Canadian Natural Resources: Financial Reports (26 Q3 Interim Report)

Canadian Natural's President, Scott Stauth, commented on the Company's third quarter results, "The strength of our well-balanced and diverse portfolio, combined with our continued focus on safe, effective and efficient operations, delivered another strong quarter. In Q3/26, we achieved production of approximately 1,217,000 bbl/d of liquids and

2.6 Bcf/d of natural gas, totaling approximately 1,652,000 BOE/d, inclusive of a planned turnaround at Horizon, reflecting the quality of our long life low decline asset base and disciplined operating culture.

Our thermal in situ operations achieved record quarterly production of approximately 300,000 bbl/d, an increase of 25,000 bbl/d from Q3/25 levels, driven by continued strong performance from new pads in Pike and Primrose. In our North American Conventional E&P assets, excluding thermal in situ operations, we also achieved record quarterly liquids production of approximately 358,000 bbl/d, an increase of 49,000 bbl/d from Q3/25 levels driven by accretive acquisitions and strong well performance.

At Horizon, subsequent to quarter end, the team safely and successfully completed the planned turnaround in 28 days, seven days earlier than budgeted, through strong execution, adding significant high value, high margin Synthetic Crude Oil ("SCO") production in Q4/26. Following the turnaround, Oil Sands Mining and Upgrading production has been strong, with current rates averaging approximately 640,000 bbl/d. At Horizon, we continue to build on the success of the 2024 reliability enhancement project that enabled us to move major turnarounds to once every two years from annually, and, combined with verified analysis of key parameters from the 2026 turnaround, we are now targeting to extend turnaround intervals at Horizon to once every three years, further increasing reliability and utilization. As a result, Horizon's three year average production capacity increases by an additional 5,000 bbl/d of high margin SCO, bringing total Oil Sands Mining and Upgrading production capacity up to approximately 597,000 bbl/d.

We are pleased to see the federal government designating the proposed West Coast oil pipeline, now known as Pacific Link, as a project of national interest. In addition, the federal government announced the Productivity Mega Deduction ("PMD"), which is expected to enhance competitiveness and investment in Canada. These measures, combined with the trilateral Memorandum of Understanding ("MOU") between the Oil Sands Alliance, the Government of Alberta and the Federal government, will support future economic growth, add additional egress opportunities, provide a clear pathway to reduce Greenhouse Gas ("GHG") emissions and enhance Canada's competitiveness for investment on a global scale. The next important step in this process is finalizing definitive agreements of the MOU, which will provide clarity on assessing our potential growth projects. If industry and governments are able to successfully complete and finalize the definitive agreements of the MOU, the result will be greater investments in the Canadian economy by the oil and gas industry, creating more jobs for Canadians and greater taxes and royalties for governments."

Canadian Natural's Chief Financial Officer, Victor Darel, added, "We achieved our net debt target of $13 billion in Q3/26, resulting in the Company now targeting to allocate 100% of free cash flow to shareholder returns through share repurchases. To further enhance visibility on share repurchases, effective immediately, the pace of monthly share repurchases is targeted at $800 million per month in both November 2026 and December 2026. As we move into 2027, shareholder returns are expected to remain strong as we now target to allocate 100% of free cash flow to share repurchases, subject to market conditions.

In the first nine months of 2026, we have returned a total of approximately $10.6 billion to shareholders, including

$6.8 billion directly through dividends and share buybacks and $3.8 billion indirectly through reductions in net debt.

We delivered strong financial results during the quarter, generating adjusted funds flow of approximately $5.5 billion or

$2.68 per share and adjusted net earnings of $3.4 billion or $1.67 per share, including the impact of a planned turnaround at Horizon and lower commodity prices relative to the second quarter, highlighting the quality of our assets and the effectiveness of our operational and capital allocation strategies. Additionally, sulphur pricing continued to strengthen, which contributed pre-tax net revenue of approximately $0.5 billion in Q3/26 and $0.9 billion year to date."

• Generated quarterly net earnings of approximately $3.0 billion and quarterly adjusted net earnings from operations of

  $3.4 billion.

• Generated quarterly adjusted funds flow of approximately $5.5 billion.

  • Captured strong SCO pricing that averaged a US$6.65/bbl premium to WTI in the quarter as a result of strong diesel pricing.

  • Strong sulphur pricing and sulphur production contributed pre-tax net revenue of approximately $0.5 billion(1) in Q3/26 and $0.9 billion through the first nine months of 2026.

• The Company achieved its $13 billion net debt target in Q3/26, with 100% of free cash flow now targeted for allocation to share repurchases.

• Returns to shareholders were significant, totaling approximately $5.3 billion in Q3/26.

  • Direct returns to shareholders totaled approximately $2.9 billion in Q3/26, comprised of $1.3 billion in dividends and

    $1.6 billion in share repurchases.

  • Indirect returns to shareholders, through net debt reductions, totaled approximately $2.4 billion in Q3/26, with net debt decreasing to $12.1 billion as of September 30, 2026, below our $13 billion net debt target.

• Total quarterly production was approximately 1,652,000 BOE/d, an increase of 31,000 BOE/d or 2% from Q3/25 levels.

  • Strong quarterly liquids production was approximately 1,217,000 bbl/d, an increase of 42,000 bbl/d or 4% from Q3/25 levels, inclusive of the planned turnaround at Horizon in Q3/26, which reduced volumes by approximately 75,000 bbl/d for the quarter.

    • Record quarterly thermal in situ production of approximately 300,000 bbl/d, an increase of 25,000 bbl/d or 9% from Q3/25 levels.

      - The two new Steam Assisted Gravity Drainage ("SAGD") pads at Pike 1 continue to exceed expectations, currently producing approximately 46,500 bbl/d at a Steam to Oil Ratio ("SOR") of 1.7x.

    • Record North American Conventional E&P quarterly liquids production of approximately 358,000 bbl/d, an increase of 49,000 bbl/d or 16% from Q3/25 levels.

• Subsequent to quarter end, on October 6, 2026, the team safely and successfully completed the planned turnaround at Horizon in 28 days, seven days earlier than budgeted. This early completion of the turnaround will result in approximately 23,000 bbl/d of additional high margin SCO production in Q4/26 than originally budgeted. Oil Sands Mining and Upgrading production has been strong, with current rates averaging approximately 640,000 bbl/d.

  SHAREHOLDER RETURNS

• On November 4, 2026, the Board of Directors approved a quarterly cash dividend of $0.625 per common share, payable on January 5, 2027 to shareholders of record at the close of business on December 15, 2026.

  • This represents an annualized dividend of $2.50 per common share. Our dividend has grown for 26 consecutive years, demonstrating 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.

• Year to date, up to and including November 4, 2026, the Company has returned a total of approximately $8.9 billion directly to shareholders through $5.1 billion in dividends and $3.8 billion through the repurchase and cancellation of approximately 58.2 million common shares at a weighted average price of $65.85 per share.

  • Included in year to date returns to shareholders is $728 million of share repurchases in October 2026.

• To further enhance visibility, effective immediately, the pace of monthly share repurchases is targeted at $800 million per month in both November 2026 and December 2026.

  • As we move into 2027, shareholder returns are expected to remain strong as we now target to allocate 100% of free cash flow to share repurchases, subject to market conditions.

1. Item is a component of 'Other income and revenue' in Note 17 Segmented Information in the Company's consolidated financial statements.

HIGHLIGHTS Three Months Ended Nine Months Ended Sep 30

2025

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. 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.

Three Months Ended Nine Months Ended Sep 30

2025

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

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

   • Oil Sands Mining and Upgrading production averaged 543,089 bbl/d of SCO in Q3/26, a decrease of 7% from Q3/25 levels, reflecting the planned turnaround at Horizon, partially offset by the additional working interest acquired in the Albian mines in December 2025.

     • The Company's Oil Sands Mining and Upgrading operating costs are industry leading, averaging $25.80/bbl (US$18.44/bbl) of SCO in Q3/26. Operating costs on a per barrel basis primarily reflect lower production as a result of the turnaround at Horizon.

   • Subsequent to quarter end, on October 6, 2026, the Company safely and successfully completed the planned turnaround at Horizon in 28 days, seven days earlier than budgeted. This early completion of the turnaround will result in approximately 23,000 bbl/d of additional high margin SCO production in Q4/26 than originally budgeted. Following the turnaround, Oil Sands Mining and Upgrading production has been strong, with current rates averaging approximately 640,000 bbl/d.

     • At Horizon, we continue to build on the success of the 2024 reliability enhancement project that enabled us to move major turnarounds to once every two years from annually, and, combined with verified analysis of key parameters from the 2026 turnaround, we are now targeting to extend turnaround intervals at Horizon to once every three years, further increasing reliability and utilization.

       • As a result of moving to a three year turnaround cycle, Horizon's average production capacity over the three year period increases by an additional 5,000 bbl/d of high margin SCO barrels, bringing total Oil Sands Mining and Upgrading production capacity up to approximately 597,000 bbl/d.

   • The Company's Naphtha Recovery Unit Tailings Treatment ("NRUTT") project at Horizon remains on track with capital on budget and targeted incremental annual production of approximately 6,300 bbl/d of SCO, following mechanical completion in Q3/27.

     North America Exploration and Production

     Thermal In Situ Oil Sands

     Three Months Ended Nine Months Ended

     	Sep 30 2026	Jun 30 Sep 30 2026 2025	Sep 30 2026	Sep 30 2025
     Bitumen production (bbl/d)	299,632	275,607 274,752	283,396	278,046
     Net bitumen wells drilled	45	38 11	114	53

   • Record thermal in situ production of 299,632 bbl/d was achieved in Q3/26, an increase of approximately 25,000 bbl/d or 9% from Q3/25 levels, reflecting strong production from the recently added SAGD pads and the new Cyclic Steam Stimulation ("CSS") pad at Primrose that came on production in July 2026.

     • Jackfish achieved record quarterly production of 143,039 bbl/d in Q3/26, exceeding its facility nameplate capacity by approximately 23,000 bbl/d as a result of strong performance from the Pike 1 pads.

       • The two new SAGD pads at Pike 1 continue to exceed expectations, currently producing approximately 46,500 bbl/d at a SOR of 1.7x. The Pike 1 SAGD pads are top tier in industry, driven by high-quality resource and continuous improvement in technology and execution.

     • Thermal in situ operating costs averaged $10.19/bbl (US$7.28/bbl) in Q3/26, a decrease of approximately 2% compared to $10.35/bbl in Q3/25, reflecting higher production, partially offset by higher energy costs.

   • Canadian Natural has decades of robust, capital efficient drill to fill opportunities across its long life low decline thermal in situ assets. The Company is on track with its 2026 budget, with the following pad additions:

     • At Primrose, two Cyclic Steam Stimulation ("CSS") pads are targeted to come on production in Q1/27 and Q2/27.

     • At Kirby, the Company is drilling a SAGD pad, which is targeted to come on production in Q3/27.

   • 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 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.

     • As a result of continued strong production performance from new wells at the Kirby South pilot, the Company is targeting to begin solvent injection using diluent in the first half of 2027.

       Crude oil and NGLs - excluding Thermal In Situ Oil Sands

       Three Months Ended Nine Months Ended

       	Sep 30 2026	Jun 30 Sep 30 2026 2025	Sep 30 2026	Sep 30 2025
       Crude oil and NGLs production (bbl/d)	358,484	338,138 309,873	341,848	285,931
       Net crude oil wells drilled	108	80 78	271	192

   • Record quarterly North America E&P liquids production, excluding thermal in situ operations, of 358,484 bbl/d was achieved in Q3/26, an increase of approximately 49,000 bbl/d or 16% from Q3/25 levels. This record reflects accretive Charlie Lake light crude oil acquisitions and strong organic growth in heavy crude oil, light crude oil and NGLs.

     • Strong primary heavy crude oil production averaged 95,621 bbl/d in Q3/26, an increase of 9% from Q3/25 levels, reflecting growth in our quick payout, high return multilateral wells.

       • Canadian Natural's highly successful multilateral drilling program, driven by continuous improvement in execution and technology advancements, continues to unlock opportunities on our 3 million net acres of high quality, multizone land throughout our primary heavy crude oil assets.

       • Operating costs in the Company's primary heavy crude oil operations averaged $18.02/bbl (US$12.88/bbl) in Q3/26, an increase from $16.46/bbl in Q3/25, reflecting increased weather related road maintenance and higher diesel costs.

     • In the Company's Pelican Lake polymer flood area, production averaged 45,514 bbl/d in Q3/26, an increase of 8% from Q3/25 levels, reflecting strong results from Driftwood and the long life low decline nature of these assets.

       • Operating costs at Pelican Lake averaged $10.45/bbl (US$7.47/bbl) in Q3/26, an increase from $9.00/bbl in Q3/25, reflecting increased trucked production from Driftwood.

     • Record quarterly production of 217,349 bbl/d was achieved in North America light crude oil and NGLs in Q3/26, an increase of approximately 37,000 bbl/d or 21% from Q3/25 levels, primarily reflecting accretive acquisitions and strong drilling results.

       • Operating costs in the Company's North America light crude oil and NGLs operations averaged $12.85/bbl (US$9.18/bbl) in Q3/26, comparable to Q3/25 levels.

         North America Natural Gas

         Three Months Ended Nine Months Ended

         	Sep 30 2026	Jun 30 Sep 30 2026 2025	Sep 30 2026	Sep 30 2025
         Natural gas production (MMcf/d)	2,602	2,563 2,658	2,611	2,498
         Net natural gas wells drilled	11	23 17	58	58

   • North America natural gas production averaged 2,602 MMcf/d in Q3/26, a decrease of 2% from Q3/25 levels, reflecting natural field declines partially offset by accretive acquisitions completed in 2026 and strong liquids-rich natural gas drilling results. North America natural gas operating costs averaged $1.14/Mcf in Q3/26.

     International Exploration and Production

     	Sep 30 2026	Jun 30 Sep 30 2026 2025	Sep 30 2026
     Crude oil production (bbl/d) Natural gas production (MMcf/d)	15,973 5	10,390 9,843 4 10	11,110 4	12,247 12

     Three Months Ended Nine Months Ended Sep 30

     2025

   • International E&P crude oil production volumes averaged 15,973 bbl/d in Q3/26, an increase of 62% compared to Q3/25 levels. The increase reflects the return of production at Baobab in Offshore Africa in June 2026 following completion of the refurbishment of the floating production storage and offloading ("FPSO") vessel, partially offset by the planned North Sea abandonments conducted as part of the previously announced decommissioning activities.

     • At Baobab, the Company commenced its Phase 5 drilling program in September 2026 and is targeting to complete the drilling program in Q3/27.

Drilling Activity Three Months Ended Nine Months Ended

1. Includes bitumen wells.

   • Canadian Natural drilled a total of 443 net crude oil and natural gas wells in the first nine months of 2026, 140 more than in the comparable period in 2025.

Three Months Ended Nine Months Ended

Sep 30

2025

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.

     • Approximately 776,000 bbl/d or 64% of total liquids production in Q3/26 consisted of SCO, light crude oil and NGLs.

     • The SCO price premium to WTI was strong in Q3/26, averaging US$6.65/bbl, primarily driven by strong diesel refining margins and planned seasonal maintenance in the Western Canadian Sedimentary Basin ("WCSB").

       • Current SCO annual average strip pricing in 2026 represents a premium to WTI of approximately US$5.56/bbl.

   • Canadian Natural has increased its committed volumes to 177,750 bbl/d on the Trans Mountain Expansion ("TMX") pipeline, bringing total contracted crude oil export transportation capacity up to 265,250 bbl/d to Canada's west coast and to the United States Gulf Coast, representing approximately 22% 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 84,730 bbl/d in Q3/26.

   • Canadian Natural maintains a diversified natural gas marketing strategy. In 2026, the Company is targeting to consume the equivalency of approximately 34% of its forecasted natural gas production in its Oil Sands Mining and Upgrading and thermal operations, with approximately 33% targeted to be sold at AECO/Station 2 pricing, and approximately 33% 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 Marketing, LLC. ("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.

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 Accounting Standards 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 and nine months ended September 30, 2026 dated November 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. Working capital movements, foreign exchange rate changes and other factors may result in shareholder returns varying from free cash flow generated in a particular period. Accordingly, the timing and allocation of shareholder returns may be accelerated, deferred or reallocated between periods at management's discretion.

As of September 30, 2026, the Company's net debt was below its $13 billion net debt target, resulting in the Company now targeting to allocate 100% of free cash flow to shareholder returns through share repurchases.

The Company's free cash flow for the three months ended September 30, 2026 and comparable periods is shown below:

Three Months Ended

(1) Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A for the three and nine months ended September 30, 2026 dated November 4, 2026.

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 (or capital forecast) is a forward-looking 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.

The capital budget (or capital forecast) excludes 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 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, forecasted or anticipated production volumes, royalties, production expenses, capital expenditures, forecasted 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"), the Pike thermal oil sands project ("Pike"), 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 crude oil, bitumen, 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/or deployment of technology and technological innovations (including artificial intelligence ("AI")) and the timely and effective implementation thereof; 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, bitumen, natural gas, and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates, and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance, or achievements of the Company to be materially different from any future results, performance, or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of conflicts in the Middle East and in Ukraine, the restriction or disruption of global trade routes, 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, bitumen, 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 timing, impact, and success of the implementation of the Memorandum of Understanding ("MOU") entered into between the Government of Canada and the Government of Alberta in November 2025 and the trilateral Memorandum of Understanding ("trilateral MOU") entered into between the Oil Sands Alliance, the Government of Alberta, and the Government of Canada in July 2026, including the execution of definitive agreements and satisfaction of other regulatory, financial and other conditions contemplated thereunder; 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 or AI-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the impact of AI on the Company's business operations; 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 of the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, bitumen, 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 or emissions, 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 and the trilateral 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 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 March 26, 2026, the Competition Act was further amended to remove the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminate private rights of action under the revised business-activity greenwashing provision. Notwithstanding these amendments, uncertainty surrounding the interpretation and enforcement of this legislation, which includes any 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 and nine months ended September 30, 2026, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2025. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three and nine months ended September 30, 2026 and this MD&A have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("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 and nine months ended September 30, 2026 in relation to the comparable periods in 2025 and the second quarter of 2026. 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, 2025, 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 November 4, 2026.

Three Months Ended Nine Months Ended Sep 30

2025

1. Further details related to product sales are disclosed in note 17 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 nine months ended September 30, 2026 were $8,848 million compared with $5,517 million for the nine months ended September 30, 2025. Net earnings for the nine months ended September 30, 2026 included non-operating losses, net of tax, of $1,593 million compared with non-operating losses of $216 million for the nine months ended September 30, 2025 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain on acquisition in 2025, and a recoverability charge related to the increase in estimated future abandonment costs for the Ninian field and T-Block assets in the North Sea in the third quarter of 2025. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2026 were $10,441 million compared with $5,733 million for the nine months ended September 30, 2025. Further details related to the movements in adjusted net earnings from operations are discussed in the 'Non-GAAP and Other Financial Measures' section of this MD&A.

   Net earnings for the third quarter of 2026 were $2,997 million compared with $600 million for the third quarter of 2025 and

   $4,503 million for the second quarter of 2026. Net earnings for the third quarter of 2026 included non-operating losses, net of tax, of $430 million compared with non-operating losses of $1,201 million for the third quarter of 2025 and non-operating losses of $65 million for the second quarter of 2026 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, and a recoverability charge related to the increase in estimated future abandonment costs for the Ninian field and T-Block assets in the North Sea in the third quarter of 2025. Excluding these items, adjusted net earnings from operations for the third quarter of 2026 were $3,427 million compared with $1,801 million for the third quarter of 2025 and $4,568 million for the second quarter of 2026. Further details related to the movements in adjusted net earnings from operations are discussed in the 'Non-GAAP and Other Financial Measures' section of this MD&A.

   The increase in net earnings and adjusted net earnings from operations for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected:

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

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

     The increase in net earnings and adjusted net earnings from operations for the third quarter of 2026 from the third quarter of 2025 primarily reflected:

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

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

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

   • lower sales volumes in the Oil Sands Mining and Upgrading segment.

     The decrease in net earnings and adjusted net earnings from operations for the third quarter of 2026 from the second quarter of 2026 primarily reflected:

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

   • lower realized SCO pricing and sales volumes in the Oil Sands Mining and Upgrading segment; partially offset by:

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

The impacts of depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchange loss (gain), and the gain on acquisition in 2025 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.

Cash flows from operating activities for the nine months ended September 30, 2026 were $17,115 million compared with

$11,338 million for the nine months ended September 30, 2025. Cash flows from operating activities for the third quarter of 2026 were $7,010 million compared with $3,940 million for the third quarter of 2025 and $6,823 million for the second quarter of 2026. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.

Adjusted funds flow for the nine months ended September 30, 2026 was $16,762 million compared with $11,712 million for the nine months ended September 30, 2025. Adjusted funds flow for the third quarter of 2026 was $5,522 million compared with $3,920 million for the third quarter of 2025 and $6,866 million for the second quarter of 2026. 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") recoveries, and prepaid cost of service tolls. Further details related to the movements in adjusted funds flow are discussed in the 'Non-GAAP and Other Financial Measures' section of this MD&A.

Crude oil and NGLs production before royalties for the third quarter of 2026 of 1,217,178 bbl/d increased 4% from 1,175,604 bbl/d for the third quarter of 2025 and decreased 3% from 1,248,889 bbl/d for the second quarter of 2026. Natural gas production before royalties for the third quarter of 2026 of 2,607 MMcf/d was comparable with 2,668 MMcf/d for the third quarter of 2025 and 2,567 MMcf/d for the second quarter of 2026. Total production before royalties for the third quarter of 2026 of 1,651,720 BOE/d was comparable with 1,620,261 BOE/d for the third quarter of 2025 and 1,676,754 BOE/d for the second quarter of 2026. Crude oil and NGLs and natural gas production volumes are discussed in detail in the 'Daily Production, before royalties' section of this MD&A.

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

   Product Prices

   In the Company's Exploration and Production segments, the realized crude oil and NGLs price averaged $95.93 per bbl for the third quarter of 2026, an increase of 32% from $72.57 per bbl for the third quarter of 2025 and a decrease of 9% from

   $105.11 per bbl for the second quarter of 2026. The realized natural gas price increased 40% to average $2.09 per Mcf for the third quarter of 2026 from $1.49 per Mcf for the third quarter of 2025 and was comparable with $2.05 per Mcf for the second quarter of 2026. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price increased 30% to average $114.56 per bbl for the third quarter of 2026 from $87.85 per bbl for the third quarter of 2025 and decreased 9% from $125.78 per bbl for the second quarter of 2026. 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 'Realized Product Prices, Royalties and Transportation - Oil Sands Mining and Upgrading' sections of this MD&A.

   Production Expense

   In the Company's Exploration and Production segments, crude oil and NGLs production expense(1) averaged $13.76 per bbl for the third quarter of 2026, an increase of 4% from $13.18 per bbl for the third quarter of 2025 and a decrease of 8% from $14.99 per bbl for the second quarter of 2026. Natural gas production expense(1) averaged $1.18 per Mcf for the third quarter of 2026, comparable with $1.16 per Mcf for the third quarter of 2025 and a decrease of 8% from $1.28 per Mcf for the second quarter of 2026. In the Oil Sands Mining and Upgrading segment, production expense(1) averaged $25.80 per bbl for the third quarter of 2026, an increase of 21% from $21.29 per bbl for the third quarter of 2025 and an increase of 16% from $22.19 per bbl for the second quarter of 2026. Crude oil and NGLs and natural gas production expense is discussed in detail in the 'Production Expense - Exploration and Production' and 'Production Expense - Oil Sands Mining and Upgrading' sections of this MD&A.

   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)	Sep 30 2026	Jun 30 2026	Mar 31 2026	Dec 31 2025
   Product sales (1)	$ 15,643	$ 17,214	$ 12,404	$ 10,710
   Crude oil and NGLs	$ 14,269	$ 16,067	$ 11,114	$ 9,666
   Natural gas	$ 531	$ 503	$ 832	$ 735
   Net earnings	$ 2,997	$ 4,503	$ 1,348	$ 5,303
   Net earnings per common share
   - basic	$ 1.46	$ 2.17	$ 0.65	$ 2.55
   - diluted	$ 1.45	$ 2.15	$ 0.64	$ 2.54
   	Sep 30	Jun 30	Mar 31	Dec 31
   ($ millions, except per common share amounts)	2025	2025	2025	2024
   Product sales (1)	$ 11,070	$ 9,675	$ 12,712	$ 11,064
   Crude oil and NGLs	$ 10,468	$ 8,874	$ 11,732	$ 10,381
   Natural gas	$ 399	$ 600	$ 716	$ 451
   Net earnings	$ 600	$ 2,459	$ 2,458	$ 1,138
   Net earnings per common share
   - basic	$ 0.29	$ 1.17	$ 1.17	$ 0.54
   - diluted	$ 0.29	$ 1.17	$ 1.17	$ 0.54

   1. Further details related to product sales for the three months ended September 30, 2026 and 2025 are disclosed in note 17 to the financial statements.

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

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

   • Crude oil pricing - Fluctuations in global supply/demand including crude oil production levels from OPEC+ and its impact on world supply; the impact of geopolitical and market uncertainties (including those due to the conflicts in the Middle East and in Ukraine, the restriction or disruption of global trade routes, and the impacts of ongoing tariff and trade uncertainty) on worldwide benchmark pricing; the impact of shale oil production in North America; market egress including the Trans Mountain Expansion ("TMX") pipeline; the impact of increased availability of heavy crude oil at the US Gulf Coast; 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, including the ramp-up of processing capacity at LNG Canada; 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; 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, which returned to service during the second quarter of 2026.

   • 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; natural field declines; the impact of seasonal conditions; wildfires; and maintenance activities 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 compliance costs; fluctuating energy costs; inflationary cost pressures; cost optimizations across all segments; turnarounds in the Oil Sands Mining and Upgrading segment; and maintenance activities.

   • 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; the impact on the depletable base resulting from the gain recognized on the AOSP mine assets in the fourth quarter of 2025; 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 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 - Fluctuations due to 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 and a gain on disposition of the 10% interest in the non-operated Scotford Upgrader ("Scotford") and the Quest Carbon Capture and Storage facility ("Quest") disposed of as part of the AOSP asset swap in the fourth quarter of 2025.

Global crude oil benchmark pricing decreased in the third quarter of 2026 as uncertainty over crude oil supply disruptions, including market expectations of a partial recovery in Middle East crude oil supply combined with weaker global demand reduced crude oil pricing early in the quarter. This decrease was partially offset by escalating geopolitical tensions toward the end of the third quarter, as global crude oil supply disruptions persisted following renewed conflict in the Middle East. Crude oil pricing is expected to remain volatile in the near-term amid ongoing geopolitical uncertainty. Although pricing may stabilize as supply recovers and supply-demand fundamentals reassert themselves, further conflict or disruptions to global crude oil supply could materially impact pricing through the remainder of 2026.

Natural gas benchmark pricing remained relatively consistent in the third quarter of 2026, as higher US production and planned LNG maintenance activities in the US Gulf Coast were offset by increased summer electricity demand. In Canada, increased demand from higher processing capacity at LNG Canada supported AECO benchmark pricing, partially offsetting elevated Western Canadian Sedimentary Basin ("WCSB") production. Demand from LNG Canada is expected to continue supporting AECO pricing as the facility operates toward full processing capacity.

In July 2026, the Oil Sands Alliance, the Government of Alberta, and the Government of Canada entered into a trilateral MOU. The trilateral MOU outlines a potential regulatory and fiscal framework intended to support the competitiveness of Canada's energy industry. Implementation of the framework contemplated by the trilateral MOU remains subject to definitive agreements and regulatory approvals.

Three Months Ended Nine Months Ended Sep 30

2025

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, which affect product revenues as Canadian dollar sales prices change relative to the US dollar benchmark prices.

Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$83.62 per bbl for the nine months ended September 30, 2026, an increase of 25% from US$66.67 per bbl for the nine months ended September 30, 2025. WTI averaged US$85.68 per bbl for the third quarter of 2026, an increase of 32% from US$64.95 per bbl for the third quarter of 2025 and a decrease of 8% from US$92.85 per bbl for the second quarter of 2026.

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$94.13 per bbl for the nine months ended September 30, 2026, an increase of 33% from US$70.82 per bbl for the nine months ended September 30, 2025. Brent averaged US$96.79 per bbl for the third quarter of 2026, an increase of 40% from US$69.08 per bbl for the third quarter of 2025 and a decrease of 7% from US$104.51 per bbl for the second quarter of 2026.

The increase in WTI and Brent benchmark pricing for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected continued conflict in the Middle East and the resulting global supply disruptions, partially offset by releases of global crude oil inventories in the second and third quarters of 2026 and weaker demand. The decrease in WTI and Brent benchmark pricing for the third quarter of 2026 from the second quarter of 2026 primarily reflected uncertainty over global crude oil supply disruptions, including market expectations of a partial recovery of Middle East crude oil supply early in the third quarter, partially offset by escalating geopolitical tensions toward the end of the quarter.

The WCS Heavy Differential averaged US$14.20 per bbl for the nine months ended September 30, 2026, compared with US$11.07 per bbl for the nine months ended September 30, 2025. The WCS Heavy Differential averaged US$13.86 per bbl for the third quarter of 2026, compared with US$10.36 per bbl for the third quarter of 2025 and US$14.62 per bbl for the second quarter of 2026. The widening of the WCS Heavy Differential for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected strong WTI benchmark pricing and increased heavy crude oil availability at the US Gulf Coast, partially offset by a tightening of the sour crude oil market due to Middle East supply disruptions. The narrowing of the WCS Heavy Differential for the third quarter of 2026 from the second quarter of 2026 primarily reflected strong seasonal demand and high refinery utilization in the third quarter.

The SCO price averaged US$88.51 per bbl for the nine months ended September 30, 2026, an increase of 33% from US$66.66 per bbl for the nine months ended September 30, 2025. SCO pricing averaged US$92.33 per bbl for the third quarter of 2026, an increase of 39% from US$66.26 per bbl for the third quarter of 2025 and a decrease of 9% from US$101.22 per bbl for the second quarter of 2026. The increase in SCO pricing for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected higher WTI benchmark pricing, planned seasonal maintenance, and stronger refinery demand amid tighter refined product markets due to Middle East supply disruptions. The decrease in SCO pricing for the third quarter of 2026 from the second quarter of 2026 primarily reflected lower WTI benchmark pricing, partially offset by strong diesel refining margins and planned seasonal maintenance in the WCSB.

NYMEX benchmark pricing averaged US$3.60 per MMBtu for the nine months ended September 30, 2026, an increase of 6% from US$3.39 per MMBtu for the nine months ended September 30, 2025. NYMEX benchmark pricing averaged US$2.96 per MMBtu for the third quarter of 2026, a decrease of 4% from US$3.07 per MMBtu for the third quarter of 2025 and comparable with US$2.89 per MMBtu for the second quarter of 2026. The increase in NYMEX natural gas pricing for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected strong LNG demand and exports out of the US Gulf Coast, and weather-related outages in the Eastern US following severe winter storms early in the first quarter of 2026. The decrease in NYMEX natural gas pricing for the third quarter of 2026 from the third quarter of 2025 primarily reflected higher US production combined with planned LNG maintenance activities in the US Gulf Coast in the third quarter of 2026, partially offset by increased summer electricity demand amid record average temperatures in the US, and increased LNG export capacity.

AECO benchmark pricing averaged $1.75 per GJ for the nine months ended September 30, 2026, an increase of 9% from

$1.61 per GJ for the nine months ended September 30, 2025. AECO benchmark pricing averaged $1.47 per GJ for the third quarter of 2026, an increase of 56% from $0.94 per GJ for the third quarter of 2025 and comparable with $1.43 per GJ for the second quarter of 2026. The increase in AECO natural gas pricing for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher NYMEX benchmark pricing, and increased demand from the continued ramp-up of LNG Canada. The increase in AECO natural gas pricing for the third quarter of 2026 from the third quarter of 2025 primarily reflected higher processing capacity at LNG Canada in 2026, partially offset by elevated WCSB production.

Three Months Ended Nine Months 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 Nine Months 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.

Crude oil and NGLs production before royalties for the nine months ended September 30, 2026 averaged 1,221,452 bbl/d, an increase of 9% from 1,122,859 bbl/d for the nine months ended September 30, 2025. Crude oil and NGLs production before royalties for the third quarter of 2026 averaged 1,217,178 bbl/d, an increase of 4% from 1,175,604 bbl/d for the third quarter of 2025 and a decrease of 3% from 1,248,889 bbl/d for the second quarter of 2026. The increase in crude oil and NGLs production before royalties for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected the acquisitions completed in 2025 and 2026 in the North America Exploration and Production segment, the AOSP asset swap completed in the fourth quarter of 2025, and the impact of the planned turnaround at Scotford in the second quarter of 2025, partially offset by the planned turnaround at Horizon in the third quarter of 2026 in the Oil Sands Mining and Upgrading segment. The increase in crude oil and NGLs production before royalties for the third quarter of 2026 from the third quarter of 2025 primarily reflected pad additions in thermal in situ, strong drilling results, and the acquisitions completed in 2026 in the North America Exploration and Production segment, and the AOSP asset swap completed in the fourth quarter of 2025, partially offset by the planned turnaround at Horizon in the third quarter of 2026 in the Oil Sands Mining and Upgrading segment. The decrease in crude oil and NGLs production before royalties for the third quarter of 2026 from the second quarter of 2026 primarily reflected the planned turnaround at Horizon in the third quarter of 2026 in the Oil Sands Mining and Upgrading segment, partially offset by higher thermal in situ production due to a pad addition at Primrose, and strong drilling results in the North America Exploration and Production segment.

Annual crude oil and NGLs production before royalties for 2026 is targeted to average between 1,204,000 bbl/d and 1,243,000 bbl/d. Production targets constitute forward-looking statements. Refer to the 'Advisory' section of this MD&A for further details on forward-looking statements.

Natural gas production before royalties for the nine months ended September 30, 2026 averaged 2,615 MMcf/d, an increase of 4% from 2,510 MMcf/d for the nine months ended September 30, 2025. Natural gas production before royalties for the third quarter of 2026 averaged 2,607 MMcf/d, comparable with 2,668 MMcf/d for the third quarter of 2025 and 2,567 MMcf/d for the second quarter of 2026. The increase in natural gas production before royalties for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected production associated with the light crude oil and liquids-rich natural gas acquisitions completed in 2025 and 2026, partially offset by natural field declines.

Annual natural gas production before royalties for 2026 is targeted to average between 2,595 MMcf/d and 2,635 MMcf/d. Production targets constitute forward-looking statements. Refer to the 'Advisory' section of this MD&A for further details on forward-looking statements.

North America crude oil and NGLs production before royalties for the nine months ended September 30, 2026 averaged 625,243 bbl/d, an increase of 11% from 563,977 bbl/d for the nine months ended September 30, 2025. Record North America crude oil and NGLs production before royalties for the third quarter of 2026 of 658,116 bbl/d increased 13% from 584,625 bbl/d for the third quarter of 2025 and increased 7% from 613,745 bbl/d for the second quarter of 2026. The increase in North America crude oil and NGLs production before royalties for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected the acquisitions completed in 2025 and 2026, and strong drilling results. The increase in North America crude oil and NGLs production before royalties for the third quarter of 2026 from the third quarter of 2025 primarily reflected pad additions at thermal in situ, strong drilling results, and the acquisitions completed in 2026. The increase in North America crude oil and NGLs production before royalties for the third quarter of 2026 from the second quarter of 2026 primarily reflected a thermal in situ pad addition at Primrose in the third quarter of 2026, and strong drilling results.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, with record quarterly production averaging 299,632 bbl/d for the third quarter of 2026, an increase of 9% from 274,752 bbl/d for the third quarter of 2025 and from 275,607 bbl/d for the second quarter of 2026. The increase in thermal in situ production in the third quarter of 2026 from the third quarter of 2025 primarily reflected pad additions at Pike. The increase in thermal in situ production in the third quarter of 2026 from the second quarter of 2026 primarily reflected a pad addition at Primrose in the third quarter of 2026.

Pelican Lake heavy crude oil production before royalties for the third quarter of 2026 averaged 45,514 bbl/d, an increase of 8% from 42,070 bbl/d for the third quarter of 2025 and an increase of 3% from 44,053 bbl/d for the second quarter of 2026, primarily reflecting strong results at Driftwood.

North America natural gas production before royalties for the nine months ended September 30, 2026 averaged 2,611 MMcf/d, an increase of 5% from 2,498 MMcf/d for the nine months ended September 30, 2025. Natural gas production before royalties averaged 2,602 MMcf/d for the third quarter of 2026, comparable with 2,658 MMcf/d for the third quarter of 2025 and 2,563 MMcf/d for the second quarter of 2026. The increase in natural gas production before royalties for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected production associated with the light crude oil and liquids-rich natural gas acquisitions completed in 2025 and 2026, partially offset by natural field declines.

SCO production before royalties for the nine months ended September 30, 2026 averaged 585,099 bbl/d, an increase of 7% from 546,635 bbl/d for the nine months ended September 30, 2025. SCO production before royalties for the third quarter of 2026 averaged 543,089 bbl/d, a decrease of 7% from 581,136 bbl/d for the third quarter of 2025 and a decrease of 13% from 624,754 bbl/d for the second quarter of 2026. The increase in SCO production before royalties for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected the AOSP asset swap completed in the fourth quarter of 2025, and the impact of the planned turnaround at Scotford in the second quarter of 2025, partially offset by the planned turnaround at Horizon in the third quarter of 2026. The decrease in SCO production before royalties for the third quarter of 2026 from the third quarter of 2025 primarily reflected the planned turnaround at Horizon in the third quarter of 2026, partially offset by the AOSP asset swap completed in the fourth quarter of 2025. The decrease in SCO production before royalties for the third quarter of 2026 from the second quarter of 2026 primarily reflected the planned turnaround at Horizon in the third quarter of 2026.

International crude oil and NGLs production before royalties for the nine months ended September 30, 2026 averaged 11,110 bbl/d, a decrease of 9% from 12,247 bbl/d for the nine months ended September 30, 2025. International crude oil and NGLs production before royalties for the third quarter of 2026 averaged 15,973 bbl/d, an increase of 62% from 9,843 bbl/d for the third quarter of 2025 and an increase of 54% from 10,390 bbl/d for the second quarter of 2026. The decrease in International crude oil and NGLs production before royalties for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected planned North Sea abandonments conducted as part of the previously announced decommissioning plans, partially offset by the return to service of the FPSO at Baobab in June 2026. The increase in crude oil and NGLs production before royalties for the third quarter of 2026 from the comparable periods primarily reflected the return to service of the FPSO at Baobab in June 2026.

Three Months Ended Nine Months 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 Nine Months 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 increased 26% to average $92.21 per bbl for the nine months ended September 30, 2026 from $73.40 per bbl for the nine months ended September 30, 2025. North America realized crude oil and NGLs prices averaged $95.34 per bbl for the third quarter of 2026, an increase of 32% from $72.35 per bbl for the third quarter of 2025 and a decrease of 9% from $104.77 per bbl for the second quarter of 2026. The increase in North America realized crude oil and NGLs prices per bbl for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected higher WTI benchmark pricing, partially offset by a widening of the WCS Heavy Differential. The decrease for the third quarter of 2026 from the second quarter of 2026 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 third quarter of 2026 contributed approximately 254,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 7% to average $2.48 per Mcf for the nine months ended September 30, 2026 from $2.32 per Mcf for the nine months ended September 30, 2025. North America realized natural gas prices increased 43% to average $2.07 per Mcf for the third quarter of 2026 from $1.45 per Mcf for the third quarter of 2025 and were comparable with $2.03 per Mcf for the second quarter of 2026. The increase in North America realized natural gas prices per Mcf for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher AECO and NYMEX benchmark pricing. The increase in North America realized natural gas prices per Mcf for the third quarter of 2026 from the third quarter of 2025 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

Jun 30

2026

Sep 30

2025

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 increased 16% to average $118.79 per bbl for the nine months ended September 30, 2026 from $102.18 per bbl for the nine months ended September 30, 2025. International realized crude oil and NGLs prices increased 29% to average $121.42 per bbl for the third quarter of 2026 from $94.08 per bbl for the third quarter of 2025 and decreased 4% from $126.82 per bbl for the second quarter of 2026. 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 Nine Months 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 and nine months ended September 30, 2026 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 21% of product sales for the nine months ended September 30, 2026 compared with 17% of product sales for the nine months ended September 30, 2025. Crude oil and NGLs royalty rates averaged approximately 25% of product sales for the third quarter of 2026 compared with 18% for the third quarter of 2025 and 19% for the second quarter of 2026. The increase in royalty rates for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected higher benchmark and annualized bitumen pricing, and the impact of sliding scale royalty rates. The increase in royalty rates for the third quarter of 2026 from the second quarter of 2026 primarily reflected higher annualized bitumen pricing, and the impact of sliding scale royalty rates.

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

Natural gas royalty rates averaged approximately 4% of product sales for the nine months ended September 30, 2026 compared with 3% of product sales for the nine months ended September 30, 2025. Natural gas royalty rates averaged approximately 3% of product sales for the third quarter of 2026 compared with 2% for the third quarter of 2025 and 3% for the second quarter of 2026. The increase in royalty rates for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected prevailing benchmark pricing.

Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.

Royalty rates as a percentage of product sales averaged approximately 4% for the nine months ended September 30, 2026 compared with 4% of product sales for the nine months ended September 30, 2025. Royalty rates as a percentage of product sales averaged approximately 4% for the third quarter of 2026 compared with 5% of product sales for the third quarter of 2025 and 5% for the second quarter of 2026.

Three Months Ended Nine Months 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 nine months ended September 30, 2026 averaged

$12.75 per bbl, an increase of 5% from $12.17 per bbl for the nine months ended September 30, 2025. North America crude oil and NGLs production expense for the third quarter of 2026 averaged $12.22 per bbl, comparable with $11.97 per bbl for the third quarter of 2025 and a decrease of 6% from $13.05 per bbl for the second quarter of 2026. The increase in crude oil and NGLs production expense per bbl for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher NGL processing costs resulting from acquisitions completed in the second half of 2025 and seasonal maintenance costs, partially offset by higher sales volumes in 2026. The decrease in crude oil and NGLs production expense per bbl for the third quarter of 2026 from the second quarter of 2026 primarily reflected higher sales volumes.

North America natural gas production expense for the nine months ended September 30, 2026 averaged $1.21 per Mcf, an increase of 8% from $1.12 per Mcf for the nine months ended September 30, 2025. North America natural gas production expense for the third quarter of 2026 of $1.14 per Mcf was comparable with $1.14 per Mcf for the third quarter of 2025 and decreased 9% from $1.25 per Mcf for the second quarter of 2026. The increase in natural gas production expense per Mcf for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher service costs. The decrease in natural gas production expense per Mcf for the third quarter of 2026 from the second quarter of 2026 primarily reflected lower energy costs.

International crude oil and NGLs production expense for the nine months ended September 30, 2026 averaged $101.35 per bbl, a decrease of 4% from $106.02 per bbl for the nine months ended September 30, 2025. International crude oil and NGLs production expense for the third quarter of 2026 of $81.06 per bbl decreased 40% from $134.12 per bbl for the third quarter of 2025 and decreased 43% from $141.98 per bbl for the second quarter of 2026. The decrease in crude oil and NGLs production expense per bbl for the three and nine months ended September 30, 2026 from the comparable periods primarily reflected the return to service of the FPSO at Baobab in June 2026.

Three Months Ended Nine Months Ended

1. During the third quarter of 2025, the Company recognized a recoverability charge of $1,258 million in depletion, depreciation and amortization expense related to the abandonment and decommissioning of its North Sea assets.

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 production or current period normal course depletion, depreciation and amortization expense such as asset recoverability charges. 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 nine months ended September 30, 2026 averaged

$12.16 per BOE, a decrease of 7% from $13.10 per BOE for the nine months ended September 30, 2025. Adjusted depletion, depreciation and amortization expense for the third quarter of 2026 averaged $12.25 per BOE, a decrease of 6% from $13.08 per BOE for the third quarter of 2025 and comparable with $12.09 per BOE for the second quarter of 2026. The decrease in adjusted depletion, depreciation and amortization expense per BOE for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected higher sales volumes in 2026.

Three Months Ended Nine Months 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 nine months ended September 30, 2026 averaged $0.79 per BOE, comparable with $0.78 per BOE for the nine months ended September 30, 2025. Asset retirement obligation accretion expense for the third quarter of 2026 averaged $0.75 per BOE, a decrease of 3% from

$0.77 per BOE for the third quarter of 2025 and a decrease of 6% from $0.80 per BOE for the second quarter of 2026. The decrease in asset retirement obligation accretion expense per BOE for the third quarter of 2026 from the third quarter of 2025 primarily reflected higher sales volumes in 2026, partially offset by the impact of revisions in cost and timing estimates in the North Sea in the second half of 2025. The decrease in asset retirement obligation accretion expense per BOE for the third quarter of 2026 from the second quarter of 2026 primarily reflected higher sales volumes in the third quarter of 2026.

The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites, achieving quarterly SCO production of 543,089 bbl/d during the third quarter of 2026, reflecting the planned turnaround at Horizon during the quarter.

Three Months Ended Nine Months Ended Sep 30

2025

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

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

3. Calculated as royalties divided by sales volumes.

4. Calculated as transportation expense divided by sales volumes.

The realized SCO sales price averaged $110.26 per bbl for the nine months ended September 30, 2026, an increase of 22% from $90.45 per bbl for the nine months ended September 30, 2025. The realized SCO sales price averaged $114.56 per bbl for the third quarter of 2026, an increase of 30% from $87.85 per bbl for the third quarter of 2025 and a decrease of 9% from $125.78 per bbl for the second quarter of 2026. The increase in the realized SCO sales price per bbl for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected higher WTI benchmark pricing combined with a strong SCO premium over WTI, partially offset by changes in the product sales mix between periods. The decrease in the realized SCO sales price per bbl for the third quarter of 2026 from the second quarter of 2026 primarily reflected lower WTI benchmark pricing.

The fluctuations in bitumen royalties per bbl in any particular period reflect the prevailing annualized bitumen value for royalty purposes, and the impact of sliding scale royalty rates. The increase in bitumen royalties per bbl for the three and nine months ended September 30, 2026 from the comparable periods primarily reflected higher annualized bitumen pricing, and the impact of sliding scale royalty rates.

Transportation expense averaged $2.56 per bbl for the nine months ended September 30, 2026, a decrease of 29% from

$3.59 per bbl for the nine months ended September 30, 2025. Transportation expense averaged $2.49 per bbl for the third quarter of 2026, a decrease of 35% from $3.86 per bbl for the third quarter of 2025 and comparable with $2.57 per bbl for the second quarter of 2026. The decrease in transportation expense per bbl for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected lower transportation expense following the recognition of the Corridor pipeline as a lease asset following the AOSP asset swap in the fourth quarter of 2025. The decrease in transportation expense per bbl for the third quarter of 2026 from the third quarter of 2025 also reflected lower volumes shipped to the US Gulf Coast in 2026.

Three Months Ended Nine Months Ended

Three Months Ended Nine Months 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 nine months ended September 30, 2026 averaged $23.85 per bbl, an increase of 4% from

$22.98 per bbl for the nine months ended September 30, 2025. Production expense for the third quarter of 2026 averaged

$25.80 per bbl, an increase of 21% from $21.29 per bbl for the third quarter of 2025 and an increase of 16% from $22.19 per bbl for the second quarter of 2026. The increase in production expense per bbl for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher service and energy costs, including diesel costs, partially offset by higher sales volumes in 2026. The increase in production expense per bbl for the third quarter of 2026 from the comparable periods primarily reflected the impact of the planned turnaround at Horizon in the third quarter of 2026.

Three Months Ended Nine Months Ended Sep 30

2025

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

Depletion, depreciation and amortization expense for the nine months ended September 30, 2026 averaged $13.98 per bbl, an increase of 4% from $13.49 per bbl for the nine months ended September 30, 2025. Depletion, depreciation and amortization expense for the third quarter of 2026 of $15.43 per bbl increased 15% from $13.38 per bbl for the third quarter of 2025 and increased 18% from $13.11 per bbl for the second quarter of 2026. The increase in depletion, depreciation and amortization expense per bbl for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected a higher depletable base due to the gain recognized on the AOSP mine assets and the recognition of the Corridor pipeline as a lease asset, both arising from the AOSP asset swap in the fourth quarter of 2025, partially offset by the impact of higher sales volumes in 2026. The increase in depletion, depreciation and amortization expense per bbl for the third quarter of 2026 from the third quarter of 2025 primarily reflected the impact of the planned turnaround at Horizon in the third quarter of 2026, a higher depletable base due to the gain recognized on the AOSP mine assets and the recognition of the Corridor pipeline as a lease asset, both arising from the AOSP asset swap in the fourth quarter of 2025. The increase in depletion, depreciation and amortization expense per bbl for the third quarter of 2026 from the second quarter of 2026 primarily reflected the impact of the planned turnaround at Horizon in the third quarter of 2026.

Three Months Ended Nine Months Ended Sep 30

2025

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

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense for the nine months ended September 30, 2026 of $0.40 per bbl decreased 7% from $0.43 per bbl for the nine months ended September 30, 2025. Asset retirement obligation accretion expense for the third quarter of 2026 of $0.42 per bbl increased 5% from $0.40 per bbl for the third quarter of 2025 and increased 11% from $0.38 per bbl for the second quarter of 2026. The decrease in asset retirement obligation accretion expense per bbl for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher sales volumes in 2026. The increase in asset retirement obligation accretion expense per bbl for the third quarter of 2026 from the comparable periods primarily reflected lower sales volumes in the third quarter of 2026.

Three Months Ended Nine Months 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's processing design capacity is 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. Bitumen feedstock throughput can exceed design capacity when asset reliability and operational performance support higher processing rates. 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 third quarter of 2026, production of ultra-low sulphur diesel and other refined products averaged 84,730 BOE/d (21,182 BOE/d to the Company) (three months ended June 30, 2026 - 92,748 BOE/d; 23,187 BOE/d to the Company; three months ended September 30, 2025 - 38,434 BOE/d; 9,608 BOE/d to the Company), reflecting the 25% toll payer commitment.

As at September 30, 2026, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $373 million (December 31, 2025 - $496 million). For the three months ended September 30, 2026, the Company's recovery of its share of unrecognized equity losses was $43 million (three months ended June 30, 2026 -recovery of unrecognized equity losses of $66 million; three months ended September 30, 2025 - recovery of unrecognized equity losses of $21 million; nine months ended September 30, 2026 - recovery of unrecognized equity losses of $134 million; nine months ended September 30, 2025 - recovery of unrecognized equity losses of $26 million). For the three and nine months ended September 30, 2026, the Company received partnership distributions of $11 million.

Three Months Ended Nine Months Ended

1. Calculated as administration expense divided by sales volumes.

2. Total Company sales volumes.

Administration expense for the nine months ended September 30, 2026 averaged $1.05 per BOE, a decrease of 3% from

$1.08 per BOE for the nine months ended September 30, 2025. Administration expense for the third quarter of 2026 of

$1.08 per BOE increased 5% from $1.03 per BOE for the third quarter of 2025 and increased 4% from $1.04 per BOE for the second quarter of 2026. The decrease in administration expense per BOE for the nine months ended September 30, 2026 from the nine months ended September 30, 2025 primarily reflected higher sales volumes, partially offset by higher personnel and corporate costs. The increase in administration expense per BOE for the third quarter of 2026 from the third quarter of 2025 primarily reflected higher personnel costs, partially offset by higher sales volumes. The increase in administration expense per BOE for the third quarter of 2026 from the second quarter of 2026 primarily reflected higher personnel costs and lower overhead recoveries.

Three Months Ended Nine Months Ended Sep 30

2025

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 $879 million of share-based compensation expense for the nine months ended September 30, 2026 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 Nine Months 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 nine months ended September 30, 2026 averaged $1.71 per BOE, an increase of 22% from $1.40 per BOE for the nine months ended September 30, 2025. Interest and other financing expense for the third quarter of 2026 of $1.43 per BOE increased 131% from $0.62 per BOE for the third quarter of 2025 and decreased 9% from $1.57 per BOE for the second quarter of 2026. The increase in interest and other financing expense per BOE for the three and nine months ended September 30, 2026 from the comparable periods in 2025 primarily reflected the impact of interest on tax recoveries in the North Sea in the third quarter of 2025, and higher average lease liabilities following the recognition of the Corridor pipeline in the fourth quarter of 2025, partially offset by higher sales volumes in 2026 and lower average long-term debt outstanding. The decrease in interest and other financing expense per BOE for the third quarter of 2026 from the second quarter of 2026 primarily reflected lower average long-term debt outstanding combined with higher interest income in the third quarter.

The Company's average effective interest rate for the three and nine months ended September 30, 2026 was 4.9%, a decrease from 5.1% for the nine months ended September 30, 2025, and 5.2% for the third quarter of 2025, and was comparable with the second quarter of 2026, reflecting interest rates on the medium-term note issuances in December 2025, combined with a lower effective interest rate on higher average lease liabilities.

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 Nine Months Ended

1. In the third quarter of 2026, the Company entered into fixed price financial contracts to buy 25,000 MMBtu/d of natural gas at US$1.32 AECO for the period of August to December 2026, and 25,000 MMBtu/d of natural gas at US$1.74 AECO for the period of January to December 2027.

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 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 15 to the financial statements.

The Company recorded a net realized risk management loss of $104 million for the nine months ended September 30, 2026 and a net realized risk management loss of $7 million for the third quarter of 2026.

The Company recorded a net unrealized risk management loss of $380 million ($292 million after tax of $88 million) for the nine months ended September 30, 2026 and a net unrealized risk management loss of $72 million ($55 million after tax of

$17 million) for the third quarter of 2026 (nine months ended September 30, 2025 - unrealized loss of $148 million ($114 million after tax of $34 million); three months ended June 30, 2026 - unrealized gain of $8 million ($6 million after tax of $2 million); three months ended September 30, 2025 - unrealized loss of $160 million ($124 million after tax of

$36 million)).

Further details related to outstanding derivative financial instruments as at September 30, 2026 are disclosed in note 15 to the financial statements.

Three Months Ended Nine Months Ended

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

The net realized foreign exchange loss for the nine months ended September 30, 2026 primarily reflected exchange rate fluctuations on the settlement of US dollar debt and working capital items denominated in US dollars.

The net unrealized foreign exchange loss for the nine months ended September 30, 2026 primarily reflected the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at September 30, 2026 was US$0.7047 (June 30, 2026 - US$0.7040; September 30, 2025 - US$0.7191).

Three Months Ended Nine Months Ended

Three Months Ended Nine Months 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, and a recoverability charge related to the increase in estimated future abandonment costs for the Ninian field and T-Block assets in the North Sea in the third quarter of 2025.

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 and nine months ended September 30, 2026 and the comparable periods included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings.

The current and deferred corporate income tax and the current and deferred PRT in the North Sea for the three and nine months ended September 30, 2026 and the comparable periods included the impact of carrybacks of abandonment expenditures related to the decommissioning activities in the North Sea.

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

NET CAPITAL EXPENDITURES (1) (2)

Three Months Ended Nine Months 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.

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 $6,316 million for the nine months ended September 30, 2026 compared with $5,342 million for the nine months ended September 30, 2025. Net capital expenditures were $1,883 million for the third quarter of 2026 compared with $2,124 million for the third quarter of 2025 and $2,405 million for the second quarter of 2026. In addition, the Company reported abandonment expenditures of $677 million for the nine months ended September 30, 2026 compared with $570 million for the nine months ended September 30, 2025. Abandonment expenditures were

$248 million for the third quarter of 2026 compared with $189 million for the third quarter of 2025 and $182 million for the second quarter of 2026.

Drilling Activity (1) (2)

Three Months Ended Nine Months Ended

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

2. Excludes stratigraphic and service wells.

3. Includes bitumen wells.

During the third quarter of 2026, the Company drilled 11 net natural gas wells, 61 net primary heavy crude oil wells, 10 net Pelican Lake heavy crude oil wells, 45 net thermal bitumen wells, and 37 net light crude oil wells.

1. Calculated as current assets less current liabilities, excluding the current portion of long-term debt.

2. Capital Management 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.

   As at September 30, 2026, the Company's capital resources consisted primarily of cash flows from operating activities, available bank credit facilities, and access to debt capital markets. Cash flows from operating activities and the Company's ability to renew existing bank credit facilities and raise new debt are dependent on factors discussed in the 'Business Environment' section of this MD&A and in the 'Risks and Uncertainties' section of the Company's annual MD&A for the year ended December 31, 2025. In addition, the Company's ability to renew existing bank credit facilities and raise new debt reflects current credit ratings, as determined by independent rating agencies and market conditions.

   The Company continues to believe its internally generated cash flows from operating activities, supported by its ongoing hedge policy, the flexibility of its capital expenditure programs and multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms will provide sufficient liquidity to sustain its operations in the short-, medium-, and long-term and support its growth strategy.

   On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:

   • Monitoring cash flows from operating activities, which is the primary source of funds;

   • Monitoring exposure to individual customers, contractors, suppliers, and joint venture partners on a regular basis and, where appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default;

   • Actively managing the allocation of capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments, and long-term debt;

   • Monitoring the Company's ability to fulfill financial obligations as they become due or the ability to monetize assets in a timely manner at a reasonable price;

   • Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and

   • Reviewing the Company's borrowing capacity:

     • During the first quarter of 2026, the Company cancelled the $140 million portion of its $2,565 million revolving syndicated credit facility, maturing June 2027, reducing the capacity to $2,425 million, with a maturity of June 2029.

     • Borrowings under the Company's credit facilities may be made by way of pricing referenced to CORRA, SOFR, US base rate or Canadian prime rate.

     • The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

     • During the third quarter of 2026, the Company repaid $441 million of 3.42% medium-term notes originally due December 1, 2026.

     • In August 2025, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires in September 2027. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. As at September 30, 2026, the Company had $1,350 million remaining on its base shelf prospectus.

     • In August 2025, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$4,500 million of debt securities in the United States, which expires in September 2027. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. As at September 30, 2026, the Company had US$3,003 million remaining on its base shelf prospectus.

As at September 30, 2026, the Company had undrawn bank credit facilities of $5,421 million, and a fully drawn non-revolving term credit facility of $4,000 million. Including cash and cash equivalents, the Company had approximately

$9,937 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit.

Long-term debt, net was $12,117 million as at September 30, 2026 (December 31, 2025 - $15,944 million), resulting in a debt to book capitalization ratio of 20.5% (December 31, 2025 - 26.4%). The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility agreements to not exceed 65%. As at September 30, 2026, the Company was in compliance with this covenant.

The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Further details related to the Company's long-term debt as at September 30, 2026 are discussed in note 8 to the financial statements.

The Company periodically utilizes commodity derivative financial instruments under its commodity hedge policy to reduce the risk of volatility in commodity prices and to support the Company's cash flow for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase of commodity put options is in addition to the above parameters.

As at September 30, 2026, the maturity dates of certain financial liabilities, including long-term debt and other long-term liabilities and related interest payments, were as follows:

1. Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.

2. Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $331 million; one to less than two years, $286 million; two to less than five years, $614 million; and thereafter, $1,712 million.

3. Includes a gross derivative liability of $563 million associated with the Company's natural gas embedded derivative. The gross liability is offset by a gross derivative asset of $126 million, resulting in a net liability of $437 million.

4. Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at September 30, 2026.

As at September 30, 2026, there were 2,045,524,000 common shares outstanding (December 31, 2025 - 2,081,578,000 common shares) and 54,791,000 stock options outstanding (December 31, 2025 - 54,734,000 stock options). As at November 3, 2026, the Company had 2,035,130,000 common shares outstanding and 53,095,000 stock options outstanding.

On March 4, 2026, the Board of Directors approved a 6% increase in the quarterly dividend to $0.625 per common share, beginning with the dividend paid on April 7, 2026.

On March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.

On March 10, 2026, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 182,396,564 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2026 and ending March 12, 2027, subject to applicable securities laws.

For the nine months ended September 30, 2026, the Company purchased 46,975,000 common shares at a weighted average price of $64.01 per common share for a total cost, including tax, of $3,055 million. Retained earnings were reduced by $2,786 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to September 30, 2026, up to and including November 3, 2026, the Company purchased 10,800,000 common shares at a weighted average price of $73.64 per common share for a total cost, including tax, of $811 million.

In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company's commitments as at September 30, 2026:

Remaining

1. The Company's commitment under its product transportation agreement on the TMX pipeline reflects the toll approved by the Canada Energy Regulator in the third quarter of 2026. The Company's product transportation commitment was extended through 2046, with capacity increased to approximately 178,000 bbl/d.

2. In the second quarter of 2026, the Company executed crude oil transportation agreements delivering between 150,000 bbl/d and 165,000 bbl/d of new pipeline capacity to US markets, with service currently expected to commence in the fourth quarter of 2028. These agreements are subject to certain conditions precedent, including a final investment decision by the project proponents and certain regulatory approvals. Accordingly, the related agreements will not be recognized as commitments until the completion of all conditions precedent. The transportation agreements have a term of 20 years and, if all conditions are met, will result in transportation payments of approximately $500 million to $550 million annually being added to the Company's commitments.

3. Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $1,728 million of interest payable over the 40-year tolling period, ending in 2058.

In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement, and construction of its various development projects. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation.

The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.

The preparation of financial statements requires the Company to make estimates, assumptions, and judgements in the application of IFRS Accounting Standards that have a significant impact on the financial results of the Company. Actual results may differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant accounting estimates is contained in the Company's annual MD&A and audited consolidated financial statements for the year ended December 31, 2025.

There have been no changes to internal control over financial reporting ("ICFR") during the nine months ended September 30, 2026 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting. Due to inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

This MD&A includes references to non-GAAP and other financial measures as defined in 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 Accounting Standards and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below.

Adjusted net earnings from operations is a non-GAAP financial measure that adjusts net earnings as presented in the Company's consolidated statements of earnings, for non-operating items, net of tax impacts. The Company considers adjusted net earnings from operations a key measure in evaluating its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. A reconciliation for adjusted net earnings from operations is presented below.

Three Months Ended Nine Months Ended

1. Share-based compensation includes costs incurred under the Company's Stock Option Plan and PSU Plan. The fair value of the share-based compensation is recognized as a liability on the Company's balance sheets, and periodic changes in the fair value are recognized in net earnings. Pre-tax share-based compensation for the three months ended September 30, 2026 was an expense of $431 million (three months ended June 30, 2026 - $196 million recovery; three months ended September 30, 2025 - $63 million expense; nine months ended September 30, 2026 - $879 million expense; nine months ended September 30, 2025 - $97 million expense).

2. Derivative financial instruments are recognized at fair value on the Company's balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than those amounts reflected in the financial statements due to changes in prices of the underlying items hedged, primarily natural gas and foreign exchange. The pre-tax unrealized risk management loss for the three months ended September 30, 2026 was $72 million (three months ended June 30, 2026 - $8 million gain; three months ended September 30, 2025 - $160 million loss; nine months ended September 30, 2026 - $380 million loss; nine months ended September 30, 2025 - $148 million loss).

3. Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange gains and losses are the same.

4. Realized foreign exchange gains and losses associated with financing activities primarily result from the repayment of US dollar denominated debt and are recognized in net earnings. Pre- and after-tax amounts for these realized foreign exchange gains and losses are the same.

5. During the second quarter of 2025, the Company acquired an interest in certain producing and non-producing assets in the North America Exploration and Production segment, resulting in a pre- and after-tax gain on acquisition of $80 million representing the excess of the fair value of the net assets acquired compared to the total purchase consideration.

6. During the third quarter of 2025, the Company recognized a pre-tax recoverability charge of $1,258 million ($695 million after-tax) in depletion, depreciation and amortization relating to the increase in estimated future abandonment costs for the Ninian field and T-Block assets in the North Sea. The costs are included in capital and abandonment expenditures, consistent with the treatment of all abandonment expenditures for the purpose of the Company's non-GAAP measures.