | | | $ | 1.37 | |
| – diluted | | $ | 2.13 | | | $ | 1.32 | | | $ | 1.62 | | | $ | 1.36 | |
| ($ millions, except per common share amounts) | | Sep 30
2022 | | Jun 30
2022 | | Mar 31
2022 | | Dec 31
2021 |
Product sales (1) | | $ | 12,574 | | | $ | 13,812 | | | $ | 12,132 | | | $ | 10,190 | |
| Crude oil and NGLs | | $ | 11,001 | | | $ | 11,727 | | | $ | 10,773 | | | $ | 8,979 | |
| Natural gas | | $ | 1,342 | | | $ | 1,605 | | | $ | 1,002 | | | $ | 958 | |
| Net earnings | | $ | 2,814 | | | $ | 3,502 | | | $ | 3,101 | | | $ | 2,534 | |
| Net earnings per common share | | | | | | | | |
| – basic | | $ | 2.52 | | | $ | 3.04 | | | $ | 2.66 | | | $ | 2.16 | |
| – diluted | | $ | 2.49 | | | $ | 3.00 | | | $ | 2.63 | | | $ | 2.14 | |
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(1)Further details related to product sales for the three months ended September 30, 2023 and 2022 are disclosed in note 17 to the financial statements.
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
▪Crude oil pricing – Fluctuating global supply/demand including crude oil production levels from OPEC+ and its impact on world supply; the impact of geopolitical and market uncertainties, including those due to COVID-19 and in connection with governmental responses to COVID-19, and the impact of the Russian invasion of Ukraine on worldwide benchmark pricing; the impact of shale oil production in North America; the impact of the Western Canadian Select ("WCS") Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America; and the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the International segments.
▪Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third-party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, and the impact of shale gas production in the US.
(1)Calculated as respective production expense divided by respective sales volumes.
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| Canadian Natural Resources Limited | 5 | Three and nine months ended September 30, 2023 |
▪Crude oil and NGLs sales volumes – Fluctuations in production from the Kirby and Jackfish thermal oil sands projects, fluctuations in production due to the cyclic nature of the Primrose thermal oil projects, fluctuations in the Company's drilling program in North America and the International segments, natural decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and wildfires and a third-party pipeline outage in the North America segment. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments.
▪Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in North America and the International segments, natural decline rates, the impact and timing of acquisitions, and wildfires and a third-party pipeline outage in the North America segment.
▪Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, increased carbon tax and energy costs, inflationary cost pressures, cost optimizations across all segments, the impact and timing of acquisitions, turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.
▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions and dispositions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea at December 31, 2022.
▪Share-based compensation – Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.
▪Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities.
▪Interest expense – Fluctuations due to changing long-term debt levels, and the impact of movements in benchmark interest rates on outstanding floating rate long-term debt and accrued interest on the deferred Petroleum Revenue Tax ("PRT") recovery.
▪Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt, partially offset by the impact of any cross currency swap hedges outstanding.
▪(Gain) loss from investments – Fluctuations due to the (gain) loss from the investment in PrairieSky Royalty Ltd. shares.
BUSINESS ENVIRONMENT
Risks and Uncertainties
Global benchmark crude oil prices gained momentum in the third quarter of 2023 following the OPEC+ decision to extend production cuts into 2024. The global crude oil market continues to be impacted by heightened geopolitical tensions, which has led to price volatility in benchmark crude oil prices. Additionally, although inflationary pressures are easing, the Company has experienced and may continue to experience inflationary pressures on its operating and capital expenditures in addition to higher than normal fluctuations in commodity prices and interest rates.
Liquidity
As at September 30, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,140 million in liquidity (1). The Company also has certain other dedicated credit facilities supporting letters of credit.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
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| Canadian Natural Resources Limited | 6 | Three and nine months ended September 30, 2023 |
Benchmark Commodity Prices
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| | Three Months Ended | | | Nine Months Ended |
(Average for the period) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| WTI benchmark price (US$/bbl) | | $ | 82.18 | | | $ | 73.75 | | | $ | 91.64 | | | | $ | 77.37 | | | $ | 98.14 | |
| Dated Brent benchmark price (US$/bbl) | | $ | 86.68 | | | $ | 78.37 | | | $ | 99.34 | | | | $ | 82.11 | | | $ | 103.73 | |
| WCS Heavy Differential from WTI (US$/bbl) | | $ | 12.86 | | | $ | 15.07 | | | $ | 19.87 | | | | $ | 17.51 | | | $ | 15.78 | |
| SCO price (US$/bbl) | | $ | 84.99 | | | $ | 76.67 | | | $ | 100.51 | | | | $ | 79.97 | | | $ | 102.66 | |
| Condensate benchmark price (US$/bbl) | | $ | 77.91 | | | $ | 72.28 | | | $ | 87.15 | | | | $ | 76.66 | | | $ | 97.19 | |
| Condensate Differential from WTI (US$/bbl) | | $ | 4.27 | | | $ | 1.47 | | | $ | 4.49 | | | | $ | 0.71 | | | $ | 0.95 | |
| NYMEX benchmark price (US$/MMBtu) | | $ | 2.55 | | | $ | 2.10 | | | $ | 8.18 | | | | $ | 2.69 | | | $ | 6.77 | |
| AECO benchmark price (C$/GJ) | | $ | 2.26 | | | $ | 2.22 | | | $ | 5.51 | | | | $ | 2.86 | | | $ | 5.27 | |
US/Canadian dollar average exchange rate (US$) | | $ | 0.7456 | | | $ | 0.7447 | | | $ | 0.7660 | | | | $ | 0.7432 | | | $ | 0.7796 | |
Substantially all of the Company's production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company's realized prices are directly impacted by fluctuations in foreign exchange rates, and its product revenues continued to be impacted by the volatility of the Canadian dollar as the Canadian dollar sales price the Company received for its crude oil and natural gas sales is based on US dollar denominated benchmarks.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$77.37 per bbl for the nine months ended September 30, 2023, a decrease of 21% from US$98.14 per bbl for the nine months ended September 30, 2022. WTI averaged US$82.18 per bbl for the third quarter of 2023, a decrease of 10% from US$91.64 per bbl for the third quarter of 2022, and an increase of 11% from US$73.75 per bbl for the second quarter of 2023.
Crude oil sales contracts for the Company's International segments are typically based on Brent pricing, which is representative of international markets and overall global supply and demand. Brent averaged US$82.11 per bbl for the nine months ended September 30, 2023, a decrease of 21% from US$103.73 per bbl for the nine months ended September 30, 2022. Brent averaged US$86.68 per bbl for the third quarter of 2023, a decrease of 13% from US$99.34 per bbl for the third quarter of 2022, and an increase of 11% from US$78.37 per bbl for the second quarter of 2023.
The decrease in WTI and Brent pricing for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected concerns of lower global crude oil demand as a result of persistent inflation and the resulting increase in interest rates. The increase in WTI and Brent pricing for the third quarter of 2023 from the second quarter of 2023 primarily reflected the OPEC+ decision to extend production cuts into 2024.
The WCS Heavy Differential averaged US$17.51 per bbl for the nine months ended September 30, 2023, compared with US$15.78 per bbl for the nine months ended September 30, 2022. The WCS Heavy Differential averaged US$12.86 per bbl for the third quarter of 2023, compared with US$19.87 per bbl for the third quarter of 2022, and US$15.07 per bbl for the second quarter of 2023. The widening of the WCS Heavy Differential for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected weaker global sour crude oil pricing in part due to the availability of discounted Russian crude oil in the market, and US Strategic Petroleum Reserve sour crude oil releases that carried over into the first half of 2023. The narrowing of the WCS Heavy Differential for the third quarter of 2023 from the third quarter of 2022 primarily reflected strengthening of US Gulf Coast heavy oil pricing in 2023 and a decrease in supply from the US Strategic Petroleum Reserve following releases in 2022. The narrowing of the WCS Heavy Differential for the third quarter of 2023 from the second quarter of 2023 primarily reflected strengthening global sour crude oil pricing due to OPEC+ production cuts.
The SCO price averaged US$79.97 per bbl for the nine months ended September 30, 2023, a decrease of 22% from US$102.66 per bbl for the nine months ended September 30, 2022. The SCO price averaged US$84.99 per bbl for the third quarter of 2023, a decrease of 15% from US$100.51 per bbl for the third quarter of 2022, and an increase of 11% from US$76.67 per bbl for the second quarter of 2023. The change in SCO pricing for the three and nine months ended September 30, 2023 from the comparable periods primarily reflected movements in WTI benchmark pricing.
| | | | | | | | |
| Canadian Natural Resources Limited | 7 | Three and nine months ended September 30, 2023 |
NYMEX natural gas prices averaged US$2.69 per MMBtu for the nine months ended September 30, 2023, a decrease of 60% from US$6.77 per MMBtu for the nine months ended September 30, 2022. NYMEX natural gas prices averaged US$2.55 per MMBtu for the third quarter of 2023, a decrease of 69% from US$8.18 per MMBtu for the third quarter of 2022, and an increase of 21% from US$2.10 per MMBtu for the second quarter of 2023. The decrease in NYMEX natural gas prices for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected lower storage draws due to mild winter weather in 2023, combined with increased production in North America. Additionally, lower global LNG prices amid ample supply put downward pressure on NYMEX benchmark prices. The increase in NYMEX natural gas prices for the third quarter of 2023 from the second quarter of 2023 primarily reflected record temperatures in major consuming regions of the US, significantly increasing demand.
AECO natural gas prices averaged $2.86 per GJ for the nine months ended September 30, 2023, a decrease of 46% from $5.27 per GJ for the nine months ended September 30, 2022. AECO natural gas prices averaged $2.26 per GJ for the third quarter of 2023, a decrease of 59% from $5.51 per GJ for the third quarter of 2022, and comparable with $2.22 per GJ for the second quarter of 2023. The decrease in AECO natural gas prices for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected NYMEX benchmark pricing, and increased production levels in the Western Canadian Sedimentary Basin.
DAILY PRODUCTION, before royalties
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Crude oil and NGLs (bbl/d) | | | | | |
| North America – Exploration and Production | 519,581 | | 465,143 | | 471,632 | | 487,512 | | 477,751 | |
North America – Oil Sands Mining and Upgrading (1) | 490,853 | | 355,246 | | 487,553 | | 434,895 | | 424,988 | |
| International – Exploration and Production | | | | | |
North Sea | 12,016 | | 12,699 | | 10,855 | | 12,647 | | 12,514 | |
Offshore Africa | 12,703 | | 13,821 | | 13,638 | | 13,533 | | 14,826 | |
Total International (2) | 24,719 | | 26,520 | | 24,493 | | 26,180 | | 27,340 | |
| Total Crude oil and NGLs | 1,035,153 | | 846,909 | | 983,678 | | 948,587 | | 930,079 | |
Natural gas (MMcf/d) (3) | | | | | |
| North America | 2,139 | | 2,072 | | 2,117 | | 2,113 | | 2,065 | |
| International | | | | | |
North Sea | 1 | | 2 | | 1 | | 2 | | 2 | |
Offshore Africa | 11 | | 11 | | 14 | | 10 | | 14 | |
| Total International | 12 | | 13 | | 15 | | 12 | | 16 | |
| Total Natural gas | 2,151 | | 2,085 | | 2,132 | | 2,125 | | 2,081 | |
| Total Barrels of oil equivalent (BOE/d) | 1,393,614 | | 1,194,326 | | 1,338,940 | | 1,302,715 | | 1,276,970 | |
| Product mix | | | | | |
| Light and medium crude oil and NGLs | 10% | 11% | 10% | 10% | 11% |
| Pelican Lake heavy crude oil | 3% | 4% | 4% | 4% | 4% |
| Primary heavy crude oil | 5% | 6% | 5% | 6% | 5% |
| Bitumen (thermal oil) | 21% | 20% | 18% | 20% | 20% |
Synthetic crude oil (1) | 35% | 30% | 36% | 33% | 33% |
| Natural gas | 26% | 29% | 27% | 27% | 27% |
Percentage of gross revenue (1) (4) (5) | | | | | |
| Crude oil and NGLs | 95% | 93% | 88% | 93% | 89% |
| Natural gas | 5% | 7% | 12% | 7% | 11% |
(1)SCO production before royalties excludes SCO consumed internally as diesel.
(2)"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used.
(3)Natural gas production volumes approximate sales volumes.
(4)Net of blending and feedstock costs and excluding risk management activities.
(5)Excluding Midstream and Refining revenue.
| | | | | | | | |
| Canadian Natural Resources Limited | 8 | Three and nine months ended September 30, 2023 |
DAILY PRODUCTION, net of royalties
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Crude oil and NGLs (bbl/d) | | | | | |
| North America – Exploration and Production | 409,479 | | 388,670 | | 361,987 | | 398,258 | | 371,575 | |
| North America – Oil Sands Mining and Upgrading | 387,407 | | 301,239 | | 391,165 | | 366,606 | | 344,611 | |
| International – Exploration and Production | | | | | |
| North Sea | 11,968 | | 12,654 | | 10,776 | | 12,616 | | 12,466 | |
| Offshore Africa | 11,746 | | 12,343 | | 11,965 | | 12,273 | | 13,586 | |
| Total International | 23,714 | | 24,997 | | 22,741 | | 24,889 | | 26,052 | |
| Total Crude oil and NGLs | 820,600 | | 714,906 | | 775,893 | | 789,753 | | 742,238 | |
Natural gas (MMcf/d) | | | | | |
| North America | 2,068 | | 2,014 | | 1,920 | | 2,024 | | 1,868 | |
| International | | | | | |
| North Sea | 1 | | 2 | | 1 | | 2 | | 2 | |
| Offshore Africa | 10 | | 10 | | 12 | | 10 | | 13 | |
| Total International | 11 | | 12 | | 13 | | 12 | | 15 | |
| Total Natural gas | 2,079 | | 2,026 | | 1,933 | | 2,036 | | 1,883 | |
| Total Barrels of oil equivalent (BOE/d) | 1,167,139 | | 1,052,602 | | 1,098,001 | | 1,129,014 | | 1,056,008 | |
The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO, and natural gas.
Crude oil and NGLs production before royalties for the nine months ended September 30, 2023 averaged 948,587 bbl/d, comparable with 930,079 bbl/d for the nine months ended September 30, 2022. Crude oil and NGLs production for the third quarter of 2023 averaged 1,035,153 bbl/d, an increase of 5% from 983,678 bbl/d for the third quarter of 2022, and an increase of 22% from 846,909 bbl/d for the second quarter of 2023. The increase in crude oil and NGLs production for the third quarter of 2023 from the third quarter of 2022 primarily reflected increased thermal oil production resulting from pad additions at Primrose and Kirby. The increase in crude oil and NGLs production for the third quarter of 2023 from the second quarter of 2023 primarily reflected the completion of planned turnaround activities at Horizon and the non-operated Scotford Upgrader ("Scotford") in the second quarter of 2023, combined with strong thermal oil production.
Natural gas production before royalties for the nine months ended September 30, 2023 of 2,125 MMcf/d was comparable with 2,081 MMcf/d for the nine months ended September 30, 2022. Record natural gas production for the third quarter of 2023 averaged 2,151 MMcf/d, comparable with 2,132 MMcf/d for the third quarter of 2022, and an increase of 3% from 2,085 MMcf/d for the second quarter of 2023. The increase in natural gas production for the third quarter of 2023 from the second quarter of 2023 primarily reflected reduced wildfire impacts, restored volumes following a third-party pipeline outage through the second quarter of 2023, together with drilling activity, partially offset by natural field declines.
The Company's 2023 production is targeted to be at the lower end of the corporate guidance range of 1,330,000 BOE/d to 1,374,000 BOE/d, due to wildfires in Western Canada in the second and third quarters, a third-party pipeline outage in the first half of the year, and the previously announced unplanned outages at Horizon in January 2023.
| | | | | | | | |
| Canadian Natural Resources Limited | 9 | Three and nine months ended September 30, 2023 |
North America – Exploration and Production
North America crude oil and NGLs production before royalties for the nine months ended September 30, 2023 averaged 487,512 bbl/d, comparable with 477,751 bbl/d for the nine months ended September 30, 2022. Record North America crude oil and NGLs production for the third quarter of 2023 of 519,581 bbl/d increased 10% from 471,632 bbl/d for the third quarter of 2022, and increased 12% from 465,143 bbl/d for the second quarter of 2023. The increase in North America crude oil and NGLs production for the third quarter of 2023 from the comparable periods primarily reflected increased thermal oil production and drilling activity, partially offset by natural field declines. The increase from the second quarter of 2023 also reflected reduced wildfire impacts, and restored volumes following a third-party pipeline outage through the second quarter of 2023.
The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 287,085 bbl/d for the third quarter of 2023, an increase of 18% from 243,393 bbl/d for the third quarter of 2022, and an increase of 20% from 238,941 bbl/d for the second quarter of 2023. The increase in thermal in situ production in the third quarter of 2023 from the comparable periods primarily reflected pad additions at Primrose and Kirby, partially offset by natural field declines.
Pelican Lake heavy crude oil production before royalties for the third quarter of 2023 averaged 46,897 bbl/d, a decrease of 6% from 50,051 bbl/d for the third quarter of 2022, and comparable with 47,151 bbl/d for the second quarter of 2023, demonstrating Pelican Lake's long life low decline production.
Natural gas production before royalties for the nine months ended September 30, 2023 averaged 2,113 MMcf/d, comparable with 2,065 MMcf/d for the nine months ended September 30, 2022. Record natural gas production for the third quarter of 2023 averaged 2,139 MMcf/d, comparable with 2,117 MMcf/d for the third quarter of 2022, and an increase of 3% from 2,072 MMcf/d for the second quarter of 2023. The increase in natural gas production for the third quarter of 2023 from the second quarter of 2023 primarily reflected reduced wildfire impacts, restored volumes following a third-party pipeline outage through the second quarter of 2023, together with drilling activity, partially offset by natural field declines.
North America – Oil Sands Mining and Upgrading
SCO production before royalties for the nine months ended September 30, 2023 of 434,895 bbl/d was comparable with 424,988 bbl/d for the nine months ended September 30, 2022. SCO production for the third quarter of 2023 of 490,853 bbl/d was comparable with 487,553 bbl/d for the third quarter of 2022, and increased 38% from 355,246 bbl/d for the second quarter of 2023. The increase in SCO production for the third quarter of 2023 from the second quarter of 2023 primarily reflected the completion of planned turnaround activities at Horizon and Scotford during the second quarter of 2023.
International – Exploration and Production
International crude oil and NGLs production before royalties for the nine months ended September 30, 2023 averaged 26,180 bbl/d, a decrease of 4% from 27,340 bbl/d for the nine months ended September 30, 2022. International crude oil and NGLs production for the third quarter of 2023 averaged 24,719 bbl/d, comparable with 24,493 bbl/d for the third quarter of 2022, and a decrease of 7% from 26,520 bbl/d for the second quarter of 2023, primarily reflecting the impact of planned maintenance activities, together with natural field declines.
International Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when control of the product passes to the customer and delivery has taken place. Revenue has not been recognized in the International segments on crude oil volumes held in various storage facilities or FPSOs, as follows:
| | | | | | | | | | | |
| (bbl) | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 |
| | | |
| | | |
| International | 1,167,250 | | 816,475 | | 1,126,786 | |
| | | | | | | | |
| Canadian Natural Resources Limited | 10 | Three and nine months ended September 30, 2023 |
OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
Realized price (2) | | $ | 87.83 | | | $ | 72.06 | | | $ | 84.91 | | | | $ | 73.45 | | | $ | 97.99 | |
Transportation (2) | | 4.07 | | | 4.57 | | | 4.10 | | | | 4.37 | | | 4.14 | |
Realized price, net of transportation (2) | | 83.76 | | | 67.49 | | | 80.81 | | | | 69.08 | | | 93.85 | |
Royalties (3) | | 17.32 | | | 11.09 | | | 19.48 | | | | 12.98 | | | 20.75 | |
Production expense (4) | | 14.40 | | | 18.38 | | | 16.86 | | | | 16.51 | | | 17.41 | |
Netback (2) | | $ | 52.04 | | | $ | 38.02 | | | $ | 44.47 | | | | $ | 39.59 | | | $ | 55.69 | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
Realized price (5) | | $ | 2.81 | | | $ | 2.53 | | | $ | 6.57 | | | | $ | 3.20 | | | $ | 6.61 | |
Transportation (6) | | 0.56 | | | 0.58 | | | 0.51 | | | | 0.56 | | | 0.50 | |
Realized price, net of transportation | | 2.25 | | | 1.95 | | | 6.06 | | | | 2.64 | | | 6.11 | |
Royalties (3) | | 0.09 | | | 0.07 | | | 0.61 | | | | 0.15 | | | 0.65 | |
Production expense (4) | | 1.25 | | | 1.37 | | | 1.16 | | | | 1.36 | | | 1.21 | |
Netback | | $ | 0.91 | | | $ | 0.51 | | | $ | 4.29 | | | | $ | 1.13 | | | $ | 4.25 | |
Barrels of oil equivalent ($/BOE) (1) | | | | | | | | | | | |
Realized price (2) | | $ | 59.40 | | | $ | 48.94 | | | $ | 66.04 | | | | $ | 51.31 | | | $ | 74.62 | |
Transportation (2) | | 3.78 | | | 4.11 | | | 3.64 | | | | 3.97 | | | 3.68 | |
Realized price, net of transportation (2) | | 55.62 | | | 44.83 | | | 62.40 | | | | 47.34 | | | 70.94 | |
Royalties (3) | | 10.61 | | | 6.75 | | | 12.88 | | | | 8.03 | | | 13.94 | |
Production expense (4) | | 11.64 | | | 14.24 | | | 12.68 | | | | 13.10 | | | 13.28 | |
Netback (2) | | $ | 33.37 | | | $ | 23.84 | | | $ | 36.84 | | | | $ | 26.21 | | | $ | 43.72 | |
(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as royalties divided by respective sales volumes.
(4)Calculated as production expense divided by respective sales volumes.
(5)Calculated as natural gas sales divided by natural gas sales volumes.
(6)Calculated as natural gas transportation expense divided by natural gas sales volumes.
| | | | | | | | |
| Canadian Natural Resources Limited | 11 | Three and nine months ended September 30, 2023 |
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
North America (2) | | $ | 86.77 | | | $ | 69.44 | | | $ | 83.62 | | | | $ | 71.90 | | | $ | 96.11 | |
International average (3) | | $ | 113.59 | | | $ | 103.64 | | | $ | 120.09 | | | | $ | 105.20 | | | $ | 132.96 | |
North Sea (3) | | $ | 108.22 | | | $ | 106.39 | | | $ | 123.18 | | | | $ | 106.91 | | | $ | 135.73 | |
Offshore Africa (3) | | $ | 118.09 | | | $ | 100.68 | | | $ | 119.08 | | | | $ | 105.55 | | | $ | 131.02 | |
Crude oil and NGLs average (2) | | $ | 87.83 | | | $ | 72.06 | | | $ | 84.91 | | | | $ | 73.45 | | | $ | 97.99 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) (3) | | | | | | | | | | | |
| North America | | $ | 2.76 | | | $ | 2.47 | | | $ | 6.51 | | | | $ | 3.15 | | | $ | 6.56 | |
| International average | | $ | 12.21 | | | $ | 13.16 | | | $ | 14.83 | | | | $ | 13.04 | | | $ | 12.60 | |
| North Sea | | $ | 9.99 | | | $ | 9.48 | | | $ | 20.88 | | | | $ | 10.70 | | | $ | 16.91 | |
| Offshore Africa | | $ | 12.44 | | | $ | 13.71 | | | $ | 14.27 | | | | $ | 13.44 | | | $ | 11.99 | |
| Natural gas average | | $ | 2.81 | | | $ | 2.53 | | | $ | 6.57 | | | | $ | 3.20 | | | $ | 6.61 | |
| | | | | | | | | | | |
Average ($/BOE) (1) (2) | | $ | 59.40 | | | $ | 48.94 | | | $ | 66.04 | | | | $ | 51.31 | | | $ | 74.62 | |
(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as crude oil and NGLs sales and natural gas sales divided by respective sales volumes.
North America
North America realized crude oil and NGLs prices decreased 25% to average $71.90 per bbl for the nine months ended September 30, 2023 from $96.11 per bbl for the nine months ended September 30, 2022. North America realized crude oil and NGLs prices increased 4% to average $86.77 per bbl for the third quarter of 2023 from $83.62 per bbl for the third quarter of 2022, and increased 25% from $69.44 per bbl for the second quarter of 2023. The decrease for the nine months ended September 30, 2023 from the comparable period in 2022 was primarily due to lower WTI benchmark pricing and the widening of the WCS Heavy Differential. The increase in North America realized crude oil and NGLs prices for the third quarter of 2023 from the comparable period in 2022, primarily reflected the narrowing of the WCS differential, partially offset by lower WTI benchmark pricing. The increase for the third quarter of 2023 from the second quarter of 2023 primarily reflected higher WTI benchmark pricing, combined with the narrowing of the WCS Heavy Differential. The Company continues to focus on its crude oil blending marketing strategy and in the third quarter of 2023 contributed approximately 210,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices decreased 52% to average $3.15 per Mcf for the nine months ended September 30, 2023 from $6.56 per Mcf for the nine months ended September 30, 2022. North America realized natural gas prices decreased 58% to average $2.76 per Mcf for the third quarter of 2023 from $6.51 per Mcf for the third quarter of 2022, and increased 12% from $2.47 per Mcf for the second quarter of 2023. The decrease in North America realized natural gas prices for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected decreased AECO benchmark and export pricing. The increase for the third quarter of 2023 from the second quarter of 2023 primarily reflected increased NYMEX pricing on the Company's exports to the US.
| | | | | | | | |
| Canadian Natural Resources Limited | 12 | Three and nine months ended September 30, 2023 |
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended |
| (Quarterly average) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 |
Wellhead Price (1) | | | | | | |
| Light and medium crude oil and NGLs ($/bbl) | | $ | 72.07 | | | $ | 68.11 | | | $ | 82.26 | |
| Pelican Lake heavy crude oil ($/bbl) | | $ | 93.19 | | | $ | 76.66 | | | $ | 91.98 | |
| Primary heavy crude oil ($/bbl) | | $ | 93.80 | | | $ | 76.20 | | | $ | 89.80 | |
| Bitumen (thermal oil) ($/bbl) | | $ | 89.50 | | | $ | 66.51 | | | $ | 80.74 | |
| Natural gas ($/Mcf) | | $ | 2.76 | | | $ | 2.47 | | | $ | 6.51 | |
(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
International
International realized crude oil and NGLs prices decreased 21% to average $105.20 per bbl for the nine months ended September 30, 2023 from $132.96 per bbl for the nine months ended September 30, 2022. International realized crude oil and NGLs prices decreased 5% to average $113.59 per bbl for the third quarter of 2023 from $120.09 per bbl for the third quarter of 2022, and increased 10% from $103.64 per bbl for the second quarter of 2023. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The fluctuations in realized crude oil and NGLs prices for the three and nine months ended September 30, 2023 from the comparable periods reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
ROYALTIES – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
| North America | | $ | 17.79 | | | $ | 11.56 | | | $ | 19.78 | | | | $ | 13.31 | | | $ | 21.53 | |
| International average | | $ | 5.67 | | | $ | 5.38 | | | $ | 11.24 | | | | $ | 6.07 | | | $ | 6.30 | |
| North Sea | | $ | 0.42 | | | $ | 0.36 | | | $ | 0.86 | | | | $ | 0.38 | | | $ | 0.38 | |
| Offshore Africa | | $ | 8.90 | | | $ | 10.77 | | | $ | 14.61 | | | | $ | 9.87 | | | $ | 10.47 | |
| Crude oil and NGLs average | | $ | 17.32 | | | $ | 11.09 | | | $ | 19.48 | | | | $ | 12.98 | | | $ | 20.75 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
| North America | | $ | 0.09 | | | $ | 0.07 | | | $ | 0.61 | | | | $ | 0.14 | | | $ | 0.64 | |
| Offshore Africa | | $ | 0.59 | | | $ | 0.65 | | | $ | 1.73 | | | | $ | 0.64 | | | $ | 1.62 | |
| Natural gas average | | $ | 0.09 | | | $ | 0.07 | | | $ | 0.61 | | | | $ | 0.15 | | | $ | 0.65 | |
| | | | | | | | | | | |
Average ($/BOE) (1) | | $ | 10.61 | | | $ | 6.75 | | | $ | 12.88 | | | | $ | 8.03 | | | $ | 13.94 | |
(1)Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs and natural gas royalties for the three and nine months ended September 30, 2023 and the comparable periods reflected movements in benchmark commodity prices, fluctuations in the WCS Heavy Differential and the impact of sliding scale royalty rates.
Crude oil and NGLs royalty rates (1) averaged approximately 19% of product sales for the nine months ended September 30, 2023 compared with 22% of product sales for the nine months ended September 30, 2022. Crude oil and NGLs royalty rates averaged approximately 21% of product sales for the third quarter of 2023 compared with 24% for the third quarter of 2022 and 17% for the second quarter of 2023.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
| | | | | | | | |
| Canadian Natural Resources Limited | 13 | Three and nine months ended September 30, 2023 |
The decrease in royalty rates for the three and nine months ended September 30, 2023 from the comparable periods in 2022 was primarily due to lower benchmark prices and fluctuations in the WCS Heavy Differential. The increase in royalty rates for the third quarter of 2023 compared to the second quarter of 2023 primarily reflected higher benchmark pricing and the narrowing of the WCS Heavy Differential.
Natural gas royalty rates averaged approximately 5% of product sales for the nine months ended September 30, 2023 compared with 10% of product sales for the nine months ended September 30, 2022. Natural gas royalty rates averaged approximately 3% of product sales for the third quarter of 2023 compared with 9% for the third quarter of 2022, and 3% for the second quarter of 2023. The decrease in royalty rates for the three and nine months ended September 30, 2023 from the comparable periods in 2022 was primarily due to lower benchmark prices.
Offshore Africa
Under the terms of the various Production Sharing Contracts royalty rates fluctuate based on realized commodity pricing, capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 9% for the nine months ended September 30, 2023 compared with 8% of product sales for the nine months ended September 30, 2022. Royalty rates as a percentage of product sales averaged approximately 7% for the third quarter of 2023 compared with 12% of product sales for the third quarter of 2022, and 10% for the second quarter of 2023. Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
| North America | | $ | 13.21 | | | $ | 15.64 | | | $ | 15.98 | | | | $ | 15.16 | | | $ | 16.06 | |
| International average | | $ | 44.16 | | | $ | 51.50 | | | $ | 40.86 | | | | $ | 44.94 | | | $ | 42.49 | |
| North Sea | | $ | 83.44 | | | $ | 81.32 | | | $ | 115.41 | | | | $ | 81.92 | | | $ | 81.52 | |
| Offshore Africa | | $ | 20.04 | | | $ | 19.44 | | | $ | 16.64 | | | | $ | 20.23 | | | $ | 15.05 | |
| Crude oil and NGLs average | | $ | 14.40 | | | $ | 18.38 | | | $ | 16.86 | | | | $ | 16.51 | | | $ | 17.41 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
| North America | | $ | 1.22 | | | $ | 1.35 | | | $ | 1.13 | | | | $ | 1.33 | | | $ | 1.18 | |
| International average | | $ | 7.40 | | | $ | 4.83 | | | $ | 4.99 | | | | $ | 6.72 | | | $ | 4.57 | |
| North Sea | | $ | 9.19 | | | $ | 9.17 | | | $ | 12.67 | | | | $ | 9.95 | | | $ | 8.68 | |
| Offshore Africa | | $ | 7.21 | | | $ | 4.17 | | | $ | 4.27 | | | | $ | 6.17 | | | $ | 3.99 | |
| Natural gas average | | $ | 1.25 | | | $ | 1.37 | | | $ | 1.16 | | | | $ | 1.36 | | | $ | 1.21 | |
| | | | | | | | | | | |
Average ($/BOE) (1) | | $ | 11.64 | | | $ | 14.24 | | | $ | 12.68 | | | | $ | 13.10 | | | $ | 13.28 | |
(1)Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs production expense for the nine months ended September 30, 2023 averaged $15.16 per bbl, a decrease of 6% from $16.06 per bbl for the nine months ended September 30, 2022. North America crude oil and NGLs production expense for the third quarter of 2023 of $13.21 per bbl decreased 17% from $15.98 per bbl for the third quarter of 2022, and decreased 16% from $15.64 per bbl for the second quarter of 2023. The decrease in crude oil and NGLs production expense per bbl for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected lower natural gas fuel costs, partially offset by higher service costs. The decrease in crude oil and NGLs production expense per bbl for the third quarter of 2023 from the comparable periods primarily reflected increased production volumes in the third quarter of 2023, combined with lower energy costs.
| | | | | | | | |
| Canadian Natural Resources Limited | 14 | Three and nine months ended September 30, 2023 |
North America natural gas production expense averaged $1.33 per Mcf for the nine months ended September 30, 2023, an increase of 13% from $1.18 per Mcf for the nine months ended September 30, 2022. North America natural gas production expense for the third quarter of 2023 averaged $1.22 per Mcf, an increase of 8% from $1.13 per Mcf for the third quarter of 2022, and a decrease of 10% from $1.35 per Mcf for the second quarter of 2023. The increase in natural gas production expense per Mcf for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected higher service costs. The decrease in natural gas production expense per Mcf for the third quarter of 2023 from the second quarter of 2023 primarily reflected the impact of higher production volumes.
International
International crude oil and NGLs production expense for the nine months ended September 30, 2023 averaged $44.94 per bbl, an increase of 6% from $42.49 per bbl for the nine months ended September 30, 2022. International crude oil and NGLs production expense for the third quarter of 2023 of $44.16 per bbl increased 8% from $40.86 per bbl for the third quarter of 2022, and decreased 14% from $51.50 per bbl for the second quarter of 2023. The fluctuations in crude oil and NGLs production expense per bbl primarily reflected the timing of liftings from various fields that have different cost structures, the timing of maintenance activities, lower production volumes, and the impact of foreign exchange.
DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per BOE amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| North America | | $ | 947 | | | $ | 871 | | | $ | 913 | | | | $ | 2,708 | | | $ | 2,646 | |
| North Sea | | 12 | | | 15 | | | 15 | | | | 28 | | | 94 | |
| Offshore Africa | | 47 | | | 65 | | | 39 | | | | 147 | | | 132 | |
| Depletion, depreciation and amortization | | $ | 1,006 | | | $ | 951 | | | $ | 967 | | | | $ | 2,883 | | | $ | 2,872 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
$/BOE (1) | | $ | 12.22 | | | $ | 12.26 | | | $ | 12.48 | | | | $ | 12.21 | | | $ | 12.34 | |
(1)Calculated as depletion, depreciation and amortization divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Depletion, depreciation and amortization expense for the nine months ended September 30, 2023 of $12.21 per BOE was comparable with $12.34 per BOE for the nine months ended September 30, 2022. Depletion, depreciation and amortization expense for the third quarter of 2023 of $12.22 per BOE was comparable with $12.48 per BOE for the third quarter of 2022, and $12.26 per BOE for the second quarter of 2023.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per BOE amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| North America | | $ | 59 | | | $ | 58 | | | $ | 50 | | | | $ | 176 | | | $ | 120 | |
| North Sea | | 11 | | | 12 | | | 10 | | | | 34 | | | 23 | |
| Offshore Africa | | 2 | | | 2 | | | 2 | | | | 6 | | | 5 | |
| Asset retirement obligation accretion | | $ | 72 | | | $ | 72 | | | $ | 62 | | | | $ | 216 | | | $ | 148 | |
$/BOE (1) | | $ | 0.87 | | | $ | 0.93 | | | $ | 0.80 | | | | $ | 0.91 | | | $ | 0.64 | |
(1)Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.
| | | | | | | | |
| Canadian Natural Resources Limited | 15 | Three and nine months ended September 30, 2023 |
Asset retirement obligation accretion expense for the nine months ended September 30, 2023 of $0.91 per BOE increased 42% from $0.64 per BOE for the nine months ended September 30, 2022. Asset retirement obligation accretion expense for the third quarter of 2023 of $0.87 per BOE increased 9% from $0.80 per BOE for the third quarter of 2022, and decreased 6% from $0.93 per BOE for the second quarter of 2023. The increase in asset retirement obligation accretion expense per BOE for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. The decrease in asset retirement obligation accretion expense per BOE for the third quarter of 2023 from the second quarter of 2023 reflected higher sales volumes.
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
The Company continues to focus on safe, reliable, and efficient operations leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 490,853 bbl/d in the third quarter of 2023 following the completion of planned turnaround activities in the second quarter of 2023.
The Company incurred production expense of $1,003 million for the third quarter of 2023, comparable with $1,005 million for the third quarter of 2022, and $997 million for the second quarter of 2023, reflecting the Company's continued focus on cost control and efficiencies across the entire asset base.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($/bbl) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Realized SCO sales price (1) | | $ | 108.55 | | | $ | 95.08 | | | $ | 120.91 | | | | $ | 100.57 | | | $ | 122.45 | |
Bitumen value for royalty purposes (2) | | $ | 84.66 | | | $ | 66.51 | | | $ | 82.19 | | | | $ | 66.85 | | | $ | 91.69 | |
Bitumen royalties (3) | | $ | 21.90 | | | $ | 13.58 | | | $ | 24.87 | | | | $ | 15.52 | | | $ | 22.85 | |
Transportation (1) | | $ | 2.18 | | | $ | 2.03 | | | $ | 1.55 | | | | $ | 1.91 | | | $ | 1.69 | |
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Calculated as the quarterly average of the bitumen methodology price.
(3)Calculated as royalties divided by sales volumes.
The realized SCO sales price averaged $100.57 per bbl for the nine months ended September 30, 2023, a decrease of 18% from $122.45 per bbl for the nine months ended September 30, 2022. The realized SCO sales price averaged $108.55 per bbl for the third quarter of 2023, a decrease of 10% from $120.91 per bbl for the third quarter of 2022, and an increase of 14% from $95.08 per bbl for the second quarter of 2023. The decrease in the realized SCO sales price for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected the decrease in WTI benchmark pricing. The increase in realized SCO sales price for the third quarter of 2023 from the second quarter of 2023 primarily reflected an increase in WTI benchmark pricing.
The decrease in bitumen royalties per bbl for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected the impact of lower prevailing bitumen pricing. The increase for the third quarter of 2023 from the second quarter of 2023 primarily reflected higher prevailing bitumen pricing and the impact of sliding scale royalty rates.
Transportation expense averaged $1.91 per bbl for the nine months ended September 30, 2023, an increase of 13% from $1.69 per bbl for the nine months ended September 30, 2022. Transportation expense averaged $2.18 per bbl for the third quarter of 2023, an increase of 41% from $1.55 per bbl for the third quarter of 2022, and an increase of 7% from $2.03 per bbl for the second quarter of 2023. The increase in transportation expense per bbl for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected higher sales to the US Gulf Coast in 2023. The increase for third quarter of 2023 from the second quarter of 2023 primarily reflected higher sales to the US Gulf Coast, partially offset by higher total sales volumes.
| | | | | | | | |
| Canadian Natural Resources Limited | 16 | Three and nine months ended September 30, 2023 |
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 17 to the financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Production expense, excluding natural gas costs | | $ | 962 | | | $ | 957 | | | $ | 935 | | | | $ | 2,890 | | | $ | 2,810 | |
| Natural gas costs | | 41 | | | 40 | | | 70 | | | | 152 | | | 249 | |
| Production expense | | $ | 1,003 | | | $ | 997 | | | $ | 1,005 | | | | $ | 3,042 | | | $ | 3,059 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
($/bbl) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Production expense, excluding natural gas costs (1) | | $ | 21.22 | | | $ | 30.03 | | | $ | 20.77 | | | | $ | 24.33 | | | $ | 24.10 | |
Natural gas costs (2) | | 0.90 | | | 1.25 | | | 1.58 | | | | 1.28 | | | 2.14 | |
Production expense (3) | | $ | 22.12 | | | $ | 31.28 | | | $ | 22.35 | | | | $ | 25.61 | | | $ | 26.24 | |
| Sales volumes (bbl/d) | | 492,926 | | | 350,041 | | | 489,146 | | | | 435,109 | | | 427,165 | |
(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, 2023 of $25.61 per bbl was comparable with $26.24 per bbl for the nine months ended September 30, 2022. Production expense for the third quarter of 2023 averaged $22.12 per bbl, comparable with $22.35 per bbl for the third quarter of 2022, and a decrease of 29% from $31.28 per bbl for the second quarter of 2023. The decrease in production expense per bbl for the third quarter of 2023 from the second quarter of 2023 primarily reflected higher production volumes following the completion of planned turnaround activities in the second quarter.
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per bbl amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Depletion, depreciation and amortization | | $ | 527 | | | $ | 442 | | | $ | 484 | | | | $ | 1,457 | | | $ | 1,341 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
$/bbl (1) | | $ | 11.62 | | | $ | 13.88 | | | $ | 10.75 | | | | $ | 12.27 | | | $ | 11.50 | |
(1)Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for the nine months ended September 30, 2023 of $12.27 per bbl increased 7% from $11.50 per bbl for the nine months ended September 30, 2022. Depletion, depreciation and amortization expense for the third quarter of 2023 of $11.62 per bbl increased 8% from $10.75 per bbl for the third quarter of 2022, and decreased 16% from $13.88 per bbl for the second quarter of 2023. The increase in depletion, depreciation and amortization expense on a per bbl basis for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected the impact of asset additions. The decrease in depletion, depreciation and amortization expense on a per bbl basis for the third quarter of 2023 from the second quarter of 2023 primarily reflected the impact of higher volumes in the third quarter following the completion of planned turnaround activities in the second quarter.
| | | | | | | | |
| Canadian Natural Resources Limited | 17 | Three and nine months ended September 30, 2023 |
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per bbl amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Asset retirement obligation accretion | | $ | 20 | | | $ | 19 | | | $ | 20 | | | | $ | 59 | | | $ | 51 | |
$/bbl (1) | | $ | 0.43 | | | $ | 0.62 | | | $ | 0.43 | | | | $ | 0.50 | | | $ | 0.43 | |
(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, 2023 of $0.50 per bbl increased 16% from $0.43 per bbl for the nine months ended September 30, 2022. Asset retirement obligation accretion expense for the third quarter of 2023 of $0.43 per bbl was comparable with $0.43 per bbl for the third quarter of 2022, and decreased 31% from $0.62 per bbl for the second quarter of 2023. The increase in asset retirement obligation accretion expense on a per bbl basis for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. The decrease in asset retirement obligation accretion expense on a per bbl basis for the third quarter of 2023 from the second quarter of 2023 primarily reflected the impact of higher sales volumes in the third quarter following the completion of planned turnaround activities in the second quarter.
MIDSTREAM AND REFINING
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | | |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 | | |
| Product sales | | | | | | | | | | | | | |
| Midstream activities | | $ | 20 | | | $ | 15 | | | $ | 21 | | | | $ | 56 | | | $ | 59 | | | |
| NWRP, refined product sales and other | | 237 | | | 203 | | | 134 | | | | 690 | | | 701 | | | |
| Segmented revenue | | 257 | | | 218 | | | 155 | | | | 746 | | | 760 | | | |
| | | | | | | | | | | | | |
| Less: | | | | | | | | | | | | | |
| NWRP, refining toll | | 66 | | | 85 | | | 66 | | | | 221 | | | 190 | | | |
| Midstream activities | | 8 | | | 6 | | | 6 | | | | 22 | | | 18 | | | |
| Production expense | | 74 | | | 91 | | | 72 | | | | 243 | | | 208 | | | |
| NWRP, transportation and feedstock costs | | 183 | | | 162 | | | 113 | | | | 498 | | | 536 | | | |
| Depreciation | | 4 | | | 4 | | | 3 | | | | 12 | | | 11 | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Segmented (loss) earnings | | $ | (4) | | | $ | (39) | | | $ | (33) | | | | $ | (7) | | | $ | 5 | | | |
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 (25% toll payer) of bitumen feedstock for the Company and 37,500 bbl/d (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), 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 2023, production of ultra-low sulphur diesel and other refined products averaged 78,376 BOE/d (19,594 BOE/d to the Company), (three months ended June 30, 2023 – 79,112 BOE/d; 19,778 BOE/d to the Company; three months ended September 30, 2022 – 32,252 BOE/d; 8,063 BOE/d to the Company), reflecting the 25% toll payer commitment.
| | | | | | | | |
| Canadian Natural Resources Limited | 18 | Three and nine months ended September 30, 2023 |
As at September 30, 2023, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $550 million (December 31, 2022 – $551 million). For the three months ended September 30, 2023, the Company's recovery of its share of unrecognized equity losses was $18 million (nine months ended September 30, 2023 – recovery of unrecognized equity losses of $1 million; three months ended September 30, 2022 – unrecognized equity loss of $1 million; nine months ended September 30, 2022 – unrecognized equity loss of $26 million).
ADMINISTRATION EXPENSE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per BOE amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Administration expense | | $ | 108 | | | $ | 119 | | | $ | 94 | | | | $ | 333 | | | $ | 307 | |
$/BOE (1) | | $ | 0.84 | | | $ | 1.09 | | | $ | 0.76 | | | | $ | 0.94 | | | $ | 0.88 | |
Sales volumes (BOE/d) (2) | | 1,388,033 | | | 1,202,336 | | | 1,331,189 | | | | 1,300,390 | | | 1,279,771 | |
(1)Calculated as administration expense divided by sales volumes.
(2)Total Company sales volumes.
Administration expense for the nine months ended September 30, 2023 of $0.94 per BOE increased 7% from $0.88 per BOE for the nine months ended September 30, 2022. Administration expense for the third quarter of 2023 of $0.84 per BOE increased 11% from $0.76 per BOE for the third quarter of 2022, and decreased 23% from $1.09 per BOE for the second quarter of 2023. The increase in administration expense per BOE for the three and nine months ended September 30, 2023 from the comparable periods in 2022 was primarily due to higher personnel costs. The decrease in administration expense per BOE for the third quarter of 2023 from the second quarter of 2023 primarily reflected lower corporate costs combined with higher sales volumes in the third quarter, partially offset by lower overhead recoveries.
SHARE-BASED COMPENSATION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Expense (recovery) | | $ | 298 | | | $ | 70 | | | $ | (4) | | | | $ | 434 | | | $ | 485 | |
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 by individual employee performance and the extent to which certain other performance measures are met.
The Company recognized $434 million of share-based compensation expense for the nine months ended September 30, 2023, primarily as a result of the measurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the period, and changes in the Company's share price.
| | | | | | | | |
| Canadian Natural Resources Limited | 19 | Three and nine months ended September 30, 2023 |
INTEREST AND OTHER FINANCING EXPENSE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except effective interest rate) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Interest and other financing expense | | $ | 187 | | | $ | 178 | | | $ | 150 | | | | $ | 519 | | | $ | 473 | |
Less: Interest income and other (1) | | 4 | | | 3 | | | (18) | | | | (2) | | | (28) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Interest expense on long-term debt and lease liabilities (1) | | $ | 183 | | | $ | 175 | | | $ | 168 | | | | $ | 521 | | | $ | 501 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Average current and long-term debt (2) | | $ | 13,393 | | | $ | 12,910 | | | $ | 13,714 | | | | $ | 12,882 | | | $ | 14,257 | |
Average lease liabilities (2) | | 1,490 | | | 1,510 | | | 1,526 | | | | 1,505 | | | 1,539 | |
Average long-term debt and lease liabilities (2) | | $ | 14,883 | | | $ | 14,420 | | | $ | 15,240 | | | | $ | 14,387 | | | $ | 15,796 | |
Average effective interest rate (3) (4) | | 4.8% | | 4.8% | | 4.3% | | | 4.8% | | 4.1% |
| | | | | | | | | | | |
Interest and other financing expense per $/BOE (5) | | $ | 1.46 | | | $ | 1.63 | | | $ | 1.23 | | | | $ | 1.46 | | | $ | 1.36 | |
Sales volumes (BOE/d) (6) | | 1,388,033 | | | 1,202,336 | | | 1,331,189 | | | | 1,300,390 | | | 1,279,771 | |
(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, 2023 of $1.46 per BOE increased 7% from $1.36 per BOE for the nine months ended September 30, 2022. Interest and other financing expense per BOE for the third quarter of 2023 increased 19% to $1.46 per BOE from $1.23 per BOE for the third quarter of 2022, and decreased 10% from $1.63 per BOE for the second quarter of 2023. The increase in interest and other financing expense per BOE for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected the impact of higher interest rates on floating rate long-term debt. The decrease in interest and other financing expense per BOE for the third quarter of 2023 from the second quarter of 2023 primarily reflected higher sales volumes in the third quarter.
The Company's average effective interest rate for the three and nine months ended September 30, 2023 increased from the comparable periods in 2022 primarily due to higher prevailing interest rates on floating rate long-term debt held during 2023.
| | | | | | | | |
| Canadian Natural Resources Limited | 20 | Three and nine months ended September 30, 2023 |
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Foreign currency contracts | | $ | 30 | | | $ | (30) | | | $ | (43) | | | | $ | (2) | | | $ | (40) | |
Natural gas financial instruments (1) | | (1) | | | 3 | | | (3) | | | | 5 | | | 19 | |
Crude oil and NGLs financial instruments (1) | | — | | | — | | | 2 | | | | — | | | 16 | |
| | | | | | | | | | | |
| Net realized loss (gain) | | 29 | | | (27) | | | (44) | | | | 3 | | | (5) | |
| | | | | | | | | | | |
| Foreign currency contracts | | 2 | | | 2 | | | — | | | | 7 | | | (14) | |
Natural gas financial instruments (1) | | 1 | | | (6) | | | (44) | | | | 12 | | | (28) | |
Crude oil and NGLs financial instruments (1) | | — | | | — | | | (4) | | | | — | | | (1) | |
| | | | | | | | | | | |
| Net unrealized loss (gain) | | 3 | | | (4) | | | (48) | | | | 19 | | | (43) | |
| Net loss (gain) | | $ | 32 | | | $ | (31) | | | $ | (92) | | | | $ | 22 | | | $ | (48) | |
(1)Commodity financial instruments were assumed in the acquisition of Storm Resources Ltd. and Painted Pony Energy Ltd. in the fourth quarter of 2021 and 2020, respectively.
During the nine months ended September 30, 2023, net realized risk management losses were related to the settlement of natural gas financial instruments, partially offset by realized gains on foreign currency contracts. The Company recorded a net unrealized loss of $19 million ($16 million after-tax of $3 million) on its risk management activities for the nine months ended September 30, 2023, including a net unrealized loss of $3 million ($2 million after-tax of $1 million) for the third quarter of 2023 (three months ended June 30, 2023 – unrealized gain of $4 million, $2 million after-tax of $2 million; three months ended September 30, 2022 – unrealized gain of $48 million, $37 million after-tax of $11 million; nine months ended September 30, 2022 – unrealized gain of $43 million, $36 million after-tax of $7 million).
Further details related to outstanding derivative financial instruments as at September 30, 2023 are disclosed in note 15 to the financial statements.
FOREIGN EXCHANGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Net realized (gain) loss | | $ | (48) | | | $ | 29 | | | $ | (49) | | | | $ | (30) | | | $ | (132) | |
| Net unrealized loss (gain) | | 250 | | | (231) | | | 785 | | | | 16 | | | 1,055 | |
Net loss (gain) (1) | | $ | 202 | | | $ | (202) | | | $ | 736 | | | | $ | (14) | | | $ | 923 | |
(1)Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange gain for the nine months ended September 30, 2023 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange loss for the nine months ended September 30, 2023 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at September 30, 2023 was US$0.7387 (June 30, 2023 – US$0.7554, September 30, 2022 – US$0.7300).
| | | | | | | | |
| Canadian Natural Resources Limited | 21 | Three and nine months ended September 30, 2023 |
INCOME TAXES
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except effective tax rates) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
North America (1) | | $ | 587 | | | $ | 299 | | | $ | 755 | | | | $ | 1,366 | | | $ | 2,444 | |
| North Sea | | (11) | | | (4) | | | 14 | | | | (9) | | | 36 | |
| Offshore Africa | | 23 | | | 20 | | | 21 | | | | 53 | | | 51 | |
Current PRT – North Sea | | — | | | (5) | | | (36) | | | | (45) | | | (37) | |
| Other taxes | | 3 | | | 3 | | | 3 | | | | 9 | | | 13 | |
| Current income tax | | 602 | | | 313 | | | 757 | | | | 1,374 | | | 2,507 | |
| Deferred corporate income tax | | 195 | | | (15) | | | 194 | | | | 203 | | | 450 | |
Deferred PRT – North Sea | | 6 | | | 11 | | | — | | | | 24 | | | — | |
| Deferred income tax | | 201 | | | (4) | | | 194 | | | | 227 | | | 450 | |
| Income tax | | $ | 803 | | | $ | 309 | | | $ | 951 | | | | $ | 1,601 | | | $ | 2,957 | |
| Earnings before taxes | | $ | 3,147 | | | $ | 1,772 | | | $ | 3,765 | | | | $ | 7,207 | | | $ | 12,374 | |
Effective tax rate on net earnings (2) | | 26% | | 17% | | 25% | | | 22% | | 24% |
| | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except effective tax rates) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Income tax | | $ | 803 | | | $ | 309 | | | $ | 951 | | | | $ | 1,601 | | | $ | 2,957 | |
Tax effect on non-operating items (3) | | 4 | | | 2 | | | (15) | | | | 14 | | | (16) | |
| Current PRT – North Sea | | — | | | 5 | | | 36 | | | | 45 | | | 37 | |
| Deferred PRT – North Sea | | (6) | | | (11) | | | — | | | | (24) | | | — | |
| Other taxes | | (3) | | | (3) | | | (3) | | | | (9) | | | (13) | |
| Effective tax on adjusted net earnings | | $ | 798 | | | $ | 302 | | | $ | 969 | | | | $ | 1,627 | | | $ | 2,965 | |
Adjusted net earnings from operations (4) | | $ | 2,850 | | | $ | 1,256 | | | $ | 3,493 | | | | $ | 5,987 | | | $ | 10,669 | |
Adjusted net earnings from operations, before taxes | | $ | 3,648 | | | $ | 1,558 | | | $ | 4,462 | | | | $ | 7,614 | | | $ | 13,634 | |
Effective tax rate on adjusted net earnings from operations (5) (6) | | 22% | | 19% | | 22% | | | 21% | | 22% |
(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 tax effect of PSUs, unrealized risk management, and abandonment expenditure recovery in adjusted net earnings from operations.
(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, 2023 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 corporate income tax and current and deferred PRT in the North Sea for the three and nine months ended September 30, 2023 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 | 22 | Three and nine months ended September 30, 2023 |
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
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Exploration and Evaluation | | | | | | | | | | | |
Net expenditures | | $ | (2) | | | $ | 9 | | | $ | 2 | | | | $ | 35 | | | $ | 25 | |
Net property (dispositions) acquisitions | | (1) | | | (2) | | | 1 | | | | (3) | | | (1) | |
Total Exploration and Evaluation | | (3) | | | 7 | | | 3 | | | | 32 | | | 24 | |
Property, Plant and Equipment | | | | | | | | | | | |
Net property acquisitions | | 8 | | | 17 | | | 1 | | | | 25 | | | 513 | |
Well drilling, completion and equipping | | 352 | | | 443 | | | 410 | | | | 1,305 | | | 1,138 | |
Production and related facilities | | 301 | | | 354 | | | 378 | | | | 1,016 | | | 882 | |
Other | | 18 | | | 19 | | | 15 | | | | 48 | | | 44 | |
Total Property, Plant and Equipment | | 679 | | | 833 | | | 804 | | | | 2,394 | | | 2,577 | |
Total Exploration and Production | | 676 | | | 840 | | | 807 | | | | 2,426 | | | 2,601 | |
Oil Sands Mining and Upgrading | | | | | | | | | | | |
Project costs | | 112 | | | 106 | | | 77 | | | | 270 | | | 196 | |
Sustaining capital | | 286 | | | 480 | | | 223 | | | | 1,027 | | | 804 | |
Turnaround costs | | 18 | | | 132 | | | 18 | | | | 172 | | | 271 | |
| | | | | | | | | | | |
Net property acquisitions | | 6 | | | — | | | — | | | | 6 | | | — | |
Other | | 2 | | | 1 | | | 3 | | | | 4 | | | 6 | |
Total Oil Sands Mining and Upgrading | | 424 | | | 719 | | | 321 | | | | 1,479 | | | 1,277 | |
Midstream and Refining | | 1 | | | 2 | | | 2 | | | | 6 | | | 7 | |
Head office | | 7 | | | 8 | | | 5 | | | | 23 | | | 18 | |
Abandonment expenditures, net (2) | | 123 | | | 100 | | | 114 | | | | 360 | | | 251 | |
Net capital expenditures | | $ | 1,231 | | | $ | 1,669 | | | $ | 1,249 | | | | $ | 4,294 | | | $ | 4,154 | |
By Segment | | | | | | | | | | | |
North America | | $ | 629 | | | $ | 778 | | | $ | 736 | | | | $ | 2,291 | | | $ | 2,456 | |
North Sea | | 14 | | | 5 | | | 40 | | | | 22 | | | 78 | |
Offshore Africa | | 33 | | | 57 | | | 31 | | | | 113 | | | 67 | |
Oil Sands Mining and Upgrading | | 424 | | | 719 | | | 321 | | | | 1,479 | | | 1,277 | |
Midstream and Refining | | 1 | | | 2 | | | 2 | | | | 6 | | | 7 | |
Head office | | 7 | | | 8 | | | 5 | | | | 23 | | | 18 | |
| | | | | | | | | | | |
Abandonment expenditures, net (2) | | 123 | | | 100 | | | 114 | | | | 360 | | | 251 | |
Net capital expenditures | | $ | 1,231 | | | $ | 1,669 | | | $ | 1,249 | | | | $ | 4,294 | | | $ | 4,154 | |
(1)Net capital expenditures exclude the impact of lease assets and fair value and revaluation adjustments, and include non-cash transfers of property, plant and equipment to inventory due to change in use.
(2)Non-GAAP Financial Measure. 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 | 23 | Three and nine months ended September 30, 2023 |
Net capital expenditures for the nine months ended September 30, 2023 were $4,294 million compared with $4,154 million for the nine months ended September 30, 2022. Net capital expenditures for the nine months ended September 30, 2023 included base capital expenditures (1) of $3,522 million and strategic growth capital expenditures (1) of $744 million, in accordance with the Company's capital budget.
2023 Capital Budget
On November 30, 2022, the Company announced its 2023 base capital budget (2) targeted at approximately $4,190 million. The budget also includes incremental strategic growth capital of approximately $1,020 million that targets to add additional production and capacity growth beyond 2023 in the Company's Exploration and Production segments, and long life low decline thermal in situ and Oil Sands Mining and Upgrading assets.
On August 2, 2023, the 2023 capital budget in Oil Sands Mining and Upgrading and North America E&P was increased by a combined $200 million compared to the original budget. Oil Sands Mining and Upgrading was increased by approximately $130 million primarily reflecting increased third-party service costs and scope changes relating to sustaining activities to ensure safe and effective operations. The remaining approximately $70 million relates to North America E&P and thermal operations largely as a result of increased non-operated and workover activity as well as inflationary pressures. The Company's 2023 targeted total capital program has increased by 4% to approximately $5,400 million.
The 2023 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
Drilling Activity (1) (2)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
(number of net wells) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | Sep 30
2023 | | Sep 30
2022 |
Net successful crude oil wells (3) | | 44 | | | 52 | | | 98 | | | 179 | | | 237 | |
Net successful natural gas wells | | 10 | | | 21 | | | 14 | | | 52 | | | 57 | |
Dry wells | | — | | | — | | | — | | | 2 | | | 1 | |
Total | | 54 | | | 73 | | | 112 | | | 233 | | | 295 | |
Success rate | | 100% | | 100% | | 100% | | 99% | | 99% |
(1)Includes drilling activity for North America and International segments.
(2)In addition, during the third quarter of 2023, on a net basis, the Company drilled 4 service wells in the Company's Oil Sands Mining and Upgrading segment, and 1 service well in the Company's thermal oil projects. During the nine months ended September 30, 2023, on a net basis, the Company drilled 334 stratigraphic and 11 service wells in the Oil Sands Mining and Upgrading segment, 24 stratigraphic and 43 service wells in the Company's thermal oil projects, and 2 service wells in the Northern Plains region.
(3)Includes bitumen wells.
North America
During the third quarter of 2023, the Company drilled 10 net natural gas wells, 34 net primary heavy crude oil wells, 2 net bitumen (thermal oil) wells, and 8 net light crude oil wells.
(1)Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures.
(2)Forward looking non-GAAP Financial Measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures.
| | | | | | | | |
| Canadian Natural Resources Limited | 24 | Three and nine months ended September 30, 2023 |
LIQUIDITY AND CAPITAL RESOURCES
| | | | | | | | | | | | | | | | | | | | | | | | | | |
($ millions, except ratios) | | Sep 30
2023 | | Jun 30
2023 | | Dec 31
2022 | | Sep 30
2022 |
Adjusted working capital (1) | | $ | 866 | | | $ | (293) | | | $ | (1,190) | | | $ | (606) | |
Long-term debt, net (2) | | $ | 11,519 | | | $ | 12,033 | | | $ | 10,525 | | | $ | 12,384 | |
Shareholders' equity | | $ | 39,634 | | | $ | 38,644 | | | $ | 38,175 | | | $ | 38,139 | |
| | | | | | | | |
Debt to book capitalization (2) | | 22.5% | | 23.7% | | 21.6% | | 24.5% |
After-tax return on average capital employed (3) | | 15.0% | | 15.8% | | 22.1% | | 24.0% |
(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, 2023, 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 is 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, 2022. 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 maintenance and growth 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:
◦During the third quarter of 2023, the Company extended its revolving credit facility originally maturing February 2024 to February 2025.
◦During the second quarter of 2023, the Company extended its revolving syndicated credit facility originally maturing June 2024 to June 2027.
◦Borrowings under the Company's revolving credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers' acceptances, 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.
◦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, replacing the Company's previous base shelf prospectus which would have expired in August 2023. 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 | 25 | Three and nine months ended September 30, 2023 |
◦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, replacing the Company's previous base shelf prospectus which would have expired in August 2023. 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.
As at September 30, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,140 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At September 30, 2023, the Company had $202 million 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 $11,519 million as at September 30, 2023, resulting in a debt to book capitalization ratio (1) of 22.5% (December 31, 2022 – 21.6%); this ratio was below the 25% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flows from operating activities are greater than current investment activities. 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, 2023 are discussed in note 8 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, 2023, the Company was in compliance with this covenant.
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, 2023, 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) | $ | 1,604 | | | $ | 1,624 | | | $ | 2,358 | | | $ | 6,121 | |
Other long-term liabilities (2) | $ | 220 | | | $ | 172 | | | $ | 425 | | | $ | 672 | |
Interest and other financing expense (3) | $ | 608 | | | $ | 542 | | | $ | 1,365 | | | $ | 3,476 | |
(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, $216 million; one to less than two years, $172 million; two to less than five years, $425 million; and thereafter, $672 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, 2023.
Share Capital
As at September 30, 2023, there were 1,087,326,000 common shares outstanding (December 31, 2022 – 1,102,636,000 common shares) and 28,682,000 stock options outstanding (December 31, 2022 - 31,150,000). As at October 31, 2023, the Company had 1,082,415,000 common shares outstanding and 28,344,000 stock options outstanding.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share, beginning with the dividend payable on January 5, 2024. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share. On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share. On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share, from $0.5875 per common share. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
(1)Capital management measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
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| Canadian Natural Resources Limited | 26 | Three and nine months ended September 30, 2023 |
On March 8, 2023, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, up to 92,296,006 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2023 and ending March 12, 2024.
For the nine months ended September 30, 2023, the Company purchased 22,500,000 common shares at a weighted average price of $78.64 per common share for a total cost of $1,769 million. Retained earnings were reduced by $1,553 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to September 30, 2023, up to and including October 31, 2023, the Company purchased 5,150,000 common shares at a weighted average price of $88.40 per common share for a total cost of $455 million.
COMMITMENTS AND CONTINGENCIES
In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company's commitments as at September 30, 2023:
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| ($ millions) | Remaining 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | Thereafter |
Product transportation and processing (1) | $ | 299 | | | $ | 1,406 | | | $ | 1,292 | | | $ | 1,169 | | | $ | 1,118 | | | $ | 11,423 | |
North West Redwater Partnership service toll (2) | $ | 38 | | | $ | 158 | | | $ | 156 | | | $ | 139 | | | $ | 125 | | | $ | 5,092 | |
Offshore vessels and equipment | $ | 11 | | | $ | 35 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Field equipment and power | $ | 15 | | | $ | 27 | | | $ | 25 | | | $ | 23 | | | $ | 22 | | | $ | 215 | |
| Other | $ | 6 | | | $ | 46 | | | $ | 41 | | | $ | 35 | | | $ | — | | | $ | — | |
(1)The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion ("TMX") is subject to change pending approval of the interim toll filing by the Canada Energy Regulator.
(2)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 $3,014 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.
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, 2022.
CONTROL ENVIRONMENT
There have been no changes to internal control over financial reporting ("ICFR") during the nine months ended September 30, 2023 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.
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| Canadian Natural Resources Limited | 27 | Three and nine months ended September 30, 2023 |
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 or cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the 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. 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.
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| | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Net earnings | | $ | 2,344 | | | $ | 1,463 | | | $ | 2,814 | | | | $ | 5,606 | | | $ | 9,417 | |
Share-based compensation, net of tax (1) | | 295 | | | 66 | | | (8) | | | | 423 | | | 471 | |
Unrealized risk management loss (gain), net of tax (2) | | 2 | | | (2) | | | (37) | | | | 16 | | | (36) | |
Unrealized foreign exchange loss (gain), net of tax (3) | | 250 | | | (231) | | | 785 | | | | 16 | | | 1,055 | |
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Realized foreign exchange gain on settlement of cross currency swap, net of tax (4) | | — | | | — | | | — | | | | — | | | (69) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Gain from investments, net of tax (5) | | (41) | | | (40) | | | (36) | | | | (74) | | | (94) | |
| | | | | | | | | | | |
Other, net of tax (6) | | — | | | — | | | (25) | | | | — | | | (75) | |
Non-operating items, net of tax | | 506 | | | (207) | | | 679 | | | | 381 | | | 1,252 | |
Adjusted net earnings from operations | | $ | 2,850 | | | $ | 1,256 | | | $ | 3,493 | | | | $ | 5,987 | | | $ | 10,669 | |
(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, 2023 was an expense of $298 million (three months ended June 30, 2023 – $70 million expense, three months ended September 30, 2022 – $4 million recovery; nine months ended September 30, 2023 – $434 million expense, nine months ended September 30, 2022 – $485 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 for the three months ended September 30, 2023 was $3 million (three months ended June 30, 2023 – $4 million gain, three months ended September 30, 2022 – $48 million gain; nine months ended September 30, 2023 – $19 million loss, nine months ended September 30, 2022 – $43 million gain).
(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 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the US$1,100 million 6.25% US dollar debt securities due March 2038. The Company realized cash proceeds of $158 million on settlement. Pre- and after-tax amounts for the realized foreign exchange gain on settlement of the swap are the same.
(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. There is zero net tax impact on these gains and losses from investments.
(6)Other relates to the impact of government grant income under the provincial well-site rehabilitation programs. Pre-tax other for the three months ended September 30, 2023 was $nil (three months ended June 30, 2023 – $nil, three months ended September 30, 2022 – $33 million; nine months ended September 30, 2023 – $nil, nine months ended September 30, 2022 – $98 million).
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| Canadian Natural Resources Limited | 28 | Three and nine months ended September 30, 2023 |
Adjusted Funds Flow
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment, repay debt, and provide returns to shareholders through dividends and share buybacks. A reconciliation for adjusted funds flow, from cash flows from operating activities is presented below.
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| | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Cash flows from operating activities | | $ | 3,498 | | | $ | 2,745 | | | $ | 6,098 | | | | $ | 7,538 | | | $ | 14,847 | |
Net change in non-cash working capital | | 1,088 | | | (17) | | | (1,024) | | | | 2,979 | | | 438 | |
Abandonment expenditures, net (1) | | 123 | | | 100 | | | 114 | | | | 360 | | | 251 | |
Movements in other long-term assets (2) | | (25) | | | (86) | | | 20 | | | | (22) | | | 79 | |
Adjusted funds flow | | $ | 4,684 | | | $ | 2,742 | | | $ | 5,208 | | | | $ | 10,855 | | | $ | 15,615 | |
(1)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the "Abandonment Expenditures, net" section below.
(2)Includes the unamortized cost of the share bonus program.
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 14 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.
Abandonment Expenditures, net
Abandonment expenditures, net, is a non-GAAP financial measure that represents the abandonment expenditures to settle asset retirement obligations as reflected in the Company's annual capital budget. Abandonment expenditures, net is calculated as abandonment expenditures, as presented in the Company's consolidated Statements of Cash Flows, adjusted for the impact of government grant income under the provincial well-site rehabilitation programs. A reconciliation of abandonment expenditures, net is presented below.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Abandonment expenditures | | $ | 123 | | | $ | 100 | | | $ | 147 | | | | $ | 360 | | | $ | 349 | |
| Government grants for abandonment expenditures | | — | | | — | | | (33) | | | | — | | | (98) | |
| Abandonment expenditures, net | | $ | 123 | | | $ | 100 | | | $ | 114 | | | | $ | 360 | | | $ | 251 | |
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 17 to the financial statements.
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| Canadian Natural Resources Limited | 29 | Three and nine months ended September 30, 2023 |
Realized Price ($/bbl and $/BOE) – Exploration and Production
Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE sales include the impact of blending and feedstock costs and other by-product sales. The Company considers realized price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market for its crude oil and NGLs sales volumes and BOE sales volumes.
Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized price are presented below.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except bbl/d and $/bbl) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs (bbl/d) | | | | | | | | | | | |
| North America | | 516,038 | | | 466,284 | | | 469,532 | | | | 487,917 | | | 479,936 | |
| International | | | | | | | | | | | |
| North Sea | | 7,839 | | | 19,991 | | | 4,229 | | | | 9,305 | | | 10,642 | |
| Offshore Africa | | 12,769 | | | 18,603 | | | 13,020 | | | | 13,931 | | | 15,137 | |
| Total International | | 20,608 | | | 38,594 | | | 17,249 | | | | 23,236 | | | 25,779 | |
| Total sales volumes | | 536,646 | | | 504,878 | | | 486,781 | | | | 511,153 | | | 505,715 | |
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Crude oil and NGLs sales (1) | | $ | 5,351 | | | $ | 4,405 | | | $ | 4,813 | | | | $ | 13,597 | | | $ | 17,567 | |
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Less: Blending and feedstock costs (2) | | 1,014 | | | 1,094 | | | 1,010 | | | | 3,346 | | | 4,037 | |
Realized crude oil and NGLs sales | | $ | 4,337 | | | $ | 3,311 | | | $ | 3,803 | | | | $ | 10,251 | | | $ | 13,530 | |
Realized price ($/bbl) | | $ | 87.83 | | | $ | 72.06 | | | $ | 84.91 | | | | $ | 73.45 | | | $ | 97.99 | |
(1)Crude oil and NGLs sales in note 17 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.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except BOE/d and $/BOE) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Barrels of oil equivalent (BOE/d) | | | | | | | | | | | |
| North America | | 872,555 | | | 811,590 | | | 822,257 | | | | 840,032 | | | 824,102 | |
| International | | | | | | | | | | | |
| North Sea | | 8,022 | | | 20,269 | | | 4,447 | | | | 9,598 | | | 10,977 | |
| Offshore Africa | | 14,530 | | | 20,436 | | | 15,339 | | | | 15,651 | | | 17,527 | |
| Total International | | 22,552 | | | 40,705 | | | 19,786 | | | | 25,249 | | | 28,504 | |
| Total sales volumes | | 895,107 | | | 852,295 | | | 842,043 | | | | 865,281 | | | 852,606 | |
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Barrels of oil equivalent sales (1) | | $ | 5,908 | | | $ | 4,884 | | | $ | 6,100 | | | | $ | 15,455 | | | $ | 21,320 | |
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Less: Blending and feedstock costs (2) | | 1,014 | | | 1,094 | | | 1,010 | | | | 3,346 | | | 4,037 | |
Less: Sulphur expense (income) | | 1 | | | (5) | | | (25) | | | | (12) | | | (85) | |
Realized barrels of oil equivalent sales | | $ | 4,893 | | | $ | 3,795 | | | $ | 5,115 | | | | $ | 12,121 | | | $ | 17,368 | |
Realized price ($/BOE) | | $ | 59.40 | | | $ | 48.94 | | | $ | 66.04 | | | | $ | 51.31 | | | $ | 74.62 | |
(1)Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 17 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.
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| Canadian Natural Resources Limited | 30 | Three and nine months ended September 30, 2023 |
Transportation – Exploration and Production
Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products to the market excluding the impact of blending costs. A reconciliation for Exploration and Production transportation and the calculations for transportation on a per unit basis are presented below.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except $ per unit amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Transportation, blending and feedstock (1) | | $ | 1,326 | | | $ | 1,413 | | | $ | 1,292 | | | | $ | 4,285 | | | $ | 4,895 | |
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| Less: Blending and feedstock costs | | 1,014 | | | 1,094 | | | 1,010 | | | | 3,346 | | | 4,037 | |
| | | | | | | | | | | |
| Transportation | | $ | 312 | | | $ | 319 | | | $ | 282 | | | | $ | 939 | | | $ | 858 | |
Transportation ($/BOE) | | $ | 3.78 | | | $ | 4.11 | | | $ | 3.64 | | | | $ | 3.97 | | | $ | 3.68 | |
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| Amounts attributed to crude oil and NGLs | | $ | 200 | | | $ | 210 | | | $ | 184 | | | | $ | 610 | | | $ | 571 | |
Transportation ($/bbl) | | $ | 4.07 | | | $ | 4.57 | | | $ | 4.10 | | | | $ | 4.37 | | | $ | 4.14 | |
| Amounts attributed to natural gas | | $ | 112 | | | $ | 109 | | | $ | 98 | | | | $ | 329 | | | $ | 287 | |
Transportation ($/Mcf) | | $ | 0.56 | | | $ | 0.58 | | | $ | 0.51 | | | | $ | 0.56 | | | $ | 0.50 | |
(1)Transportation, blending and feedstock in note 17 to the financial statements.
North America – Realized Product Prices and Royalties
Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial measure) divided by sales volumes. Realized crude oil and NGLs sales include the impact of blending costs. The Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.
Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it describes the Company's royalties for crude oil and NGLs sales volumes on a per unit basis.
A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices and the royalty rates are presented below.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except $/bbl and royalty rates) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs sales (1) | | $ | 5,135 | | | $ | 4,040 | | | $ | 4,622 | | | | $ | 12,924 | | | $ | 16,631 | |
Less: Blending and feedstock costs (2) | | 1,014 | | | 1,094 | | | 1,010 | | | | 3,346 | | | 4,037 | |
Realized crude oil and NGLs sales | | $ | 4,121 | | | $ | 2,946 | | | $ | 3,612 | | | | $ | 9,578 | | | $ | 12,594 | |
Realized crude oil and NGLs prices ($/bbl) | | $ | 86.77 | | | $ | 69.44 | | | $ | 83.62 | | | | $ | 71.90 | | | $ | 96.11 | |
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Crude oil and NGLs royalties (3) | | $ | 845 | | | $ | 491 | | | $ | 854 | | | | $ | 1,773 | | | $ | 2,820 | |
| Crude oil and NGLs royalty rates | | 21% | | 17% | | 24% | | | 19% | | 22% |
(1)Crude oil and NGLs sales in note 17 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 17 to the financial statements.
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| Canadian Natural Resources Limited | 31 | Three and nine months ended September 30, 2023 |
Realized Product Prices and Transportation – Oil Sands Mining and Upgrading
Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure) including the impact of blending and feedstock costs, divided by SCO sales volumes. The Company considers realized SCO sales price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its SCO sales volumes.
Transportation ($/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.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except for bbl/d and $/bbl) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| | | | | | | | | | | |
| SCO sales volumes (bbl/d) | | 492,926 | | | 350,041 | | | 489,146 | | | | 435,109 | | | 427,165 | |
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Crude oil and NGLs sales (1) | | $ | 5,591 | | | $ | 3,546 | | | $ | 6,056 | | | | $ | 13,619 | | | $ | 15,869 | |
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| Less: Blending and feedstock costs | | 670 | | | 517 | | | 615 | | | | 1,674 | | | 1,589 | |
| Realized SCO sales | | $ | 4,921 | | | $ | 3,029 | | | $ | 5,441 | | | | $ | 11,945 | | | $ | 14,280 | |
| Realized SCO sales price ($/bbl) | | $ | 108.55 | | | $ | 95.08 | | | $ | 120.91 | | | | $ | 100.57 | | | $ | 122.45 | |
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Transportation, blending and feedstock (2) | | $ | 768 | | | $ | 582 | | | $ | 684 | | | | $ | 1,900 | | | $ | 1,785 | |
Less: Blending and feedstock costs | | 670 | | | 517 | | | 615 | | | | 1,674 | | | 1,589 | |
Transportation | | $ | 98 | | | $ | 65 | | | $ | 69 | | | | $ | 226 | | | $ | 196 | |
| Transportation ($/bbl) | | $ | 2.18 | | | $ | 2.03 | | | $ | 1.55 | | | | $ | 1.91 | | | $ | 1.69 | |
(1)Crude oil and NGLs sales in note 17 to the financial statements.
(2)Transportation, blending and feedstock in note 17 to the financial statements.
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 abandonment expenditures including the impact of government grant income under the provincial well-site rehabilitation programs. 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.
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| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| Cash flows used in investing activities | | $ | 1,199 | | | $ | 1,560 | | | $ | 1,129 | | | | $ | 3,912 | | | $ | 3,725 | |
| Net change in non-cash working capital | | (91) | | | 9 | | | 6 | | | | 22 | | | 178 | |
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| Capital expenditures | | 1,108 | | | 1,569 | | | 1,135 | | | | 3,934 | | | 3,903 | |
Abandonment expenditures, net (1) | | 123 | | | 100 | | | 114 | | | | 360 | | | 251 | |
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Net capital expenditures (2) | | $ | 1,231 | | | $ | 1,669 | | | $ | 1,249 | | | | $ | 4,294 | | | $ | 4,154 | |
(1)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the "Abandonment Expenditures, net" section above.
(2)For the nine months ended September 30, 2023 includes base capital expenditures of $3,522 million, and strategic growth capital expenditures of $744 million. Strategic growth capital expenditures represent the allocation of the Company's free cash flow that will be directed to strategic capital growth opportunities that target to increase production volumes in future periods and that exceed the Company's base capital expenditures for the current fiscal year, as outlined in the Company's capital budget.
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| Canadian Natural Resources Limited | 32 | Three and nine months ended September 30, 2023 |
Liquidity
Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities, cash and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing the Company's financial position. The Company's calculation of liquidity is presented below.
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($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Dec 31
2022 | | Sep 30
2022 | |
| Undrawn bank credit facilities | | $ | 5,450 | | | $ | 4,954 | | | $ | 5,520 | | | $ | 5,520 | | |
| Cash and cash equivalents | | 125 | | | 122 | | | 920 | | | 565 | | |
Investments | | 565 | | | 524 | | | 491 | | | 403 | | |
Liquidity | | $ | 6,140 | | | $ | 5,600 | | | $ | 6,931 | | | $ | 6,488 | | |
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 13 to the financial statements.
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 13 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.
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($ millions, except ratios) | | Sep 30
2023 | | Jun 30
2023 | | Dec 31
2022 | | Sep 30
2022 | |
| Interest adjusted after-tax return: | | | | | | | | | |
| Net earnings, 12 months trailing | | $ | 7,126 | | | $ | 7,596 | | | $ | 10,937 | | | $ | 11,951 | | |
Interest and other financing expense, net of tax, 12 months trailing (1) | | 459 | | | 431 | | | 424 | | | 497 | | |
| Interest adjusted after-tax return | | $ | 7,585 | | | $ | 8,027 | | | $ | 11,361 | | | $ | 12,448 | | |
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12 months average current portion long-term debt (2) | | $ | 1,337 | | | $ | 1,274 | | | $ | 1,359 | | | $ | 1,478 | | |
12 months average long-term debt (2) | | 10,706 | | | 10,961 | | | 11,761 | | | 12,707 | | |
12 months average common shareholders' equity (2) | | 38,635 | | | 38,577 | | | 38,218 | | | 37,688 | | |
| 12 months average capital employed | | $ | 50,678 | | | $ | 50,812 | | | $ | 51,338 | | | $ | 51,873 | | |
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| After-tax return on average capital employed | | 15.0% | | 15.8% | | 22.1% | | 24.0% | |
(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.
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| Canadian Natural Resources Limited | 33 | Three and nine months ended September 30, 2023 |
