Canadian Natural's President, Scott Stauth, commented on the Company's second quarter results, "Our relentless focus on continuous improvement combined with effective and efficient operations drove strong performance year to date in 2025. Our ability to effectively allocate capital across our strong asset base provides us with a competitive advantage. This ability, combined with accretive acquisitions, creates significant long-term value for our shareholders. Our culture of accountability and the strength of our assets is a unique advantage that results in both capital and operating cost savings and maximizes value for our shareholders.

We successfully completed a planned turnaround at our Athabasca Oil Sands Project ("AOSP") in Q2/25, five days ahead of schedule and on budget. Production and upgrader utilization at Horizon and AOSP, before and after the turnaround, was high, driven by strong performance on our Reliability Enhancement and debottlenecking projects. In July 2025, Oil Sands Mining and Upgrading Synthetic Crude Oil ("SCO") production averaged approximately 602,000 bbl/d with upgrader utilization of 106%, and we expect the second half of 2025 to continue to deliver strong operating results.

In Q2/25, despite the turnaround at AOSP which reduced production levels in the quarter by approximately 120,000 bbl/d, we achieved quarterly production volumes totaling approximately 1,420 MBOE/d, including liquids production of 1,019 Mbbl/d and natural gas production of 2,407 MMcf/d. Total corporate production on a BOE basis in Q2/25 was up approximately 135,000 BOE/d from Q2/24 levels, reflecting opportunistic acquisitions and organic growth across our asset base achieved in the last 12 months.

We continue to achieve strong results from our drilling programs across our Conventional assets as we are realizing capital efficiencies, resulting in high levels of activity without increased capital. This includes our multilateral heavy crude oil program where we are targeting to drill 26 more wells in 2025 than originally budgeted. Importantly, the low operating costs on these multilateral wells drive strong returns on capital, adding significant value.

On our recently acquired Duvernay assets, we continue to see reductions on both capital and operating costs supporting execution of organic growth opportunities. We are realizing more value than we planned at the time of the acquisition. This is being achieved through our commitment to continuous improvement and a strong team culture that focuses on improving our operating costs. In Q2/25, we had strong operating costs in the Duvernay of $8.43/BOE, a decrease of 11% from Q1/25 levels of $9.52/BOE.

On June 26, 2025, we closed an acquisition of lands and production in the Palliser Block located in southern Alberta. We had budgeted to close the Palliser Block acquisition on March 1, 2025, which would have added production volumes of approximately 50,000 BOE/d, including 20,000 bbl/d of Mannville light crude oil and NGLs, in Q2/25. This acquisition and production was included in our original 2025 capital budget and production guidance, but due to this delayed closing in late June 2025, added only 2,000 BOE/d to our production levels for Q2/25. This acquisition also included approximately 1.1 million net acres of high quality land, with currently identified significant light crude oil inventory on the lands of approximately 850 locations.

Subsequent to quarter end, on July 2, 2025, we closed an acquisition of liquids-rich Montney assets located in the Grande Prairie area of northern Alberta for approximately $750 million with production from the acquisition of approximately 32,000 BOE/d, including 12,500 bbl/d of NGLs. Our original 2025 capital budget and production guidance did not include this acquisition. These assets are directly adjacent to our existing core Montney assets, providing opportunities for synergies while adding approximately 120,000 net acres of high quality land with currently identified significant liquids-rich inventory of approximately 150 locations."

Canadian Natural's Chief Financial Officer, Victor Darel, added "In Q2/25, we generated adjusted net earnings of $1.5 billion or $0.71 per share, and adjusted funds flow of $3.3 billion or $1.56 per share. We returned approximately $1.6 billion to our shareholders in the quarter, including $1.2 billion in dividends and $0.4 billion in share repurchases.

Our business model is robust and sustainable, resulting in a top tier WTI breakeven in the low to mid-US$40 per barrel range at which prices we generate the adjusted funds flow required to cover both maintenance capital levels and dividends. Our balance sheet remains strong with liquidity of approximately $4.8 billion as at June 30, 2025, providing significant flexibility.

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

(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 six months ended June 30, 2025 dated August 6, 2025.

(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2025 dated August 6, 2025.

(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 for the three and six months ended June 30, 2025 dated August 6, 2025.

(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.

▪The strength of Canadian Natural's long life low decline asset base, supported by safe, reliable, effective and efficient operations, makes our business unique, robust and sustainable. In Q2/25, the Company generated strong financial results, including:

•Net earnings of approximately $2.5 billion and adjusted net earnings from operations of approximately $1.5 billion.

•Cash flows from operating activities of approximately $3.1 billion.

•Adjusted funds flow of approximately $3.3 billion.

▪Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $4.8 billion in liquidity(1) as at June 30, 2025.

•Subsequent to quarter end, the Company repaid US$600 million of US dollar debt securities due in July 2025.

•Subsequent to quarter end, Canadian Natural received a new long-term investment grade credit rating of BBB+ from Fitch Ratings. Canadian Natural's existing long-term credit ratings are A (low) from DBRS, Baa1 from Moody's and BBB- from S&P.

(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the Company's MD&A for the three and six months ended June 30, 2025 dated August 6, 2025.

▪Canadian Natural continues to focus on safe, reliable, effective and efficient operations, delivering strong quarterly average production of 1,420,358 BOE/d in Q2/25, consisting of total liquids production of 1,019,149 bbl/d and natural gas production of 2,407 MMcf/d. Total BOE production in Q2/25 is approximately 10% higher than Q2/24 levels, reflecting both opportunistic acquisitions and organic growth completed over the last 12 months.

•Oil Sands Mining and Upgrading production averaged 463,808 bbl/d of SCO in Q2/25, an increase of 13% from Q2/24 levels. The increase is a result of the Reliability Enhancement Project, eliminating the need for a turnaround at Horizon in 2025, and the Scotford Upgrader debottleneck which were completed in 2024, combined with the additional 20% working interest in AOSP acquired in December 2024, partially offset by the Q2/25 turnaround at AOSP completed successfully and five days ahead of schedule in the quarter.

◦Subsequent to quarter end, July 2025 Oil Sands Mining and Upgrading production averaged approximately 602,000 bbl/d with upgrader utilization of 106%, and the Company expects the second half of 2025 to continue to deliver strong operating results.

•Canadian Natural’s highly successful multilateral drilling program continues to unlock opportunity on the Company’s extensive, high quality land throughout our primary heavy crude oil assets of approximately 3.0 million net acres.

◦As a result of capital efficiencies achieved across the Company and our deep inventory of high return opportunities, Canadian Natural is now targeting to drill 182 net primary heavy crude oil multilateral wells in 2025, 26 more wells than in the original budget and an increase of approximately 60 wells or 50% from 2024 drilling levels.

◦Increasing well counts and optimized well designs continue to deliver strong results with average peak rates of approximately 230 bbl/d per well achieved from these multilateral wells in the first six months of 2025.

•On the liquids-rich Duvernay assets, Canadian Natural continues to achieve strong performance as the Company applies to these assets its continuous improvement culture, effective and efficient operations and area expertise.

◦Our extended well lengths, which on average are 20% longer than 2024 lengths and optimized completions designs, combined with strong execution continues to lower development costs. On a length normalized basis, combined drilling and completion costs for 2025 are now targeting an improvement of approximately 16% or $2.0 million per well lower compared to 2024 costs, a further improvement of $0.2 million per well compared to Q1/25 levels.

◦As a result of operating synergies and our focus on continuous improvement, the Company achieved strong operating costs in our first six months of operating the Duvernay assets, averaging $8.43/BOE in Q2/25, a decrease of 11% compared to Q1/25 levels of $9.52/BOE.

▪On June 26, 2025, Canadian Natural closed an acquisition of lands and production in the Palliser Block located in southern Alberta. The Company had budgeted to close the Palliser Block acquisition on March 1, 2025, which would have added production volumes of approximately 50,000 BOE/d, including 20,000 bbl/d of Mannville light crude oil and NGLs, in Q2/25. This acquisition and production was included in the Company's original 2025 capital budget and production guidance, but due to this delayed closing in late June 2025, added only 2,000 BOE/d to production levels in Q2/25. This acquisition also included approximately 1.1 million net acres of high quality land, with currently identified significant light crude oil inventory on the lands of approximately 850 locations.

▪Subsequent to quarter end, on July 2, 2025, Canadian Natural closed an acquisition of liquids-rich Montney assets located in the Grande Prairie area of northern Alberta for approximately $750 million with production from the acquisition of approximately 32,000 BOE/d, including 12,500 bbl/d of NGLs. The Company's original 2025 capital budget and production guidance did not include this acquisition. These assets are directly adjacent to the Company's existing core Montney assets, providing opportunities for synergies while adding approximately 120,000 net acres of high quality land with currently identified significant liquids-rich inventory of approximately 150 locations.

▪Canadian Natural plans to update our annual 2025 corporate production guidance and capital forecast upon closing of the AOSP swap, which is targeted for Q3/25.

▪Concurrent with the closing of the Chevron acquisition in December 2024 the Company revised its free cash flow policy to be 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, up from the previous target of $10 billion, free cash flow allocation will be 100% to shareholder returns.

▪Due to accretive acquisitions completed in late 2024 and 2025 year to date and strong operational results, Canadian Natural targets to provide similar shareholder returns in 2025 as compared to 2024. This is targeted to be achieved despite only allocating 60% of free cash flow in 2025 to shareholder returns as compared to allocating 100% of free cash flow in 2024 to shareholder returns. These shareholder returns in 2025 will be as a result of the previously announced dividend increase in Q1/25 and continuation of Canadian Natural’s share buyback program throughout the year. In addition, Canadian Natural targets to reduce its year end 2025 net debt levels by approximately $2 billion from year end 2024 levels.

▪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 Q2/25 were strong, totaling approximately $1.6 billion, comprised of $1.2 billion of dividends and $0.4 billion through the repurchase and cancellation of approximately 8.6 million common shares at a weighted average price of $41.46 per share.

•Year to date in 2025, up to and including August 6, 2025, the Company has returned a total of approximately $4.6 billion directly to shareholders through $3.6 billion in dividends and $1.0 billion through the repurchase and cancellation of approximately 22.4 million common shares at a weighted average price of $42.76 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 October 3, 2025 to shareholders of record at the close of business on September 19, 2025.

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

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

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

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

(1)Includes bitumen wells.

▪Canadian Natural drilled a total of 197 net crude oil and natural gas producer wells in the first six months of 2025, 32 more than in the first six months of 2024.

▪North America E&P liquids production, excluding thermal in situ, averaged 271,022 bbl/d in Q2/25, an increase of 17% or approximately 40,000 bbl/d from Q2/24 levels, reflecting production volumes from the Duvernay assets acquired in December 2024, along with strong organic growth from our heavy crude oil multilateral wells as well as liquids-rich natural gas and light crude oil assets.

•Primary heavy crude oil production averaged 87,288 bbl/d in Q2/25, an increase of 10% from Q2/24 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 the Company’s extensive, high quality land throughout our primary heavy crude oil assets of approximately 3.0 million net acres.

–As a result of capital efficiencies achieved across the Company and our deep inventory of high return opportunities, Canadian Natural is now targeting to drill 182 net primary heavy crude oil multilateral wells in 2025, 26 more wells than in the original budget and an increase of approximately 60 wells or 50% from 2024 drilling levels.

–Increasing well counts and optimized well designs continue to deliver strong results with average peak rates of approximately 230 bbl/d per well achieved in the first six months of 2025.

◦Operating costs in the Company's primary heavy crude oil operations averaged $17.44/bbl (US$12.60/bbl) in Q2/25, comparable to Q2/24 levels.

•Pelican Lake production averaged 43,078 bbl/d in Q2/25 a decrease of 4% from Q2/24 levels, reflecting low natural field declines from this long life low decline asset.

◦Operating costs at Pelican Lake averaged $9.01/bbl (US$6.51/bbl) in Q2/25, comparable to Q2/24 levels.

•North America light crude oil and NGLs production averaged 140,656 bbl/d in Q2/25, an increase of 31% or approximately 33,000 bbl/d compared to Q2/24 levels, primarily driven by the Duvernay assets acquired in December 2024 and strong drilling results across our liquids-rich natural gas assets.

◦Operating costs in the Company's North America light crude oil and NGLs operations averaged $10.94/bbl (US$7.90/bbl) in Q2/25, a decrease of 20% from Q2/24 levels of $13.75/bbl, primarily reflecting higher production volumes.

◦On the liquids-rich Duvernay assets, Canadian Natural continues to achieve strong performance as the Company applies to these assets its continuous improvement culture, effective and efficient operations and area expertise.

–Our extended well lengths, which on average are 20% longer than 2024 lengths and optimized completions designs, combined with strong execution continues to lower development costs. On a length normalized basis, combined drilling and completion costs for 2025 are now targeting an improvement of approximately 16% or $2.0 million per well lower compared to 2024 costs, a further improvement of $0.2 million per well compared to Q1/25 levels.

–As a result of operating synergies and our focus on continuous improvement, the Company achieved strong operating costs in our first six months of operating the Duvernay assets, averaging $8.43/BOE in Q2/25, a decrease of 11% compared to Q1/25 levels of $9.52/BOE.

–The Company is targeting to drill 43 gross wells in the Duvernay as part of the 2025 capital development program and remains on track to achieve budget production of approximately 60,000 BOE/d, with an average initial rate of approximately 1,600 BOE/d per well year to date.

▪North America natural gas production averaged 2,398 MMcf/d in Q2/25, an increase of 14% from Q2/24 levels, driven by strong drilling results in the Company's liquids-rich Montney, Duvernay and Deep Basin natural gas assets.

•North America natural gas operating costs averaged $1.07/Mcf in Q2/25, a decrease of 10% from Q2/24 levels of $1.19/Mcf, primarily reflecting higher production volumes and cost efficiencies.

▪Thermal in situ production averaged 274,789 bbl/d in Q2/25, an increase of 3% from Q2/24 levels, reflecting strong results from the recent pad additions at Primrose, partially offset by natural field declines and impacts from wildfires.

•Thermal in situ operating costs remain strong, averaging $11.05/bbl (US$7.98/bbl) in Q2/25, comparable to Q2/24 levels.

▪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 is targeting to begin drilling a Cyclic Steam Stimulation ("CSS") pad in late Q3/25 with production targeted to come on in 2026.

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

•At Kirby, the Company is targeting to bring the recently drilled five well pair SAGD pad on production in Q4/25.

•At Pike, the Company has completed drilling two SAGD pads, which will be tied into existing Jackfish facilities and targets to keep the Jackfish plants at full capacity. The first of these two pads is targeted to come on production in Q1/26 and the second 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 Company's commercial scale solvent SAGD pad at Kirby North, we began solvent injection in June 2024. In Q2/25, we executed workovers on two well pairs to enhance SORs, solvent recovery and production trends, which we will continue to monitor over the coming months.

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

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

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

▪Oil Sands Mining and Upgrading production averaged 463,808 bbl/d of SCO in Q2/25, an increase of 13% from Q2/24 levels. The increase is a result of the Reliability Enhancement Project, eliminating the need for a turnaround at Horizon in 2025, and the Scotford Upgrader debottleneck which were completed in 2024, combined with the additional 20% working interest in AOSP acquired in December 2024, partially offset by the Q2/25 turnaround at AOSP completed successfully and five days ahead of schedule in the quarter.

•Subsequent to quarter end, July 2025 Oil Sands Mining and Upgrading production averaged approximately 602,000 bbl/d with upgrader utilization of 106%, and the Company expects the second half of 2025 to continue to deliver strong operating results.

•Oil Sands Mining and Upgrading operating costs averaged $26.53/bbl (US$19.17/bbl) of SCO in Q2/25, an increase of 2% from Q2/24 levels, reflecting the AOSP turnaround in Q2/25.

▪Oil Sands Mining and Upgrading continues to outperform our expectations following both the Reliability Enhancement Project at Horizon and the debottlenecking at AOSP that were completed in 2024, driving high utilization and industry leading operating costs.

•At Horizon, the Reliability Enhancement Project increased the capacity of zero decline, high value SCO production to 264,000 bbl/d over a two year timeframe by shifting the planned turnarounds to once every two years from the previous annual cycle. As a result, 2025 is the first year without a planned turnaround, resulting in high targeted utilization. With enhanced infrastructure now in place, the Company can perform certain maintenance activities with zero production impact.

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

▪International E&P crude oil production volumes averaged 9,530 bbl/d in Q2/25, a decrease of 60% compared to Q2/24 levels. The decrease reflects temporary suspension of production at Baobab in Offshore Africa due to the planned life extension project on its floating production storage and offloading ("FPSO") vessel, as well as maintenance and decommissioning activities in the North Sea and natural field declines.

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

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

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

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

(4)Excludes risk management activities.

(5)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2025 dated August 6, 2025.

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

▪WTI prices averaged US$63.71/bbl in Q2/25, decreases of US$7.71/bbl and US$16.84/bbl from Q1/25 and Q2/24 levels respectively. The decreases reflect weaker global demand outlooks amid ongoing trade and tariff uncertainty, combined with larger than expected OPEC+ output hikes in Q2/25.

▪SCO pricing averaged US$64.69/bbl in Q2/25, representing a US$0.98/bbl premium to WTI pricing, compared to a US$2.35/bbl discount to WTI in Q1/25 and a US$2.78 discount to WTI in Q2/24. The SCO differential strengthened in Q2/25 relative to the comparable periods, primarily driven by lower production levels in the Western Canadian Sedimentary Basin ("WCSB") as a result of maintenance activities that took place in Q2/25.

▪The WCS differential to WTI continued to narrow in Q2/25, averaging US$10.19/bbl, representing a US$2.47/bbl improvement from Q1/25 and a US$3.35/bbl improvement from Q2/24. The tighter WCS differential reflects the start-up of the Trans Mountain Expansion ("TMX") pipeline in Q2/24, which has brought structural change to the Canadian oil market by increasing egress, reducing price volatility and diversifying market access. The narrowing of the WCS differential in Q2/25 also reflects stronger United States Gulf Coast ("USGC") heavy crude oil pricing and production impacts in the WCSB as a result of maintenance activities and shut-in production from wildfires that occurred in Q2/25.

▪The North West Redwater refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 60,549 bbl/d in Q2/25, reflecting a turnaround that commenced in Q2/25.

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

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

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

▪AECO natural gas prices averaged $1.97/GJ in Q2/25, an increase of $0.61/GJ from Q2/24 and a $0.05/GJ increase from Q1/25. The increase in AECO natural gas pricing compared to Q2/24 primarily reflects stronger NYMEX benchmark pricing combined with increased exports out of the WCSB.

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

▪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 uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including tariffs imposed or announced by the US government on certain goods and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded to additional goods); uncertainty in the regulatory framework governing greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps; 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; 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.

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 six months ended June 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 six months ended June 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 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 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 August 6, 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. 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 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 six months ended June 30, 2025 dated August 6, 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 June 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 six months ended June 30, 2025 dated August 6, 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 six months ended June 30, 2025 dated August 6, 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 budget reflects budgeted net capital expenditures, before abandonment expenditures related to the execution of the Company's abandonment and reclamation programs in North America and the North Sea. The Company currently carries an Asset Retirement Obligation ("ARO") liability on its balance sheet for these budgeted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries. Current tax recoveries are refundable at a rate of approximately 23% in Canada and a combined current income tax and Petroleum Revenue Tax ("PRT") rate approximating 70% to 75% in the UK portion of the North Sea. The Company is eligible to recover interest on refunded PRT previously paid.

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

Canadian Natural Resources Limited (TSX-CNQ / NYSE-CNQ) will be issuing its 2025 Second Quarter Earnings Results on Thursday, August 7, 2025 before market open.

A conference call will be held at 9:00 a.m. MDT / 11:00 a.m. EDT on Thursday, August 7, 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: 26234#)

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 uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including tariffs imposed or announced by the US government on certain goods and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded to additional goods); uncertainty in the regulatory framework governing greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps; 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; 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.

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 six months ended June 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 six months ended June 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 six months ended June 30, 2025 in relation to the comparable periods in 2024 and the first 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 August 6, 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 six months ended June 30, 2025 were $4,917 million compared with $2,702 million for the six months ended June 30, 2024. Net earnings for the six months ended June 30, 2025 included non-operating income, net of tax, of $985 million compared with non-operating losses of $664 million for the six months ended June 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, 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 six months ended June 30, 2025 were $3,932 million compared with $3,366 million for the six months ended June 30, 2024.

Net earnings for the second quarter of 2025 were $2,459 million compared with $1,715 million for the second quarter of 2024 and $2,458 million for the first quarter of 2025. Net earnings for the second quarter of 2025 included non-operating income, net of tax, of $963 million compared with non-operating losses of $177 million for the second quarter of 2024 and non-operating income of $22 million for the first 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 loss from investments, the gain on acquisition, 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 second quarter of 2025 were $1,496 million compared with $1,892 million for the second quarter of 2024 and $2,436 million for the first quarter of 2025.

The movements in net earnings and adjusted net earnings from operations for the three and six months ended June 30, 2025 from the three and six months ended June 30, 2024 primarily reflected:

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

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

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

partially offset by:

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

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

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

▪lower realized SCO pricing and sales volumes in the Oil Sands Mining and Upgrading segment, and

▪lower realized crude oil and NGLs pricing and 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 (gain) loss, gain on acquisition, and the loss (gain) from investments also contributed to fluctuations in net earnings from the comparable periods. These items are discussed in detail in the relevant sections of this MD&A.

Cash flows from operating activities for the six months ended June 30, 2025 were $7,398 million compared with $6,952 million for the six months ended June 30, 2024. Cash flows from operating activities for the second quarter of 2025 were $3,114 million compared with $4,084 million for the second quarter of 2024 and $4,284 million for the first 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 six months ended June 30, 2025 was $7,792 million compared with $6,752 million for the six months ended June 30, 2024. Adjusted funds flow for the second quarter of 2025 was $3,262 million compared with $3,614 million for the second quarter of 2024 and $4,530 million for the first 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, accrued interest on Petroleum Revenue Tax ("PRT") recoveries, and prepaid cost of service tolls.

Crude oil and NGLs production before royalties for the second quarter of 2025 of 1,019,149 bbl/d increased 9% from 934,066 bbl/d for the second quarter of 2024 and decreased 13% from 1,173,804 bbl/d for the first quarter of 2025. Natural gas production before royalties for the second quarter of 2025 of 2,407 MMcf/d increased 14% from 2,110 MMcf/d for the second quarter of 2024 and was comparable with 2,451 MMcf/d for the first quarter of 2025. Total production before royalties for the second quarter of 2025 of 1,420,358 BOE/d increased 10% from 1,285,798 BOE/d for the second quarter of 2024 and decreased 10% from 1,582,348 BOE/d for the first 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 $69.58 per bbl for the second quarter of 2025, a decrease of 20% from $86.64 per bbl for the second quarter of 2024 and a decrease of 13% from $79.85 per bbl for the first quarter of 2025. The realized natural gas price increased 62% to average $2.58 per Mcf for the second quarter of 2025 from $1.59 per Mcf for the second quarter of 2024 and decreased 18% from $3.13 per Mcf for the first quarter of 2025. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 20% to average $87.22 per bbl for the second quarter of 2025 from $108.81 per bbl for the second quarter of 2024 and decreased 9% from $95.52 per bbl for the first 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 "Oil Sands Mining and Upgrading" sections of this MD&A.

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

In the Company's Exploration and Production segments, crude oil and NGLs production expense(1) averaged $14.03 per bbl for the second quarter of 2025, a decrease of 4% from $14.54 per bbl for the second quarter of 2024 and a decrease of 11% from $15.74 per bbl for the first quarter of 2025. Natural gas production expense(1) averaged $1.11 per Mcf for the second quarter of 2025, a decrease of 8% from $1.21 per Mcf for the second quarter of 2024 and a decrease of 8% from $1.20 per Mcf for the first quarter of 2025. In the Oil Sands Mining and Upgrading segment, production expense(1) averaged $26.53 per bbl for the second quarter of 2025, comparable with $25.95 per bbl for the second quarter of 2024 and an increase of 21% from $21.88 per bbl for the first 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 "Oil Sands Mining and Upgrading" sections of this MD&A.

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 June 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.

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

▪Crude oil and NGLs sales volumes – Fluctuations in production from Kirby and Jackfish, fluctuations in production due to the cyclic nature of Primrose, fluctuations in the Company's drilling program in the North America Exploration and Production segment, natural field 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, 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, 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, increased 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 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 accrued interest on PRT recoveries.

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

Global crude oil benchmark pricing declined through the second quarter of 2025, driven by demand outlook concerns due to ongoing tariff and trade uncertainty and the impact of larger than expected OPEC+ output hikes. Crude oil benchmark price volatility provided pricing support in the latter half of the quarter as escalating tensions in the Middle East led to concerns of supply disruptions. Natural gas benchmark pricing remained stable in the second quarter of 2025. In Canada, the start-up of LNG Canada, which began exporting cargoes at the outset of the third quarter of 2025, will provide additional market egress and is expected to support AECO benchmark pricing.

In the first quarter of 2025, the US government announced tariffs on certain Canadian goods with countermeasures subsequently announced by the Canadian government. These trade measures have created market volatility which may continue to affect pricing received for the Company's products, increase the cost or reduce the availability of products in the Company's supply chain, and introduce additional foreign currency volatility. As of the date of this MD&A, the duration and impact of these trade actions remains uncertain, and 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 June 30, 2025, the Company had undrawn revolving bank credit facilities of $4,723 million. Including cash and cash equivalents, the Company had approximately $4,825 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$67.55 per bbl for the six months ended June 30, 2025, a decrease of 14% from US$78.76 per bbl for the six months ended June 30, 2024. WTI averaged US$63.71 per bbl for the second quarter of 2025, a decrease of 21% from US$80.55 per bbl for the second quarter of 2024 and a decrease of 11% from US$71.42 per bbl for the first 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$71.71 per bbl for the six months ended June 30, 2025, a decrease of 15% from US$84.07 per bbl for the six months ended June 30, 2024. Brent averaged US$67.78 per bbl for the second quarter of 2025, a decrease of 20% from US$84.90 per bbl for the second quarter of 2024 and a decrease of 10% from US$75.68 per bbl for the first quarter of 2025.

The decrease in WTI and Brent benchmark pricing for the three and six months ended June 30, 2025 from the comparable periods reflected weaker global demand outlooks amid ongoing tariff and trade uncertainty, combined with larger than expected OPEC+ output hikes in the second quarter of 2025.

The WCS Heavy Differential averaged US$11.42 per bbl for the six months ended June 30, 2025, compared with US$16.44 per bbl for the six months ended June 30, 2024. The WCS Heavy Differential averaged US$10.19 per bbl for the second quarter of 2025, compared with US$13.54 per bbl for the second quarter of 2024 and US$12.66 per bbl for the first quarter of 2025. The narrowing of the WCS Heavy Differential for the six months ended June 30, 2025 from the six months ended June 30, 2024 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 second quarter of 2025 from the comparable periods primarily reflected production impacts in the Western Canadian Sedimentary Basin ("WCSB") as a result of maintenance activities and shut-in production from wildfires that occurred in the second quarter of 2025.

The SCO price averaged US$66.87 per bbl for the six months ended June 30, 2025, a decrease of 12% from US$76.38 per bbl for the six months ended June 30, 2024. The SCO price averaged US$64.69 per bbl for the second quarter of 2025, a decrease of 22% from US$83.33 per bbl for the second quarter of 2024 and a decrease of 6% from US$69.07 per bbl for the first quarter of 2025. The decrease in SCO pricing for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected weaker WTI benchmark pricing. The decrease in SCO pricing for the second quarter of 2025 from the first quarter of 2025 primarily reflected weaker WTI benchmark pricing, partially offset by the SCO differential strengthening due to lower production levels in the WCSB as a result of maintenance activities that took place in the second quarter of 2025.

NYMEX benchmark pricing averaged US$3.55 per MMBtu for the six months ended June 30, 2025, an increase of 72% from US$2.06 per MMBtu for the six months ended June 30, 2024. NYMEX benchmark pricing averaged US$3.44 per MMBtu for the second quarter of 2025, an increase of 82% from US$1.89 per MMBtu for the second quarter of 2024 and a decrease of 6% from US$3.66 per MMBtu for the first quarter of 2025. The increase in NYMEX natural gas prices for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected lower US inventory levels following cold weather conditions in the first quarter of 2025, combined with higher LNG exports out of the US Gulf Coast in 2025. The decrease in NYMEX natural gas pricing for the second quarter of 2025 from the first quarter of 2025 primarily reflected reduced LNG exports from the US Gulf Coast due to maintenance activities, as well as seasonal demand factors.

AECO benchmark pricing averaged $1.94 per GJ for the six months ended June 30, 2025, an increase of 18% from $1.65 per GJ for the six months ended June 30, 2024. AECO benchmark pricing averaged $1.97 per GJ for the second quarter of 2025, an increase of 45% from $1.36 per GJ for the second quarter of 2024 and comparable with $1.92 per GJ for the first quarter of 2025. The increase in AECO natural gas prices for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected stronger NYMEX benchmark pricing, combined with increased exports out of the WCSB.

(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 six months ended June 30, 2025 averaged 1,096,049 bbl/d, an increase of 15% from 954,866 bbl/d for the six months ended June 30, 2024. Crude oil and NGLs production before royalties for the second quarter of 2025 averaged 1,019,149 bbl/d, an increase of 9% from 934,066 bbl/d for the second quarter of 2024 and a decrease of 13% from 1,173,804 bbl/d for the first quarter of 2025. The increase in crude oil and NGLs production before royalties for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, strong utilization in the Oil Sands Mining and Upgrading segment, and thermal oil pad additions and strong drilling results in the North America Exploration and Production segment. The decrease in crude oil and NGLs production before royalties for the second quarter of 2025 from the first quarter of 2025 primarily reflected the planned turnaround at the non-operated Scotford Upgrader ("Scotford") successfully completed in the second quarter of 2025.

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

Natural gas production before royalties for the six months ended June 30, 2025 averaged 2,429 MMcf/d, an increase of 14% from 2,129 MMcf/d for the six months ended June 30, 2024. Natural gas production before royalties for the second quarter of 2025 averaged 2,407 MMcf/d, an increase of 14% from 2,110 MMcf/d for the second quarter of 2024 and comparable with 2,451 MMcf/d for the first quarter of 2025. The increase in natural gas production before royalties for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024 and strong drilling results, partially offset by natural field declines.

Annual natural gas production for 2025 is targeted to average between 2,425 MMcf/d and 2,480 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

North America crude oil and NGLs production before royalties for the six months ended June 30, 2025 averaged 553,482 bbl/d, an increase of 10% from 502,636 bbl/d for the six months ended June 30, 2024. North America crude oil and NGLs production before royalties for the second quarter of 2025 of 545,811 bbl/d increased 9% from 499,636 bbl/d for the second quarter of 2024 and decreased 3% from 561,238 bbl/d for the first quarter of 2025. The increase in North America crude oil and NGLs production for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, thermal pad additions at Primrose, and strong drilling results from heavy oil multilaterals, liquids-rich natural gas, and light oil, partially offset by natural field declines. The decrease in North America crude oil and NGLs production for the second quarter of 2025 from the first quarter of 2025 primarily reflected maintenance activities, the impact of wildfires, and natural field declines.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 274,789 bbl/d for the second quarter of 2025, an increase of 3% from 268,044 bbl/d for the second quarter of 2024 and a decrease of 3% from 284,706 bbl/d for the first quarter of 2025. The increase in thermal in situ production in the second quarter of 2025 from the second quarter of 2024 primarily reflected pad additions at Primrose, partially offset by natural field declines. The decrease in thermal in situ production in the second quarter of 2025 from the first quarter of 2025 primarily reflected natural field declines and the impact of wildfires.

Pelican Lake heavy crude oil production before royalties for the second quarter of 2025 averaged 43,078 bbl/d, a decrease of 4% from 44,839 bbl/d for the second quarter of 2024 reflecting Pelican Lake's long life low decline production, and comparable with 43,175 bbl/d for the first quarter of 2025.

North America natural gas production before royalties for the six months ended June 30, 2025 averaged 2,417 MMcf/d, an increase of 14% from 2,117 MMcf/d for the six months ended June 30, 2024. Natural gas production before royalties averaged 2,398 MMcf/d for the second quarter of 2025, an increase of 14% from 2,099 MMcf/d for the second quarter of 2024 and comparable with 2,436 MMcf/d for the first quarter of 2025. The increase in natural gas production for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024 and strong drilling results, partially offset by natural field declines.

SCO production before royalties for the six months ended June 30, 2025 averaged 529,099 bbl/d, an increase of 24% from 427,863 bbl/d for the six months ended June 30, 2024. SCO production before royalties for the second quarter of 2025 averaged 463,808 bbl/d, an increase of 13% from 410,518 bbl/d for the second quarter of 2024 and a decrease of 22% from 595,116 bbl/d for the first quarter of 2025. The increase in SCO production for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, combined with strong performance and utilization at both Horizon and AOSP. The increase in SCO production for the second quarter of 2025 from the second quarter of 2024 also reflected the turnaround at Horizon in the second quarter of 2024, partially offset by the planned turnaround at Scotford completed in the second quarter of 2025. The decrease for the second quarter of 2025 from the first quarter of 2025 primarily reflected the turnaround at Scotford.

International crude oil and NGLs production before royalties for the six months ended June 30, 2025 averaged 13,468 bbl/d, a decrease of 45% from 24,367 bbl/d for the six months ended June 30, 2024. International crude oil and NGLs production before royalties for the second quarter of 2025 averaged 9,530 bbl/d, a decrease of 60% from 23,912 bbl/d for the second quarter of 2024 and a decrease of 45% from 17,450 bbl/d for the first quarter of 2025. The decrease in International crude oil and NGLs production for the three and six months ended June 30, 2025 from the comparable periods primarily reflected 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, maintenance activities in the North Sea in the second quarter of 2025, 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 4% to average $73.95 per bbl for the six months ended June 30, 2025 from $76.94 per bbl for the six months ended June 30, 2024. North America realized crude oil and NGLs prices averaged $69.30 per bbl for the second quarter of 2025, a decrease of 19% from $85.49 per bbl for the second quarter of 2024 and a decrease of 12% from $78.56 per bbl for the first quarter of 2025. The decrease in North America realized crude oil and NGLs prices per bbl for the three and six months ended June 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 decrease in North America realized crude oil and NGLs prices per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower WTI benchmark pricing. 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 second quarter of 2025 contributed approximately 210,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 39% to average $2.80 per Mcf for the six months ended June 30, 2025 from $2.02 per Mcf for the six months ended June 30, 2024. North America realized natural gas prices increased 66% to average $2.54 per Mcf for the second quarter of 2025 from $1.53 per Mcf for the second quarter of 2024 and decreased 17% from $3.06 per Mcf for the first quarter of 2025. The increase in North America realized natural gas prices per Mcf for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher benchmark pricing. The decrease for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower 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 $103.58 per bbl for the six months ended June 30, 2025 from $114.08 per bbl for the six months ended June 30, 2024. International realized crude oil and NGLs prices decreased 21% to average $91.00 per bbl for the second quarter of 2025 from $115.27 per bbl for the second quarter of 2024 and decreased 15% from $107.04 per bbl for the first 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, and prevailing Brent benchmark prices and foreign exchange rates at the time of lifting.

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

North America crude oil and NGLs and natural gas royalties for the three and six months ended June 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 16% of product sales for the six months ended June 30, 2025 compared with 20% of product sales for the six months ended June 30, 2024. Crude oil and NGLs royalty rates averaged approximately 13% of product sales for the second quarter of 2025 compared with 21% for the second quarter of 2024 and 19% for the first quarter of 2025. The decrease in royalty rates for the three and six months ended June 30, 2025 from the comparable periods primarily reflected prevailing benchmark pricing and the impact of sliding scale royalty rates.

Natural gas royalty rates averaged approximately 3% of product sales for the six months ended June 30, 2025 compared with 3% of product sales for the six months ended June 30, 2024. Natural gas royalty rates averaged approximately 3% of product sales for the second quarter of 2025 compared with 1% for the second quarter of 2024 and 4% for the first quarter of 2025. The fluctuations in royalty rates for the second quarter of 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 six months ended June 30, 2025 compared with 5% of product sales for the six months ended June 30, 2024. Royalty rates as a percentage of product sales averaged approximately 5% for the second quarter of 2025 compared with 4% of product sales for the second quarter of 2024 and 4% for the first 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)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

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

North America crude oil and NGLs production expense for the six months ended June 30, 2025 averaged $12.28 per bbl, a decrease of 9% from $13.56 per bbl for the six months ended June 30, 2024. North America crude oil and NGLs production expense for the second quarter of 2025 of $11.89 per bbl decreased 4% from $12.44 per bbl for the second quarter of 2024 and decreased 6% from $12.65 per bbl for the first quarter of 2025. The decrease in crude oil and NGLs production expense per bbl for the six months ended June 30, 2025 from the six months ended June 30, 2024 primarily reflected higher production volumes. The decrease in crude oil and NGLs production expense per bbl for the second quarter of 2025 from the second quarter of 2024 primarily reflected higher production volumes, partially offset by higher energy costs. The decrease in crude oil and NGLs production expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower energy costs.

North America natural gas production expense for the six months ended June 30, 2025 averaged $1.11 per Mcf, a decrease of 10% from $1.23 per Mcf for the six months ended June 30, 2024. North America natural gas production expense for the second quarter of 2025 of $1.07 per Mcf decreased 10% from $1.19 per Mcf for the second quarter of 2024 and decreased 8% from $1.16 per Mcf for the first quarter of 2025. The decrease in natural gas production expense per Mcf for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher production volumes. The decrease in natural gas production expense per Mcf for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower energy costs.

International crude oil and NGLs production expense for the six months ended June 30, 2025 averaged $101.16 per bbl, an increase of 58% from $64.00 per bbl for the six months ended June 30, 2024. International crude oil and NGLs production expense for the second quarter of 2025 of $175.70 per bbl increased 163% from $66.83 per bbl for the second quarter of 2024 and increased 118% from $80.63 per bbl for the first quarter of 2025. The increase in crude oil and NGLs production expense per bbl for the three and six months ended June 30, 2025 from the comparable periods 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.

(1)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.

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

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

Adjusted depletion, depreciation and amortization expense for the six months ended June 30, 2025 averaged $13.11 per BOE, an increase of 3% from $12.71 per BOE for the six months ended June 30, 2024. Adjusted depletion, depreciation and amortization expense for the second quarter of 2025 averaged $12.94 per BOE, comparable with $12.77 per BOE for the second quarter of 2024 and $13.27 per BOE for the first quarter of 2025. The increase in adjusted depletion, depreciation and amortization expense per BOE for the six months ended June 30, 2025 from the six months ended June 30, 2024 primarily reflected the impact of changes in North America depletion rates due to changes in reserve estimates at December 31, 2024, combined with a higher depletable base due to asset additions, partially offset by higher sales volumes.

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

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

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the six months ended June 30, 2025 averaged $0.78 per BOE, a decrease of 18% from $0.95 per BOE for the six months ended June 30, 2024. Asset retirement obligation accretion expense for the second quarter of 2025 averaged $0.79 per BOE, a decrease of 17% from $0.95 per BOE for the second quarter of 2024 and comparable with $0.77 per BOE for the first quarter of 2025. The decrease in asset retirement obligation accretion expense per BOE for the three and six months ended June 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 Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 463,808 bbl/d in the second quarter of 2025 primarily reflecting the planned turnaround at Scotford completed during the quarter.

(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 $91.88 per bbl for the six months ended June 30, 2025, a decrease of 6% from $98.18 per bbl for the six months ended June 30, 2024. The realized SCO sales price averaged $87.22 per bbl for the second quarter of 2025, a decrease of 20% from $108.81 per bbl for the second quarter of 2024 and a decrease of 9% from $95.52 per bbl for the first quarter of 2025. The decrease in realized SCO sales price per bbl for the three and six months ended June 30, 2025 from the comparable periods primarily reflected lower WTI benchmark pricing.

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

Transportation expense averaged $3.44 per bbl for the six months ended June 30, 2025, an increase of 56% from $2.21 per bbl for the six months ended June 30, 2024. Transportation expense averaged $3.73 per bbl for the second quarter of 2025, an increase of 33% from $2.81 per bbl for the second quarter of 2024 and an increase of 16% from $3.21 per bbl for the first quarter of 2025. The increase in transportation expense per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher volumes shipped on the TMX pipeline in 2025. The increase in transportation expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected the Company's commitments on egress pipelines and lower sales volumes due to the turnaround at Scotford in the second quarter of 2025.

(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.

Oil Sands Mining and Upgrading production expense was $1,120 million for the second quarter of 2025, an increase of 19% from $941 million for the second quarter of 2024, primarily reflecting the acquisition of the additional working interest in AOSP in December 2024. Production expense decreased 5% in the second quarter of 2025 from $1,185 million for the first quarter of 2025 primarily reflecting lower energy costs.

Production expense for the six months ended June 30, 2025 averaged $23.91 per bbl, a decrease of 6% from $25.36 per bbl for the six months ended June 30, 2024. Production expense for the second quarter of 2025 averaged $26.53 per bbl, comparable with $25.95 per bbl for the second quarter of 2024 and an increase of 21% from $21.88 per bbl for the first quarter of 2025. The decrease in production expense per bbl for the six months ended June 30, 2025 from the six months ended June 30, 2024 primarily reflected higher production volumes. The increase in production expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower production volumes. SCO production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.

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

Depletion, depreciation and amortization expense for the six months ended June 30, 2025 averaged $13.55 per bbl, a decrease of 3% from $13.95 per bbl for the six months ended June 30, 2024. Depletion, depreciation and amortization expense for the second quarter of 2025 of $14.96 per bbl decreased 3% from $15.37 per bbl for the second quarter of 2024 and increased 20% from $12.45 per bbl for the first quarter of 2025. The decrease in depletion, depreciation and amortization expense per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher sales volumes, partially offset by a higher depletable base due to asset additions. The increase in depletion, depreciation and amortization expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower sales volumes in the second 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 six months ended June 30, 2025 of $0.45 per bbl decreased 17% from $0.54 per bbl for the six months ended June 30, 2024. Asset retirement obligation accretion expense for the second quarter of 2025 of $0.51 per bbl decreased 12% from $0.58 per bbl for the second quarter of 2024 and increased 28% from $0.40 per bbl for the first quarter of 2025. The decrease in asset retirement obligation accretion expense per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the impact of higher sales volumes in 2025. The increase in asset retirement obligation accretion expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected the impact of lower sales volumes in the second quarter.

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 second quarter of 2025, production of ultra-low sulphur diesel and other refined products averaged 60,549 BOE/d (15,137 BOE/d to the Company) (three months ended March 31, 2025 – 83,863 BOE/d; 20,966 BOE/d to the Company; three months ended June 30, 2024 – 78,272 BOE/d; 19,568 BOE/d to the Company), reflecting the 25% toll payer commitment.

As at June 30, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $504 million (December 31, 2024 – $509 million). For the three months ended June 30, 2025, the Company's recovery of its share of unrecognized equity losses was $24 million (three months ended March 31, 2025 – unrecognized equity losses of $19 million; six months ended June 30, 2025 – recovery of unrecognized equity losses of $5 million; three months ended June 30, 2024 – recovery of unrecognized equity losses of $35 million; six months ended June 30, 2024 – recovery of unrecognized equity losses of $39 million).

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

(2)Total Company sales volumes.

Administration expense for the six months ended June 30, 2025 of $1.11 per BOE increased 6% from $1.05 per BOE for the six months ended June 30, 2024. Administration expense for the second quarter of 2025 of $1.17 per BOE increased 10% from $1.06 per BOE for the second quarter of 2024 and the first quarter of 2025. The increase in administration expense per BOE for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher personnel costs, partially offset by higher overhead recoveries and higher sales volumes. The increase in administration expense per BOE for the second quarter of 2025 from the first quarter of 2025 reflected the impact of lower sales volumes in the second quarter.

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 $34 million of share-based compensation expense for the six months ended June 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 six months ended June 30, 2025 increased 45% to $1.81 per BOE from $1.25 per BOE for the six months ended June 30, 2024. Interest and other financing expense for the second quarter of 2025 increased 36% to $1.84 per BOE from $1.35 per BOE for the second quarter of 2024 and increased 3% from $1.79 per BOE for the first quarter of 2025. The increase in interest and other financing expense per BOE for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher average debt levels, including higher floating rate debt, partially offset by higher sales volumes. The increase in interest and other financing expense per BOE for the second quarter of 2025 from the first quarter of 2025 primarily reflected the impact of lower sales volumes in the second quarter of 2025, partially offset by lower average debt levels driven by movements in the US/Canadian dollar exchange rate.

The Company's average effective interest rate for the three and six months ended June 30, 2025 of 5.1% increased 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.