Canadian Natural Resources : Supplemental Information (CNQ 2025 Annual Report)

About this update from Canadian Natural Resources Limited

2025 ANNUAL REPORT 2025 Performance Highlights The Company continues to maximize value for shareholders, with another successful year in 2025. We set several new production records, lowered operating costs and capital expenditures came in under our forecast. We grew organically and completed several accretive acquisitions, including the Palliser Block assets in southern Alberta and liquids-rich Montney assets in the Grande Prairie area, along with increasing our ownership in the Albian mines to 100% through an asset swap. We strengthened our financial position in 2025 by reducing net debt and ended the year with strong financial metrics. 2025 2024 2023 FINANCIAL ($ millions, except per common share amounts) Product sales (1) $ 44,167 $ 41,509 $ 40,835 Net earnings $ 10,820 $ 6,106 $ 8,233 Per common share (2) - basic $ 5.17 $ 2.87 $ 3.77 - diluted $ 5.16 $ 2.85 $ 3.74 Adjusted net earnings from operations (3) $ 7,444 $ 7,414 $ 8,533 Per common share (2) - basic (4) $ 3.56 $ 3.49 $ 3.91 - diluted (4) $ 3.55 $ 3.46 $ 3.87 Cash flows from operating activities $ 15,106 $ 13,386 $ 12,353 Adjusted funds flow (3) $ 15,460 $ 14,859 $ 15,274 Per common share (2) - basic (4) $ 7.39 $ 6.99 $ 7.00 - diluted (4) $ 7.37 $ 6.94 $ 6.93 Cash flows used in investing activities $ 6,687 $ 14,095 $ 4,858 Net capital expenditures (3) $ 6,579 $ 14,431 $ 4,909 Abandonment expenditures $ 771 $ 646 $ 509 Long-term debt, net (5) $ 15,944 $ 18,688 $ 9,922 Shareholders' equity $ 44,366 $ 39,468 $ 39,832 Debt to book capitalization (5) 26% 32% 20% Further details related to product sales are disclosed in note 21 to the Company's audited consolidated financial statements. Per common share amounts have been updated to reflect the two for one common share split in June 2024. Further details are disclosed in the 'Advisory' section of the Company's Management's Discussion and Analysis ("MD&A") and in note 1 to the Company's audited consolidated financial statements. Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's annual MD&A included in this annual report. Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A. Capital Management Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A and note 15 to the Company's audited consolidated financial statements. Cover: Jackpine Mine Extraction building. TABLE OF CONTENTS 1 2025 Performance Highlights 3 Letter to Shareholders 7 2025 Year End Reserves 10 Management's Discussion and Analysis Consolidated Financial Statements Management's Report 59 Management's Assessment of Internal Control over Financial Reporting 60 Report of Independent Registered Public Accounting Firm 67 Notes to the Consolidated Financial Statements 103 Supplementary Oil and Gas Information 113 Ten Year Review 115 Corporate Information 2025 2024 2023 OPERATING Daily production, before royalties (1) Crude oil and NGLs (Mbbl/d) North America - Exploration and Production 569 509 496 North America - Oil Sands Mining and Upgrading 565 472 451 North Sea 8 12 13 Offshore Africa 3 13 13 1,146 1,006 974 Natural gas (MMcf/d) North America 2,538 2,136 2,139 North Sea 3 2 2 Offshore Africa 6 9 10 2,547 2,147 2,151 Barrels of oil equivalent (MBOE/d) (2) 1,571 1,363 1,332 Drilling activity (3) North America 438 387 284 North Sea - - - Offshore Africa - - - 438 387 284 Numbers may not add due to rounding. 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. Net wells. Excludes net stratigraphic test and service wells. ~1,146,000 BBL/D RECORD LIQUIDS PRODUCTION 77% OF TOTAL LIQUIDS PRODUCTION IS LONG LIFE LOW DECLINE Letter to Shareholders Canadian Natural holds one of the largest, most diversified and highest-quality portfolios in the oil and natural gas industry. Our long life low decline production base provides reliable, sustainable output, while our extensive infrastructure ownership in core areas gives us strong control over operations, costs, and market access. This affords us significant flexibility when balancing our four pillars of capital allocation: returns to shareholders, balance sheet strength, resource value growth and opportunistic acquisitions. Our operational excellence delivers industry-leading performance through safety, reliability and cost efficiency and our low maintenance capital and low break-even costs support sustainable free cash flow generation. This, combined with our strong balance sheet and financial strength, drive strong and sustainable returns to shareholders. 2025 was the best operational year in the Company's long history of maximizing value for our shareholders. We set several production records, lowered our operating costs and capital expenditures came in under our forecast. We grew organically and completed several accretive acquisitions, and as a result, we achieved record annual production of 1,571 MBOE/d in 2025, resulting in year-over-year production growth of 15% or approximately 207 MBOE/d from 2024 levels. We also achieved record annual liquids production of 1,146 Mbbl/d, of which 65% was comprised of Synthetic Crude Oil ("SCO"), light crude oil and NGLs. Strong execution across our large, diverse asset base continues to provide significant opportunities to create shareholder value in 2026 and beyond. This is evidenced by our increased production, strong free cash flow and growth in reserves achieved in 2025, through both organic growth and accretive acquisitions. These successes provided the Board of Directors with the confidence to approve a dividend increase and an enhancement to our direct shareholder returns, by adjusting our net debt targets as a part of our free cash flow allocation policy. Additionally, as of March 5, 2026, we decreased our 2026 operating capital forecast by approximately $310 million, following the completion of a strategic acquisition early in 2026, and increased our 2026 production guidance range to 1,615 MBOE/d and 1,665 MBOE/d from the previous guidance range of 1,590 MBOE/d and 1,650 MBOE/d. In 2025, we generated adjusted net earnings from operations of $7.4 billion or $3.56 per share, and adjusted funds flow of $15.5 billion or $7.39 per share. Throughout the year, we completed several accretive acquisitions, increasing production and cash flow, while reducing net debt by approximately $2.7 billion to just under $16 billion at year end 2025. In total we returned approximately $9.0 billion to our shareholders in 2025, including $4.9 billion in dividends, $1.4 billion in share repurchases and $2.7 billion in net debt reduction. Subsequent to year end, the Board of Directors approved a 6.4% increase to our quarterly dividend, bringing the annualized dividend up to $2.50 per common share. This marks 2026 as the 26 th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 20% over that time, demonstrating the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base. Additionally, the Board of Directors have, effective January 1, 2026, adjusted the net debt target levels in our free cash flow allocation policy which results in an acceleration of the next increase to direct shareholder returns. Now, when net debt falls below $16 billion, compared to our previous target of $15 billion, we will increase direct shareholder returns in the form of share repurchases to 75% of free cash flow generated, managed on a forward-looking basis. Our financial flexibility and long life low decline asset base provide a strong foundation and a competitive advantage with low maintenance capital requirements. Our US$ WTI breakeven remains top tier in the low to mid-$40 per barrel range. Our balance sheet is strong with significant liquidity of approximately $6.3 billion at year end 2025. Our excellent results highlight the cash flow generating capability of our top tier asset base with strong year end metrics, including Debt to Book Capitalization at 26%. ~$9.0 BILLION RETURNED TO SHAREHOLDERS IN 2025 ~1,571,000 BOE/D RECORD TOTAL PRODUCTION Canadian Natural's reserves are significant when compared to other major oil companies, which support long-term organic growth opportunities. Year end 2025 total proved reserves of 15.91 billion BOE and total proved plus probable reserves of 20.75 billion BOE represent increases of approximately 4% and 3%, respectively, from year end 2024 levels. With approximately 73% of the Company's total proved reserves being long life low decline, the strength and depth of our assets is evident and provide us with a total proved reserves life index ("RLI") of 31 years and a total proved plus probable RLI of 40 years. We continue to deliver strong total proved Finding, Development and Acquisition ("FD&A") costs, including changes in Future Development Cost ("FDC"), achieving an industry leading FD&A in 2025 of $3.64/BOE for total proved reserves and $2.42/BOE for total proved plus probable reserves. Canada's energy sector plays an important role in Canada's economy, providing jobs, economic growth, and reliable, affordable energy that the world needs. We believe that Canada has the people, resources, and expertise to be a global leader in oil and natural gas production. Canadian Natural remains focused on supporting Canada in supplying safe, reliable and responsibly produced energy. We continue to incorporate environmental, social and governance practices that enhance our long-term sustainability across all aspects of our business. Our diverse, long life low decline assets are ideal for continued review and evaluation of new technologies designed to improve productivity and reduce environmental impacts. We continue to create shared value in the communities where we operate in Canada, the United Kingdom and Africa. This 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 is committed to working together with these diverse communities to identify opportunities for education and training, employment, business development, and community investment. At the end of 2025, our work with Indigenous businesses led to approximately $1.1 billion in contracts being awarded during the year, a 33% increase from 2024 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. In 2026, we look to continue to deliver on our four pillars of capital allocation through our updated 2026 forecasted operating capital expenditures of approximately $6.0 billion, along with $993 million of abandonment expenditures and $125 million of carbon capture expenditures. We have capital flexibility to adjust to evolving market conditions, ensuring we are allocating capital effectively, strengthening our balance sheet and maximizing value for our shareholders. We have a long track record of consistently delivering strong, industry leading results driven by our safe, reliable operations and relentless focus on continuous improvement, which maximizes long-term shareholder value. Our team is world class and we would like to thank our employees and contractors for their hard work and focus on delivering safe, reliable, effective and efficient operations across all areas of the business. Your commitment to operational excellence and relentless focus on continuous improvement by following our mission statement underpins our ongoing success and positions Canadian Natural very well to drive long-term shareholder value into the future. N. MURRAY EDWARDS SCOTT G. STAUTH VICTOR C. DAREL Executive Chairman President Chief Financial Officer Advisory SPECIAL NOTE REGARDING NON-GAAP AND OTHER FINANCIAL MEASURES This document includes references to Non-GAAP and Other Financial Measures as defined in National Instrument 52-112 -Non-GAAP and Other Financial Measures Disclosure ("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 Accounting Standards and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this document and the Company's MD&A and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A. FREE CASH FLOW ALLOCATION POLICY Free cash flow is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay or maintain net debt levels, pursuant to the free cash flow allocation policy. The Company's free cash flow is used to determine the targeted amount of shareholder returns after dividends. The amount allocated to shareholders varies depending on the Company's net debt position. Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward-looking annual basis, while managing working capital and cash requirements as needed. Up to October 2024, before the announcement of the Chevron acquisition, the Company was targeting to allocate 100% of its free cash flow in 2024 to shareholder returns. In October 2024, with the announcement of the Chevron acquisition, the Board of Directors adjusted the allocation of free cash flow as follows: 60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion. When net debt is between $12 billion and $15 billion, free cash flow allocation will be 75% to shareholder returns and 25% to the balance sheet. When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns. The Company's free cash flow for the year ended December 31, 2025 and comparable period is shown below: Year Ended ($ millions) Dec 31 2025 Dec 31 2024 Adjusted funds flow (1) $ 15,460 $ 14,859 Less: Dividends on common shares 4,871 4,429 Net capital expenditures (2) 6,579 5,286 Abandonment expenditures 771 646 Free cash flow $ 3,239 $ 4,498 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 annual MD&A. Non-GAAP Financial Measure. In 2024, for the purpose of the free cash flow calculated above, net capital expenditures of $5,286 million excludes net acquisitions of $9,145 million. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's annual MD&A. In March 2026, the Board of Directors adjusted the allocation of free cash flow, effective January 1, 2026, as follows: When net debt is at or above $16 billion, 60% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 40% to the balance sheet. When net debt is between $13 billion and $16 billion, 75% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 25% to the balance sheet. When net debt is at or below $13 billion, 100% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases. CAPITAL BUDGET Capital budget (or capital forecast) is a forward-looking non-GAAP financial measure. 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 capital budget (or capital forecast) excludes abandonment expenditures related to the execution of the Company's abandonment and reclamation programs in North America and the North Sea. The Company currently carries an Asset Retirement Obligation ("ARO") liability on its balance sheet for these forecasted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries in Canada and the UK portion of the North Sea. The Company is eligible to recover interest related to tax recoveries in the North Sea. 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. Refer to note 15 to the Company's 2025 audited consolidated financial statements. 2025 Year End Reserves DETERMINATION OF RESERVES For the year ended December 31, 2025, 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 International Limited for its North America Conventional, Thermal and International reserves evaluation and review, 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 National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("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 RLI (1) of 31 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, 2025 (all reserves values are Company Gross unless stated otherwise). Total proved reserves increased 4% to 15.910 billion BOE, with reserves additions and revisions of 1.253 billion BOE. Total proved plus probable reserves increased 3% to 20.750 billion BOE, with reserves additions and revisions of 1.213 billion BOE. The strength and depth of the Company's assets are evident as approximately 73% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 31 years and a total proved plus probable BOE RLI of 40 years. - Additionally, high value, zero decline SCO and bitumen from the Horizon and Albian mines represent approximately 50% of total proved reserves with a RLI of 39 years. Proved developed producing reserves additions and revisions for 2025 were 1.129 billion BOE, replacing 2025 production by 197%. The proved developed producing BOE RLI is 20 years. Total proved reserves additions and revisions for 2025 replaced 2025 production by 218%. Total proved plus probable reserves additions and revisions for 2025 replaced 2025 production by 212%. In 2025, Canadian Natural continued to achieve strong FD&A costs: FD&A costs, including changes in FDC, are $3.64/BOE for total proved reserves and $2.42/BOE for total proved plus probable reserves. At December 31, 2025, the net present value of Future Net Revenues ("FNR"), before income tax, discounted at 10%, was $110.1 billion for proved developed producing reserves, $157.8 billion for total proved reserves, and $191.0 billion for total proved plus probable reserves. (1) Supplementary financial measure. Refer to the notes to the '2025 Year End Reserves' on page 9. Summary of Company Gross Reserves as of December 31, 2025 Forecast Prices and Costs Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil Thermal Bitumen Mining Bitumen Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent Total Company (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) Proved Developed Producing 121 130 188 684 835 7,043 5,861 229 10,207 Developed Non-Producing 28 6 - 42 - - 272 13 135 Undeveloped 160 92 55 2,603 14 91 11,873 575 5,568 Total Proved 309 228 243 3,330 849 7,134 18,006 817 15,910 Probable 118 105 107 1,845 46 554 9,969 404 4,840 Total Proved plus Probable 427 333 349 5,175 895 7,688 27,974 1,221 20,750 Reconciliation of Company Gross Reserves as of December 31, 2025 Forecast Prices and Costs TOTAL PROVED Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil Thermal Bitumen Mining Bitumen Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent Total Company (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) December 31, 2024 252 219 255 3,312 - 7,663 16,904 713 15,231 Discoveries - - - - - - - - - Extensions 16 12 - 66 - - 113 8 121 Infill Drilling 2 17 1 9 - - 191 36 97 Improved Recovery - 1 3 - - 2 - - 6 Acquisitions 68 - - - 427 - 1,153 74 760 Dispositions - - - - - - - - - Economic Factors (4) (4) (3) - - - (99) (4) (32) Technical Revisions 1 15 2 43 426 (328) 674 28 300 Production (26) (32) (16) (100) (4) (202) (930) (38) (573) December 31, 2025 309 228 243 3,330 849 7,134 18,006 817 15,910 TOTAL PROVED PLUS Light and Primary Pelican Lake Natural Barrels PROBABLE Medium Heavy Heavy Thermal Mining Synthetic Natural Gas of Oil Crude Oil Crude Oil Crude Oil Bitumen Bitumen Crude Oil Gas Liquids Equivalent Total Company (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) December 31, 2024 346 318 360 5,190 - 8,255 27,156 1,116 20,110 Discoveries - - - - - - - - - Extensions 22 20 - 89 - - 167 12 171 Infill Drilling 2 26 3 11 - - 325 54 149 Improved Recovery - 1 4 - - 2 - - 7 Acquisitions 99 - - - 450 - 1,469 95 888 Dispositions - - - - - - - - - Economic Factors (5) (5) (2) - - - (99) (4) (32) Technical Revisions (11) 5 - (15) 449 (367) (114) (14) 29 Production (26) (32) (16) (100) (4) (202) (930) (38) (573) December 31, 2025 427 333 349 5,175 895 7,688 27,974 1,221 20,750 NOTES TO RESERVES: Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests. Information in the reserves data tables may not add due to rounding. BOE values and oil and natural gas metrics may not calculate exactly due to rounding. Forecast pricing assumptions utilized by the IQREs in the reserves estimates are the 3-Consultant-Average of price forecasts developed by Sproule International Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2025: 2026 2027 2028 2029 2030 Crude Oil and NGLs WTI US$/bbl 59.92 65.10 70.28 71.93 73.37 WCS C$/bbl 65.13 70.43 76.90 78.71 80.29 Canadian Light Sweet C$/bbl 77.54 83.60 90.17 92.32 94.17 Cromer LSB C$/bbl 75.09 81.56 86.95 89.19 90.98 Edmonton C5+ C$/bbl 80.01 86.19 92.83 95.04 96.94 Brent US$/bbl 63.92 69.13 74.36 76.10 77.62 Natural Gas AECO C$/MMBtu 3.00 3.30 3.49 3.58 3.65 BC Westcoast Station 2 C$/MMBtu 2.66 3.07 3.25 3.34 3.41 Henry Hub US$/MMBtu 3.74 3.78 3.85 3.93 4.01 All prices increase at a rate of 2% per year after 2030. A US$/C$ foreign exchange rate of 0.7277 was used for 2026, 0.7367 for 2027, and 0.7400 for 2028 and thereafter in the year end 2025 evaluation. 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. Oil and natural 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. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production. 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. Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2026 proved developed producing production forecast prepared by the IQREs. Finding, Development and Acquisition ("FD&A") costs including changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2025 and net changes in FDC from December 31, 2024 to December 31, 2025 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation ("ADR") costs. ADR costs included in the calculation of the Future Net Revenue ("FNR") consist of both the Company's Asset Retirement Obligation ("ARO") for North America and Offshore Africa, before inflation and discounting, for development existing as at December 31, 2025 and forecast estimates of ADR costs attributable to future development activity. Management's Discussion and Analysis Table of Contents Definitions and Abbreviations 11 Advisory 12 Objectives and Strategy 15 Financial and Operational Highlights 16 Business Environment and Outlook 19 Analysis of Changes in Product Sales 21 Daily Production 22 Exploration and Production 24 Oil Sands Mining and Upgrading 28 Midstream and Refining 30 Corporate and Other 31 Net Capital Expenditures 34 Liquidity and Capital Resources 35 Commitments and Contingencies 38 Reserves 39 Risks and Uncertainties 40 Environment 41 Accounting Policies and Standards 45 Control Environment 47 Non-GAAP and Other Financial Measures 48 Other 53 Definitions and Abbreviations AECO Alberta natural gas reference location AIF Annual Information Form AOSP Athabasca Oil Sands Project API specific gravity measured in degrees on the American Petroleum Institute scale ARO asset retirement obligations bbl barrel bbl/d barrels per day Bcf billion cubic feet Bcf/d billion cubic feet per day Bitumen 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 BOE barrels of oil equivalent BOE/d barrels of oil equivalent per day Brent Dated Brent C$ Canadian dollars CO 2 carbon dioxide CO 2 e carbon dioxide equivalents CORRA Canadian Overnight Repo Rate Average Crude oil includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, and synthetic crude oil E&P Exploration and Production FASB Financial Accounting Standards Board FPSO Floating Production, Storage and Offloading Vessel GHG greenhouse gas GJ gigajoules GJ/d gigajoules per day Horizon Horizon Oil Sands Mbbl/d thousand barrels per day MBOE thousand barrels of oil equivalent MBOE/d thousand barrels of oil equivalent per day Mcf thousand cubic feet Mcfe thousand cubic feet equivalent Mcf/d thousand cubic feet per day MMbbl million barrels MMBOE million barrels of oil equivalent MMBtu million British thermal units MMBtu/d million British thermal units per day MMcf million cubic feet MMcf/d million cubic feet per day MOU Memorandum of Understanding between the Government of Canada and the Government of Alberta. NGLs natural gas liquids NWRP North West Redwater Partnership NYMEX New York Mercantile Exchange NYSE New York Stock Exchange OPEC+ Organization of the Petroleum Exporting Countries Plus PRT Petroleum Revenue Tax SCO synthetic crude oil. Includes all crude oil blends (including mining bitumen) produced from Horizon, AOSP mines and Scotford Upgrader. SEC United States Securities and Exchange Commission SOFR Secured Overnight Financing Rate TSX Toronto Stock Exchange UK United Kingdom US United States US$ United States dollars WCS Western Canadian Select IFRS Accounting Standards International Financial Reporting Standards as issued by the International Accounting Standards Board WCS Heavy Differential WCS Heavy Differential from WTI Mbbl thousand barrels WCSB Western Canadian Sedimentary Basin WTI West Texas Intermediate reference location at Cushing, Oklahoma Advisory SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration", or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, forecast and anticipated abandonment expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon, AOSP, the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, NGLs, or SCO that the Company may be reliant upon to transport its products to market; the maintenance of the Company's facilities and any expected return to service dates; the construction, expansion, or maintenance of third-party facilities that process the Company's products; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the materiality of the impact of tax interpretations and litigation on the Company's results, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives, or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas, and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The forward-looking statements are based on current expectations, estimates, and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance, or achievements of the Company to be materially different from any future results, performance, or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of OPEC+, the impact of conflicts in the Middle East, in Ukraine and in Venezuela, the restriction or disruption of global trade routes, the impact of changes to US economic policy, 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; the impact of the ramp-up of LNG Canada on commodity 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; changes and uncertainties in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded); uncertainty in the regulatory framework governing GHG emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps, and the implementation of the MOU in November 2025; civil unrest and political uncertainty, including changes in government, actions of or against terrorists, insurgent groups, or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime, and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling, and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting, or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting, or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets, including the acquisition of the remaining interest in the AOSP mines and other acquisitions that occurred in 2025; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium-, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses. The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state, and local laws and regulations such as restrictions on production or emissions, the imposition of tariffs, embargoes, or export restrictions on the Company's products (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded), changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations (including the implementation of the MOU). Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available. Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity, and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change. SPECIAL NOTE REGARDING NON-GAAP AND OTHER FINANCIAL MEASURES This MD&A includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position, or cash flow. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided in the 'Non-GAAP and Other Financial Measures' section of this MD&A. SPECIAL NOTE REGARDING COMMON SHARE SPLIT AND COMPARATIVE FIGURES At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split. SPECIAL NOTE REGARDING AMENDMENTS TO THE COMPETITION ACT (CANADA) On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement, which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. Subsequently, on November 4, 2025, the federal government tabled the 2025 Budget, which proposed further amendments to the Competition Act , namely removing the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminating private rights of action under the revised business-activity greenwashing provision. Uncertainty surrounding the interpretation and enforcement of this legislation, which includes the status of any proposed or future amendments, may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results. SPECIAL NOTE REGARDING CURRENCY, FINANCIAL INFORMATION, PRODUCTION AND RESERVES This MD&A should be read in conjunction with the Company's audited consolidated financial statements for the year ended December 31, 2025. It should also be read in conjunction with the Company's MD&A for the three months and year ended December 31, 2025. 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, 2025 and this MD&A have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (the "IFRS Accounting Standards"). Production volumes and per unit statistics are presented throughout this MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, and SCO (including mining bitumen). 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 2025 financial results compared to 2024 and 2023, unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2026. 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, 2025, its Annual Information Form for the year ended December 31, 2025, and its audited consolidated financial statements for the year ended December 31, 2025, is available on SEDAR+ at https://www.sedarplus.ca , and on EDGAR at https://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 March 4, 2026. Objectives and Strategy The Company's objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value 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 and its commitments 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 longterm 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 (1) , thermal bitumen, 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; Expanding market access for crude oil and natural gas by supporting and participating in pipeline and infrastructure projects that add incremental transportation capacity to existing and new markets; and Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil and thermal bitumen. 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 provide the means to responsibly and sustainably grow in the long term. 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. Financial and Operational Highlights ($ millions, except per common share amounts) 2025 2024 2023 (1) Product sales (2) $ 44,167 $ 41,509 $ 40,835 Crude oil and NGLs $ 40,740 $ 39,084 $ 37,300 Natural gas $ 2,450 $ 1,568 $ 2,575 Net earnings $ 10,820 $ 6,106 $ 8,233 Per common share - basic $ 5.17 $ 2.87 $ 3.77 - diluted $ 5.16 $ 2.85 $ 3.74 Adjusted net earnings from operations (3) $ 7,444 $ 7,414 $ 8,533 Per common share - basic (4) $ 3.56 $ 3.49 $ 3.91 - diluted (4) $ 3.55 $ 3.46 $ 3.87 Cash flows from operating activities $ 15,106 $ 13,386 $ 12,353 Adjusted funds flow (3) $ 15,460 $ 14,859 $ 15,274 Per common share - basic (4) $ 7.39 $ 6.99 $ 7.00 - diluted (4) $ 7.37 $ 6.94 $ 6.93 Dividends declared per common share (5) $ 2.35 $ 2.14 $ 1.85 Total assets $ 91,830 $ 85,359 $ 75,955 Long-term debt, net (6) $ 15,944 $ 18,688 $ 9,922 Cash flows used in investing activities $ 6,687 $ 14,095 $ 4,858 Net capital expenditures (3) $ 6,579 $ 14,431 $ 4,909 Abandonment expenditures $ 771 $ 646 $ 509 Average realized price Crude oil and NGLs - Exploration and Production ($/bbl) (4) $ 71.54 $ 77.76 $ 72.36 Natural gas - Exploration and Production ($/Mcf) (7) $ 2.51 $ 1.86 $ 3.10 SCO - Oil Sands Mining and Upgrading ($/bbl) (4) $ 86.41 $ 98.03 $ 100.06 Daily production, before royalties (BOE/d) 1,570,757 1,363,496 1,332,105 Crude oil and NGLs (bbl/d) 1,146,175 1,005,603 973,530 Natural gas (MMcf/d) (8) 2,547 2,147 2,151 Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the 'Advisory' section of this MD&A and in note 1 to the Company's audited consolidated financial statements. Further details related to product sales are disclosed in note 21 to the Company's audited consolidated financial statements. Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. On March 4, 2026, the Board of Directors approved a 6% increase in the quarterly dividend to $0.625 per common share, beginning with the dividend payable on April 7, 2026. On March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share. On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $0.525 per common share. On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $0.50 per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.45 per common share. Capital management measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. Calculated as natural gas sales divided by sales volumes. Natural gas production volumes approximate sales volumes. CONSOLIDATED NET EARNINGS AND ADJUSTED NET EARNINGS FROM OPERATIONS For 2025, the Company reported net earnings of $10,820 million compared with $6,106 million for 2024 (2023 - $8,233 million). Net earnings for 2025 included non-operating income, net of tax, of $3,376 million compared with non-operating losses of $1,308 million for 2024 (2023 - non-operating losses of $300 million) related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain from investment, the gain on acquisitions, disposition, and remeasurement, and recoverability charges related to the North Sea and Offshore Africa. Excluding these items, adjusted net earnings from operations for 2025 were $7,444 million compared with $7,414 million for 2024 (2023 - $8,533 million). The increase in net earnings and adjusted net earnings from operations for 2025 compared with 2024 primarily reflected: higher sales volumes in the Oil Sands Mining and Upgrading segment; higher crude oil and NGLs sales volumes in the North America Exploration and Production segment; and higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment; partially offset by: lower realized SCO pricing (1) in the Oil Sands Mining and Upgrading segment; and lower realized crude oil and NGLs pricing (1) 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 depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchange (gain) loss, the gain on acquisitions, disposition, and remeasurement, the gain from investment, and recoverability charges related to the North Sea and Offshore Africa also contributed to the increase in net earnings for 2025 from 2024. These items are discussed in detail in the relevant sections of this MD&A. The AOSP asset swap is discussed below, and the recoverability charges related to the North Sea and Offshore Africa are discussed in detail in the 'Adjusted Depletion, Depreciation and Amortization - Exploration and Production' section of this MD&A. AOSP ASSET SWAP TRANSACTION On November 1, 2025, the Company completed the AOSP asset swap with Shell Canada Limited and affiliates ("Shell"). As a result of the transaction, the Company acquired from Shell, the remaining 10% interest in the AOSP mines, associated reserves, and additional working interests in a number of other non-producing oil sands leases, and in exchange to Shell, a 10% non-operated working interest in the Scotford Upgrader ("Scotford") and Quest Carbon Capture and Storage ("Quest") facilities. As a result, the Company owns and operates 100% of the AOSP mines and retains an 80% non-operated working interest in Scotford and Quest. The transaction had an effective date of March 1, 2025. The Company recognized a $4,989 million gain related to the transaction, comprised of a $17 million gain on acquisition representing the excess of the fair value of the net assets acquired compared to the total purchase consideration and previously held interests, a non-cash gain of $4,508 million ($3,471 million after-tax) related to the remeasurement of the previously held interest in the AOSP mines to fair value, and a non-cash gain on disposition of $464 million ($357 million after-tax) related to the disposition of the 10% interest in Scotford and Quest. Further details are disclosed in note 6 to the Company's audited consolidated financial statements. CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW Cash flows from operating activities for 2025 were $15,106 million compared with $13,386 million for 2024 (2023 - $12,353 million). The increase in cash flows from operating activities for 2025 from 2024 were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital. Adjusted funds flow for 2025 was $15,460 million ($7.39 per common share) compared with $14,859 million ($6.99 per common share) for 2024 (2023 - $15,274 million; $7.00 per common share (2) ). The increase in adjusted funds flow for 2025 from 2024 was primarily due to the factors noted above related to the increase in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, and movements in other long-term assets, including the unamortized cost of contributions to the Company's employee bonus program, interest on PRT and corporate tax recoveries, and prepaid cost of service tolls. PRODUCTION VOLUMES Record crude oil and NGLs production before royalties for 2025 of 1,146,175 bbl/d increased 14% from 1,005,603 bbl/d in 2024 (2023 - 973,530 bbl/d). Natural gas production before royalties for 2025 averaged 2,547 MMcf/d, an increase of 19% from 2,147 MMcf/d in 2024 (2023 - 2,151 MMcf/d). Total production before royalties for 2025 of 1,570,757 BOE/d increased 15% from 1,363,496 BOE/d in 2024 (2023 - 1,332,105 BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in detail in the 'Daily Production' section of this MD&A. Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the 'Advisory' section of this MD&A and in note 1 to the Company's audited consolidated financial statements. PRODUCT PRICES In the Company's Exploration and Production segments, the 2025 realized crude oil and NGLs prices decreased 8% to average $71.54 per bbl from $77.76 per bbl in 2024 (2023 - $72.36 per bbl), and the 2025 realized natural gas price increased 35% to average $2.51 per Mcf from $1.86 per Mcf in 2024 (2023 - $3.10 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company's 2025 realized SCO sales price averaged $86.41 per bbl, a decrease of 12% from $98.03 per bbl in 2024 (2023 - $100.06 per bbl). The Company's realized product pricing is reflective of the prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the 'Business Environment and Outlook', 'Realized Product Prices - Exploration and Production', and the 'Realized Product Prices, Royalties and Transportation - Oil Sands Mining and Upgrading' sections of this MD&A. PRODUCTION EXPENSE In the Company's Exploration and Production segments, the 2025 crude oil and NGLs production expense (1) averaged $14.33 per bbl, comparable with $14.72 per bbl in 2024 (2023 - $16.12 per bbl), and natural gas production expense (1) averaged $1.14 per Mcf in 2025, a decrease of 7% from $1.22 per Mcf in 2024 (2023 - $1.30 per Mcf). In the Oil Sands Mining and Upgrading segment, the 2025 production expense (1) averaged $22.66 per bbl, comparable with $22.88 per bbl in 2024 (2023 - $24.32 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the 'Production Expense - Exploration and Production' and the 'Production Expense - Oil Sands Mining and Upgrading' sections of this MD&A. SUMMARY OF QUARTERLY FINANCIAL RESULTS The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters: ($ millions, except per common share amounts) 2025 Total Dec 31 Sep 30 Jun 30 Mar 31 Product sales (1) $ 44,167 $ 10,710 $ 11,070 $ 9,675 $ 12,712 Crude oil and NGLs $ 40,740 $ 9,666 $ 10,468 $ 8,874 $ 11,732 Natural gas $ 2,450 $ 735 $ 399 $ 600 $ 716 Net earnings Net earnings per common share $ 10,820 $ 5,303 $ 600 $ 2,459 $ 2,458 - basic $ 5.17 $ 2.55 $ 0.29 $ 1.17 $ 1.17 - diluted $ 5.16 $ 2.54 $ 0.29 $ 1.17 $ 1.17 2024 Total Dec 31 Sep 30 Jun 30 Mar 31 (2) Product sales (1) $ 41,509 $ 11,064 $ 10,401 $ 10,622 $ 9,422 Crude oil and NGLs $ 39,084 $ 10,381 $ 9,943 $ 10,084 $ 8,676 Natural gas $ 1,568 $ 451 $ 257 $ 331 $ 529 Net earnings $ 6,106 $ 1,138 $ 2,266 $ 1,715 $ 987 Net earnings per common share - basic $ 2.87 $ 0.54 $ 1.07 $ 0.80 $ 0.46 - diluted $ 2.85 $ 0.54 $ 1.06 $ 0.80 $ 0.46 Further details related to product sales are disclosed in note 21 to the Company's audited consolidated financial statements. Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the 'Advisory' section of this MD&A and in note 1 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 conflicts in the Middle East, Ukraine and Venezuela, and the impacts of ongoing tariff and trade uncertainty) on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the start-up of the Trans Mountain Expansion ("TMX") pipeline in 2024, 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, the impact of third-party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, the impact of liquefied natural gas ("LNG") demand and exports, and the impact of shale gas production in the US. (1) Calculated as respective production expense divided by respective sales volumes. Crude oil and NGLs sales volumes - Fluctuations in production from Kirby and Jackfish, fluctuations in production due to the cyclic nature of Primrose, fluctuations in the Company's drilling program in the North America Exploration and Production segment, natural field declines, the impact of turnarounds in the Oil Sands Mining and Upgrading segment, the impact and timing of acquisitions (including the acquisition of working interests in AOSP and Duvernay assets in 2024, the acquisition of assets in the Palliser block and the Grande Prairie area in 2025, and the AOSP asset swap in 2025), wildfires, and maintenance activities in the North America Exploration and Production segment. Sales volumes in the International segments also reflected fluctuations due to the timing of liftings, planned abandonment activities in the North Sea, and temporary suspension of production at Baobab in Offshore Africa for planned FPSO maintenance. Natural gas sales volumes - Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, the impact and timing of acquisitions (including the acquisition of a working interest in the Duvernay assets in 2024, and the acquisition of assets in the Palliser block and the Grande Prairie area in 2025), natural field declines, the impact of seasonal conditions, and wildfires 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, carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds 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, timing of acquisitions, 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 in the Oil Sands Mining and Upgrading segment, and recoverability charges related to the North Sea and Offshore Africa. Share-based compensation - Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability. Risk management - Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities. Interest expense - Fluctuations due to changing long-term debt levels and lease liabilities, the impact of movements in benchmark interest rates on outstanding floating rate long-term debt, and interest on PRT and corporate tax recoveries. Foreign exchange - Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt and working capital. Gain on acquisitions, disposition, and remeasurement - A gain on acquisitions representing the excess of the fair value of the net assets acquired compared to total purchase consideration and previously held interests, a gain on remeasurement to fair value of the Company's pre-existing 90% interest in the AOSP mines as part of the AOSP asset swap, and a gain on disposition of the 10% interest in Scotford and Quest disposed of as part of the AOSP asset swap. Business Environment and Outlook Global crude oil benchmark pricing declined through the fourth quarter of 2025 as increasing global supply outpaced relatively modest demand growth, which remained subdued amid ongoing tariff and trade uncertainty. Late in the fourth quarter of 2025, escalating geopolitical tensions contributed to heightened concerns regarding potential crude oil supply disruptions entering into 2026. Natural gas benchmark pricing increased during the fourth quarter of 2025, driven by seasonal demand factors and continued strength in LNG export activity out of the US Gulf Coast. In Canada, AECO benchmark pricing improved due to robust export volumes out of the WCSB. The ongoing ramp-up of LNG Canada is expected to further increase LNG demand and support AECO pricing in 2026. During 2025, the US government announced tariffs on certain Canadian goods. While these actions have contributed to market volatility, including commodity price and foreign currency volatility, these tariffs have not had a material impact on the Company's financial results as of the date of this MD&A. The duration of these trade actions remains uncertain, and broader changes to US economic policy may have a material effect on the Company's business, financial conditions, or results in future periods. The Company will continue to monitor and assess the implications of any current or emerging US economic policies. BENCHMARK COMMODITY PRICES (Yearly average) 2025 2024 2023 WTI benchmark price (US$/bbl) $ 64.77 $ 75.72 $ 77.61 Dated Brent benchmark price (US$/bbl) $ 69.02 $ 80.75 $ 82.61 WCS Heavy Differential from WTI (US$/bbl) $ 11.10 $ 14.73 $ 18.62 SCO price (US$/bbl) $ 64.42 $ 75.09 $ 79.64 Condensate benchmark price (US$/bbl) $ 63.32 $ 72.94 $ 76.55 NYMEX benchmark price (US$/MMBtu) $ 3.43 $ 2.27 $ 2.74 AECO benchmark price (C$/GJ) $ 1.76 $ 1.36 $ 2.77 US/Canadian dollar average exchange rate (US$) $ 0.7155 $ 0.7300 $ 0.7409 US/Canadian dollar year end exchange rate (US$) $ 0.7292 $ 0.6942 $ 0.7573 Substantially all of the Company's production is sold based on US dollar benchmark pricing, with crude oil marketed based on WTI and Brent indices, and natural gas marketed using a diversified mix of AECO- and NYMEX-based pricing. The Company's realized prices are directly impacted by fluctuations in foreign exchange rates resulting in product revenues being impacted by changes in Canadian dollar sales prices relative to the US dollar benchmark prices. Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$64.77 per bbl for 2025, a decrease of 14% from US$75.72 per bbl for 2024 (2023 - US$77.61 per bbl). Crude oil sales contracts for the Company's International segments are typically based on Brent benchmark pricing, which is representative of international markets and overall global supply and demand. Brent averaged US$69.02 per bbl for 2025, a decrease of 15% from US$80.75 per bbl for 2024 (2023 - US$82.61 per bbl). The decrease in WTI and Brent benchmark pricing for 2025 from 2024 primarily reflected increased global supply and inventory builds driven by near-record production from non-OPEC+ producers and higher OPEC+ output. Supply gains exceeded global demand growth, which remained muted amid ongoing tariff and trade uncertainty. The WCS Heavy Differential averaged US$11.10 per bbl for 2025 compared with US$14.73 per bbl for 2024 (2023 -US$18.62 per bbl). The narrowing of the WCS Heavy Differential for 2025 from 2024 primarily reflected full year takeaway capacity on the TMX pipeline and strong US Gulf Coast heavy oil pricing. The SCO price averaged US$64.42 per bbl for 2025, a decrease of 14% from US$75.09 per bbl for 2024 (2023 - US$79.64 per bbl). The decrease in SCO pricing for 2025 from 2024 primarily reflected weaker WTI benchmark pricing. NYMEX benchmark pricing averaged US$3.43 per MMBtu for 2025, an increase of 51% from US$2.27 per MMBtu for 2024 (2023 - US$2.74 per MMBtu). The increase in NYMEX natural gas pricing for 2025 from 2024 primarily reflected lower US inventory levels in the first half of 2025, combined with record LNG exports out of the US Gulf Coast. AECO benchmark pricing averaged $1.76 per GJ for 2025, an increase of 29% from $1.36 per GJ for 2024 (2023 - $2.77 per GJ). The increase in AECO natural gas pricing for 2025 from 2024 primarily reflected higher NYMEX benchmark pricing and increased exports out of the WCSB. Analysis of Changes in Product Sales Changes due to Changes due to ($ millions) 2023 North America Volumes Prices Other 2024 Volumes Prices Other 2025 Crude oil and NGLs $ 17,375 $ 283 $ 1,082 $ - $ 18,740 $ 2,392 $ (2,030) $ - $ 19,102 Natural gas 2,375 3 (963) - 1,415 261 611 - 2,287 Other (1) 10 - - (4) 6 - - 86 92 19,760 286 119 (4) 20,161 2,653 (1,419) 86 21,481 North Sea Crude oil and NGLs 435 30 2 - 467 (95) (47) - 325 Natural gas 7 1 (1) - 7 4 2 - 13 Other (1) - - - 4 4 - - (4) - 442 31 1 4 478 (91) (45) (4) 338 Offshore Africa Crude oil and NGLs 577 (142) (1) - 434 (260) (10) - 164 Natural gas 51 (7) (2) - 42 (13) 1 - 30 Other (1) 9 - - (5) 4 - - (3) 1 637 (149) (3) (5) 480 (273) (9) (3) 195 Oil Sands Mining and Upgrading Crude oil and NGLs 18,661 823 (221) - 19,263 4,138 (3,289) - 20,112 Other (1) 5 - - 11 16 - - 188 204 18,666 823 (221) 11 19,279 4,138 (3,289) 188 20,316 Midstream and Refining Midstream activities 76 - - 6 82 - - 9 91 Refined product sales and other (1) 926 - - (113) 813 - - (143) 670 1,002 - - (107) 895 - - (134) 761 Inter-segment Elimination and Other (2) Product sales 318 - - (116) 202 - - 864 1,066 Other (1) 10 - - 4 14 - - (4) 10 328 - - (112) 216 - - 860 1,076 Total $ 40,835 $ 991 $ (104) $ (213) $ 41,509 $ 6,427 $ (4,762) $ 993 $ 44,167 Includes the sale of diesel and other refined products, and other income. 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 increased 6% to $44,167 million for 2025 from $41,509 million for 2024 (2023 - $40,835 million). The increase in total product sales was primarily due to higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and higher crude oil and NGLs sales volumes, together with higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment; partially offset by lower realized SCO pricing and lower realized crude oil and NGLs pricing in the Oil Sands Mining and Upgrading and North America Exploration and Production segments, respectively. Crude oil and NGLs and natural gas pricing are discussed in detail in the 'Business Environment and Outlook', 'Exploration and Production' and '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 2025, 1% of the Company's crude oil and NGLs and natural gas product sales were generated outside of North America (2024 - 2%; 2023 - 3%). North Sea accounted for 1% of crude oil and NGLs and natural gas product sales for 2025 (2024 - 1%; 2023 - 1%), and Offshore Africa accounted for less than 1% of crude oil and NGLs and natural gas product sales for 2025 (2024 - 1%; 2023 - 2%). Daily Production DAILY PRODUCTION, BEFORE ROYALTIES 2025 2024 2023 Crude oil and NGLs (bbl/d) North America - Exploration and Production 569,401 509,288 496,100 North America - Oil Sands Mining and Upgrading (1) International - Exploration and Production 565,102 472,245 451,339 North Sea 8,468 11,536 12,639 Offshore Africa 3,204 12,534 13,452 Total International (2) 11,672 24,070 26,091 Total Crude oil and NGLs 1,146,175 1,005,603 973,530 Natural gas (MMcf/d) (3) North America 2,538 2,136 2,139 International North Sea 3 2 2 Offshore Africa 6 9 10 Total International 9 11 12 Total Natural gas 2,547 2,147 2,151 Total Barrels of oil equivalent (BOE/d) 1,570,757 1,363,496 1,332,105 Product mix Light and medium crude oil and NGLs 11% 10% 10% Pelican Lake heavy crude oil 3% 3% 3% Primary heavy crude oil 6% 6% 6% Thermal bitumen 17% 20% 20% Synthetic crude oil (1) 36% 35% 34% Natural gas 27% 26% 27% Percentage of product sales (1) (4) (5) Crude oil and NGLs 94% 96% 93% Natural gas 6% 4% 7% SCO production before royalties excludes SCO consumed internally as diesel. "International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used in this MD&A. Natural gas production volumes approximate sales volumes. Net of blending and feedstock costs and excluding risk management activities. Excluding Midstream and Refining revenue. DAILY PRODUCTION, NET OF ROYALTIES 2025 2024 2023 Crude oil and NGLs (bbl/d) North America - Exploration and Production 476,850 408,237 406,534 North America - Oil Sands Mining and Upgrading (1) International - Exploration and Production 467,415 386,171 385,996 North Sea 8,451 11,509 12,609 Offshore Africa 3,061 11,918 12,183 Total International 11,512 23,427 24,792 Total Crude oil and NGLs 955,777 817,835 817,322 Natural gas (MMcf/d) North America 2,466 2,091 2,055 International North Sea 3 2 2 Offshore Africa 6 9 10 Total International 9 11 12 Total Natural gas 2,475 2,102 2,067 Total Barrels of oil equivalent (BOE/d) 1,368,198 1,168,209 1,161,852 (1) SCO production net of royalties excludes SCO consumed internally as diesel. The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, thermal bitumen, SCO, and natural gas. Total 2025 production before royalties averaged 1,570,757 BOE/d, an increase of 15% from 1,363,496 BOE/d in 2024 (2023 - 1,332,105 BOE/d). Record crude oil and NGLs production before royalties for 2025 averaged 1,146,175 bbl/d, an increase of 14% from 1,005,603 bbl/d for 2024 (2023 - 973,530 bbl/d). The increase in crude oil and NGLs production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, strong utilization in the Oil Sands Mining and Upgrading segment, and strong drilling results in the North America Exploration and Production segment. Annual crude oil and NGLs production before royalties for 2025 was within the Company's previously issued production target of 1,137,000 bbl/d and 1,151,000 bbl/d. Annual crude oil and NGLs production before royalties for 2026 is now targeted to average between 1,188,000 bbl/d and 1,229,000 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 2025 on a BOE basis. Record natural gas production before royalties for 2025 averaged 2,547 MMcf/d, an increase of 19% from 2,147 MMcf/d for 2024 (2023 - 2,151 MMcf/d). The increase in natural gas production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets. Annual natural gas production before royalties for 2025 was within the Company's previously issued production target of 2,535 MMcf/d and 2,575 MMcf/d. Annual natural gas production before royalties for 2026 is now targeted to average between 2,560 MMcf/d and 2,615 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 Record North America crude oil and NGLs production before royalties for 2025 averaged 569,401 bbl/d, an increase of 12% from 509,288 bbl/d for 2024 (2023 - 496,100 bbl/d). The increase in North America crude oil and NGLs production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results. Thermal oil production before royalties for 2025 averaged 275,086 bbl/d, comparable with 271,011 bbl/d for 2024 (2023 -262,000 bbl/d). Pelican Lake heavy crude oil production before royalties averaged 42,470 bbl/d for 2025, a decrease of 5% from 44,779 bbl/d for 2024 (2023 - 47,078 bbl/d) reflecting Pelican Lake's long life low decline production. Record North America natural gas production before royalties for 2025 averaged 2,538 MMcf/d, an increase of 19% from 2,136 MMcf/d for 2024 (2023 - 2,139 MMcf/d). The increase in natural gas production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets. North America - Oil Sands Mining and Upgrading Record SCO production before royalties for 2025 averaged 565,102 bbl/d, an increase of 20% from 472,245 bbl/d for 2024 (2023 - 451,339 bbl/d). The increase in SCO production before royalties for 2025 from 2024 primarily reflected the acquisition completed in December 2024, combined with strong utilization. International - Exploration and Production International crude oil and NGLs production before royalties for 2025 averaged 11,672 bbl/d, a decrease of 52% from 24,070 bbl/d for 2024 (2023 - 26,091 bbl/d). The decrease in International crude oil and NGLs production before royalties for 2025 from 2024 primarily reflected the temporary suspension of production at Baobab in Offshore Africa due to planned maintenance on its FPSO, which is expected to return to service in the second quarter of 2026, planned North Sea abandonments conducted as part of the previously announced decommissioning plans, and natural field declines. Exploration and Production OPERATING HIGHLIGHTS 2025 2024 2023 Crude oil and NGLs ($/bbl) (1) Realized price (2) $ 71.54 $ 77.76 $ 72.36 Transportation (3) 7.02 5.50 4.23 Realized price, net of transportation (2) 64.52 72.26 68.13 Royalties (4) 11.53 14.85 12.55 Production expense (5) 14.33 14.72 16.12 Netback (2) $ 38.66 $ 42.69 $ 39.46 Natural gas ($/Mcf) (1) Realized price (6) $ 2.51 $ 1.86 $ 3.10 Transportation (3) 0.59 0.62 0.56 Realized price, net of transportation 1.92 1.24 2.54 Royalties (4) 0.08 0.05 0.13 Production expense (5) 1.14 1.22 1.30 Netback (7) $ 0.70 $ (0.03) $ 1.11 Barrels of oil equivalent ($/BOE) (1) Realized price (2) $ 47.98 $ 50.82 $ 50.54 Transportation (3) 5.54 4.78 3.88 Realized price, net of transportation (2) 42.44 46.04 46.66 Royalties (4) 6.90 8.96 7.77 Production expense (5) 11.18 11.73 12.74 Netback (2) $ 24.36 $ 25.35 $ 26.15 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. Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. Calculated as transportation expense divided by respective sales volumes. Calculated as royalties divided by respective sales volumes. Calculated as production expense divided by respective sales volumes. Calculated as natural gas sales divided by natural gas sales volumes. Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids-rich natural gas plays. REALIZED PRODUCT PRICES - EXPLORATION AND PRODUCTION 2025 2024 2023 Crude oil and NGLs ($/bbl) (1) North America (2) $ 70.90 $ 76.37 $ 70.51 International average (3) $ 98.07 $ 108.80 $ 107.46 North Sea (3) $ 97.26 $ 111.53 $ 110.99 Offshore Africa (3) $ 99.71 $ 106.00 $ 106.25 Crude oil and NGLs average (2) $ 71.54 $ 77.76 $ 72.36 Natural gas ($/Mcf) (1) (3) North America $ 2.47 $ 1.81 $ 3.04 International average $ 12.45 $ 12.01 $ 12.81 North Sea $ 11.77 $ 9.93 $ 10.45 Offshore Africa $ 12.77 $ 12.46 $ 13.19 Natural gas average $ 2.51 $ 1.86 $ 3.10 Average ($/BOE) (1) (2) $ 47.98 $ 50.82 $ 50.54 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. Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. 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 7% to average $70.90 per bbl for 2025 from $76.37 per bbl for 2024 (2023 - $70.51 per bbl), primarily reflecting lower WTI benchmark pricing, partially offset by a narrowing of the WCS Heavy Differential. The Company remains focused on its crude oil blending and marketing strategy, which includes expanding market access within existing pipeline infrastructure, supporting pipeline projects that increase transportation capacity to new markets, and collaborating with refiners to enhance heavy conversion capacity. During 2025, the Company contributed approximately 223,000 bbl/d of heavy crude oil blends to the WCS stream. North America realized natural gas prices increased 36% to average $2.47 per Mcf for 2025 from $1.81 per Mcf for 2024 (2023 - $3.04 per Mcf). The increase in realized natural gas prices per Mcf for 2025 from 2024 primarily reflected higher AECO benchmark and export pricing. The prices received in the North America Exploration and Production segment by product type were as follows: (Yearly average) 2025 2024 2023 Wellhead Price (1) Light and medium crude oil and NGLs ($/bbl) $ 65.77 $ 69.42 $ 70.72 Pelican Lake heavy crude oil ($/bbl) $ 75.07 $ 82.83 $ 77.69 Primary heavy crude oil ($/bbl) $ 73.74 $ 81.97 $ 75.67 Thermal bitumen ($/bbl) $ 72.42 $ 76.57 $ 67.62 Natural gas ($/Mcf) $ 2.47 $ 1.81 $ 3.04 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 averaged $98.07 per bbl for 2025, a decrease of 10% from $108.80 per bbl for 2024 (2023 - $107.46 per bbl). Realized crude oil and NGLs prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, prevailing Brent benchmark prices and foreign exchange rates at the time of lifting. ROYALTIES - EXPLORATION AND PRODUCTION 2025 2024 2023 Crude oil and NGLs ($/bbl) (1) North America $ 11.77 $ 15.40 $ 12.89 International average $ 1.56 $ 2.75 $ 5.99 North Sea $ 0.15 $ 0.26 $ 0.33 Offshore Africa $ 4.41 $ 5.30 $ 10.08 Crude oil and NGLs average $ 11.53 $ 14.85 $ 12.55 Natural gas ($/Mcf) (1) North America $ 0.08 $ 0.04 $ 0.13 Offshore Africa $ 0.59 $ 0.57 $ 0.62 Natural gas average $ 0.08 $ 0.05 $ 0.13 Average ($/BOE) (1) $ 6.90 $ 8.96 $ 7.77 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 production, capital, and abandonment costs incurred. North America crude oil and NGLs and natural gas royalties for 2025 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 17% of product sales for 2025 compared with 20% of product sales for 2024 (2023 - 18%). The decrease in royalty rates for 2025 from 2024 primarily reflected lower benchmark pricing and the impact of sliding scale royalty rates. Natural gas royalty rates averaged approximately 3% of product sales for 2025 compared with 2% of product sales for 2024 (2023 - 4%). The increase in royalty rates for 2025 from 2024 primarily reflected higher prevailing benchmark pricing. 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 4% for 2025 compared with 5% of product sales for 2024 (2023 - 9%). 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 2025 2024 2023 Crude oil and NGLs ($/bbl) (1) North America $ 12.19 $ 12.55 $ 14.46 International average $ 103.48 $ 62.99 $ 48.16 North Sea $ 136.47 $ 103.28 $ 85.57 Offshore Africa $ 36.73 $ 21.77 $ 21.14 Crude oil and NGLs average $ 14.33 $ 14.72 $ 16.12 Natural gas ($/Mcf) (1) North America $ 1.11 $ 1.19 $ 1.27 International average $ 9.23 $ 6.51 $ 7.26 North Sea $ 12.18 $ 8.95 $ 9.85 Offshore Africa $ 7.80 $ 5.98 $ 6.83 Natural gas average $ 1.14 $ 1.22 $ 1.30 Average ($/BOE) (1) $ 11.18 $ 11.73 $ 12.74 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. Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. North America North America crude oil and NGLs production expense for 2025 averaged $12.19 per bbl, comparable with $12.55 per bbl for 2024 (2023 - $14.46 per bbl). North America natural gas production expense for 2025 averaged $1.11 per Mcf, a decrease of 7% from $1.19 per Mcf for 2024 (2023 - $1.27 per Mcf). The decrease in natural gas production expense per Mcf for 2025 from 2024 primarily reflected higher production volumes. International International crude oil and NGLs production expense for 2025 averaged $103.48 per bbl, an increase of 64% from $62.99 per bbl for 2024 (2023 - $48.16 per bbl). The increase in crude oil and NGLs production expense per bbl for 2025 from 2024 primarily reflected activities at Ninian in the pre-cessation period, the timing of liftings from various fields that have different cost structures, and the impact of foreign exchange. ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) 2025 2024 2023 North America $ 4,582 $ 3,831 $ 3,679 North Sea 1,573 279 494 Offshore Africa 432 297 213 Depletion, depreciation and amortization $ 6,587 $ 4,407 $ 4,386 Less: Recoverability charges (1) 1,777 222 436 Adjusted depletion, depreciation and amortization (2) $ 4,810 $ 4,185 $ 3,950 $/BOE (3) $ 13.07 $ 12.92 $ 12.27 During 2024, in connection with the Company's notice of withdrawal from Block 11B/12B in South Africa, the Company derecognized $62 million of exploration and evaluation assets through depletion, depreciation and amortization expense. This is a non-GAAP financial measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production. It may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements (depletion, depreciation and amortization expense), as an indication of the Company's performance. This is a non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. Adjusted depletion, depreciation and amortization expense for 2025 of $13.07 per BOE was comparable with $12.92 per BOE for 2024 (2023 - $12.27 per BOE). International Matters - North Sea and Offshore Africa Pre-tax recoverability charges of $1,777 million in 2025 reflect the acceleration of the Company's abandonment and decommissioning activities and revisions to cost estimates in the North Sea, together with strategic decisions to not pursue an extension of its Production Sharing Contract ("PSC") for the Espoir Field, Block CI - 26, in Offshore Africa and to not pursue development of Kossipo in Offshore Africa. In the North Sea, following a competitive tender for the Ninian South Platform, estimated abandonment costs were higher than originally budgeted. Accordingly, the Company updated its abandonment and decommissioning cost estimates for the Ninian Central and South Platforms and T - Block (Tiffany, Toni and Thelma fields). Additionally, based on current and forecasted economic conditions, including commodity prices and market egress, the Company determined that the T - Block assets were no longer economically viable. Cessation of production has been accelerated to the first quarter of 2027 and associated crude oil reserves were de-booked. As a result, the Company recognized a non - cash charge of $836 million (2024 - $21 million; 2023 - $113 million), comprised of a recoverability charge recognized in depletion, depreciation and amortization expense of $1,462 million (2024 - $160 million; 2023 - $436 million), net of deferred tax recoveries of $626 million (2024 - $139 million; 2023 - $323 million). In Offshore Africa, the Company determined that it would not pursue an extension of its PSC for the Espoir Field, Block CI - 26, and de-booked associated crude oil reserves. The Company is working with the Government of Côte d'Ivoire to facilitate the transition of operatorship in the second half of 2026. As a result, the Company recognized a non-cash recoverability charge of $269 million as at December 31, 2025. Additionally, the Company decided not to pursue development of Kossipo, and recognized a recoverability charge of $46 million related to the derecognition of its exploration and evaluation assets. Estimates of asset retirement obligations and related tax recoveries remain subject to revision as abandonment activities progress. Recoverability charges are recognized in depletion, depreciation and amortization expense. ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) 2025 2024 2023 North America $ 221 $ 231 $ 234 North Sea 64 65 46 Offshore Africa 9 9 8 Asset retirement obligation accretion $ 294 $ 305 $ 288 $/BOE (1) $ 0.80 $ 0.94 $ 0.89 (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 2025 of $0.80 per BOE decreased 15% from $0.94 per BOE for 2024 (2023 - $0.89 per BOE). The decrease in asset retirement obligation accretion expense per BOE for 2025 from 2024 reflected the impact of changes in discount rates at December 31, 2024, combined with higher sales volumes in 2025, partially offset by revisions in cost and timing estimates at December 31, 2024, North America acquisitions completed during 2025, and North Sea cost and timing estimate revisions during 2025. Oil Sands Mining and Upgrading OPERATING HIGHLIGHTS The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. Record SCO production averaged 565,102 bbl/d in 2025, reflecting the acquisition completed in December 2024, combined with strong utilization . Additionally, the Company successfully completed the AOSP asset swap with Shell during the fourth quarter of 2025. REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION - OIL SANDS MINING AND UPGRADING ($/bbl) 2025 2024 2023 Realized SCO sales price (1) $ 86.41 $ 98.03 $ 100.06 Bitumen value for royalty purposes (2) $ 66.23 $ 72.68 $ 65.43 Bitumen royalties (3) $ 13.84 $ 17.23 $ 14.43 Transportation (4) $ 3.31 $ 2.91 $ 1.89 Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A. Calculated as the annual average of the bitumen methodology price. Calculated as royalties divided by sales volumes. Calculated as transportation expense divided by sales volumes. The realized SCO sales price averaged $86.41 per bbl for 2025, a decrease of 12% from $98.03 per bbl for 2024 (2023 - $100.06 per bbl). The decrease in realized SCO sales price per bbl for 2025 from 2024 primarily reflected lower WTI benchmark pricing. Bitumen royalties averaged $13.84 per bbl for 2025, a decrease from $17.23 per bbl for 2024 (2023 - $14.43 per bbl) primarily reflecting the decrease in average bitumen value for royalty purposes and the impact of royalty true-ups. Transportation expense averaged $3.31 per bbl for 2025, an increase of 14% from $2.91 per bbl for 2024 (2023 - $1.89 per bbl). The increase in transportation expense per bbl for 2025 from 2024 primarily reflected higher volumes shipped on the TMX pipeline in 2025. PRODUCTION EXPENSE - OIL SANDS MINING AND UPGRADING The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 21 to the Company's audited consolidated financial statements. ($ millions) 2025 2024 2023 Production expense, excluding natural gas costs $ 4,543 $ 3,801 $ 3,794 Natural gas costs 150 120 195 Production expense $ 4,693 $ 3,921 $ 3,989 ($/bbl) 2025 2024 2023 Production expense, excluding natural gas costs (1) $ 21.94 $ 22.18 $ 23.13 Natural gas costs (2) 0.72 0.70 1.19 Production expense (3) $ 22.66 $ 22.88 $ 24.32 Sales volumes (bbl/d) 567,335 468,280 449,282 Calculated as production expense, excluding natural gas costs, divided by sales volumes. Calculated as natural gas costs divided by sales volumes. Calculated as production expense divided by sales volumes. Production expense for 2025 of $22.66 per bbl was comparable with $22.88 per bbl for 2024 (2023 - $24.32 per bbl). DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) 2025 2024 2023 Depletion, depreciation and amortization $ 2,780 $ 2,258 $ 2,011 $/bbl (1) $ 13.42 $ 13.17 $ 12.26 (1) Calculated as depletion, depreciation and amortization divided by sales volumes. Depletion, depreciation and amortization expense for 2025 of $13.42 per bbl was comparable with $13.17 per bbl for 2024 (2023 - $12.26 per bbl). ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) 2025 2024 2023 Asset retirement obligation accretion $ 86 $ 84 $ 78 $/bbl (1) $ 0.42 $ 0.49 $ 0.48 (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 2025 of $0.42 per bbl decreased 14% from $0.49 per bbl for 2024 (2023 - $0.48 per bbl). The decrease in asset retirement obligation accretion expense per bbl for 2025 from 2024 primarily reflected the impact of higher sales volumes. Midstream and Refining ($ millions) 2025 2024 2023 Product sales Midstream activities $ 91 $ 82 $ 76 NWRP, refined product sales and other 670 813 926 Segmented revenue Less: 761 895 1,002 NWRP, refining toll 262 295 303 Midstream activities 22 20 29 Production expense 284 315 332 NWRP, feedstock costs 503 669 646 Transportation expenses 42 16 18 Depreciation 17 16 16 Segmented loss $ (85) $ (121) $ (10) 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 is transported through its fully owned and operated Pelican ...

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