Canadian Natural Resources
Annual Report 2023

Plain-text annual report

2 0 2 3 A N N U A L R E P O R T 2 0 2 3 A N N U A L R E P O R T C A N A D I A N N A T U R A L 2023 Performance Highlights Canadian Natural's unique, diverse and balanced portfolio of assets provides us with flexible capital allocation, maximizing value for our shareholders. In 2023, the Company focused on effective and efficient operations and achieved record production, which delivered strong financial results, significant returns to shareholders and reserves growth in the year. FINANCIAL ($ millions, except per common share amounts) Product sales (1) Net earnings Per common share – basic                                     – diluted Adjusted net earnings from operations (2) Per common share – basic (3)                                     – diluted (3) Cash flows from operating activities Adjusted funds flow (2) Per common share – basic (3) – diluted (3) Cash flows used in investing activities Net capital expenditures (4) Abandonment expenditures, net (2) Long-term debt, net (5) Shareholders' equity Debt to book capitalization (5) 2023 2022 2021 40,835 $ 49,530 $ 32,854 8,233 $ 10,937 $ 7,664 7.54 $ 7.47 $ 9.64 $ 9.52 $ 6.49 6.46 8,533 $ 12,863 $ 7,420 7.82 $ 7.74 $ 11.33 $ 11.19 $ 12,353 $ 19,391 $ 15,274 $ 19,791 $ 14.00 $ 13.86 $ 4,858 $ 4,909 $ 509 $ 17.44 $ 17.22 $ 4,987 $ 5,136 $ 335 $ 9,922 $ 10,525 $ 39,832 $ 38,175 $ 20% 22% 6.28 6.25 14,478 13,733 11.63 11.57 3,703 4,676 232 13,950 36,945 27% $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1) Further details related to product sales are disclosed in the "Segmented Information" note to the Company's audited consolidated financial statements. (2) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual Management's Discussion and Analysis ("MD&A") included in this annual report. (3) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. (4) Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. (5) Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. Cover: Albian Extraction – Photo by D. Londo. TABLE OF CONTENTS 01 03 06 09 56 57 1 2023 Performance Highlights Letter to Shareholders 2023 Year End Reserves Management's Discussion and Analysis Consolidated Financial Statements Management's Report 58 59 65 97 107 109 Management's Assessment of Internal Control over Financial Reporting Report of Independent Registered Public Accounting Firm Notes to the Consolidated Financial Statements Supplementary Oil and Gas Information Ten Year Review Corporate Information Canadian Natural 2023 Annual Report OPERATING Daily production, before royalties (1) Crude oil and NGLs (Mbbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Barrels of oil equivalent (MBOE/d) (2) Drilling activity (3) North America North Sea Offshore Africa 2023 2022 2021 496 451 13 13 974 480 426 13 14 933 473 448 18 14 952 2,139 2,075 1,680 2 10 2,151 1,332 284 — — 284 2 13 2,090 1,281 390 — — 390 3 12 1,695 1,235 193 6 — 199 (1) Numbers may not add due to rounding. (2) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, 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. (3) Net wells. Excludes net stratigraphic test and service wells. 1,332,105 BOE/D RECORD PRODUCTION 78% OF TOTAL LIQUIDS PRODUCTION IS LONG LIFE LOW DECLINE Canadian Natural 2023 Annual Report 2 Letter to Shareholders In 2023, we delivered on our capital allocation strategy by strengthening our balance sheet, providing significant returns to shareholders and strategically developing our assets. Our culture of continuous improvement, focus on cost control and disciplined capital allocation continues to drive strong operational and financial results, maximizing value for our shareholders. We achieved record annual average daily production of 1,332 MBOE/d in 2023, an increase of 4% from 2022 levels, or 7% growth on a production per share basis. We delivered strong financial results in 2023, including adjusted funds flow of $15.3 billion and significant free cash flow(1) of approximately $6.9 billion. In the past three years, we have reduced our net debt by over $11  billion and delivered approximately $21.5  billion directly to shareholders through $11.0  billion in dividends and $10.5 billion in share repurchases. These impressive results delivered returns to shareholders of approximately $30 per share through debt reductions and shareholder distributions over the three year time period. We ended 2023 with approximately $9.9 billion in net debt, achieving our net debt level of $10 billion. As per our free cash flow allocation policy, we will now target to return 100% of free cash flow to shareholders through dividends and share buybacks. In 2023, the Board of Directors approved two separate increases to our quarterly dividend, for a combined increase of 18% to $1.00 per common share. Subsequent to year end, in February of 2024, the Board of Directors approved an additional 5% increase to the quarterly dividend to $1.05 per common share, or $4.20 per common share on an annual basis, demonstrating the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline asset base. The Company has a leading track record of 24 consecutive years of dividend increases, with a compound annual growth rate of 21% over that time period. In February 2024, our Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to receipt of shareholder approval and all necessary regulatory approvals, including approval from the Toronto Stock Exchange. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024. One of Canadian Natural's strengths is the diversity of our world class assets, which have been strategically assembled and developed over several decades. Our top tier assets have a low decline rate as well as low maintenance capital relative to the size and quality of our reserves, which affords us significant flexibility when balancing our four pillars of capital allocation: returns to shareholders, balance sheet strength, resource value growth and opportunistic acquisitions. We delivered on our capital allocation strategy in 2023, through our disciplined and flexible approach to planning with a goal of safe, reliable, effective and efficient operations, maximizing value for our shareholders. Our significant reserves base provides us with a key advantage, with total proved reserves of 13.9 billion BOE and total proved plus probable reserves of 18.5 billion BOE as of year end 2023, which increased 2% and 3% respectively from year end 2022 levels. The increase in our reserves reflects the success of our capital efficient development opportunities across our asset base with reserve replacement ratios of 166% and 194% on a total proved and total proved plus probable basis respectively. With approximately 75% of the Company's total proved reserves being long life low decline, the strength and depth of our assets is evident and provides us with a total proved reserves life index of 32 years and a total proved plus probable reserves life index of 43 years. ~$7.2 BILLION RETURNED TO SHAREHOLDERS IN 2023 ACHIEVED NET DEBT OF ~$10 BILLION 3 Canadian Natural 2023 Annual Report N. MURRAY EDWARDS Executive Chairman TIM S. MCKAY Vice Chairman SCOTT G. STAUTH President MARK A. STAINTHORPE Chief Financial Officer Canadian Natural is committed to supplying safe, reliable and responsible energy, along with reducing our environmental footprint. We incorporate environmental, social and governance practices that strengthen our long-term sustainability across all aspects of our business and are uniquely positioned with diverse, long life low decline assets which are ideal for piloting and applying technologies that reduce greenhouse gas ("GHG") emissions and provide industry leading environmental performance. We are committed to supporting Canada's and Alberta's climate goals and continue to reduce our environmental footprint with our robust environmental targets, including net zero GHG emissions in the oil sands by 2050. It is important to continue working together with the Canadian and Alberta governments to make the Pathways Alliance a transformative industry collaboration and achieve meaningful GHG reductions in Canada. We believe Canadian energy is one of the most responsibly produced sources of energy in the world and should be the preferred choice of energy. Canadian Natural has robust environmental targets and a defined pathway to achieve long-term emissions reductions. Our integrated GHG emissions management strategy includes ongoing investments in technology and innovation, while leveraging technology across the Company. Our environmental areas of focus include, but are not limited to: carbon capture, sequestration/storage and utilization, the use of solvents, energy/steam efficiencies, methane reduction, and tailings and water management. We are also an industry leader in abandonment and reclamation activity. From 2019 to 2023, we have abandoned 11,368 inactive wells and received 4,712 reclamation certificates, representing 10,014 hectares of reclaimed land. We are committed to creating shared value in the communities where we operate in Canada, the United Kingdom and Africa. This group of stakeholders includes more than 24,000 landowners, over 160 municipalities and more than 80 Indigenous communities in Western Canada, as well as industry, governments, regulators, academia, and non-governmental groups. The Company works with these diverse communities to identify opportunities for education and training, employment, business development and community investment. In 2023, we worked with 221 Indigenous businesses through which approximately $830 million in contracts were awarded, a 21% increase from 2022 levels. Canadian Natural also has a strong commitment to corporate governance, which assures stakeholders that the Company always operates with the highest levels of integrity and ethical standards. Our strong execution in 2023 sets us up to continue delivering on our four pillars of capital allocation through our disciplined 2024 capital budget of approximately $5.4 billion. This budget is strategically weighted to longer cycle thermal development in the first half of 2024 and shorter cycle growth in the second half of the year, targeting strong exit production levels. As well it provides us with the flexibility to adjust to changing market egress and evolving market conditions, ensuring we are allocating capital effectively and maximizing value for our shareholders. We remain committed to sustainable, growing shareholder returns, a strong balance sheet and reducing our environmental footprint through innovative technology and continuous improvement, continuing to build upon its history of creating premium value for our shareholders. We would like to thank our employees and contractors for their hard work and commitment to deliver safe, reliable, effective and efficient operations across all areas of the business. Your commitment to operational excellence underpins the ongoing success of the business, while our culture of working together and continuous improvement positions Canadian Natural well to continue to drive long-term shareholder value. N. MURRAY EDWARDS Executive Chairman TIM S. MCKAY Vice Chairman SCOTT G. STAUTH MARK A. STAINTHORPE President Chief Financial Officer (1) Refer to page 5 and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for additional details. Canadian Natural 2023 Annual Report 4 NON-GAAP AND OTHER FINANCIAL MEASURES This report includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 – Non- GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position or cash flow and are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. These measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the Company's financial statements. FREE CASH FLOW POLICY IN 2023 AND 2024 Free cash flow is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company’s ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay debt, pursuant to the free cash flow allocation policy. The Company’s free cash flow is used to determine the target amount of shareholder returns after dividends and is currently in the form of share repurchases. The calculation in determining free cash flow varies depending on the Company’s net debt position as follows: ▪ ▪ Allocation of Free Cash Flow in 2024 The Company's free cash flow allocation policy is applied based on the Company's net debt level. As net debt of $10 billion was achieved at the end of 2023, the Company will now target to return 100% of free cash flow to shareholders in 2024 through dividends and share repurchases. Free cash flow is calculated as adjusted funds flow less net capital expenditures, abandonment expenditures, and dividends on common shares. The Company targets to manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required. Allocation of Free Cash Flow in 2023 When net debt was between $10 billion and $15 billion, as was the case in 2023, approximately 50% of free cash flow was allocated to shareholder returns and 50% was allocated to the balance sheet, less strategic growth/acquisition opportunities, with free cash flow calculated as adjusted funds flow less base capital expenditures, abandonment expenditures, and dividends on common shares. The Company's free cash flow for each of the years ended December 31, 2023, 2022 and 2021 is shown below and excludes strategic growth/acquisition capital per the Company's net debt position and the free cash flow allocation policy which existed at that time: ($ millions) Adjusted Funds Flow (1) Less: Base Capital Expenditures (2) Abandonment Expenditures, net (3) Dividends on Common Shares Free Cash Flow 2023 2022 2021 $ 15,274 $ 19,791 $ 13,733 3,958 509 3,891 3,621 335 4,926 $ 6,917 $ 10,909 $ 3,251 232 2,170 8,080 (1) Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the “Non-GAAP and Other Financial Measures” section of the Company's MD&A included in this annual report. (2) Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of Company's MD&A included in this annual report for more details on net capital expenditures. (3) Non-GAAP Financial Measure. In prior reporting periods, abandonment expenditures was reported as part of base capital; however, in Q4/23, the Company revised the composition of its net capital expenditures non-GAAP financial measure to exclude expenditures related to the Company's abandonment program. A reconciliation of abandonment expenditures and abandonment expenditures, net is presented in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A included in this annual report. CAPITAL BUDGET Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non- GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures. LONG-TERM DEBT, NET Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents. 5 Canadian Natural 2023 Annual Report 2023 Year End Reserves DETERMINATION OF RESERVES For the year ended December 31, 2023, Canadian Natural retained Independent Qualified Reserves Evaluators ("IQREs") to evaluate and review all of the Company’s proved and proved plus probable reserves. The Company retained Sproule Associates Limited for its North America Conventional and Thermal reserves evaluation and review, Sproule International Limited for its North Sea and Offshore Africa reserves evaluation, and GLJ Ltd. for its Oil Sands Mining and Upgrading reserves evaluation. The evaluation and review was conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs. The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with the IQREs as to the Company’s reserves. Additional reserves information is disclosed in the Company's Annual Information Form. RESERVES INFORMATION HIGHLIGHTS A key differentiator for Canadian Natural is the strength, diversity and balance of its world class, top tier assets. The Company's total proved reserve life index ("RLI")(1) of 32 years is supported by long life low decline assets that have been strategically assembled and developed over several decades. The low maintenance capital requirements relative to the size and quality of the reserves affords the Company significant flexibility when balancing its four pillars of capital allocation to maximize shareholder value. The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2023 (all reserves values are Company Gross unless stated otherwise). ▪ ▪ ▪ ▪ ▪ Total proved reserves increased 2% to 13.910 billion BOE, with reserves additions and revisions of 0.809 billion BOE. Total proved plus probable reserves increased 3% to 18.504  billion BOE, with reserves additions and revisions of 0.944 billion BOE. ◦ The strength and depth of the Company's assets are evident as approximately 75% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 32 years and a total proved plus probable BOE RLI of 43 years. – Additionally, high value, zero decline SCO represents approximately 50% of total proved reserves with a RLI of 44 years. In 2023, proved developed producing reserves additions and revisions were 540 million BOE, replacing 2023 production by 111%. The proved developed producing BOE RLI is 21 years. In 2023, total proved reserves additions and revisions replaced 2023 production by 166%. Total proved plus probable reserves additions and revisions replaced 2023 production by 194%. In 2023, Canadian Natural continued to achieve strong finding and development costs: ◦ ◦ Finding, development and acquisition ("FD&A")(1) costs, excluding changes in Future Development Cost ("FDC"), were $5.86/BOE for total proved reserves and $5.02/BOE for total proved plus probable reserves. FD&A costs, including changes in FDC, were $9.25/BOE for total proved reserves and $8.28/BOE for total proved plus probable reserves. At December 31, 2023, the net present value of future net revenues, before income tax, discounted at 10%, was $105.9 billion for proved developed producing reserves, $153.7 billion for total proved reserves, and $186.5 billion for total proved plus probable reserves. ◦ The Company's total proved net asset value (NAV) per share increased to $139.07 per share at December 31, 2023 from $131.79  per share at December 31, 2022 after adjusting for asset retirement obligations and net debt. Total proved plus probable NAV per share increased to $169.65 per share at December 31, 2023 from $161.53 per share at December 31, 2022. (1) Supplementary financial measure. Refer to the notes of the "2023 Year End Reserves" on page 8. Canadian Natural 2023 Annual Report 6 Summary of Company Gross Reserves as of December 31, 2023 Forecast Prices and Costs Light and Medium Crude Oil Primary Heavy Pelican Lake Heavy Crude Oil Crude Oil Bitumen (Thermal Oil) Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent Total Company Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) 114 5 100 218 87 305 106 7 80 193 95 288 203 — 55 258 107 365 653 38 2,596 3,287 1,903 5,191 6,827 4,730 138 8,829 — 83 229 10,045 6,910 15,005 550 9,279 7,460 24,284 7 398 543 305 848 95 4,986 13,910 4,594 18,504 Reconciliation of Company Gross Reserves as of December 31, 2023 Forecast Prices and Costs TOTAL PROVED Total Company December 31, 2022 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2023 TOTAL PROVED PLUS PROBABLE Total Company December 31, 2022 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2023 Light and Medium Crude Oil Primary Heavy Pelican Lake Heavy Crude Oil Crude Oil Bitumen (Thermal Oil) Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) 231 179 262 3,284 6,873 13,627 486 13,587 — 18 8 — — — 1 (12) (27) 218 — 22 6 — — — 1 13 (28) 193 — — — 1 — — 1 12 (17) — 68 — 6 — — 1 24 (96) — 5 191 1,246 — 34 — — — (23) (165) 638 — — (7) (81) 362 (785) 258 3,287 6,910 15,005 — 43 35 — — (1) (2) 3 1 548 156 40 — (2) (12) 77 (22) 543 (486) 13,910 Light and Medium Crude Oil Primary Heavy Pelican Lake Heavy Crude Oil Crude Oil Bitumen (Thermal Oil) Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) 320 272 376 5,186 7,408 22,270 772 18,046 — 28 12 — — — 1 (28) (27) 305 — 37 8 — — — 1 (2) (28) 288 — — — 1 — — 1 4 (17) 365 — 97 — 7 — — 1 (4) (96) — 7 209 2,009 — 51 — — — (43) (165) 962 — — (8) (88) (83) (785) 1 74 48 — — (1) (2) (21) (22) 2 780 227 58 — (2) (12) (108) (486) 5,191 7,460 24,284 848 18,504 7 Canadian Natural 2023 Annual Report NOTES TO RESERVES: 1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests. 2. Information in the reserves data tables may not add due to rounding. BOE values and oil and gas metrics may not calculate exactly due to rounding. 3. Forecast pricing assumptions utilized by the IQREs in the reserves estimates are the 3-Consultant-Average of price forecasts developed by Sproule Associates Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2023: Crude Oil and NGLs WTI WCS Canadian Light Sweet Cromer LSB Edmonton C5+ Brent Natural Gas AECO US$/bbl C$/bbl C$/bbl C$/bbl C$/bbl US$/bbl C$/MMBtu BC Westcoast Station 2 C$/MMBtu Henry Hub US$/MMBtu 2024 2025 2026 2027 2028 73.67 76.74 92.91 93.57 96.79 78.00 2.20 2.06 2.75 74.98 79.77 95.04 95.86 76.14 81.12 96.07 96.46 77.66 82.88 97.99 79.22 85.04 99.95 98.39 100.36 98.75 100.71 102.72 104.78 79.18 80.36 81.79 83.41 3.37 3.25 3.64 4.05 3.93 4.02 4.13 4.01 4.10 4.21 4.09 4.18 All prices increase at a rate of 2% per year after 2028. A foreign exchange rate of 0.7517 US$/C$ for 2024 and 2025, and 0.7550 US$/C$ was used for 2026 and thereafter in the 2023 year end evaluation. 4. A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. 5. Oil and gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural’s performance over time. However, such measures are not reliable indicators of Canadian Natural’s future performance and future performance may vary. 6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production. 7. Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period. 8. Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2024 proved developed producing production forecast prepared by the IQREs. 9. Finding, Development and Acquisition ("FD&A") costs excluding changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2023 by the sum of total additions and revisions for the relevant reserves category. 10. FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2023 and net changes in FDC from December 31, 2022 to December 31, 2023 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs. 11. Abandonment, decommissioning and reclamation ("ADR") costs included in the calculation of the Future Net Revenue ("FNR") consist of both the Company's total Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as at December 31, 2023 and forecast estimates of ADR costs attributable to future development activity. Canadian Natural 2023 Annual Report 8 Management's Discussion and Analysis Table of Contents Definitions and Abbreviations Advisory Objectives and Strategy Financial and Operational Highlights Business Environment Analysis of Changes in Product Sales Daily Production Exploration and Production Oil Sands Mining and Upgrading Midstream and Refining Corporate and Other Net Capital Expenditures Liquidity and Capital Resources Commitments and Contingencies Reserves Risks and Uncertainties Environment Accounting Policies and Standards Control Environment Non-GAAP and Other Financial Measures Outlook Other 10 11 13 14 18 20 21 23 27 28 29 32 34 36 37 38 39 42 45 46 52 52 9 Canadian Natural 2023 Annual Report AECO AIF AOSP API ARO bbl bbl/d Bcf Bcf/d Bitumen BOE BOE/d Brent C$ CAGR CAPEX CO2 CO2e Crude oil CSS EOR E&P FASB FPSO GHG GJ GJ/d Definitions and Abbreviations Alberta natural gas reference location Annual Information Form Athabasca Oil Sands Project specific gravity measured in degrees on the American Petroleum Institute scale asset retirement obligations IFRS LNG Mbbl Mbbl/d MBOE International Financial Reporting Standards liquefied natural gas thousand barrels thousand barrels per day thousand barrels of oil equivalent MBOE/d thousand barrels of oil equivalent per day barrel barrels per day billion cubic feet billion cubic feet per day a naturally occurring solid or semi-solid hydrocarbon consisting mainly of heavier hydrocarbons that are too heavy or thick to flow at reservoir conditions, and recoverable at economic rates using thermal in situ recovery methods barrels of oil equivalent barrels of oil equivalent per day Dated Brent Canadian dollars compound annual growth rate capital expenditures carbon dioxide carbon dioxide equivalents includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil Cyclic Steam Stimulation Enhanced Oil Recovery Exploration and Production Financial Accounting Standards Board Floating Production, Storage and Offloading Vessel greenhouse gas gigajoules gigajoules per day Mcf Mcfe Mcf/d MMbbl MMBOE MMBtu MMcf thousand cubic feet thousand cubic feet equivalent thousand cubic feet per day million barrels million barrels of oil equivalent million British thermal units million cubic feet MMcf/d million cubic feet per day NGLs NWRP natural gas liquids North West Redwater Partnership NYMEX New York Mercantile Exchange NYSE OPEC+ PRT SAGD SCO SEC New York Stock Exchange Organization of the Petroleum Exporting Countries Plus Petroleum Revenue Tax Steam-Assisted Gravity Drainage synthetic crude oil United States  Securities and Exchange Commission SOFR Secured Overnight Financing Rate Tcf TSX UK US US$ trillion cubic feet Toronto Stock Exchange United Kingdom United States United States dollars US GAAP generally accepted accounting principles in the United States WCS Western Canadian Select WCS Heavy Differential WTI WCS Heavy Differential from WTI West Texas Intermediate location at Cushing, Oklahoma reference Horizon Horizon Oil Sands IASB IBOR International Accounting Standards Board Interbank Offered Rate Canadian Natural 2023 Annual Report 10 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 abandonment of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil production, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); 11 Canadian Natural 2023 Annual Report asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses. The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available. Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this 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, PRODUCTION AND RESERVES This MD&A should be read in conjunction with the audited consolidated financial statements for the year ended   December  31, 2023. It should also be read in conjunction with the Company's MD&A for the three months and year ended December  31, 2023. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's audited consolidated financial statements for the year ended December  31, 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, per unit statistics and reserves data 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 2023 financial results compared to 2022 and 2021, unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2024. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its quarterly MD&A for the three months and year ended December 31, 2023, its Annual Information Form for the year ended December 31, 2023, and its is available on SEDAR+ at audited consolidated financial statements for the year ended December  31, 2023, 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 February 28, 2024. Canadian Natural 2023 Annual Report 12 Objectives and Strategy The Company’s objective is to create value by generating cash flow and net asset value (1) on a per common share basis through the economic and sustainable development of its existing crude oil and natural gas properties and through the discovery and/or acquisition of new reserves. The Company strives to meet these objectives in a sustainable and responsible way, maintaining a commitment to environmental stewardship and safety excellence. The Company endeavors to meet these objectives by having a defined growth and value enhancement plan for each of its products and segments. The Company takes a balanced approach to growth and investments, and focuses on creating long- term shareholder value, including through its dividend and share buyback programs, in accordance with its capital allocation policy. The Company allocates its capital by maintaining: ▪ ▪ ▪ ▪ ▪ Balance among its products, namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil (2), bitumen (thermal oil), SCO and natural gas; A large, balanced, diversified, high quality, long life low decline asset base; Balance among acquisitions, development and exploration; Balance between sources and terms of debt financing and a strong financial position; and Commitment to environmental stewardship throughout the decision-making process. The Company’s three-phase crude oil marketing strategy includes: ▪ ▪ ▪ Blending various crude oil streams with diluents to create more attractive feedstock; Supporting and participating in pipeline expansions and/or new additions; and Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil and bitumen (thermal oil). Operational discipline, safe, effective and efficient operations, and cost control are fundamental to the Company and embrace the key piece of the Company's mission statement: "doing it right". By consistently managing costs throughout all cycles of the industry, the Company believes it will achieve continued growth. Effective and efficient operations and cost control are attained by developing area knowledge, and by maintaining high working interests and operator status in the Company's properties. The Company is committed to maintaining a strong balance sheet and flexible capital structure. The Company believes it has built the necessary financial capacity to develop its reserves, execute on growth projects and take advantage of favourable acquisition opportunities. Additionally, the Company periodically utilizes its risk management hedging program to reduce the risk of volatility in commodity prices and foreign exchange rates, and corresponding cash flows. Strategic accretive acquisitions are a key component of the Company’s strategy. The Company has used a combination of internally generated cash flows and debt and equity financing to selectively acquire properties generating future cash flows in its core areas. The Company's financial discipline, commitment to a strong balance sheet, and capacity to internally generate cash flows provides the means to responsibly and sustainably grow in the long term. (1) Discounted value of crude oil and natural gas reserves plus value of unproved land, less net debt. (2) Pelican Lake heavy crude oil is 12–17º API oil, which receives medium quality crude netbacks due to lower production expense and lower royalty rates. 13 Canadian Natural 2023 Annual Report Financial and Operational Highlights ($ millions, except per common share amounts) Product sales (1) Crude oil and NGLs Natural gas Net earnings Per common share – basic – diluted Adjusted net earnings from operations (2) Per common share – basic (3) – diluted (3) Cash flows from operating activities Adjusted funds flow (2) Per common share – basic (3) – diluted (3) Dividends declared per common share (4) Total assets Long-term debt, net (5) Cash flows used in investing activities Net capital expenditures (6) Abandonment expenditures, net (2) Average realized price Crude oil and NGLs - Exploration and Production ($/bbl) (3) Natural gas - Exploration and Production ($/Mcf) (7) SCO - Oil Sands Mining and Upgrading ($/bbl) (3) Daily production, before royalties (BOE/d) Crude oil and NGLs (bbl/d) Natural gas (MMcf/d) (8) 2023 40,835 $ 37,300 $ 2,575 $ 8,233 $ 7.54 $ 7.47 $ 2022 49,530 $ 43,009 $ 5,236 $ 10,937 $ 9.64 $ 9.52 $ 8,533 $ 12,863 $ 7.82 $ 7.74 $ 12,353 $ 15,274 $ 14.00 $ 13.86 $ 3.70 $ 75,955 $ 9,922 $ 4,858 $ 4,909 $ 509 $ 11.33 $ 11.19 $ 19,391 $ 19,791 $ 17.44 $ 17.22 $ 4.60 $ 76,142 $ 10,525 $ 4,987 $ 5,136 $ 335 $ 72.36 $ 3.10 $ 90.64 $ 6.55 $ 100.06 $ 117.69 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2021 32,854 29,256 2,716 7,664 6.49 6.46 7,420 6.28 6.25 14,478 13,733 11.63 11.57 2.00 76,665 13,950 3,703 4,676 232 63.71 4.07 77.95 1,332,105 1,281,434 1,234,906 973,530 2,151 933,149 2,090 952,404 1,695 (1) Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements. (2) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. (3) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. (4) 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 paid 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. On November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 per common share. On March 3, 2021, the Board of Directors approved an 11% increase in the quarterly dividend to $0.47 per common share, from $0.425 per common share. (5) Capital management measure. Refer to note 16 to the Company's audited consolidated financial statements. (6) Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. (7) Calculated as natural gas sales divided by sales volumes. (8) Natural gas production volumes approximate sales volumes. Canadian Natural 2023 Annual Report 14 CONSOLIDATED NET EARNINGS AND ADJUSTED NET EARNINGS For 2023, the Company reported net earnings of $8,233 million compared with $10,937 million for 2022 (2021 – $7,664 million). Net earnings for 2023 included non-operating losses, net of tax, of $300 million compared with non-operating losses of $1,926 million for 2022 (2021 – non-operating income of $244 million) 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 and repayment of US dollar debt securities, the gain on acquisitions, the gain from investments, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea in 2022, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for 2023 were $8,533 million compared with $12,863 million for 2022 (2021 – $7,420 million). The decrease in net earnings and adjusted net earnings from operations for 2023 compared with 2022 primarily reflected: ▪ ▪ ▪ lower realized crude oil and NGLs pricing (1) in the North America Exploration and Production 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 SCO sales volumes in the Oil Sands Mining and Upgrading segment; and higher crude oil and NGLs sales volumes in the North America Exploration and Production segment. A detailed reconciliation of the changes in the Company's product sales is provided in the "Analysis of Changes in Product Sales" section of this MD&A. 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 for 2023 from 2022. These items are discussed in detail in the relevant sections of this MD&A. Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked crude oil reserves as at December 31, 2022 and is accelerating abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651 million (after- tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $969 million. As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a non-cash charge of $113 million (after-tax) related to an increase in its estimate of the future abandonment costs for the Ninian field in the North Sea. The non-cash charge is comprised of a recoverability charge of $436 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $323  million. The Company’s estimate of its asset retirement obligation liability, including the Ninian field recoverability charge and associated tax recoveries, is subject to revision in future periods as abandonment efforts progress. (1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. 15 Canadian Natural 2023 Annual Report CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW Cash flows from operating activities for 2023 were $12,353 million compared with $19,391 million for 2022 (2021 – $14,478  million). The decrease in cash flows from operating activities for 2023 from 2022 were primarily due to the factors previously noted related to the decrease in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital. Adjusted funds flow for 2023 was $15,274 million ($14.00 per common share) compared with $19,791 million ($17.44 per common share) for 2022 (2021 – $13,733 million; $11.63 per common share). The decrease in adjusted funds flow for 2023 from 2022 was primarily due to the factors noted above related to the decrease 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, accrued interest on the deferred PRT recovery, and prepaid cost of service tolls. PRODUCTION VOLUMES Record crude oil and NGLs production before royalties for 2023 of 973,530 bbl/d increased 4% from 933,149 bbl/d in 2022 (2021 – 952,404 bbl/d). Record natural gas production before royalties for 2023 increased 3% to average 2,151 MMcf/d from 2,090 MMcf/d in 2022 (2021 – 1,695 MMcf/d). Total production before royalties for 2023 of 1,332,105 BOE/d increased 4% from 1,281,434 BOE/d in 2022 (2021 – 1,234,906 BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of this MD&A. PRODUCT PRICES In the Company’s Exploration and Production segments, the 2023 realized crude oil and NGLs prices decreased 20% to average $72.36 per bbl from $90.64 per bbl in 2022 (2021 – $63.71 per bbl), and the 2023 realized natural gas price decreased 53% to average $3.10 per Mcf from $6.55 per Mcf in 2022 (2021 – $4.07 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company’s 2023 realized SCO sales price decreased 15% to average $100.06 per bbl from $117.69 per bbl in 2022 (2021 – $77.95 per bbl). The Company's realized pricing reflected prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the "Business Environment", "Realized Product Prices - Exploration and Production", and the "Oil Sands Mining and Upgrading" sections of this MD&A. PRODUCTION EXPENSE In the Company’s Exploration and Production segments, the 2023 crude oil and NGLs production expense (1) decreased 11% to average $16.12 per bbl from $18.17 per bbl in 2022 (2021 – $14.71 per bbl), and natural gas production expense (1) averaged $1.30 per Mcf in 2023, an increase of 7% from $1.22 per Mcf in 2022 (2021 – $1.18 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company's 2023 production expense (1) averaged $24.32 per bbl, a decrease of 7% from $26.04 per bbl in 2022 (2021 – $20.91 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the "Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A. (1) Calculated as respective production expense divided by respective sales volumes. Canadian Natural 2023 Annual Report 16 SUMMARY OF QUARTERLY FINANCIAL RESULTS The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters: ($ millions, except per common share amounts) 2023 Product sales (1) $ Crude oil and NGLs Natural gas Net earnings Net earnings per common share – basic – diluted $ $ $ $ $ ($ millions, except per common share amounts) 2022 Product sales (1) $ Crude oil and NGLs Natural gas Net earnings Net earnings per common share – basic – diluted $ $ $ $ $ Total 40,835 $ 37,300 $ 2,575 $ 8,233 $ Dec 31 10,679 $ 9,829 $ 603 $ 2,627 $ Sep 30 11,762 $ 10,944 $ 599 $ 2,344 $ 8,846 $ 8,115 $ 522 $ 1,463 $ Jun 30 Mar 31 7.54 $ 7.47 $ 2.43 $ 2.41 $ 2.15 $ 2.13 $ 1.34 $ 1.32 $ Total 49,530 $ 43,009 $ 5,236 $ 10,937 $ Dec 31 11,012 $ 9,508 $ 1,287 $ 1,520 $ Sep 30 12,574 $ 11,001 $ 1,342 $ 2,814 $ Jun 30 13,812 $ 11,727 $ 1,605 $ 3,502 $ 9.64 $ 9.52 $ 1.37 $ 1.36 $ 2.52 $ 2.49 $ 3.04 $ 3.00 $ 9,548 8,412 851 1,799 1.63 1.62 Mar 31 12,132 10,773 1,002 3,101 2.66 2.63 (1) Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements. Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to: ▪ ▪ ▪ ▪ ▪ ▪ ▪ Crude oil pricing – Fluctuations in global supply/demand including crude oil production levels from OPEC+ and its impact on world supply; the impact of geopolitical and market uncertainties, including those due to the Russian invasion of Ukraine on worldwide benchmark pricing; the impact of shale oil production in North America; the impact of the WCS Heavy Differential from WTI in North America; and the impact of the differential between WTI and Brent benchmark pricing in the International segments. Natural gas pricing – 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. Crude oil and NGLs sales volumes – Fluctuations in production from the Kirby and Jackfish thermal oil sands projects, fluctuations in production due to the cyclic nature of the Primrose thermal oil projects, fluctuations in the Company’s drilling program in the North America Exploration and Production segment, natural 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 2023 in the North America Exploration and Production segment. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments. Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, natural decline rates, the impact and timing of acquisitions, and wildfires and a third- party pipeline outage in 2023 in the North America Exploration and Production segment. Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, increased carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments. Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, 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. 17 Canadian Natural 2023 Annual Report         ▪ ▪ ▪ Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company’s risk management activities. Interest expense – Fluctuations due to changing long-term debt levels, and the impact of movements in benchmark interest rates on outstanding floating rate long-term debt and accrued interest on the deferred PRT recovery. Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses were also recorded with respect to US dollar denominated debt, partially offset by the impact of any cross currency swap hedges outstanding. Gain from investment – Fluctuations due to the gain from the investment in PrairieSky Royalty Ltd. shares. ▪ Business Environment Rising interest rates in response to persistent inflation and concerns of a global recession put downward pressure on global crude oil benchmark pricing in 2023 and heightened geopolitical tensions led to pricing volatility throughout 2023. Higher non- OPEC supply and record US production in the fourth quarter of 2023 reduced the impact of previously announced OPEC+ production cuts. 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 December 31, 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 $6,852 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. Capital Spending On December 14, 2023, the Company announced its 2024 capital budget (2) targeted at approximately $5,420  million, and targets to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns and the balancing of project risks and time horizons. The 2024 capital budget and targeted abandonment expenditures constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements. (1) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. (2) Forward-looking non-GAAP Financial Measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on Net Capital Expenditures. Canadian Natural 2023 Annual Report 18 BENCHMARK COMMODITY PRICES (Yearly average) WTI benchmark price (US$/bbl) Dated Brent benchmark price (US$/bbl) WCS Heavy Differential from WTI (US$/bbl) SCO benchmark price (US$/bbl) Condensate benchmark price (US$/bbl) Condensate Differential from WTI (US$/bbl) NYMEX benchmark price (US$/MMBtu) AECO benchmark price (C$/GJ) US/Canadian dollar average exchange rate (US$) US/Canadian dollar year end exchange rate (US$) 2023 77.61 $ 82.61 $ 18.62 $ 79.64 $ 76.55 $ 1.06 $ 2.74 $ 2.77 $ 2022 94.23 $ 99.80 $ 18.26 $ 98.66 $ 93.69 $ 0.54 $ 6.64 $ 5.28 $ 2021 67.96 70.49 13.04 66.36 68.24 (0.28) 3.85 3.38 0.7409 $ 0.7573 $ 0.7686 $ 0.7389 $ 0.7979 0.7901 $ $ $ $ $ $ $ $ $ $ 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. Product revenue continued to be impacted by changes in 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 North America are typically based on WTI benchmark pricing. WTI averaged US$77.61 per bbl for 2023, a decrease of 18% from US$94.23 per bbl for 2022 (2021 – US$67.96 per bbl). 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$82.61 per bbl for 2023, a decrease of 17% from US$99.80 per bbl for 2022 (2021 – US$70.49 per bbl). The decrease in WTI and Brent pricing for 2023 from 2022 primarily reflected concerns of higher non-OPEC supply and lower than anticipated global crude oil demand, as a result of persistent inflation and the resulting increase in interest rates. The WCS Heavy Differential averaged US$18.62 per bbl for 2023, compared with US$18.26 per bbl for 2022 (2021 – US$13.04 per bbl). The SCO price averaged US$79.64 per bbl for 2023, a decrease of 19% from US$98.66 per bbl for 2022 (2021 – US$66.36 per bbl). The decrease in SCO pricing for 2023 from 2022 primarily reflected the decrease in WTI benchmark pricing, together with increased production and egress constraints in the Western Canadian Sedimentary Basin ("WCSB"). NYMEX natural gas prices averaged US$2.74 per MMBtu for 2023, a decrease of 59% from US$6.64 per MMBtu for 2022 (2021 – US$3.85 per MMBtu). The decrease in NYMEX natural gas prices for 2023 from 2022 primarily reflected increased production and lower storage draws due to mild winter weather in 2023. Additionally, lower global LNG prices amid ample supply put downward pressure on NYMEX benchmark prices. AECO natural gas prices averaged $2.77 per GJ for 2023, a decrease of 48% from $5.28 per GJ for 2022 (2021 – $3.38 per GJ). The decrease in AECO natural gas prices for 2023 from 2022 primarily reflected NYMEX benchmark pricing, increased production in the WCSB, and lower storage draws due to decreased demand resulting from mild winter weather in 2023. 19 Canadian Natural 2023 Annual Report Analysis of Changes in Product Sales ($ millions) North America Changes due to Changes due to 2021 Volumes Prices Other 2022 Volumes Prices Other 2023 Crude oil and NGLs $ 14,478 $ 286 $ 5,991 $ — $ 20,755 $ 730 $ (4,110) $ — $ 17,375 Natural gas Other (1) North Sea Crude oil and NGLs Natural gas Other (1) Offshore Africa Crude oil and NGLs Natural gas Other (1) Oil Sands Mining and Upgrading Crude oil and NGLs Other (1) Midstream and Refining Midstream activities Refined product sales and other (1) Intersegment eliminations and other (2) Product sales Other (1) 2,484 119 17,081 584 — 870 1,863 — 7,854 607 5 (1) (183) 199 (2) — 10 — 611 (185) 209 420 31 7 458 45 2 — 47 229 22 — 251 — 98 98 — — 1 1 — — 1 1 4,931 217 25,903 153 — 883 (2,709) — 2,375 — (207) 10 (6,819) (207) 19,760 623 13 — 636 694 55 8 757 (117) (3) — (71) (3) — (120) (74) 1 (8) — (118) 4 — (7) (114) — — — — — — 1 1 435 7 — 442 577 51 9 637 14,033 (592) 7,363 — 20,804 1,012 (3,155) — 18,661 73 — — 14,106 (592) 7,363 78 681 759 (164) 3 (161) — — — — — — — — — — — — 76 76 2 225 227 454 2 456 149 — — (144) 5 20,953 1,012 (3,155) (144) 18,666 80 906 986 290 5 295 — — — — — — — — — — — — (4) 76 20 16 28 5 33 926 1,002 318 10 328 Total $ 32,854 $ 140 $ 15,677 $ 859 $ 49,530 $ 1,768 $ (10,162) $ (301) $ 40,835 (1) Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations partners' share of the costs of lease contracts. (2) Eliminates internal transportation and electricity charges and includes production, processing and other purchasing and selling activities that are not included in the above segments. Product sales decreased 18% to $40,835 million for 2023 from $49,530 million for 2022 (2021 – $32,854 million). The decrease in product sales was primarily the result of an overall decrease in realized commodity pricing across the Company's segments in 2023. Crude oil and NGLs and natural gas pricing are discussed in detail in the "Business Environment", "Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of this MD&A. For 2023, 3% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America (2022 – 3%; 2021 – 3%). North Sea accounted for 1% of crude oil and NGLs and natural gas product sales for 2023 (2022 – 1%; 2021 – 2%), and Offshore Africa accounted for 2% of crude oil and NGLs and natural gas product sales for 2023 (2022 – 2%; 2021 – 1%). Canadian Natural 2023 Annual Report 20                                                                     Daily Production DAILY PRODUCTION, BEFORE ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading (1) International – Exploration and Production North Sea Offshore Africa Total International (2) Total Crude oil and NGLs Natural gas (MMcf/d) (3) North America International North Sea Offshore Africa Total International Total Natural gas Total Barrels of oil equivalent (BOE/d) Product mix Light and medium crude oil and NGLs Pelican Lake heavy crude oil Primary heavy crude oil Bitumen (thermal oil) Synthetic crude oil (1) Natural gas Percentage of product sales (1) (4) (5) Crude oil and NGLs Natural gas 2023 2022 2021 496,100 451,339 479,971 425,945 472,621 448,133 12,639 13,452 26,091 12,890 14,343 27,233 17,633 14,017 31,650 973,530 933,149 952,404 2,139 2,075 1,680 2 10 12 2 13 15 3 12 15 2,151 2,090 1,695 1,332,105 1,281,434 1,234,906 10% 3% 6% 20% 34% 27% 93% 7% 11% 4% 5% 20% 33% 27% 88% 12% 10% 5% 5% 21% 36% 23% 91% 9% (1) SCO production before royalties excludes SCO consumed internally as diesel. (2) "International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used. (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. 21 Canadian Natural 2023 Annual Report   DAILY PRODUCTION, NET OF ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading International – Exploration and Production North Sea Offshore Africa Total International Total Crude oil and NGLs Natural gas (MMcf/d) North America International North Sea Offshore Africa Total International Total Natural gas Total Barrels of oil equivalent (BOE/d) 2023 2022 2021 406,534 385,996 374,089 351,740 404,637 410,385 12,609 12,183 24,792 12,849 12,972 25,821 17,588 13,354 30,942 817,322 751,650 845,964 2,055 1,885 1,593 2 10 12 2 11 13 3 11 14 2,067 1,898 1,607 1,161,852 1,068,063 1,113,878 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. Total 2023 production before royalties averaged 1,332,105 BOE/d, an increase of 4% from 1,281,434 BOE/d in 2022 (2021 – 1,234,906 BOE/d). Record crude oil and NGLs production before royalties for 2023 averaged 973,530 bbl/d, an increase of 4% from 933,149 bbl/d for 2022 (2021 – 952,404 bbl/d). The increase in crude oil and NGLs production for 2023 from 2022 primarily reflected stronger production in the Oil Sands Mining and Upgrading, and North America Exploration and Production segments in 2023 due to pad additions in thermal oil, drilling activity, and the impact of extreme cold weather conditions in the fourth quarter of 2022. Annual crude oil and NGLs production for 2023 was within the Company's previously issued production target of 969,000 bbl/d to 1,001,000 bbl/d. Annual crude oil and NGLs production for 2024 is targeted to average between 977,000 bbl/d and 1,008,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements. Natural gas production before royalties accounted for 27% of the Company's total production in 2023 on a BOE basis. Record natural gas production for 2023 of 2,151 MMcf/d increased 3% from 2,090 MMcf/d for 2022 (2021 – 1,695 MMcf/d). The increase in natural gas production for 2023 from 2022 primarily reflected 2023 drilling activity, partially offset by the impact of wildfires and a third party pipeline outage in 2023, together with natural field declines. Annual natural gas production for 2023 was slightly below the Company's previously issued production target of 2,170 MMcf/d to 2,242 MMcf/d. Annual natural gas production for 2024 is targeted to average between 2,120 MMcf/d and 2,230 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements. North America – Exploration and Production North America crude oil and NGLs production before royalties for 2023 averaged 496,100 bbl/d, an increase of 3% from 479,971 bbl/d for 2022 (2021 – 472,621 bbl/d). The increase in North America crude oil and NGLs production for 2023 from 2022 primarily reflected pad additions in thermal oil and conventional drilling activity in 2023, partially offset by the impacts of wildfires and a third party pipeline outage in 2023, and natural field declines. Thermal oil production before royalties for 2023 averaged 262,000 bbl/d, an increase of 4% from 252,018 bbl/d for 2022 (2021 – 259,284 bbl/d). The increase in thermal oil production for 2023 from 2022 primarily reflected pad additions at Primrose and Kirby in 2023, partially offset by natural field declines. Pelican Lake heavy crude oil production before royalties averaged 47,078 bbl/d for 2023, a decrease of 6% from 50,333 bbl/d for 2022 (2021 – 54,390 bbl/d), primarily reflecting natural field declines. Natural gas production before royalties for 2023 averaged 2,139 MMcf/d, an increase of 3% from 2,075 MMcf/d for 2022 (2021  – 1,680 MMcf/d). The increase in natural gas production for 2023 from 2022 primarily reflected 2023 drilling activity, partially offset by the impact of wildfires and a third party pipeline outage in 2023, together with natural field declines. Canadian Natural 2023 Annual Report 22   North America – Oil Sands Mining and Upgrading Record SCO production before royalties for 2023 of 451,339 bbl/d increased 6% from 425,945 bbl/d for 2022 (2021 – 448,133 bbl/d). The increase in SCO production for 2023 from 2022 primarily reflected stronger production in 2023 following the impact of an extended turnaround at the non-operated Scotford Upgrader in the first half of 2022, as well as an unplanned outage at Horizon and extreme cold weather conditions impacting mining operations in the fourth quarter of 2022. International – Exploration and Production International crude oil and NGLs production before royalties for 2023 averaged 26,091  bbl/d, a decrease of 4% from 27,233  bbl/d for 2022 (2021 – 31,650 bbl/d). The decrease in production for 2023 from 2022 primarily reflected natural field declines. INTERNATIONAL CRUDE OIL INVENTORY VOLUMES The Company recognizes revenue on its crude oil production when control of the product passes to the customer and delivery has taken place. Revenue has not been recognized in the International segments on crude oil volumes held in various storage facilities or FPSOs, as follows: (bbl) International Exploration and Production OPERATING HIGHLIGHTS Crude oil and NGLs ($/bbl) (1) Realized price (2) Transportation (2) Realized price, net of transportation (2) Royalties (3) Production expense (4) Netback (2) Natural gas ($/Mcf) (1) Realized price (5) Transportation (6) Realized price, net of transportation Royalties (3) Production expense (4) Netback Barrels of oil equivalent ($/BOE) (1) Realized price (2) Transportation (2) Realized price, net of transportation (2) Royalties (3) Production expense (4) Netback (2) 2023 2022 2021 515,543 390,959 727,439 2023 2022 2021 $ 72.36 $ 90.64 $ $ $ $ $ 4.23 68.13 12.55 16.12 4.13 86.51 18.91 18.17 39.46 $ 49.43 $ 3.10 $ 6.55 $ 0.56 2.54 0.13 1.30 0.51 6.04 0.61 1.22 1.11 $ 4.21 $ 50.54 $ 70.07 $ 3.88 46.66 7.77 12.74 3.72 66.35 12.75 13.76 $ 26.15 $ 39.84 $ 63.71 3.86 59.85 8.59 14.71 36.55 4.07 0.45 3.62 0.22 1.18 2.22 49.67 3.44 46.23 5.98 11.98 28.27 (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. 23 Canadian Natural 2023 Annual Report   REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) North America (2) International average (3) North Sea (3) Offshore Africa (3) Crude oil and NGLs average (2) Natural gas ($/Mcf) (1) (3) North America International average North Sea Offshore Africa Natural gas average Average ($/BOE) (1) (2) 2023 2022 2021 $ $ $ $ $ $ $ $ $ $ $ 70.51 $ 107.46 $ 110.99 $ 106.25 $ 72.36 $ 3.04 $ 12.81 $ 10.45 $ 13.19 $ 3.10 $ 50.54 $ 88.43 $ 128.41 $ 129.04 $ 127.85 $ 90.64 $ 6.51 $ 12.78 $ 15.75 $ 12.23 $ 6.55 $ 70.07 $ 62.10 87.04 87.98 85.71 63.71 4.05 6.21 2.94 7.17 4.07 49.67 (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 20% to average $70.51 per bbl for 2023 from $88.43 per bbl for 2022 (2021 – $62.10 per bbl), primarily due to lower WTI benchmark pricing. The Company continues to focus on its crude oil blending marketing strategy including a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with refiners to add incremental heavy crude oil and bitumen (thermal oil) conversion capacity. During 2023, the Company contributed approximately 217,000 bbl/d of heavy crude oil blends to the WCS stream. The Company has 20-year transportation agreements to ship 94,000 bbl/d of crude oil on the Trans Mountain Pipeline Expansion that will provide waterborne access to international markets. The expansion is nearing completion and Trans Mountain Corporation targets the pipeline to be operational in the second quarter of 2024. North America realized natural gas prices decreased 53% to average $3.04 per Mcf for 2023 from $6.51 per Mcf for 2022 (2021 – $4.05 per Mcf). The decrease in realized natural gas prices for 2023 from 2022 primarily reflected lower AECO benchmark and export pricing. Comparisons of the prices received in North America Exploration and Production by product type were as follows: (Yearly average) Wellhead Price (1) Light and medium crude oil and NGLs ($/bbl) Pelican Lake heavy crude oil ($/bbl) Primary heavy crude oil ($/bbl) Bitumen (thermal oil) ($/bbl) Natural gas ($/Mcf) 2023 2022 2021 $ $ $ $ $ 70.72 $ 77.69 $ 75.67 $ 67.62 $ 3.04 $ 88.24 $ 96.18 $ 93.80 $ 85.51 $ 6.51 $ 61.29 68.05 65.88 60.20 4.05 (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 16% to average $107.46 per bbl for 2023 from $128.41 per bbl for 2022 (2021 – $87.04 per bbl). Realized crude oil and NGLs prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The decrease in realized crude oil and NGLs prices for 2023 from 2022 reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar. Canadian Natural 2023 Annual Report 24       ROYALTIES – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) North America International average North Sea Offshore Africa Crude oil and NGLs average Natural gas ($/Mcf) (1) North America Offshore Africa Natural gas average Average ($/BOE) (1) 2023 2022 2021 $ $ $ $ $ $ $ $ $ 12.89 $ 5.99 $ 0.33 $ 10.08 $ 12.55 $ 0.13 $ 0.62 $ 0.13 $ 7.77 $ 19.64 $ 6.38 $ 0.30 $ 11.79 $ 18.91 $ 0.61 $ 1.50 $ 0.61 $ 12.75 $ 9.06 1.75 0.19 3.94 8.59 0.22 0.33 0.22 5.98 (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 Government royalties on a significant portion of North America crude oil and NGLs production fall under the oil sands royalty regime and are calculated on a project by project basis as a percentage of gross revenue less operating, capital and abandonment costs incurred. North America crude oil and NGLs and natural gas royalties for 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 18% of product sales for 2023, compared with 22% of product sales for 2022 (2021 – 15%). The decrease in royalty rates for 2023 from 2022 was primarily due to lower benchmark prices. Natural gas royalty rates averaged approximately 4% of product sales for 2023, compared with 9% of product sales for 2022 (2021 – 5%). The decrease in royalty rates for 2023 from 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 2023, comparable with 9% of product sales for 2022 (2021 – 5%). 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 Crude oil and NGLs ($/bbl) (1) North America International average North Sea Offshore Africa Crude oil and NGLs average Natural gas ($/Mcf) (1) North America International average North Sea Offshore Africa Natural gas average Average ($/BOE) (1) 2023 2022 2021 14.46 $ 48.16 $ 85.57 $ 21.14 $ 16.12 $ 1.27 $ 7.26 $ 9.85 $ 6.83 $ 1.30 $ 16.25 $ 51.01 $ 88.99 $ 17.25 $ 18.17 $ 1.19 $ 5.16 $ 9.27 $ 4.40 $ 1.22 $ 13.12 37.77 54.13 14.73 14.71 1.15 5.07 7.31 4.41 1.18 12.74 $ 13.76 $ 11.98 $ $ $ $ $ $ $ $ $ $ $ (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. (1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. 25 Canadian Natural 2023 Annual Report     North America North America crude oil and NGLs production expense for 2023 averaged $14.46 per bbl, a decrease of 11% from $16.25 per bbl for 2022 (2021 – $13.12 per bbl). The decrease in crude oil and NGLs production expense per bbl for 2023 from 2022 primarily reflected lower energy costs, partially offset by higher service costs. North America natural gas production expense for 2023 averaged $1.27 per Mcf, an increase of 7% from $1.19 per Mcf for 2022 (2021 – $1.15 per Mcf). The increase in natural gas production expense per Mcf for 2023 from 2022 primarily reflected higher service costs. International International crude oil and NGLs production expense for 2023 averaged $48.16 per bbl, a decrease of 6% from $51.01 per bbl for 2022 (2021 – $37.77 per bbl). The decrease in crude oil production expense per bbl for 2023 from 2022 primarily reflected lower energy costs and the timing of liftings from various fields that have different cost structures. ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) North America North Sea Offshore Africa Depletion, Depreciation and Amortization Less: Recoverability charge (1) (2) Adjusted depletion, depreciation and amortization (3) $/BOE (4) $ $ $ $ 2023 2022 3,679 $ 3,595 $ 494 213 4,386 $ 436 3,950 $ 12.27 $ 1,747 173 5,515 $ 1,620 3,895 $ 12.45 $ 2021 3,569 160 142 3,871 — 3,871 13.49 (1) As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a recoverability charge of $436 million in depletion, depreciation and amortization expense related to an increase in its estimate of future abandonment costs for the Ninian field in the North Sea. (2) Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. As at December 31, 2022 the Company completed a recoverability assessment of its assets in the North Sea, and recognized a recoverability charge of $1,620 million in depletion, depreciation, and amortization expense following a detailed assessment which determined that the Ninian field was no longer economic. (3) This is a non-GAAP measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production. It may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the financial statements (depletion, depreciation and amortization expense), as applicable, as an indication of the Company's performance. (4) Non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. Adjusted depletion, depreciation and amortization expense for 2023 of $12.27 per BOE was comparable with $12.45 per BOE for 2022 (2021 – $13.49 per BOE). Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa. ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) North America North Sea Offshore Africa Asset Retirement Obligation Accretion $/BOE (1) $ $ $ 2023 234 $ 46 8 288 $ 0.89 $ 2022 171 $ 33 7 211 $ 0.67 $ 2021 101 21 6 128 0.44 (1) Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for 2023 of $0.89 per BOE increased 33% from $0.67 per BOE for 2022 (2021 – $0.44 per BOE). The increase in asset retirement obligation accretion expense per BOE for 2023 from 2022 primarily reflected the impact of cost, inflation and timing estimates, regulatory changes, and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. Canadian Natural 2023 Annual Report 26 Oil Sands Mining and Upgrading OPERATING HIGHLIGHTS The Company continues to focus on safe, reliable and efficient operations and leveraging its technical expertise across the Horizon and AOSP sites with record SCO production in 2023 averaging 451,339 bbl/d. The Company incurred production expense of $3,989 million for 2023, comparable with $4,076 million for 2022 (2021 – $3,414 million), reflecting the Company's continued focus on cost control and efficiencies across the entire asset base. REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING ($/bbl) Realized SCO sales price (1) Bitumen value for royalty purposes (2) Bitumen royalties (3) Transportation (1) 2023 2022 100.06 $ 117.69 $ 65.43 $ 14.43 $ 1.89 $ 83.07 $ 20.71 $ 1.71 $ $ $ $ $ 2021 77.95 58.39 6.62 1.21 (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 $100.06 per bbl for 2023, a decrease of 15% from $117.69 per bbl for 2022 (2021 – $77.95 per bbl). The decrease in the realized SCO sales price for 2023 compared to 2022 primarily reflected the decrease in WTI benchmark pricing. The decrease in bitumen royalties per bbl for 2023 from 2022 primarily reflected the impact of lower prevailing bitumen pricing combined with the impact of sliding scale royalty rates. Transportation expense averaged $1.89 per bbl for 2023, an increase of 11% from $1.71 per bbl for 2022 (2021 – $1.21 per bbl). The increase in transportation expense for 2023 from 2022 primarily reflected higher sales to the US Gulf Coast in 2023, partially offset by higher total sales volumes. PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 22 to the Company’s audited consolidated financial statements. ($ millions) Production expense, excluding natural gas costs Natural gas costs Production expense ($/bbl) Production expense, excluding natural gas costs (1) Natural gas costs (2) Production expense (3) Sales volumes (bbl/d) $ $ $ $ 2023 2022 3,794 $ 3,743 $ 195 333 3,989 $ 4,076 $ 2023 2022 23.13 $ 23.91 $ 1.19 2.13 24.32 $ 26.04 $ 2021 3,176 238 3,414 2021 19.45 1.46 20.91 449,282 428,820 447,230 (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 2023 of $24.32 per bbl decreased 7% from $26.04 per bbl for 2022 (2021 – $20.91 per bbl). The decrease in production expense per bbl for 2023 as compared to 2022 primarily reflected higher production volumes and lower energy costs. 27 Canadian Natural 2023 Annual Report DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) Depletion, depreciation and amortization $/bbl (1) $ $ 2023 2,011 $ 12.26 $ 2022 1,822 $ 11.64 $ 2021 1,838 11.26 (1) Calculated as depletion, depreciation and amortization divided by sales volumes. Depletion, depreciation and amortization expense for 2023 of $12.26 per bbl increased 5% from $11.64 per bbl for 2022 (2021 – $11.26 per bbl), reflecting the impact of a higher depletable base due to asset additions, partially offset by higher sales volumes in 2023. ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) Asset retirement obligation accretion $/bbl (1) $ $ 2023 78 $ 0.48 $ 2022 70 $ 0.45 $ 2021 57 0.35 (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 2023 of $0.48 per bbl increased 7% from $0.45 per bbl for 2022 (2021 – $0.35 per bbl). The increase in asset retirement obligation accretion expense on a per bbl basis for 2023 from 2022 primarily reflected the impact of cost, inflation and timing estimates, and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. Midstream and Refining ($ millions) Product sales Midstream activities NWRP, refined product sales and other Segmented revenue Less: NWRP, refining toll Midstream activities Production expense NWRP, transportation and feedstock costs Depreciation Income from NWRP Segmented (loss) earnings 2023 2022 2021 $ 76 $ 80 $ 926 1,002 303 29 332 664 16 — 906 986 247 24 271 691 16 — $ (10) $ 8 $ 78 681 759 213 21 234 550 15 (400) 360 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 NWRP. Approximately 25% of the Company's crude oil production was transported to international mainline liquid pipelines via the 100% owned and operated ECHO and Pelican Lake pipelines. The Midstream pipeline asset ownership allows the Company to control transportation costs, earn third party revenue, and manage the marketing of heavy crude oils. 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. Production of ultra-low sulphur diesel and other refined products for 2023 averaged 81,525 BOE/d (20,381 BOE/d to the Company) (2022 – 58,351 BOE/d; 14,588 BOE/d to the Company; 2021 – 69,713 BOE/d; 17,428 BOE/d to the Company). On June 30, 2021, the equity partners, together with the toll payers, agreed to optimize the structure of NWRP to better align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest remained unchanged. Canadian Natural 2023 Annual Report 28 Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048 to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, and issued lower cost senior secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the Company received a $400 million distribution from NWRP during 2021. To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December 2023, $500  million of 2.00% series M senior secured bonds due December 2026, $1,000  million of 2.80% series N senior secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051. During 2023, NWRP repaid the $500 million of 1.20% series L senior secured bonds. During 2023, NWRP's syndicated credit facility was reduced by $60 million to $3,115 million (2022 – $3,175 million) following the repayment and cancellation of a portion of the non-revolving credit facility that matured in June 2023. NWRP's syndicated credit facility is comprised of a $2,175 million revolving credit facility, with $118 million maturing June 2024 and the remainder maturing June 2025, and a $940 million non-revolving credit facility maturing June 2025. As at December 31, 2023, NWRP had borrowings of $2,559 million under the syndicated credit facility (December 31, 2022 – $2,318 million) and borrowings of $77 million under its short-term demand operating facility (December 31, 2022 – $nil). During 2022, NWRP entered into a $150 million facility to support letters of credit. As at December 31, 2023, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $555 million (2022 – $551 million). The unrecognized equity loss from NWRP for 2023 was $4 million (2022 – recovery of unrecognized equity losses of $11 million; 2021 – unrecognized equity loss of $9 million and partnership distributions of $400 million). Corporate and Other ADMINISTRATION EXPENSE ($ millions, except per BOE amounts) Expense $/BOE (1) Sales volumes (BOE/d) (2) (1) Calculated as administration expense divided by sales volumes. (2) Total Company sales volumes. $ $ 2023 452 $ 0.93 $ 2022 415 $ 0.88 $ 2021 366 0.81 1,331,092 1,285,877 1,233,457 Administration expense for 2023 of $0.93 per BOE increased 6% from $0.88 per BOE for 2022 (2021 – $0.81 per BOE). Administration expense per BOE increased from 2022 primarily due to higher personnel and corporate costs, partially offset by higher sales volumes and higher overhead recoveries. SHARE-BASED COMPENSATION ($ millions) Share-based compensation expense $ 2023 491 $ 2022 804 $ 2021 514 The Company’s Stock Option Plan provides employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met. The Company recognized $491 million of share-based compensation expense for 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. An expense of $70 million related to PSUs granted to certain executive employees was included in the share-based compensation expense for 2023 (2022 – $101 million expense; 2021 – $79 million expense). 29 Canadian Natural 2023 Annual Report INTEREST AND OTHER FINANCING EXPENSE ($ millions, except effective interest rate) Interest and other financing expense Less: Interest income and other (1) Interest on long-term debt and lease liabilities (1) Average current and long-term debt (2) Average lease liabilities (2) Average long-term debt and lease liabilities (2) Average effective interest rate (3) (4) Interest and other financing expense per $/BOE (5) Sales volumes (BOE/d) (6) (1) Item is a component of interest and other financing expense. $ $ $ $ $ 2023 636 $ (55) 691 $ 2022 549 $ (121) 670 $ 12,749 $ 13,986 $ 1,500 1,531 14,249 $ 15,517 $ 4.8% 4.3% 2021 711 (32) 743 18,935 1,619 20,554 3.5% 1.31 $ 1.17 $ 1.58 1,331,092 1,285,877 1,233,457 (2) The average of current and long-term debt and lease liabilities outstanding during the respective year. (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 Company's audited consolidated financial statements, as applicable, as an indication of the Company's performance. (4) Calculated as the average interest on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance for the respective year. 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 2023 increased 12% to $1.31 per BOE from $1.17 per BOE for 2022 (2021 – $1.58 per BOE). The increase in interest and other financing expense per BOE for 2023 from 2022 primarily reflected the impact of higher interest rates on floating rate long-term debt, together with the impact of higher accrued interest income on the deferred PRT recovery in 2022, partially offset by lower average debt levels in 2023. The Company’s average effective interest rate of 4.8% for 2023 increased from 4.3% for 2022 primarily due to higher prevailing interest rates on floating rate debt held during 2023. RISK MANAGEMENT ACTIVITIES The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes. ($ millions) Foreign currency contracts Natural gas financial instruments (1) (2) Crude oil and NGLs financial instruments (1) Net realized (gain) loss Foreign currency contracts Natural gas financial instruments (1) (2) Crude oil and NGLs financial instruments (1) Net unrealized loss (gain) Net (gain) loss $ 2023 (17) $ 2022 (37) $ 3 — (14) (9) 21 — 12 13 17 (7) (16) (10) (2) (28) $ (2) $ (35) $ 2021 1 17 (1) 17 6 11 2 19 36 (1) Commodity financial instruments were assumed in the acquisition of Storm Resources Ltd. ("Storm") in 2021, and Painted Pony Energy Ltd. ("Painted Pony") in 2020. (2) In the fourth quarter of 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024. During 2023, net realized risk management gains were related to the settlement of foreign currency contracts, partially offset by losses on natural gas financial instruments. The Company recorded a net unrealized loss of $12 million ($7 million after-tax of $5 million) on its risk management activities for 2023 (2022 – $28 million unrealized gain, $25 million after-tax of $3 million; 2021 – $19 million unrealized loss, $16 million after-tax of $3 million). Further details related to outstanding derivative financial instruments as at December 31, 2023 are disclosed in note 19 to the Company's audited consolidated financial statements. Canadian Natural 2023 Annual Report 30 FOREIGN EXCHANGE ($ millions) Net realized (gain) loss Net unrealized (gain) loss Net (gain) loss (1) $ $ 2023 (19) $ (260) (279) $ 2022 (114) $ 852 738 $ 2021 78 (205) (127) (1) Amounts are reported net of the hedging effect of cross currency swaps. The net realized foreign exchange gain for 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 gain for 2023 was primarily related to the impact of a stronger Canadian dollar with respect to outstanding US dollar debt. The US/Canadian dollar exchange rate at December 31, 2023 was US$0.7573 (December 31, 2022 – US$0.7389, December 31, 2021 – US$0.7901). INCOME TAXES ($ millions, except effective tax rates) North America (1) North Sea Offshore Africa Current PRT – North Sea Other taxes Current income tax Deferred corporate income tax Deferred PRT – North Sea Deferred income tax Income tax Earnings before taxes Effective tax rate on net earnings (2) ($ millions, except effective tax rates) Income tax Tax effect on non-operating items (3) Current PRT – North Sea Deferred PRT – North Sea Other taxes 2023 2022 $ 1,853 $ 2,789 $ (6) 73 (58) 17 1,879 267 (214) 53 1,932 $ 10,165 $ 19% 2023 69 74 (42) 16 2,906 302 (441) (139) 2,767 $ 13,704 $ 20% 2022 $ $ $ 1,932 $ 2,767 $ 345 58 9 (17) 2,327 $ 8,533 $ 10,860 $ 21% 964 42 — (16) 3,757 $ 12,863 $ 16,620 $ 23% 2021 1,841 7 21 (34) 13 1,848 399 — 399 2,247 9,911 23% 2021 2,247 5 34 — (13) 2,273 7,420 9,693 23% Effective tax on adjusted net earnings Adjusted net earnings from operations (4) Adjusted net earnings from operations, before taxes Effective tax rate on adjusted net earnings from operations (5) (6) $ $ $ (1) Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments. (2) Calculated as total of current and deferred income tax divided by earnings before taxes. (3) Includes the net income tax effect on PSUs, unrealized risk management, and government grant income related to abandonment expenditures in 2022, as well as deferred PRT and income tax recoveries related to the recoverability charges recognized in 2023 and 2022. (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 2023 and the comparable years included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings. The current and deferred corporate income tax and current and deferred PRT in the North Sea in 2023 and 2022 included the impact of carrybacks of PRT losses, including expenditures related to decommissioning activities at the Company's platforms in the North Sea. Deferred PRT and income taxes also reflected the impact of the recoverability charges recognized in depletion, depreciation, and amortization expense for 2023 and 2022. 31 Canadian Natural 2023 Annual Report 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. During 2023, the Company filed Scientific Research and Experimental Development claims of approximately $380 million (2022 – $283 million; 2021 – $229 million) relating to qualifying research and development expenditures for Canadian income tax purposes. Net Capital Expenditures (1) (2) ($ millions) EXPLORATION AND PRODUCTION Exploration and Evaluation Assets Net expenditures Net property dispositions Total Exploration and Evaluation Assets Property, Plant and Equipment Net property acquisitions (3) Well drilling, completion and equipping Production and related facilities Other Total Property, Plant and Equipment Total Exploration and Production OIL SANDS MINING AND UPGRADING Project costs Sustaining capital Turnaround costs Net property acquisitions (dispositions) Other (4) Total Oil Sands Mining and Upgrading Midstream and Refining Head office Net capital expenditures Abandonments expenditures, net (5) By Segment North America (3) North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream and Refining Head office Net capital expenditures 2023 2022 2021 $ 47 $ (3) 36 $ (3) 33 12 (11) 1 44 24 1,579 1,267 61 2,931 2,975 348 1,347 189 5 5 1,894 10 30 4,909 $ 509 $ 513 1,545 1,233 59 3,350 3,383 294 1,171 287 (40) 7 1,719 9 25 5,136 $ 335 $ $ $ $ 2,770 $ 3,133 $ 33 172 1,894 10 30 126 124 1,719 9 25 1,112 918 802 64 2,896 2,897 236 1,035 145 — 331 1,747 9 23 4,676 232 2,662 173 62 1,747 9 23 $ 4,909 $ 5,136 $ 4,676 (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. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. (3) (4) Includes cash consideration of $771 million and the settlement of long-term debt of $183 million assumed in the acquisition of Storm in 2021. Includes the acquisition of a 5% net carried interest on an existing oil sands lease in 2021. (5) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. Canadian Natural 2023 Annual Report 32 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. Net capital expenditures for 2023 were $4,909 million compared with $5,136 million for 2022. Net capital expenditures for 2023 included base capital expenditures (1) of $3,958 million and strategic growth capital expenditures (1) of $925 million, in accordance with the Company's capital budget. In addition, the Company reported abandonment expenditures (2) of $509 million for the year ended December 31, 2023 compared with $335 million for the year ended December 31, 2022. 2024 CAPITAL BUDGET On December 14, 2023, the Company announced its 2024 capital budget targeted at approximately $5,420  million, and targeting to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024. The 2024 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements. DRILLING ACTIVITY (1) (2) (number of net wells) Net successful crude oil wells (3) Net successful natural gas wells Dry wells Total Success rate 2023 221 61 2 284 99% 2022 317 72 1 390 99% 2021 149 49 1 199 99% (1) (2) Includes drilling activity for North America and International segments. In addition, during 2023, on a net basis, the Company drilled 334 stratigraphic and 11  service wells in the Oil Sands Mining and Upgrading segment, 24 stratigraphic and 48 service wells in the Company's thermal oil projects, and 2 service wells in the Northern Plains region. (3) Includes bitumen wells. North America During 2023, the Company drilled 61 net natural gas wells, 132 net primary heavy crude oil wells, 2 net Pelican Lake heavy crude oil wells, 50 net bitumen (thermal oil) wells and 39 net light crude oil wells. (1) Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures. (2) A reconciliation of abandonment expenditures and abandonment expenditures, net is presented in the "Non-GAAP and Other Financial Measures" section of this MD&A. 33 Canadian Natural 2023 Annual Report Liquidity and Capital Resources ($ millions, except ratios) Adjusted working capital (1) Long-term debt, net (2) Shareholders’ equity 2023 712 $ 9,922 $ 39,832 $ 2022 (1,190) $ 10,525 $ 38,175 $ $ $ $ Debt to book capitalization (2) After-tax return on average capital employed (3) 20% 17% 22% 22% (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. 2021 (480) 13,950 36,945 27% 16% As at December 31, 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 are dependent on factors discussed in the "Business Environment" section and in the "Risks and Uncertainties" section of this MD&A. 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 the implementation of 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 2022, the Company repaid and cancelled its $500 million non-revolving portion of the $1,000 million term credit facility, reducing the remaining facility to the $500 million revolving credit facility maturing February 2023, and extended this facility from February 2023 to February 2024. During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025. ◦ During 2023, the Company extended its $2,425 million revolving syndicated credit facility originally maturing June 2024 to June 2027. ◦ The revolving syndicated credit facilities are extendible annually at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal would be repayable on the maturity date. Borrowings under the Company's revolving term 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. ◦ During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations. ◦ The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. ◦ During 2023, the Company repaid $405 million of 1.45% medium-term notes. ◦ During 2022, the Company repaid through market purchases $498 million of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028. ◦ During 2022, the Company repaid $1,000 million of 3.31% medium-term notes. Canadian Natural 2023 Annual Report 34 ◦ During 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. ◦ During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023. ◦ During 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 December 31, 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 $6,852 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At December  31, 2023, the Company had no commercial paper drawn under its commercial paper program and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program. During 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. As at December 31, 2023, the Company had no cross currency swap contracts outstanding. As at December 31, 2023, there were no foreign currency contracts designated as cash flow hedges. Long-term debt, net was $9,922 million at December  31, 2023, resulting in a debt to book capitalization ratio (1) of 20% (December  31, 2022 – 22%, December  31, 2021 – 27%); this ratio was below the 25% to 45% internal range utilized by management. The ratio may fall below or exceed the targeted range depending on the timing of acquisitions, the execution of the Company's capital program, and commodity price and foreign currency volatility. 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 at December  31, 2023 are discussed in note 11 to the Company’s audited consolidated 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 December 31, 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. Further details related to the Company’s commodity derivative financial instruments outstanding at December 31, 2023 are discussed in note 19 to the Company’s audited consolidated financial statements. As at December  31, 2023, the maturity dates of long-term debt and other long-term liabilities and related interest payments were as follows: Long-term debt (1) Other long-term liabilities (2) Interest and other financing expense (3) Less than 1 year 1 to less than 2 years 2 to less than 5 years $ $ $ 980 $ 302 $ 582 $ 1,584 $ 184 $ 518 $ 2,317 $ 428 $ 1,257 $ Thereafter 5,978 645 3,362 (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, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 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 December 31, 2023. (1) Capital management measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. 35 Canadian Natural 2023 Annual Report   SHARE CAPITAL As at December  31, 2023, there were 1,072,408,000 common shares outstanding (December  31, 2022 – 1,102,636,000 common shares) and 26,205,000 stock options outstanding (December  31, 2022 – 31,150,000 common shares). As at February 27, 2024, the Company had 1,070,845,000 common shares outstanding and 28,296,000 stock options outstanding. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $1.05 per common share, beginning with the dividend payable on April 5, 2024. On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share. 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. On November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 per common share. On March 3, 2021, the Board of Directors approved an 11% increase in the quarterly dividend to $0.47 per common share, from $0.425 per common share. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. 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. During 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share for a total cost of $3,318 million. Retained earnings were reduced by $2,929 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2023, up to and including February 27, 2024, the Company purchased 4,000,000 common shares at a weighted average price of $85.54 per common share for a total cost of $342 million. On February 28, 2024, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE. Share Split On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024. Commitments and Contingencies In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company’s commitments as at December 31, 2023: ($ millions) Product transportation and processing (1) North West Redwater Partnership service toll (2) Offshore vessels and equipment Field equipment and power Other $ $ $ $ $ 2024 2025 2026 2027 2028 Thereafter 1,572 $ 1,595 $ 1,408 $ 1,358 $ 1,242 $ 13,380 158 $ 36 $ 38 $ 145 $ 157 $ — $ 25 $ 111 $ 139 $ — $ 23 $ 112 $ 126 $ 130 $ 4,985 — $ 22 $ 25 $ — $ 22 $ 26 $ — 193 355 (1) The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion reflects interim tolls approved by the Canada Energy Regulator in the fourth quarter of 2023, and is subject to change pending the approval of final tolls. (2) 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 $3,011 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. Canadian Natural 2023 Annual Report 36 Reserves For the years ended December  31, 2023 and 2022, the Company retained Independent Qualified Reserves Evaluators to evaluate and review all of the Company’s total proved and total proved plus probable reserves. The evaluation and review was conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and disclosed in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") requirements. The following are reconciliation tables of the Company gross total proved and total proved plus probable reserves using forecast prices and costs as at the effective date of December 31, 2023: Total Proved December 31, 2022 (1) Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2023 (1) Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil (MMbbl) 231 (MMbbl) 179 (MMbbl) 262 Bitumen (Thermal Oil) (MMbbl) 3,284 Synthetic Crude Oil (MMbbl) 6,873 — 18 8 — — — 1 (12) (27) 218 — 22 6 — — — 1 13 — — — 1 — — 1 12 (28) 193 (17) 258 — 68 — 6 — — 1 24 (96) — 191 — 34 — — — (23) (165) Natural Gas (Bcf) 13,627 5 1,246 638 — — (7) (81) 362 (785) Natural Gas Liquids Barrels of Oil Equivalent (MMbbl) 486 (MMBOE) 13,587 — 43 35 — — (1) (2) 3 1 548 156 40 — (2) (12) 77 (22) (486) 3,287 6,910 15,005 543 13,910 Total Proved Plus Probable Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil December 31, 2022 (1) Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2023 (1) (MMbbl) 320 (MMbbl) 272 (MMbbl) 376 — 28 12 — — — 1 — 37 8 — — — 1 (28) (27) 305 (2) (28) 288 — — — 1 — — 1 4 (17) 365 Bitumen (Thermal Oil) (MMbbl) 5,186 Synthetic Crude Oil (MMbbl) 7,408 — 97 — 7 — — 1 — 209 — 51 — — — (4) (96) (43) (165) Natural Gas (Bcf) 22,270 7 2,009 962 — — (8) (88) (83) (785) 5,191 7,460 24,284 Natural Gas Liquids Barrels of Oil Equivalent (MMbbl) 772 (MMBOE) 18,046 1 74 48 — — (1) (2) (21) (22) 848 2 780 227 58 — (2) (12) (108) (486) 18,504 (1) Information in the reserves data tables may not add due to rounding. BOE values as presented may not calculate due to rounding. At December  31, 2023, the total proved crude oil, bitumen (thermal oil) and NGLs reserves were 11,409 MMbbl, and total proved plus probable crude oil, bitumen (thermal oil) and NGLs reserves were 14,457 MMbbl. Total proved reserves additions and revisions replaced 126% of 2023 production. Additions to total proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions amounted to 430 MMbbl, and additions to total proved plus probable reserves amounted to 570 MMbbl. Net positive revisions amounted to 18 MMbbl for total proved reserves and net negative revisions amounted to 92 MMbbl for total proved plus probable reserves, primarily due to technical revisions. At December  31, 2023, the total proved natural gas reserves were 15,005 Bcf, and total proved plus probable natural gas reserves were 24,284 Bcf. Total proved reserves additions and revisions replaced 275% of 2023 production. Additions to total proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions amounted to 1,882 Bcf, and additions to total proved plus probable reserves amounted to 2,970 Bcf. Net positive revisions amounted to 280 Bcf for total proved reserves, primarily due to technical revisions. Net negative revisions amounted to 171 Bcf for total proved plus probable reserves, primarily due to economic factors and technical revisions. 37 Canadian Natural 2023 Annual Report       The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with each of the Company’s Independent Qualified Reserves Evaluators to review the qualifications of and procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of future net revenue of the remaining reserves. Additional reserves information is annually disclosed in the AIF. The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States FASB Topic 932 "Extractive Activities - Oil and Gas" in the Company’s annual report on Form 40-F filed with the SEC and in the "Supplementary Oil and Gas Information" section of the Company’s annual report. Risks and Uncertainties The Company is exposed to various operational risks inherent in the exploration, development, production and marketing of crude oil and NGLs and natural gas and the mining, extracting and upgrading of bitumen into SCO. These inherent risks include, but are not limited to, the following: ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ Volatility in the prevailing prices of crude oil and NGLs, natural gas and refined products; The ability to find, produce and replace reserves, whether sourced from exploration, improved recovery or acquisitions, at a reasonable cost, including the risk of reserves revisions due to economic and technical factors. Reserves revisions can have a positive or negative impact on asset valuations, ARO and depletion rates; Reservoir quality and uncertainty of reserves estimates; Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in projects; Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner; Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting and upgrading the Company’s bitumen products; Timing and success of integrating the business and operations of acquired companies and assets; Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including derivative financial instruments and physical sales contracts as part of a hedging program; Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms; Foreign exchange risk due to the effect of fluctuating exchange rates on the Company’s US dollar denominated debt and revenue from sales predominantly based on US dollar denominated benchmarks; Environmental impact risk associated with exploration and development activities, including GHG; Future legislative and regulatory developments related to environmental regulation, including but not limited to GHG compliance costs and reduction targets; The timing and pace of change to a low carbon economy is uncertain and the ability to access insurance and capital may be adversely affected in the event that financial institutions, investors, insurers, rating agencies and/or lenders adopt more restrictive decarbonisation policies; Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or restrictions in the jurisdictions where the Company has operations, including but not limited to restrictions on production and the certainty and timelines for regulatory processes; Geopolitical risks associated with changing governments or governmental policies, social instability and other political, economic or diplomatic developments in the regions where the Company has its operations; Changing royalty regimes; The ability to secure adequate transportation for products, which could be affected by pipeline constraints, the construction by third parties of new or expansion of existing pipeline capacity and other factors; The access to markets for the Company’s products; The risk of significant interruption or failure of the Company's information technology systems and related data and control systems or a significant breach that could adversely affect the Company's operations; Business interruptions because of unexpected events such as fires or explosions whether caused by human error or nature, severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or equipment failures of facilities and infrastructure and other similar events affecting the Company or other parties whose operations or assets directly or indirectly impact the Company and that may or may not be financially recoverable; Canadian Natural 2023 Annual Report 38 ▪ ▪ ▪ Epidemics or pandemics have the potential to disrupt the Company’s operations, projects and financial condition through the disruption of the local or global supply chain and transportation services, or the loss of manpower resulting from quarantines that affect the Company’s labour pools in the local communities, workforce camps or operating sites or that are instituted by local health authorities as a precautionary measure, any of which may require the Company to temporarily reduce or shutdown its operations depending on the extent and severity of a potential outbreak and the areas or operations impacted (as was the case with the COVID-19 pandemic). Depending on the severity, a large scale epidemic or pandemic could impact international demand for commodities and have a corresponding impact on the prices realized by the Company, which could have a material adverse effect on the Company's financial condition; Liquidity risk related to the Company's ability to fulfill financial obligations as they become due or ability to liquidate assets in a timely manner at a reasonable price; and Other circumstances affecting revenue and expenses. The Company uses a variety of means to seek to mitigate and/or minimize these risks. The Company maintains a comprehensive property loss and business interruption insurance program to reduce risk. Operational control is enhanced by focusing efforts on large core areas with high working interests and by assuming operatorship of key facilities. Product mix is diversified, consisting of the production of natural gas and the production of crude oil of various grades and NGLs. The Company believes this diversification reduces price risk when compared with over-leverage to one commodity. Accounts receivable from the sale of crude oil and natural gas are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company seeks to manage these risks by 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. Derivative financial instruments are periodically utilized to help ensure targets are met and to manage commodity price, foreign currency and interest rate exposures. The Company is exposed to possible losses in the event of non- performance by counterparties to derivative financial instruments; however, the Company seeks to manage this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions. The arrangements and policies concerning the Company’s financial instruments are under constant review and may change depending upon the prevailing market conditions. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company has implemented cyber security protocols and procedures designed to reduce the risk of failure or a significant breach of the Company’s information technology systems and related data and control systems. The Company has safety, integrity and environmental management systems to recover and process crude oil and natural gas resources safely, efficiently, and in an environmentally sustainable manner and mitigate risk. The Company’s capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist. For additional details regarding the Company’s risks and uncertainties, refer to the Company’s AIF for the year ended December 31, 2023. Environment The Company has a Corporate Statement on Environmental Management which affirms that environmental stewardship is a fundamental value of the Company. The Company continues to invest in people, proven and new technologies, facilities and infrastructure to recover and process crude oil and natural gas resources efficiently and in an environmentally responsible and sustainable manner. Environmental, social, economic and health considerations are evaluated in new project designs and in operations to improve environmental performance. Processes are employed to avoid, mitigate, minimize or compensate for environmental effects. When working with local communities, the Company considers the interests and values of the people using the land in proximity to its operations, and where appropriate, adapts projects to recognize those matters. The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation compliance, particularly in North America and the North Sea. Existing and expected legislation and regulations may require the Company to address and mitigate the effect of its activities on the environment. The Company has processes in place and is committed to complying with all existing environmental standards and regulations and has included appropriate amounts in its capital budget to continue to meet current environmental protection requirements; however there are no assurances that the effect of future environmental laws and regulations will not be significant to the Company's business, financial condition and results of operations. Increasingly stringent laws and regulations may have an adverse effect on the Company’s future net earnings. The Company’s associated environmental risk management strategies incorporate working constructively with legislators and regulators on any new or revised policies, legislation or regulations to reflect a balanced approach to sustainable development. Specific measures in response to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, water management and land management to minimize disturbance impacts. The Company’s environmental risk management strategies employ an Environmental Management Plan (the "Plan"). 39 Canadian Natural 2023 Annual Report As part of risk management, the Company develops, assesses and implements technologies and innovative practices that will improve environmental performance, often through collaborative efforts with industry partners, governments and research institutions. Details of the Plan, along with performance results, are presented to, and reviewed by, the Board of Directors quarterly. The Plan and the Company's operating guidelines focus on minimizing the impact of operations while meeting regulatory requirements, regional management frameworks for air quality and emissions, ground and surface water and biodiversity, industry operating standards and guidelines, and internal corporate standards. Training and due diligence for operators and contractors is key to the effectiveness of the Company’s environmental management programs and the prevention of incidents to protect the environment. The Company, as part of this Plan, has implemented proactive programs that include: ▪ ▪ Environmental planning to assess potential impacts and implement avoidance and mitigation programs in order to maintain biodiversity for terrestrial and aquatic systems and high value ecosystems; Continued evaluation of new technologies to reduce environmental impacts, including support for Canada’s Oil Sands Innovation Alliance ("COSIA"), the innovation arm of Pathways, Petroleum Technology Alliance Canada ("PTAC") and other research institutions; ▪ Mitigation of the Company's climate change impacts through implementation of various CO2 emissions reduction and carbon capture projects including: CO2 injection for EOR, CO2 injection in tailings and the Quest Carbon Capture and Storage Facility; a methane emissions reduction program, including solution gas conservation to reduce methane venting, and an equipment retrofit program to reduce methane emissions from pneumatic equipment; and optimization of efficiencies at the Company’s facilities; ▪ Water programs to improve efficiency of use and recycle rates as well as to reduce fresh water use; ▪ ▪ ▪ Groundwater monitoring for all thermal in situ and mine operations; Effective reclamation and decommissioning programs across the Company’s operations. In North America, well abandonment and progressive reclamation of large contiguous areas of land provides the foundation for the enhancement of biodiversity and functional wildlife habitats. In the Company's International operations, decommissioning activities continued for the Banff and Kyle fields and planning commenced for decommissioning of the Ninian Hub area; Tailings management in Oil Sands Mining to minimize fine tailings and promote progressive reclamation; ▪ Monitoring programs to assess changes to biodiversity, wildlife and fisheries in order to manage construction and operation effects and to assess reclamation success; ▪ ▪ ▪ ▪ Participation and support for the Oil Sands Monitoring Program of regional important resources; An active spill prevention and management program; Supporting regional air shed monitoring for emissions and their deposition; and An internal environmental management system for compliance audit and inspection programs of operating facilities. The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been discounted using a weighted average discount rate of 5.2% (2022 – 5.6%; 2021 – 4.0%). For 2023, the Company’s capital expenditures included $509 million for abandonment expenditures (2022 – $449 million; 2021 – $307 million). Refer to the “Non-GAAP and Other Financial Measures” section of this MD&A for further details on abandonments expenditures, net. The Company’s estimated discounted ARO at December 31, 2023 was as follows: ($ millions) Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream and Refining 2023 2022 $ 4,471 $ 1,441 165 1,612 1 $ 7,690 $ 4,326 1,011 143 1,427 1 6,908 The discounted ARO was based on estimates of future costs to abandon and restore wells, production facilities, mine sites, upgrading facilities and tailings, and offshore production platforms. Factors that affect costs include number of wells drilled, well depth, facility size and the specific environmental legislation. The estimated future costs are based on estimates of current costs in accordance with present legislation, industry operating practice as well as the expected work scope and the timing of abandonment. Canadian Natural 2023 Annual Report 40       In 2021, the Alberta Energy Regulator (“AER”) announced a new Liability Management Framework, as part of its life-cycle management of oil and gas wells, facilities and pipelines, which imposes annual mandatory spending targets for companies for the closure of inactive wells and related infrastructure. Under the framework, the AER assigns licensees a mandatory annual spend target for their abandonment and reclamation activities, which is determined based on a licensee's proportionate share of the provincial inventory of inactive wells and related infrastructure, among other factors. Mandatory spend targets became effective January 1, 2022 and were increased for the 2023 performance year. During 2022, the government of Saskatchewan also introduced the Inactive Liability Reduction Program and the government of British Columbia updated its Dormancy and Shutdown Regulations, which provide mandatory targets for decommissioning and restoring inactive wells and facilities in those provinces. The Company has updated its forecasts of future expenditures to settle its ARO liability based on the set and forecasted annual targets. As a result, the Company’s ARO liability as at December 31, 2022 was increased on an inflated and discounted basis due to earlier forecasted expenditures to settle liabilities associated with the closure of inactive well and facilities. GREENHOUSE GAS AND OTHER EMISSIONS The Company has a large, diversified and balanced portfolio and a risk management strategy which incorporates an integrated GHG emissions reduction strategy and investments in technology and innovation to improve its GHG performance. The Company’s integrated GHG emissions reduction strategy includes: 1) integrating emissions reduction in project planning and operations; 2) leveraging technology to create value and enhance performance; 3) investing in research and development and supporting collaboration with industry, entrepreneurs, academia and governments; 4) focusing on continuous improvement to drive long-term emissions reduction; 5) leading in carbon capture, sequestration and storage; 6) engaging in policy and regulatory development (including trading capacity and offsetting emissions); and, 7) reviewing and developing new business opportunities and trends. The Company is a founding member and contributor to the Pathways Alliance, an alliance of oil sands producers working collectively with federal and provincial governments, to achieve the goal of net zero GHG emissions from oil sands operations by 2050 to help Canada meet its climate goals, including its Paris Agreement commitments and 2050 net zero aspirations. The Company, through industry associations, is working with Canadian legislators and regulators as they develop and implement new GHG emission laws and regulations to support emissions reductions and properly reflect a balanced approach to sustainable development. Internally, the Company is pursuing an integrated emissions reduction strategy and is committed to complying with existing and future emissions reduction requirements, for both GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to develop strategies that will enable it to deal with the risks and opportunities associated with new GHG and air emissions policies. In addition, the Company is working with relevant parties to ensure that new policies encourage technological innovation, energy efficiency, and targeted research and development while not impacting competitiveness. Governments in jurisdictions in which the Company operates have developed or are developing GHG regulations as part of their national and international climate change commitments. The Company uses existing GHG regulations to determine the impact of compliance costs on current and future projects. The Company monitors the development of GHG regulations on an ongoing basis in the jurisdictions in which it operates to assess the impact of future regulatory developments on the Company's operations and planned projects. In Canada, the federal government has ratified the Paris climate change agreement, with a commitment to reduce GHG emissions by 40 - 45% from 2005 levels by 2030. In 2022, the federal government released the Clean Fuel Regulations that were effective July 1, 2023, which apply to producers or importers of gasoline and diesel and require reductions in the carbon intensity associated with gasoline and diesel fuels produced and supplied in Canada. The Canadian government has also committed to cap and cut emissions from the oil and gas sector, and in December 2023, announced a regulatory framework for a national cap-and-trade system with plans to publish draft regulations by mid-2024. The draft framework currently proposed to cap 2030 emissions at 35-38% below 2018 levels (as estimated by Environment and Climate Change Canada) while providing some compliance flexibility to emit up to 20-23% below the 2019 threshold. The federal government is also developing a comprehensive management system for air pollutants and has released regulations pertaining to certain boilers, heaters and compressor engines operated by the Company. The federal government announced its intention to increase the carbon price to $170/tonne by 2030 in annual increments of $15/tonne after 2022. Carbon pricing regulatory systems in all provinces are subject to periodic review by the federal government to assess the adequacy of the provincial systems against the federal Greenhouse Gas Pollution Pricing Act. Such future reviews may affect the carbon price and/or the stringency of provincial systems. In Alberta, effective January 1, 2020, the GHG regulation (the Carbon Competitiveness Incentive Regulation) was replaced with the Technology Innovation and Emissions Reduction Regulation ("TIER"). The coverage of TIER has expanded to include all of the Company's assets in Alberta (as an alternative to the federal fuel charge). In December 2022, the Alberta government published changes to TIER effective January 1, 2023 that reduce the amount of emissions allocations for facilities under the regulation. Additionally, emissions coverage within TIER was expanded to include flaring from all TIER regulated facilities. The carbon price in Alberta was $65/tonne for emissions above the TIER-regulated limits in 2023 and increases annually in $15/ tonne increments to $170/tonne in 2030, which aligns with the federal carbon pricing schedule. The non-operated Scotford Upgrader and the North West Redwater bitumen upgrader and refinery are also subject to compliance under TIER. 41 Canadian Natural 2023 Annual Report In British Columbia, carbon tax is currently being assessed at $65/tonne of CO2e on fuel consumed and gas flared and vented in the province and is expected to continue to increase by $15/tonne of CO2e annually until reaching $170/tonne of CO2e in 2030 as stated in the 2023 provincial budget, which aligns with the federal carbon pricing schedule. Additionally, the government of British Columbia announced in its 2023 provincial budget that it would replace its carbon tax for large industrial emitters with an output based pricing system that will take effect on April 1, 2024. As part of its Prairie Resilience Plan, the Saskatchewan government has a regulation ("The Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations") that applies to facilities emitting more than 25 kilotonnes of CO2e annually and required the North Tangleflags in situ heavy oil facility and the Senlac in situ heavy crude oil facility to meet reduction targets for GHG emissions effective 2020. This regulation also enables facilities below the threshold to aggregate and opt into the Saskatchewan regulatory system as an alternative to the federal fuel charge. This regulation also adopts the federal carbon pricing schedule to 2030. In Manitoba, the federal output-based pricing system and carbon pricing schedule applies for facilities with emissions greater than or equal to 10 kilotonnes of CO2e annually, and the federal fuel charge applies for facilities with emissions of less than 10 kilotonnes of CO2e annually. By 2025, the federal government has committed to reduce methane emissions from the oil and gas sector by 40% to 45% below 2012 levels. The federal government's methane regulation came into effect on January 1, 2020 and applies nationally unless provinces reach equivalency agreements with the federal government, under which the federal regulation would not be in effect for those jurisdictions. The provinces of British Columbia, Alberta and Saskatchewan have implemented provincial methane regulations, and have reached equivalency agreements with the federal government. Accordingly, the applicable provincial methane regulations govern in the three western provinces whereas the federal methane regulation applies to methane emissions in the province of Manitoba. In 2022, the federal government announced a framework for expanding methane regulations to achieve at least a 75% reduction below 2012 levels, by 2030 with the draft regulatory framework released in November 2022 and amendments published in December 2023. Feedback on the draft regulations will continue into 2024. In the UK, GHG regulations have been in effect since 2005. In Phase 1 (2005 - 2007) of the UK National Allocation Plan, the Company operated below its CO2 allocation. In Phase 2 (2008 - 2012) the Company’s CO2 allocation was decreased below the Company’s operations emissions. In Phase 3 (2013 - 2020) the Company’s CO2 allocation was further reduced. Following the UK's withdrawal from the European Union ("EU") on January 31, 2020, a new UK Emissions Trading Scheme ("ETS") was launched on January 1, 2021. The new scheme is currently aligned with the EU ETS rules and applies to energy intensive industries, the power generation sector and aviation. The Company continues to focus on implementing CO2 emission reduction program opportunities at its facilities and on trading mechanisms to ensure compliance with requirements now in effect. Accounting Policies and Standards REGULATORY DEVELOPMENTS On May 27, 2021, the Canadian Securities Administrators ("CSA") announced the adoption of NI 52-112 and related amendments. This National Instrument replaces the previous CSA staff notice on Non-GAAP Measures. NI 52-112 governs how entities present non-GAAP and other financial measures and ratios. The requirements apply to the Company's MD&A and certain other disclosure documents beginning in 2021. CHANGES IN ACCOUNTING POLICIES In May 2023, the IASB issued amendments to IAS 12 "Income Taxes" related to the accounting for deferred taxes arising in those jurisdictions implementing the Organization for Economic Co-operation and Development's Pillar Two model rules ("Pillar Two Legislation"). Pillar Two Legislation did not have a significant impact on the Company’s financial results in 2023, and based on legislation substantively enacted to date in jurisdictions in which the Company currently operates, is not expected to have a significant impact on the Company's results in future periods. In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. In February 2021, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to require companies to disclose their material accounting policy information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS Practice Statement 2 "Making Materiality Judgements". The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. Canadian Natural 2023 Annual Report 42 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 this MD&A and the audited consolidated financial statements for the year ended December 31, 2023. A) Depletion, Depreciation and Amortization and Impairment Exploration and evaluation ("E&E") costs relating to activities to explore and evaluate crude oil and natural gas properties are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E assets are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. Technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. The judgements associated with the estimation of proved reserves are described below in "Crude Oil and Natural Gas Reserves". An alternative acceptable accounting method for E&E costs under IFRS 6 "Exploration for and Evaluation of Mineral Resources" is to charge exploratory dry holes and geological and geophysical exploration costs incurred after having obtained the legal rights to explore an area against net earnings in the period incurred rather than capitalizing to E&E assets. E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of related Cash Generating Units ("CGUs"), aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. The determination of the fair value of CGUs requires the use of assumptions and estimates including future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and production costs, discount rates, income taxes, and the potential impact of climate related matters and in accordance with related government regulations. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Crude oil and natural gas properties in the Exploration and Production segments are depleted using the unit-of-production method over proved reserves, except for major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future estimated development expenditures required to develop proved reserves. Estimates of proved reserves have a significant impact on net earnings, as they are a key input to the calculation of depletion expense. The Company assesses property, plant and equipment for impairment discounted at rates currently ranging from 10% to 12% whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low commodity prices for an extended period, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs a recoverability assessment related to the specific assets at the CGU level. B) Crude Oil and Natural Gas Reserves Reserves estimates are based on estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements, including the potential impact of climate related matters and in accordance with related government regulations. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information. Reserves estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and amortization and for determining potential asset impairment. For example, a revision to the proved reserves estimates would result in a higher or lower depletion, depreciation and amortization charge to net earnings. Downward revisions to reserves estimates may also result in an impairment of E&E and property, plant and equipment carrying amounts. C) Asset Retirement Obligations The Company is required to recognize a liability for ARO associated with its property, plant and equipment, including property, plant and equipment for which underlying reserves have been de-booked, and the carrying value of the asset has been fully depleted. An ARO liability associated with the retirement of a tangible long-lived asset is recognized to the extent of a legal obligation resulting from an existing or enacted law, statute, ordinance or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company’s total ARO amount, including the potential impact of climate related matters and in accordance with related government regulations. These individual assumptions may be subject to change. 43 Canadian Natural 2023 Annual Report The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they are incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at the Company’s weighted average credit-adjusted risk-free interest rate, which is currently 5.2%. Subsequent to initial measurement, the ARO is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense whereas changes in discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Changes in estimates would impact accretion and depletion expense. In addition, differences between actual and estimated costs to settle the ARO, timing of cash flows to settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO. D) Income Taxes The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted that are expected to apply when the asset or liability is recovered. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be due. E) Risk Management Activities The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as appropriate. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction and these differences may be material. F) Purchase Price Allocations Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties, together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation and amortization expense and impairment tests. The Company has made various assumptions in determining the fair values of acquired assets and liabilities. The most significant assumptions and judgements relate to the estimation of the fair value of crude oil and natural gas properties. To determine the fair value of these properties, the Company estimates crude oil and natural gas reserves. Reserves estimates are based on the work performed by the Company’s internal engineers and outside consultants. The judgements associated with these estimated reserves are described above in "Crude Oil and Natural Gas Reserves". Estimates of future prices are based on prices derived from price forecasts among industry analysts and internal assessments. The Company applies estimated future prices to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimated future net revenues for the properties acquired. G) Share-Based Compensation The Company has made various assumptions in estimating the fair values of stock options granted including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the estimated fair value of the liability. H) Leases Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility. To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit in the lease is not readily determinable. Canadian Natural 2023 Annual Report 44 I) Government Grants The Company receives or is eligible for government grants including emissions credits. Government grants are recognized in net earnings when there is reasonable assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and offset credits generated under the Alberta TIER regulation are initially recorded at fair value as determined by the prescribed Alberta TIER fund compliance rates in effect at the time the credits are recognized. Control Environment The Company’s management, including the President, the Chief Financial Officer and the Senior Vice-President, Finance and Principal Accounting Officer, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2023, and concluded that disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings and other reports filed with securities regulatory authorities in Canada and the United States is recorded, processed, summarized and reported within the time periods specified and such information is accumulated and communicated to the Company’s management to allow timely decisions regarding required disclosures. The Company’s management, including the President, the Chief Financial Officer, and the Senior Vice-President, Finance and Principal Accounting Officer, also evaluated the effectiveness of internal control over financial reporting as at December  31, 2023, and concluded that internal control over financial reporting is effective. Further, there were no changes in the Company’s internal control over financial reporting during 2023 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting. While the Company’s management believes that the Company’s disclosure controls and procedures and internal control over financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 45 Canadian Natural 2023 Annual Report Non-GAAP and Other Financial Measures This MD&A includes references to non-GAAP and other financial measures as defined in NI 52-112. These financial measures are used by the Company to evaluate its financial performance, financial position and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the Company's audited consolidated financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company’s non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below. ADJUSTED NET EARNINGS FROM OPERATIONS Adjusted net earnings from operations is a non-GAAP financial measure that adjusts net earnings as presented in the Company's consolidated Statements of Earnings, for non-operating items, net of tax impacts. The Company considers adjusted net earnings from operations a key measure in evaluating its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. A reconciliation for adjusted net earnings from operations is presented below. ($ millions) Net earnings Share-based compensation, net of tax (1) Unrealized risk management loss (gain), net of tax (2) Unrealized foreign exchange (gain) loss, net of tax (3) Realized foreign exchange (gain) loss, net of tax (4) Gain on acquisitions, net of tax (5) Gain from investments, net of tax (6) Recoverability charge, net of tax (7) (8) Other, net of tax (9) Non-operating items, net of tax Adjusted net earnings from operations 2023 2022 $ 8,233 $ 10,937 $ 474 7 (260) — — (34) 113 — 300 780 (25) 852 (62) — (182) 651 (88) 1,926 $ 8,533 $ 12,863 $ 2021 7,664 495 16 (205) 118 (478) (132) — (58) (244) 7,420 (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 2023 was an expense of $491 million (2022 – $804 million expense; 2021 – $514 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 Company's audited consolidated 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 2023 was $12 million (2022 – $28 million gain; 2021 – $19 million loss). (3) Unrealized foreign exchange losses and gains result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps in 2022, and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange losses and gains are the same. (4) During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023, resulting in a realized foreign exchange loss of $7 million. Also, during 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, resulting in a realized foreign exchange gain of $69 million. During 2021, the Company repaid US$500 million of 3.45% debt securities, resulting in a realized foreign exchange loss of $118 million. Pre- and after-tax amounts for these realized foreign exchange gains and losses are the same. (5) During 2021, the Company completed two acquisitions resulting in a pre- and after-tax gain of $478 million. (6) The Company’s investments have been accounted for at fair value through profit and loss and are measured each period with (gains) losses recognized in net earnings. There is zero net tax impact on these (gains) losses from investments. (7) The Company recognized a pre-tax recoverability charge of $436 million in depletion, depreciation and amortization expense related to revised project scope and the current cost environment for planned decommissioning and abandonment activities at the Ninian field in the North Sea in 2023. The costs are considered to be capital in nature, consistent with the treatment of all abandonment related expenditures for the purpose of the Company's non-GAAP measures. (8) The Company recognized a pre-tax recoverability charge of $1,620 million in depletion, depreciation and amortization expense at December 31, 2022 relating to the de-booking of reserves at the Ninian field in the North Sea. Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked associated crude oil reserves as at December 31, 2022, and is accelerating abandonment. (9) During 2022, the Company recognized the impact of government grant income under the provincial well-site rehabilitation programs of $114 million (2021 –  $75 million). Canadian Natural 2023 Annual Report 46 ADJUSTED FUNDS FLOW Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. A reconciliation for adjusted funds flow, from cash flows from operating activities is presented below. ($ millions) Cash flows from operating activities Net change in non-cash working capital Abandonment expenditures, net (1) Movements in other long-term assets (2) Adjusted funds flow 2023 2022 $ 12,353 $ 19,391 $ 2,417 509 (5) (79) 335 144 2021 14,478 (964) 232 (13) $ 15,274 $ 19,791 $ 13,733 (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, accrued interest on the deferred PRT recovery, accrued interest on subordinated debt advances to NWRP and prepaid cost of service tolls. ADJUSTED NET EARNINGS FROM OPERATIONS AND ADJUSTED FUNDS FLOW, PER 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 17 to the Company's audited consolidated 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 historical annual capital budgets. Abandonment expenditures, net is calculated as abandonment expenditures, as presented in the Company's audited 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. ($ millions) Abandonment expenditures Government grants for abandonment expenditures Abandonment expenditures, net $ $ 2023 509 $ — 509 $ 2022 449 $ (114) 335 $ 2021 307 (75) 232 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", "Per Unit Results – Exploration and Production", and "Per Unit Results – Oil Sands Mining and Upgrading" sections of this MD&A for the netback calculations on a per unit basis for crude oil and NGLs, natural gas 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 22 to the Company's audited consolidated financial statements. 47 Canadian Natural 2023 Annual Report REALIZED PRICE ($/BBL AND $/BOE) – EXPLORATION AND PRODUCTION Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE sales include the impact of blending and feedstock costs and other by-product sales. The Company considers realized price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market for its crude oil and NGLs sales volumes and BOE sales volumes. Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized price are presented below. ($ millions, except bbl/d and $/bbl) Crude oil and NGLs (bbl/d) North America International North Sea Offshore Africa Total International Total sales volumes Crude oil and NGLs sales (1) (2) Less: Blending and feedstock costs (3) Realized crude oil and NGLs sales Realized price ($/bbl) 2023 2022 2021 497,604 480,691 471,331 10,749 14,882 25,631 523,235 13,215 14,866 28,081 508,772 $ $ $ 18,387 $ 22,072 $ 4,568 13,819 $ 72.36 $ 5,239 16,833 $ 90.64 $ 18,942 13,452 32,394 503,725 15,505 3,792 11,713 63.71 (1) Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements. (2) Includes other miscellaneous income in the segment. (3) Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section. ($ millions, except BOE/d and $/BOE) Barrels of oil equivalent (BOE/d) North America International North Sea Offshore Africa Total International Total sales volumes Barrels of oil equivalent sales (1) (2) Less: Blending and feedstock costs (3) Less: Sulphur income Realized barrels of oil equivalent sales Realized price ($/BOE) 2023 2022 2021 854,138 826,526 751,330 11,034 16,638 27,672 881,810 13,598 16,933 30,531 857,057 $ $ $ 20,820 $ 27,071 $ 4,568 (14) 16,266 $ 50.54 $ 5,239 (88) 21,920 $ 70.07 $ 19,512 15,385 34,897 786,227 18,025 3,792 (21) 14,254 49.67 (1) Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 22 to the Company's audited consolidated financial statements. (2) Includes other miscellaneous income in the segment. (3) Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section. Canadian Natural 2023 Annual Report 48 TRANSPORTATION – EXPLORATION AND PRODUCTION Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products to the market excluding the impact of blending and feedstock costs. A reconciliation for Exploration and Production transportation and the calculations for transportation on a per unit basis are presented below. ($ millions, except $ per unit amounts) Transportation, blending and feedstock (1) Less: Blending and feedstock costs Transportation Transportation ($/BOE) Amounts attributed to crude oil and NGLs Transportation ($/bbl) Amounts attributed to natural gas Transportation ($/Mcf) $ $ $ $ $ $ $ 2023 5,816 $ 4,568 1,248 $ 3.88 $ 807 $ 4.23 $ 441 $ 0.56 $ 2022 6,401 $ 5,239 1,162 $ 3.72 $ 767 $ 4.13 $ 395 $ 0.51 $ 2021 4,780 3,792 988 3.44 710 3.86 278 0.45 (1) Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements. NORTH AMERICA – REALIZED PRODUCT PRICES AND ROYALTIES Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial measure) divided by sales volumes. Realized crude oil and NGLs sales include the impact of blending and feedstock costs. The Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes. Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it describes the Company’s royalties for crude oil and NGLs sales volumes on a per unit basis. A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices and the royalty rates are presented below. ($ millions, except $/bbl and royalty rates) Crude oil and NGLs sales (1) Less: Blending and feedstock costs (2) Realized crude oil and NGLs sales Realized crude oil and NGLs prices ($/bbl) Crude oil and NGLs royalties (3) Crude oil and NGLs royalty rates $ $ $ $ 2023 2022 17,375 $ 20,755 $ 4,568 12,807 $ 70.51 $ 5,239 15,516 $ 88.43 $ 2,340 $ 3,445 $ 18% 22% 2021 14,478 3,792 10,686 62.10 1,558 15% (1) Crude oil and NGLs sales in note 22 to the Company's audited consolidated 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 22 to the Company's audited consolidated financial statements. 49 Canadian Natural 2023 Annual Report 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. ($ millions, except for bbl/d and $/bbl) SCO sales volumes (bbl/d) Crude oil and NGLs sales (1) (2) Less: Blending and feedstock costs Realized SCO sales Realized SCO sales price ($/bbl) Transportation, blending and feedstock (3) Less: Blending and feedstock costs Transportation Transportation ($/bbl) 2023 449,282 2022 428,820 2021 447,230 $ $ $ $ $ $ 18,661 $ 20,804 $ 2,253 16,408 $ 100.06 $ 2,563 $ 2,253 310 $ 1.89 $ 2,384 18,420 $ 117.69 $ 2,652 $ 2,384 268 $ 1.71 $ 14,033 1,309 12,724 77.95 1,505 1,309 196 1.21 (1) Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements. (2) Excludes other miscellaneous income not pertaining to crude oil and NGLs sales. (3) Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements. CHANGE IN COMPOSITION OF NON-GAAP FINANCIAL MEASURE During the fourth quarter of 2023, the Company revised the composition of its Net Capital Expenditures non-GAAP financial measure to exclude expenditures related to the Company's abandonment program. The revision was made during Management's assessment of its annual capital budgeting process, and will provide users a better representation of the composition of the Company's capital budget, and in evaluating performance. The composition of this measure has been updated for all periods presented. NET CAPITAL EXPENDITURES Net capital expenditures is a non-GAAP financial measure that represents cash flows used in investing activities as presented in the Company's audited consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, proceeds from investments, the repayment of NWRP subordinated debt advances, the settlement of long-term debt assumed in acquisitions, and cash flows from investing activities not included in the Company's capital budget. The Company includes acquisition and disposition capital in net capital expenditures. 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. ($ millions) Cash flows used in investing activities Net change in non-cash working capital Proceeds from investment Repayment of NWRP subordinated debt advances Settlement of long-term debt acquired (1) Net capital expenditures (2) Abandonment expenditures, net (3) Capital and abandonment expenditures 2023 2022 $ 4,858 $ 4,987 $ 51 — — — 4,909 509 149 — — — 5,136 335 $ 5,418 $ 5,471 $ 2021 3,703 107 128 555 183 4,676 232 4,908 (1) Relates to the settlement of long-term debt assumed in the acquisition of Storm in 2021. (2) For 2023, includes base capital expenditures of $3,958 million and strategic growth capital expenditures of $925 million. Strategic growth capital expenditures represent the allocation of the Company's free cash flow that will be directed to strategic capital growth opportunities that target to increase production volumes in future periods and that exceed the Company's base capital expenditures for the current fiscal year, as outlined in the Company's capital budget. (3) Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section above. Canadian Natural 2023 Annual Report 50 LIQUIDITY Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities, cash and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing the Company's financial position. The Company’s calculation of liquidity is presented below. ($ millions) Undrawn bank credit facilities Cash and cash equivalents Investments Liquidity LONG-TERM DEBT, NET $ $ 2023 2022 5,450 $ 5,520 $ 877 525 920 491 6,852 $ 6,931 $ 2021 6,098 744 309 7,151 Long-term debt, net, is a capital management measure that represents long-term debt less cash and cash equivalents, as disclosed in note 16 to the Company's audited consolidated financial statements. A reconciliation of the Company's long-term debt, net is presented below. ($ millions) Long-term debt Less: cash and cash equivalents Long-term debt, net DEBT TO BOOK CAPITALIZATION 2023 2022 10,799 $ 11,445 $ 877 920 9,922 $ 10,525 $ 2021 14,694 744 13,950 $ $ 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 16 to the Company's audited consolidated financial statements. AFTER-TAX RETURN ON AVERAGE CAPITAL EMPLOYED After-tax return on average capital employed as defined by the Company is a non-GAAP ratio. The ratio is calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed (defined as current and long-term debt plus shareholders' equity) for the twelve month trailing period. The Company considers this ratio a key measure in evaluating the Company’s ability to generate profit and the efficiency with which it employs capital. A reconciliation of the Company's after-tax return on average capital employed is presented below. ($ millions, except ratios) Interest adjusted after-tax return: Net earnings (loss), 12 months trailing Interest and other financing expense, net of tax, 12 months trailing (1) Interest adjusted after-tax return 12 months average current portion long-term debt (2) 12 months average long-term debt (2) 12 months average common shareholders' equity (2) 12 months average capital employed 2023 2022 2021 $ $ $ $ 8,233 $ 10,937 $ 490 424 8,723 $ 11,361 $ 1,259 $ 1,359 $ 10,354 38,974 11,761 38,218 50,587 $ 51,338 $ 7,664 547 8,211 1,483 16,769 34,458 52,710 After-tax return on average capital employed 17% 22% 16% (1) The blended tax rate on interest was 23% for December 31, 2023, 23% for December 31, 2022, and 23% for December 31, 2021. (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. 51 Canadian Natural 2023 Annual Report Outlook The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company believes will enable it, over an extended period of time, to provide consistent growth in production and create shareholder value. Annual budgets are developed, scrutinized throughout the year and revised if necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures in each of its project areas. 2024 CAPITAL BUDGET On December 14, 2023, the Company announced its 2024 capital budget targeted at approximately $5,420 million, and targets to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns and the balancing of project risks and time horizons. The 2024 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements. Other SENSITIVITY ANALYSIS The following table is indicative of the annualized sensitivities of cash flows from operating activities and net earnings due to changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2023, excluding mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results. Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables being held constant. Price changes Crude oil – WTI US$1.00/bbl Excluding financial derivatives Natural gas – AECO C$0.10/Mcf (1) Excluding financial derivatives Including financial derivatives Volume changes Crude oil – 10,000 bbl/d Natural gas – 10 MMcf/d Foreign currency rate change $0.01 change in US$ (1) Including financial derivatives Interest rate change – 1% Cash flows from Operating Activities ($ millions) Cash flows from Operating Activities (per common share, basic) Net earnings ($ millions) Net earnings (per common share, basic) $ $ $ $ $ $ $ 334 $ 0.31 $ 334 $ 42 $ 40 $ 174 $ 3 $ 0.04 $ 0.04 $ 0.16 $ — $ 42 $ 40 $ 149 $ — $ 270 $ 5 $ 0.25 $ — $ 150 $ 5 $ 0.31 0.04 0.04 0.14 — 0.14 — (1) For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2023. Canadian Natural 2023 Annual Report 52             DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES Q1 Q2 Q3 Q4 2023 2022 2021 Crude oil and NGLs (bbl/d) North America – Exploration and Production 477,349 465,143 519,581 521,579 496,100 479,971 472,621 North America – Oil Sands Mining and Upgrading (1) 458,228 355,246 490,853 500,133 451,339 425,945 448,133 International North Sea Offshore Africa Total International Total Crude oil and NGLs Natural gas (MMcf/d) (2) North America International North Sea Offshore Africa Total International Total Natural gas Barrels of oil equivalent (BOE/d) North America – Exploration and 13,240 12,699 12,016 12,616 12,639 12,890 17,633 14,091 13,821 12,703 13,213 13,452 14,343 14,017 27,331 26,520 24,719 25,829 26,091 27,233 31,650 962,908 846,909 1,035,153 1,047,541 973,530 933,149 952,404 2,127 2,072 2,139 2,218 2,139 2,075 1,680 3 9 12 2 11 13 1 11 12 2 11 13 2 10 12 2 13 15 3 12 15 2,139 2,085 2,151 2,231 2,151 2,090 1,695 Production 831,846 810,451 876,099 891,225 852,633 825,806 752,620 North America – Oil Sands Mining and Upgrading (1) 458,228 355,246 490,853 500,133 451,339 425,945 448,133 International North Sea Offshore Africa Total International 13,659 12,976 12,199 12,880 12,925 13,273 18,203 15,658 15,653 14,463 15,075 15,208 16,410 15,950 29,317 28,629 26,662 27,955 28,133 29,683 34,153 Total Barrels of oil equivalent 1,319,391 1,194,326 1,393,614 1,419,313 1,332,105 1,281,434 1,234,906 (1) SCO production before royalties excludes SCO consumed internally as diesel. (2) Natural gas production volumes approximate sales volumes. 53 Canadian Natural 2023 Annual Report                                             PER UNIT RESULTS – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) Realized price (2) Transportation (2) Realized price, net of transportation (2) Royalties (3) Production expense (4) Netback (2) Natural gas ($/Mcf) (1) Realized price (5) Transportation (6) Realized price, net of transportation Royalties (3) Production expense (4) Netback Barrels of oil equivalent ($/BOE) (1) Realized price (2) Transportation (2) Realized price, net of transportation (2) Royalties (3) Production expense (4) Netback (2) Q1 Q2 Q3 Q4 2023 2022 2021 $ 58.85 $ 72.06 $ 87.83 $ 69.39 $ 72.36 $ 90.64 $ 63.71 4.52 54.33 10.09 16.93 4.57 67.49 11.09 18.38 4.07 83.76 17.32 14.40 3.83 65.56 11.38 15.05 4.23 68.13 12.55 16.12 4.13 86.51 18.91 18.17 $ 27.31 $ 38.02 $ 52.04 $ 39.13 $ 39.46 $ 49.43 $ $ 4.27 $ 2.53 $ 2.81 $ 2.80 $ 3.10 $ 6.55 $ $ $ 0.55 3.72 0.28 1.47 0.58 1.95 0.07 1.37 0.56 2.25 0.09 1.25 0.54 2.26 0.09 1.13 0.56 2.54 0.13 1.30 0.51 6.04 0.61 1.22 1.97 $ 0.51 $ 0.91 $ 1.04 $ 1.11 $ 4.21 $ 44.98 $ 4.03 48.94 $ 4.11 59.40 $ 3.78 48.41 $ 3.61 50.54 $ 3.88 70.07 $ 3.72 40.95 44.83 6.56 6.75 13.51 14.24 55.62 10.61 11.64 44.80 46.66 7.05 7.77 11.75 12.74 66.35 12.75 13.76 $ 20.88 $ 23.84 $ 33.37 $ 26.00 $ 26.15 $ 39.84 $ 3.86 59.85 8.59 14.71 36.55 4.07 0.45 3.62 0.22 1.18 2.22 49.67 3.44 46.23 5.98 11.98 28.27 (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. PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING Crude oil and NGLs ($/bbl) (1) Realized SCO sales price (2) Bitumen royalties (3) Transportation (2) Production expense (4) Netback (2) Q1 Q2 Q3 Q4 2023 2022 2021 $ 96.07 $ 95.08 $ 108.55 $ 98.73 $ 100.06 $ 117.69 $ 77.95 10.04 1.52 25.06 13.58 2.03 31.28 21.90 2.18 22.12 11.57 1.85 20.96 14.43 1.89 24.32 20.71 1.71 26.04 $ 59.45 $ 48.19 $ 62.35 $ 64.35 $ 59.42 $ 69.23 $ 6.62 1.21 20.91 49.21 (1) For SCO sales volumes, refer to the "Non-GAAP and Other Financial Measures" 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 sales volumes. (4) Calculated as production costs divided by sales volumes. Canadian Natural 2023 Annual Report 54                                 TRADING AND SHARE STATISTICS TSX – C$ Trading volume (thousands) Share Price ($/share) High Low Close Market capitalization as at December 31 ($ millions) Shares outstanding (thousands) NYSE – US$ Trading volume (thousands) Share Price ($/share) High Low Close Q1 Q2 Q3 Q4 2023 2022 384,779 373,032 475,363 463,881 1,697,055 1,533,722 $ $ $ 82.89 $ 83.18 $ 90.70 $ 93.44 $ 93.44 $ 67.13 $ 69.83 $ 71.61 $ 81.68 $ 67.13 $ 74.79 $ 74.48 $ 87.84 $ 86.81 $ 86.81 $ 88.18 54.20 75.19   $ 93,096 $ 82,907   1,072,408 1,102,636 137,402 126,047 132,453 206,964 602,866 755,722 $ $ $ 62.29 $ 62.33 $ 67.23 $ 68.74 $ 68.74 $ 48.81 $ 52.66 $ 53.62 $ 59.39 $ 48.81 $ 55.35 $ 56.26 $ 64.67 $ 65.52 $ 65.52 $ 70.60 42.32 55.53 Market capitalization as at December 31 ($ millions) Shares outstanding (thousands)   $ 70,264 $ 61,229   1,072,408 1,102,636 55 Canadian Natural 2023 Annual Report                                                                     Consolidated Financial Statements Table of Contents Management's Report Management’s Assessment of Internal Control over Financial Reporting Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets Consolidated Statements of Earnings Consolidated Statements of Comprehensive Income Consolidated Statements of Changes in Equity Consolidated Statements of Cash Flows Notes to the Consolidated Financial Statements 1. Accounting Policies 2. Changes in Accounting Policies 3. Accounting Standards Issued But Not Yet Applied 4. Critical Accounting Estimates and Judgements 5. Inventory 6. Exploration and Evaluation Assets 7. Property, Plant and Equipment 8. Leases 9. Investments 10. Other Long-Term Assets 11. Long-Term Debt 12. Other Long-Term Liabilities 13. Income Taxes 14. Share Capital 15. Accumulated Other Comprehensive Income 16. Capital Disclosures 17. Net Earnings Per Common Share 18. Interest and Other Financing Expense 19. Financial Instruments 20. Commitments and Contingencies 21. Supplemental Disclosure of Cash Flow Information 22. Segmented Information 23. Remuneration of Directors and Senior Management Canadian Natural 2023 Annual Report 57 58 59 61 62 62 63 64 65 65 71 71 71 73 73 74 76 77 77 79 81 82 85 86 87 87 87 88 91 91 92 96 56 Management’s Report The accompanying consolidated financial statements of Canadian Natural Resources Limited (the "Company") and all other information contained elsewhere in this Annual Report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies described in the accompanying notes. Where necessary, management has made informed judgements and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board as appropriate in the circumstances. The financial information presented elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements. Management maintains appropriate systems of internal control. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorized and recorded, assets are safeguarded from loss or unauthorized use and financial records are properly maintained to provide reliable information for preparation of financial statements. PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has been engaged, as approved by a vote of the shareholders at the Company’s most recent Annual General Meeting, to audit and provide their independent audit opinions on the following: ▪ ▪ the Company’s consolidated financial statements as at and for the year ended December 31, 2023; and the effectiveness of the Company’s internal control over financial reporting as at December 31, 2023. Their report is presented with the consolidated financial statements. The Board of Directors (the "Board") is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board exercises this responsibility through the Audit Committee of the Board, which is comprised entirely of independent directors. The Audit Committee meets with management and the independent auditors to satisfy itself that management responsibilities are properly discharged and to review the consolidated financial statements before they are presented to the Board for approval. The consolidated financial statements have been approved by the Board on the recommendation of the Audit Committee. SCOTT G. STAUTH President MARK A. STAINTHORPE, CFA VICTOR C. DAREL, CPA, CA Chief Financial Officer Senior Vice-President, Finance and Principal Accounting Officer Calgary, Alberta, Canada February 28, 2024 57 Canadian Natural 2023 Annual Report Management’s Assessment of Internal Control over Financial Reporting Management of Canadian Natural Resources Limited (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) under the United States Securities Exchange Act of 1934, as amended. Management, including the Company’s President and the Company’s Chief Financial Officer, performed an assessment of the Company’s internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on the assessment, management has concluded that the Company’s internal control over financial reporting was effective as at December 31, 2023. Management recognizes that all internal control systems have inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has provided an opinion on the Company’s internal control over financial reporting as at December  31, 2023, as stated in their accompanying Report of Independent Registered Public Accounting Firm. SCOTT G. STAUTH President MARK A. STAINTHORPE, CFA Chief Financial Officer Calgary, Alberta, Canada February 28, 2024 Canadian Natural 2023 Annual Report 58 Report of Independent Registered Public Accounting Firm To the Shareholders and Board of Directors of Canadian Natural Resources Limited Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of Canadian Natural Resources Limited and its subsidiaries (together, the Company) as of December 31, 2023 and 2022, and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 59 Canadian Natural 2023 Annual Report Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. The Impact of Crude Oil and Natural Gas Reserves on Property, Plant and Equipment Assets in the North America Exploration and Production Segment As described in Notes 1, 4 and 7 to the Company’s consolidated financial statements, the property, plant and equipment (PP&E) balance in the North America Exploration and Production segment was $24.6 billion as of December 31, 2023. Depletion, depreciation and amortization (DD&A) expense for the North America Exploration and Production segment was $3.6 billion for the year ended December 31, 2023. In accordance with the Company’s accounting policies, crude oil and natural gas properties in the North America Exploration and Production segment, excluding certain major components, are depleted using the unit-of- production method based on proved reserves. Estimates of the Company’s crude oil and natural gas reserves are based on estimated future prices and production costs, expected future rates of production and the timing and amount of future development expenditures. Management utilizes third party specialists, specifically independent qualified reserve evaluators, to evaluate and review its estimates of crude oil and natural gas reserves. These estimates are utilized for the calculation of DD&A expense. The principal considerations for our determination that performing procedures relating to the impact of crude oil and natural gas reserves on PP&E assets in the North America Exploration and Production segment is a critical audit matter are that there was a significant amount of judgment by management, including the use of specialists, when developing the estimates, specifically related to the estimates of crude oil and natural gas reserves in the North America Exploration and Production segment. This led to a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating evidence obtained related to the assumptions used in developing the estimates, including estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of internal controls in the North America Exploration and Production segment relating to management’s estimates of the Company’s crude oil and natural gas reserves and the calculation of DD&A expense. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of crude oil and natural gas reserves used to determine DD&A expense for the North America Exploration and Production segment. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings. The procedures performed also included, among others, evaluating whether the assumptions used by management’s specialists related to estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures were reasonable considering the current and past performance of the Company, consistency with industry pricing forecasts, and whether they were consistent with evidence obtained in other areas of the audit, as applicable. Additionally, these procedures also included testing the unit-of-production rates used to calculate DD&A expense. /s/ PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Canada February 28, 2024 We have served as the Company's auditor since 1973. Canadian Natural 2023 Annual Report 60 Consolidated Balance Sheets As at December 31, (millions of Canadian dollars) ASSETS Current assets Cash and cash equivalents Accounts receivable Inventory Prepaids and other Investments Current portion of other long-term assets Exploration and evaluation assets Property, plant and equipment Lease assets Other long-term assets LIABILITIES Current liabilities Accounts payable Accrued liabilities Current income taxes payable Current portion of long-term debt Current portion of other long-term liabilities Long-term debt Other long-term liabilities Deferred income taxes SHAREHOLDERS’ EQUITY Share capital Retained earnings Accumulated other comprehensive income Commitments and contingencies (note 20). Note 2023 2022 5 9 10 6 7 8 10 11 12 11 12 13 14 15 $ 877 $ 3,189 2,034 471 525 71 7,167 2,208 64,581 1,458 541   $ 75,955 $   $ 1,418 $ 3,534 — 980 1,503 7,435 9,819 8,686 10,183 36,123 10,712 28,948 172 39,832   $ 75,955 $ 920 3,555 1,815 215 491 61 7,057 2,226 64,859 1,447 553 76,142 1,341 4,209 1,324 404 1,373 8,651 11,041 8,161 10,114 37,967 10,294 27,672 209 38,175 76,142 Approved by the Board of Directors on February 28, 2024. CATHERINE M. BEST N. MURRAY EDWARDS Chair of the Audit Committee and Director Executive Chairman of the Board of Directors and Director 61 Canadian Natural 2023 Annual Report                                                             Consolidated Statements of Earnings For the years ended December 31, (millions of Canadian dollars, except per common share amounts) Note Product sales 22 $ Less: royalties Revenue Expenses Production Transportation, blending and feedstock Depletion, depreciation and amortization Administration Share-based compensation Asset retirement obligation accretion Interest and other financing expense Risk management activities (gain) loss Foreign exchange (gain) loss Gain on acquisitions Income from North West Redwater Partnership Gain from investments Earnings before taxes Current income tax expense Deferred income tax expense (recovery) Net earnings Net earnings per common share Basic Diluted 7,8 12 12 18 19 10 9 13 13 17 17 2023 40,835 $ (4,867) 35,968 2022 49,530 $ (7,232) 42,298 8,480 9,302 6,413 452 491 366 636 (2) (279) — — 8,712 9,973 7,353 415 804 281 549 (35) 738 — — (56) (196) 25,803 10,165 1,879 53 28,594 13,704 2,906 (139) $ $ $ 8,233 $ 10,937 $ 7.54 $ 7.47 $ 9.64 $ 9.52 $ 2021 32,854 (2,797) 30,057 7,152 6,604 5,724 366 514 185 711 36 (127) (478) (400) (141) 20,146 9,911 1,848 399 7,664 6.49 6.46 Consolidated Statements of Comprehensive Income For the years ended December 31, (millions of Canadian dollars) Net earnings Items that may be reclassified subsequently to net earnings Net change in derivative financial instruments designated as cash flow hedges Unrealized income, net of taxes of $nil (2022 – $1 million, 2021 –  $2 million) Reclassification to net earnings, net of taxes of $nil (2022 –  $1 million, 2021 – $1 million) Foreign currency translation adjustment Translation of net investment Other comprehensive (loss) income, net of taxes 2023 2022 $ 8,233 $ 10,937 $ 2021 7,664 2 (5) (3) (34) (37) 4 (6) (2) 212 210 15 (7) 8 (17) (9) Comprehensive income $ 8,196 $ 11,147 $ 7,655 Canadian Natural 2023 Annual Report 62             Consolidated Statements of Changes in Equity For the years ended December 31, (millions of Canadian dollars) Share capital Balance – beginning of year Issued upon exercise of stock options Previously recognized liability on stock options exercised for common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year Retained earnings Balance – beginning of year Net earnings Dividends on common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year Accumulated other comprehensive income (loss) Balance – beginning of year Other comprehensive (loss) income, net of taxes Balance – end of year Shareholders’ equity Note 14 14 14 15 2023 2022 2021   $ 10,294 $ 10,168 $ 372 435 (389) 10,712 27,672 8,233 (4,028) (2,929) 28,948 209 (37) 172 442 387 (703) 10,294 26,778 10,937 (5,175) (4,868) 27,672 (1) 210 209 9,606 707 139 (284) 10,168 22,766 7,664 (2,355) (1,297) 26,778 8 (9) (1)   $ 39,832 $ 38,175 $ 36,945 63 Canadian Natural 2023 Annual Report                               Consolidated Statements of Cash Flows For the years ended December 31, (millions of Canadian dollars) Operating activities Net earnings Non-cash items Note 2023 2022 2021 $ 8,233 $ 10,937 $ 7,664 Depletion, depreciation and amortization 7,8 Share-based compensation Asset retirement obligation accretion Unrealized risk management loss (gain) Unrealized foreign exchange (gain) loss Gain on acquisitions Gain from investments Deferred income tax expense (recovery) Realized foreign exchange (gain) loss (1) Proceeds on settlement of cross currency swap Abandonment expenditures Other Net change in non-cash working capital Cash flows from operating activities 12 21 Financing activities Repayment of bank credit facilities and commercial paper, net 11,21 11,21 Repayment of medium-term notes Repayment of US dollar debt securities Settlement of long-term debt acquired Proceeds on settlement of cross currency swaps Payment of lease liabilities Issue of common shares on exercise of stock options Dividends on common shares Purchase of common shares under Normal Course Issuer Bid Cash flows used in financing activities Investing activities Net expenditures on exploration and evaluation assets Net expenditures on property, plant and equipment Proceeds from investment Repayment of North West Redwater Partnership subordinated debt advances Net change in non-cash working capital Cash flows used in investing activities (Decrease) increase in cash and cash equivalents Cash and cash equivalents – beginning of year Cash and cash equivalents – end of year Interest paid on long-term debt, net Income taxes paid (received) 11,21 8,21 14 14 6,22 7,22 9 10 21 6,413 491 366 12 (260) — (34) 53 — — (509) 5 (2,417) 12,353 — (416) — — — (285) 372 (3,891) (3,318) (7,538) (44) (4,865) — — 51 7,353 804 281 (28) 852 — (182) (139) (62) 89 (449) (144) 79 5,724 514 185 19 (205) (478) (132) 399 118 — (307) 13 964 19,391 14,478 (1,156) (1,498) (1,356) — 69 (232) 442 (4,926) (5,571) (14,228) (33) (5,103) — — 149 (6,151) — (628) (183) — (209) 707 (2,170) (1,581) (10,215) (1) (4,492) 128 555 107 (4,858) (4,987) (3,703) (43) 920 877 $ 602 $ 176 744 920 $ 613 $ 3,317 $ 3,057 $   $   $   $ 560 184 744 672 (62) (1) Consists of the realized foreign exchange gain on settlement of cross currency swaps in 2022, and the realized foreign exchange loss on repayment of US dollar debt securities in 2022 and 2021. Canadian Natural 2023 Annual Report 64                               Notes to the Consolidated Financial Statements (tabular amounts in millions of Canadian dollars, unless otherwise stated) 1. Accounting Policies Canadian Natural Resources Limited (the "Company") is a senior independent crude oil and natural gas exploration, development and production company. The Company’s exploration and production operations are focused in North America, largely in Western Canada; the United Kingdom ("UK") portion of the North Sea; and Côte d’Ivoire and South Africa in Offshore Africa. The Oil Sands Mining and Upgrading segment produces synthetic crude oil through bitumen mining and upgrading operations at Horizon Oil Sands ("Horizon") and through the Company's direct and indirect interest in the Athabasca Oil Sands Project ("AOSP"). Within Western Canada, in the Midstream and Refining segment, the Company maintains certain activities that include pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership ("NWRP"), a general partnership formed to upgrade and refine bitumen in the Province of Alberta. The Company was incorporated in Alberta, Canada. The address of its registered office is 2100, 855 - 2 Street S.W., Calgary, Alberta, Canada. The Company’s consolidated financial statements and the related notes have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The accounting policies adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies throughout all periods presented, except where IFRS permits new accounting standards to be adopted prospectively. Changes in the Company's accounting policies are discussed in note 2. (A) PRINCIPLES OF CONSOLIDATION The consolidated financial statements have been prepared under the historical cost basis, unless otherwise required. The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly owned partnerships. Subsidiaries include all entities over which the Company has control. Subsidiaries are consolidated from the date on which the Company obtains control. They are deconsolidated from the date that control ceases. Certain of the Company’s activities are conducted through joint arrangements in which two or more parties have joint control. Where the Company has determined that it has a direct ownership interest in jointly controlled assets and obligations for the liabilities (a "joint operation"), the assets, liabilities, revenue and expenses related to the joint operation are included in the consolidated financial statements in proportion to the Company’s interest. Where the Company has determined that it has an interest in jointly controlled entities (a "joint venture"), it uses the equity method of accounting. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of the joint venture’s income or loss, less distributions received. If the Company’s share of the joint venture’s loss equals or exceeds its interest in the joint venture, the Company discontinues recognizing its share of further losses. The Company resumes recognizing profits when its share of profits exceeds the accumulated share of losses not recognized. Joint ventures accounted for using the equity method of accounting are tested for impairment whenever objective evidence indicates that the carrying amount of the investment may not be recoverable. Indications of impairment include a history of losses, significant capital expenditure overruns, liquidity concerns, financial restructuring of the investee or significant adverse changes in the technological, economic or legal environment. The amount of the impairment is measured as the difference between the carrying amount of the investment and the higher of its fair value less costs of disposal and its value in use. Impairment losses are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. (B) INVENTORY Inventory is primarily comprised of product inventory, materials and supplies and other inventory, including emissions credits, and is carried at the lower of cost and net realizable value. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in floating production, storage and offloading vessels ("FPSO"). Cost of product inventory consists of purchase costs, direct production costs, directly attributable overhead and depletion, depreciation and amortization and is determined on a first-in, first-out basis. Net realizable value for product inventory is determined by reference to forward prices. Cost for materials and supplies consists of purchase costs and is based on a first-in, first-out or an average cost basis. Net realizable value for materials and supplies and other inventory is determined by reference to current market prices. Emissions credit inventory generated in the normal course of business is initially measured in accordance with the Company's accounting policy for government grants. 65 Canadian Natural 2023 Annual Report (C) EXPLORATION AND EVALUATION ASSETS Exploration and evaluation ("E&E") assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination of proved reserves. E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized in net earnings. Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. An E&E asset is derecognized upon disposal or when no future economic benefits are expected to arise from its use. Any gain or loss arising on derecognition of the asset is recognized in net earnings within depletion, depreciation and amortization. E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of the related Cash Generating Units ("CGUs"), aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. (D) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is measured at cost less accumulated depletion and depreciation and recoverability charges. Assets under construction are not depleted or depreciated until available for their intended use. Exploration and Production The cost of an asset comprises its acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Property acquisition costs are comprised of the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant components of an item of property, plant and equipment, including crude oil and natural gas interests, have different useful lives, they are accounted for separately. Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for certain major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future development expenditures required to develop proved reserves. Oil Sands Mining and Upgrading Capitalized costs for the Oil Sands Mining and Upgrading segment are reported separately from the Company’s North America Exploration and Production segment. Capitalized costs include acquisition costs, construction and development costs, overburden removal costs incurred during the initial development of a mine at Horizon and AOSP, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Mine-related costs are depleted using the unit-of-production method based on proved reserves. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from overburden removal activity. Costs of the upgraders and related infrastructure located on the Horizon and AOSP sites are depreciated on the unit-of-production method based on the estimated productive capacity of the respective upgraders and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 20 years. Midstream, Refining and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream, refining and head office assets. Midstream and Refining assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head office assets are depreciated on a declining balance basis. Useful lives The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in depletion rates and useful lives accounted for prospectively. Derecognition A property, plant and equipment asset is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is recognized in net earnings within depletion, depreciation and amortization. Canadian Natural 2023 Annual Report 66 Major maintenance expenditures Inspection costs associated with major turnarounds are capitalized and depreciated over the period to the next major turnaround. Maintenance costs are expensed as incurred. Impairment The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU's recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and a recoverability charge is taken through depletion, depreciation and amortization expense. In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that previously recognized recoverability charges may no longer exist or may have decreased. If such indication exists, the recoverable amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, had no recoverability charge been recognized for the asset in prior periods. A reversal of a recoverability charge is recognized in net earnings. After a reversal, the depletion, depreciation and amortization charge is adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life. (E) BUSINESS COMBINATIONS Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in net earnings. (F) LEASES The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract. The lease asset is initially measured at cost. The cost of a lease asset includes the amount of the initial measurement of the lease liability, lease payments made prior to the commencement date, initial direct costs and estimates of the asset retirement obligation, if any. Subsequent to initial recognition, the lease asset is depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term. Lease liabilities are initially measured at the present value of lease payments discounted at the rate implicit in the lease, or if not readily determinable, the Company's incremental borrowing rate. Lease liabilities are remeasured if there are changes in the lease term or if the Company changes its assessment of whether it is reasonably certain it will exercise a purchase, extension or termination option. Lease liabilities are also remeasured if there are changes in the estimate of the amounts payable under the lease due to changes in indices or rates, or residual value guarantees. Lease assets are reported in a separate caption in the consolidated balance sheet. Lease liabilities are reported within other long-term liabilities in the consolidated balance sheet. Where the Company acts as the operator of a joint operation, the Company recognizes 100% of the related lease asset and lease liability. As the Company recovers its joint operation partners' share of the costs of the lease contract, these recoveries are recognized as other income in the consolidated statements of earnings. (G) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on all of its property, plant and equipment and certain exploration and evaluation assets based on current legislation and operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the date of the balance sheets. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense, whereas changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision. 67 Canadian Natural 2023 Annual Report (H) FOREIGN CURRENCY TRANSLATION Functional and presentation currency Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary economic environment in which the subsidiary operates (the "functional currency"). When the Company disposes of its entire interest in a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. (I) REVENUE RECOGNITION AND COSTS OF GOODS SOLD Revenue from the sale of crude oil and NGLs and natural gas products is recognized when performance obligations in the sales contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending beyond one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the term of the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time. Sales of the Company’s crude oil and NGLs and natural gas products to customers are made pursuant to contracts based on prevailing commodity pricing at or near the time of delivery and volumes of product delivered. Revenues are typically collected in the month following delivery and accordingly, the Company has elected to apply the practical expedient to not adjust consideration for the effects of a financing component. Purchases and sales of crude oil and NGLs and natural gas with the same counterparty, made to facilitate sales to customers or potential customers, that are entered into in contemplation of one another, are combined and recorded as non-monetary exchanges and measured at the net settlement amount. Revenue in the consolidated statement of earnings represents the Company’s share of product sales net of royalty payments to governments and other mineral interest owners. The Company discloses the disaggregation of revenues from sales of crude oil and NGLs and natural gas in the segmented information in note 22. Related costs of goods sold are comprised of production, transportation, blending and feedstock, and depletion, depreciation and amortization expenses. These amounts have been separately presented in the consolidated statements of earnings. (J) PRODUCTION SHARING CONTRACTS Production generated from Côte d’Ivoire in Offshore Africa is shared under the terms of various Production Sharing Contracts ("PSCs"). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the respective government state oil companies (the "Governments"). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs. (K) INCOME TAX The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases. Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring income taxes. Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using income tax rates that are substantively enacted at each reporting date. Canadian Natural 2023 Annual Report 68 (L) SHARE-BASED COMPENSATION The Company’s Stock Option Plan (the "Option Plan") provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are remeasured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the stock options are recorded as share capital. 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. PSUs vest three years from original grant date. The liability for PSUs is initially measured in reference to the Company's stock price and the number of awards expected to vest and is remeasured at each reporting period for changes in the fair value of the liability. The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets. (M) FINANCIAL INSTRUMENTS The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method. Cash and cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are solely comprised of payments of principal and interest. Investments in publicly traded shares are classified as fair value through profit or loss. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss. Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability. Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings. Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument. Impairment of financial assets At each reporting date, on a forward looking basis, the Company assesses the expected credit losses associated with its financial assets carried at amortized cost. Expected credit losses are measured as the difference between the cash flows that are due to the Company and the cash flows that the Company expects to receive, discounted at the effective interest rate determined at initial recognition. For trade accounts receivable, the Company applies the simplified approach permitted by IFRS 9, which requires expected lifetime credit losses to be recognized from initial recognition of the receivables. To measure expected credit losses, accounts receivable are grouped based on the number of days the receivables have been outstanding and internal credit assessments of the customers. Credit risk for longer-term receivables is assessed based on an external credit rating of the counterparty. For longer-term receivables with credit risk that has not increased significantly since the date of recognition, the Company measures the expected credit loss as the 12-month expected credit loss. Changes in the provision for expected credit loss are recognized in net earnings. 69 Canadian Natural 2023 Annual Report (N) RISK MANAGEMENT ACTIVITIES The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis. The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are recognized in risk management activities in net earnings. Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are recognized in risk management activities in net earnings. Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred under accumulated other comprehensive income and amortized into net earnings in the periods in which the underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings. Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk management activities in net earnings. (O) GOVERNMENT GRANTS The Company receives or is eligible for government grants, including emissions credits. Government grants are recognized in net earnings when there is reasonable assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and offset credits generated under the Alberta Technology Innovation and Emissions Reduction (“TIER”) regulation are initially recorded at the value prescribed by the Alberta TIER fund compliance rates in effect at the time the credits are recognized. (P) PER COMMON SHARE AMOUNTS The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method. (Q) SHARE CAPITAL Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a reduction of retained earnings. Shares are cancelled upon purchase. Canadian Natural 2023 Annual Report 70 2. Changes in Accounting Policies In May 2023, the IASB issued amendments to IAS 12 "Income Taxes" related to the accounting for deferred taxes arising in those jurisdictions implementing the Organization for Economic Co-operation and Development's Pillar Two model rules ("Pillar Two Legislation"). The amendments were effective immediately and adopted in the second quarter of 2023. Pillar Two Legislation did not have a significant impact on the Company’s financial results in 2023, and based on legislation substantively enacted to date in jurisdictions in which the Company currently operates, is not expected to have a significant impact on the Company's results in future periods. In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences. The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. In February 2021, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to require companies to disclose their material accounting policy information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS Practice Statement 2 "Making Materiality Judgements". The amendments were adopted on January 1, 2023 and did not have a significant impact on the Company's consolidated financial statements. 3. Accounting Standards Issued But Not Yet Applied In January 2020, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to clarify that liabilities are classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting period for an entity to defer settlement of the liability for at least twelve months after the reporting period. In October 2022, the IASB issued further amendments to specify that the classification of debt as current or non-current at the reporting date is not affected by covenants to be complied with after the reporting date, and added disclosure requirements about these covenants. All amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted retrospectively. These amendments have no impact on the Company's consolidated financial statements. 4. Critical Accounting Estimates and Judgements The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. (A) CRUDE OIL AND NATURAL GAS RESERVES Purchase price allocations, depletion, depreciation and amortization, asset retirement obligations, and amounts used in impairment calculations are based on estimates of crude oil and natural gas reserves. Reserves estimates are based on estimated future prices and production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements including the potential impact of climate related matters and in accordance with related government regulations. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information. (B) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and operating practices. Estimated future costs include assumptions of dates of future abandonment and technological advances and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in environmental legislation, the impact of inflation, changes in technology, changes in operating practices, revisions to work scope, changes in the date of abandonment due to changes in reserves life, and the potential impact of climate related matters and in accordance with related government regulations. These differences may have a material impact on the estimated provision. (C) INCOME TAXES The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be due. 71 Canadian Natural 2023 Annual Report (D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest rate yield curves and foreign exchange rates. (E) PURCHASE PRICE ALLOCATIONS Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests. (F) SHARE-BASED COMPENSATION The Company has made various assumptions in estimating the fair values of stock options granted under its Option Plan, including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the estimated fair value of the liability. (G) IDENTIFICATION OF CGUs CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, shared infrastructures, and the way in which management monitors the Company’s operations. (H) IMPAIRMENT OF ASSETS The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGUs' or the assets' fair value less costs of disposal and its value in use. These calculations require the use of estimates and assumptions and are subject to change as new information becomes available, including information on future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and operating costs, after-tax discount rates (currently ranging from 10% to 12%), and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. (I) LEASES Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility. To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit in the lease is not readily determinable. (J) CONTINGENCIES Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle the contingency. Canadian Natural 2023 Annual Report 72 5. Inventory Product inventory Materials, supplies and other $ $ 2023 546 $ 1,488 2,034 $ 2022 611 1,204 1,815 During 2023, approximately $29 billion of purchased and produced inventory was recorded as expense (2022 – approximately $33 billion). 6. Exploration and Evaluation Assets Cost At December 31, 2021 Additions/Acquisitions Transfers to property, plant and equipment Derecognitions and other Foreign exchange adjustments At December 31, 2022 Additions/Acquisitions Transfers to property, plant and equipment Derecognitions and other Foreign exchange adjustments Exploration and Production North America North Sea Offshore Africa   Oil Sands Mining and Upgrading Total $ 2,057 $ — $ 91 $ 102 $ 2,250 41 (71) (1) — 2,026 45 (38) (2) — — — — — — — — — — 5 — — 2 98 3 — — (1) — — — — 102 — (25) — — 77 $ 46 (71) (1) 2 2,226 48 (63) (2) (1) 2,208 At December 31, 2023 $ 2,031 $ — $ 100 $ 73 Canadian Natural 2023 Annual Report                     7. Property, Plant and Equipment Exploration and Production North America North Sea Offshore Africa   Oil Sands Mining and Upgrading Midstream and Refining Head Office Total Cost At December 31, 2021 $ 77,834 $ 7,438 $ 3,980 $ 46,856 $ 466 $ 508 $ 137,082 Additions/Acquisitions Transfers from exploration and evaluation assets Derecognitions (1) Disposals Foreign exchange adjustments and other At December 31, 2022 Additions/Acquisitions Transfers from exploration and evaluation assets Derecognitions (1) Foreign exchange 3,564 304 75 1,380 71 (394) — — 81,075 2,951 38 (581) — (1) — 517 8,258 558 — — — — — (469) (35) 277 — 4,332 47,732 187 2,088 — — 25 (470) adjustments and other — (210) (110) — At December 31, 2023 $ 83,483 $ 8,606 $ 4,409 $ 49,375 $ 8 — — — — 474 10 — — — 484 $ 25 5,356 — — — 3 71 (864) (35) 797 536 142,407 30 5,824 — — — 63 (1,051) (320) 566 $ 146,923 Accumulated depletion and depreciation At December 31, 2021 $ 52,732 $ 5,951 $ 2,923 $ 8,499 $ 183 $ 394 $ 70,682 Expense Derecognitions (1) Disposals Recoverability charge Foreign exchange adjustments and other At December 31, 2022 Expense Derecognitions (1) Recoverability charge Foreign exchange 3,502 (394) — — (5) 55,835 3,592 (581) — 117 (1) — 1,620 419 8,106 40 — 436 148 — — — 206 3,277 177 — — 1,684 (469) (2) — — 9,712 1,856 (470) — 15 — — — — 198 15 — — 23 — — — 3 420 24 — — 5,489 (864) (2) 1,620 623 77,548 5,704 (1,051) 436 adjustments and other (6) (200) (96) 7 At December 31, 2023 $ 58,840 $ 8,382 $ 3,358 $ 11,105 $ — 213 $ — (295) 444 $ 82,342 Net book value At December 31, 2023 At December 31, 2022 $ $ 24,643 $ 25,240 $ 224 $ 152 $ 1,051 $ 38,270 $ 1,055 $ 38,020 $ 271 $ 276 $ 122 $ 116 $ 64,581 64,859 (1) An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal. Canadian Natural 2023 Annual Report 74                                   Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked crude oil reserves as at December 31, 2022 and is accelerating abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651 million (after- tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $969 million. As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a non-cash charge of $113 million (after-tax) related to an increase in its estimate of the future abandonment costs for the Ninian field in the North Sea. The non-cash charge is comprised of a recoverability charge of $436 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $323 million. The Company’s estimate of its asset retirement obligation liability, including the Ninian field recoverability charge and associated tax recoveries, is subject to revision in future periods as abandonment efforts progress. As at December 31, 2023, the Company completed its normal course assessment of the recoverability of its other property, plant and equipment and exploration and evaluation assets, and determined the carrying amounts of all its cash generating units to be recoverable. As at December 31, 2023, property, plant and equipment included project costs, not subject to depletion and depreciation, of $191  million in the Oil Sands Mining and Upgrading segment (2022 – $162 million in the Oil Sands Mining and Upgrading segment). ACQUISITIONS IN 2022 & 2021 During 2022, the Company acquired a number of crude oil and natural gas properties in the North America Exploration and Production segment for net cash consideration of $513  million and assumed associated asset retirement obligations of $11 million. No net deferred income tax liabilities were recognized and no pre-tax gains were recognized on these transactions. During 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm Resources Ltd. ("Storm") for total cash consideration of $771  million. In connection with the acquisition the Company assumed certain product transportation and processing commitments (note 20). During 2021, the Company completed two acquisitions of natural gas producing assets and related processing infrastructure in the Montney region of British Columbia, including property, plant and equipment assets of $257  million and exploration and evaluation assets of $13  million, for cash consideration of $131  million. In connection with the acquisitions, the Company assumed asset retirement obligations of $58  million, other liabilities of $65  million, and recognized a deferred tax asset of $462 million. A gain of $478 million was recognized as a result of the acquisitions, representing the excess of the fair value of the net assets acquired compared with the total purchase consideration. Acquisitions in the comparative years have been accounted for as business combinations using the acquisition method of accounting. Gains reported on the acquisitions represent the excess of the fair value of the net assets acquired compared to the total purchase consideration. 75 Canadian Natural 2023 Annual Report 8. Leases LEASE ASSETS Product transportation and storage Field equipment and power Offshore vessels and equipment Office leases and other At December 31, 2021 $ Additions Depreciation Foreign exchange and other At December 31, 2022 Additions Depreciation Foreign exchange and other At December 31, 2023 $ LEASE ASSETS, BY SEGMENT 974 $ 44 (106) — 912 27 (98) (1) 840 $ 354 $ 110 (86) (1) 377 218 (111) (2) 482 $ 99 $ 28 (31) 1 97 49 (45) (30) 71 $ 81 $ — (21) 1 61 23 (19) — 65 $ As at December 31, 2023 and 2022, the Company had the following lease assets by segment: Total 1,508 182 (244) 1 1,447 317 (273) (33) 1,458 Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Head Office LEASE LIABILITIES 2023 2022 $ 280 $ 18 119 1,001 40 $ 1,458 $ 277 1 98 1,015 56 1,447 The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease liabilities at December 31, 2023 and 2022, were as follows: Lease liabilities Less: current portion $ $ 2023 1,555 $ 298 1,257 $ 2022 1,540 244 1,296 In addition to the lease assets disclosed above, on an ongoing basis the Company enters into short-term leases related to its Exploration and Production and Oil Sands Mining and Upgrading activities. Other amounts included in net earnings and cash flows during 2023 and 2022 are provided below: Expenses relating to short-term leases (1) Interest expense on lease liabilities Variable lease payments not included in the measurement of lease liabilities Total cash outflows for leases (2) $ $ $ $ 2023 403 $ 64 $ 59 $ 1,325 $ 2022 410 60 49 1,204 (1) During 2023, the Company capitalized $514 million (2022 – $453 million) of short-term leases as additions to property, plant and equipment. (2) Comprised of cash outflows relating to lease liabilities, short-term leases, and variable lease payments. Canadian Natural 2023 Annual Report 76           9. Investments As at December 31, 2023 and 2022, the Company had the following investment: Investment in PrairieSky Royalty Ltd. INVESTMENT IN PRAIRIESKY ROYALTY LTD. $ 2023 525 $ 2022 491 The Company’s 22.6 million common shares investment in PrairieSky Royalty Ltd. ("PrairieSky") does not constitute significant influence, and is accounted for at fair value through profit or loss, measured at each reporting date. As at December 31, 2023 the market price per common share was $23.20 (December 31, 2022 – $21.70; December 31, 2021 – $13.63). As at December  31, 2023, the Company’s investment in PrairieSky was classified as a current asset. PrairieSky is in the business of acquiring and managing oil and gas royalty income assets through indirect third-party oil and gas development. The gain from the investment in PrairieSky was comprised as follows: Gain from investment Dividend income $ $ 2023 (34) $ (22) (56) $ 2022 (182) $ (14) (196) $ 2021 (81) (7) (88) INVESTMENT IN INTER PIPELINE LTD. During 2021, in accordance with a third-party offer to purchase, the Company elected to take total cash proceeds of $128  million, or $20.00 per common share, in exchange for its 6.4  million common shares investment in Inter Pipeline Ltd ("Inter Pipeline"). In 2021, the Company also recognized a $53 million gain from the investment in Inter Pipeline comprised of a $51 million fair value gain on the investment and $2 million of dividend income. The Company's investment did not constitute significant influence, and was accounted for at fair value through profit or loss, measured at each reporting date. 10. Other Long-Term Assets Long-term prepayments, contracts and other (1) Prepaid cost of service toll Long-term inventory Risk management (note 19) Less: current portion $ 2023 279 $ 179 141 13 612 71 $ 541 $ 2022 269 199 137 9 614 61 553 (1) Includes physical product sales contracts assumed in acquisitions in prior periods, accrued interest on the deferred PRT recovery, and the unamortized portion of the Company's share bonus program. INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP The Company has a 50% equity investment in North West Redwater Partnership ("NWRP"). NWRP operates a 50,000 barrels per day bitumen upgrader and refinery that processes approximately 12,500 barrels per day (25% toll payer) of bitumen feedstock for the Company and 37,500 barrels per day (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 (note 20). Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment (note 22). On June 30, 2021, the equity partners together with the toll payers, agreed to optimize the structure of NWRP to better align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest remained unchanged. 77 Canadian Natural 2023 Annual Report       Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048 to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, and issued lower cost senior secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the Company received a $400 million distribution from NWRP during 2021. To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December 2023, $500  million of 2.00% series M senior secured bonds due December 2026, $1,000  million of 2.80% series N senior secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051. During 2023, NWRP repaid the $500 million of 1.20% series L senior secured bonds. As at December 31, 2023, NWRP had borrowings of $2,559 million under the syndicated credit facility (December 31, 2022 – $2,318 million), and borrowings of $77 million under its short-term demand operating facility (December 31, 2022 – $nil). During 2023, NWRP's syndicated credit facility was reduced by $60 million to $3,115 million (2022 – $3,175 million) following the repayment and cancellation of the portion of the non-revolving credit facility that matured in June 2023. NWRP's syndicated credit facility is comprised of a $2,175 million revolving credit facility, with $118 million maturing June 2024 and the remainder maturing June 2025, and a $940 million non-revolving credit facility maturing June 2025. During 2022, NWRP entered into a $150 million facility to support letters of credit. The assets, liabilities, partners’ equity, product sales and equity (loss) income related to NWRP at December 31, 2023 and 2022 were comprised as follows: Current assets Non-current assets Current liabilities Non-current liabilities Partners’ equity Partners’ equity at Company's 50% interest Revenue (1) Net (loss) income (2) 2023 349 $ 10,508 $ 1,054 $ 10,913 $ (1,110) $ (555) $ 1,527 $ (8) $ 2022 257 10,729 849 11,239 (1,102) (551) 1,267 22 $ $ $ $ $ $ $ $ (1) (2) Included in NWRP's revenue for 2023 is $335 million (2022 – $317 million) related to the Company's 25% share of the refining toll. Included in the net (loss) income for 2023 is the impact of depreciation and amortization expense of $387 million (2022 – $245 million) and interest and other financing expense of $500 million (2022 – $422 million). The carrying value of the Company’s interest in NWRP is $nil, and as at December 31, 2023, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $555 million (2022 – $551 million). The Company's unrecognized equity loss from NWRP for 2023 was $4 million (2022 – recovery of the unrecognized share of the equity loss of $11 million; 2021 – unrecognized equity loss of $9 million and partnership distributions were $400 million). Canadian Natural 2023 Annual Report 78 11. Long-Term Debt Canadian dollar denominated debt, unsecured Medium-term notes 1.45% debentures due November 16, 2023 3.55% debentures due June 3, 2024 3.42% debentures due December 1, 2026 2.50% debentures due January 17, 2028 4.85% debentures due May 30, 2047 US dollar denominated debt, unsecured US dollar debt securities 3.80% due April 15, 2024 (US$500 million) 3.90% due February 1, 2025 (US$600 million) 2.05% due July 15, 2025 (US$600 million) 3.85% due June 1, 2027 (US$1,250 million) 2.95% due July 15, 2030 (US$500 million) 7.20% due January 15, 2032 (US$400 million) 6.45% due June 30, 2033 (US$350 million) 5.85% due February 1, 2035 (US$350 million) 6.50% due February 15, 2037 (US$450 million) 6.25% due March 15, 2038 (US$1,100 million) 6.75% due February 1, 2039 (US$400 million) 4.95% due June 1, 2047 (US$750 million) Long-term debt before transaction costs and original issue discounts, net Less: original issue discounts, net (1) transaction costs (1) (2) Less: current portion of long-term debt (1) (2) 2023 2022 $ — $ 320 441 225 300 404 332 441 225 300 1,286 1,702 660 792 792 1,651 660 528 462 462 594 1,453 528 991 9,573 10,859 11 49 10,799 980 $ 9,819 $ 677 812 812 1,692 677 541 474 474 609 1,488 541 1,015 9,812 11,514 13 56 11,445 404 11,041 (1) The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. (2) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. 79 Canadian Natural 2023 Annual Report                   BANK CREDIT FACILITIES AND COMMERCIAL PAPER As at December  31, 2023, the Company had undrawn bank credit facilities of $5,450 million. Details of these facilities are described below. The Company also has certain other dedicated credit facilities supporting letters of credit. ▪ ▪ ▪ ▪ a $100 million demand credit facility; a $500 million revolving credit facility, maturing February 2025; a $2,425 million revolving syndicated credit facility, maturing June 2025; and a $2,425 million revolving syndicated credit facility, maturing June 2027. During 2023, the Company extended its $2,425 million revolving syndicated credit facility, originally maturing June 2024, to June 2027. During 2022, the Company repaid and cancelled the $1,150 million non-revolving term credit facility maturing February 2023. During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations. Borrowings under the Company's revolving term 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. During 2022, the Company repaid and cancelled $500 million of the non-revolving portion of the term credit facility, amended the remaining facility to a $500  million revolving credit facility, and extended maturity from February 2023 to February 2024. During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025. The Company’s borrowings under its US commercial paper program are authorized up to a maximum US$2,500  million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program. The Company’s weighted average interest rate on total long-term debt outstanding for the year ended December 31, 2023 was 4.8% (December 31, 2022 – 4.3%). As at December 31, 2023, letters of credit and guarantees aggregating to $446 million were outstanding (December 31, 2022 – $637 million). MEDIUM-TERM NOTES During 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. During 2023, the Company repaid $405 million of 1.45% medium-term notes. During 2022, the Company repaid $1,000 million of 3.31% medium-term notes. During 2022, the Company repaid through market purchases $95  million of 1.45% medium-term notes due November 2023, $169 million of 3.55% medium-term notes due June 2024, $159 million of 3.42% medium-term notes due December 2026, and $75 million of 2.50% medium-term notes due January 2028. US DOLLAR DEBT SECURITIES During 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. During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023. SCHEDULED DEBT REPAYMENTS Scheduled debt repayments are as follows: Year 2024 2025 2026 2027 2028 Thereafter Canadian Natural 2023 Annual Report $ $ $ $ $ $ Repayment 980 1,584 441 1,651 225 5,978 80 12. Other Long-Term Liabilities Asset retirement obligations Lease liabilities (note 8) Share-based compensation Transportation and processing contracts (1) Risk management (note 19) Other Less: current portion 2023 $ 7,690 $ 1,555 780 87 4 73 10,189 1,503 $ 8,686 $ 2022 6,908 1,540 832 159 3 92 9,534 1,373 8,161 (1) Product transportation and processing obligations assumed from acquisitions in prior years (note 7). ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and discounted using a weighted average discount rate of 5.2% (2022 – 5.6%; 2021 – 4.0%) and inflation rates of up to 2% (December 31, 2022 – up to 2%). Reconciliations of the discounted asset retirement obligations were as follows: Balance – beginning of year Liabilities incurred Liabilities acquired, net Liabilities settled Asset retirement obligation accretion Revision of cost, inflation and timing estimates (1) Impact of regulatory changes (2) Change in discount rates Foreign exchange adjustments Balance – end of year Less: current portion 2023 2022 $ 6,908 $ 6,806 $ 25 — 20 11 (509) (449) 366 621 — 314 (35) 7,690 634 281 897 982 (1,698) 58 6,908 495 $ 7,056 $ 6,413 $ 2021 5,861 5 76 (307) 185 508 1,208 (723) (7) 6,806 249 6,557 (1) Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to the acceleration of the abandonment and subsequent cost estimate increases on future abandonment at the Ninian field in the North Sea in 2022 and 2023. (2) Reflects changes to the estimated timing of settlement of the Company's asset retirement obligations due to provincial regulatory changes in Alberta, British Columbia and Saskatchewan in 2022 and 2021. Segmented Asset Retirement Obligations Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream and Refining 2023 2022 $ 4,471 $ 1,441 165 1,612 1 $ 7,690 $ 4,326 1,011 143 1,427 1 6,908 81 Canadian Natural 2023 Annual Report                   SHARE-BASED COMPENSATION The liability for share-based compensation includes costs incurred under the Company’s Option and PSU plans. The Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The PSU plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met. The Company recognizes a liability for potential cash settlements under these plans. The current portion of the liability represents the maximum amount of the liability payable within the next twelve month period if all vested stock options and PSUs are settled in cash. Balance – beginning of year Share-based compensation expense $ Cash payment for stock options surrendered and PSUs vested Transferred to common shares Other Balance – end of year Less: current portion 2023 832 $ 491 (110) (435) 2 780 538 2022 489 $ 804 (79) (387) 5 832 559 $ 242 $ 273 $ 2021 160 514 (48) (139) 2 489 329 160 Included within share-based compensation liability as at December 31, 2023 was $96 million (2022 – $127 million; 2021 – $90 million) related to PSUs granted to certain executive employees. The fair value of stock options outstanding was estimated using the Black-Scholes valuation model with the following weighted average assumptions: Fair value Share price Expected volatility Expected dividend yield Risk free interest rate Expected forfeiture rate Expected stock option life (1) (1) At original time of grant. $ $ 2023 35.93 $ 86.81 $ 30.9% 4.6% 3.6% 5.4% 2022 32.96 $ 75.19 $ 35.8% 4.5% 3.8% 5.0% 2021 16.98 53.45 35.5% 4.4% 1.1% 4.7% 4.2 years 4.2 years 4.2 years The intrinsic value of vested stock options at December 31, 2023 was $164 million (2022 – $208 million; 2021 – $112 million). 13. Income Taxes The provision for income tax was as follows: Expense (recovery) Current corporate income tax – North America (1) Current corporate income tax – North Sea Current corporate income tax – Offshore Africa Current PRT (2) – North Sea Other taxes Current income tax Deferred corporate income tax Deferred PRT (2) – North Sea Deferred income tax Income tax $ 2023 1,853 $ (6) 73 (58) 17 1,879 267 (214) 53 2022 2,789 $ 69 74 (42) 16 2,906 302 (441) (139) 2021 1,841 7 21 (34) 13 1,848 399 — 399 $ 1,932 $ 2,767 $ 2,247 (1) Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments. (2) Petroleum Revenue Tax. As at December 31, 2022, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax recovery of $528 million and a deferred PRT recovery of $441 million in connection with the Company's de-booking of its crude oil reserves and acceleration of the abandonment at the Ninian field in the North Sea (note 7). Canadian Natural 2023 Annual Report 82       As at December 31, 2023, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax recovery of $118 million and a deferred PRT recovery of $205 million in connection with the increase in the Company's estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea (note 7). The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows: Canadian statutory income tax rate Income tax provision at statutory rate Effect on income taxes of: UK PRT and other taxes Impact of UK PRT and other taxes on corporate income tax Foreign and domestic tax rate differentials Non-taxable portion of capital gains Stock options exercised for common shares Non-taxable gain on corporate acquisitions Revisions arising from prior year tax filings Change in unrecognized capital loss carryforward asset Other Income tax 2023 23.3% 2022 23.2% $ 2,364 $ 3,180 $ (255) 105 (104) (35) 91 — (174) (35) (25) (467) 190 (203) 65 159 — (186) 65 (36) 2021 23.2% 2,298 (21) 11 (11) (26) 98 (110) 16 (26) 18 $ 1,932 $ 2,767 $ 2,247 The following table summarizes the temporary differences that give rise to the net deferred income tax liability: Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets $ 12,172 $ 11,985 2023 2022 Lease assets Investments Investment in North West Redwater Partnership Taxable PRT for corporate income tax Other Deferred income tax assets Asset retirement obligations Lease liabilities Share-based compensation Loss carryforwards Unrealized foreign exchange loss on long-term debt Deferred PRT Net deferred income tax liability 336 54 904 256 41 336 56 903 176 25 13,763 13,481 (2,098) (1,822) (356) (31) (417) (39) (639) (354) (33) (652) (67) (439) (3,580) 10,183 $ (3,367) 10,114 $ 83 Canadian Natural 2023 Annual Report                     Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows: Property, plant and equipment and exploration and evaluation assets $ 2023 196 $ 2022 (334) $ Lease assets Unrealized foreign exchange on long-term debt Unrealized risk management activities Asset retirement obligations Lease liabilities Share-based compensation Loss carryforwards Investments Investment in North West Redwater Partnership Deferred PRT Taxable PRT for corporate income tax Other 1 28 — (292) (3) 2 235 (2) 1 86 (214) 15 53 $ (15) (81) (12) (74) 11 (11) 618 21 53 (441) 176 (50) (139) $ $ The following table summarizes the movements of the net deferred income tax liability during the year: Balance – beginning of year Deferred income tax expense (recovery) Deferred income tax expense included in other comprehensive (loss) income Foreign exchange adjustments Business combinations Balance – end of year 2023 2022 $ 10,114 $ 10,220 $ 53 — 16 — (139) — 33 — $ 10,183 $ 10,114 $ 2021 184 (30) 34 19 (213) 25 (10) 202 21 83 — — 84 399 2021 10,144 399 1 (2) (322) 10,220 Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. 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. Deferred income tax assets are recognized for temporary differences to the extent that the realization of the related tax benefit through future taxable profits is probable. Deferred PRT assets will be recovered from the UK Government, directly or through other third parties, as related abandonment expenditures are made. The Company has not recognized deferred income tax assets with respect to taxable capital loss carryforwards in excess of $1,000  million in North America, which can be carried forward indefinitely and only applied against future taxable capital gains. In addition, the Company has not recognized deferred income tax assets related to North American tax pools of approximately $950 million, which can only be claimed against income from certain oil and gas properties. Deferred income tax liabilities have not been recognized on the unremitted net earnings of wholly controlled subsidiaries. The Company is able to control the timing and amount of distributions and no taxes are payable on distributions from these subsidiaries provided that the distributions remain within certain limits. Canadian Natural 2023 Annual Report 84       14. Share Capital AUTHORIZED Preferred shares issuable in a series. Unlimited number of common shares without par value. ISSUED COMMON SHARES Balance – beginning of year Issued upon exercise of stock options Previously recognized liability on stock options exercised for common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year PREFERRED SHARES 2023 Number of shares (thousands) 1,102,636 $ 9,822 — Amount 10,294 372 435 2022 Number of shares (thousands) 1,168,369 $ 11,605 — Amount 10,168 442 387 (40,050) (389) (77,338) (703) 1,072,408 $ 10,712 1,102,636 $ 10,294 Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company. DIVIDENDS The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $1.05 per common share, beginning with the dividend payable on April 5, 2024. On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share. 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. NORMAL COURSE ISSUER BID On March 8, 2023, the Company's application was approved for a Normal Course Issuer Bid ("NCIB") to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 92,296,006 common shares, over a 12-month period commencing March 13, 2023 and ending March 12, 2024. For the year ended December 31, 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share for a total cost of $3,318 million. Retained earnings were reduced by $2,929 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2023, up to and including February 27, 2024, the Company purchased 4,000,000 common shares at a weighted average price of $85.54 per common share for a total cost of $342 million. On February 28, 2024, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE. SHARE SPLIT On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024. 85 Canadian Natural 2023 Annual Report SHARE-BASED COMPENSATION – STOCK OPTIONS The Company’s Option Plan provides for the granting of stock options to employees. Stock options granted under the Option Plan have terms ranging from five to six years to expiry and vest over a five-year period. The exercise price of each stock option granted is determined at the closing market price of the common shares on the TSX on the day prior to the grant. Each stock option granted provides the holder the choice to purchase one common share of the Company at the stated exercise price or receive a cash payment equal to the difference between the stated exercise price and the market price of the Company’s common shares on the date of surrender of the stock option. The Option Plan is a "rolling 7%" plan, whereby the aggregate number of common shares that may be reserved for issuance under the plan shall not exceed 7% of the common shares outstanding from time to time. The following table summarizes information relating to stock options outstanding at December 31, 2023 and 2022: Outstanding – beginning of year Granted Exercised for common shares Surrendered for cash settlement Forfeited Outstanding – end of year Exercisable – end of year 2023 2022 Stock options (thousands) Weighted average exercise price Stock options (thousands) Weighted average exercise price 31,150 $ 7,024 $ (9,822) $ (218) $ (1,929) $ 26,205 $ 3,672 $ 42.37 80.17 37.84 38.77 50.86 53.60 42.14 38,327 $ 7,547 $ (11,605) $ (441) $ (2,678) $ 31,150 $ 5,522 $ 35.88 68.15 38.06 38.43 41.43 42.37 37.60 The range of exercise prices of stock options outstanding and exercisable at December 31, 2023 was as follows: Stock options outstanding Stock options exercisable Range of exercise prices $20.76 $29.99 – $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 – – – – – – $39.99 $49.99 $59.99 $69.99 $79.99 $86.06 Stock options outstanding (thousands) 5,441 5,411 2,381 433 3,837 7,787 915 26,205 Weighted average remaining term (years) Weighted average exercise price Stock options exercisable (thousands) Weighted average exercise price 2.01 $ 1.03 $ 2.41 $ 3.86 $ 3.49 $ 4.18 $ 5.72 $ 2.87 $ 27.42 36.67 40.52 54.24 64.90 78.48 84.12 53.60 969 $ 1,227 $ 630 $ 30 $ 301 $ 515 $ — $ 3,672 $ 15. Accumulated Other Comprehensive Income The components of accumulated other comprehensive income, net of taxes, were as follows: Derivative financial instruments designated as cash flow hedges Foreign currency translation adjustment $ $ 2023 72 $ 100 172 $ 24.84 36.56 40.50 54.24 64.21 76.35 — 42.14 2022 75 134 209 Canadian Natural 2023 Annual Report 86           16. Capital Disclosures The Company has defined its capital to mean its long-term debt and consolidated shareholders’ equity, as determined at each reporting date. The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the Company to access capital markets to sustain its on-going operations and support its growth strategies. The Company primarily monitors capital on the basis of an internally derived financial measure referred to as its "debt to book capitalization ratio", which is the ratio of current and long-term debt less cash and cash equivalents divided by the sum of the carrying value of shareholders' equity plus current and long-term debt less cash and cash equivalents. The Company's internal targeted range for its debt to book capitalization ratio is 25% to 45%. The ratio may fall below or exceed the targeted range depending on the timing of acquisitions, the execution of the Company's capital program, and commodity price and foreign currency volatility. As at December 31, 2023, the ratio was below the target range at 20%. Readers are cautioned that the debt to book capitalization ratio is not defined by IFRS and this financial measure may not be comparable to similar measures presented by other companies. Further, there are no assurances that the Company will continue to use this measure to monitor capital or will not alter the method of calculation of this measure in the future. Long-term debt Less: cash and cash equivalents Long-term debt, net Total shareholders’ equity Debt to book capitalization $ $ $ 2023 10,799 $ 877 9,922 $ 39,832 $ 20% 2022 11,445 920 10,525 38,175 22% 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%. At December 31, 2023, the Company was in compliance with this covenant. 17. Net Earnings Per Common Share Weighted average common shares outstanding – basic (thousands of shares) Effect of dilutive stock options (thousands of shares) Weighted average common shares outstanding – diluted (thousands of shares) Net earnings Net earnings per common share – basic – diluted 2023 2022 2021 1,091,312 1,134,960 1,181,250 10,812 14,222 5,307 1,102,124 1,149,182 1,186,557 $ $ $ 8,233 $ 10,937 $ 7.54 $ 7.47 $ 9.64 $ 9.52 $ 7,664 6.49 6.46 In 2023, the Company excluded 3,230,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share (2022 – 2,039,000; 2021 – 3,496,000). 18. Interest and Other Financing Expense Interest and other financing expense Long-term debt Lease liabilities Total interest and other financing expense Total interest income and other Net interest and other financing expense 2023 2022 2021 $ $ 627 $ 610 $ 64 691 (55) 636 $ 60 670 (121) 549 $ 681 62 743 (32) 711 87 Canadian Natural 2023 Annual Report                 19. Financial Instruments The Company's financial instruments are comprised of cash and cash equivalents, accounts receivable, investments, risk management assets and liabilities, accounts payable, accrued liabilities, lease liabilities and long-term debt. These financial instruments, with the exception of investments and risk management assets and liabilities, are classified as financial assets and liabilities at amortized cost. Investments are classified as financial assets at fair value through profit or loss and are based on quoted market prices. Risk management assets and liabilities are classified as derivatives held for trading or as cash flow hedges. At each measurement date, the estimated fair values of derivative financial instruments in Level 2 have been determined based on appropriate internal valuation methodologies and/or third party indications, including quoted forward prices for commodities, foreign exchange rates, interest yield curves and other volatility factors. The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows: Asset (liability) Balance – beginning of year Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities (1) Foreign exchange Balance – end of year Less: current portion $ 2023 6 $ 3 — 9 8 $ 1 $ (1) Risk management assets and liabilities are disclosed in note 10 and note 12, respectively. Net (gain) loss from risk management activities for the years ended December 31, were as follows: Net realized risk management (gain) loss Net unrealized risk management loss (gain) 2023 2022 $ $ (14) $ 12 (2) $ (7) $ (28) (35) $ 2022 55 70 (119) 6 — 6 2021 17 19 36 The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt. The Company's financial instruments are categorized as Level 1 with the exception of risk management assets and liabilities which are categorized as Level 2. There were no transfers between Level 1, 2 and 3 financial instruments. The fair value of the Company’s fixed rate long-term debt is outlined below: Fixed rate long-term debt (1) (2) 2023 Carrying amount $ (10,799) $ Level 1 Fair Value 2022 Carrying amount Level 1 Fair Value (10,795) $ (11,445) $ (10,796) (1) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (2) Includes the current portion of fixed rate long-term debt. Canadian Natural 2023 Annual Report 88               RISK MANAGEMENT The Company periodically uses derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the Company’s consolidated balance sheets. Asset (liability) Derivatives held for trading Natural gas (1) Foreign currency forward contracts Included within: Current portion of other long-term assets Current portion of other long-term liabilities Other long-term assets 2023 2022 $ $ $ $ (3) $ 12 9 $ 12 $ (4) 1 9 $ 3 3 6 3 (3) 6 6 (1) In 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024. FINANCIAL RISK FACTORS The Company's financial risks are consistent with those disclosed in notes 1 and 4. a) Market risk Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency exchange risk. COMMODITY PRICE RISK MANAGEMENT The Company periodically uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with the sale of its future crude oil and natural gas production and with natural gas purchases. The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. INTEREST RATE RISK MANAGEMENT The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December  31, 2023, the Company had no interest rate swap contracts outstanding. FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long- term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt, commercial paper and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. During 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. As at December 31, 2023, the Company had US$1,003 million of foreign currency forward contracts outstanding (December 31, 2022 – US$1,017 million), with original terms of up to 90 days, all of which were designated as derivatives held for trading. 89 Canadian Natural 2023 Annual Report             FINANCIAL INSTRUMENT SENSITIVITIES The following table summarizes the annualized sensitivities of the Company’s 2023 net earnings and other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2023, resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear. 2023 2022 Increase (decrease) to net earnings Increase (decrease) to other comprehensive income Increase (decrease) to net earnings Increase (decrease) to other comprehensive income $ $ $ $ (5) $ 5 $ (128) $ 125 $ — $ — $ — $ — $ (4) $ 4 $ (135) $ 131 $ — — — — Interest rate risk Increase interest rate 1% Decrease interest rate 1% Foreign currency exchange rate risk Weakening of the Canadian dollar by US$0.01 Strengthening of the Canadian dollar by US$0.01 b) Credit risk Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an obligation. COUNTERPARTY CREDIT RISK MANAGEMENT The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. At December 31, 2023, substantially all of the Company’s accounts receivable were due within normal trade terms and the average expected credit loss was approximately 1% of the Company's accounts receivable balance (December 31, 2022 – 1%). The Company is also exposed to possible losses in the event of nonperformance by counterparties to derivative financial instruments; however, the Company manages this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions. As at December 31, 2023, the Company had net risk of $11 million with specific counterparties related to derivative financial instruments (December  31, 2022 – $7 million). The carrying amount of financial assets approximates the maximum credit exposure. c) Liquidity risk Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows. Canadian Natural 2023 Annual Report 90     The maturity dates of the Company’s financial liabilities were as follows: Accounts payable Accrued liabilities Long-term debt (1) Other long-term liabilities (2) Interest and other financing expense (3) Less than 1 year 1 to less than 2 years 2 to less than 5 years Thereafter 1,418 $ 3,534 $ 980 $ 302 $ 582 $ — $ — $ 1,584 $ 184 $ 518 $ — $ — $ 2,317 $ 428 $ 1,257 $ — — 5,978 645 3,362 $ $ $ $ $ (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, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 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 at December 31, 2023. 20. 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 December 31, 2023: Product transportation and processing (1) $ North West Redwater Partnership service toll (2) Offshore vessels and equipment Field equipment and power Other 2024 1,572 $ 2025 1,595 $ 2026 1,408 $ 2027 1,358 $ 2028 1,242 $ Thereafter 13,380 $ $ $ $ 158 $ 157 $ 139 $ 126 $ 130 $ 4,985 36 $ 38 $ — $ 25 $ — $ 23 $ 145 $ 111 $ 112 $ — $ 22 $ 25 $ — $ 22 $ 26 $ — 193 355 (1) The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion reflects interim tolls approved by the Canada Energy Regulator in 2023, and is subject to change pending the approval of final tolls. (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 $3,011 million of interest payable over the 40-year tolling period, ending in 2058 (note 10). 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. 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. 21. Supplemental Disclosure of Cash Flow Information Changes in non-cash working capital: Accounts receivable Inventory Prepaids and other Accounts payable Accrued liabilities Current income tax (liabilities) assets Other long-term liabilities Net changes in non-cash working capital Relating to: Operating activities Investing activities 2023 2022 2021 $ $ $ $ 368 $ (219) (23) 78 (812) (1,558) (200) (2,366) $ (2,417) $ 51 (2,366) $ (441) $ (266) (20) 537 896 (282) (196) 228 $ 79 $ 149 228 $ (850) (487) 39 80 525 1,918 (154) 1,071 964 107 1,071 91 Canadian Natural 2023 Annual Report                     The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended December 31, 2023 and 2022: At December 31, 2021 Changes from financing cash flows: Repayment of long-term debt, net (1) Proceeds on settlement of cross currency swaps Payment of lease liabilities Non-cash changes: Lease additions Changes in foreign exchange and fair value (2) At December 31, 2022 Changes from financing cash flows: Repayment of long-term debt, net (1) Payment of lease liabilities Non-cash changes: Lease additions Changes in foreign exchange and fair value (2) Long-term debt Cash flow hedges on US dollar debt securities Lease liabilities Liabilities from financing activities $ 14,694 $ (119) $ 1,584 $ 16,159 (4,010) — — — 761 11,445 (416) — — (230) — 69 — — 50 — — — — — — — (232) 182 6 1,540 — (285) 317 (17) (4,010) 69 (232) 182 817 12,985 (416) (285) 317 (247) At December 31, 2023 $ 10,799 $ — $ 1,555 $ 12,354 (1) (2) Includes original issue discounts and premiums, and directly attributable transaction costs. Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt securities, the amortization of original issue discounts and premiums and directly attributable transaction costs, and derecognition of lease liabilities. 22. Segmented Information The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas liquids and natural gas. The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and production activities. Midstream and Refining activities include the Company’s pipeline operations, an electricity co-generation system and NWRP. Segmented revenue and segmented results include transactions between business segments. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers are based on the location of the seller. Inter-segment elimination and Other includes internal and corporate transportation and electricity charges. Production, processing and other purchasing and selling activities, that are not included in the preceding segments are also reported in the segmented information as Inter-segment eliminations and Other. Operating segments have been determined based on the nature of the Company’s activities and the geographic locations in which the Company operates, and are consistent with the level of information regularly provided to and reviewed by the Company’s chief operating decision makers. Canadian Natural 2023 Annual Report 92 (millions of Canadian dollars) 2023 2022 2021 2023 2022 2021 2023 2022 2021 North America North Sea Offshore Africa Segmented product sales Crude oil and NGLs (1) Natural gas Other income and revenue (2) Total segmented product sales 19,760 25,903 17,081 $ 17,375 $ 20,755 $ 14,478 $ 2,375 4,931 2,484 119 217 10 7 — 13 — 5 (1) 442 636 611 Less: royalties (2,443) (3,918) (1,694) (1) (1) (1) Segmented revenue 17,317 21,985 15,387 441 635 610 51 9 637 (57) 580 55 8 757 (71) 686 31 7 458 (21) 437 435 $ 623 $ 607 $ 577 $ 694 $ 420 Segmented expenses Production Transportation, blending and feedstock (1) Depletion, depreciation and amortization (3) Asset retirement obligation accretion Risk management activities (commodity derivatives) Gain on acquisitions Income from NWRP 3,617 3,754 2,963 342 437 383 141 114 91 5,808 6,394 4,772 7 6 7 1 1 1 3,679 3,595 3,569 494 1,747 160 213 173 142 234 171 101 46 33 21 8 7 24 — — 18 — — 29 (478) — — — — — — — — — — — — — — — — 6 — — — 240 197 Total segmented expenses 13,362 13,932 10,956 889 2,223 571 363 295 Segmented earnings (loss) $ 3,955 $ 8,053 $ 4,431 $ (448) $ (1,588) $ 39 $ 217 $ 391 $ Non-segmented expenses Administration Share-based compensation Interest and other financing expense Risk management activities (other) Foreign exchange (gain) loss Gain from investments Total non-segmented expenses Earnings before taxes Current income tax Deferred income tax Net earnings (1) (2) (3) 93 Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and Upgrading segment. Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations partners' share of the costs of lease contracts. Includes a recoverability charge in depletion, depreciation and amortization, related to the Ninian field in the North Sea at December 31, 2023 for $436 million (December 31, 2022 – $1,620 million) (note 7). Canadian Natural 2023 Annual Report  Oil Sands Mining  Inter-segment and Upgrading Midstream and Refining elimination and Other Total 2023 2022 2021 2023 2022 2021 2023 2022 2021 2023 2022 2021 $ 18,661 $ 20,804 $ 14,033 $ 76 $ 80 $ 78 $ 176 $ 53 $ (360) $ 37,300 $ 43,009 $ 29,256 — 5 — 149 — 73 — 926 18,666 20,953 14,106 1,002 (2,366) (3,242) (1,081) — 16,300 17,711 13,025 1,002 — 906 986 — 986 — 681 759 — 759 142 10 328 — 328 237 196 2,575 5,236 2,716 5 3 960 1,285 882 295 (161) 40,835 49,530 32,854 — — (4,867) (7,232) (2,797) 295 (161) 35,968 42,298 30,057 3,989 4,076 3,414 332 271 234 59 60 67 8,480 8,712 7,152 2,563 2,652 1,505 664 691 550 259 229 (231) 9,302 9,973 6,604 2,011 1,822 1,838 16 16 15 — — — 6,413 7,353 5,724 78 70 57 — — — — — — 366 281 185 — — — — — — — — — — — — — — — 8,641 8,620 6,814 1,012 978 — — (400) 399 — — — — — — — — — 24 — — 18 — — 29 (478) (400) 318 289 (164) 24,585 26,337 18,816 $ 7,659 $ 9,091 $ 6,211 $ (10) $ 8 $ 360 $ 10 $ 6 $ 3 $ 11,383 $ 15,961 $ 11,241 452 491 415 804 366 514 636 549 711 (26) (279) (53) 738 (56) (196) 7 (127) (141) 1,218 2,257 1,330 10,165 13,704 9,911 1,879 2,906 1,848 53 (139) 399 $ 8,233 $ 10,937 $ 7,664 Canadian Natural 2023 Annual Report 94 CAPITAL EXPENDITURES (1) 2023 2022 Net expenditures Non-cash and fair value changes (2) Capitalized  costs Net expenditures Non-cash and fair value changes (2) Capitalized  costs Exploration and evaluation assets Exploration and    Production North America $ 41 $ Offshore Africa Oil Sands Mining and Upgrading Property, plant and equipment Exploration and    Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream and Refining Head Office 3 — 44 2,729 33 169 2,931 1,894 10 30 4,865 $ 4,909 $ 28 $ (59) $ (36) $ — (25) (61) 5 $ 3 (25) (17) (321) 525 18 222 2,408 558 187 3,153 (251) 1,643 — — (29) (90) $ 10 30 4,836 5 — 33 3,105 126 119 3,350 1,719 9 25 5,103 4,819 $ 5,136 $ — — (59) 136 177 (44) 269 (843) (1) — (575) (634) $ (31) 5 — (26) 3,241 303 75 3,619 876 8 25 4,528 4,502 (1) This table provides a reconciliation of capitalized costs, reported in note 6 and note 7, to net expenditures reported in the investing activities section of the statements of cash flows. The reconciliation excludes the impact of foreign exchange adjustments. (2) Derecognitions, asset retirement obligations, transfer of exploration and evaluation assets, and other fair value adjustments. SEGMENTED ASSETS Exploration and Production North America North Sea Offshore Africa Other Oil Sands Mining and Upgrading Midstream and Refining Head Office 2023 2022 $ 30,058 $ 31,135 602 1,380 32 42,865 856 162 378 1,322 54 42,102 979 172 $ 75,955 $ 76,142 95 Canadian Natural 2023 Annual Report                                                                   23. Remuneration of Directors and Senior Management REMUNERATION OF NON-MANAGEMENT DIRECTORS Fees earned REMUNERATION OF SENIOR MANAGEMENT (1) Salary Common stock option based awards Annual incentive plans Long-term incentive plans $ $ $ 2023 3 $ 2022 2 $ 2023 2 $ 2022 2 $ 13 5 19 12 5 18 39 $ 37 $ 2021 2 2021 2 10 6 19 37 (1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years. Canadian Natural 2023 Annual Report 96       Supplementary Oil & Gas Information for the Fiscal Year Ended December 31, 2023 (Unaudited) This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board ("FASB") Topic 932 – "Extractive Activities – Oil and Gas" and where applicable, financial information is prepared in accordance with International Financial Reporting Standards ("IFRS"). For the years ended December 31, 2023, 2022, 2021 and 2020 the Company filed its reserves information under National Instrument 51-101 – "Standards of Disclosure of Oil and Gas Activities" ("NI 51-101"), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. There are significant differences in the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission ("SEC") requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material. For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2023, 2022, 2021 and 2020 the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2023 and 2022 reserves for SEC requirements. Crude Oil and NGLs       Canadian Light Sweet (C$/bbl) Cromer LSB (C$/bbl) Brent (US$/bbl) WTI (US$/bbl) WCS (C$/bbl) 2023 2022 78.10 94.13 79.95 99.40 100.93 118.90 99.48 117.76 82.51 97.98 Edmonton C5+ Henry Hub (US$/MMBtu) (C$/bbl) 103.43 119.93 Natural Gas BC Westcoast Station 2 (C$/MMBtu) AECO (C$/MMBtu) 2.75 6.44 2.79 5.59 2.10 4.51 A foreign exchange rate of US$0.7407/C$1.00 was used in the 2023 evaluation (2022 - US$0.7709/C$1.00), determined on the same basis as the 12-month average price. Net Proved Crude Oil and Natural Gas Reserves The Company retains Independent Qualified Reserves Evaluators to evaluate and review the Company's proved crude oil, bitumen, synthetic crude oil ("SCO"), natural gas, and natural gas liquids ("NGLs") reserves. ▪ ▪ For the years ended December 31, 2023, 2022, 2021 and 2020, the reports by GLJ Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals. For the years ended December 31, 2023, 2022, 2021 and 2020, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, bitumen, natural gas and NGLs reserves. Proved crude oil and natural gas reserves, as defined within the SEC's Regulation S-X, are the estimated quantities of oil and gas that by analysis of geoscience and engineering data demonstrate with reasonable certainty to be economically producible, from a given date forward, from known reservoirs under existing economic conditions, operating methods and government regulations. Developed crude oil and natural gas reserves are reserves of any category that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change. 97 Canadian Natural 2023 Annual Report The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2023, 2022, 2021 and 2020: Crude Oil and NGLs (MMbbl) (1) Net Proved Reserves North America Synthetic Crude Oil Bitumen (2) Crude Oil & NGLs North America Total North Sea Offshore Africa Total Reserves, December 31, 2020 6,847 2,413 525 9,785 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices (3) Revisions of prior estimates — — — — (150) (927) 174 101 19 — — (103) (296) 155 Reserves, December 31, 2021 5,944 2,289 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices (3) Revisions of prior estimates — 29 — — (128) (455) — 195 5 267 — (91) (263) 144 14 14 52 — (45) 108 40 708 11 21 21 — (45) (73) 54 115 33 52 — (297) (1,115) 369 8,941 205 56 288 — (265) (791) 198 Reserves, December 31, 2022 5,390 2,546 696 8,632 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices (3) Revisions of prior estimates 162 28 — — (141) 333 68 67 9 — — (102) 123 26 Reserves, December 31, 2023 5,840 2,669 Net Proved Developed Reserves December 31, 2020 December 31, 2021 December 31, 2022 December 31, 2023 6,770 5,929 5,389 5,804 628 584 582 610 51 37 — (1) (47) 29 1 767 285 370 359 337 280 75 — (1) (289) 484 94 9,276 7,682 6,883 6,330 6,752 87 — — — — (6) 1 (3) 79 — — — — (5) 1 (64) 11 — — — — (5) — 3 9 32 39 5 6 71 9,943 — — — — (5) (4) 2 115 33 52 — (309) (1,118) 368 64 9,083 — — — — (5) (2) — 57 — — — — (4) 1 1 205 56 288 — (274) (792) 134 8,700 280 75 — (1) (298) 485 98 54 9,339 37 38 34 30 7,751 6,960 6,369 6,787 (1) Information in the reserves data tables may not add due to rounding. (2) Bitumen as defined by the SEC, "is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis." Under this definition, all the Company's thermal and primary heavy crude oil reserves have been classified as bitumen. (3) Includes changes due to commodity price and resulting royalty volumes. Canadian Natural 2023 Annual Report 98                                 2023 total proved Crude Oil and NGLs reserves increased by 639 MMbbl: ▪ ▪ ▪ ▪ ▪ ▪ Extensions and discoveries: Increase of 280 MMbbl primarily due to pit extensions at Oil Sands Mining and Upgrading (SCO) and infill drilling/future offset additions at various Bitumen, natural gas (NGLs) and Crude Oil properties. Improved recovery: Increase of 75 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) and Bitumen properties. Sales of reserves in place: Decrease of 1 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in Alberta. Production: Decrease of 298 MMbbl. Economic revisions due to prices: Increase of 485 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various Bitumen properties due to lower bitumen pricing resulting in lower royalties and higher net reserves. Revisions of prior estimates: Increase of 98 MMbbl primarily due to transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and Upgrading (SCO) and improved performance at various Bitumen properties. 2022 total proved Crude Oil and NGLs reserves decreased by 383 MMbbl: ▪ ▪ ▪ ▪ ▪ ▪ Extensions and discoveries: Increase of 205 MMbbl primarily due to extension drilling/future offset additions at various Bitumen properties. Improved recovery: Increase of 56 MMbbl primarily due to improved recovery at Oil Sands Mining and Upgrading (SCO) and infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties. Purchases of reserves in place: Increase of 288 MMbbl primarily due to a Bitumen acquisition in Alberta. Production: Decrease of 274 MMbbl. Economic revisions due to prices: Decrease of 792 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves. Revisions of prior estimates: Increase of 134 MMbbl primarily due to improved performance at various Bitumen, North America Crude Oil and natural gas (NGLs) properties, partially offset by removal of future undeveloped reserves at North Sea. 2021 total proved Crude Oil and NGLs reserves decreased by 860 MMbbl: ▪ ▪ ▪ ▪ ▪ ▪ Extensions and discoveries: Increase of 115 MMbbl primarily due to extension drilling/future offset additions at various Bitumen properties. Improved recovery: Increase of 33 MMbbl primarily due to increased recovery of thermal Bitumen at Jackfish and Kirby properties and infill drilling/future offset additions at various Crude Oil and natural gas (NGLs) properties. Purchases of reserves in place: Increase of 52 MMbbl primarily due to natural gas (NGLs) acquisitions in northeast British Columbia. Production: Decrease of 309 MMbbl. Economic revisions due to prices: Decrease of 1,118 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and thermal Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves. Revisions of prior estimates: Increase of 368 MMbbl primarily due to transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and Upgrading (SCO) and improved performance at various North America and Offshore Africa Crude Oil, Bitumen and natural gas (NGLs) properties. 99 Canadian Natural 2023 Annual Report Natural Gas (Bcf) (1) Net Proved Reserves Reserves, December 31, 2020 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices (2) Revisions of prior estimates Reserves, December 31, 2021 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices (2) Revisions of prior estimates Reserves, December 31, 2022 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices (2) Revisions of prior estimates Reserves, December 31, 2023 Net Proved Developed Reserves December 31, 2020 December 31, 2021 December 31, 2022 December 31, 2023 (1) (2) Information in the reserves data tables may not add due to rounding. Includes changes due to commodity price and resulting royalty volumes. North America North Sea Offshore Africa 7,655 545 161 1,654 (1) (581) 712 1,139 11,285 251 192 228 — (688) (572) 1,521 12,217 1,185 603 — (6) (750) 87 57 13,393 3,116 4,469 4,956 4,029 12 — — — — (1) — (3) 8 — — — — (1) — (3) 4 — — — — (1) — (1) 3 6 3 1 1 34 — — — — (4) (4) — 25 — — — — (4) (3) 7 25 — — — — (4) 1 1 23 22 20 19 10 Total 7,701 545 161 1,654 (1) (587) 708 1,136 11,318 251 192 228 — (693) (575) 1,526 12,246 1,185 603 — (6) (755) 88 58 13,419 3,144 4,492 4,975 4,040 Canadian Natural 2023 Annual Report 100               2023 total proved Natural Gas reserves increased by 1,173 Bcf primarily due to the following: ▪ ▪ ▪ ▪ ▪ ▪ Extensions and discoveries: Increase of 1,185 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. Improved recovery: Increase of 603 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northwest British Columbia. Sales of reserves in place: Decrease of 6 Bcf primarily due to dispositions from various Natural Gas properties in Alberta. Production: Decrease of 755 Bcf. Economic revisions due to prices: Increase of 88 Bcf primarily at various North America Natural Gas properties due to lower natural gas pricing resulting in lower royalties and higher net reserves. Revisions of prior estimates: Increase of 58 Bcf primarily due to category transfers from probable to proved partially offset by negative revisions in various North American core areas as a result of decreased performance. 2022 total proved Natural Gas reserves increased by 928 Bcf primarily due to the following: ▪ ▪ ▪ ▪ ▪ ▪ Extensions and discoveries: Increase of 251 Bcf primarily due to extension drilling/future offset additions in the Montney formation of northwest Alberta and northeast British Columbia. Improved recovery: Increase of 192 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. Purchases of reserves in place: Increase of 228 Bcf primarily due to property acquisitions in North America core areas. Production: Decrease of 693 Bcf. Economic revisions due to prices: Decrease of 575 Bcf primarily at various North America natural gas properties due to higher natural gas pricing resulting in higher royalties and lower net reserves. Revisions of prior estimates: Increase of 1,526 Bcf primarily due to overall positive revisions in several North American core areas as a result of increased performance and category transfers from probable to proved. 2021 total proved Natural Gas reserves increased by 3,617 Bcf primarily due to the following: ▪ ▪ ▪ ▪ ▪ ▪ ▪ Extensions and discoveries: Increase of 545 Bcf primarily due to extension drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. Improved recovery: Increase of 161 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of northwest Alberta and northeast British Columbia. Purchases of reserves in place: Increase of 1,654 Bcf primarily due to the Storm Resources Ltd. and other acquisitions in northeast British Columbia. Sales of reserves in place: Decrease of 1 Bcf from Natural Gas properties in North America. Production: Decrease of 587 Bcf. Economic revisions due to prices: Increase of 708 Bcf primarily due to increased Natural Gas price in North America. Revisions of prior estimates: Increase of 1,136 Bcf primarily due to overall positive revisions in several North American core areas as a result of increased performance and category transfers from probable to proved. 101 Canadian Natural 2023 Annual Report Capitalized Costs Related to Crude Oil and Natural Gas Activities (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation Net capitalized costs (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation Net capitalized costs (millions of Canadian dollars) Proved properties Unproved properties 2023 North America North Sea Offshore Africa Total $ 132,858 $ 8,606 $ 4,409 $ 145,873 2,108 134,966 — 8,606 100 4,509 2,208 148,081 (69,945) (8,382) (3,358) (81,685) $ 65,021 $ 224 $ 1,151 $ 66,396 2022 North America North Sea Offshore Africa Total $ 128,807 $ 8,258 $ 4,332 $ 141,397 2,128 130,935 — 8,258 98 4,430 2,226 143,623 (65,547) (8,106) (3,277) (76,930) $ 65,388 $ 152 $ 1,153 $ 66,693 2021 North America 124,690 $ $ North Sea 7,438 $ Offshore Africa 3,980 $ 2,159 126,849 — 7,438 91 4,071 Total 136,108 2,250 138,358 Less: accumulated depletion and depreciation (61,231) (5,951) (2,923) (70,105) Net capitalized costs $ 65,618 $ 1,487 $ 1,148 $ 68,253 Canadian Natural 2023 Annual Report 102             Costs Incurred in Crude Oil and Natural Gas Activities (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred 2023 North America North Sea Offshore Africa $ — $ — $ — $ — 43 5,039 — — 558 — 3 187 $ 5,082 $ 558 $ 190 $ 2022 North America North Sea Offshore Africa $ 524 $ — $ — $ — 40 4,387 — — 304 — 5 75 $ 4,951 $ 304 $ 80 $ Total — — 46 5,784 5,830 Total 524 — 45 4,766 5,335 2021 North America North Sea Offshore Africa Total $ 1,371 $ — $ — $ 1,371 26 4 4,301 — — 208 — 8 48 $ 5,702 $ 208 $ 56 $ 26 12 4,557 5,966 103 Canadian Natural 2023 Annual Report                               Results of Operations from Crude Oil and Natural Gas Producing Activities The Company's results of operations from crude oil and natural gas producing activities for the years ended December 31, 2023, 2022 and 2021 are summarized in the following tables: (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties, blending and feedstock costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties, blending and feedstock costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties, blending and feedstock costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations 2023 North America North Sea Offshore Africa Total $ 26,773 $ 442 $ 581 $ 27,796 (7,606) (1,550) (5,690) (312) — (2,700) (342) (7) (494) (46) 273 70 (141) (1) (213) (8) — (54) (8,089) (1,558) (6,397) (366) 273 (2,684) $ 8,915 $ (104) $ 164 $ 8,975 2022 North America North Sea Offshore Africa $ 31,698 $ (7,830) (1,424) (5,417) (241) — (3,896) 635 $ (437) (6) (1,747) (33) 483 442 687 $ (114) (1) (173) (7) — (98) Total 33,020 (8,381) (1,431) (7,337) (281) 483 (3,552) $ 12,890 $ (663) $ 294 $ 12,521 2021 North America North Sea Offshore Africa $ 23,111 $ (6,377) (1,176) (5,407) (158) — (2,317) $ 7,676 $ 611 $ (383) (7) (160) (21) 33 (29) 44 $ 438 $ (91) (1) (142) (6) — (50) 148 $ Total 24,160 (6,851) (1,184) (5,709) (185) 33 (2,396) 7,868 Canadian Natural 2023 Annual Report 104       Standardized Measure of Discounted Future Net Cash Flows from Proved Crude Oil and Natural Gas Reserves and Changes Therein The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of- the-month price for each month within the 12-month period prior to the end of the reporting period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including: ▪ ▪ ▪ ▪ ▪ ▪ ▪ Future production will include production not only from proved properties, but may also include production from probable and possible reserves; Future production of crude oil and natural gas from proved properties will differ from reserves estimated; Future production rates will vary from those estimated; Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply; Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change; Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and Future development and asset retirement obligations will differ from those estimated. Future net revenues, development, production and asset retirement obligation costs have been based upon the estimates referred to above. The following tables summarize the Company's future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 - "Extractive Activities - Oil and Gas": (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows Standardized measure of future net cash flows (1) (1) Includes abandonment cost estimates for the Ninian field. (millions of Canadian dollars) Future cash inflows 2023 North America North Sea Offshore Africa Total $ 863,544 $ 1,067 $ 6,144 $ 870,755 (276,498) (636) (1,880) (279,014) (86,615) (1,873) (1,927) (90,415) (113,516) 967 (508) (113,057) 386,915 (475) 1,829 388,269 (278,814) 168 (887) (279,533) $ 108,101 $ (307) $ 942 $ 108,736 2022 North America North Sea Offshore Africa Total $ 986,672 $ 1,506 $ 7,304 $ 995,482 Future production costs Future development costs and asset retirement obligations (303,270) (691) (1,998) (305,959) (83,803) (1,416) (1,439) (86,658) Future income taxes Future net cash flows 10% annual discount for timing of future cash flows Standardized measure of future net cash flows (1) (1) Includes abandonment cost estimates for the Ninian field. (136,905) 462,694 (327,333) 135,361 $ $ 517 (84) 84 — $ (900) (137,288) 2,967 465,577 (1,330) 1,637 $ (328,579) 136,998 105 Canadian Natural 2023 Annual Report     (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows 2021 North America North Sea Offshore Africa Total $ 679,123 $ 7,791 $ 5,581 $ 692,495 (238,144) (77,375) (81,860) 281,744 (201,227) (4,074) (1,857) (719) 1,141 (142) (1,818) (244,036) (1,142) (565) (80,374) (83,144) 2,056 284,941 (788) (202,157) Standardized measure of future net cash flows $ 80,517 $ 999 $ 1,268 $ 82,784 The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table: (millions of Canadian dollars) Sales of crude oil and natural gas produced, net of production costs 2023 2022 2021 $ (18,174) $ (23,242) $ (16,149) Net changes in sales prices and production costs Extensions, discoveries and improved recovery Changes in estimated future development costs Purchases of proved reserves in place Sales of proved reserves in place Revisions of previous reserve estimates Accretion of discount Changes in production timing and other Net change in income taxes Net change Balance - beginning of year Balance - end of year (47,145) 8,196 (1,511) — (47) 6,647 17,769 (2,831) 8,834 (28,262) 136,998 79,291 6,198 (3,640) 5,745 — (9,956) 10,712 5,463 74,558 2,948 (2,773) 4,010 (1) (186) 3,460 6,638 (16,357) (17,232) 54,214 82,784 55,273 27,511 82,784 $ 108,736 $ 136,998 $ Canadian Natural 2023 Annual Report 106   Ten Year Review Years ended December 31 2023 2022 2021 2020 2019 2018 2017 2016 2015 2014 FINANCIAL INFORMATION (C$ millions, except per share amounts) Net earnings (loss) Per share – basic ($/share) Per share – diluted ($/share) Cash flows from operating activities Adjusted funds flow (1) Per share – basic ($/share) (2) Per share – diluted ($/share) (2) Cash flows used in investing activities Net capital expenditures (1) Abandonment expenditures, net (1) Balance sheet information (C$ millions) Adjusted working capital (3) Exploration and evaluation assets Property, plant and equipment, net Total assets Long-term debt, net (4) Shareholders' equity SHARE INFORMATION Common shares outstanding (thousands) Weighted average shares outstanding 8,233 10,937 7,664 7.54 7.47 9.64 9.52 6.49 6.46 12,353 19,391 14,478 (435) (0.37) (0.37) 4,714 4.55 4.54 2.13 2.12 8,829 10,121 5,416 2,591 2,397 15,274 19,791 13,733 5,200 10,267 9,088 14.00 13.86 4,858 4,909 509 17.44 17.22 4,987 5,136 335 11.63 11.57 3,703 4,676 232 4.40 4.40 2,819 2,957 249 8.62 8.61 7,255 6,825 296 7.46 7.43 4,814 13,102 4,441 16,855 290 274 2.04 2.03 7,262 7,347 6.25 6.21 (204) (0.19) (0.19) 3,452 4,293 3.90 3.89 3,811 3,527 267 (637) (0.58) (0.58) 5,632 5,785 5.29 5.28 3,929 3.60 3.58 8,459 9,587 8.78 8.74 5,465 11,177 3,483 11,398 370 346 712 2,208 64,581 75,955 9,922 39,832 (1,190) 2,226 64,859 76,142 10,525 38,175 (480) 2,250 66,400 76,665 13,950 36,945 626 2,436 65,752 75,276 21,269 32,380 241 2,579 68,043 78,121 20,843 34,991 (601) 2,637 64,559 71,559 20,522 31,974 513 2,632 65,170 73,867 22,321 31,653 1,056 2,382 50,910 58,648 16,788 26,267 1,193 2,586 51,475 59,275 16,725 27,381 (673) 3,557 52,480 60,200 13,977 28,891 1,072,408 1,102,636 1,168,369 1,183,866 1,186,857 1,201,886 1,222,769 1,110,952 1,094,668 1,091,837 – basic (thousands) 1,091,312 1,134,960 1,181,250 1,181,768 1,190,977 1,218,798 1,175,094 1,100,471 1,093,862 1,091,754 Weighted average shares outstanding – diluted (thousands) Dividends declared ($/share) (5) Trading statistics TSX – C$ Trading volume (thousands) Share Price (C$/share) High Low Close NYSE – US$ Trading volume (thousands) Share Price (US$/share) High Low Close RATIOS Debt to book capitalization (4) After-tax return on average capital employed (2) Daily production before royalties per ten thousand common shares (BOE/d) Total proved plus probable reserves per common share (BOE) (6) Net asset value ($/share) (7) 1,102,124 1,149,182 1,186,557 1,181,768 1,193,106 1,223,758 1,182,823 1,100,471 1,093,862 1,096,822 3.70 4.60 2.00 1.70 1.50 1.34 1.10 0.94 0.92 0.90 1,697,055 1,533,722 1,568,872 1,866,414 904,013 806,254 588,422 653,727 728,033 717,580 93.44 67.13 86.81 88.18 54.20 75.19 55.59 28.67 53.45 42.57 9.80 30.59 42.56 30.01 42.00 49.08 30.11 32.94 47.00 35.90 44.92 46.74 21.27 42.79 42.46 25.01 30.22 49.57 31.00 35.92 602,866 755,722 795,605 1,058,121 679,697 796,971 608,008 892,220 951,311 812,521 68.74 48.81 65.52 20 % 17 % 70.60 42.32 55.53 22 % 22 % 44.33 22.40 42.25 27 % 16 % 32.79 6.71 24.05 40 % — % 32.56 22.58 32.35 37 % 11 % 12.4 11.6 10.6 9.8 9.3 38.19 21.85 24.13 36.78 27.53 35.72 39 % 41 % 6 % 9.0 6 % 7.9 35.28 14.60 31.88 39 % — % 34.46 18.94 21.83 38 % (1) % 46.65 26.53 30.88 33 % 10 % 7.3 7.8 7.2 17.3 174.80 16.4 164.55 14.5 119.36 13.5 71.62 12.0 97.09 11.1 101.89 9.7 81.41 8.3 74.77 8.3 73.39 8.1 78.99 (1) (2) (3) (4) (5) (6) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. The composition of Net capital expenditures has been updated for all periods presented. For years prior to 2023, the sum of Net capital expenditures and Abandonment expenditures, net, equals the previously stated Net capital expenditures Non-GAAP measure. Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. Calculated as current assets less current liabilities, excluding the current portion of long-term debt. Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. On February 28, 2024, the Board of Directors approved a quarterly dividend of $1.05 per common share, a 5% increase from the previous quarterly dividend of $1.00 per common share. The dividend is payable on April 5, 2024. Based upon company gross reserves (forecast price and costs, before royalties), using year end common shares outstanding. 107 Canadian Natural 2023 Annual Report Years ended December 31 COMPANY NET RESERVES (8) Crude oil and NGLs (MMbbl) Company net proved reserves (after royalties) 2023 2022 2021 2020 2019 2018 2017 2016 2015 2014 North America North Sea Offshore Africa 8,977 8 53 8,940 11 59 8,740 79 64 8,980 96 70 8,129 109 70 7,163 119 72 6,423 120 70 3,909 134 74 3,645 158 74 9,038 Company net proved plus probable reserves (after royalties) 11,240 12 69 North America North Sea Offshore Africa 9,010 8,883 9,147 8,307 7,354 6,613 4,117 3,877 11,181 15 77 10,883 117 85 11,151 160 94 10,231 175 93 9,456 186 98 8,353 180 102 6,015 252 108 5,806 284 113 11,322 11,273 11,085 11,405 10,499 9,740 8,635 6,375 6,203 Natural gas (Bcf) Company net proved reserves (after royalties) North America North Sea Offshore Africa 12,952 3 22 11,614 4 27 11,076 8 25 8,373 12 32 5,795 16 37 6,005 27 21 6,032 21 15 5,845 41 23 5,383 39 21 12,977 Company net proved plus probable reserves (after royalties) 20,596 5 36 North America North Sea Offshore Africa 11,645 11,109 8,417 5,849 6,053 6,068 5,909 5,443 18,617 7 40 18,315 11 39 13,884 17 48 8,556 21 52 8,681 38 44 8,454 32 47 7,888 85 55 7,361 96 50 20,637 18,664 18,364 13,949 8,630 8,763 8,533 8,028 7,507 3,380 204 78 3,662 5,609 308 119 6,036 5,054 83 36 5,173 6,791 114 68 6,973 Total company net proved reserves (after royalties) (MMBOE) Total company net proved plus probable reserves (after royalties) (MMBOE) OPERATING INFORMATION Daily production (before royalties) (9) Crude oil and NGLs (Mbbl/d) North America Exploration and Production North America Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total production (before royalties) (MBOE/d) PRODUCT PRICING (10) Average crude oil & NGLs price ($/bbl) (2) (11) Average natural gas price ($/Mcf) Average SCO price ($/bbl) (2) (12) 11,201 10,951 10,734 10,549 9,282 8,363 7,625 5,102 4,784 4,524 14,761 14,384 14,146 13,730 11,938 11,202 10,057 7,713 7,454 7,198 496 480 473 460 406 351 359 351 400 451 13 13 974 426 13 14 933 448 18 14 952 417 23 17 918 395 28 21 850 426 24 20 821 282 23 20 685 123 24 26 524 123 22 19 564 2,139 2 10 2,151 2,075 2 13 2,090 1,680 3 12 1,695 1,450 12 15 1,477 1,443 24 24 1,491 1,490 32 26 1,548 1,601 39 22 1,662 1,622 38 31 1,691 1,663 36 27 1,726 1,332 1,281 1,235 1,164 1,099 1,079 962 806 852 391 111 17 12 531 1,527 7 21 1,555 790 72.36 3.10 100.06 90.64 6.55 117.69 63.71 4.07 77.95 31.90 2.40 43.98 55.08 2.34 70.18 46.92 2.61 68.61 48.57 2.76 63.98 36.93 2.32 58.59 41.13 3.16 61.39 77.04 4.83 100.27 (7) Net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for existing development as at December 31, 2023) of the Company’s total proved plus probable crude oil, natural gas and NGL reserves prepared using forecast prices and costs, as reported in the Company's AIF, plus the estimated market value of core unproved property at $300/acre ($300/acre in 2022, $285/acre from 2021 to 2015, $300/acre in 2014), less debt plus/minus the working capital deficit/surplus divided by common shares outstanding. Future development costs & abandonment & reclamation costs attributable to future development activity have been applied against the future net revenue. Company net reserves are company gross reserves after royalties. Reserves data may not add due to rounding and BOE values may not calculate exactly due to rounding. Numbers may not add due to rounding. Product prices reflect realized product prices before blending costs, transportation costs and exclude risk management activities. (8) (9) (10) (11) Average crude oil and NGLs pricing excludes SCO. (12) For years 2017 to 2023, average SCO product price includes AOSP realized product prices net of blending and feedstock costs. Canadian Natural 2023 Annual Report 108 Corporate Information Board of Directors *Catherine M. Best, FCA, ICD.D (1)(2) Corporate Director Calgary, Alberta *M. Elizabeth Cannon, Ph.D, O.C.(3)(5) Corporate Director Calgary, Alberta N. Murray Edwards, O.C. Corporate Director St. Moritz, Switzerland *Christopher L. Fong (3)(5) Corporate Director Calgary, Alberta *Ambassador Gordon D. Giffin (1)(4)(6) Partner and Global Vice-Chair, emeritus, Dentons US LLP Sarasota, Florida *Wilfred A. Gobert (1)(2)(4) Corporate Director Calgary, Alberta *Christine M. Healy (1)(4) Corporate Director Montréal, Québec *Steve W. Laut (3)(5) Corporate Director Calgary, Alberta *Honourable Frank J. McKenna, P.C., O.C., O.N.B., K.C.(2)(4) Deputy Chair, TD Bank Group Cap Pelé, New Brunswick Scott G. Stauth (3)(7) President, Canadian Natural Resources Limited Calgary, Alberta *David A. Tuer (1)(5) Corporate Director Calgary, Alberta *Annette M. Verschuren, O.C. (2)(3) Chairman and Chief Executive Officer, NRStor Inc. Toronto, Ontario (1) Audit Committee member (2) Compensation Committee member (3) Health, Safety, Asset Integrity and Environmental Committee member (4) Nominating, Governance and Risk Committee member (5) Reserves Committee member (6) Lead Independent Director (7) Mr. Tim. S. McKay stepped down as President effective February 28, 2024 and assumed the role of Vice Chairman to support management transition until his retirement. Mr. McKay resigned as a Director of the Company effective February 27, 2024. Mr. Scott G. Stauth was appointed President of the Company effective February 28, 2024. *Determined to be independent by the Nominating, Governance and Risk Committee of the Board of Directors and pursuant to the independent standards established under National Instrument 58-101 and the New York Stock Exchange Corporate Governance Listing Standards. Senior Officers N. Murray Edwards Executive Chairman Tim S. McKay Vice Chairman Scott G. Stauth President Jay E. Froc Chief Operating Officer, Oil Sands Robin S. Zabek Chief Operating Officer, Exploration and Production Mark A. Stainthorpe Chief Financial Officer Troy J.P. Andersen Senior Vice-President, Canadian Conventional Field Operations Calvin J. Bast Senior Vice-President, Production Victor C. Darel Senior Vice-President, Finance and Principal Accounting Officer Dwayne F. Giggs Senior Vice-President, Exploration Dean W. Halewich Senior Vice-President, Safety, Risk Management and Innovation Ron K. Laing Senior Vice-President, Corporate Development and Land Devin C. Lowe Senior Vice-President, Exploitation Warren P. Raczynski Senior Vice-President, Thermal Trevor T. Wagil Senior Vice-President, Oil Sands Mining and Upgrading Brenda G. Balog Vice-President, Legal and General Counsel Erin L. Lunn Vice-President, Land Mark A. Overwater Vice-President, Marketing Kyle G. Pisio Vice-President, Drilling, Completions and Asset Retirement Roy D. Roth Vice-President, Facilities and Pipelines Kara L. Slemko Vice-President, Corporate Development and Commercial Operations Stephanie A. Graham Corporate Secretary and Associate General Counsel, Canada 109 Canadian Natural 2023 Annual Report HEAD OFFICE Canadian Natural Resources Limited 2100, 855 – 2 Street S. W. Calgary, Alberta T2P 4J8 Telephone: (403) 517-6700 Facsimile: (403) 517-7350 Website: www.cnrl.com INVESTOR RELATIONS Telephone: (403) 514-7777 Email: ir@cnrl.com INTERNATIONAL OFFICE CNR International (U.K.) Limited St. Magnus House, Guild Street Aberdeen AB11 6NJ Scotland REGISTRAR AND TRANSFER AGENT Computershare Trust Company of Canada Calgary, Alberta Toronto, Ontario Computershare Investor Services LLC New York, New York AUDITORS PricewaterhouseCoopers LLP Calgary, Alberta INDEPENDENT QUALIFIED RESERVES EVALUATORS GLJ Ltd. Calgary, Alberta Sproule Associates Limited Calgary, Alberta Sproule International Limited Calgary, Alberta STOCK LISTING – CNQ Toronto Stock Exchange The New York Stock Exchange COMPANY DEFINITION Throughout the annual report, Canadian Natural Resources Limited is referred to as “us”, “we”, “our”, “Canadian Natural”, or the “Company”. CURRENCY All amounts are reported in Canadian currency unless otherwise stated. ABBREVIATIONS Abbreviations can be found on page 10. METRIC CONVERSION CHART To Convert barrels thousand cubic feet feet miles acres tonnes To cubic metres cubic metres metres kilometres hectares tons Multiply by 0.159 28.174 0.305 1.609 0.405 1.102 COMMON SHARE DIVIDEND The Company paid its first dividend on its common shares on April 1, 2001. Since then, dividends have been paid quarterly. The following table shows the aggregate amount of the cash dividends declared per common share of the Company and accrued in each of its last three years ended December 31, 2023. Cash dividends declared per common share 2023 2022 2021 $3.70 $4.60 $2.00 NOTICE OF ANNUAL MEETING Canadian Natural’s 2024 Annual and Special Meeting of the Shareholders will be held on Thursday, May 2, 2024 at 11:00  a.m. Mountain Daylight Time in Exhibition Hall E of the Telus Convention Centre, Calgary, Alberta. CORPORATE GOVERNANCE Canadian Natural’s corporate governance practices and disclosure of those practices are in compliance with National Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices. Canadian Natural, as a foreign private issuer in the United States, may rely on home jurisdiction listing standards for compliance with most of the New York Stock Exchange (NYSE) Corporate Governance Listing Standards but must disclose any significant differences between its corporate governance practices and those required for U.S. companies listed on the NYSE. Canadian Natural follows Toronto Stock Exchange (TSX) rules with respect to shareholder approval of equity compensation plans and material revisions to such plans. TSX rules provide that only the creation of or material amendments to equity compensation plans which provide for new issuance of securities are subject to shareholder approval. However, the NYSE requires shareholder approval of all equity compensation plans whether they provide for the delivery of newly issued securities, or rely on securities acquired in the open market by the issuing company for the purposes of redistribution to plan beneficiaries, and material revisions to such plans. Canadian Natural has a performance share unit plan pursuant to which common shares are purchased through the TSX. This is not a new issue of securities under the performance share unit plan and under TSX rules the plan is not subject to shareholder approval. Canadian Natural has included as exhibits to its Annual Report on Form 40-F for the 2023 fiscal year filed with the United States Securities and Exchange Commission certificates of the Chief Executive Officer and Chief Financial Officer certifying as to disclosure controls and procedures and internal control over financial reporting. Canadian Natural 2023 Annual Report 110 T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com 2100, 855 – 2 Street S.W. Calgary, AB T2P 4J8 www.cnrl.com 2 0 2 3 A N N U A L R E P O R T C A N A D I A N N A T U R A L 

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