Canadian Natural Resources Limited Announces 2025 Second Quarter Results

Calgary, Alberta--(Newsfile Corp. - August 7, 2025) - Canadian Natural's (TSX: CNQ) (NYSE: CNQ) 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."

HIGHLIGHTS

• 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.

RETURNS TO SHAREHOLDERS

• 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.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

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.

• 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 Exploration and Production

•  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.

North America Oil Sands Mining and Upgrading

• 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 Exploration and Production

•  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.

MARKETING

• 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.

ADVISORY

Special Note Regarding Forward-Looking Statements

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration", or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs"), or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the construction, expansion, or maintenance of third-party facilities that process the Company's products; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the materiality of the impact of tax interpretations and litigation on the Company's results, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives, or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas, and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates, and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance, or achievements of the Company to be materially different from any future results, performance, or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of 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.

The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state, and local laws and regulations such as restrictions on production, the imposition of tariffs, embargoes, or export restrictions on the Company's products (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), changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.

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

Special Note Regarding Common Share Split and Comparative Figures

At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split.

Special Note Regarding Amendments to the Competition Act (Canada)

On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which permits private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and enforcement of this legislation may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.

Special Note Regarding Currency, Financial Information and Production

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.

Special Note Regarding Non-GAAP and Other Financial Measures

This document includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure. 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 Allocation Policy

Free cash flow is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay or maintain net debt levels, pursuant to the free cash flow allocation policy.

The Company's free cash flow is used to determine the targeted amount of shareholder returns after dividends. The amount allocated to shareholders varies depending on the Company's net debt position.

Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash 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:

Long-term Debt, net

Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.

Breakeven WTI Price

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

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

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.

CONFERENCE CALL

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.

Dial-in to the live event:

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

Listen to the audio webcast:

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

Conference call playback:

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.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/261613