Slides
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Corporate Presentation October 2025
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2 Cenovus at a glance Note: See Advisory. Market capitalization as at October 30th, 2025. Values are approximate. Expected production based on mid-point of corporate guidance. Proved plus probable reserves evaluated by independent qualified evaluators effective date of December 31, 2024. Cash returns to shareholders includes base dividends, preferred share dividends, variable dividends, preferred share redemptions and common share repurchases. Ticker symbol TSX, NYSE | CVE Shares outstanding 1,766 million Market capitalization $41 billion Operating Statistics 2025 production ~815 MBOE/d Upgrading and refining operable capacity 473 Mbbls/d 2024 proved plus probable (2P) reserves 8.5 BBOE Financial Summary Trailing twelve months Adjusted Funds Flow (AFF) $7.8 billion September 30, 2025 Net Debt $5.3 billion September 30, 2025 Long-Term Debt, including current portion $7.2 billion Trailing twelve months total cash returns to shareholders $3.4 billion Net Debt/Trailing twelve months AFF 0.7x Annual dividend per share (yield) $0.80/share (3.4%) Market Summary
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3 Third-quarter 2025 results Note: See Advisory. 1) Non-GAAP financial measure. Upstream Production 833 MBOE/d Downstream Throughput 711 Mbbls/d Cash From Operating Activities $2,131 million Adjusted Funds Flow1 $2,466 million Free Funds Flow1 $1,312 million Capital Investments $1,154 million Net Debt $5,255 million Long-Term Debt, including current portion $7,156 million • Record upstream production in the third quarter, including record production from the Oil Sands segment. • Record quarterly production at Foster creek bringing forward growth from the optimization project ahead of schedule. • Narrows Lake project complete and ramping up toward full rates. • West White Rose project nearing completion, with first oil expected in the second quarter of 2026. • Record U.S. refining crude throughput with a utilization of 99%. • Unit operating expense excluding turnarounds declined 8% relative to the prior quarter. • Returned $1.3 billion to shareholders through share buybacks and dividends in the third quarter. • Closed sale of 50% interest in WRB Refining to joint venture partner Philips 66. • Cash proceeds received October 1, 2025. Highlights Third-quarter results
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4 Cenovus’s value proposition Note: See Advisory. 1) Base dividend capacity calculated at US$45 WTI. Dividend capacity calculated as adjusted funds flow less sustaining capital, asset retirement obligations and capital lease expenses. Robust balance sheet Manage towards $4.0B net debt; represents <1x cash flow at US$45 WTI. Returning excess cash to shareholders Repurchased ~3% of shares outstanding in the first 9 months of 2025. Highly efficient capital driving growth to ~950,000 BOE/d by 2028. Growing base dividend capacity to ~$2.0B1 Double-digit annual base dividend growth. Conservative capital structure Disciplined operating model Increasing shareholder returns Low operating & sustaining capital costs Combined oil sands operating and sustaining capital costs <$21/bbl. Low cost, long-life resource base Resilient at bottom of the cycle Sustaining capital & base dividend funded at US$45 WTI. 8.5 billion barrels of 2P reserves 29-year reserves life index. All discretionary investments generate economic returns at US$45 WTI.
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5 $0 $5 $10 $15 Sustaining Capital Operating Costs Combined sustaining + operating costs of <$21/bbl Significant thermal bitumen reserves with ~35yrs reserves life index World class Oil Sands assets: low cost with decades of reserves Note: See Advisory. 1) Forecasted at US$60 WTI. 2) Proved plus probable reserves evaluated by independent qualified evaluators effective December 31, 2024. Competitive operating costs1 of $10 - $12 per barrel Oil Sands sustaining capital1 of $7 - $9 per barrel Sustainable value creation over the long term $/bbl 7.6 BBOE of booked 2P thermal bitumen reserves2 2024 Production (BBOE) Proved plus Probable (2P) Reserves (BBOE) Christina Lake Foster Creek Lloyd Thermal Sunrise
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6 The most experienced and highest performing SAGD operator Leveraging operating experience and technology to delivery industry-leading results Steam to oil ratioCumulative operating years Lowest SORMost experiencedHighest production Notes: Peers include CNQ, COP, MEG, SU. Cumulative operating years calculated as the sum of all operating durations for SAGD producers and injectors. Production and SOR based on total SAGD average in 2024. Source: Petrinex and AER. 0 5,000 10,000 15,000 20,000 CVE 0 100 200 300 400 500 600 700 CVE Planned Growth 2024 Production Peer Peer Peer Peer Peer Peer Peer Peer Production (Mbbls/d) 1.0 2.0 3.0 CVE Peer Peer Peer Peer
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7 Integrated planning from geology through to production to reduce SOR, lower F&D and drive higher value Cenovus’s optimized SAGD development approach W12 Foster Creek Narrows Lake development (July 2025) Christina Lake development (2028+) 31m Understanding the reservoir is key to efficient resource recovery Prioritizing the next best resource at the lowest cost Engineering well design to match geographical formation Utilizing technology to optimize reservoir conformance Actively reallocating steam to pads with better SOR to maximize production Injector Producer 0 2,000 4,000 0 1 2 3 4 5 6 7 8 9 10 0 4,000 8,000 0 1 2 3 4 5 6 7 8 9 10 Steam (bbls/d) Oil (bbls/d) Optimized Unoptimized Optimized Unoptimized Geological characterization Optimal dev Sequencing Front end well design Operating strategy Late life management Note: See Advisory.
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8 Capital efficient Oil Sands growth projects Near-term Oil Sands production growth >20,000 bbls/d Steady growth 2024 – 2028 2028+ peak production Narrows Lake Tie Back Foster Creek Optimization Sunrise Optimization Conventional Heavy Oil 15,000 – 20,000 bbls/d Steady growth 2024 – 2027 2027 peak production >30,000 bbls/d Growth into early 2026 2027 peak production 20,000 – 30,000 bbls/d First oil achieved July 2025 2026 peak production Note: See Advisory.
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9 Note: See Advisory. 1. Annual pre-tax synergies at $60/bbl WTI and WTI-WCS differential of $14/bbl. Consolidating the highest-quality resource within the Oil Sands Proposed acquisition of MEG • Fully contiguous assets in Christina Lake enables seamless, integrated development of the region. • Together with Foster Creek, brings together the industry’s three most efficient projects with combined production of ~550 Mbbls/d and SOR of ~2.2. • Expecting over $400 million in identified annual synergies 1 starting in 2028. • Total combined Oil Sands production of over 720 Mbbls/d growing to ~850 Mbbls/d in 2028. Cenovus Christina Lake MEG Christina Lake Foster Creek Narrows Lake Cenovus MEG Christina Lake Oil Sands Property
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10 $0 $50 $100 $150 $200 $250 $300 $350 $400 MEG acquisition synergies Note: See Advisory. 1. Annual pre-tax synergies at $60/bbl WTI and WTI-WCS differential of $14/bbl. Over $400 million of expected annual synergies identified with implementation plans in place Over $400MM of expected annual synergies1 $MM G&A Commercial Financing Near-term Operating & Development 2028+ Operating & Development $80MM $30MM $10MM $30MM >$250MM $150MM near-term synergies achievable in 2026 • ~$120MM annual corporate and commercial synergies achievable in first full year. • ~$80MM G&A: corporate overhead, IT , procurement. • ~$30MM commercial: Transportation optimization, trading & marketing, storage & blending. • ~$10MM financing fees and other. • ~$280MM annual operating and development synergies. • ~$30MM near-term: production and cost enhancements, net of incremental capital. • >$250MM annual from 2028 onward: higher production, structurally lower sustaining capital, operating efficiencies. • Additional >$200MM near-term one-time benefit net of integration and transaction costs (not included in chart). Corporate and Commercial Operating and Development
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11 Continuing to hit key milestones 0 20 40 60 2026F 2027F 2028F Mbbls/d Concrete gravity structure installed in Q2 2025 First oil expected in Q2 2026 Topsides lifted and set in place in early Q3 2025 White Rose production profile1 Drilling expected to commence in Q4 2025 West White Rose Project Net peak production of ~45,000 bbls/d in 2028 High-netback, Brent-based pricingNote: See Advisory. 1) Production net to Cenovus.
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12 2025 capital investment Disciplined capital investment with targeted investment in high return growth projects Downstream Sustaining Upstream Sustaining Sunrise Growth Conventional Heavy Oil Foster Creek Optimization & Enhanced Sulphur Recovery Projects Conventional Gas West White Rose Downstream $1.4B - $1.8B Targeted Growth Capital Total Capital $4.6B - $5.0B Majority of growth capital spend concluding in 2025 Total Sustaining capital of ~$3.2B Note: See Advisory.
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13 Capital allocation priorities Committed to balance sheet strength and shareholder returns • Manage towards ~$4.0 billion of net debt. • Fully fund sustaining capital and base dividend at US$45 WTI. • Deliver disciplined growth through highly efficient capital projects that meet hurdles at US$45 WTI. • Approximately ~100% excess of EFFF returned to shareholders when $4 billion net debt target is achieved. Committed capital Safe and reliable operations Sustaining capital Base & preferred dividends Asset retirement obligations Capital leases Discretionary capital Growth capital Shareholder returns Share buybacks Acquisitions & divestitures Variable dividends Maintain $4.0B of net debt EFFF = AFF - committed capital - growth capital +/- A&D Note: See Advisory.
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14 Disciplined and sustainable shareholder returns Consistent track record of base dividend growth and opportunistic repurchases $0.00 $0.10 $0.20 $0.30 2021 2022 2023 2024 2025 $/share Note: See Advisory. 1) Includes repurchases of common shares, warrants and expiration of options. Growing quarterly base dividend 1,600 1,800 2,000 2,200 2021 2022 2023 2024 2025 YTD Fully Diluted Shares (MM) Executing buyback program Five consecutive years of double-digit base dividend per share growth ~55% base dividend compound annual growth rate Excess free funds flow used to reduce shares outstanding ~241MM shares retired1 since 2021 Over 11% of shares outstanding retired since 2021 +200% +33% +29% +11% -1.9% -3.4% -4.1% -3.2%
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15 $0 $1,000 $2,000 CAD Bonds USD Bonds Resilient balance sheet enables financial flexibility Note: See Advisory. 1) CAD$ maturities converted to US$ using 0.718 US$/C$ exchange rate. No maturities until 2027 Average debt tenor 11 years Average debt coupon of 4.44% Current credit ratings & outlooks S&P Moody’s DBRS Fitch BBB Baa1 BBB (High) BBB Negative Negative Under Review Stable Preferred Shares Principal ($MM) Reset Date Series 1 $268 03-31-2026 Series 2 $32 03-31-2026 Series 3 $250 Redeemed Series 5 $200 Redeemed Series 7 $150 Redeemed Unused committed credit facility of $5.5 billion Low risk maturity profile1 Strong Investment grade credit ratings
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Business overview
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17 • Safety behaviours drive continuous improvement and field level empowerment. • Safety metrics included on corporate scorecard. • Compliance to our operations integrity management system protects the safety of our people and integrity of our assets. • Our values and eight safety commitments set out the attitudes expected of everyone who works at Cenovus. Prioritizing safety and asset integrity Committed to a strong safety culture Note: See Advisory.
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Diverse cash flow streams from multiple jurisdictions Portfolio overview Upstream production2 Christina Lake 236 Mbbls/d Foster Creek 201 Mbbls/d Sunrise 52 Mbbls/d Lloyd Thermal & CHO 125 Mbbls/d Conventional 124 MBOE/d Offshore 66 MBOE/d Total Production 806 MBOE/d Operable capacity & heavy oil %2 Lloydminster Upgrader 78.5 Mbbls/d 100% Lloyd Refinery 29.5 Mbbls/d 100% Lima Refinery 170 Mbbls/d 15% Toledo Refinery 151 Mbbls/d 60% Superior Refinery 44 Mbbls/d 80% Total Capacity 473 Mbbls/d ~55% Note: See Advisory. 1) Joint ventures Cenovus does not operate. 2) Production, operable capacity as of nine months ended October 30, 2025. Approximate heavy oil throughput capacity.
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19 Note: See Advisory. Production and operating costs as of nine months ended October 30, 2025. Oil Sands Christina Lake Foster Creek Lloydminster Thermals Sunrise Lloydminster Conventional Heavy Oil Best-in-class assets with low-cost structure and long-life reserves Nameplate capacity 260 Mbbls/d Production 236 Mbbls/d Operating costs $8/bbl Cogeneration capacity ~100MW Nameplate capacity 180 Mbbls/d Production 201 Mbbls/d Operating costs $10/bbl Cogeneration capacity ~100MW Production 101 Mbbls/d High quality, lower viscosity thermal production vs. typical oil sands projects Nameplate capacity 60 Mbbls/d Production 52 Mbbls/d Operating costs $18/bbl Applying Cenovus development approach to access deep inventory of high-quality resource Production 24 Mbbls/d Piloting CO2 EOR technology Horizontal multi-lateral well development Nameplate capacity 107 Mbbls/d Best-in-class asset entering new growth area at Narrows Lake Progressing optimization project to lower cost and grow production
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20 • Short-cycle opportunities that provide ability to adjust to market conditions. • Diversifying our funds flow and utilizing extensive pipeline network to market product ex-Alberta. • Constructive long-term view of the North American gas market. • Modestly increasing investment to optimize owned infrastructure and reduce unit operating costs. Conventional land base and districts North Corridor Rainbow Edson Clearwater Disciplined approach to Conventional development Strategic long-term portfolio with optionality to grow Note: See Advisory.
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21 Offshore strategic value Note: See Advisory. 1) Free cash flow profile defined as asset operating margin less capital investments, not including tax at US$75 WTI. Atlantic • Atlantic portfolio sustains exposure to Brent pricing well into the 2030s. • Generates substantial free cash flow over the five-year plan. • Robust go-forward returns at bottom of the cycle pricing with West White Rose Project completion. Asia Pacific • Strong free cash flow generation, with limited capital requirements. • Geographically diverse business tied to high-value, mostly fixed- price contracts. • Exploring portfolio upside opportunities and contract extensions. -$1.5 -$0.8 $0.0 $0.8 $1.5 2025F 2026F 2027F 2028F West White Rose Project free cash flow profile1 $0.0 $1.0 $2.0 2021 2022 2023 2024 Asia Pacific free cash flow profile1$ billion $ billion Consistently delivering ~$1 billion of free cash flow per yearInflection point coming in 2026 Stable, diversified free cash flow generation
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22 Lloydminster Upgrader Lloydminster Refinery Commercial fuels business Note: See Advisory. 1) Capacity stated represents operable capacity. Canadian refining Heavy Oil Throughput Capacity 1 78.5 Mbbls/d Produces high quality, low sulphur synthetic crude oil and diesel fuel, and recovers diluent from the feedstock Condensate is cycled back to the nearby thermal operations Heavy Oil Throughput Capacity 1 29.5 Mbbls/d Produces more than 30 different types and grades of road asphalt from heavy oil 10 asphalt terminals in Canada and U.S. to serve retail customer base Commercial fuels business includes approximately 155 cardlock, bulk plant and travel centre locations Upgrader and refinery strategically located in Lloydminster
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23 Lima, Ohio Toledo, Ohio Superior, Wisconsin Note: See Advisory. 1) Capacity stated represents operable capacity. U.S. refining Throughput capacity1 170 Mbbls/d Heavy oil capacity 25 Mbbls/d Access to Canadian heavy, West Texas and North Dakota supply Throughput capacity1 151 Mbbls/d Heavy oil capacity 90 Mbbls/d Directly connected to Canadian heavy crude and configured to process high- TAN grades Throughput capacity1 44 Mbbls/d Integration with our Oil Sands business provides balanced differential exposure Heavy oil capacity 34 Mbbls/d Directly connected to Canadian heavy crude, producing high quality asphalt
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24 Note: See Advisory. 1) Crude unit utilization reflects total Downstream business. 2025F reflects mid-points of October 2025 guidance. 2) Crude unit utilization as a percentage of operable capacity. 3) Unit operating expenses calculated by dividing operating costs excluding turnarounds expenses by total processed inputs. 70% 80% 90% 100% 2023 2024 2025F Increasing crude utilization • Record Canadian Refining rates through nine months. • Targeted reliability improvements made at Lloydminster, Lima and Toledo during recent turnarounds. • Operations excellence established across the network. • Enhanced preventative maintenance programs. • Capturing synergies between operated fleet. Crude unit utilization 1,2 (%) $10 $11 $12 $13 $14 $15 2023 2024 2025F Unit operating expenses1,3 ($/bbl) Driving down operating expenses • Focused cost oversight and application of best practices across sites. • Higher reliability drives lower unit costs. • Turnaround performance emphasis. • Streamlining overhead costs and contract services. Improvement of ~14% Decrease of ~20% Canadian and U.S. refining Integration with our Oil Sands business provides balanced differential exposure
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Appendix
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26 2025 guidance Note: See Advisory. 1) Specified financial measure. Upstream operating costs are divided by sales volumes and include the company’s proportionate share of operating costs from equity-accounted affiliates where applicable. Downstream operating costs are divided by total processed inputs and exclude expensed turnaround costs. Capital investments ($MM) Production/ throughput (MBOE/d or Mbbls/d) Operating costs1 ($/bbl or $/BOE) Turnaround expenses ($MM) Oil Sands 2,700 – 2,800 620 – 625 10.75 – 12.75 Conventional 350 – 400 120 – 125 11.00 – 12.00 Atlantic 10 – 15 50.00 – 60.00 Asia Pacific 55 – 60 10.00 – 11.00 Offshore 900 – 1,000 65 – 75 Total Upstream 3,950 – 4,200 805 – 825 Canadian Refining 105 – 110 11.00 – 12.00 - U.S. Refining 510 – 515 10.00 – 12.00 360 – 380 Total Downstream 650 – 750 615 – 625 Corporate 0 – 50 Total 4,600 – 5,000
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27 2025 planned maintenance Note: See Advisory. Turnaround activity is subject to change. Production Impact Q4 Annualized Upstream Oil Sands MBOE/d - 7 - 9 Offshore MBOE/d - 1 - 2 Conventional MBOE/d - - Downstream Canadian Refining Mbbls/d - - U.S. Refining Mbbls/d 8 - 12 12 - 14 Turnaround Expenses Q4 Annualized Downstream Canadian Refining $MM - - U.S. Refining $MM 10 - 15 360 - 380
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28 Note: See Advisory. Feedstock and refined product mix based on assumptions reflected in 2025 guidance. Refinery feedstock (% of crude throughput) Refined products (% of production) 100% 40% 47% 10% 3% Canadian Refining U.S. Refining Heavy Light/Medium Synthetic Oil Other 53% 42% 11% 33% 16% 4%31% 10% Canadian Refining U.S. Refining Gasoline Synthetic Oil Distillates Asphalt Other Snapshot of feedstocks & refined products Refineries provide diversified feedstock and product slate
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29 Commodity price assumptions US$45 WTI Scenario 2025F 2026F 2027F 2028F Brent $47.00 $47.00 $47.00 $47.00 WTI $45.00 $45.00 $45.00 $45.00 WTI-WCS differential $12.50 $12.50 $12.50 $12.50 WCS $32.50 $32.50 $32.50 $32.50 Chicago 3-2-1 crack spread $16.00 $16.00 $16.00 $16.00 RINs $4.00 $4.00 $4.00 $4.00 AECO (C$/mcf) $2.12 $2.12 $2.12 $2.12 FX (US$/C$) 0.74 0.74 0.74 0.74 US$60 WTI Scenario 2025F 2026F 2027F 2028F Brent $65.00 $65.00 $65.00 $65.00 WTI $60.00 $60.00 $60.00 $60.00 WTI-WCS differential $14.00 $14.00 $14.00 $14.00 WCS $46.00 $46.00 $46.00 $46.00 Chicago 3-2-1 crack spread $18.50 $18.50 $18.50 $18.50 RINs $4.00 $4.00 $4.00 $4.00 AECO (C$/mcf) $2.40 $2.40 $2.40 $2.40 FX (US$/C$) 0.78 0.78 0.78 0.78 US$75 WTI Scenario 2025F 2026F 2027F 2028F Brent $81.00 $81.00 $81.00 $81.00 WTI $75.00 $75.00 $75.00 $75.00 WTI-WCS differential $18.00 $18.00 $18.00 $18.00 WCS $57.00 $57.00 $57.00 $57.00 Chicago 3-2-1 crack spread $22.00 $22.00 $22.00 $22.00 RINs $4.00 $4.00 $4.00 $4.00 AECO (C$/mcf) $2.65 $2.65 $2.65 $2.65 FX (US$/C$) 0.82 0.82 0.82 0.82 US$/bbl unless otherwise stated Note: See Advisory.
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30 Advisory Barrels of Oil Equivalent Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. Oil and Gas Advisory All production referenced herein is presented on a net before royalties basis, unless otherwise stated. This presentation makes assumptions relating to future production volumes based on reserve evaluation calculations prepared by third party independent evaluators. 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 bitumen reserves and in projecting future rates of production. The total amount or timing of actual future production may vary significantly from reserves and production estimates. Total combined company oil sands production of 720 Mbbls/d as presented on Slide 9 represents combined 2025 mid-point production guidance from both Cenovus and MEG. Total combined company Foster Creek and MEG and Cenovus Christina Lake production of 550 Mbbls/d as presented on Slide 9 is based on the mid-point between combined July, 2025 production and 2024 year end production. Steam to oil (SOR) ratio of 2.2 as presented on Slide 9 is based on: (i) in respect of Cenovus, the 2.08 SOR for Christina Lake and 2.28 SOR for Foster Creek, both for the year ended December 31, 2024; and (ii) in respect of MEG, the 2.39 SOR for the year ended December 31, 2024, as disclosed in MEG’s annual information form dated February 27, 2025 for the year ended December 31, 2024. Forward-looking Information This presentation contains certain forward-looking statements and forward-looking information (collectively referred to as “forward looking information”) within the meaning of applicable securities legislation, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. Forward-looking information in this presentation is identified by words such as “committed”, “continue”, “drive”, “expect”, “F”, “focus”, “grow”, “maintain”, “opportunities”, “plan”, “priorities”, “progress”, “target”, “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: reserves life index; production; Net Debt target; Adjusted Funds Flow; Free Funds Flow; operating and capital costs; base dividend growth and base dividend capacity; increasing shareholder returns; allocation of Excess Free Funds Flow to shareholder returns; capital investment; growing the base business; expectations for the timing of completion and operation, and production associated with growth projects: Narrows Lake, Foster Creek, Sunrise, West White Rose and conventional heavy oil; planned maintenance turnarounds; over $400 million of synergies expected from the proposed MEG acquisition; capital allocation priorities; Atlantic free cash flow profile; capital requirements; credit ratings; low cost structure; reliability; refining and oil sands integration; throughput capacity; safety culture and performance; increasing crude utilization and decreasing operating expenses; and our 2025 guidance. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information in this presentation are based on and include but are not limited to: the allocation of Free Funds Flow and the assumptions inherent in Cenovus’s 2025 guidance available on cenovus.com and other risks identified under “Risk Management and Risk Factors” and “Advisory” in Cenovus’s MD&A for the year ended December 31, 2024. Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For additional information regarding Cenovus’s material risk factors, the assumptions made, and risks and uncertainties which could cause actual results to differ from the anticipated results, refer to “Risk Management and Risk Factors” and “Advisory” in Cenovus’s MD&A for the periods ended December 31, 2024 and September 30, 2025 and to the risk factors, assumptions and uncertainties described in other documents Cenovus files from time to time with securities regulatory authorities in Canada (available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and Cenovus’s website at cenovus.com).
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31 Advisory Specified Financial Measures Advisory Certain financial measures in this presentation do not have a standardized meaning prescribed by IFRS Accounting Standards and, therefore, are Specified Financial Measures. These Specified Financial Measures may not be comparable to similar measures presented by other issuers. See the Specified Financial Measures Advisory located in our Management’s Discussion and Analysis for the periods ended December 31, 2024 and September 30, 2025 (available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on Cenovus's website at cenovus.com) for information incorporated by reference about these Specified Financial Measures. © 2025 Cenovus Energy Inc.