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1 JANUARY 2026 VERMILION ENERGY INVESTOR PRESENTATION GLOBAL GAS PRODUCER FREE CASH FLOW FOCUSED FINANCIAL DISCIPLINE
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2 Montney Momentum o Excess free cash flow(1) inflection following infrastructure build-out WHAT VERMILION OFFERS INVESTORS 2 Dominant Deep Basin o Depth and quality of inventory with infrastructure in place drives profitable growth Germany Production Growth o Positioned for organic growth with production from new discoveries, upside from additional prospects Return of Capital o Long-term return of capital underpinned by excess free cash flow growth Repositioned Global Gas Portfolio o Profitable, long-life assets delivering top decile realized gas price
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3 Global gas producer with top decile realized gas price VERMILION AT A GLANCE Market Summary VET Trading Price (January 2, 2026) $11.71 (TSX), US$8.54 (NYSE) Shares Outstanding (December 31, 2025) 152.9 MM Average Daily Trading Volume (shares) 0.8 MM (TSX), 1.3 MM (NYSE) Quarterly Dividend (2026 planned) $0.135/share Capital Structure Market Capitalization $1.8 B Enterprise Value $3.2 B Year-End 2025 Net Debt(1) $1.4 B Year-End 2025 Net Debt-to-FFO Ratio(1) 1.4x Guidance 2025 2026 Production (boe/d) 119,500 118,000 – 122,000 Q4 2025 Production (boe/d) 119,000 – 121,000 E&D Capital Expenditures(1,2) $630 – 640MM $600 – 630MM All financial data is reported in Canadian dollars, unless otherwise stated 3
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4 Allocating 85% of capital to repositioned global gas assets 2026 BUDGET 78% 14% 8% PRODUCTION WEIGHTING(2) CANADA EUROPEAN GAS ASSETS LEGACY OIL 67% 18% 15% E&D CAPITAL ALLOCATION(2) CANADA EUROPEAN GAS ASSETS LEGACY OIL $600 – 630MM 67% Canada 33% International 4 • Announced 4% dividend increase effective Q1 2026(1) • 30% improvement in 2026 capital intensity and unit operating costs compared to 2024 • E&D capital investment in: o Drilling (Deep Basin, Montney, Netherlands) o Building strategic infrastructure (Montney) o Advancing deep gas exploration (Germany) 118 – 122 mboe/d 70% Natural Gas 30% Liquids
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5 Significant unit cost reduction and improved capital efficiency UPDATED 2025 GUIDANCE & 2026 BUDGET 5 CATEGORY 2025 CURRENT(1) 2026 CURRENT(1) Production (boe/d) 119,500 118,000 - 122,000 % Natural gas 65% 70% E&D capital expenditures ($MM) $630 - 640 $600 - 630 ↓ 3% Operating ($/boe) $13.00 - 13.50 $12.25 - 13.25 ↓ 4% General and administration ($/boe)(2) $2.25 - 2.75 $1.65 - 2.15 ↓ 24% Transportation ($/boe) $3.00 - 3.50 $3.00 - 3.50 – Royalty rate (% of sales) 8 - 9% 7 - 9% ↓ 6% Cash taxes (% of pre-tax FFO) 3 - 7% 2 - 6% ↓ 20% Asset retirement obligations settled ($MM) $60 $55 ↓ 8% Payments on lease obligations ($MM) $15 $10 ↓ 33%
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6 REPOSITIONED GLOBAL GAS PORTFOLIO
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7 Streamlining operating regions and increasing operational scale in our core areas 7 REPOSITIONED PORTFOLIO: MORE EFFICIENT $7,400 $5,100 2024 2026e IMPROVED CAPITAL INTENSITY (CAPEX/FLOWING BOE) 85 120 2024 2026e HIGHER PRODUCTION (MBOE/D) $21.41 $14.65 2024 2026e LOWER UNIT COSTS (OPEX + G&A/BOE) >40% increase in boe/d >30% decrease in cost structure >30% decrease in capex/flowing boe
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8 Enhanced profitability through long-life assets and improved capital efficiency 25+ Years Drilling Inventory(1) High-return, multi-zone development with existing infrastructure to support production growth Generating EFCF(2) through efficient development 20+ Years Drilling Inventory Lower capital and unit OPEX, progressing infrastructure to support long term liquids-rich production Pivoting to EFCF following infrastructure build-out 10+ Years Drilling Inventory Lowest cost international gas exposure through material deep gas exploration prospects Growing EFCF with Deep Gas Exploration program REPOSITIONED PORTFOLIO: KEY GROWTH ASSETS Deep Basin Montney Germany 8
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9 Vermilion’s growth assets have decades of development ahead that is not reflected in our reserves 16% GERMANY & NETHERLANDS GAS INVENTORY FOR THE FUTURE 9 ~31 . Accumulations 7% 14% DEEP BASIN ~1,450 . Locations(1) 20% BOOKED LOCATIONS EVALUATION LOCATIONS UNBOOKED LOCATIONS 29% MONTNEY ~250 . Locations
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10 TOP DECILE REALIZED GAS PRICE 10 AECO 43% Canadian Gas Hedges 34% Alliance 5% Europe 18% NATURAL GAS PRICE EXPOSURE(3) Canada 82% Europe 18% GAS PRODUCTION BY REGION(2) AVERAGE (EXCL VET) = $2.63 $0 $1 $2 $3 $4 $5 $6 REALIZED NATURAL GAS PRICE ($/MCF) Q3 2025 REALIZED NATURAL GAS PRICE(1) REALIZED GAS PRICE REALIZED HEDGE GAIN Vermilion’s unique Global Gas portfolio delivers top decile realized gas price
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11 European natural gas prices trade at a significant premium to North American benchmarks DIRECT EXPOSURE TO EUROPEAN GAS PRICES $0 $10 $20 $30 $40 $50 2017 2018 2019 2020 2021 2022 2023 2024 2025e 2026e TTF GAS PRICES (C$/MMBTU)(1) HISTORICAL AND FORWARD PRICING OF EUROPEAN GAS 11 Euro Gas 2025 2026 % Hedged 59% 52% Average Floor $17 $14
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12 Vermilion’s Canadian assets are focused in two of the top four North American gas plays CANADA LIQUIDS-RICH GAS ADVANTAGE 12Source: Peters & Co. Limited Fall 2025 Energy Overview. Estimates based on ~US$65.00/B WTI, ~US$4.00/Mcf NYMEX, ~$3.25/Mcf AECO. - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Montney Oil Marcellus Montney Liquids Rich Deep Basin Duvernay Kaybob Montney Dry Gas Permian Delaware Haynesville Permian Midland PAYOUT (YEARS)(1) HALF-CYCLE PAYOUT PERIOD Canadian Plays (Median 1.1 Years) U.S. Plays (Median 1.4 Years)
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13 KEY ASSET OVERVIEW
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14 Decades of stacked zone inventory supported by existing infrastructure DEEP BASIN: OVERVIEW Overview Key Statistics Production: 70,000 boe/d (Q3 2025)(1) Acreage: 1.1 million net acres(2) Infrastructure: >100,000 boe/d nameplate capacity(3) History Vermilion has operated in the Deep Basin since 1995 and has grown to be one of the largest producers in this prolific basin Outlook Efficient capital allocation across our broad land base and through the multiple stacked zones supports production of 70,000 - 90,000 boe/d (4) Over 25 years of high-quality drilling inventory(5) with minimal required infrastructure spending drives strong return profile 14 Source: XI Technologies Asset Book
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15 Culture of continuous improvement converts operational wins into material cost savings $1,000 $1,500 $2,000 $2,500 $3,000 2023 2024 2025 $ / HORIZONTAL METRE(1) DRILLING COST – VET VS. PEERS DEEP BASIN PEERS VERMILION PROFITABLE GROWTH: OPERATIONAL EXCELLENCE 15 Shallower target depths Consistent three-rig drilling program Longer laterals at a lower per-metre cost
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16 ROBUST DEEP BASIN ECONOMICS 16 Upper Cretaceous Spirit River Jurassic/Lwr Cretaceous Lateral Length (m) 2,800 2,900 2,800 DCET Cost ($MM) $5.0 – 5.5 $6.0 – 6.5 $5.5 – 7.5 IP365 (boe/d)(1) 450 750 475 2P Reserves (mboe)(2) 770 1,050 610 Liquids % of Reserves(3) 32% 14% 47% IRR(4) 110% 110% 70% Payout (years)(5) 1.1 1.0 1.2 NPV10 ($MM)(6) $8.4 $8.7 $5.9 Upper CretaceousSpirit River Jurassic / Lwr Cretaceous Competitive well economics + minimal infrastructure requirements = profitable full-cycle development
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17 MONTNEY: OVERVIEW 17 Overview Key Statistics Production: 16,000 boe/d (Q3 2025)(1) Acreage: 80,000 acres(2) Infrastructure: >30,000 boe/d nameplate capacity (H2/2027 Est.)(3) History Entered the Montney in 2022, grew production from ~4,000 boe/d to ~16,000 boe/d currently Reduced DCET capital by >30% since 2022 Outlook Plan to reach 28,000 boe/d target production rate in 2028(4), will pivot to EFCF(5) generation with ~8 wells per year to maintain production Approaching Excess Free Cash Flow inflection, with majority of infrastructure spend completed
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18 A significant and contiguous premium acreage block in the oil window of the Montney PREMIUM MONTNEY ACREAGE 18 VET owns ~10% of CEI.V(1) (~$45 million) Source: Land information sourced from EVA
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19 Continuous improvement drives efficiencies on our BC Montney assets MONTNEY COST OPTIMIZATION 19 $- $2 $4 $6 $8 $10 $12 $14 16-28 (2023) 16-28 (2024) 9-21 (2024) 8-4 / 9-21 Average (2025) Revised Target Cost ($8.5MM) PER WELL COST ($MM) BC MONTNEY AVERAGE WELL COST • DCET(1) cost reduced to $8.5MM (from $9.6MM) o Improves project economics, represents ~$100 million (NPV10)(2) in future development costs o DCET cost savings are repeatable • Water hub and disposal infrastructure reduces cost of water handling o Allows for more recycled water to be used • Drilling speed (>20% faster) and frac efficiency (>80% improvement) drives lower cost
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20 BC Middle Montney Lateral Length (m) 3,000 DCET Cost ($MM) $8.5 IP365 (boe/d)(1) 950 2P Reserves (mboe)(2) 1,500 Liquids % of Reserves(3) 38% IRR(4) 120% Payout (years)(5) 0.8 NPV10 ($MM)(6) $12.9 20 MONTNEY WELL ECONOMICS Leading DCET costs in the oil window of the Montney
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21 Target production rate generates $125-150MM of EFCF on lower capital requirements 21 MONTNEY PIVOTS TO EFCF IN 2028 - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2022 2023 2024 2025 2026 2027 2028 2029 2030+ BOE/D (NET) PRODUCTION TIMELINE(1) Pivot to Excess Free Cash Flow o Achieve 28,000 boe/d target rate, transition to sustaining capital with minimal infrastructure o 2029+ drill ~8 wells/yr to maintain production 2026-2028 Plan o Phase 3 expansion, owned infrastructure build-out complete o $70MM total infrastructure spend o Forecast drilling ~40 wells to reach target production rate 2022-2025 Execution o Acquired Mica Montney, spun out CEI.V o Commissioned 8-33 battery in Q2 2024 o Phase 2 expansion complete Q1 2025 o Reduced average well cost from $12MM to $8.5MM on first 4 pads Excess Free Cash Flow(2) generationBuild infrastructure and reduce DCET costs
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22 Significant undeveloped land base with long runway of high-return projects across Germany and Netherlands EUROPEAN GAS ASSETS: GERMANY & NETHERLANDS 22 Overview Key Statistics Gas Production: 46 mmcf/d (57% Germany / 43% Netherlands)(1) Acreage: 1.45 million acres (50% Germany / 50 % Netherlands)(2) History Proven track record of development with 30+ exploration wells at 70% success rate over 20 years Significant undeveloped land base in Germany from 2015 farm-in agreement, 3D seismic coverage throughout Outlook Building out Germany infrastructure and developing material gas discovery; exploration upside from long runway of prospects Source: ESRI, SRTM Worldwide Elevation Data
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23 GERMANY EXPLORATION POTENTIAL 23 Vermilion has ~700,000 net acres of land and an experienced technical team with 70% success rate drilling similar zones in the Netherlands Deep Gas Exploration Type Well (1.0 Net) Vertical Depth (m) ~5,000 DCET Cost ($MM) $40 – 50 2P Reserves (Bcf)(1) ~30 Gas % of Reserves(2) 100% IRR(3) 35% Payout (years)(4) 1.9 Lifetime Payout(5) 4x NPV10 ($MM)(6) $60 Identified 9 structures to date and have drilled 3; potential for up to 30 total locations with success Small “e” exploration – finding gas where gas has been found
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24 Vermilion’s largest discovery in over a decade is the latest significant discovery in the North German Basin Discovery Well 2P Reserves 68 Bcf Property Gross(1) 44 Bcf Gross to Vermilion SIZE OF THE PRIZE 24 Source: Petroleum Geological Atlas of the Southern Permian Basin Areas (2010), LBEG - “Erdgastabellen 1949-2024”, ESRI NORTH GERMAN BASIN
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25 Germany exploration program offers low-cost international exposure and long-duration EFCF GERMANY OUTLOOK: ORGANIC GROWTH - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2023 2024 2025 2026 2027 2028 2029 2030+ BOE/D (NET) DEEP GAS PROGRAM PRODUCTION TIMELINE(1) Legacy Germany Deep Gas Success To-Date (1.6 net) Additional Wells 25 2024-2026 Success & First Production o Osterheide (OSTH) and Wisselshorst (WSSH) discoveries o OSTH online Q1 2025 at restricted rates o Initial WSSH infrastructure build-out o WSSH target on-stream date mid-2026 2027-2028 Follow-up Activity o Drill two (1.3 net) additional wells o Infrastructure debottlenecking to accelerate production and EFCF(2) Self-funded Growth o Full contribution from 2.9 net wells drives organic Euro Gas growth, EFCF and additional capital allocation optionality Excess free cash flow generationDrilling and facility investment
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26 CAPITAL ALLOCATION
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27 Disciplined capital allocation focused on creating long term shareholder value CAPITAL ALLOCATION PRIORITIES Provide Compounding Shareholder Returns Target long-term value-add acquisition opportunities Maintain Robust Asset Base Maintain Strong Balance Sheet o Targeting net debt to FFO ratio(1) less than 1.0x o Allocating 60% of EFCF(2) to debt repayment o $1.1B of available liquidity o Repositioned global gas portfolio o Depth and quality of inventory o Long-duration, profitable asset base o 40% return of EFCF o Five consecutive years of dividend increases o Repurchased 20 million shares (3) (12% of Q2/22 shares outstanding) o Focus on increased operational scale in core areas o Committed to deep-value international acquisitions 27
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28 FINANCIAL LIQUIDITY 0.0x 0.5x 1.0x 1.5x 2.0x 2022 2023 2024 2025e 2026e NET DEBT TO FFO RATIO(1) HISTORICAL NET DEBT TO FFO 28 Committed to returning to 1.0x leverage Available Liquidity of $1.12B $0.23B $0.53B $0.56B CURRENT CREDIT CAPACITY(2) Undrawn Capacity on Revolving Credit Facility Revolving Credit Facility 2029 Maturity Senior Unsecured Notes 2030 Maturity Senior Unsecured Notes 2033 Maturity Strong financial position with a focus on debt repayment and ample available liquidity
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29 Repositioned portfolio delivers lower cost structure and improved capital efficiency FFO & CAPITAL ALLOCATION 0 20 40 60 80 100 120 140 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2024 2025e 2026e PRODUCTION (‘000 BOE/D) $MM FFO ALLOCATION(1) FFO (EX. REALIZED HEDGE GAIN) REALIZED HEDGE GAIN* E&D CAPEX/ARO/LEASES EFCF PRODUCTION Net Debt to Trailing FFO(1) 0.8x 1.4x 1.5x FFO ($/basic share) $ 7.63 ~$ 6.50 ~$ 5.70 Unhedged FFO ($/basic share) $ 5.61 ~$ 5.60 ~$ 5.60 WTI (US$/bbl) $ 75.72 $ 65.17 $ 59.98 AECO ($/mcf) $ 1.44 $ 1.86 $ 3.26 TTF ($/mmbtu) $ 14.89 $ 16.98 $ 14.66 29
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30 Visit vermilionenergy.com/Invest-with-us/hedging for more detailed hedging information STRONG HEDGE POSITION 0% 20% 40% 60% 80% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total PERCENTAGE OF PRODUCTION HEDGED (%)(1) 2025 WTI BRENT NATURAL GAS 0% 20% 40% 60% 80% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total PERCENTAGE OF PRODUCTION HEDGED (%)(1) 2026 WTI BRENT NATURAL GAS 30 WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/MMBtu) N.A. Gas (C$/MMBtu) Avg. Sold Call $94.75 N/A $20.83 $3.97 Avg. Bought Put $84.23 N/A $13.61 $2.73 Avg. Swap $100.53 $105.15 $19.91 $2.84 WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/MMBtu) N.A. Gas (C$/MMBtu) Avg. Sold Call $95.36 N/A $18.85 $4.49 Avg. Bought Put $85.47 N/A $11.96 $3.03 Avg. Swap $85.89 N/A $15.59 $3.33
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31 Decreasing share count with ratable dividend increases enhances value per share COMPOUNDING RETURN OF CAPITAL 31 $0.00 $0.20 $0.40 $0.60 $0.80 2022 2023 2024 2025 2026e DIVIDENDS PER SHARE(1) ANNUAL DIVIDEND PER SHARE 145 150 155 160 165 2022 2023 2024 2025e 2026e SHARE COUNT (MM)(2) SHARE COUNT Announced 2026 dividend payout is <10% of FFO
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32 ADDITIONAL INFORMATION
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33 PRICING & FFO SENSITIVITY 33 2026 FFO SENSITIVITY (C$MM)(2) Change FFO Impact (Hedged) FFO Impact (Unhedged) TTF & NBP $1.00/mmbtu $23MM $28MM NA Gas Prices $0.25/mmbtu $23MM $34MM WTI & Brent US$1/bbl $9MM $13MM CAD/USD $0.01 $6MM $6MM CAD/EUR $0.01 $1MM $1MM COMMODITY PRICES(1) 2025e 2026e TTF ($/mmbtu) $16.98 $14.66 NBP ($/mmbtu) $16.68 $14.41 AECO ($/mcf) $ 1.86 $ 3.26 Henry Hub (US$/mmbtu) $ 3.39 $ 3.97 Brent (US$/bbl) $69.42 $63.89 WTI (US$/bbl) $65.17 $59.98 MSW = WTI less (US$/bbl) $ 3.61 $ 3.72 CAD/USD 1.40 1.38 CAD/EUR 1.58 1.63 CAD/AUD 0.90 0.91 EUR/GBP 1.17 1.13
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34 Global gas portfolio pairs long duration, liquids-rich Canadian gas with premium-priced European production GLOBAL GAS ASSETS 34 MONTNEY • Q3 2025 production = 85,698 boe/d (29% liquids) (Continuing operations) IRELAND CROATIA NETHERLANDS GERMANY DEEP BASIN • Q3 2025 production = 19,795 boe/d (91% gas) Canada Liquid-Rich Gas Europe Premium-Priced Gas
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35 Over 70% of Vermilion’s Canadian production(2) underpinned by natural gas tailwinds CANADIAN GAS FUNDAMENTALS • Natural gas demand for Canadian LNG is expected to increase notably by end of decade (>6.0 bcf/d) o Strong momentum carried into 2024 with positive FID on Cedar and completion of Coastal GasLink pipeline • Opportunities for WCSB operators to benefit from international pricing Project Name Natural Gas Demand(1) Operational Start Date(1) LNG Canada (Phase 1 / 2) ~1.8 / 1.8 bcf/d 2025 / 2028-2030 Woodfibre LNG ~0.3 bcf/d 2027 Cedar LNG ~0.4 bcf/d 2028 Tilbury Phase 2 Expansion ~0.4 bcf/d 2028 Ksi Lisims LNG ~1.4 bcf/d 2029 Total >6.0 bcf/d by 2030 West Coast Canadian LNG(1) North American Power Demand • Increased power associated with datacenter development is underpinning long-term natural gas demand o 24/7 power reliability will necessitate the development of ~5-10 bcf/d of additional natural gas production in North America • Established egress with excess capacity from WCSB to key demand center regions (Virginia, Texas, Midwest US, etc.) West Coast Canadian LNG Status Update 35 Average (2012-2024) = $2.76 $0 $1 $2 $3 $4 $5 $6 2012 2014 2016 2018 2020 2022 2024 2026e* AECO PRICES (C$/MMBTU) HISTORICAL AND FORWARD AECO GAS PRICING(3) Source: EIA; CER; S&P Global, RBC Research, Project Websites
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36 Direct exposure to premium-priced European gas EUROPEAN GAS FUNDAMENTALS (20) - 20 40 60 80BCF/D EUROPEAN SUPPLY/DEMAND BALANCE HISTORY(2) Domestic production** Russia (incl. Turkey transit) LNG Storage draw/injection Consumption 36 • Europe(1) consumes ~40 Bcf/d per annum, with ~30 Bcf/d swing between summer and winter • Russian supply has decreased ~12 bcf/d and the EU is formalizing plans to fully end its dependency on Russian gas o REPowerEU Plan directs member states to stop all imports of Russian gas by 2027 o New contracts for Russian gas will be prevented and spot contracts will be stopped by the end of 2025 • Europe dependent on LNG imports and must compete with the rest of the world for LNG volumes • Global LNG demand continues to increase o EU recognizes natural gas as transition fuel, many countries have demonstrated increased interest in gas-fired power generation o India LNG demand expected to double by 2030 o Demand for LNG, especially in China, South Asia and Southeast Asia, is expected to absorb new supply coming to market 30 35 40 45 50 55 60 2018 2019 2020 2021 2022 2023 2024 BCF/D GLOBAL LNG IMPORTS(3) Winter 2023 demand down ~10 Bcf/d due to 2nd warmest winter, government policy, and extremely high prices
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37 Low decline oil assets generating free cash flow LEGACY OIL ASSETS 37 FRANCE • #1 domestic oil producer with two-thirds of the domestic industry • Extensive inventory of workovers, recompletions, and infill drilling • Q3 2025 production = 6,811 boe/d (100% oil) AUSTRALIA • Offshore oil field approximately 80 km N.W. off the coast of Australia (55m water depth) • Q3 2025 production = 3,693 boe/d (100% oil) • Wandoo crude currently sells at ~US$10/bbl premium to Dated Brent
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38 Read more at vermilionenergy.com/sustainability ENVIRONMENT, SOCIAL & GOVERNANCE • Achieved 16% reduction in Scope 1 emissions intensity since 2019(1); now focused on reducing Scope 1+2 emissions intensity by 25-30% by 2030 • Asset high-grading and ARO spending has reduced well count by 50% since 2022 Environment • Geothermal energy for Parentis greenhouse supports 220 direct jobs • Geothermal energy for La-Teste eco-neighborhood reduces heating costs, avoids 250 tonnes/year of CO2(2)Social • Board diversity, including 30% female members • Executive and employee compensation linked to ESG metricsGovernance 38 Vermilion’s Purpose: To responsibly produce essential energy while delivering long-term value to our people, shareholders, customers, partners and communities 0.015 0.020 0.025 0.030 2019 2020 2021 2022 2023 2024 EMISSIONS INTENSITY TREND Scope 1&2 tCO2e per BOE
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39 Reducing well count and asset retirement obligations while growing production REDUCED WELL COUNT - 1,000 2,000 3,000 4,000 5,000 6,000 2022 2023 2024 2025e WELL COUNT (NET)(1) TOTAL WELL COUNT PRODUCING WELLS NON-PRODUCING WELLS ARO settled ($MM) $38 $57 $55 $60 39 • Total well count has been reduced by 50% since 2022 through asset high-grading and asset retirement obligation expenditures • Average production per well has more than doubled since 2022 • Annual ARO spend of $50-55MM per year for the next 10+ years with no major obligations o Larger scale ARO program results in better capital efficiency
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40 Enhancing economic opportunities through innovation and partnerships SUSTAINABILITY PROJECTS 40 Advancing environmental projects in communities where we live and work LA TESTE ECO-NEIGHBOURHOOD • Our oil operations provide 1.2 GWh of geothermal energy to an eco-neighborhood • 30-year partnership provides up to 80% of the energy required for 550 homes • Prevents the emission of 250t of CO2/year and considerably reduces residents’ heating bills PARENTIS SUSTAINABILITY PARTNERSHIP • Our oil operations provide 40 GWh of geothermal energy annually to a tomato greenhouse operation • Prevents emission of 6,900t of CO2/year • Produces 8,000t of tomatoes per year and has created 220 direct agricultural jobs in a region in need of investment BIODIVERSITY IN IRELAND • Our biodiversity action plan exemplifies how we manage our activities in Ireland with a focus on protecting the habitats and species around us • We are committed to maintaining an increase of species diversity in maturing habitats and exploring opportunities for further enhancement • Supports societal awareness of the ecological values of the landscape, its habitats and species
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41 41 ADVISORY This presentation is for information purposes only and is not intended to, and should not be construed to constitute, an offer to sell or the solicitation of an offer to buy, securities of Vermilion Energy Inc. ("Vermilion", the "Company", "we", or "us"). This presentation and its contents should not be construed, under any circumstances, as investment, tax or legal advice. Any person viewing this presentation acknowledges the need to conduct their own thorough investigation into Vermilion and its activities before considering any investment in its securities. All references are to Canadian dollars unless otherwise specified. Forward-Looking Statements Certain statements included or incorporated by reference in this document may constitute forward-looking statements or information under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this document may include, but are not limited to: duration and life of inventory and assets; well production timing and expected production rates and financial returns, including half-cycle internal rate of return, therefrom; future production and costs; repositioning of portfolio and its impact to 2028 and onward; five year outlook; wells expected to be drilled and impact on production and total wells; exploration and development plans, and the timing and effects thereof; estimated recoverable gas; effects of infrastructure build out in Montney; outlook for Vermilion’s key assets and geographies, including production and EFCF growth, targets and forecasts; petroleum and natural gas sales, netbacks, and the expectation of generating strong free cash flow therefrom; exposure to and the effect of changes in crude oil and natural gas prices, and changes in exchange and inflation rates; commodity price and exchange rate forecasts; statements regarding Vermilion’s hedging program including the anticipated impact of Vermilion’s hedging program on free cash flows; unhedged EFCF gas sensitivities; capital expenditures including Vermilion’s ability to fund such expenditures in 2025 and future periods; future production levels and the timing thereof, including Vermilion’s future guidance, and rates of total and per share production growth and EFCF growth, including Vermilion’s ability to maintain or grow production; future production weighting, including weighting for product type or geography; estimated volumes of reserves and resources; statements regarding the return of capital and share buybacks; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; declines in Ireland including timing; statements regarding the growth and size of Vermilion's future project inventory, including the number of future drilling locations expected to be available and infrastructure; acquisition and disposition strategy and plans; operating and other expenses, including the payment and amount of future dividends; lifetime payout of wells; future construction, infrastructure build-outs, planning and permitting, including costs and effects on production and EFCF; reduction of debt per boe, net debt, net debt to FFO and net debt to production; anticipated DCET costs; sustainable shareholder returns; debt maturity; credit capacity; future investments; future pipeline capacity; capital allocation and effects therefrom; EFCF run rate; drilling programs; WSSH target on-stream timing; and the timing of regulatory proceedings and approvals. Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this presentation, assumptions have been made regarding, among other things: the accuracy of the McDaniel & Associates Report; the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; management’s expectations relating to the timing and results of exploration and development activities; the impact of Vermilion’s dividend policy on its future cash flows; credit ratings; hedging program; expected future cash flows and free cash flow and expected future cash flow and free cash flow per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; general economic and competitive conditions; ability of management to execute key priorities; and the effectiveness of various actions resulting from the Vermilion's strategic priorities. Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion’s financial position and business objectives, and the information may not be appropriate for other purposes. Forward- looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates, interest rates and inflation; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against or involving Vermilion; and other risks and uncertainties described elsewhere in this presentation or in Vermilion's other filings with Canadian securities regulatory authorities. References to Vermilion or the Company in this document include Westbrick Energy Inc. which amalgamated with Vermilion Energy Inc. on February 26, 2025. The forward-looking statements or information, including financial outlooks, contained in this presentation are made as of December 10, 2025, and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, including financial outlooks, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws. ESG Data This presentation contains references to sustainability/ESG data and performance that reflect metrics and concepts that are commonly used in such frameworks as the Global Reporting Initiative, the Task Force on Climate-related Financial Disclosures, and the Sustainability Accounting Standards Board. Vermilion has used best efforts to align with the most commonly accepted methodologies for ESG reporting, including with respect to climate data and information on potential future risks and opportunities, in order to provide a fuller context for our current and future operations. However, these methodologies are not yet standardized, are frequently based on calculation factors that change over time, and continue to evolve rapidly. Readers are particularly cautioned to evaluate the underlying definitions and measures used by other companies, as these may not be comparable to Vermilion’s. While Vermilion will continue to monitor and adapt its reporting accordingly, the Company is not under any duty to update or revise the related sustainability/ESG data or statements except as required by applicable securities laws. Non-GAAP Financial Measures and Ratios This presentation includes references to certain financial measures that are not standardized, specified, defined, or determined under International Financial Reporting Standards ("IFRS") and are therefore considered non-GAAP or other specified financial measures and may not be comparable to similar measures presented by other issuers. These measures and ratios include “FFO”, “net debt”, “net debt to production”, “net debt-to-FFO”, “E&D capital expenditures”, “free cash flow”, “EFCF”, “EFCF per share”, “Unhedged EFCF” and “payout”. Management believes that, in conjunction with results presented in accordance with IFRS, these measures and ratios assist in providing a more complete understanding of certain aspects of Vermilion's results of operations and financial performance. Readers are cautioned, however, that these measures and ratios should not be construed as an alternative to measures determined in accordance with IFRS as an indication of our performance. For a full description of these financial measures and ratios and a reconciliation of these measures and ratios to their most directly comparable GAAP measures and ratios, please refer to the "Non-GAAP and Other Specified Financial Measures" section of Vermilion’s MD&A for the three and nine months ended September 30, 2025, which information is incorporated by reference herein. Reserves Advisories Reserves estimates in this presentation are derived from an evaluation report dated March 4, 2025 with an effective date of December 31, 2024 are prepared by McDaniel & Associates Consultants Ltd. (the "McDaniel Report"), an independent qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. For a full description of the McDaniel Report, including the forecast price and cost assumptions used therein, please refer to Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024. This presentation includes reference to certain metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Readers are cautioned as to the reliability of oil and gas metrics used in this presentation. These oil and gas metrics includes “DCET costs" and "decline rates". DCET costs includes all capital spent to drill, complete, equip and tie-in a well. Management uses these oil and gas metrics for its own performance measurements and to provide readers with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance, which may not compare to the Company's performance in previous periods, and therefore should not be unduly relied upon. Additional oil and gas metrics in this document may include, but are not limited to: Boe Equivalency: Certain natural gas volumes have been converted on the basis of six thousand cubic feet of gas to one barrel of oil. Barrels of oil equivalent (boes) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil 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 addition, utilizing a conversion of six thousand cubic feet of gas to one barrel of oil may be misleading as an indicator of value as the value ration between conventional natural gas and crude oil, based on the prices of natural gas and crude oil, differ significantly from the energy equivalency of six million cubic feet to one barrel of oil.
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42 42 SLIDE NOTES Disclaimer: Estimates of drilling locations Drilling inventory reflects company estimates of future drilling locations and expected pace of future development, and includes locations evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") as well as unbooked locations. Of the locations disclosed in this presentation, 365 have been evaluated by McDaniel, as part of either Vermilion’s reserve report for the year ended December 31, 2024, or a report prepared by McDaniel for the evaluation of the acquisition of Westbrick Energy Ltd. with an effective date of November 30, 2024. The remainder of locations are unbooked. Unbooked drilling locations are the internal estimates of Vermilion based on Vermilion's prospective acreage and internal review of potential locations. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Vermilion's management as an estimation of Vermilion's multi- year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Vermilion will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Vermilion will actually drill wells, including the number and timing thereof, is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management of Vermilion has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Disclaimer: Multi-year estimates Elements of company 2026-2030 forecast derived by utilizing, among other assumptions, historical Vermilion production performance and current cost assumptions, adjusted annually after 2026. 2027 and beyond provided for illustrative purposes only. Budgets and forecast beyond 2026 have not been finalized and are subject to a variety of factors including prior year’s results. Included in this presentation are estimates of the Company's 2026-2030 production, excess free cash flow and excess free cash flow per share which are based on various assumptions as to business unit production levels, commodity prices, the anticipated receipt of drilling permits and other assumptions and in the case of the years other than 2025 or 2026, such estimates are provided for illustrative purposes only. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in December 2025 and are included to provide readers with an understanding of the Company's anticipated excess free cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. Slide 2 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 3 (1) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. Year-end 2025 net debt based on company estimates and full year average reference prices as at October 27, 2025 (see Pricing & FFO Sensitivity slide). (2) Non-GAAP financial measure or ratio. Slide 4 (1) Subject to approval by the Company’s Board of Directors. (2) Based on company estimates as at October 27, 2025. Slide 5 (1) Current 2025 guidance reflects foreign exchange assumptions of CAD/USD 1.40, CAD/EUR 1.58, and CAD/AUD 0.90. Current 2026 guidance reflects foreign exchange assumptions of CAD/USD 1.38, CAD/EUR 1.63, and CAD/AUD 0.91. (2) General and administration expense exclusive of expected cash-settled equity based compensation of $0.15-0.20/boe. Slide 7 (1) Production, unit costs and capital intensity for 2024 reflects actuals per annual report. Estimates for 2026e based on Company estimates as at October 27, 2025. Slide 8 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 9 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations. Slide 10 (1) Q3 2025 realized natural price per company public disclosures. Realized hedge gains for peers reflects realized gain for gas as disclosed, or full realized hedge gain for Q3 2025 if gain by product type not disclosed. (2) Based on company 2026 estimates as at October 27, 2025. (3) Price exposure reflects hedges in place October 27, 2025 as a percentage of estimated 2026 production based on company 2026 estimates as at October 27, 2025. Slide 11 (1) 2017 – 2024: Actual prices. 2025e-2026e forward price as at October 27, 2025 strip pricing (see Pricing & FFO Sensitivity slide). Slide 14 (1) Production for Q3 2025, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Reported production in Canada includes Deep Basin and Montney production. (2) Acreage includes approximately 770,000 net acres of land from the acquisition of Westbrick Energy Ltd., which closed on February 26, 2025, and was not included in Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024. (3) Infrastructure nameplate capacity reflects Vermilion owned and operated infrastructure, including gas plants, major compressors, and oil batteries. Vermilion has available capacity on owned processing infrastructure and has existing connections to third-party infrastructure with significant available capacity. (4) Based on company estimates as of December 9, 2025. (5) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations. Slide 15 (1) Drilling cost per horizontal metre is a measure of efficiency of drilling operations, which represents a significant component of the total cost of an oil and gas well. Values shown as per available Deep Basin peer disclosures and Vermilion actual results for the applicable year.
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43 43 Slide 16 (1) Production rates presented above are for a limited timeframe only and may not be indicative of future performance or the ultimate recovery for a given well or pad. Readers are cautioned not to place reliance on such rates. (2) 2P gross estimates provided by McDaniel & Associates Consultants Ltd (“McDaniel”). (3) Estimated liquids (light and medium crude oil and NGLs) included in reserve estimates as a percentage of total reserves, as provided by McDaniel. (4) Before tax IRR based on estimates provided by McDaniel and using flat US$70 WTI / $3.50 AECO pricing assumptions. IRRs shown represent weighted average by formation, based on the number of drilling locations assessed and the IRR associated with those locations. (5) Payout represents the point at which a well recovers all upfront cost of that well on a half-cycle basis. Payouts shown are based on Company estimates as of December 9, 2025, and using flat US$70 WTI / $3.50 AECO pricing assumption. (6) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as of December 9, 2025, and flat US$70 WTI / $3.50 AECO pricing assumptions. Slide 17 (1) Production for Q3 2025, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Reported production in Canada includes Deep Basin and Montney production. (2) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024, available on SEDAR+ at www.sedarplus.ca. (3) Infrastructure nameplate capacity includes existing Vermilion owned and operated facilities as well as future expansion, the timing of which is based on company estimates as of December 9, 2025. (4) Based on company estimates as of December 9, 2025, refer to the disclaimer on multi-year estimates. (5) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 18 (1) Vermilion has ownership of, or control and direction over, approximately 10% of the issued and outstanding common shares of Coelacanth Energy Inc. (“CEI.V”). For additional detail, refer to Vermilion press release dated December 17, 2025. Slide 19 (1) Total cost to drill, complete, equip and tie-in (“DCET”) per well. (2) Net present value (“NPV10”) is a supplementary financial measure which represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate. Management uses this measure to determine the current value of long-term cash flow, considering the time value of money over the period assessed. Slide 20 (1) Production rates presented above are for a limited timeframe only and may not be indicative of future performance or the ultimate recovery for a given well or pad. Readers are cautioned not to place reliance on such rates. (2) 2P gross estimates provided by McDaniel & Associates Consultants Ltd (“McDaniel”). (3) Estimated liquids (light and medium crude oil and NGLs) included in reserve estimates as a percentage of total gross 2P reserves, as provided by McDaniel. (4) Before tax IRR based on estimates provided by McDaniel and flat US$70 WTI / $3.50 AECO pricing assumptions. Reflects deep cut economics and January 1, 2027, BC natural gas royalty framework. (5) Payout represents the point at which a well recovers all upfront cost of that well on a half-cycle basis. Payouts shown are based on Company estimates as of December 9, 2025, and using flat US$70 WTI / $3.50 AECO pricing assumptions. (6) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as of December 9, 2025, and using flat US$70 WTI / $3.50 AECO pricing assumptions. Slide 21 (1) 2022-2024 reflects actual production, 2025 based on company estimates as of December 9, 2025. Company 2026-2030 forecast as of December 9, 2025, refer to the disclaimer on multi-year estimates. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 22 (1) Gas production for Q3 2025, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. (2) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024, available on SEDAR+ at www.sedarplus.ca. Slide 23 (1) 2P gross reserves based on internal estimates as at May 7, 2025. (2) Estimated natural gas included in reserve estimates as a percentage of total reserves. (3) After tax IRR based on internal estimates as at May 7, 2025, using flat €28/MWh pricing assumptions. (4) Payout is the point in time at which all costs associated with a well are recovered from the cash flows of the well, calculated using after-tax cash flows beginning at the on-stream date. (5) Lifetime payout represents the number of times a well recovers all upfront cost of that well on a half-cycle basis. Payout shown is an average for Germany development based on Company estimates as of December 9, 2025, and using flat €28/MWh pricing assumptions. (6) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as at May 7, 2025 and using flat €28/MWh pricing assumptions. Slide 24 (1) Total proved plus probable conventional natural gas reserves, as evaluated by McDaniel, a qualified reserves evaluator. Gross reserves reflect 64% working interest in Wisselshorst Z1a well. Refer to Vermilion’s annual report for the three months and year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 25 (1) 2023-2024 reflects actual production, 2025 based on company estimates as of December 9, 2025. Company 2026-2030 forecast as of December 9, 2025, refer to the disclaimer on multi-year estimates. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 27 (1) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. Year-end 2025 net debt based on company estimates as of December 9, 2025, and full year average reference prices as at October 27, 2025 (see Pricing & FFO Sensitivity slide). (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. (3) Shares purchased to December 31, 2025. SLIDE NOTES
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44 44 Slide 28 (1) Reflects period-end net debt to four quarter trailing fund flows from operations, for further information refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures” section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. 2025e-2026e based on company estimates and full year average reference prices as at October 27, 2025 (see Pricing & FFO Sensitivity slide). (2) Reflects outstanding borrowings and available liquidity at September 30, 2025. Revolving credit facility (“RCF”) balance includes letters of credit outstanding and may not agree to reported RCF balance at September 30, 2025. Refer to Vermilion’s financial statements for the three and nine months ended September 30, 2025, available SEDAR+ at www.sedarplus.ca for additional information. USD borrowings translated at September 30, 2025 FX rate of 1.3921. Slide 29 (1) 2024 reflects period-end net debt to four quarter trailing fund flows from operations, for further information refer to the "Non- GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, a vailable on SEDAR+ at www.sedarplus.ca. Production for 2024 reflects actual production per annual report. Estimates for 2025e and 2026e, including net debt to trai ling FFO and FFO per share, based on company estimates using October 27, 2025 strip pricing (above). * Realized hedge gain reflects actual/forecast realized gain and tax impact of hedge gain. Slide 30 (1) Company estimates as at December 9, 2025, includes impacts of Westbrick acquisition, which closed February 26, 2025 and sales of Saskatchewan and United States assets, which closed in July 2025. Hedge percentages based on contract volumes as a percentage of net of royalty production and excludes basis swaps on North American natural gas. Slide 31 (1) Subject to approval by the Company’s Board of Directors. (2) 2022 – 2024 actual share count. 2025e-2026e based on company estimates and full year average reference prices as at October 27, 2025 (see Pricing & FFO Sensitivity slide). Slide 33 (1) Commodity price assumptions listed have been reflected throughout this presentation using the October 27, 2025 strip, unless otherwise noted. (2) Annual FFO sensitivity based on company 2026 estimates, with 2026 full year average reference prices as at October 27, 2025. Slide 35 (1) As per public disclosure. (2) Based on company 2026 estimates as at October 27, 2025. (3) 2012-2024 : Actual prices, 2025e-2026e forward price as at October 27, 2025 strip pricing (see Pricing & FFO Sensitivity slide). Slide 36 (1) Europe for the purposes of this discussion defined as EU27+UK (2) Source: Refinitiv, November 2025, domestic production includes EU and UK production and direct pipeline supply from Norway, North Africa and Azerbaijan. (3) Source: Bloomberg, May 2025 Slide 38 (1) Emissions calculated in general accordance with GHG Protocol and IPCC guidance; reported intensities are based on operated throughput; Scope 1 and 2 emissions externally verified (limited assurance) in accordance with ISO 14064-3 standard. (2) Based on 2024 data. Slide39 (1) Producing and non-producing well count for 2022-2024 per Vermilion’s Annual Information Form for the respective year. 2025e reflects the addition of producing and non-producing wells from Westbrick Energy and the divestment of producing and non-producing wells in Saskatchewan and the United States. SLIDE NOTES