Canadian Natural's President, Scott Stauth, commented on the Company's third quarter results, "Operations were strong in Q3/25 as we achieved record quarterly production volumes totaling approximately 1,620 MBOE/d, including records for both liquids and natural gas at 1,176 Mbbl/d and 2,668 MMcf/d respectively. We increased total corporate production by 19% or approximately 257,000 BOE/d from Q3/24 levels, reflecting both accretive acquisitions and organic growth achieved across our asset base over the last 12 months.

Our world class Oil Sands Mining and Upgrading assets continue to achieve strong operational performance as Q3/25 production averaged approximately 581,000 bbl/d of SCO, with strong utilization of 104% and industry leading operating costs of approximately $21 per barrel.

Subsequent to quarter end, we closed the AOSP swap with Shell Canada Limited and affiliates ("Shell") on November 1, 2025, with an effective date of March 1, 2025. Canadian Natural now owns and operates 100% of the Albian oil sands mines and associated reserves and retains a non-operated 80% interest in the Scotford Upgrader and Quest facilities. This generates additional cash flow and adds approximately 31,000 bbl/d of annual, zero decline bitumen production to our portfolio, driving long-term value creation for our shareholders. This swap also enhances our ability to integrate equipment and services across our mining operations, unlocking additional value through continuous improvement initiatives.

Additionally, we increased our annual 2025 corporate production guidance range to 1,560 MBOE/d to 1,580 MBOE/d, while our 2025 operating capital forecast remains unchanged at approximately $5.9 billion while executing additional activity on our increased asset base size."

Canadian Natural's Chief Financial Officer, Victor Darel, added "Our business model is robust and sustainable, underpinned by a strong balance sheet that provides flexibility through significant liquidity, totaling approximately $4.3 billion as at September 30, 2025. We closed accretive and opportunistic acquisitions in the quarter and remained at similar net debt levels when compared to Q2/25. These are excellent results, highlighting the free cash flow generating capability of our top tier asset base.

In Q3/25, we generated adjusted net earnings of $1.8 billion or $0.86 per share, and adjusted funds flow of $3.9 billion or $1.88 per share. We returned approximately $1.5 billion to our shareholders in the quarter, including $1.2 billion in dividends and $0.3 billion in share repurchases as we continue to execute on our free cash flow allocation policy." ▪Generated net earnings of approximately $0.6 billion and adjusted net earnings from operations of approximately $1.8 billion.

▪Generated adjusted funds flow of approximately $3.9 billion.

▪Returns to shareholders totaled approximately $1.5 billion, comprised of $1.2 billion in dividends and $0.3 billion in share repurchases.

•Year to date, up to and including November 5, 2025, the Company has returned a total of approximately $6.2 billion directly to shareholders through $4.9 billion in dividends and $1.3 billion in share repurchases.

•25 consecutive years of dividend growth with a CAGR of 21% over that time.

◦Subsequent to quarter end, declared a quarterly cash dividend on its common shares of $0.5875 per common share.

▪Record quarterly corporate production of 1,620,261 BOE/d.

•Significant total BOE production growth of approximately 257,000 BOE/d or 19% from Q3/24 levels reflects accretive acquisitions and organic growth achieved over the last 12 months.

•Record quarterly liquids production of 1,175,604 bbl/d was achieved, an increase of approximately 154,000 bbl/d or 15% from Q3/24 levels.

◦Oil Sands Mining and Upgrading production was strong, averaging 581,136 bbl/d of SCO with upgrader utilization of 104% and industry leading operating costs of $21.29/bbl (US$15.46/bbl) in Q3/25.

▪Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $4.3 billion in liquidity(1) as at September 30, 2025. During Q3/25, the Company:

•Repaid US$600 million of US dollar debt securities due in July 2025.

•Received a new long-term investment grade credit rating of BBB+ from Fitch Ratings.

▪Subsequent to quarter end, on November 1, 2025, Canadian Natural closed the AOSP swap with Shell. Canadian Natural now owns and operates 100% of the Albian oil sands mines and associated reserves and retains a non-operated 80% interest in the Scotford Upgrader and Quest facilities.

•The transaction adds approximately 31,000 bbl/d of annual, zero decline bitumen production, providing additional cash flow and enabling more effective and efficient operations between the Horizon and Albian mines.

•The swap did not include any cash consideration, with the exception of regular closing adjustments to reflect the effective date of March 1, 2025.

•Following the close, Canadian Natural updated its 2025 capital and production guidance as follows:

◦2025 production guidance range of 1,560 MBOE/d to 1,580 MBOE/d.

◦2025 operating capital forecast remains unchanged at approximately $5.9 billion, following the $100 million reduction previously announced in May 2025.

–As a result of strong operational execution and capital discipline, additional activity on a larger asset base, following opportunistic acquisitions in the year, has been executed with no incremental capital required.

(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and nine months ended September 30, 2025 dated November 5, 2025 ("MD&A").

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

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

(3)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.

(4)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.

▪Net earnings of $0.6 billion in Q3/25 reflected a non-cash recoverability charge of approximately $0.7 billion related to an increase in the estimate for future abandonment costs for the Ninian field and T-Block assets in the North Sea. Adjusted net earnings from operations, excluding the impact of the recoverability charge and unrealized foreign exchange and risk management activities, was strong at $1.8 billion in the quarter.

▪Canadian Natural has a strong history of 25 consecutive years of growing its sustainable dividend with a CAGR of 21% over that time, demonstrating the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.

•Returns to shareholders in Q3/25 were strong, totaling approximately $1.5 billion, comprised of $1.2 billion of dividends and $0.3 billion through the repurchase and cancellation of approximately 7.2 million common shares at a weighted average price of $43.12 per share.

•Year to date, up to and including November 5, 2025, the Company has returned a total of approximately $6.2 billion directly to shareholders through $4.9 billion in dividends and $1.3 billion through the repurchase and cancellation of approximately 29.6 million common shares at a weighted average price of $42.92 per share.

•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 January 6, 2026 to shareholders of record at the close of business on December 12, 2025.

Canadian Natural is pleased to announce the appointment of Ms. Shelley A.M. Brown, CM, FCPA, FCA, ICD.D, O.C. to the Board of Directors of the Company and to the Audit Committee effective November 4, 2025. Ms. Brown is a Chartered Accountant who retired as a Senior Audit Partner with Deloitte after more than 35 years in public accounting. Ms. Brown has extensive experience working with public companies in the mining and manufacturing sectors and has over 30 years of experience working with both non-profit and public company boards including in the role of audit committee chair. Ms. Brown holds a Bachelor of Commerce from the University of Saskatchewan and is a Fellow of the Institutes of Chartered Accountants of Alberta, Saskatchewan, British Columbia and Ontario.

(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 production averaged 581,136 bbl/d of SCO in Q3/25, an increase of 17% from Q3/24 levels, reflecting the additional working interest in AOSP acquired in December 2024 combined with effective and efficient operations.

•Oil Sands Mining and Upgrading achieved strong upgrader utilization in Q3/25 of 104%.

•Oil Sands Mining and Upgrading operating costs are industry leading, averaging $21.29/bbl (US$15.46/bbl) of SCO in Q3/25.

▪Subsequent to quarter end, Canadian Natural closed the AOSP swap with Shell on November 1, 2025, with an effective date of March 1, 2025. Canadian Natural now owns and operates 100% of the Albian oil sands mines and associated reserves and retains a non-operated 80% interest in the Scotford Upgrader and Quest Carbon Capture and Storage facilities.

•The transaction adds approximately 31,000 bbl/d of annual, zero decline bitumen production, providing additional cash flow and enabling more effective and efficient operations between the Horizon and Albian mines.

▪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.

▪Thermal in situ production averaged 274,752 bbl/d in Q3/25, comparable to Q3/24 levels.

•Thermal in situ operating costs remain strong, averaging $10.35/bbl (US$7.52/bbl) in Q3/25, a decrease of 2% from Q3/24 levels of $10.52/bbl.

▪Canadian Natural has significant thermal in situ facility processing capacity of 340,000 bbl/d, resulting in approximately 70,000 bbl/d of annual 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, the Company began drilling a Cyclic Steam Stimulation ("CSS") pad in Q3/25 with production targeted to come on in the second half of 2026.

•At Jackfish, the Company brought a Steam Assisted Gravity Drainage ("SAGD") pad on production in July 2025 as planned.

•At Kirby, the Company brought a five well-pair SAGD pad on production in late October 2025 as planned.

•At Pike, the Company tied the two recently drilled SAGD pads into the Jackfish facilities. These two SAGD pads are targeted to keep the Jackfish facilities at full capacity with the first pad targeted to come on production in January 2026 and the second pad targeted to come on production in Q2/26.

▪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 commercial scale solvent SAGD pad at Kirby North, current SOR reductions and solvent recoveries are meeting expectations following recent workovers and optimizations.

•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.

▪North America E&P liquids production, excluding thermal in situ, averaged 309,873 bbl/d in Q3/25, an increase of 36% or approximately 82,000 bbl/d from Q3/24 levels, reflecting opportunistic acquisitions and strong organic growth from heavy crude oil multilaterals, liquids-rich natural gas and light crude oil, partially offset by natural field declines.

•Primary heavy crude oil production averaged 87,705 bbl/d in Q3/25, an increase of 14% from Q3/24 levels, reflecting strong drilling results from the Company's multilateral wells, partially offset by natural field declines.

◦Canadian Natural’s highly successful multilateral drilling program continues to unlock opportunity on our approximately 3 million net acres of high quality land throughout our primary heavy crude oil assets.

◦Operating costs in the Company's primary heavy crude oil operations averaged $16.46/bbl (US$11.95/bbl) in Q3/25, a decrease of 12% from Q3/24 levels, primarily as a result of higher production volumes and the increasing proportion of lower operating cost multilateral production.

•Pelican Lake production averaged 42,070 bbl/d in Q3/25 a decrease of 7% from Q3/24 levels, reflecting planned maintenance in Q3/25 and the low natural field declines from this long life low decline asset.

◦Operating costs at Pelican Lake averaged $9.00/bbl (US$6.54/bbl) in Q3/25, an increase of 3% Q3/24 levels.

•North America light crude oil and NGLs production averaged 180,098 bbl/d in Q3/25, an increase of 69% or approximately 74,000 bbl/d from Q3/24 levels, primarily reflecting production volumes from the acquisition of liquids-rich Duvernay assets in Q4/24, light crude oil Palliser Block assets in Q2/25 and the liquids-rich Montney assets in the Grande Prairie area in Q3/25.

◦Operating costs in the Company's North America light crude oil and NGLs operations averaged $12.91/bbl (US$9.38/bbl) in Q3/25, a decrease of 6% from Q3/24 levels of $13.73/bbl, primarily reflecting higher production volumes.

•As previously announced, on July 2, 2025, Canadian Natural closed an acquisition of liquids-rich Montney assets located in the Grande Prairie area for approximately $750 million, which included production of approximately 32,000 BOE/d, including 12,500 bbl/d of NGLs.

▪North America natural gas production averaged 2,658 MMcf/d in Q3/25, an increase of 30% from Q3/24 levels, primarily reflecting opportunistic acquisitions and strong drilling results in the Company's liquids-rich natural gas assets, partially offset by natural field declines.

•North America natural gas operating costs averaged $1.14/Mcf in Q3/25, a decrease of 7% from Q3/24 levels of $1.23/Mcf, primarily reflecting higher production volumes and cost efficiencies.

▪International E&P crude oil production volumes averaged 9,843 bbl/d in Q3/25, a decrease of 59% compared to Q3/24 levels. The decrease reflects temporary suspension of production at Baobab in Offshore Africa due to the planned refurbishment on its floating production storage and offloading ("FPSO") vessel, both planned and unplanned maintenance and planned decommissioning activities in the North Sea and natural field declines.

•The annual production impact in 2025 from the planned Baobab FPSO refurbishment is targeted to be approximately 7,800 bbl/d, with production targeted to resume in Q2/26.

(1)Includes bitumen wells.

▪Canadian Natural drilled a total of 303 net crude oil and natural gas wells in the first nine months of 2025, 30 more than in the first nine months of 2024.

(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.

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

▪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 United States Gulf Coast, being approximately 22% of 2025 forecasted 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 North West Redwater refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 38,434 bbl/d in Q3/25, reflecting the successful completion of the planned turnaround during the quarter.

▪Canadian Natural has a diversified natural gas marketing strategy with the Company targeting in 2025 to use the equivalent of approximately 31% of forecasted natural gas production in its Oil Sands Mining and Upgrading and thermal operations, with approximately 38% targeted to be sold at AECO/Station 2 pricing, and approximately 31% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value.

▪Canadian Natural has entered into a long-term natural gas supply agreement with Cheniere Energy, Inc. ("Cheniere") where the Company has agreed to sell 140,000 MMBtu/d of natural gas to Cheniere for a term of 15 years, with delivery anticipated to begin in 2030, subject to a number of conditions precedent including a positive final investment decision of the Sabine Pass Liquefaction Expansion Project by Cheniere.

•Under the terms of the agreement, Canadian Natural will deliver natural gas to Cheniere in Chicago and receive a Japan Korea Marker ("JKM") index price less deductions for transportation and liquefaction.

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 uncertainties in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded); uncertainty in the regulatory framework governing 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; civil unrest and political uncertainty, including changes in government, actions of or against terrorists, insurgent groups, or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime, and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling, and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting, or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting, or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs, actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium-, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital

structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this document 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, 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 MD&A and unaudited interim consolidated financial statements (the "financial statements") for the three and nine months ended September 30, 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 MD&A and financial statements for the three and nine months ended September 30, 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 November 5, 2025.

This document includes references to Non-GAAP and Other Financial Measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). These financial measures are used by the Company to evaluate its financial performance, financial position, and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this this document and the Company's MD&A and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and nine months ended September 30, 2025 dated November 5, 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 September 30, 2025 and comparable periods 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 and nine months ended September 30, 2025 dated November 5, 2025.

(2)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 and nine months ended September 30, 2025 dated November 5, 2025.

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 forecast reflects forecasted 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 forecasted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries in Canada and the UK portion of the North Sea. The Company is eligible to recover interest on related to tax recoveries in the North Sea.

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 Third Quarter Earnings Results on Thursday, November 6, 2025 before market open.

A conference call will be held at 9:00 a.m. MT / 11:00 a.m. ET on Thursday, November 6, 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: 56299#)

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.

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 uncertainties in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded); uncertainty in the regulatory framework governing 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; civil unrest and political uncertainty, including changes in government, actions of or against terrorists, insurgent groups, or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime, and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling, and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting, or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting, or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs, actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium-, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

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 and nine months ended September 30, 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 and nine months ended September 30, 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 and nine months ended September 30, 2025 in relation to the comparable periods in 2024 and the second quarter of 2025. 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 November 5, 2025.

FINANCIAL HIGHLIGHTS

(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 nine months ended September 30, 2025 were $5,517 million compared with $4,968 million for the nine months ended September 30, 2024. Net earnings for the nine months ended September 30, 2025 included non‑operating losses, net of tax, of $216 million compared with non-operating losses of $469 million for the nine months ended September 30, 2024 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain from investments, the gain on acquisition, a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian field and T‑Block assets in the North Sea in the third quarter of 2025, and a recoverability charge related to the notice to withdraw from Block 11B/12B in South Africa in the second quarter of 2024. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2025 were $5,733 million compared with $5,437 million for the nine months ended September 30, 2024.

Net earnings for the third quarter of 2025 were $600 million compared with $2,266 million for the third quarter of 2024 and $2,459 million for the second quarter of 2025. Net earnings for the third quarter of 2025 included non-operating losses, net of tax, of $1,201 million compared with non-operating income of $195 million for the third quarter of 2024 and non‑operating income of $963 million for the second quarter of 2025 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain on acquisition, and a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian field and T‑Block assets in the North Sea in the third quarter of 2025. Excluding these items, adjusted net earnings from operations for the third quarter of 2025 were $1,801 million compared with $2,071 million for the third quarter of 2024 and $1,496 million for the second quarter of 2025.

The increase in net earnings and adjusted net earnings from operations for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected:

▪higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment;

▪lower realized SCO pricing(1) in the Oil Sands Mining and Upgrading segment; and

▪lower realized crude oil and NGLs pricing(1) in the North America Exploration and Production segment.

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

▪lower realized SCO pricing in the Oil Sands Mining and Upgrading segment; and

▪lower realized crude oil and NGLs pricing in the North America Exploration and Production segment;

▪higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment.

The movements in net earnings and adjusted net earnings from operations for the third quarter of 2025 from the second quarter of 2025 primarily reflected:

▪higher crude oil and NGLs, and natural gas sales volumes in the North America Exploration and Production segment; and

▪higher realized crude oil and NGLs pricing in the North America Exploration and Production segment;

▪lower realized natural gas pricing in the North America Exploration and Production segment.

The impacts of depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchange loss (gain), gain on acquisition, 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.

The Company is progressing its abandonment and decommissioning activities in the North Sea, including the tendering and awarding of contracts for the Ninian South Platform. Following a competitive bidding process in 2025, cost estimates have come in higher than originally budgeted. As a result, the Company has reviewed and updated estimates for abandonment and decommissioning costs for its North Sea assets, including the Ninian Central and South Platforms and T‑Block (comprising the Tiffany, Toni, and Thelma fields). In addition, based on current and forecasted economic conditions, including commodity pricing and market egress for T‑Block volumes, the Company has determined that the T-Block assets are no longer economically viable. The Company is assessing alternatives for the potential acceleration of the T‑Block decommissioning plan. As a result, at September 30, 2025, the Company recognized a non-cash charge of $695 million, comprised of additional abandonment costs for the Ninian field of $734 million, net of deferred tax recoveries of $359 million, and an additional charge of $524 million for T‑Block, net of deferred tax recoveries of $204 million, relating to current and forecasted economic conditions. The Company's estimate of its asset retirement obligations, including its long-term abandonment projects in the North Sea and associated tax recoveries, are subject to revision in future periods as abandonment activities progress.

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

Cash flows from operating activities for the nine months ended September 30, 2025 were $11,338 million compared with $9,954 million for the nine months ended September 30, 2024. Cash flows from operating activities for the third quarter of 2025 were $3,940 million compared with $3,002 million for the third quarter of 2024 and $3,114 million for the second quarter of 2025. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.

Adjusted funds flow for the nine months ended September 30, 2025 was $11,712 million compared with $10,673 million for the nine months ended September 30, 2024. Adjusted funds flow for the third quarter of 2025 was $3,920 million compared with $3,921 million for the third quarter of 2024 and $3,262 million for the second quarter of 2025. 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, interest on Petroleum Revenue Tax ("PRT") and corporate tax recoveries, and prepaid cost of service tolls.

Crude oil and NGLs production before royalties for the third quarter of 2025 of 1,175,604 bbl/d increased 15% from 1,021,572 bbl/d for the third quarter of 2024 and increased 15% from 1,019,149 bbl/d for the second quarter of 2025. Natural gas production before royalties for the third quarter of 2025 of 2,668 MMcf/d increased 30% from 2,049 MMcf/d for the third quarter of 2024 and increased 11% from 2,407 MMcf/d for the second quarter of 2025. Total production before royalties for the third quarter of 2025 of 1,620,261 BOE/d increased 19% from 1,363,086 BOE/d for the third quarter of 2024 and increased 14% from 1,420,358 BOE/d for the second quarter of 2025. 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 $72.57 per bbl for the third quarter of 2025, a decrease of 8% from $79.15 per bbl for the third quarter of 2024 and an increase of 4% from $69.58 per bbl for the second quarter of 2025. The realized natural gas price increased 19% to average $1.49 per Mcf for the third quarter of 2025 from $1.25 per Mcf for the third quarter of 2024 and decreased 42% from $2.58 per Mcf for the second quarter of 2025. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 13% to average $87.85 per bbl for the third quarter of 2025 from $100.93 per bbl for the third quarter of 2024 and was comparable with $87.22 per bbl for the second quarter of 2025. 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 "Realized Product Prices, Royalties and Transportation – 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 $13.18 per bbl for the third quarter of 2025, a decrease of 10% from $14.65 per bbl for the third quarter of 2024 and a decrease of 6% from $14.03 per bbl for the second quarter of 2025. Natural gas production expense(1) averaged $1.16 per Mcf for the third quarter of 2025, a decrease of 8% from $1.26 per Mcf for the third quarter of 2024 and an increase of 5% from $1.11 per Mcf for the second quarter of 2025. In the Oil Sands Mining and Upgrading segment, production expense(1) averaged $21.29 per bbl for the third quarter of 2025, comparable with $20.67 per bbl for the third quarter of 2024 and a decrease of 20% from $26.53 per bbl for the second quarter of 2025. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Production Expense – Oil Sands Mining and Upgrading" sections of this MD&A.

(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 September 30, 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.

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 impacts of ongoing tariff and trade uncertainty) on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the start-up of the Trans Mountain Expansion ("TMX") pipeline in 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 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, the acquisition of assets in the Palliser Block in the second quarter of 2025, and the acquisition of assets in the Grande Prairie area in the third quarter of 2025, wildfires, and maintenance activities in the North America Exploration and Production segment. Sales volumes in the International segments also reflected fluctuations due to the timing of liftings, planned abandonment activities in the North Sea, and temporary suspension of production at Baobab in Offshore Africa for planned floating production storage and offloading vessel ("FPSO") maintenance.

▪Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, the impact and timing of acquisitions, including the acquisition of a working interest in the Duvernay assets in the fourth quarter of 2024, the acquisition of assets in the Palliser Block in the second quarter of 2025, and the acquisition of assets in the Grande Prairie area in the third quarter of 2025, natural field decline rates, the impact of seasonal conditions, and wildfires in the North America Exploration and Production segment.

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

▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes, timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds in the Oil Sands Mining and Upgrading segment, a recoverability charge at September 30, 2025 relating to an increase in estimate of future abandonment costs for the Ninian field and T‑Block assets in the North Sea, recoverability charges 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, the impact of movements in benchmark interest rates on outstanding floating rate long-term debt, and interest on PRT and corporate tax recoveries.

▪Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt and working capital.

Global crude oil benchmark pricing remained relatively stable through the third quarter of 2025, though continued to experience downward pressure from weaker demand outlooks amid ongoing tariff and trade uncertainty, and the impact of the unwinding of OPEC+ supply cuts. Additionally, near record non-OPEC+ production during the quarter reduced the impact of geopolitical supply uncertainty. Natural gas benchmark pricing declined in the third quarter of 2025, driven by increasing inventory levels primarily as a result of weaker US demand. In Canada, AECO benchmark pricing declined due to strong production in the Western Canadian Sedimentary Basin ("WCSB"), combined with third-party pipeline outages reducing export egress, and lower processing capacity than expected at LNG Canada.

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 any tariffs imposed or announced continue 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 September 30, 2025, the Company had undrawn revolving bank credit facilities of $4,201 million. Including cash and cash equivalents, the Company had approximately $4,314 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$66.67 per bbl for the nine months ended September 30, 2025, a decrease of 14% from US$77.55 per bbl for the nine months ended September 30, 2024. WTI averaged US$64.95 per bbl for the third quarter of 2025, a decrease of 14% from US$75.16 per bbl for the third quarter of 2024 and comparable with US$63.71 per bbl for the second quarter of 2025.

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$70.82 per bbl for the nine months ended September 30, 2025, a decrease of 14% from US$82.78 per bbl for the nine months ended September 30, 2024. Brent averaged US$69.08 per bbl for the third quarter of 2025, a decrease of 14% from US$80.25 per bbl for the third quarter of 2024 and comparable with US$67.78 per bbl for the second quarter of 2025.

The decrease in WTI and Brent benchmark pricing for the three and nine months ended September 30, 2025 from the comparable periods in 2024 reflected weaker global demand outlooks amid ongoing tariff and trade uncertainty, combined with increased OPEC+ supply and near record non-OPEC+ production.

The WCS Heavy Differential averaged US$11.07 per bbl for the nine months ended September 30, 2025, compared with US$15.46 per bbl for the nine months ended September 30, 2024. The WCS Heavy Differential averaged US$10.36 per bbl for the third quarter of 2025, compared with US$13.51 per bbl for the third quarter of 2024 and US$10.19 per bbl for the second quarter of 2025. The narrowing of the WCS Heavy Differential for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected the start-up of the TMX pipeline in the second quarter of 2024, and strong US Gulf Coast heavy oil pricing. The narrowing of the WCS Heavy Differential for the third quarter of 2025 from the third quarter of 2024 primarily reflected higher refinery utilization further supported by strong US Gulf Coast heavy oil pricing.

The SCO price averaged US$66.66 per bbl for the nine months ended September 30, 2025, a decrease of 13% from US$76.42 per bbl for the nine months ended September 30, 2024. The SCO price averaged US$66.26 per bbl for the third quarter of 2025, a decrease of 13% from US$76.51 per bbl for the third quarter of 2024 and comparable with US$64.69 per bbl for the second quarter of 2025. The decrease in SCO pricing for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected weaker WTI benchmark pricing.

NYMEX benchmark pricing averaged US$3.39 per MMBtu for the nine months ended September 30, 2025, an increase of 61% from US$2.10 per MMBtu for the nine months ended September 30, 2024. NYMEX benchmark pricing averaged US$3.07 per MMBtu for the third quarter of 2025, an increase of 42% from US$2.16 per MMBtu for the third quarter of 2024 and a decrease of 11% from US$3.44 per MMBtu for the second quarter of 2025. The increase in NYMEX natural gas prices for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower US inventory levels in the first half of 2025, combined with higher LNG exports out of the US Gulf Coast. The decrease in NYMEX natural gas pricing for the third quarter of 2025 from the second quarter of 2025 primarily reflected increased inventory levels from strong US production and lower electricity demand, partially offset by increased LNG exports out of the US Gulf Coast.

AECO benchmark pricing averaged $1.61 per GJ for the nine months ended September 30, 2025, an increase of 19% from $1.35 per GJ for the nine months ended September 30, 2024. AECO benchmark pricing averaged $0.94 per GJ for the third quarter of 2025, an increase of 22% from $0.77 per GJ for the third quarter of 2024 and a decrease of 52% from $1.97 per GJ for the second quarter of 2025. The increase in AECO natural gas prices for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected higher NYMEX benchmark pricing, combined with increased exports out of the WCSB. The decrease in AECO natural gas pricing for the third quarter of 2025 from the second quarter of 2025 reflected increased inventory levels from strong production in the WCSB, lower processing capacity than expected at LNG Canada, and third-party pipeline outages reducing export egress.

(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 nine months ended September 30, 2025 averaged 1,122,859 bbl/d, an increase of 15% from 977,265 bbl/d for the nine months ended September 30, 2024. Crude oil and NGLs production before royalties for the third quarter of 2025 averaged 1,175,604 bbl/d, an increase of 15% from 1,021,572 bbl/d for the third quarter of 2024 and an increase of 15% from 1,019,149 bbl/d for the second quarter of 2025. The increase in crude oil and NGLs production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, strong utilization in the Oil Sands Mining and Upgrading segment, and strong drilling results in the North America Exploration and Production segment. The increase in crude oil and NGLs production before royalties for the third quarter of 2025 from the second quarter of 2025 primarily reflected strong utilization in the Oil Sands Mining and Upgrading segment following the completion of the planned turnaround at the non-operated Scotford Upgrader ("Scotford") in the second quarter, combined with the acquisitions completed in the second and third quarters of 2025 in the North America Exploration and Production segment.

Annual crude oil and NGLs production for 2025 is now targeted to average between 1,137,000 bbl/d and 1,151,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Natural gas production before royalties for the nine months ended September 30, 2025 averaged 2,510 MMcf/d, an increase of 19% from 2,102 MMcf/d for the nine months ended September 30, 2024. Natural gas production before royalties for the third quarter of 2025 averaged 2,668 MMcf/d, an increase of 30% from 2,049 MMcf/d for the third quarter of 2024 and an increase of 11% from 2,407 MMcf/d for the second quarter of 2025. The increase in natural gas production before royalties for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the acquisitions completed in December 2024 and during the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets, partially offset by natural field declines.

Annual natural gas production for 2025 is now targeted to average between 2,535 MMcf/d and 2,575 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 nine months ended September 30, 2025 averaged 563,977 bbl/d, an increase of 12% from 501,674 bbl/d for the nine months ended September 30, 2024. North America crude oil and NGLs production before royalties for the third quarter of 2025 of 584,625 bbl/d increased 17% from 499,772 bbl/d for the third quarter of 2024 and increased 7% from 545,811 bbl/d for the second quarter of 2025. The increase in North America crude oil and NGLs production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, and strong drilling results from heavy oil multilaterals, liquids-rich natural gas, and light oil, partially offset by natural field declines. The increase in North America crude oil and NGLs production for the third quarter of 2025 from the second quarter of 2025 primarily reflected the acquisitions completed in the second and third quarters of 2025, partially offset by natural field declines.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 274,752 bbl/d for the third quarter of 2025, comparable with 271,551 bbl/d for the third quarter of 2024 and 274,789 bbl/d for the second quarter of 2025.

Pelican Lake heavy crude oil production before royalties for the third quarter of 2025 averaged 42,070 bbl/d, a decrease of 7% from 45,101 bbl/d for the third quarter of 2024 reflecting Pelican Lake's long life low decline production and planned maintenance activities. Pelican Lake heavy crude oil production before royalties for the third quarter of 2025 was comparable with 43,078 bbl/d for the second quarter of 2025.

North America natural gas production before royalties for the nine months ended September 30, 2025 averaged 2,498 MMcf/d, an increase of 19% from 2,091 MMcf/d for the nine months ended September 30, 2024. Natural gas production before royalties averaged 2,658 MMcf/d for the third quarter of 2025, an increase of 30% from 2,039 MMcf/d for the third quarter of 2024 and an increase of 11% from 2,398 MMcf/d for the second quarter of 2025. The increase in natural gas production before royalties for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the acquisitions completed in December 2024 and during the second and third quarters of 2025, and strong drilling results in the Company's liquids-rich natural gas assets, partially offset by natural field declines.

SCO production before royalties for the nine months ended September 30, 2025 averaged 546,635 bbl/d, an increase of 21% from 451,298 bbl/d for the nine months ended September 30, 2024. SCO production before royalties for the third quarter of 2025 averaged 581,136 bbl/d, an increase of 17% from 497,656 bbl/d for the third quarter of 2024 and an increase of 25% from 463,808 bbl/d for the second quarter of 2025. The increase in SCO production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, combined with high utilization. The increase in SCO production for the third quarter of 2025 from the second quarter of 2025 primarily reflected strong utilization following the completion of the planned turnaround at Scotford in the second quarter.

International crude oil and NGLs production before royalties for the nine months ended September 30, 2025 averaged 12,247 bbl/d, a decrease of 50% from 24,293 bbl/d for the nine months ended September 30, 2024. International crude oil and NGLs production before royalties for the third quarter of 2025 averaged 9,843 bbl/d, a decrease of 59% from 24,144 bbl/d for the third quarter of 2024 and comparable with 9,530 bbl/d for the second quarter of 2025. The decrease in International crude oil and NGLs production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the temporary suspension of production at Baobab in Offshore Africa due to planned maintenance on its FPSO, which is expected to return to service in the second quarter of 2026, planned North Sea abandonments conducted as part of the previously announced decommissioning plans, and natural field declines.

(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 decreased 5% to average $73.40 per bbl for the nine months ended September 30, 2025 from $77.06 per bbl for the nine months ended September 30, 2024. North America realized crude oil and NGLs prices averaged $72.35 per bbl for the third quarter of 2025, a decrease of 6% from $77.29 per bbl for the third quarter of 2024 and an increase of 4% from $69.30 per bbl for the second quarter of 2025. The decrease in North America realized crude oil and NGLs prices per bbl for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower WTI benchmark pricing, partially offset by a narrowing of the WCS Heavy Differential. The increase in North America realized crude oil and NGLs prices per bbl for the third quarter of 2025 from the second quarter of 2025 reflected prevailing benchmark pricing, and product sales mix. Realized crude oil and NGLs pricing is also directly impacted by fluctuations in foreign exchange rates as sales prices are primarily denominated with reference to US dollar benchmarks. The Company continues to focus on its crude oil blending marketing strategy and in the third quarter of 2025 contributed approximately 228,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 33% to average $2.32 per Mcf for the nine months ended September 30, 2025 from $1.75 per Mcf for the nine months ended September 30, 2024. North America realized natural gas prices increased 22% to average $1.45 per Mcf for the third quarter of 2025 from $1.19 per Mcf for the third quarter of 2024 and decreased 43% from $2.54 per Mcf for the second quarter of 2025. The increase in North America realized natural gas prices per Mcf for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected higher benchmark pricing. The decrease for the third quarter of 2025 from the second quarter of 2025 reflected lower 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 9% to average $102.18 per bbl for the nine months ended September 30, 2025 from $112.14 per bbl for the nine months ended September 30, 2024. International realized crude oil and NGLs prices decreased 14% to average $94.08 per bbl for the third quarter of 2025 from $109.41 per bbl for the third quarter of 2024 and increased 3% from $91.00 per bbl for the second quarter of 2025. 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, 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 three and nine months ended September 30, 2025 and the comparable periods reflected movements in benchmark commodity prices, fluctuations in the WCS Heavy Differential and the impact of sliding scale royalty rates.

Crude oil and NGLs royalty rates(1) averaged approximately 17% of product sales for the nine months ended September 30, 2025 compared with 20% of product sales for the nine months ended September 30, 2024. Crude oil and NGLs royalty rates averaged approximately 18% of product sales for the third quarter of 2025 compared with 20% for the third quarter of 2024 and 13% for the second quarter of 2025. The decrease in royalty rates for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected prevailing benchmark pricing and the impact of sliding scale royalty rates. The increase in royalty rates for third quarter of 2025 from the second quarter of 2025 primarily reflected higher bitumen pricing and the impact of sliding scale royalty rates.

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

Natural gas royalty rates averaged approximately 3% of product sales for the nine months ended September 30, 2025 compared with 2% of product sales for the nine months ended September 30, 2024. Natural gas royalty rates averaged approximately 2% of product sales for the third quarter of 2025 compared with 1% for the third quarter of 2024 and 3% for the second quarter of 2025. The fluctuations in royalty rates for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected prevailing 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 nine months ended September 30, 2025 compared with 5% of product sales for the nine months ended September 30, 2024. Royalty rates as a percentage of product sales averaged approximately 5% for the third quarter of 2025 compared with 5% of product sales for the third quarter of 2024 and 5% for the second quarter of 2025. Royalty rates as a percentage of product sales reflected the timing of liftings, and the status of payout in the various fields.

(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 nine months ended September 30, 2025 averaged $12.17 per bbl, a decrease of 8% from $13.17 per bbl for the nine months ended September 30, 2024. North America crude oil and NGLs production expense for the third quarter of 2025 of $11.97 per bbl decreased 3% from $12.36 per bbl for the third quarter of 2024 and was comparable with $11.89 per bbl for the second quarter of 2025. The decrease in crude oil and NGLs production expense per bbl for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower fuel costs.

North America natural gas production expense for the nine months ended September 30, 2025 averaged $1.12 per Mcf, a decrease of 9% from $1.23 per Mcf for the nine months ended September 30, 2024. North America natural gas production expense for the third quarter of 2025 of $1.14 per Mcf decreased 7% from $1.23 per Mcf for the third quarter of 2024 and increased 7% from $1.07 per Mcf for the second quarter of 2025. The decrease in natural gas production expense per Mcf for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected higher production volumes. The increase in natural gas production expense per Mcf for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher energy and service costs.

International crude oil and NGLs production expense for the nine months ended September 30, 2025 averaged $106.02 per bbl, an increase of 80% from $59.04 per bbl for the nine months ended September 30, 2024. International crude oil and NGLs production expense for the third quarter of 2025 of $134.12 per bbl increased 158% from $52.04 per bbl for the third quarter of 2024 and decreased 24% from $175.70 per bbl for the second quarter of 2025. The increase in crude oil and NGLs production expense per bbl for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected activities at Ninian in the pre-cessation period, the timing of liftings from various fields that have different cost structures, and the impact of foreign exchange. The decrease in crude oil and NGLs production expense per bbl for the third quarter of 2025 from the second quarter of 2025 primarily reflected the timing of liftings from various fields that have different cost structures.

(1)The Company is progressing its abandonment and decommissioning activities in the North Sea, including the tendering and awarding of contracts for the Ninian South Platform. Following a competitive bidding process in 2025, cost estimates have come in higher than originally budgeted. As a result, the Company has reviewed and updated estimates for abandonment and decommissioning costs for its North Sea assets, including the Ninian Central and South Platforms and T‑Block (comprising the Tiffany, Toni, and Thelma fields). In addition, based on current and forecasted economic conditions, including commodity pricing and market egress for T‑Block volumes, the Company has determined that the T-Block assets are no longer economically viable. During the third quarter of 2025, the Company recognized a recoverability charge of $1,258 million in depletion, depreciation and amortization expense related to its North Sea assets.

(2)In connection with the Company's notice of withdrawal from Block 11B/12B in South Africa in the second quarter of 2024, the Company derecognized $62 million of exploration and evaluation assets through depletion, depreciation and amortization expense.

(3)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.

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

Adjusted depletion, depreciation and amortization expense for the nine months ended September 30, 2025 averaged $13.10 per BOE, comparable with $12.89 per BOE for the nine months ended September 30, 2024. Adjusted depletion, depreciation and amortization expense for the third quarter of 2025 averaged $13.08 per BOE, comparable with $13.27 per BOE for the third quarter of 2024 and $12.94 per BOE for the second quarter of 2025.

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

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the nine months ended September 30, 2025 averaged $0.78 per BOE, a decrease of 19% from $0.96 per BOE for the nine months ended September 30, 2024. Asset retirement obligation accretion expense for the third quarter of 2025 averaged $0.77 per BOE, a decrease of 21% from $0.97 per BOE for the third quarter of 2024 and a decrease of 3% from $0.79 per BOE for the second quarter of 2025. The decrease in asset retirement obligation accretion expense per BOE for the three and nine months ended September 30, 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 2025, partially offset by revisions in cost and timing estimates at December 31, 2024. The decrease in asset retirement obligation accretion expense per BOE for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher sales volumes.

The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 581,136 bbl/d in the third quarter of 2025 primarily reflecting strong utilization in the Oil Sands Mining and Upgrading segment.

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

(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 $90.45 per bbl for the nine months ended September 30, 2025, a decrease of 9% from $99.19 per bbl for the nine months ended September 30, 2024. The realized SCO sales price averaged $87.85 per bbl for the third quarter of 2025, a decrease of 13% from $100.93 per bbl for the third quarter of 2024 and comparable with $87.22 per bbl for the second quarter of 2025. The decrease in realized SCO sales price per bbl for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower WTI benchmark pricing.

The fluctuations in bitumen royalties per bbl in any particular period reflect prevailing bitumen value for royalty purposes, and the impact of sliding scale royalty rates. The fluctuations in bitumen royalties per bbl for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the changes in average bitumen value for royalty purposes.

Transportation expense averaged $3.59 per bbl for the nine months ended September 30, 2025, an increase of 37% from $2.62 per bbl for the nine months ended September 30, 2024. Transportation expense averaged $3.86 per bbl for the third quarter of 2025, an increase of 16% from $3.34 per bbl for the third quarter of 2024 and an increase of 3% from $3.73 per bbl for the second quarter of 2025. The increase in transportation expense per bbl for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher volumes shipped on the TMX pipeline in 2025. The increase in transportation expense per bbl for the third quarter of 2025 from the third quarter of 2024 and the second quarter of 2025 reflected the Company's commitments on egress pipelines, combined with higher volumes shipped on the TMX pipeline and to the US Gulf Coast.

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

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

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

Production expense for the nine months ended September 30, 2025 averaged $22.98 per bbl, a decrease of 3% from $23.64 per bbl for the nine months ended September 30, 2024. Production expense for the third quarter of 2025 averaged $21.29 per bbl, comparable with $20.67 per bbl for the third quarter of 2024 and a decrease of 20% from $26.53 per bbl for the second quarter of 2025. The decrease in production expense per bbl for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher production volumes from the acquisition of the additional 20% working interest in AOSP in December 2024. The decrease in production expense per bbl for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher production volumes from strong utilization and lower fuel costs.

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

Depletion, depreciation and amortization expense for the nine months ended September 30, 2025 averaged $13.49 per bbl, comparable with $13.33 per bbl for the nine months ended September 30, 2024. Depletion, depreciation and amortization expense for the third quarter of 2025 of $13.38 per bbl increased 9% from $12.27 per bbl for the third quarter of 2024 and decreased 11% from $14.96 per bbl for the second quarter of 2025. The increase in depletion, depreciation and amortization expense per bbl for the third quarter of 2025 from the third quarter of 2024 primarily reflected a higher depletable base due to asset additions, partially offset by higher sales volumes. The decrease in depletion, depreciation and amortization expense per bbl for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher sales volumes in the third quarter.

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

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the nine months ended September 30, 2025 of $0.43 per bbl decreased 16% from $0.51 per bbl for the nine months ended September 30, 2024. Asset retirement obligation accretion expense for the third quarter of 2025 of $0.40 per bbl decreased 13% from $0.46 per bbl for the third quarter of 2024 and decreased 22% from $0.51 per bbl for the second quarter of 2025. The decrease in asset retirement obligation accretion expense per bbl for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the impact of higher sales volumes.

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 third quarter of 2025, production of ultra-low sulphur diesel and other refined products averaged 38,434 BOE/d (9,608 BOE/d to the Company) (three months ended June 30, 2025 – 60,549 BOE/d; 15,137 BOE/d to the Company; three months ended September 30, 2024 – 72,109 BOE/d; 18,027 BOE/d to the Company), reflecting the successful completion of the planned turnaround in the third quarter, and the Company's 25% toll payer commitment.

As at September 30, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $483 million (December 31, 2024 – $509 million). For the three months ended September 30, 2025, the Company's recovery of its share of unrecognized equity losses was $21 million (three months ended June 30, 2025 – recovery of unrecognized equity losses of $24 million; nine months ended September 30, 2025 – recovery of unrecognized equity losses of $26 million; three months ended September 30, 2024 – recovery of unrecognized equity losses of $6 million; nine months ended September 30, 2024 – recovery of unrecognized equity losses of $45 million).

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

(2)Total Company sales volumes.

Administration expense for the nine months ended September 30, 2025 of $1.08 per BOE increased 4% from $1.04 per BOE for the nine months ended September 30, 2024. Administration expense for the third quarter of 2025 of $1.03 per BOE was comparable with $1.02 per BOE for the third quarter of 2024 and decreased 12% from $1.17 per BOE for the second quarter of 2025. The increase in administration expense per BOE for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher personnel costs, partially offset by higher overhead recoveries and higher sales volumes. The decrease in administration expense per BOE for the third quarter of 2025 from the second quarter of 2025 primarily reflected 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 $97 million of share-based compensation expense for the nine months ended September 30, 2025 primarily as a result of changes in the Company's share price, 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, and the impact of vested stock options exercised or surrendered during the period.

(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 nine months ended September 30, 2025 increased 12% to $1.40 per BOE from $1.25 per BOE for the nine months ended September 30, 2024. Interest and other financing expense for the third quarter of 2025 decreased 50% to $0.62 per BOE from $1.24 per BOE for the third quarter of 2024 and decreased 66% from $1.84 per BOE for the second quarter of 2025. The increase in interest and other financing expense per BOE for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher average debt levels, including higher floating rate debt levels, partially offset by higher sales volumes. The decrease in interest and other financing expense per BOE for the third quarter of 2025 from the third quarter of 2024 and second quarter of 2025 primarily reflected interest on the deferred PRT and corporate tax recoveries in the North Sea.

The Company's average effective interest rate for the three and nine months ended September 30, 2025 averaged 5.2% and 5.1%, respectively, an increase from the comparable periods in 2024, reflecting higher floating rate long-term debt held during 2025.

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.