Canadian Natural Resources: Financial Reports (25 Q4 Interim Report)

Canadian Natural's President, Scott Stauth, commented on the Company's fourth quarter and year end 2025 results, "The year 2025 was the best operational year in the Company's long history of maximizing value for our shareholders. We set several production records, lowered our operating costs and capital expenditures came in under our forecast. We grew organically and completed several accretive acquisitions, including the Palliser Block assets in southern Alberta and liquids-rich Montney assets in the Grande Prairie area, along with increasing our ownership in the Albian mines to 100% through an asset swap. As a result, we achieved record annual production of 1,571 MBOE/d in 2025, resulting in year-over-year growth of 15% or approximately 207 MBOE/d from 2024 levels. We also achieved record annual liquids production of 1,146 Mbbl/d, of which 65% was comprised of Synthetic Crude Oil ("SCO"), light crude oil and NGLs, which are not subject to widening heavy crude oil differentials.

Strong execution across our large, diverse asset base continues to provide significant opportunities to create shareholder value in 2026 and beyond. This is evident by our increased production, strong free cash flow and growth in reserves achieved in 2025, through organic growth and accretive acquisitions. These successes provided the Board of Directors with the confidence to approve a dividend increase and an enhancement to our direct shareholder returns, by adjusting our net debt targets as a part of our free cash flow allocation policy. Additionally, we are decreasing our 2026 operating capital forecast by approximately $310 million, following the completion of a strategic acquisition early in 2026, and increasing our 2026 production guidance range to 1,615 MBOE/d and 1,665 MBOE/d from the previous guidance range of 1,590 MBOE/d and 1,650 MBOE/d.

Canadian Natural's reserves are significant when compared to other major oil companies, which support long-term organic growth opportunities. Year end 2025 total proved reserves of 15.91 billion BOE and total proved plus probable reserves of

20.75 billion BOE represent increases of approximately 4% and 3%, respectively, from year end 2024 levels. With approximately 73% of the Company's total proved reserves being long life low decline, the strength and depth of our assets is evident and provide us with a total proved reserves life index ("RLI") of 31 years and a total proved plus probable RLI of 40 years. We continue to deliver strong total proved Finding, Development and Acquisition ("FD&A") costs, including changes in Future Development Cost ("FDC"), achieving an industry leading FD&A in 2025 of $3.64/BOE for total proved reserves and $2.42/BOE for total proved plus probable reserves."

Canadian Natural's Chief Financial Officer, Victor Darel, added "In 2025, we generated adjusted net earnings of $7.4 billion or $3.56 per share, and adjusted funds flow of $15.5 billion or $7.39 per share. Throughout the year, we completed several accretive acquisitions, increasing production and cash flow, while reducing net debt by approximately $2.7 billion to just under $16 billion at year end 2025. We returned approximately $9.0 billion to our shareholders in 2025, including $4.9 billion in dividends, $1.4 billion in share repurchases and $2.7 billion in net debt reduction. Subsequent to year end, the Board approved an approximate 6.4% increase to our quarterly dividend, bringing the annualized dividend up to $2.50 per common share. This marks 2026 as the 26th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 20% over that time, demonstrating the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.

Additionally, the Board of Directors have, effective January 1, 2026, adjusted the net debt target levels in our free cash flow allocation policy which results in an acceleration of the next increase to direct shareholder returns. Now, when net debt falls below $16 billion, compared to our previous target of $15 billion, we will increase direct shareholder returns in the form of share repurchases to 75% of free cash flow generated, managed on a forward-looking basis.

Our financial flexibility and long life low decline asset base provide a strong foundation and a competitive advantage with low maintenance capital requirements. Our US$ WTI breakeven remains top tier in the low to mid-$40 per barrel range. Our balance sheet is strong with significant liquidity of approximately $6.3 billion at year end 2025. Our excellent results highlight the cash flow generating capability of our top tier asset base with strong year end metrics including Debt to Book Capitalization at 26% and Debt to Adjusted EBITDA at 0.7x."

• Generated net earnings of approximately $10.8 billion and adjusted net earnings from operations of $7.4 billion.

• Generated adjusted funds flow of approximately $15.5 billion.

• Returns to shareholders totaled approximately $9.0 billion, comprised of $4.9 billion in dividends, $1.4 billion in share repurchases and $2.7 billion through reduction in the Company's net debt.

  • Approximately 33.5 million common shares were repurchased and cancelled in 2025 at a weighted average price of

    $43.28 per share.

• Record total annual production of approximately 1,571,000 BOE/d, an increase of 207,000 BOE/d or 15% from 2024 levels.

  • Record total liquids production of approximately 1,146,000 bbl/d, an increase of 141,000 bbl/d or 14% from 2024 levels.

    • Strong total corporate liquids operating costs(1) of $18.44/bbl (US$13.19/bbl), compared to $18.56/bbl (US$13.55/bbl) in 2024.

    • Record Oil Sands Mining and Upgrading production of approximately 565,000 bbl/d of zero decline SCO, with upgrader utilization of 100%, including the planned turnaround at the Athabasca Oil Sands Project ("AOSP").

      • Industry leading Oil Sands Mining and Upgrading operating costs of $22.66/bbl (US$16.21/bbl), compared to

        $22.88/bbl (US$16.70/bbl) in 2024.

    • Record thermal in situ production of 275,000 bbl/d of long life low decline production.

  • Record natural gas production of 2,547 MMcf/d, an increase of 400 MMcf/d or 19% from 2024 levels.

• Canadian Natural reduced net debt by approximately $2.7 billion from 2024 year end levels.

  • Repaid US$1.2 billion of US dollar debt securities.

  • Issued C$1.65 billion in 3, 5 and 10 year medium-term notes.

    2025 FOURTH QUARTER HIGHLIGHTS

• Generated net earnings of approximately $5.3 billion and adjusted net earnings from operations of $1.7 billion.

• Generated adjusted funds flow of approximately $3.7 billion.

• Returns to shareholders totaled approximately $2.7 billion, comprised of $1.2 billion in dividends, $0.3 billion in share repurchases and $1.2 billion through reduction in the Company's net debt.

• Record total quarterly production of approximately 1,659,000 BOE/d, an increase of 188,000 BOE/d or 13% from Q4/24 levels.

  • Record total liquids production of approximately 1,215,000 bbl/d, an increase of 125,000 bbl/d or 12% from Q4/24 levels.

    • Record Oil Sands Mining and Upgrading production of approximately 620,000 bbl/d of zero decline SCO with upgrader utilization of 105%.

      • Industry leading Oil Sands Mining and Upgrading operating costs of $21.84/bbl (US$15.66/bbl).

• On November 1, 2025, Canadian Natural closed the AOSP asset swap with Shell and now owns and operates 100% of the Albian oil sands mines and associated reserves.

  • The transaction added approximately 31,000 bbl/d of annual, zero decline bitumen production to our Oil Sands Mining and Upgrading portfolio.

1. Operating costs are calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.

   ACCELERATING SHAREHOLDER RETURNS WITH REVISED FREE CASH FLOW ALLOCATION POLICY

   As a result of the Company's continued strong execution and resilience to volatile commodity prices, combined with continued growth of production, cash flow and reserves through strategic acquisitions and organic development, Canadian Natural is increasing its annual dividend and enhancing direct shareholder returns by updating its net debt targets within the Company's free cash flow allocation policy. The policy was last adjusted in October 2024, when on a proforma basis, including the acquired Chevron assets, annual production was approximately 1,465,000 BOE/d. Since then, through organic growth and strategic acquisitions, annual production has grown by approximately 12% or 175,000 BOE/d, to the mid-point of updated 2026 guidance.

   • The Board of Directors have approved an approximate 6.4% increase to the quarterly cash dividend to $0.625 per common share, from $0.5875 per common share, payable on April 7, 2026 to shareholders of record at the close of business on March 20, 2026.

     • This dividend increase represents an annualized dividend of $2.50 per common share and demonstrates the confidence that the Board has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.

       • Canadian Natural's leading track record of 26 consecutive years of dividend growth continues with a CAGR of 20% over that time.

   • The Company's free cash flow allocation policy has been revised based upon the increase in the Company's reserves and production from when it was last reviewed in 2024.

     • When net debt is at or above $16 billion (formerly $15 billion), 60% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 40% to the balance sheet.

     • When net debt is between $13 billion (formerly $12 billion) and $16 billion (formerly $15 billion), 75% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 25% to the balance sheet.

     • When net debt is at or below $13 billion (formerly $12 billion), 100% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases.

     • The Company targets to manage the allocation of free cash flow on a forward-looking annual basis, while managing working capital and cash requirements as needed.

     • Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures.

   • On March 4, 2026, the Board of Directors approved the renewal of the Company's Normal Course Issuer Bid ("NCIB"), which states that during the 12 month period commencing on March 13, 2026 and ending on March 12, 2027, the Company can repurchase for cancellation up to 10% of the public float (as determined in accordance with the rules of the TSX), subject to TSX approval.

     UPDATED 2026 GUIDANCE

   • Canadian Natural is utilizing its capital flexibility in 2026 by reducing forecasted Operating Capital Expenditures by approximately $310 million, which reflects continuous improvement and efficiency gains on our development program and a deferral of front-end engineering and design ("FEED") capital on our Jackpine mine expansion opportunity at Albian.

     • As first communicated at the Company's 2025 investor day held on November 7, 2025, Canadian Natural continues to progress on its budgeted defined short-term growth strategy through the development of its Conventional E&P assets and thermal drill to fill pad additions, and its medium-term growth strategy by expending FEED capital on both its 70,000 bbl/d Pike 2 growth project and 30,000 bbl/d Jackfish expansion project.

     • As a part of its long-term growth strategy, the Company is deferring FEED and defined capital for our Oil Sands Jackpine mine expansion opportunity at Albian, that was originally included in our 2026 capital budget. This approximately $8.25 billion project is being deferred due to the lack of finalization of government regulatory policies as it relates to carbon pricing and methane, which creates uncertainty and economic burden for long-term growth investments. Once there is more certainty on these regulatory policies, approval timelines and egress, we will reassess the viability of this project.

     • Additionally, subsequent to year end, Canadian Natural has acquired assets in the Peace River area of Alberta, which are adjacent to existing operations in the area, and elsewhere for approximately $765 million.

     • As a result, forecasted annual capital is being updated as follows:

1. Forward-looking Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three months and year ended December 31, 2025 dated March 4, 2026 ("MD&A").

   Note: 2026 capital expenditures excludes approximately $993 million of abandonment expenditures, before recoveries, related to the execution of the Company's abandonment and reclamation programs in North America and the North Sea.

   • Following the recent acquisition, Canadian Natural is increasing its 2026 production guidance range to 1,615 MBOE/d and 1,665 MBOE/d, with the mid-point being 20 MBOE/d higher than the budget.

1. Reflects planned downtime for turnaround activities in all areas. Note: Rounded to the nearest 1,000 bbl/d.

Dec 31

2024

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

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

3. Includes the impact of cash paid and received related to acquisitions and dispositions. The Company received net cash consideration of $212 million related to the AOSP asset swap in Q4/25. Refer to the 'Net Capital Expenditures' table in the Company's MD&A.

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

   • Net earnings of approximately $10.8 billion in 2025 reflected strong operational performance, as well as the impact of non-cash accounting gains on the AOSP asset swap that closed in Q4/25, together with non-cash recoverability charges related to the North Sea and Offshore Africa. These items are discussed in detail in the Q4/25 Financial Statements and MD&A.

     • Adjusted net earnings from operations was strong at $7.4 billion in 2025.

       RESERVES HIGHLIGHTS

       A key differentiator for Canadian Natural is the strength, diversity and balance of its world class, top tier assets. The Company's total proved reserve life index ("RLI")(1) of 31 years is supported by long life low decline assets that have been strategically assembled and developed over several decades. The low maintenance capital requirements relative to the size and quality of the reserves affords the Company significant flexibility when balancing its four pillars of capital allocation to maximize shareholder value.

       The Company's reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators ("IQREs"). The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2025 (all reserves values are Company Gross unless stated otherwise).

   • Total proved reserves increased 4% to 15.910 billion BOE, with reserves additions and revisions of 1.253 billion BOE. Total proved plus probable reserves increased 3% to 20.750 billion BOE, with reserves additions and revisions of

     1.213 billion BOE.

     • The strength and depth of the Company's assets are evident as approximately 73% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 31 years and a total proved plus probable BOE RLI of 40 years.

       • Additionally, high value, zero decline SCO and bitumen from the Horizon and Albian mines represent approximately 50% of total proved reserves with a RLI of 39 years.

   • Proved developed producing reserves additions and revisions for 2025 were 1.129 billion BOE, replacing 2025 production by 197%. The proved developed producing BOE RLI is 20 years.

   • Total proved reserves additions and revisions for 2025 replaced 2025 production by 218%. Total proved plus probable reserves additions and revisions for 2025 replaced 2025 production by 212%.

   • In 2025, Canadian Natural continued to achieve strong Finding, Development and Acquisition ("FD&A") costs:

     • FD&A costs, including changes in Future Development Cost ("FDC"), are $3.64/BOE for total proved reserves and

       $2.42/BOE for total proved plus probable reserves.

   • The net present value of future net revenues, before income tax, discounted at 10%, is $110.1 billion for proved developed producing reserves, $157.8 billion for total proved reserves, and $191.0 billion for total proved plus probable reserves.

1. Supplementary financial measure. Refer to the '2025 Year End Reserves' section of this document.

Three Months Ended Year Ended

Dec 31

2024

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 achieved record annual production in 2025, averaging 565,102 bbl/d of SCO, an increase of 20% or approximately 93,000 bbl/d from 2024 levels, reflecting the additional working interests acquired in AOSP, combined with effective and efficient operations.

     • Oil Sands Mining and Upgrading achieved strong annual upgrader utilization, averaging 100% in 2025, which included a planned turnaround at AOSP.

     • Industry leading Oil Sands Mining and Upgrading operating costs averaged $22.66/bbl (US$16.21/bbl) of SCO in 2025, compared to $22.88/bbl (US$16.70/bbl) in 2024.

     • Oil Sands Mining and Upgrading production has strong realized pricing, averaging $86.41/bbl in 2025.

   • 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.

   • As a part of its long-term growth strategy, the Company is deferring FEED and defined capital for our Oil Sands Jackpine mine expansion opportunity at Albian, that was originally included in our 2026 capital budget. This approximately

     $8.25 billion project is being deferred due to the lack of finalization of government regulatory policies as it relates to carbon pricing and methane, which creates uncertainty and economic burden for long-term growth investments. Once there is more certainty on these regulatory policies, approval timelines and egress, we will reassess the viability of this project.

     North America Exploration and Production

     Thermal In Situ Oil Sands

     Three Months Ended Year Ended

     	Dec 31 2025	Sep 30 2025	Dec 31 2024	Dec 31 2025	Dec 31 2024
     Bitumen production (bbl/d)	266,308	274,752	276,231	275,086	271,011
     Net bitumen wells drilled Net successful bitumen wells drilled	25 24	11 11	16 16	78 77	94 94
     Success rate	96%	100%	100%	99%	100%

   • Thermal in situ achieved record annual production in 2025, averaging 275,086 bbl/d, an increase of 2% from 2024 levels, reflecting the Company's capital efficient pad add and development program, partially offset by natural field declines.

     • Thermal in situ operating costs remain strong, averaging $11.09/bbl (US$7.93/bbl) in 2025, comparable to 2024 levels.

   • As part of the Company's defined short-term growth strategy, Canadian Natural has decades of robust 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.

     • The first Pike 1 pad was brought on production ahead of schedule in December 2025 which is tied into the Jackfish 3 facility. Current production rates from this pad of approximately 27,000 bbl/d are exceeding expectations, with a Steam to Oil Ratio ("SOR") of approximately 1.8x. A second Pike 1 pad is targeted to come on production in April 2026 and is targeted to keep production at the Jackfish 3 facility at full capacity.

     • At Primrose, the Company completed drilling a Cyclic Steam Stimulation ("CSS") pad in February 2026, with production targeted to come on in Q3/26. The Company is drilling two additional CSS pads which are targeted to come on production in 2027.

     • At Kirby, the Company is planning to commence drilling a Steam Assisted Gravity Drainage ("SAGD") pad in Q2/26, which is targeted to come on production in 2027.

   • As part of the Company's defined medium-term growth strategy, in 2026, front end engineering is progressing on both its 70,000 bbl/d Pike 2 growth project and 30,000 bbl/d Jackfish expansion project. In December 2025, Canadian Natural received regulatory approval for the Pike 2 SAGD project.

   • 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 SOR and Greenhouse Gas ("GHG") emissions, at the same time optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.

     • The Company continues to operate the commercial scale solvent SAGD pad at Kirby North and the solvent enhanced steam flood pilot at Primrose. An additional solvent SAGD pilot at Kirby South is targeted to begin injection in Q2/26 to evaluate additional future commercial development opportunities.

       Crude oil and NGLs - excluding Thermal In Situ Oil Sands

       Three Months Ended Year Ended

       	Dec 31 2025	Sep 30 2025	Dec 31 2024	Dec 31 2025	Dec 31 2024
       Crude oil and NGLs production (bbl/d)	319,189	309,873	255,729	294,315	238,277
       Net crude oil wells drilled Net successful crude oil wells drilled	90 90	78 78	84 84	282 281	214 213
       Success rate	100%	100%	100%	99%	99%

   • North America E&P liquids production, excluding thermal in situ, averaged 294,315 bbl/d in 2025, an increase of 24% or approximately 56,000 bbl/d from 2024 levels, reflecting opportunistic acquisitions and strong organic growth from heavy crude oil multilaterals, light crude oil and liquids-rich natural gas.

     • Primary heavy crude oil production averaged 87,888 bbl/d in 2025, an increase of 11% from 2024 levels, reflecting strong drilling results from the Company's multilateral wells.

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

       • Operating costs in the Company's primary heavy crude oil operations averaged $16.68/bbl (US$11.93/bbl) in 2025, a decrease of 8% from 2024 levels, primarily reflecting lower operating cost multilateral production.

     • Pelican Lake production averaged 42,470 bbl/d in 2025, a decrease of 5% from 2024 levels, reflecting the low natural field declines from this long life low decline asset.

       • Operating costs at Pelican Lake averaged $9.24/bbl (US$6.61/bbl) in 2025, comparable to 2024 levels.

     • North America light crude oil and NGLs production averaged 163,957 bbl/d in 2025, an increase of 43% or approximately 50,000 bbl/d from 2024 levels, primarily reflecting opportunistic acquisitions and strong drilling results.

       • Operating costs in the Company's North America light crude oil and NGLs operations averaged $12.39/bbl (US$8.87/bbl) in 2025, a decrease of 9% from 2024 levels, primarily reflecting higher production volumes.

         North America Natural Gas

         Three Months Ended Year Ended

         	Dec 31 2025	Sep 30 2025	Dec 31 2024	Dec 31 2025	Dec 31 2024
         Natural gas production (MMcf/d)	2,657	2,658	2,273	2,538	2,136
         Net natural gas wells drilled Net successful natural gas wells drilled	20 20	17 17	14 14	78 78	79 78
         Success rate	100%	100%	100%	100%	99%

   • Record North America natural gas production was achieved in 2025, averaging 2,538 MMcf/d, an increase of 19% from 2024 levels, primarily reflecting opportunistic acquisitions and strong drilling results in the Company's liquids-rich natural gas assets.

     • North America natural gas operating costs averaged $1.11/Mcf in 2025, a decrease of 7% from 2024 levels, primarily reflecting higher production volumes and cost efficiencies.

       International Exploration and Production

       	Dec 31 2025	Sep 30 Dec 31 2025 2024	Dec 31 2025
       Crude oil production (bbl/d) Natural gas production (MMcf/d)	9,966 3	9,843 23,411 10 10	11,672 9	24,070 11

       Three Months Ended Year Ended

       Dec 31

       2024

   • International E&P crude oil production volumes averaged 11,672 bbl/d in 2025, a decrease of 52% compared to 2024 levels. The decrease reflects temporary suspension of production at Baobab in Offshore Africa due to the planned refurbishment of its floating production storage and offloading ("FPSO") vessel which is expected to return to service in Q2/26, planned decommissioning activities in the North Sea and natural field declines.

1. Includes bitumen wells.

   • Canadian Natural drilled a total of 438 net crude oil and natural gas wells in 2025, 51 more than in 2024.

Three Months Ended Year Ended Dec 31

2024

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

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

3. Pricing is net of blending and feedstock costs.

4. Excludes risk management activities.

5. Non-GAAP ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A.

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

   • Canadian Natural has total contracted crude oil transportation capacity of 256,500 bbl/d, consisting of committed volumes to Canada's west coast and to the United States Gulf Coast, being approximately 21% of 2026 forecasted liquids production. The egress supports Canadian Natural's long-term sales strategy by targeting diverse refining markets which drive stronger netbacks while also reducing exposure to egress constraints.

   • The North West Redwater refinery, 50% owned by the Company, primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 68,139 bbl/d in 2025.

   • Canadian Natural has a diversified natural gas marketing strategy with the Company in 2026 to consume the equivalent of approximately 31% of forecasted natural gas production in its Oil Sands Mining and Upgrading and thermal operations, with approximately 37% 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.

   • Canadian Natural has a long-term natural gas supply agreement with Cheniere Energy, Inc. ("Cheniere") as part of the Sabine Pass Liquefaction Expansion Project 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.

     • 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.

For the year ended December 31, 2025, the Company retained IQREs, Sproule International Limited and GLJ Ltd., to evaluate and review all of the Company's proved and proved plus probable reserves. The evaluation and review was conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.

The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with the IQREs as to the Company's reserves.

Additional reserves information is disclosed in the Company's Annual Information Form.

1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.

2. Information in the reserves data tables may not add due to rounding. BOE values and oil and natural gas metrics may not calculate exactly due to rounding.

3. Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates are the 3-Consultant-Average of price forecasts developed by Sproule International Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2025:

   2026 2027 2028 2029 2030

   Crude Oil and NGLs

   WTI	US$/bbl	59.92	65.10	70.28	71.93	73.37
   WCS	C$/bbl	65.13	70.43	76.90	78.71	80.29
   Canadian Light Sweet	C$/bbl	77.54	83.60	90.17	92.32	94.17
   Cromer LSB	C$/bbl	75.09	81.56	86.95	89.19	90.98
   Edmonton C5+	C$/bbl	80.01	86.19	92.83	95.04	96.94
   Brent	US$/bbl	63.92	69.13	74.36	76.10	77.62
   AECO	C$/MMBtu	3.00	3.30	3.49	3.58	3.65
   BC Westcoast Station 2	C$/MMBtu	2.66	3.07	3.25	3.34	3.41
   Henry Hub	US$/MMBtu	3.74	3.78	3.85	3.93	4.01

   All prices increase at a rate of 2% per year after 2030.

   A US$/C$ foreign exchange rate of 0.7277 was used for 2026, 0.7367 for 2027, and 0.7400 for 2028 and thereafter in the year end 2025 evaluation.

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

5. Oil and natural gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural's performance over time. However, such measures are not reliable indicators of Canadian Natural's future performance and future performance may vary.

6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.

7. Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period.

8. Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2026 proved developed producing production forecast prepared by the IQREs.

9. Finding, Development and Acquisition ("FD&A") costs including changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2025 and net changes in FDC from December 31, 2024 to December 31, 2025 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs.

10. Abandonment, decommissioning and reclamation ("ADR") costs included in the calculation of the Future Net Revenue ("FNR") consist of both the Company's Asset Retirement Obligation ("ARO") for North America and Offshore Africa, before inflation and discounting, for development existing as at December 31, 2025 and forecast estimates of ADR costs attributable to future development activity.

ADVISORY

Special Note Regarding Non-GAAP and Other Financial Measures

This document includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). These financial measures are used by the Company to evaluate its financial performance, financial position, and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this document and the Company's MD&A and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three months and year ended December 31, 2025 dated March 4, 2026.

Free Cash Flow Allocation Policy

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

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

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

Up to October 2024, before the announcement of the Chevron acquisition, the Company was targeting to allocate 100% of its free cash flow in 2024 to shareholder returns.

In October 2024, with the announcement of the Chevron acquisition, the Board of Directors adjusted the allocation of free cash flow as follows:

• 60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion.

• When net debt is between $12 billion and $15 billion, free cash flow allocation will be 75% to shareholder returns and 25% to the balance sheet.

• When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns. The Company's free cash flow for the year ended December 31, 2025 and comparable period is shown below:

Year Ended

1. Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three months and year ended December 31, 2025 dated March 4, 2026.

2. Non-GAAP Financial Measure. In 2024, for the purpose of the free cash flow calculated above, net capital expenditures of $5,286 million excludes net acquisitions of $9,145 million. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three months and year ended December 31, 2025 dated March 4, 2026.

   In March 2026, the Board of Directors adjusted the allocation of free cash flow, effective January 1, 2026, as follows:

   • When net debt is at or above $16 billion, 60% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 40% to the balance sheet.

   • When net debt is between $13 billion and $16 billion, 75% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 25% to the balance sheet.

   • When net debt is at or below $13 billion, 100% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases.

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 and is based on net capital expenditures (non-GAAP financial measure). Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns, and the balancing of project risks and time horizons. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for more details on net capital expenditures.

Capital expenditures reflect forecasted net capital expenditures, before abandonment expenditures related to the execution of the Company's abandonment and reclamation programs in North America and the North Sea. The Company currently carries an Asset Retirement Obligation ("ARO") liability on its balance sheet for these forecasted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries in Canada and the UK portion of the North Sea. The Company is eligible to recover interest on related to tax recoveries in the North Sea.

Capital Efficiency

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.

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ADVISORY

Special Note Regarding Forward-Looking Statements

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

The forward-looking statements are based on current expectations, estimates, and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance, or achievements of the Company to be materially different from any future results, performance, or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of conflicts in the Middle East, Ukraine and Venezuela, the impact of changes to US economic policy, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; the impact of the ramp-up of LNG Canada on commodity prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; changes and uncertainties in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded); uncertainty in the regulatory framework governing 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, and the implementation of the Memorandum of Understanding ("MOU") entered into between the Government of Canada and the Government of Alberta in November 2025; civil unrest and political uncertainty, including changes in government, actions of or against terrorists, insurgent groups, or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime, and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling, and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting, or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting, or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets, including the acquisition of the remaining interest in the AOSP mines and other acquisitions that occurred in 2025; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs; actions by governmental authorities; government

regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short-, medium-, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

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

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

Special Note Regarding Non-GAAP and Other Financial Measures

This MD&A includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position, or cash flow. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided in the 'Non-GAAP and Other Financial Measures' section of this MD&A.

Special Note Regarding Common Share Split and Comparative Figures

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

Special Note Regarding Amendments to the Competition Act (Canada)

On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement, which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. Subsequently, on November 4, 2025, the federal government tabled the 2025 Budget, which proposed further amendments to the Competition Act, namely removing the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminating private rights of action under the revised business-activity greenwashing provision. Uncertainty surrounding the interpretation and enforcement of this legislation, which includes the status of any proposed or future amendments, may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.

Special Note Regarding Currency, Financial Information and Production

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

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

bitumen, and SCO (including mining bitumen). Production on an "after royalties" or "company net" basis is also presented for information purposes only.

The following discussion and analysis refers primarily to the Company's financial results for the three months and year ended December 31, 2025 in relation to the comparable periods in 2024 and the third 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 https://www.sedarplus.ca, and on EDGAR at https://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 March 4, 2026.

Three Months Ended Year Ended

Dec 31

2024

1. Further details related to product sales are disclosed in note 16 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.

   SUMMARY OF FINANCIAL HIGHLIGHTS Consolidated Net Earnings and Adjusted Net Earnings from Operations

   Net earnings for the year ended December 31, 2025 were $10,820 million compared with $6,106 million for the year ended December 31, 2024. Net earnings for the year ended December 31, 2025 included non-operating income, net of tax, of

   $3,376 million compared with non-operating losses of $1,308 million for the year ended December 31, 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 investment, the gain on acquisitions, disposition, and remeasurement, and recoverability charges related to the North Sea and Offshore Africa. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2025 were $7,444 million compared with $7,414 million for the year ended December 31, 2024.

   Net earnings for the fourth quarter of 2025 were $5,303 million compared with $1,138 million for the fourth quarter of 2024 and $600 million for the third quarter of 2025. Net earnings for the fourth quarter of 2025 included non-operating income, net of tax, of $3,592 million compared with non-operating losses of $839 million for the fourth quarter of 2024 and non-operating losses of $1,201 million for the third quarter of 2025 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain on acquisitions, disposition, and remeasurement, and recoverability charges related to the North Sea and Offshore Africa. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2025 were $1,711 million compared with $1,977 million for the fourth quarter of 2024 and $1,801 million for the third quarter of 2025.

   The movements in net earnings and adjusted net earnings from operations for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected:

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

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

   • higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment; partially offset by:

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

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

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

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

   • higher realized natural gas pricing in the North America Exploration and Production segment; and

   • higher crude oil and NGLs sales volumes in the North America Exploration and Production segment; partially offset by:

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

   • lower realized crude oil and NGLs pricing in the North America Exploration and Production segment.

The impacts of depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchange (gain) loss, the gain on acquisitions, disposition, and remeasurement, the gain from investment, and recoverability charges related to the North Sea and Offshore Africa also contributed to the movements in net earnings from the comparable periods. These items are discussed in detail in the relevant sections of this MD&A. The AOSP asset swap is discussed below, and the recoverability charges related to the North Sea and Offshore Africa are discussed in detail in the 'Adjusted Depletion, Depreciation and Amortization - Exploration and Production' section of this MD&A.

On November 1, 2025, the Company completed the AOSP asset swap with Shell Canada Limited and affiliates ("Shell"). As a result of the transaction, the Company acquired from Shell, the remaining 10% interest in the AOSP mines, associated reserves, and additional working interests in a number of other non-producing oil sands leases, and in exchange to Shell, a 10% non-operated working interest in the Scotford Upgrader ("Scotford") and Quest Carbon Capture and Storage ("Quest") facilities. As a result, the Company owns and operates 100% of the AOSP mines and retains an 80% non-operated working interest in Scotford and Quest. The transaction had an effective date of March 1, 2025.

The Company recognized a $4,989 million gain related to the transaction, comprised of a $17 million gain on acquisition representing the excess of the fair value of the net assets acquired compared to the total purchase consideration and previously held interests, a non-cash gain of $4,508 million ($3,471 million after-tax) related to the remeasurement of the previously held interest in the AOSP mines to fair value, and a non-cash gain on disposition of $464 million ($357 million after-tax) related to the disposition of the 10% interest in Scotford and Quest. Further details are disclosed in note 4 to the financial statements.

Cash flows from operating activities for the year ended December 31, 2025 were $15,106 million compared with

$13,386 million for the year ended December 31, 2024. Cash flows from operating activities for the fourth quarter of 2025 were $3,768 million compared with $3,432 million for the fourth quarter of 2024 and $3,940 million for the third 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 year ended December 31, 2025 was $15,460 million compared with $14,859 million for the year ended December 31, 2024. Adjusted funds flow for the fourth quarter of 2025 was $3,748 million compared with

$4,186 million for the fourth quarter of 2024 and $3,920 million for the third quarter of 2025. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above related to the fluctuations in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, and movements in other long-term assets, including the unamortized cost of contributions to the Company's employee bonus program, interest on Petroleum Revenue Tax ("PRT") and corporate tax recoveries, and prepaid cost of service tolls.

1. Non-GAAP ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.

Record crude oil and NGLs production before royalties for the fourth quarter of 2025 of 1,215,364 bbl/d increased 12% from 1,090,002 bbl/d for the fourth quarter of 2024 and increased 3% from 1,175,604 bbl/d for the third quarter of 2025. Natural gas production before royalties for the fourth quarter of 2025 of 2,660 MMcf/d increased 17% from 2,283 MMcf/d for the fourth quarter of 2024 and was comparable with 2,668 MMcf/d for the third quarter of 2025. Total production before royalties for the fourth quarter of 2025 of 1,658,681 BOE/d increased 13% from 1,470,428 BOE/d for the fourth quarter of 2024 and was comparable with 1,620,261 BOE/d for the third 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 $64.42 per bbl for the fourth quarter of 2025, a decrease of 14% from $75.22 per bbl for the fourth quarter of 2024 and a decrease of 11% from

$72.57 per bbl for the third quarter of 2025. The realized natural gas price increased 43% to average $2.89 per Mcf for the fourth quarter of 2025 from $2.02 per Mcf for the fourth quarter of 2024 and increased 94% from $1.49 per Mcf for the third quarter of 2025. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 20% to average $75.90 per bbl for the fourth quarter of 2025 from $95.08 per bbl for the fourth quarter of 2024 and decreased 14% from $87.85 per bbl for the third quarter of 2025. The Company's realized product pricing is reflective of the prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the 'Business Environment', 'Realized Product Prices - Exploration and Production', and the 'Realized Product Prices, Royalties and Transportation - Oil Sands Mining and Upgrading' sections of this MD&A.

In the Company's Exploration and Production segments, crude oil and NGLs production expense(1) averaged $14.35 per bbl for the fourth quarter of 2025, an increase of 9% from $13.15 per bbl for the fourth quarter of 2024 and $13.18 per bbl for the third quarter of 2025. Natural gas production expense(1) averaged $1.10 per Mcf for the fourth quarter of 2025, comparable with $1.12 per Mcf for the fourth quarter of 2024 and a decrease of 5% from $1.16 per Mcf for the third quarter of 2025. In the Oil Sands Mining and Upgrading segment, production expense(1) averaged $21.84 per bbl for the fourth quarter of 2025, an increase of 4% from $20.97 per bbl for the fourth quarter of 2024 and an increase of 3% from

$21.29 per bbl for the third quarter of 2025. Crude oil and NGLs and natural gas production expense is discussed in detail in the 'Production Expense - Exploration and Production' and the 'Production Expense - Oil Sands Mining and Upgrading' sections of this MD&A.

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

   SUMMARY OF QUARTERLY FINANCIAL RESULTS

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

   ($ millions, except per common share amounts)	Dec 31 2025	Sep 30 2025	Jun 30 2025	Mar 31 2025
   Product sales (1)	$ 10,710	$ 11,070	$ 9,675	$ 12,712
   Crude oil and NGLs	$ 9,666	$ 10,468	$ 8,874	$ 11,732
   Natural gas	$ 735	$ 399	$ 600	$ 716
   Net earnings	$ 5,303	$ 600	$ 2,459	$ 2,458
   Net earnings per common share
   - basic	$ 2.55	$ 0.29	$ 1.17	$ 1.17
   - diluted	$ 2.54	$ 0.29	$ 1.17	$ 1.17
   	Dec 31	Sep 30	Jun 30	Mar 31
   ($ millions, except per common share amounts)	2024	2024	2024	2024
   Product sales (1)	$ 11,064	$ 10,401	$ 10,622	$ 9,422
   Crude oil and NGLs	$ 10,381	$ 9,943	$ 10,084	$ 8,676
   Natural gas	$ 451	$ 257	$ 331	$ 529
   Net earnings	$ 1,138	$ 2,266	$ 1,715	$ 987
   Net earnings per common share
   - basic	$ 0.54	$ 1.07	$ 0.80	$ 0.46
   - diluted	$ 0.54	$ 1.06	$ 0.80	$ 0.46

   1. Further details related to product sales for the three months ended December 31, 2025 and 2024 are disclosed in note 16 to the financial statements.

      Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:

      • Crude oil pricing - Fluctuations in global supply/demand including crude oil production levels from OPEC+ and its impact on world supply, the impact of geopolitical and market uncertainties (including those due to the conflicts in the Middle East, Ukraine and Venezuela, and the impacts of ongoing tariff and trade uncertainty) on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the start-up of the Trans Mountain Expansion ("TMX") pipeline in 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, the impact of liquefied natural gas ("LNG") demand and exports, and the impact of shale gas production in the US.

      • Crude oil and NGLs sales volumes - Fluctuations in production from Kirby and Jackfish, fluctuations in production due to the cyclic nature of Primrose, fluctuations in the Company's drilling program in the North America Exploration and Production segment, natural field declines, the impact of turnarounds in the Oil Sands Mining and Upgrading segment, the impact and timing of acquisitions (including the acquisition of working interests in AOSP and Duvernay assets in the fourth quarter of 2024, the acquisition of assets in the Palliser Block in the second quarter of 2025, the acquisition of assets in the Grande Prairie area in the third quarter of 2025, and the AOSP asset swap in the fourth quarter of 2025), wildfires, and maintenance activities in the North America Exploration and Production segment. Sales volumes in the International segments also reflected fluctuations due to the timing of liftings, planned abandonment activities in the North Sea, and temporary suspension of production at Baobab in Offshore Africa for planned floating production storage and offloading vessel ("FPSO") maintenance.
      • Natural gas sales volumes - Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, the impact and timing of acquisitions (including the acquisition of a working interest in the Duvernay assets in the fourth quarter of 2024, the acquisition of assets in the Palliser Block in the second quarter of 2025, and the acquisition of assets in the Grande Prairie area in the third quarter of 2025), natural field declines, the impact of seasonal conditions, and wildfires in the North America Exploration and Production segment.
      • Production expense - Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.
      • Depletion, depreciation and amortization expense - Fluctuations due to changes in sales volumes, timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds in the Oil Sands Mining and Upgrading segment, and recoverability charges related to the North Sea and Offshore Africa.
      • Share-based compensation - Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.
      • Risk management - Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities.
      • Interest expense - Fluctuations due to changing long-term debt levels and lease liabilities, the impact of movements in benchmark interest rates on outstanding floating rate long-term debt, and interest on PRT and corporate tax recoveries.
      • Foreign exchange - Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt and working capital.
      • Gain on acquisitions, disposition, and remeasurement - A gain on acquisitions representing the excess of the fair value of the net assets acquired compared to total purchase consideration and previously held interests, a gain on remeasurement to fair value of the Company's pre-existing 90% interest in the AOSP mines as part of the AOSP asset swap, and a gain on disposition of the 10% interest in Scotford and Quest disposed of as part of the AOSP asset swap.

Global crude oil benchmark pricing declined through the fourth quarter of 2025 as increasing global supply outpaced relatively modest demand growth, which remained subdued amid ongoing tariff and trade uncertainty. Late in the fourth quarter of 2025, escalating geopolitical tensions contributed to heightened concerns regarding potential crude oil supply disruptions entering into 2026. Natural gas benchmark pricing increased during the fourth quarter of 2025, driven by seasonal demand factors and continued strength in LNG export activity out of the US Gulf Coast. In Canada, AECO benchmark pricing improved due to robust export volumes out of the Western Canadian Sedimentary Basin ("WCSB"). The ongoing ramp-up of LNG Canada is expected to further increase LNG demand and support AECO pricing in 2026.

In the first quarter of 2025, the US government announced tariffs on certain Canadian goods. While these actions have contributed to market volatility, including commodity price and foreign currency volatility, these tariffs have not had a material impact on the Company's financial results as of the date of this MD&A. The duration of these trade actions remains uncertain, and broader changes to US economic policy may have a material effect on the Company's business, financial conditions, or results in future periods. The Company will continue to monitor and assess the implications of any current or emerging US economic policies.

Three Months Ended Year Ended

Dec 31

2024

Substantially all of the Company's production is sold based on US dollar benchmark pricing, with crude oil marketed based on WTI and Brent indices, and natural gas marketed using a diversified mix of AECO- and NYMEX-based pricing. The Company's realized prices are directly impacted by fluctuations in foreign exchange rates resulting in product revenues being impacted by changes in Canadian dollar sales prices relative to the US dollar benchmark prices.

Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$64.77 per bbl for the year ended December 31, 2025, a decrease of 14% from US$75.72 per bbl for the year ended December 31, 2024. WTI averaged US$59.13 per bbl for the fourth quarter of 2025, a decrease of 16% from US$70.27 per bbl for the fourth quarter of 2024 and a decrease of 9% from US$64.95 per bbl for the third 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$69.02 per bbl for the year ended December 31, 2025, a decrease of 15% from US$80.75 per bbl for the year ended December 31, 2024. Brent averaged US$63.69 per bbl for the fourth quarter of 2025, a decrease of 15% from US$74.69 per bbl for the fourth quarter of 2024 and a decrease of 8% from US$69.08 per bbl for the third quarter of 2025.

The decrease in WTI and Brent benchmark pricing for the three months and year ended December 31, 2025 from the comparable periods primarily reflected increased global supply and inventory builds driven by near-record production from non-OPEC+ producers and higher OPEC+ output. Supply gains exceeded global demand growth, which remained muted amid ongoing tariff and trade uncertainty.

The WCS Heavy Differential averaged US$11.10 per bbl for the year ended December 31, 2025, compared with US$14.73 per bbl for the year ended December 31, 2024. The WCS Heavy Differential averaged US$11.20 per bbl for the fourth quarter of 2025, compared with US$12.55 per bbl for the fourth quarter of 2024 and US$10.36 per bbl for the third quarter of 2025. The narrowing of the WCS Heavy Differential for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected full year takeaway capacity on the TMX pipeline and strong US Gulf Coast heavy oil pricing. The widening of the WCS Heavy Differential for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected seasonal demand factors and strong production, together with pipeline apportionment in the WCSB.

The SCO price averaged US$64.42 per bbl for the year ended December 31, 2025, a decrease of 14% from US$75.09 per bbl for the year ended December 31, 2024. The SCO price averaged US$57.78 per bbl for the fourth quarter of 2025, a decrease of 19% from US$71.13 per bbl for the fourth quarter of 2024 and a decrease of 13% from US$66.26 per bbl for the third quarter of 2025. The decrease in SCO pricing for the three months and year ended December 31, 2025 from the comparable periods primarily reflected weaker WTI benchmark pricing.

NYMEX benchmark pricing averaged US$3.43 per MMBtu for the year ended December 31, 2025, an increase of 51% from US$2.27 per MMBtu for the year ended December 31, 2024. NYMEX benchmark pricing averaged US$3.55 per MMBtu for the fourth quarter of 2025, an increase of 27% from US$2.79 per MMBtu for the fourth quarter of 2024 and an increase of 16% from US$3.07 per MMBtu for the third quarter of 2025. The increase in NYMEX natural gas pricing for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected lower US inventory levels in the first half of 2025, combined with record LNG exports out of the US Gulf Coast. The increase in NYMEX natural gas pricing for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected seasonal demand factors and strong LNG exports out of the US Gulf Coast.

AECO benchmark pricing averaged $1.76 per GJ for the year ended December 31, 2025, an increase of 29% from

$1.36 per GJ for the year ended December 31, 2024. AECO benchmark pricing averaged $2.22 per GJ for the fourth quarter of 2025, an increase of 61% from $1.38 per GJ for the fourth quarter of 2024 and an increase of 136% from

$0.94 per GJ for the third quarter of 2025. The increase in AECO natural gas pricing for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected higher NYMEX benchmark pricing and increased exports out of the WCSB. The increase in AECO natural gas pricing for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected improved seasonal demand factors and stronger WCSB exports following third quarter pipeline maintenance.

Three Months Ended Year Ended

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.

Three Months Ended Year Ended

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

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

Record crude oil and NGLs production before royalties for the year ended December 31, 2025 averaged 1,146,175 bbl/d, an increase of 14% from 1,005,603 bbl/d for the year ended December 31, 2024. Record crude oil and NGLs production before royalties for the fourth quarter of 2025 averaged 1,215,364 bbl/d, an increase of 12% from 1,090,002 bbl/d for the fourth quarter of 2024 and an increase of 3% from 1,175,604 bbl/d for the third quarter of 2025. The increase in crude oil and NGLs production before royalties for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, strong utilization in the Oil Sands Mining and Upgrading segment, and strong drilling results in the North America Exploration and Production segment. The increase for the fourth quarter of 2025 from the fourth quarter of 2024 also reflected the completion of the AOSP asset swap in November 2025. The increase in crude oil and NGLs production before royalties for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected the completion of the AOSP asset swap in November 2025, combined with strong utilization in the Oil Sands Mining and Upgrading segment.

Annual crude oil and NGLs production before royalties for 2025 was within the Company's previously issued production target of 1,137,000 bbl/d and 1,151,000 bbl/d. Annual crude oil and NGLs production before royalties for 2026 is now targeted to average between 1,188,000 bbl/d and 1,229,000 bbl/d. Production targets constitute forward-looking statements. Refer to the 'Advisory' section of this MD&A for further details on forward-looking statements.

Record natural gas production before royalties for the year ended December 31, 2025 averaged 2,547 MMcf/d, an increase of 19% from 2,147 MMcf/d for the year ended December 31, 2024. Natural gas production before royalties for the fourth quarter of 2025 averaged 2,660 MMcf/d, an increase of 17% from 2,283 MMcf/d for the fourth quarter of 2024 and comparable with 2,668 MMcf/d for the third quarter of 2025. The increase in natural gas production before royalties for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets.

Annual natural gas production before royalties for 2025 was within the Company's previously issued production target of 2,535 MMcf/d and 2,575 MMcf/d. Annual natural gas production before royalties for 2026 is now targeted to average between 2,560 MMcf/d and 2,615 MMcf/d. Production targets constitute forward-looking statements. Refer to the 'Advisory' section of this MD&A for further details on forward-looking statements.

Record North America crude oil and NGLs production before royalties for the year ended December 31, 2025 averaged 569,401 bbl/d, an increase of 12% from 509,288 bbl/d for the year ended December 31, 2024. North America crude oil and NGLs production before royalties for the fourth quarter of 2025 of 585,497 bbl/d increased 10% from 531,960 bbl/d for the fourth quarter of 2024 and was comparable with 584,625 bbl/d for the third quarter of 2025. The increase in North America crude oil and NGLs production before royalties for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 266,308 bbl/d for the fourth quarter of 2025, a decrease of 4% from 276,231 bbl/d for the fourth quarter of 2024 and comparable with 274,752 bbl/d for the third quarter of 2025. The decrease in thermal in situ production for the fourth quarter of 2025 from the fourth quarter of 2024 primarily reflected the cyclical nature of Primrose and natural field declines, partially offset by thermal pad additions.

Pelican Lake heavy crude oil production before royalties for the fourth quarter of 2025 averaged 41,577 bbl/d, a decrease of 6% from 44,035 bbl/d for the fourth quarter of 2024 reflecting Pelican Lake's long life low decline production, and comparable with 42,070 bbl/d for the third quarter of 2025.

Record North America natural gas production before royalties for the year ended December 31, 2025 averaged 2,538 MMcf/d, an increase of 19% from 2,136 MMcf/d for the year ended December 31, 2024. Natural gas production before royalties averaged 2,657 MMcf/d for the fourth quarter of 2025, an increase of 17% from 2,273 MMcf/d for the fourth quarter of 2024 and comparable with 2,658 MMcf/d for the third quarter of 2025. The increase in natural gas production before royalties for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets.

Record SCO production before royalties for the year ended December 31, 2025 averaged 565,102 bbl/d, an increase of 20% from 472,245 bbl/d for the year ended December 31, 2024. Record SCO production before royalties for the fourth quarter of 2025 averaged 619,901 bbl/d, an increase of 16% from 534,631 bbl/d for the fourth quarter of 2024 and an increase of 7% from 581,136 bbl/d for the third quarter of 2025. The increase in SCO production before royalties for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, combined with strong utilization. The increase in SCO production for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected the completion of the AOSP asset swap in November 2025, combined with strong utilization.

International crude oil and NGLs production before royalties for the year ended December 31, 2025 averaged 11,672 bbl/d, a decrease of 52% from 24,070 bbl/d for the year ended December 31, 2024. International crude oil and NGLs production before royalties for the fourth quarter of 2025 averaged 9,966 bbl/d, a decrease of 57% from 23,411 bbl/d for the fourth quarter of 2024 and comparable with 9,843 bbl/d for the third quarter of 2025. The decrease in International crude oil and NGLs production before royalties for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected the temporary suspension of production at Baobab in Offshore Africa due to planned maintenance on its FPSO, which is expected to return to service in the second quarter of 2026, planned North Sea abandonments conducted as part of the previously announced decommissioning plans, and natural field declines.

Three Months Ended Year Ended

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.

Three Months Ended Year Ended

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 7% to average $70.90 per bbl for the year ended December 31, 2025 from $76.37 per bbl for the year ended December 31, 2024. North America realized crude oil and NGLs prices averaged $63.83 per bbl for the fourth quarter of 2025, a decrease of 14% from $74.46 per bbl for the fourth quarter of 2024 and a decrease of 12% from $72.35 per bbl for the third quarter of 2025. The decrease in North America realized crude oil and NGLs prices per bbl for the year ended December 31, 2025 from the year ended December 31, 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 fourth quarter of 2025 from the comparable periods 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 and marketing strategy and in the fourth quarter of 2025 contributed approximately 230,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 36% to average $2.47 per Mcf for the year ended December 31, 2025 from $1.81 per Mcf for the year ended December 31, 2024. North America realized natural gas prices increased 46% to average $2.89 per Mcf for the fourth quarter of 2025 from $1.98 per Mcf for the fourth quarter of 2024 and increased 99% from $1.45 per Mcf for the third quarter of 2025. The increase in North America realized natural gas prices per Mcf for the three months and year ended December 31, 2025 from the comparable periods primarily reflected higher AECO benchmark and export pricing.

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

Three Months Ended

Sep 30

2025

Dec 31

2024

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 10% to average $98.07 per bbl for the year ended December 31, 2025 from $108.80 per bbl for the year ended December 31, 2024. International realized crude oil and NGLs prices decreased 9% to average $87.45 per bbl for the fourth quarter of 2025 from $96.36 per bbl for the fourth quarter of 2024 and decreased 7% from $94.08 per bbl for the third quarter of 2025. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, prevailing Brent benchmark prices and foreign exchange rates at the time of lifting.

Three Months Ended Year Ended

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 months and year ended December 31, 2025 and the comparable periods reflected movements in benchmark commodity prices, fluctuations in the WCS Heavy Differential and the impact of sliding scale royalty rates.

Crude oil and NGLs royalty rates(1) averaged approximately 17% of product sales for the year ended December 31, 2025 compared with 20% of product sales for the year ended December 31, 2024. Crude oil and NGLs royalty rates averaged approximately 15% of product sales for the fourth quarter of 2025 compared with 20% for the fourth quarter of 2024 and 18% for the third quarter of 2025. The decrease in royalty rates for the three months and year ended December 31, 2025 from the comparable periods primarily reflected lower benchmark pricing and the impact of sliding scale royalty rates.

Natural gas royalty rates averaged approximately 3% of product sales for the year ended December 31, 2025 compared with 2% of product sales for the year ended December 31, 2024. Natural gas royalty rates averaged approximately 3% of product sales for the fourth quarter of 2025 compared with 2% for the fourth quarter of 2024 and the third quarter of 2025. The increase in royalty rates for the three months and year ended December 31, 2025 from the comparable periods primarily reflected higher 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 year ended December 31, 2025 compared with 5% of product sales for the year ended December 31, 2024. Royalty rates as a percentage of product sales averaged approximately 5% for the fourth quarter of 2025 compared with 5% of product sales for the fourth quarter of 2024 and the third 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.

Three Months Ended Year Ended

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 year ended December 31, 2025 averaged $12.19 per bbl, comparable with $12.55 per bbl for the year ended December 31, 2024. North America crude oil and NGLs production expense for the fourth quarter of 2025 of $12.24 per bbl increased 13% from $10.83 per bbl for the fourth quarter of 2024 and was comparable with $11.97 per bbl for the third quarter of 2025. The increase in crude oil and NGLs production expense per bbl for the fourth quarter of 2025 from the fourth quarter of 2024 primarily reflected higher fuel costs.

North America natural gas production expense for the year ended December 31, 2025 averaged $1.11 per Mcf, a decrease of 7% from $1.19 per Mcf for the year ended December 31, 2024. North America natural gas production expense for the fourth quarter of 2025 of $1.09 per Mcf was comparable with $1.09 per Mcf for the fourth quarter of 2024 and decreased 4% from $1.14 per Mcf for the third quarter of 2025. The decrease in natural gas production expense per Mcf for the year ended December 31, 2025 from the year ended December 31, 2024 primarily reflected higher production volumes. The decrease in natural gas production expense per Mcf for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected lower service costs.

International crude oil and NGLs production expense for the year ended December 31, 2025 averaged $103.48 per bbl, an increase of 64% from $62.99 per bbl for the year ended December 31, 2024. International crude oil and NGLs production expense for the fourth quarter of 2025 of $96.90 per bbl increased 25% from $77.66 per bbl for the fourth quarter of 2024 and decreased 28% from $134.12 per bbl for the third quarter of 2025. The increase in crude oil and NGLs production expense per bbl for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected activities at Ninian in the pre-cessation period, the timing of liftings from various fields that have different cost structures, and the impact of foreign exchange. The decrease in crude oil and NGLs production expense per bbl for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected the timing of liftings from various fields that have different cost structures.

Three Months Ended Year Ended

1. In the second quarter of 2024 and in connection with the Company's notice of withdrawal from Block 11B/12B in South Africa, the Company derecognized

   $62 million of exploration and evaluation assets through depletion, depreciation and amortization expense.

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 year ended December 31, 2025 averaged $13.07 per BOE, comparable with $12.92 per BOE for the year ended December 31, 2024. Adjusted depletion, depreciation and amortization expense for the fourth quarter of 2025 averaged $12.98 per BOE, comparable with $13.01 per BOE for the fourth quarter of 2024 and $13.08 per BOE for the third quarter of 2025.

Pre-tax recoverability charges of $1,777 million in 2025 reflect the acceleration of the Company's abandonment and decommissioning activities and revisions to cost estimates in the North Sea, together with strategic decisions to not pursue an extension of its Production Sharing Contract ("PSC") for the Espoir Field, Block CI-26, in Offshore Africa and to not pursue development of Kossipo in Offshore Africa.

In the North Sea, following a competitive tender for the Ninian South Platform, estimated abandonment and decommissioning costs were higher than originally budgeted. Accordingly, in the third quarter of 2025, the Company updated its cost estimates for the Ninian Central and South Platforms and T-Block (Tiffany, Toni and Thelma fields). Additionally, in the third quarter of 2025, based on current and forecasted economic conditions, including commodity prices and market egress, the Company determined that the T-Block assets were no longer economically viable. As a result, at September 30, 2025, the Company recognized a non-cash charge of $695 million, comprised of a $734 million recoverability charge related to Ninian abandonment costs and a $524 million recoverability charge related to T-Block, net of deferred tax recoveries of $359 million and $204 million, respectively.

Further, during the fourth quarter of 2025, the Company decided to accelerate cessation of production at T-Block to the first quarter of 2027 and de-book associated reserves. This resulted in an additional non-cash charge of $141 million, primarily reflecting revised timing of the abandonment activities and updates to cost estimates, and comprised of a recoverability charge of $204 million, net of deferred tax recoveries of $63 million.

In Offshore Africa, during the fourth quarter of 2025, the Company determined that it would not pursue an extension of its PSC for the Espoir Field, Block CI-26, and de-booked associated crude oil reserves. The Company is working with the Government of Côte d'Ivoire to facilitate the transition of operatorship in the second half of 2026. As a result, the Company recognized a non-cash recoverability charge of $269 million as at December 31, 2025. Additionally, the Company decided not to pursue development of Kossipo in Offshore Africa, and recognized a recoverability charge of $46 million related to the derecognition of its exploration and evaluation assets.

Estimates of asset retirement obligations and related tax recoveries remain subject to revision as abandonment activities progress. Recoverability charges are recognized in depletion, depreciation and amortization expense.

Three Months Ended Year Ended

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 year ended December 31, 2025 averaged $0.80 per BOE, a decrease of 15% from $0.94 per BOE for the year ended December 31, 2024. Asset retirement obligation accretion expense for the fourth quarter of 2025 averaged $0.85 per BOE, a decrease of 4% from

$0.89 per BOE for the fourth quarter of 2024 and an increase of 10% from $0.77 per BOE for the third quarter of 2025. The decrease in asset retirement obligation accretion expense per BOE for the three months and year ended December 31, 2025 from the comparable periods in 2024 reflected the impact of changes in discount rates at December 31, 2024, combined with higher sales volumes in 2025, partially offset by revisions in cost and timing estimates at December 31, 2024, North America acquisitions completed during 2025, and North Sea cost and timing estimate revisions during 2025. The increase in asset retirement obligation accretion expense per BOE for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected the impact of revisions to cost and timing estimates at September 30, 2025 associated with the North Sea abandonment activities.

The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. Record SCO production averaged 619,901 bbl/d in the fourth quarter of 2025 primarily reflecting strong utilization in the Oil Sands Mining and Upgrading segment. The completion of the AOSP asset swap also contributed to increased volumes in the fourth quarter of 2025.

Three Months Ended Year Ended

Dec 31

2024

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 $86.41 per bbl for the year ended December 31, 2025, a decrease of 12% from

$98.03 per bbl for the year ended December 31, 2024. The realized SCO sales price averaged $75.90 per bbl for the fourth quarter of 2025, a decrease of 20% from $95.08 per bbl for the fourth quarter of 2024 and a decrease of 14% from $87.85 per bbl for the third quarter of 2025. The decrease in realized SCO sales price per bbl for the three months and year ended December 31, 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 value for royalty purposes, and the impact of sliding scale royalty rates. The decrease in bitumen royalties per bbl for the three months and year ended December 31, 2025 from the comparable periods primarily reflected the decrease in average bitumen value for royalty purposes and the impact of royalty true-ups.

Transportation expense averaged $3.31 per bbl for the year ended December 31, 2025, an increase of 14% from $2.91 per bbl for the year ended December 31, 2024. Transportation expense averaged $2.56 per bbl for the fourth quarter of 2025, a decrease of 29% from $3.60 per bbl for the fourth quarter of 2024 and a decrease of 34% from $3.86 per bbl for the third quarter of 2025. The increase in transportation expense per bbl for the year ended December 31, 2025 from the year ended December 31, 2024 primarily reflected higher volumes shipped on the TMX pipeline in 2025. The decrease in transportation expense per bbl for the fourth quarter of 2025 from the fourth quarter of 2024 primarily reflected lower volumes shipped to the US Gulf Coast, partially offset by higher volumes shipped on the TMX pipeline. The decrease for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected lower volumes shipped to the US Gulf Coast and on the TMX pipeline, as well as a reduction of transportation expense following the recognition of the Corridor pipeline as a leased asset in the fourth quarter.

Three Months Ended Year Ended

Three Months Ended Year Ended

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

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

3. Calculated as production expense divided by sales volumes.

Production expense for the year ended December 31, 2025 averaged $22.66 per bbl, comparable with $22.88 per bbl for the year ended December 31, 2024. Production expense for the fourth quarter of 2025 averaged $21.84 per bbl, an increase of 4% from $20.97 per bbl for the fourth quarter of 2024 and an increase of 3% from $21.29 per bbl for the third quarter of 2025. The increase in production expense per bbl for the fourth quarter of 2025 from the comparable periods primarily reflected higher energy costs.

Three Months Ended Year Ended

Dec 31

2024

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

Depletion, depreciation and amortization expense for the year ended December 31, 2025 averaged $13.42 per bbl, comparable with $13.17 per bbl for the year ended December 31, 2024. Depletion, depreciation and amortization expense for the fourth quarter of 2025 of $13.26 per bbl increased 4% from $12.76 per bbl for the fourth quarter of 2024 and was comparable with $13.38 per bbl for the third quarter of 2025. The increase in depletion, depreciation and amortization expense per bbl for the fourth quarter of 2025 from the fourth quarter of 2024 primarily reflected a higher depletable base due to the remeasurement of the AOSP mines and the recognition of the Corridor pipeline as a leased asset following the AOSP asset swap.

Three Months Ended Year Ended

Dec 31

2024

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

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the year ended December 31, 2025 of $0.42 per bbl decreased 14% from $0.49 per bbl for the year ended December 31, 2024. Asset retirement obligation accretion expense for the fourth quarter of 2025 of $0.37 per bbl decreased 16% from $0.44 per bbl for the fourth quarter of 2024 and decreased 8% from $0.40 per bbl for the third quarter of 2025. The decrease in asset retirement obligation accretion expense per bbl for the three months and year ended December 31, 2025 from the comparable periods primarily reflected the impact of higher sales volumes.

Three Months Ended Year Ended

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 other refined products and associated refining tolls are recognized in the Midstream and Refining segment. For the fourth quarter of 2025, production of ultra-low sulphur diesel and other refined products averaged 89,969 BOE/d (22,492 BOE/d to the Company) (three months ended September 30, 2025 - 38,434 BOE/d; 9,608 BOE/d to the Company; three months ended December 31, 2024 - 77,742 BOE/d; 19,436 BOE/d to the Company), reflecting the 25% toll payer commitment.

As at December 31, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $496 million (December 31, 2024 - $509 million). For the three months ended December 31, 2025, the Company's unrecognized share of the equity loss was $13 million (three months ended September 30, 2025 - recovery of unrecognized equity losses of $21 million; year ended December 31, 2025 - recovery of unrecognized equity losses of

$13 million; three months ended December 31, 2024 - recovery of unrecognized equity losses of $1 million; year ended December 31, 2024 - recovery of unrecognized equity losses of $46 million).

Three Months Ended Year Ended

1. Calculated as administration expense divided by sales volumes.

2. Total Company sales volumes.

Administration expense for the year ended December 31, 2025 of $1.07 per BOE increased 5% from $1.02 per BOE for the year ended December 31, 2024. Administration expense for the fourth quarter of 2025 of $1.04 per BOE increased 9% from $0.95 per BOE for the fourth quarter of 2024 and was comparable with $1.03 per BOE for the third quarter of 2025. The increase in administration expense per BOE for the year ended December 31, 2025 from the year ended December 31, 2024 primarily reflected higher personnel costs, including incremental costs from recent acquisitions. The increase in administration expense per BOE for the fourth quarter of 2025 from the fourth quarter of 2024 primarily reflected higher personnel costs and lower overhead recoveries.

Three Months Ended Year Ended

Dec 31

2024

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 $180 million of share-based compensation expense for the year ended December 31, 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.

Three Months Ended Year Ended

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 year ended December 31, 2025 increased 21% to $1.45 per BOE from $1.20 per BOE for the year ended December 31, 2024. Interest and other financing expense for the fourth quarter of 2025 increased 51% to $1.60 per BOE from $1.06 per BOE for the fourth quarter of 2024 and increased 158% from $0.62 per BOE for the third quarter of 2025. The increase in interest and other financing expense per BOE for the three months and year ended December 31, 2025 from the comparable periods in 2024 primarily reflected higher average debt levels, partially offset by higher sales volumes. The increase in interest and other financing expense per BOE for the fourth quarter of 2025 from the third quarter of 2025 primarily reflected the interest income on the deferred PRT and corporate tax recoveries in the North Sea in the third quarter.

The Company's average effective interest rate for the three months and year ended December 31, 2025 was 5.1%, an increase from 4.9% for the year ended December 31, 2024, reflecting higher average long-term debt levels held in 2025, and comparable with the fourth quarter of 2024 and the third quarter of 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.

Three Months Ended Year Ended

1. During 2025, the Company periodically entered into foreign currency put options contracts. Further details are disclosed in note 14 to the financial statements.

2. In the third quarter of 2025, the Company entered into fixed price financial contracts to buy 12,500 MMBtu/d of natural gas at US$1.30 AECO for the period of August to December 2025, and 25,000 MMBtu/d of natural gas at US$2.16 AECO for the period of January to December 2026.

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

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

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

6. In the second quarter of 2025, the Company entered into a long-term natural gas supply agreement containing an embedded derivative. Further details are disclosed in note 14 to the financial statements.

The Company recorded a net realized risk management gain of $89 million for the year ended December 31, 2025 and a net realized risk management gain of $27 million for the fourth quarter of 2025.

The Company recorded a net unrealized loss of $71 million ($55 million after tax of $16 million) on its risk management activities for the year ended December 31, 2025, and a net unrealized gain of $77 million ($59 million after tax of

$18 million) for the fourth quarter of 2025 (three months ended September 30, 2025 - unrealized loss of $160 million ($124 million after tax of $36 million); three months ended December 31, 2024 - unrealized gain of $4 million ($3 million after tax of $1 million); year ended December 31, 2024 - unrealized loss of $9 million ($10 million after tax of $1 million)).

Further details related to outstanding derivative financial instruments as at December 31, 2025 are disclosed in note 14 to the financial statements.

Three Months Ended Year Ended

1. Amounts are reported net of derivative financial instruments designated as cash flow hedges.

The net realized foreign exchange loss for the year ended December 31, 2025 was primarily related to exchange rate fluctuations on the settlement of US dollar debt, and on the settlement of working capital items denominated in US dollars. The net unrealized foreign exchange gain for the year ended December 31, 2025 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at December 31, 2025 was US$0.7292 (September 30, 2025 - US$0.7191; December 31, 2024 - US$0.6942).

Three Months Ended Year Ended

Three Months Ended Year Ended

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

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

3. Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, gain on disposition and remeasurement, and recoverability charges related to the North Sea and Offshore Africa.

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

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

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

The effective tax rate on net earnings and adjusted net earnings from operations for the three months and year ended December 31, 2025 and the comparable periods included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings.

Deferred corporate income tax in North America for the three months and year ended December 31, 2025 included the deferred tax impacts of the gain on disposition and remeasurement associated with the AOSP asset swap.

The current and deferred corporate income tax and the current and deferred PRT in the North Sea for the three months and year ended December 31, 2025 and the comparable periods included the impact of carrybacks of abandonment expenditures related to the decommissioning activities in the North Sea. Deferred PRT and income taxes also reflected the impact of the recoverability charges recognized in depletion, depreciation and amortization expense.

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

NET CAPITAL EXPENDITURES (1) (2)

Three Months Ended Year Ended

1. Net capital expenditures exclude the impact of lease assets and fair value adjustments.

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

3. Includes cash consideration paid of $320 million for exploration and evaluation assets and $2,553 million for property, plant and equipment within the North America Exploration and Production segment, and $6,175 million for property, plant and equipment within the Oil Sands Mining and Upgrading segment acquired from Chevron in the fourth quarter of 2024. Includes cash acquired and received as net consideration of $212 million related to the AOSP asset swap within the Oil Sands Mining and Upgrading segment in the fourth quarter of 2025.

The Company's strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production expenses.

Net capital expenditures were $6,579 million for the year ended December 31, 2025 compared with $14,431 million for the year ended December 31, 2024. Net capital expenditures were $1,237 million for the fourth quarter of 2025 compared with

$10,348 million for the fourth quarter of 2024 and $2,124 million for the third quarter of 2025. In addition, the Company reported abandonment expenditures of $771 million for the year ended December 31, 2025 compared with $646 million for the year ended December 31, 2024. Abandonment expenditures were $201 million for the fourth quarter of 2025 compared with $151 million for the fourth quarter of 2024 and $189 million for the third quarter of 2025.

On December 16, 2025, the Company announced its 2026 operating capital budget(1) targeted at approximately

$6,300 million. With this capital, the Company is targeting production growth in 2026 of approximately 3% from 2025, as it invests in short and medium-term production, while commencing front-end engineering and design on potential additional medium and long-term value creation opportunities. In addition, the Company targets approximately $125 million of capital related to carbon capture projects. The Company targets $993 million in abandonment expenditures for 2026. Subsequent to December 31, 2025, the Company revised its operating capital budget to $5,990 million and increased its production guidance to between 1,615,000 BOE/d and 1,665,000 BOE/d.

Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns, and the balancing of project risks and time horizons. The 2026 capital budget constitutes forward-looking statements and is based on net capital expenditures (Non-GAAP Financial Measure). Refer to the 'Advisory' section of this MD&A for further details on forward-looking statements.

In February 2026, subsequent to year end, the Company acquired certain producing and non-producing crude oil and NGLs, and natural gas assets in the Peace River area in the North America Exploration and Production segment for cash consideration of approximately $765 million, subject to final closing adjustments. Net assets acquired primarily include exploration and evaluation assets and property, plant and equipment. The Company also assumed associated asset retirement obligations. The 2026 capital budget did not include capital related to this acquisition.

Drilling Activity (1) (2)

Three Months Ended Year Ended

1. Includes drilling activity for North America and International segments.

2. Excludes stratigraphic and service wells.

3. Includes bitumen wells.

During the fourth quarter of 2025, the Company drilled 20 net natural gas wells, 67 net primary heavy crude oil wells, 25 net thermal bitumen wells, and 23 net light crude oil wells.

1. Forward-looking non-GAAP Financial Measure. The operating capital budget is based on net capital expenditures (Non-GAAP Financial Measure). Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A for more details on net capital expenditures.