Canadian Natural's President, Scott Stauth, commented on the Company's Q1/25 results, "We have a long track record of being an industry leading effective and efficient producer while consistently delivering top tier operational and financial performance. All our employees are shareholders, with a strong focus on continuous improvement, consistently driving strong results. In Q1/25 we achieved record quarterly production of approximately 1,582,000 BOE/d, which included record quarterly liquids production of approximately 1,174,000 bbl/d, 79% of which was long life low decline production and record quarterly natural gas production of 2,451 MMcf/d.

At our world class Oil Sands Mining and Upgrading assets, we achieved record quarterly Synthetic Crude Oil (”SCO”) production of approximately 595,000 bbl/d resulting from a high utilization rate of 106% in Q1/25, anchored by industry leading SCO operating costs of $21.88/bbl (US$15.25/bbl), which drove significant free cash flow in the quarter. Importantly, in 2024 our annual Oil Sands Mining and Upgrading operating costs were in the range of $7.00/bbl to $10.00/bbl lower than our peer average. This equates to incremental annual margin of approximately $1.2 billion to $1.7 billion, based on our 2024 annual production.

Following our first few months of operating the Duvernay assets acquired in December 2024 we are achieving strong production results and cost reductions. We are confident we will add more value than we planned for at the time of the acquisition. This is made possible through our commitment to continuous improvement and a strong team culture that focuses on improving our already top tier operating costs, driving execution of organic growth opportunities and maximizing value to shareholders.

Canadian Natural's constant focus on continuous improvement has resulted in capturing cost efficiencies throughout our operations year to date. As a result of these efficiencies, we are in a position to reduce our 2025 capital budget by $100 million, resulting in an updated total capital forecast of $6.05 billion, excluding abandonment expenditures. This reduction in our 2025 capital will have no impact on our planned operating activities or targeted production levels for 2025."

Canadian Natural's Chief Financial Officer, Victor Darel, added "In Q1/25, we achieved strong financial results, including adjusted net earnings of $2.4 billion or $1.16 per share and adjusted funds flow of $4.5 billion, or $2.16 per share. We returned approximately $1.7 billion to our shareholders in Q1/25, including $1.2 billion in dividends and $0.5 billion in share repurchases. At the same time we strengthened our balance sheet by reducing net debt in the quarter by approximately $1.4 billion from December 31, 2024 levels.

We are committed to maximizing shareholder value and increasing sustainable returns to shareholders. As previously announced, in March 2025 the Board of Directors approved a 4% increase to our quarterly dividend to $0.5875 per common share or $2.35 per common share annualized, with 2025 being the 25th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 21% over that time.

Our business model is robust and sustainable as our top tier US$ WTI breakeven, defined as the adjusted funds flow required to cover maintenance capital and dividends, remains in the low to mid-US$40 per barrel range. Our balance sheet is already very strong and we improved it further by reducing net debt by approximately $1.4 billion in Q1/25, as mentioned above, and maintained liquidity of approximately $5.1 billion as at March 31, 2025, providing significant flexibility.

Our leading financial results combined with our top tier, safe, reliable, effective and efficient operations provide us with unique competitive advantages, all of which drive material free cash flow generation and strong returns on capital."

(1)Per common share and dividend amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of the Company's MD&A and in the financial statements for the three months ended March 31, 2025 dated May 7, 2025.

(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025 dated May 7, 2025.

(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025 dated May 7, 2025.

(4)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025 dated May 7, 2025.

(5)Excludes net acquisition costs of $9,058 million for the three months ended December 31, 2024 related to the acquisition of assets in the period.

(6)A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

▪The strength of Canadian Natural's long life low decline asset base, supported by safe, effective and efficient operations, makes our business unique, robust and sustainable. In Q1/25, the Company generated strong financial results, including:

•Net earnings of approximately $2.5 billion and adjusted net earnings from operations of approximately $2.4 billion.

•Cash flows from operating activities of approximately $4.3 billion.

•Adjusted funds flow of approximately $4.5 billion.

▪Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $5.1 billion in liquidity(1) as at March 31, 2025.

•In Q1/25, the Company completed the following:

◦Repaid US$600 million of 3.90% US dollar debt securities due February 2025.

◦Extended its $500 million revolving credit facility originally maturing February 2026 to June 2027.

(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the Company's MD&A for the three months ended March 31, 2025 dated May 7, 2025.

▪Canadian Natural continues to focus on safe, effective and efficient operations delivering record quarterly average production in Q1/25 of 1,582,348 BOE/d, consisting of record total liquids production of 1,173,804 bbl/d and record natural gas production of 2,451 MMcf/d.

•Canadian Natural's world class Oil Sands Mining and Upgrading assets delivered record quarterly production of 595,116 bbl/d of SCO in Q1/25, an increase of 34% or approximately 150,000 bbl/d from Q1/24 levels.

◦Gross production of approximately 630,000 bbl/d in Q1/25, with upgrader utilization of 106%, was the highest quarterly Oil Sands Mining and Upgrading gross production in the Company's history, achieved through successes from the recently completed Reliability Enhancement Project and Scotford Upgrader debottleneck work, driving strong performance.

–When comparing utilization over the last 5 years Canadian Natural’s was approximately 8% higher versus a comparable peer average. This equates to approximately 40,000 bbl/d of incremental annual production based on 2024 capacity.

–Industry leading quarterly Oil Sands Mining and Upgrading operating costs of $21.88/bbl (US$15.25/bbl) of SCO were achieved in Q1/25, a decrease of 12% from Q1/24 levels.

–Canadian Natural's high value SCO represented approximately 51% of the Company's total liquids volumes in Q1/25 and captured strong quarterly realized SCO pricing of $95.52/bbl, generating significant free cash flow.

◦Thermal in situ quarterly production averaged 284,706 bbl/d in Q1/25, an increase of 6% or approximately 16,500 bbl/d from Q1/24 levels as a result of the Company's capital efficient thermal pad add development program. Results have been strong from the two Cyclic Steam Stimulation ("CSS") pads that came on production ahead of schedule at Primrose in Q4/24 and Q1/25.

–Quarterly thermal in situ operating costs were strong, averaging $11.23/bbl (US$7.83/bbl) in Q1/25, a decrease of 20% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.

•On the recently acquired Duvernay assets, Canadian Natural's effective and efficient operations, area synergies and expertise in similar plays, such as the Montney, have resulted in both capital and operating cost efficiencies. Additionally, we are on track to achieve 2025 budget production of approximately 60,000 BOE/d.

◦By optimizing well length and completions design combined with top tier execution, we are drilling longer wells with improved reservoir access at lower costs. On a length normalized basis, combined drilling and completion costs for 2025 are targeting an improvement of approximately 14% or $1.8 million per well compared to 2024 costs.

◦The Company is targeting to drill 43 gross wells in the Duvernay as part of the 2025 capital development program.

◦Operating costs in Q1/25 were strong, averaging approximately $9.52/BOE.

▪Canadian Natural has a strong history of growing its sustainable dividend with 2025 being the 25th consecutive year of dividend increases with a CAGR of 21% over that time.

•Returns to shareholders in Q1/25 were strong, totaling approximately $1.7 billion, comprised of $1.2 billion of dividends and $0.5 billion through the repurchase and cancellation of approximately 11.2 million common shares at a weighted average price of $43.66 per share.

•Year to date in 2025, up to and including May 7, 2025, the Company has returned a total of approximately $3.1 billion directly to shareholders through $2.4 billion in dividends and $0.7 billion through the repurchase and cancellation of approximately 15.8 million common shares.

•Subsequent to quarter end, Canadian Natural declared a quarterly cash dividend on its common shares of $0.5875 per common share. The quarterly dividend will be payable on July 3, 2025 to shareholders of record at the close of business on June 13, 2025.

◦As previously announced, on March 6, 2025 the Board of Directors increased the quarterly dividend by 4% to $0.5875 per common share. This demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO (herein collectively referred to as "crude oil") and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company’s shareholders.

Underpinning this asset base is the Company's long life low decline production, representing approximately 77% of total budgeted liquids production in 2025, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of the Company's long life low decline production comes from its top tier thermal in situ oil sands operations and Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.

In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for our shareholders. Supporting these projects is the Company’s undeveloped landbase which enables large, repeatable drilling programs that can be optimized over time. Additionally, Canadian Natural maximizes long-term value by maintaining high ownership and operatorship of its assets, allowing the Company to control the nature, timing and extent of development. Low capital exposure projects can be stopped or started relatively quickly depending upon success, market conditions or corporate needs.

Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.

(1)Includes bitumen wells.

▪Canadian Natural drilled a total of 94 net crude oil and natural gas producer wells in Q1/25, 17 more than in Q1/24.

▪North America E&P liquids production, excluding thermal in situ, averaged 276,532 bbl/d in Q1/25, a 16% increase from Q1/24 levels, reflecting production volumes from the Duvernay assets acquired in December 2024, along with strong organic growth from our liquids-rich natural gas and primary heavy crude oil assets.

•Primary heavy crude oil production averaged 85,604 bbl/d in Q1/25, a 9% increase from Q1/24 levels, reflecting strong drilling results from the Company's multilateral wells, partially offset by natural field declines.

◦Continuing to build on the Company's highly successful multilateral drilling program, Canadian Natural targets to drill 156 net primary heavy crude oil multilateral wells in 2025.

◦Operating costs in the Company's primary heavy crude oil operations averaged $18.13/bbl (US$12.63/bbl) in Q1/25, a decrease of 5% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.

•Pelican Lake production averaged 43,175 bbl/d in Q1/25 a decrease of 4% from Q1/24 levels, reflecting low natural field declines from this long life low decline asset.

◦Operating costs at Pelican Lake averaged $9.77/bbl (US$6.81/bbl) in Q1/25, comparable to Q1/24 levels.

•North America light crude oil and NGLs production averaged 147,753 bbl/d in Q1/25, an increase of 30% or approximately 34,000 bbl/d compared to Q1/24 levels, primarily driven by the recently acquired Duvernay assets and strong drilling results in our liquids-rich natural gas assets.

◦Operating costs in the Company's North America light crude oil and NGLs operations averaged $13.15/bbl (US$9.16/bbl) in Q1/25, a decrease of 14% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.

▪North America natural gas production averaged 2,436 MMcf/d in Q1/25, an increase of 14% from Q1/24 levels, driven by the recently acquired Duvernay assets and strong drilling results in the Company's liquids-rich natural gas assets. The Company remains focused on delivering strong returns on organic growth with our liquids-rich natural gas activity in the Duvernay, Montney and Deep Basin.

•North America natural gas operating costs averaged $1.16/Mcf in Q1/25, a decrease of 9% from Q1/24 levels, primarily reflecting higher production volumes.

▪Thermal in situ production averaged 284,706 bbl/d in Q1/25, an increase of 6% or approximately 16,500 bbl/d from Q1/24 levels as a result of the Company's capital efficient thermal pad add development program. Results have been strong from the two CSS pads that came on production ahead of schedule at Primrose in Q4/24 and Q1/25.

•Quarterly thermal in situ operating costs were strong, averaging $11.23/bbl (US$7.83/bbl) in Q1/25, a decrease of 20% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.

▪Canadian Natural has significant thermal in situ facility processing capacity of approximately 340,000 bbl/d, resulting in 70,000 bbl/d of available capacity. The Company has decades of strong capital efficient drill to fill growth opportunities on its long life low decline thermal in situ assets, which we continue to develop in a disciplined manner to deliver safe and reliable thermal in situ production.

•At Primrose, following strong results from the recently drilled CSS pads, the Company is planning to reallocate a portion of pad add capital in 2025 to Primrose from Kirby to maximize returns. The Company now targets to drill a CSS pad in Q4/25 with production targeted to come on in 2026.

•At Jackfish, the Company finished drilling a SAGD pad in Q4/24, with production targeted to come on in Q3/25.

•At Pike, the Company has completed drilling one SAGD pad and is currently drilling a second SAGD pad, both of which will be tied into existing Jackfish facilities. These two pads are targeted to come on production in 2026 and keep the Jackfish plants at full capacity.

•At Kirby, the Company recently finished drilling a SAGD pad which is targeted to come on production in Q4/25.

▪Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production while reducing the Steam to Oil Ratio ("SOR") and optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.

•At the Company's commercial scale solvent SAGD pad at Kirby North, we began solvent injection in June 2024 and solvent recoveries continue to meet expectations, exceeding 80%. Pad performance monitoring has identified several well pair workover opportunities to further enhance SORs, solvent recovery and production trends. These workovers are targeted to be completed in Q2/25 with continued monitoring over the second half of 2025.

•At Primrose, the Company is continuing to operate its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate this commercial development opportunity.

(1)SCO production before royalties and excludes production volumes consumed internally as diesel.

(2)Consists of heavy and light synthetic crude oil products.

▪Oil Sands Mining and Upgrading continues to outperform expectations, through our relentless focus on continuous improvement combined with strong performance from the completed Reliability Enhancement Project at Horizon and Debottleneck Project at the Scotford Upgrader. As a result, the Company achieved strong operational results in Q1/25 as follows:

•Record quarterly production of 595,116 bbl/d of SCO was achieved in Q1/25, an increase of 34% or approximately 150,000 bbl/d from Q1/24 levels, reflecting strong operating results, the acquisition of an additional 20% working interest in AOSP in December 2024, and planned and unplanned maintenance a year earlier in Q1/24.

◦Gross production of approximately 630,000 bbl/d in Q1/25, with upgrader utilization of 106%, was the highest quarterly Oil Sands Mining and Upgrading gross production in the Company's history, as a result of continuous improvement initiatives resulting in strong performance.

◦Industry leading Oil Sands Mining and Upgrading operating costs of $21.88/bbl (US$15.25/bbl) of SCO were achieved in Q1/25, a decrease of 12% from Q1/24 levels. The decrease in operating costs in Q1/25 compared to Q1/24 was due primarily to higher production volumes and lower energy costs.

◦Canadian Natural's high value SCO represented approximately 51% of the Company's total liquids volumes in Q1/25 and captured strong quarterly realized SCO pricing of $95.52/bbl, generating significant free cash flow.

▪As previously announced, the planned AOSP turnaround began on April 4, 2025 and is targeted for 73 days. During this turnaround, the Scotford Upgrader will operate at reduced rates, impacting net annual average production by approximately 31,000 bbl/d, based on Canadian Natural's current 90% working interest.

▪At Horizon, the Company completed the Reliability Enhancement Project in 2024 which increased the capacity of the zero decline, high value SCO production at Horizon to 264,000 bbl/d over a two year timeframe by shifting the planned turnarounds to once every two years from the previous annual cycle. As a result, 2025 will be the first year without a planned turnaround, resulting in high targeted utilization at Horizon.

•With additional infrastructure in place following the completion of this project, the Company can perform certain maintenance activities with zero production impact. Capital savings are targeted to be approximately $75 million in 2025 from 2024 levels as a result of no planned turnaround impacting production.

▪At Horizon, the Company is progressing its Naphtha Recovery Unit Tailings Treatment ("NRUTT") project which targets incremental production of approximately 6,300 bbl/d of SCO following mechanical completion in Q3/27.

▪International E&P crude oil production volumes averaged 17,450 bbl/d in Q1/25, a decrease of 30% compared to Q1/24 levels primarily reflecting suspended production at Baobab in Offshore Africa due to the planned life extension project on its floating production storage and offloading vessel which commenced in January 2025, which is targeted to impact 2025 net annual production by approximately 7,800 bbl/d, combined with natural field declines. Production at Baobab is targeted to resume in Q2/26.

(1)West Texas Intermediate ("WTI"); Western Canadian Select ("WCS"); Synthetic Crude Oil ("SCO").

(2)Exploration & Production crude oil and NGLs average realized price excludes SCO.

(3)Pricing is net of blending and feedstock costs.

(4)Excludes risk management activities.

(5)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025 dated May 7, 2025.

▪Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, bitumen and SCO.

▪WTI prices averaged US$71.42/bbl in Q1/25, comparable to Q4/24 and a decrease of US$5.55/bbl compared to Q1/24 levels. The decrease compared to Q1/24 reflected weaker global demand growth outlooks amid escalating trade tensions, combined with concerns of supply growth from non-OPEC+ producers.

▪SCO pricing averaged US$69.07/bbl in Q1/25, representing a US$2.35/bbl discount to WTI pricing, compared to a US$0.86/bbl premium to WTI in Q4/24 and a US$7.54 discount to WTI in Q1/24. The SCO differential weakened in Q1/25 relative to Q4/24, driven in part by production levels in the Western Canadian Sedimentary Basin ("WCSB").

▪The WCS differential to WTI averaged US$12.66/bbl in Q1/25, comparable to Q4/24 and a US$6.68/bbl improvement compared to the US$19.34/bbl discount in Q1/24. The narrowing of the WCS differential to WTI in Q1/25 compared to Q1/24 primarily reflects the start-up of the TMX pipeline in Q2/24, combined with stronger United States Gulf Coast ("USGC") heavy oil pricing.

▪The North West Redwater refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 83,863 bbl/d in Q1/25.

▪Canadian Natural has total contracted crude oil transportation capacity of 256,500 bbl/d, with committed volumes to Canada’s west coast and to the USGC of approximately 23% of 2025 budgeted liquids production. The egress supports Canadian Natural’s long-term sales strategy by targeting expanded refining markets, driving stronger netbacks while also reducing exposure to egress constraints.

•The Company has total committed capacity on the TMX pipeline of 169,000 bbl/d providing access to markets on Canada's west coast.

•Canadian Natural has total committed capacity of 77,500 bbl/d on the Flanagan South pipeline and an additional 10,000 bbl/d of committed capacity on the Keystone Base pipeline, diversifying the Company's heavy oil access to the USGC.

▪AECO natural gas prices averaged $1.92/GJ in Q1/25, a $0.54/GJ improvement compared to Q4/24 and comparable to Q1/24. The increase in AECO natural gas pricing compared to Q4/24 primarily reflects stronger NYMEX benchmark pricing, combined with increased exports out of the WCSB. Stronger AECO pricing in Q1/25 also reflects the anticipated start-up of LNG Canada targeted for the second half of 2025.

•In 2025, the Company is targeting to use the equivalent of approximately 33% of budgeted natural gas production in its operations, with approximately 35% targeted to be sold at AECO/Station 2 pricing, and approximately 32% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value from its diversified natural gas marketing portfolio.

•As a result of Canadian Natural's diversified natural gas marketing strategy, the Company's Q1/25 realized natural gas price of $3.13/Mcf represents a $1.07/Mcf or 52% premium over the AECO benchmark price of $2.06/Mcf.

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this document and the Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; 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 the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of conflicts in the Middle East, and in Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; changes and uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes and key trade agreements (including tariffs on certain goods announced by the US government and Canadian countermeasures subsequently announced, both of which are anticipated to evolve and may be continued, suspended, increased, decreased, or imposed on additional goods); uncertainty in the regulatory framework governing greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps; 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; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this document or the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this document or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company’s estimates or opinions change.

This document should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") and MD&A for the three months ended March 31, 2025 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2024. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements and MD&A for the three months ended March 31, 2025 have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout this document on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this document, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2024, is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Information in such Annual Information Form and on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A, dated May 7, 2025.

This document includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the Company's financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company’s non-GAAP and other financial measures included in this document, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months March 31, 2025, dated May 7, 2025.

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 management as required.

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 three months ended March 31, 2025 is shown below:

(1)Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025, dated May 7, 2025.

(2)Net Capital expenditures is a Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025, dated May 7, 2025.

(3)Excludes net acquisition costs of $9,058 million for the three months ended December 31, 2024 related to the acquisition of assets in the period.

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.

The breakeven WTI price is a supplementary financial measure that represents the equivalent US dollar WTI price per barrel where the Company's adjusted funds flow is equal to the sum of maintenance capital and dividends. The Company considers the breakeven WTI price a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. The breakeven WTI price incorporates the non-GAAP financial measure adjusted funds flow as reconciled in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. Maintenance capital is a supplementary financial measure that represents the capital required to maintain annual production at prior period levels.

Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and includes acquisition capital related to a number of acquisitions for which agreements between parties have been reached as at the time of the Company's 2025 budget press release on January 9, 2025. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.

The 2025 capital budget reflects budgeted net capital expenditures, before 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 budgeted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries. Current tax recoveries are refundable at a rate of approximately 23% in Canada and a combined current income tax and Petroleum Revenue Tax ("PRT") rate approximating 70% to 75% in the UK portion of the North Sea. The Company is eligible to recover interest on refunded PRT previously paid.

Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($/bbl/d or $/BOE/d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.

Canadian Natural Resources Limited (TSX-CNQ / NYSE-CNQ) will be issuing its 2025 First Quarter Earnings Results on Thursday, May 8, 2025 before market open.

A conference call will be held at 7:00 a.m. MDT / 9:00 a.m. EDT on Thursday, May 8, 2025.

North America 1-800-717-1738 / International 001-289-514-5100.

Access the audio webcast on the home page of our website, www.cnrl.com.

North America 1-888-660-6264 / International 001-289-819-1325 (Passcode: 62718#)

Canadian Natural is a senior crude oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; 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 the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of conflicts in the Middle East and in Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; changes and uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes and key trade agreements (including tariffs on certain goods announced by the US government and Canadian countermeasures subsequently announced, both of which are anticipated to evolve and may be continued, suspended, increased, decreased, or imposed on additional goods); uncertainty in the regulatory framework governing greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps; 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; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium-, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

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.

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.

This MD&A should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three months ended March 31, 2025, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2024. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three months ended March 31, 2025 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout this MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf: 1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf: 1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf: 1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.

The following discussion and analysis refers primarily to the Company's financial results for the three months ended March 31, 2025 in relation to the first quarter of 2024 and the fourth quarter of 2024. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2024, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information in such Annual Information Form and on the Company's website does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated May 7, 2025.

FINANCIAL HIGHLIGHTS(1)

(1)Further details related to product sales are disclosed in note 15 to the financial statements.

(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(4)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Net earnings for the first quarter of 2025 were $2,458 million compared with $987 million for the first quarter of 2024 and $1,138 million for the fourth quarter of 2024. Net earnings for the first quarter of 2025 included non-operating income, net of tax, of $22 million compared with non-operating losses of $487 million for the first quarter of 2024 and non-operating losses of $839 million for the fourth quarter of 2024 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain from investments, and a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian field in the North Sea in the fourth quarter of 2024. Excluding these items, adjusted net earnings from operations for the first quarter of 2025 were $2,436 million compared with $1,474 million for the first quarter of 2024 and $1,977 million for the fourth quarter of 2024.

The increase in net earnings and adjusted net earnings from operations for the first quarter of 2025 from the first quarter of 2024 primarily reflected:

▪higher sales volumes and realized SCO sales price(2) in the Oil Sands Mining and Upgrading segment; and

▪higher crude oil and NGLs sales volumes and realized pricing(2) in the North America Exploration and Production segment.

The increase in net earnings and adjusted net earnings from operations for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected:

▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and

▪higher realized crude oil and NGLs pricing and realized natural gas pricing in the North America Exploration and Production segment.

(1)Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of this MD&A and in note 1 to the financial statements.

(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

The impacts of depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchange (gain) loss, and the gain from investments also contributed to fluctuations in net earnings from the comparable periods. These items are discussed in detail in the relevant sections of this MD&A.

Cash flows from operating activities for the first quarter of 2025 were $4,284 million compared with $2,868 million for the first quarter of 2024, and $3,432 million for the fourth quarter of 2024. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.

Adjusted funds flow for the first quarter of 2025 was $4,530 million compared with $3,138 million for the first quarter of 2024, and $4,186 million for the fourth quarter of 2024. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above related to the fluctuations in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, and movements in other long-term assets, including the unamortized cost of contributions to the Company's employee bonus program, accrued interest on Petroleum Revenue Tax ("PRT") recoveries, and prepaid cost of service tolls.

Crude oil and NGLs production before royalties for the first quarter of 2025 of 1,173,804 bbl/d increased 20% from 975,668 bbl/d for the first quarter of 2024 and increased 8% from 1,090,002 bbl/d for the fourth quarter of 2024. Natural gas production before royalties for the first quarter of 2025 of 2,451 MMcf/d increased 14% from 2,147 MMcf/d for the first quarter of 2024 and increased 7% from 2,283 MMcf/d for the fourth quarter of 2024. Total production before royalties for the first quarter of 2025 of 1,582,348 BOE/d increased 19% from 1,333,502 BOE/d for the first quarter of 2024 and increased 8% from 1,470,428 BOE/d for the fourth quarter of 2024. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.

In the Company's Exploration and Production segments, realized crude oil and NGLs prices averaged $79.85 per bbl for the first quarter of 2025, an increase of 14% from $70.01 per bbl for the first quarter of 2024 and an increase of 6% from $75.22 per bbl for the fourth quarter of 2024. The realized natural gas price increased 23% to average $3.13 per Mcf for the first quarter of 2025 from $2.55 per Mcf for the first quarter of 2024 and increased 55% from $2.02 per Mcf for the fourth quarter of 2024. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price increased 8% to average $95.52 per bbl for the first quarter of 2025 from $88.84 per bbl for the first quarter of 2024 and was comparable with $95.08 per bbl for the fourth quarter of 2024. 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", "Realized Product Prices – Exploration and Production", and the "Oil Sands Mining and Upgrading" sections of this MD&A.

In the Company's Exploration and Production segments, crude oil and NGLs production expense(1) averaged $15.74 per bbl for the first quarter of 2025, a decrease of 6% from $16.66 per bbl for the first quarter of 2024 and an increase of 20% from $13.15 per bbl for the fourth quarter of 2024. Natural gas production expense(1) averaged $1.20 per Mcf for the first quarter of 2025, a decrease of 8% from $1.30 per Mcf for the first quarter of 2024 and an increase of 7% from $1.12 per Mcf for the fourth quarter of 2024. In the Oil Sands Mining and Upgrading segment, production expense(1) averaged $21.88 per bbl for the first quarter of 2025, a decrease of 12% from $24.85 per bbl for the first quarter of 2024 and an increase of 4% from $20.97 per bbl for the fourth quarter of 2024. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.

(1)Calculated as respective production expense divided by respective sales volumes.

The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:

(1)Further details related to product sales for the three months ended March 31, 2025 and 2024 are disclosed in note 15 to the financial statements.

(2)Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of this MD&A and in note 1 to the 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 and in Ukraine, and economic impacts of escalating trade tensions) 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 the second quarter of 2024, the impact of the Western Canadian Select ("WCS") Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America, and the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the International segments.

▪Natural gas pricing – Fluctuations in both the demand for natural gas and inventory storage levels, the impact of third-party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, and the impact of shale gas production in the US.

▪Crude oil and NGLs sales volumes – Fluctuations in production from Kirby and Jackfish, fluctuations in production due to the cyclic nature of Primrose, fluctuations in the Company's drilling program in the North America Exploration and Production segment, natural field decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, the impact and timing of acquisitions, including the acquisition of working interests in AOSP and Duvernay assets in the fourth quarter of 2024, wildfires, and a third-party pipeline outage in 2023 in the North America Exploration and Production segment. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments.

▪Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, the impact and timing of acquisitions, including the acquisition of a working interest in the Duvernay assets in the fourth quarter of 2024, natural field decline rates, the impact of seasonal conditions, wildfires, and a third-party pipeline outage in 2023 in the North America Exploration and Production segment.

▪Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, increased carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.

▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes, 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 and pitstops in the Oil Sands Mining and Upgrading segment, a recoverability charge at December 31, 2024 and December 31, 2023 relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea, and a recoverability charge at June 30, 2024 relating to the notice to withdraw from Block 11B/12B in South 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 the impact of movements in benchmark interest rates on outstanding floating rate long-term debt and accrued interest on PRT 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.

Global crude oil benchmark pricing remained stable throughout the first quarter of 2025. However, mounting concerns over global crude oil demand growth outlooks and higher supply, fuelled by escalating trade tensions and an increased risk of an economic downturn, impacted pricing at the outset of the second quarter. Natural gas benchmark pricing recovered in the first quarter of 2025 following cold weather conditions in the US, increasing heating demand and storage draws. In Canada, the anticipated start-up of LNG Canada in the third quarter of 2025 will provide additional market egress and is expected to support AECO benchmark pricing.

In the first quarter of 2025, the US government announced tariffs on certain Canadian goods with countermeasures subsequently announced by the Canadian government. These trade measures have created market volatility which may continue to affect pricing received for the Company's products, increase the cost or reduce the availability of products in the Company's supply chain, and introduce additional foreign currency volatility. As of the date of this MD&A, the duration and impact of these trade actions remains uncertain, and tariffs are anticipated to evolve. The Company will continue to assess the impacts of any proposed or implemented tariffs on its business, financial condition and results.

As at March 31, 2025, the Company had undrawn revolving bank credit facilities of $4,965 million. Including cash and cash equivalents, the Company had approximately $5,058 million in liquidity(1). The Company also has certain other dedicated credit facilities supporting letters of credit. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity, and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.

(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Substantially all of the Company's production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company’s realized prices are directly impacted by fluctuations in foreign exchange rates resulting in product revenues being impacted by changes in Canadian dollar sales prices relative to the US dollar benchmark prices.

Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$71.42 per bbl for the first quarter of 2025, a decrease of 7% from US$76.97 per bbl for the first quarter of 2024 and comparable with US$70.27 per bbl for the fourth quarter of 2024.

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$75.68 per bbl for the first quarter of 2025, a decrease of 9% from US$83.23 per bbl for the first quarter of 2024 and comparable with US$74.69 per bbl for the fourth quarter of 2024.

The decrease in WTI and Brent benchmark pricing for the first quarter of 2025 from the first quarter of 2024 reflected weaker global demand growth outlooks amid escalating trade tensions, combined with concerns of supply growth from non-OPEC+ producers.

The WCS Heavy Differential averaged US$12.66 per bbl for the first quarter of 2025, compared with US$19.34 per bbl for the first quarter of 2024 and US$12.55 per bbl for the fourth quarter of 2024. The narrowing of the WCS Heavy Differential for the first quarter of 2025 from the first quarter of 2024 primarily reflected the start-up of the TMX pipeline in the second quarter of 2024, combined with stronger US Gulf Coast heavy oil pricing.

The SCO price averaged US$69.07 per bbl for the first quarter of 2025, comparable with US$69.43 per bbl for the first quarter of 2024 and a decrease of 3% from US$71.13 per bbl for the fourth quarter of 2024. The SCO differential weakened in the first quarter of 2025 relative to the fourth quarter of 2024, driven in part by production levels in the Western Canadian Sedimentary Basin ("WCSB").

NYMEX benchmark pricing averaged US$3.66 per MMBtu for the first quarter of 2025, an increase of 63% from US$2.24 per MMBtu for the first quarter of 2024 and an increase of 31% from US$2.79 per MMBtu for the fourth quarter of 2024. The increase in NYMEX benchmark pricing for the first quarter of 2025 from the comparable periods in 2024 primarily reflected cold US weather conditions in the first quarter of 2025 resulting in increased heating demand and storage draws, combined with higher LNG exports out of the US Gulf Coast.

AECO benchmark pricing averaged $1.92 per GJ for the first quarter of 2025, comparable with $1.94 per GJ for the first quarter of 2024 and an increase of 39% from $1.38 per GJ for the fourth quarter of 2024. The increase in AECO benchmark pricing for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected stronger NYMEX benchmark pricing, combined with increased exports out of the WCSB. AECO benchmark pricing also reflects the anticipated start-up of LNG Canada in the third quarter of 2025.

(1)SCO production before royalties excludes SCO consumed internally as diesel.

(2)"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used in this MD&A.

(3)Natural gas production volumes approximate sales volumes.

(4)Net of blending and feedstock costs and excluding risk management activities.

(5)Excluding Midstream and Refining revenue.

(1)SCO production net of royalties excludes SCO consumed internally as diesel.

The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO, and natural gas.

Crude oil and NGLs production before royalties for the first quarter of 2025 averaged 1,173,804 bbl/d, an increase of 20% from 975,668 bbl/d for the first quarter of 2024 and an increase of 8% from 1,090,002 bbl/d for the fourth quarter of 2024. The increase in crude oil and NGLs production before royalties for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, combined with strong utilization in the Oil Sands Mining and Upgrading segment and thermal oil pad additions in the North America Exploration and Production segment.

Annual crude oil and NGLs production for 2025 is targeted to average between 1,106,000 bbl/d and 1,142,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Natural gas production before royalties for the first quarter of 2025 averaged 2,451 MMcf/d, an increase of 14% from 2,147 MMcf/d for the first quarter of 2024 and an increase of 7% from 2,283 MMcf/d for the fourth quarter of 2024. The increase in natural gas production before royalties for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024 and strong drilling results.

Annual natural gas production for 2025 is targeted to average between 2,425 MMcf/d and 2,480 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 crude oil and NGLs production before royalties for the first quarter of 2025 of 561,238 bbl/d increased 11% from 505,636 bbl/d for the first quarter of 2024 and increased 6% from 531,960 bbl/d for the fourth quarter of 2024. The increase in North America crude oil and NGLs production for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, thermal oil pad additions at Primrose, and strong conventional drilling results.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 284,706 bbl/d for the first quarter of 2025, an increase of 6% from 268,155 bbl/d for the first quarter of 2024 and an increase of 3% from 276,231 bbl/d for the fourth quarter of 2024. The increase in thermal in situ production in the first quarter of 2025 from the comparable periods in 2024 primarily reflected pad additions at Primrose, partially offset by natural field declines.

Pelican Lake heavy crude oil production before royalties for the first quarter of 2025 averaged 43,175 bbl/d, a decrease of 4% from 45,145 bbl/d for the first quarter of 2024 reflecting Pelican Lake's long life low decline, and comparable with 44,035 bbl/d for the fourth quarter of 2024.

Natural gas production before royalties averaged 2,436 MMcf/d for the first quarter of 2025, an increase of 14% from 2,135 MMcf/d for the first quarter of 2024 and an increase of 7% from 2,273 MMcf/d for the fourth quarter of 2024. The increase in natural gas production for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024 and strong drilling results.

Record SCO production before royalties for the first quarter of 2025 averaged 595,116 bbl/d, an increase of 34% from 445,209 bbl/d for the first quarter of 2024 and an increase of 11% from 534,631 bbl/d for the fourth quarter of 2024. The increase in SCO production for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, combined with strong performance and utilization following the completion of the reliability enhancement project at Horizon and debottleneck project at the non-operated Scotford Upgrader.

International crude oil and NGLs production before royalties for the first quarter of 2025 averaged 17,450 bbl/d, a decrease of 30% from 24,823 bbl/d for the first quarter of 2024 and a decrease of 25% from 23,411 bbl/d for the fourth quarter of 2024. The decrease in International crude oil and NGLs production for the first quarter of 2025 from the comparable periods in 2024 primarily reflected suspended production at Baobab in Offshore Africa due to planned maintenance on its floating production storage and offloading vessel ("FPSO") which commenced in the first quarter of 2025 and is expected to return to service in the second quarter of 2026.

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.

(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(3)Calculated as transportation expense divided by respective sales volumes.

(4)Calculated as royalties divided by respective sales volumes.

(5)Calculated as production expense divided by respective sales volumes.

(6)Calculated as natural gas sales divided by natural gas sales volumes.

(7)Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids-rich natural gas plays.

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.

(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(3)Calculated as crude oil and NGLs sales and natural gas sales divided by respective sales volumes.

North America realized crude oil and NGLs prices averaged $78.56 per bbl for the first quarter of 2025, an increase of 15% from $68.14 per bbl for the first quarter of 2024 and an increase of 6% from $74.46 per bbl for the fourth quarter of 2024. The increase in North America realized crude oil and NGLs prices per bbl for the first quarter of 2025 from the comparable periods in 2024 primarily reflected fluctuations in the WCS Heavy Differential and in foreign exchange. The Company continues to focus on its crude oil blending marketing strategy and in the first quarter of 2025 contributed approximately 223,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 22% to average $3.06 per Mcf for the first quarter of 2025 from $2.50 per Mcf for the first quarter of 2024 and increased 55% from $1.98 per Mcf for the fourth quarter of 2024. The increase in North America realized natural gas prices per Mcf for the first quarter of 2025 from the first quarter of 2024 primarily reflected higher export pricing. The increase for the first quarter of 2025 from the fourth quarter of 2024 reflected higher AECO benchmark and export pricing.

Comparisons of the prices received in North America Exploration and Production by product type were as follows:

(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.

International realized crude oil and NGLs prices decreased 5% to average $107.04 per bbl for the first quarter of 2025 from $112.94 per bbl for the first quarter of 2024 and increased 11% from $96.36 per bbl for the fourth quarter of 2024. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing Brent benchmark prices and foreign exchange rates at the time of lifting.

(1)Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.

North America crude oil and NGLs and natural gas royalties for the first quarter of 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 19% of product sales for the first quarter of 2025 compared with 18% for the first quarter of 2024 and 20% for the fourth quarter of 2024. The fluctuations in royalty rates for the first quarter of 2025 from the comparable periods in 2024 primarily reflected prevailing benchmark pricing and fluctuations in the WCS Heavy Differential.

Natural gas royalty rates averaged approximately 4% of product sales for the first quarter of 2025 compared with 4% for the first quarter of 2024 and 2% for the fourth quarter of 2024. The fluctuations in royalty rates for the first quarter of 2025 from the comparable periods in 2024 primarily reflected benchmark pricing.

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 the first quarter of 2025 compared with 5% of product sales for the first quarter of 2024 and 5% for the fourth quarter of 2024. Royalty rates as a percentage of product sales reflected the timing of liftings, and the status of payout in the various fields.

(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(1)Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.

North America crude oil and NGLs production expense for the first quarter of 2025 of $12.65 per bbl decreased 14% from $14.72 per bbl for the first quarter of 2024 and increased 17% from $10.83 per bbl for the fourth quarter of 2024. The decrease in crude oil and NGLs production expense per bbl for the first quarter of 2025 from the first quarter of 2024 primarily reflected lower energy costs, combined with higher production volumes. The increase in crude oil and NGLs production expense per bbl for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected increased energy and seasonal service costs in the first quarter of 2025, partially offset by higher production volumes.

North America natural gas production expense for the first quarter of 2025 of $1.16 per Mcf decreased 9% from $1.27 per Mcf for the first quarter of 2024 and increased 6% from $1.09 per Mcf for the fourth quarter of 2024. The decrease in natural gas production expense per Mcf for the first quarter of 2025 from the first quarter of 2024 primarily reflected higher production volumes. The increase in natural gas production expense per Mcf for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected seasonal service costs, partially offset by higher production volumes.

International crude oil and NGLs production expense for the first quarter of 2025 of $80.63 per bbl increased 31% from $61.32 per bbl for the first quarter of 2024 and increased 4% from $77.66 per bbl for the fourth quarter of 2024. The increase in crude oil and NGLs production expense per bbl for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the timing of liftings from various fields that have different cost structures and the impact of foreign exchange.

(1)As at December 31, 2024, as a result of refined project scope and cost estimates associated with abandonment activities, the Company recognized a recoverability charge of $160 million in depletion, depreciation and amortization expense related to an increase in its estimate of future abandonment costs for the Ninian field in the North Sea.

(2)This is a non-GAAP financial measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production. It may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements (depletion, depreciation and amortization expense), as an indication of the Company's performance.

(3)This is a non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Adjusted depletion, depreciation and amortization expense for the first quarter of 2025 averaged $13.27 per BOE, an increase of 5% from $12.64 per BOE for the first quarter of 2024 and comparable with $13.01 per BOE for the fourth quarter of 2024. The increase in adjusted depletion, depreciation and amortization expense per BOE for the first quarter of 2025 from the first quarter of 2024 primarily reflected the impact of changes in North America depletion rates due to changes in reserve estimates at December 31, 2024, combined with a higher depletable base due to asset additions, partially offset by higher sales volumes.

Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.

(1)Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the first quarter of 2025 averaged $0.77 per BOE, a decrease of 19% from $0.95 per BOE for the first quarter of 2024 and a decrease of 13% from $0.89 per BOE for the fourth quarter of 2024. The decrease in asset retirement obligation accretion expense per BOE for the first quarter of 2025 from the comparable periods in 2024 reflected the impact of changes in discount rate estimate revisions at December 31, 2024, combined with higher sales volumes in the first quarter of 2025, partially offset by revisions in cost and timing estimates at December 31, 2024.

The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites with record SCO production averaging 595,116 bbl/d in the first quarter of 2025.

(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(2)Calculated as the quarterly average of the bitumen methodology price.

(3)Calculated as royalties divided by sales volumes.

(4)Calculated as transportation expense divided by sales volumes.

The realized SCO sales price averaged $95.52 per bbl for the first quarter of 2025, an increase of 8% from $88.84 per bbl for the first quarter of 2024 and comparable with $95.08 per bbl for the fourth quarter of 2024. The increase in realized SCO sales price per bbl for the first quarter of 2025 from the first quarter of 2024 primarily reflected a strengthening of the SCO differential as a result of additional egress following the start-up of the TMX pipeline in the second quarter of 2024, partially offset by lower WTI benchmark pricing.

The fluctuations in bitumen royalties per bbl in any particular period reflect prevailing bitumen pricing for royalty purposes, and the impact of sliding scale royalty rates. The increase in bitumen royalties per bbl for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the increase in average bitumen pricing for royalty purposes.

Transportation expense averaged $3.21 per bbl for the first quarter of 2025, an increase of 92% from $1.67 per bbl for the first quarter of 2024 and a decrease of 11% from $3.60 per bbl for the fourth quarter of 2024. The increase in transportation expense per bbl for the first quarter of 2025 from the first quarter of 2024 primarily reflected new volumes shipped on the TMX pipeline beginning in the second quarter of 2024. The decrease for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected lower volumes shipped to the US Gulf Coast, partially offset by higher volumes shipped on the TMX pipeline.

(1)Calculated as production expense, excluding natural gas costs, divided by sales volumes.

(2)Calculated as natural gas costs divided by sales volumes.

(3)Calculated as production expense divided by sales volumes.

The Company incurred production expense of $1,185 million for the first quarter of 2025, an increase of 15% from $1,026 million for the first quarter of 2024 and an increase of 16% from $1,019 million for the fourth quarter of 2024. The increase in production expense for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024.

Production expense for the first quarter of 2025 averaged $21.88 per bbl, a decrease of 12% from $24.85 per bbl for the first quarter of 2024 and an increase of 4% from $20.97 per bbl for the fourth quarter of 2024. The decrease in production expense per bbl for the first quarter of 2025 from the first quarter of 2024 primarily reflected higher production volumes. The increase in production expense per bbl for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected higher energy and seasonal service costs, partially offset by higher production volumes.

(1)Calculated as depletion, depreciation and amortization divided by sales volumes.

Depletion, depreciation and amortization expense for the first quarter of 2025 of $12.45 per bbl was comparable with $12.70 per bbl for the first quarter of 2024 and $12.76 per bbl for the fourth quarter of 2024.

(1)Calculated as asset retirement obligation accretion divided by sales volumes.

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the first quarter of 2025 of $0.40 per bbl decreased 22% from $0.51 per bbl for the first quarter of 2024 and decreased 9% from $0.44 per bbl for the fourth quarter of 2024. The decrease in asset retirement obligation accretion expense per bbl for the first quarter of 2025 from the comparable periods in 2024 primarily reflected the impact of higher sales volumes in the first quarter of 2025.

The Company's Midstream and Refining assets consist of two crude oil pipeline systems, a 50% working interest in an 84-megawatt cogeneration plant at Primrose, and the Company's 50% equity investment in North West Redwater Partnership ("NWRP").

NWRP operates a bitumen upgrader and refinery with an output capacity of approximately 80,000 bbl/d. The refinery processes approximately 50,000 bbl/d of bitumen feedstock, including 12,500 bbl/d of bitumen feedstock for the Company (25% toll payer) and 37,500 bbl/d of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC") (75% toll payer), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period until 2058. Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment. For the first quarter of 2025, production of ultra-low sulphur diesel and other refined products averaged 83,863 BOE/d (20,966 BOE/d to the Company) (three months ended December 31, 2024 – 77,742 BOE/d; 19,436 BOE/d to the Company; three months ended March 31, 2024 – 78,569 BOE/d; 19,642 BOE/d to the Company), reflecting the 25% toll payer commitment.

As at March 31, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $528 million (December 31, 2024 – $509 million). For the three months ended March 31, 2025, the Company's unrecognized share of the equity loss was $19 million (three months ended March 31, 2024 – recovery of unrecognized equity losses of $4 million).

(1)Calculated as administration expense divided by sales volumes.

(2)Total Company sales volumes.

Administration expense for the first quarter of 2025 averaged $1.06 per BOE, comparable with $1.04 per BOE for the first quarter of 2024 and an increase of 12% from $0.95 per BOE for the fourth quarter of 2024. The increase in administration expense per BOE for the first quarter of 2025 from the fourth quarter of 2024 primarily reflected higher personnel costs, partially offset by higher sales volumes.

The Company's Stock Option Plan provides employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment; the amount of which is determined with reference to the value of the Company's shares, by individual employee performance, and the extent to which certain other performance measures are met.

The Company recognized $26 million of share-based compensation expense for the three months ended March 31, 2025, primarily as a result of the measurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the period, and changes in the Company's share price.

(1)Item is a component of interest and other financing expense.

(2)The average of current and long-term debt and lease liabilities outstanding during the respective period.

(3)This is a non-GAAP ratio and may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance.

(4)Calculated as the average interest expense on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance. The Company presents its average effective interest rate for financial statement users to evaluate the Company’s average cost of debt borrowings.

(5)Calculated as interest and other financing expense divided by sales volumes.

(6)Total Company sales volumes.

Interest and other financing expense for the first quarter of 2025 increased 56% to $1.79 per BOE from $1.15 per BOE for the first quarter of 2024 and increased 69% from $1.06 per BOE for the fourth quarter of 2024. The increase in interest and other financing expense per BOE for the first quarter of 2025 from the comparable periods in 2024 primarily reflected higher average debt levels, partially offset by higher sales volumes.

The Company's average effective interest rate for the first quarter of 2025 averaged 5.0%, an increase from the first quarter of 2024, reflecting higher floating rate debt held in the first quarter of 2025, combined with fixed rate debt issuances in the fourth quarter of 2024.

The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.

(1)During 2025, the Company entered into foreign currency put options contracts. Further details are disclosed in note 13 to the financial statements.

(2)Certain commodity financial instruments were assumed in the acquisition of Painted Pony Energy Ltd. in the fourth quarter of 2020.

(3)In the fourth quarter of 2024, the Company entered into fixed price financial contracts to buy 12,500 MMBtu/d of natural gas at US$1.47 AECO, and 25,000 MMBtu/d of natural gas at US$1.82 AECO for the period of January to December 2025.

(4)In the fourth quarter of 2023, the Company entered into fixed price financial contracts to buy 50,000 MMBtu/d of natural gas at US$1.82 AECO for the period of January to December 2024.

During the first quarter of 2025, net realized risk management gains were primarily related to the settlement of foreign currency forward contracts. The Company recorded a net unrealized loss of $3 million ($2 million after tax of $1 million) on its risk management activities for the three months ended March 31, 2025 (three months ended December 31, 2024 – unrealized gain of $4 million ($3 million after tax of $1 million); three months ended March 31, 2024 – unrealized loss of $13 million ($12 million after tax of $1 million)).

Further details related to outstanding derivative financial instruments as at March 31, 2025 are disclosed in note 13 to the financial statements.

(1)Amounts are reported net of the hedging effect of any cross-currency swaps.

The net realized foreign exchange loss for the first quarter of 2025 was primarily related to the repayment of US dollar debt. The net unrealized foreign exchange gain for the first quarter of 2025 was primarily related to the repayment of US dollar debt during the first quarter of 2025, combined with the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at March 31, 2025 was US$0.6955 (December 31, 2024 – US$0.6942, March 31, 2024 – US$0.7390).

(1)Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.

(2)Calculated as total of current and deferred income tax divided by earnings before taxes.

(3)Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, and a recoverability charge related to the increase in future abandonment costs for Ninian field in the North Sea in the fourth quarter of 2024.

(4)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(5)This is a non-GAAP ratio and may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance.

(6)Calculated as effective tax on adjusted net earnings divided by adjusted net earnings from operations, before taxes. The Company presents its effective tax rate on adjusted net earnings from operations for financial statement users to evaluate the Company's effective tax rate on its core business activities.

The effective tax rate on net earnings and adjusted net earnings from operations for the first quarter of 2025 and the comparable periods included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings.

The current and deferred corporate income tax and the current and deferred PRT in the North Sea for the first quarter of 2025 and the comparable periods included the impact of carrybacks of abandonment expenditures related to the decommissioning activities at the Company's platforms in the North Sea.

The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company's reported results of operations, financial position or liquidity.