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1 NOVEMBER 2026 VERMILION ENERGY INVESTOR PRESENTATION GLOBAL GAS PRODUCER FREE CASH FLOW FOCUSED FINANCIAL DISCIPLINE
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2 Montney Momentum o Structural increase to excess free cash flow(1) 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 Dividend growth and share buybacks underpinned by excess free cash flow generation Enhancing Profitability of our Unique Global Gas Portfolio o Stronger capital efficiency, lower corporate declines, lower cash costs and premium commodity exposure Operational excellence driving a structurally higher Excess Free Cash Flow business
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3 VERMILION AT A GLANCE Market Summary VET Trading Price (October 30, 2026) $19.13 (TSX), US$13.69 (NYSE) Shares Outstanding (October 31, 2026) 151.4 MM Average Daily Trading Volume (shares) 1.2 MM (TSX), 1.7 MM (NYSE) Quarterly Dividend $0.135/share Capital Structure Market Capitalization $2.9 B Enterprise Value $3.8 B Year-End 2027 Net Debt(1) $0.9 B Year-End 2027 Net Debt-to-FFO Ratio(1) 0.8x Guidance 2026 2027 Production (boe/d) 122,400 122,000 – 126,000 Q4 2026 Production (boe/d) 121,000 E&D Capital Expenditures(1) $620MM $675 – 725MM All financial data is reported in Canadian dollars, unless otherwise stated 3
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4 Free cash flow funds growth, debt reduction and shareholder returns with premium European gas exposure KEY UPDATES 4 Deep Basin Montney European Gas Corporate • Continued outperformance from recent drilling program; added five net wells in 2026 with no change to E&D guidance • Recent well produced >12 mmcf/d of natural gas, >400 bbls/d of condensate in August 2026 • Drilled Upper Mannville well to ~7,800m, longest Upper Mannville well drilled by any operator • Growing production within cash flow, 2027e production up ~10%(1) with positive EFCF(2) • DCET costs reduced ~25% since 2024 to $8.2MM per well, continue to advance pilots to identify areas for further cost reductions • Reduction in remaining capital to reach 28,000 boe/d target rate; $45MM of infrastructure and 28 wells left to drill (1) • Expect European gas production of ~100mmcf/d in Q4/26(1) • Forecast record Germany production of ~7,500 boe/d in Q4/26 (1), ~25% higher than Q1/26 • Wisselshorst first production in July 2026; lease construction for follow-up wells in progress, on track for mid-2028 on-stream • Spud Netherlands well (0.5 net) in Q4/26, expect production H1/27 • Full-cycle profitability supported by sustaining capital of ~$565MM, base decline of 24% and lower unit costs • On-track for >$200 million of debt reduction, forecast year-end 2026 net debt of ~$1.1B (1,3) • Targeting a 4% dividend increase to $0.56/share in 2027, sixth consecutive annual increase • Increasing return of capital with shareholder returns of 40% – 60% of EFCF targeted
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5 2027 BUDGET HIGHLIGHTS 5 Executing the five-year plan, allocating more capital to increase European Gas and Brent Oil exposure • E&D capital budget of $675 – 725MM o Canada - $385 million • Drill 41 (36.3 net) wells in Deep Basin, 13 (13.0 net) wells in Montney • Growing Montney production ~10% with positive excess free cash flow (“EFCF”) (2) o International - $315 million • Increase of >50% vs. 2026, allocating capital to high-return drilling prospects and growth infrastructure • Drill two (1.3 net) wells in Germany, two (1.0 net) well in Netherlands, two (2.0 net) wells in Australia • Return of capital target of 40 – 60% of EFCF o Planned 4% dividend increase to $0.56/share annually DEEP BASIN MONTNEY EUROPEAN GAS ASSETS LEGACY OIL 79% 13% 8% PRODUCTION WEIGHTING(1) 65% 15% 13% 7% PRODUCTION WEIGHTING(1) 122-126 mboe/d 71% Natural Gas 29% Liquids 39% 15% 14% 11% E&D CAPITAL ALLOCATION(1) $675-725MM 55% Canada 45% International Capital Benefitting 2028+ ($150MM) includes: - Australia drill and CALM buoy replacement - Germany sales pipeline - Montney infrastructure
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6 6 GLOBAL GAS PORTFOLIO
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7 57% 22% 15% 6% 2030E PRODUCTION(1) DEEP BASIN MONTNEY EUROPEAN GAS LEGACY OIL ~130 mboe/d ~40% increase in production per share(4) FIVE-YEAR OUTLOOK: GROWING EFCF PER SHARE Ahead of plan: EFCF raised to $1.9B on higher 2026-27 pricing and asset outperformance 7 8-10% Annual production per share growth(1) $600-630MM annual capex(1) Higher 2027 capex w/ Australia drill ($700MM) Five-Year Plan Drives $1.9B Cumulative EFCF(1,2) Up from $1.7B At 2025 Investor Day 2026-2027 strip pricing(3) 2028+ flat commodity pricing (US$70 WTI / C$3.50 AECO / C$13 TTF) 2026 Operational Excellence Raised 2026 production guidance; Canada opex down 10% year-over-year; reduced DCET costs in the Montney Debt Reduction Ahead of Plan Line of sight to $750MM net debt on robust 2026-27 cash flows; targeting 40%-60% of EFCF to shareholder returns European Gas Growth 2028+ Expand production from existing discoveries; drill follow-up Wisselshorst wells; Germany tuck-in acquisition adds production and infrastructure
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8 2-3% per year Infrastructure and organization in place to produce 150 mboe/d, focusing on execution to hit 130 mboe/d by 2030 3-4% per year Ratable base dividend growth, with low current payout ratio providing runway for future increases 3-5% per year Repurchased 22 million shares from 2022 to Q3 2026, continue to actively repurchase shares 5-8% per year Reduce net debt(2) from $1.34B to ~$0.75B by 2030; capital allocation flexibility between debt reduction and direct shareholder returns 15-18% Total annual return compounds over multi-year planTotal Return(1) Prudently allocating $1.9B of EFCF(3) from our 5-year plan to create long-term shareholder value 8 TOTAL RETURN: COMPOUNDING VALUE Production Growth Dividend Yield Share Buybacks Debt Reduction Total return of ~22% in 2026
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9 Improving profitability of global gas assets enables debt reduction, dividend growth and share buybacks CAPITAL ALLOCATION 9 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 2026e 2027e $MM FFO ALLOCATION(3) FUND FLOWS FROM OPERATIONS REALIZED HEDGE LOSS* INTEREST EXPENSE E&D CAPEX/ARO/LEASES EXCESS FREE CASH FLOW FFO of ~$1,000MM Unhedged DACF(4) of ~$8.50/basic share FFO of ~$1,150MM Unhedged DACF of ~$9.50/basic share 2026 EFCF(1) Up >60% vs. Original Budget o Strong operational performance driving production 2% above original guidance, Canada opex 10% lower year-over-year 2027 Budget EFCF >20% Higher than 2026 o Investing $150MM beyond sustaining capital to support 2028+ production growth, aligned with stay-flat capital of $565MM 2028-2030 EFCF Target On Track o Improved cost structure, capital efficient growth aligns 2028-30 (2) EFCF with Investor Day, 2026-27 outperformance increases cumulative EFCF
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10 IMPROVEMENT: CAPITAL EFFICIENCY Five-year plan delivers 10% absolute production growth(1) on $630MM average annual capital Delivering Production Growth on Flat Capex 10 $450 $500 $550 $600 $650 $700 2026 BUDGET E&D CAPITAL 2027 BUDGET E&D CAPITAL 2028-2030 PLAN AVG. E&D CAPITAL E&D CAPITAL ($MM) E&D CAPITAL ALLOCATION(2) STAY-FLAT E&D CAPITAL NON-RECURRING CAPITAL AUSTRALIA DRILL CAPITAL CAPITAL ALLOCATION Non-recurring capital shifts to growth and/or returns in 2028+ Maintaining stay-flat E&D capital of ~$565MM per year Australia drilling planned for 2027, non-recurring in 2028+ • Five-year average E&D capital of $630MM (2026-2030)(1) includes one-time Australia drill program and other non-recurring capital o Stay-flat capital requirement of ~$565MM remains unchanged over 2026-2030 period • ~$200MM of non-recurring capital projects in 2026-2028: o Owned Montney infrastructure o Germany Wisselshorst debottlenecking o Ireland turnaround and optimization projects o Australia CALM buoy replacement • From 2028, the Company has more optionality to allocate capital to profitable growth and shareholder returns
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11 Low base decline supports lower stay-flat capital and improves full-cycle margins IMPROVEMENT: LOWER BASE DECLINE 11 AVERAGE = 30% 0 10 20 30 40 VET 2027 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 2027 BASE DECLINE RATE (%) BASE PRODUCTION DECLINE VS. PEERS(1) AVERAGE (EXCL VET) VET base decline has improved from ~30% in 2025 (post-acquisition) to ~24% in 2027
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12 • Lower unit operating expense from efficient growth assets: o Germany Deep Gas - ~$3/boe(1) o Deep Basin and Montney - ~$7/boe o Legacy business units with higher operating costs becoming a smaller proportion of overall corporate opex • Lower interest expense with debt reduction and retirement of senior unsecured notes o Reduced debt by $200MM in 2026, forecast similar in 2027(1) o Forecast ~$30MM lower annual interest expense in 2028-2030(2) • Staffed to execute five-year plan, expect minimal changes to personnel count Unit cost reduction of ~$1.50/boe improves profit margins IMPROVEMENT: LOWER UNIT COST 12 Delivering Lower Unit Costs $17.15 $16.90 <$16 2026e 2027e 2028-2030 Plan (Avg.) LOWER UNIT COSTS (OPEX + G&A + INTEREST/BOE)(1)
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13 Profitability rate of change is driven by improving capital efficiency, base declines and cash costs STRUCTURAL IMPROVEMENT: PROFITABILTY ~ $50MM/year Capital Allocation With lower sustaining capital, from 2028 Vermilion has optionality to allocate $50MM to profitable growth and/or shareholder returns 22% Base Decline Rate With moderating base decline from the current ~24%, Vermilion will require less E&D capital to maintain production in 2028 onward(1) ~ $1.50/boe Lower Unit Costs Lower opex through operational excellence, lower interest expense with debt reduction and lower unit G&A due to operational scale $2-3/boe Five-year plan targets ~$100MM annual EFCF impact(1)Structural Margin Improvement Improving Capital Efficiency Moderating Base Decline Lower Cash Costs 13
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14 CAPITAL ALLOCATION 14
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15 Disciplined capital allocation focused on creating long term shareholder value CAPITAL ALLOCATION PRIORITIES Compounding Shareholder Returns Strategic Portfolio Management Robust Asset Base Strong Balance Sheet o Allocating at least 40% of EFCF(1) to debt repayment o Targeting net debt to FFO ratio (2) less than 1.0x o $1.1B of available liquidity o Long-life, high-return inventory o Global gas portfolio with strong liquids exposure o Flexibility to allocate capital to enhance returns o Targeting 40-60% return of EFCF to shareholders o Six consecutive years of dividend increases o Repurchased 22MM shares (3) since Q2/22 o Increase operational scale in core areas o Uniquely positioned for international acquisitions o Acquisitions must compete with organic development 15
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16 On track to reduce net debt by >$1 billion while improving per share metrics BALANCE SHEET: ACCELERATING DEBT REDUCTION 16 $0 $500 $1,000 $1,500 $2,000 YE 2024 Q1 2025 YE 2025 YE 2026e YE 2027e NET DEBT ($MM)(1) NET DEBT 0.0x 0.5x 1.0x 1.5x 2022 2023 2024 2025 2026e 2027e NET DEBT TO FFO RATIO(3) HISTORICAL NET DEBT TO FFO AVAILABLE LIQUIDITY OF $1.1B $0.22B $0.49B $0.53B CURRENT CREDIT CAPACITY(2) UNDRAWN CAPACITY ON REVOLVING CREDIT FACILITY REVOLVING CREDIT FACILITY 2030 MATURITY SENIOR UNSECURED NOTES 2030 MATURITY SENIOR UNSECURED NOTES 2033 MATURITY Committed to operating at 1.0x leverage
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17 Enhanced profitability through long-life assets with improved capital efficiency and low base decline 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 10-15 Years Drilling Inventory Technical leaders in the Rotliegend play in Germany and Netherlands, potential to add deep gas prospects Growing EFCF with Deep Gas Exploration program ASSET BASE: KEY GROWTH ASSETS Deep Basin Montney Germany 17
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18 Development plan targets 2-3% organic production growth per year ASSET BASE: PROFITABLE RESERVES GROWTH 18 December 31, 2025 PDP 1P 2P North America (mmboe)(1) 164.1 310.4 501.4 International (mmboe)(1) 46.1 57.7 91.0 Vermilion (mmboe)(1) 210.2 368.1 592.3 PV10 (Before Tax, $B)(1) $2.0 $2.8 $4.8 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 PDP 1P 2P BOE/SHARE(1) RESERVES GROWTH PER SHARE 2023 2024 2025 Organic and inorganic reserves growth o 2P FD&A(2) of $7.71/boe drives recycle ratio of 3.5x(3) o 2P reserves replacement of over 450%(4) Significant upside to reserves bookings o 77% of Deep Basin and Montney locations are unbooked(5) o Future development in Germany, Netherlands unbooked
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19 20% BOOKED LOCATIONS UNBOOKED LOCATIONS Vermilion’s growth assets have decades of development ahead that is not reflected in our reserves 10% GERMANY & NETHERLANDS GAS ASSET BASE: INVENTORY FOR THE FUTURE 19 ~31 . Accumulations 20% DEEP BASIN ~1,450 . Locations(1) 37% MONTNEY ~250 . Locations
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20 ASSET BASE: TOP-DECILE REALIZED GAS PRICE 20 AVERAGE (EXCL VET) = $2.53 $0 $1 $2 $3 $4 $5 $6 REALIZED NATURAL GAS PRICE ($/MCF) Q2 2026 REALIZED NATURAL GAS PRICE(1) REALIZED GAS PRICE REALIZED HEDGE GAIN Vermilion’s unique Global Gas portfolio delivers top-decile realized gas price 40% 22% 4% 4% 5% 8% 4% 7% 6% NATURAL GAS PRICE EXPOSURE(2) FINANCIAL HEDGES AECO BASIS PHYSICAL HEDGES ALLIANCE STATION 2 (FROM NOV/26) EUROPE (TTF) EUROPE (THE) EUROPE (NBP) AECO Exposure Diversification Euro Gas
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21 European natural gas prices trade at a significant premium to North American benchmarks ASSET BASE: EXPOSURE TO EUROPEAN GAS PRICES $0 $10 $20 $30 $40 $50 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026e 2027e TTF GAS PRICES (C$/MMBTU)(1) HISTORICAL AND FORWARD PRICING OF GLOBAL GAS JKM TTF 21 Euro Gas H2/2026 2027 % Hedged 56% 39% Average Floor $13 $13 Since February 23, 2026(2): 2026 TTF strip up 30% 2027 TTF strip up 30% Demand from Asian buyers has elevated JKM above European benchmarks, European buyers must outcompete on pricing to secure LNG cargos
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22 ASSET BASE: PRODUCT & REVENUE RESILIENCE 22 Natural Gas 71% Liquids 29% 2027E PRODUCTION BY PRODUCT(1) Global Gas Producer with strong WTI and Brent-linked liquids contribution provides cash flow resilience Canada Natural Gas 14% Europe Natural Gas 41% Liquids 45% 2027E REVENUE BY PRODUCT(1)
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23 125 135 145 155 165 2022 2023 2024 2025 2026e 2027e SHARE COUNT (MM)(1) SHARE COUNT Improving profitability from the five-year plan positions Vermilion for increasing shareholder returns SHAREHOLDER RETURNS: COMPOUNDING IMPACT 23 $0.00 $0.20 $0.40 $0.60 $0.80 2022 2023 2024 2025 2026 2027 DIVIDENDS PER SHARE ANNUAL DIVIDEND PER SHARE 2027 dividend payout is <10% of FFO 11% lower share count improves per share metrics
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24 SHAREHOLDER RETURNS: DIVIDEND PAYOUT 0% 10% 20% 30% 40% 50% Peer 1 VET Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% DIVIDEND PAYOUT (% OF FFO)(1) DIVIDEND YIELD (%)(1) 2027 DIVIDEND PAYOUT VS. YIELD DIVIDEND PAYOUT DIVIDEND YIELD Low payout + growing EFCF(2) = capacity for ratable dividend growth 24 Vermilion offers a dividend yield in-line with peers while only paying out <10% of FFO
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25 PER-SHARE OUTPERFORMANCE VET Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 -60% -40% -20% 0% 20% 40% 60% 80% PRODUCTION PER SHARE GROWTH (VS. 2022)(1) PRODUCTION PER SHARE GROWTH VS. PEERS Vermilion has reduced share count while growing per share production over 50% 25 Vermilion has grown production per share by >50% from YE 2022 to Q2 2026 Peer group comprised of oil- and gas-weighted companies, including senior/integrated
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26 International Acquisition Upside Acquisitions in Ireland and Germany o Strategic transactions add high-netback production PORTFOLIO MANAGEMENT: PRINCIPLES Since 2022, Vermilion has repositioned the Company to enhance total returns 26 Portfolio RepositioningVermilion Approach Leverage Technical Expertise Operational Scale in Core Areas Increase European Gas Exposure Focus on Key Global Gas assets o Exited five regions, growth across core assets Germany Deep Gas Exploration Program o Successful exploration supports EFCF(1) growth Extensive Resource with Inventory Upside o 1.3MM acres in Canada, >2MM acres in Europe
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27 KEY ASSET OVERVIEW 27
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28 Vermilion’s Canadian assets are focused in two of the top four North American gas plays CANADA LIQUIDS-RICH GAS ADVANTAGE 28Source: Peters & Co. Limited Fall 2026 Energy Overview. Estimates based on ~US$70.00/B WTI, ~US$3.75/Mcf NYMEX, ~$3.00/Mcf AECO. - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Montney Oil Montney Liquids Rich Duvernay Deep Basin Montney Dry Gas Marcellus Permian Midland Permian Delaware Haynesville PAYOUT (YEARS)(1) HALF-CYCLE PAYOUT PERIOD Canadian Plays (Median 1.0 Years) U.S. Plays (Median 1.5 Years)
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29 Decades of stacked zone inventory supported by existing infrastructure DEEP BASIN: OVERVIEW Overview Key Statistics Production: 77,000 boe/d (27% liquids) (Q3 2026)(1) Acreage: 1.2 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 29 Source: XI Technologies Asset Book
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30 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 DEEP BASIN: OPERATIONAL EXCELLENCE 30 Shallower target depths o Drilling less vertical depth improves cycle time and reduces drilling cost Consistent three-rig drilling program o Maintain high-performance rig crews, ability to negotiate better cost structure Longer Wells at Lower Per Metre Cost o Improved capital efficiency and flexibility, accessing more reservoir from a single surface location
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31 DEEP BASIN: ROBUST ECONOMICS 31 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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32 MONTNEY: OVERVIEW 32 Overview Key Statistics Production: 18,000 boe/d (23% liquids) (Q3 2026)(1) Acreage: 80,000 acres(2) Infrastructure: >30,000 boe/d nameplate capacity (2028 Est.)(3) History Entered the Montney in 2022, grew production from ~4,000 boe/d to >16,000 boe/d in 2026(4) Reduced DCET capital by ~35% since 2022, focused on translating operational wins into repeatable reductions in DCET cost Outlook Plan to reach 28,000 boe/d target production rate in 2029(5), structural increase to EFCF(6) generation with ~8 wells/year to maintain production Alberta development offers upside to target production rate Approaching structural increase in EFCF with majority of infrastructure spend completed
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33 A significant and contiguous premium acreage block in the oil window of the Montney MONTNEY: PREMIUM ACREAGE 33 VET owns ~9% of CEI.V(1) (~$40 million) Source: Land information sourced from EVA
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34 Continuous improvement drives efficiencies on our BC Montney assets MONTNEY: COST OPTIMIZATION 34 $0 $2 $4 $6 $8 $10 $12 16-28 (2024) 9-21 (2024) 8-4 / 9-21 Average (2025) 8-35 (2026) Planned Cost ($8.2MM) PER WELL COST ($MM) BC MONTNEY AVERAGE WELL COST • DCET(1) cost reduced to $8.2MM (from $8.5MM) o Improves project economics, total savings to-date (right) represents >$100 million (NPV10)(2) in future development cost o Piloted new completion approach to reduce sand and water recovery in Q3/26 o DCET cost savings are repeatable • Water hub and disposal infrastructure reduces cost of water handling o Allows for more recycled water to be used • Drilling speed (>20% faster) and frac efficiency (>80% improvement) drives lower cost o Established new drilling pace benchmark in Q4/26
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35 35 MONTNEY: WELL ECONOMICS Leading DCET costs in the oil window of the Montney BC Middle Montney Lateral Length (m) 3,000 DCET Cost ($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
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36 Target production rate generates $125-150MM of EFCF on lower capital requirements 36 MONTNEY: PIVOT TO EFCF IN 2029 - 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 w/ minimal infra spend o Plan to drill ~8 wells/yr to maintain production 2022-2026 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 $8.2MM, remain focused on translating repeatable reductions to lower DCET EFCF(2) generationBuild infrastructure and reduce DCET costs 2027-2028 Plan o Phase 3 expansion, owned infra build-out complete o $45MM remaining infra spend o ~28 wells remaining to reach target production Growing within cash flow
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37 Significant undeveloped land base with long runway of high-return projects across Germany and Netherlands EUROPEAN GAS SYNERGIES: GERMANY & NETHERLANDS 37 Overview Key Statistics Gas Production: 51 mmcf/d (60% Germany / 40% Netherlands)(1) Acreage: 2.1 million acres (67% Germany / 33% Netherlands)(2) History Proven track record of development with 30+ exploration wells at 70% success rate over 20 years Technical leaders in the Rotliegend play, leveraging technology and operational synergies across the 300 km fairway Significant undeveloped land base with extensive 3D seismic coverage Outlook Building out Germany infrastructure and developing material gas discovery; exploration upside from long runway of prospects Targeting larger Netherlands prospects within existing infrastructure Source: ESRI, SRTM Worldwide Elevation Data 20+ years operating in the Netherlands… … exploring and developing the same formations in Germany ~300 km
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38 GERMANY: EXPLORATION POTENTIAL 38 Identified 9 structures to date and have drilled 3; potential for up to 30 total locations with success Deep Gas Exploration Type Well (1.0 Net) @ C$13/MMBTu Vertical Depth (m) ~5,000 DCET Cost ($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 Small “e” exploration – finding gas where gas has been found A single year at current European gas prices reduces payout to ~6 months Osterheide has generated $65MM of EFCF(7) since start-up Burgmoor has paid out 4 times since start-up in Q3 2021 Wisselshorst first production July 2026
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39 Vermilion’s largest discovery in over a decade is the latest significant discovery in the North German Basin Discovery Well 2P Reserves 67 Bcf Property Gross(1) 43 Bcf Gross to Vermilion GERMANY: SIZE OF THE PRIZE 39 Source: Petroleum Geological Atlas of the Southern Permian Basin Areas (2010), LBEG - “Erdgastabellen 1949-2024”, ESRI NORTH GERMAN BASIN Z2 Z3 Z1a Lease construction Q4 2026 Spud late-Q1/early-Q2 2027
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40 Germany exploration program offers low-cost international exposure and long-duration EFCF GERMANY: OUTLOOK FOR ORGANIC GROWTH 0 20 40 60 80 100 2023 2024 2025 2026 2027 2028 2029 2030+ MMCFE/D (NET) DEEP GAS PROGRAM PRODUCTION TIMELINE(1) Germany Base Deep Gas Success To-Date (1.6 net) Additional Wells 40 2024-2026 Success & First Production o Osterheide (OSTH) and Wisselshorst (WSSH) discoveries o OSTH online Q1 2025 at restricted rates o Initial WSSH infrastructure build-out o WSSH on-stream July 2026 at restricted rates 2027-2028 Follow-up Activity o Drill two (1.3 net) additional wells on Bommelsen license o Infrastructure debottlenecking to accelerate production and EFCF (2) 2028+ Self-funded Growth & Capital Allocation Optionality Plan to drill 4-6 wells on Deep Gas prospects by 2030, production growth 2030+ EFCF(2) generationDrilling and facility investment Production Forecast to Double by 2030 2.9 Net Wells of ~30 Gross Identified Prospects Grows VET European Gas Production to >110 mmcf/d(1)
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41 ADDITIONAL INFORMATION 41
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42 PRICING & FFO SENSITIVITY 42 COMMODITY PRICES(1) 2026e 2027e TTF ($/mmbtu) $ 28.19 $ 35.85 NBP ($/mmbtu) $ 27.69 $ 35.40 AECO ($/mcf) $ 1.84 $ 2.02 Henry Hub (US$/mmbtu) $ 3.50 $ 3.10 Brent (US$/bbl) $100.48 $ 94.89 WTI (US$/bbl) $ 87.16 $ 86.39 MSW = WTI less (US$/bbl) $ 0.44 $ 2.96 CAD/USD 1.39 1.39 CAD/EUR 1.60 1.57 CAD/AUD 0.98 0.97 EUR/GBP 1.17 1.18 2027 FFO SENSITIVITY (C$MM)(2) Change FFO Impact (Hedged) FFO Impact (Unhedged) TTF & NBP $1.00/mmbtu $15MM $23MM NA Gas Prices $0.25/mmbtu $24MM $37MM WTI & Brent US$1/bbl $ 8MM $12MM CAD/USD $0.01 $ 8MM $ 8MM CAD/EUR $0.01 $ 2MM $ 2MM
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43 Operational excellence driving a structurally higher Excess Free Cash Flow(3) business CORPORATE GUIDANCE 43 CATEGORY 2026 GUIDANCE(1) 2027 GUIDANCE(1) Production (boe/d) 122,400 122,000 - 126,000 % Natural gas 71% 71% E&D capital expenditures ($MM) $620 $675 - 725 Operating ($/boe) $12.75 - 13.25 $12.50 - 13.50 General and administration ($/boe)(2) $1.65 - 2.15 $1.65 - 2.15 Transportation ($/boe) $3.00 - 3.50 $3.00 - 3.50 Interest expense ($/boe) $2.00 - 2.50 $1.75 - 2.25 Royalty rate (% of sales) 7 - 9% 7 - 9% Cash taxes (% of pre-tax FFO) 4 - 8% 7 - 11% Asset retirement obligations settled ($MM) $55 $50 Payments on lease obligations ($MM) $10 $10
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44 0% 20% 40% 60% 80% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total PERCENTAGE OF PRODUCTION HEDGED (%)(1) 2027 WTI BRENT NATURAL GAS Visit vermilionenergy.com/Invest-with-us/hedging for more detailed hedging information HEDGE POSITION 0% 20% 40% 60% 80% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total PERCENTAGE OF PRODUCTION HEDGED (%)(1) H2/2026 WTI BRENT NATURAL GAS 44 WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/MMBtu) N.A. Gas (C$/MMBtu) Avg. Sold Call $101.88 $114.16 $24.34 $4.56 Avg. Bought Put $87.72 $92.87 $12.52 $3.07 Avg. Swap $87.28 N/A $14.74 $3.18 WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/MMBtu) N.A. Gas (C$/MMBtu) Avg. Sold Call $103.93 $113.00 $23.80 $4.52 Avg. Bought Put $89.94 $95.17 $13.22 $2.57 Avg. Swap N/A N/A $12.92 $2.97
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45 Global gas portfolio pairs long duration, liquids-rich Canadian gas with premium-priced European production GLOBAL GAS ASSETS 45 MONTNEY IRELAND CROATIA NETHERLANDS GERMANY DEEP BASIN Canada Liquid-Rich Gas Europe Premium-Priced Gas
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46 Geopolitical events and low European storage levels are supportive of European gas prices EUROPEAN GAS INVENTORIES 46 0 1,000 2,000 3,000 4,000 March June September December INVENTORY (BCF)(1) HISTORICAL NATURAL GAS INVENTORY 2021 2022 2023 2024 2025 2026 EU storage at lowest levels since Russia invasion of Ukraine Reaching 80% storage by November requires 2 Tcf of gas Legislation passed to not allow Russian LNG starting Jan/2027 Global LNG supply reduced by Straight of Hormuz closure Europe is set to enter the winter heating season with the lowest gas storage levels in at least 15 years
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47 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 47 • 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 2025 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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48 Low decline oil assets with exposure to Brent pricing generating free cash flow LEGACY OIL ASSETS 48 FRANCE • #1 domestic oil producer with two-thirds of the domestic industry • Extensive inventory of workovers, recompletions, and infill drilling AUSTRALIA • Offshore oil field approximately 80 km N.W. off the coast of Australia (55m water depth) • Q3 2026 lifting sold for US$119/bbl
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49 Read more at vermilionenergy.com/sustainability ENVIRONMENT, SOCIAL & GOVERNANCE • Achieved 16% reduction in Scope 1 emissions intensity since 2019(1) as of end 2024; now focused on reducing Scope 1+2 emissions intensity by 25-30% by 2030 • Asset high-grading and ARO spending has reduced well count by 50% since 2022 Environment • Geothermal energy for Parentis greenhouse supports 220 direct jobs • Geothermal energy for La-Teste eco-neighborhood reduces heating costs, avoids ~180 tonnes/year of CO2(2)Social • Board diversity, including 30% female members • Executive and employee compensation linked to ESG metricsGovernance 49 Vermilion’s Purpose: To responsibly produce essential energy, operating internationally to create long-term value for our shareholders, people and communities 0.015 0.020 0.025 0.030 2019 2020 2021 2022 2023 2024 2025 EMISSIONS INTENSITY TREND Scope 1+2 tCO2e per BOE
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50 Reducing well count and asset retirement obligations while growing production REDUCED WELL COUNT - 1,000 2,000 3,000 4,000 5,000 6,000 2022 2023 2024 2025 2026e 2027e WELL COUNT (NET)(1) TOTAL WELL COUNT PRODUCING WELLS NON-PRODUCING WELLS ARO settled ($MM) $38 $57 $55 $62 $55 $50 50 • 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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51 Enhancing economic opportunities through innovation and partnerships SUSTAINABILITY PROJECTS 51 Advancing environmental projects in communities where we live and work LA TESTE ECO-NEIGHBOURHOOD • Our oil operations provided 0.8 GWh of geothermal energy in 2025 • 30-year partnership provides an important part of the energy required for 550 homes • Avoids the emission of ~180t of CO2/year and considerably reduces residents’ heating bills PARENTIS SUSTAINABILITY PARTNERSHIP • Our oil operations provided 50 GWh of geothermal energy in 2025 to a nearby tomato greenhouse operation • Avoids the emission of 11,300t of CO2/year in relation to natural gas • 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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52 52 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 2026 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 November 4, 2026, 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, 2026, which information is incorporated by reference herein. Reserves Advisories Reserves estimates in this presentation are derived from an evaluation report dated March 3, 2026 with an effective date of December 31, 2025 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, 2025. 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. 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, 429 have been evaluated by McDaniel as part of Vermilion’s reserve report for the year ended December 31, 2025. 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.
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53 53 SLIDE NOTES Disclaimer: Multi-year estimates Elements of the company’s 2026-2030 forecast are derived by utilizing, among other assumptions, historical Vermilion production performance and current cost assumptions, adjusted annually after 2026. 2028 and beyond provided for illustrative purposes only. Budgets and forecast beyond 2027 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, capital and excess free cash flow 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 2028 and beyond, 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 November 2026 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 and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, 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 and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. Year-end 2027 net debt based on company estimates and full year average reference prices as at October 26, 2026 (see Pricing & FFO Sensitivity slide). Slide 4 (1) Based on company estimates as at October 26, 2026. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. (3) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. Year-end 2026 net debt based on company estimates and full year average reference prices as at October 26, 2026 (see Pricing & FFO Sensitivity slide). Slide 5 (1) Based on company estimates as at October 26, 2026. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 7 (1) Based on company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. (3) 2026-2027 forward price as at October 26, 2026, strip pricing (see Pricing & FFO Sensitivity slide). 2028+ based on company estimates as at October 26, 2026, and using flat US$70/bbl WTI, C$3.50/GJ AECO and C$13/MMBtu TTF pricing assumptions. (4) Production per share represents total annual production in barrels of oil equivalent (“boe”), with natural gas converted on the basis of one boe for six mcf of natural gas, divided by weighted average basic shares outstanding. Slide 8 (1) Total return based on company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. 2026-2027 estimates using forward price as at October 26, 2026, strip pricing (see Pricing & FFO Sensitivity slide), 2028+ using flat US$70/bbl WTI, C$3.50/GJ AECO and C$13/MMBtu TTF pricing assumptions. Share metrics calculated using $19 share price. (2) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. (3) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 9 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. (2) Based on company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. (3) Estimates for 2026e based on company estimates using October 26, 2026 strip pricing (see Pricing & FFO Sensitivity slide). (4) Unhedged DACF per basic share is calculated by dividing unhedged debt adjusted cash flows (FFO plus after-tax loss on derivative instruments plus interest expense) by the basic weighted average shares outstanding. More information can be found in the “Non-GAAP and Other Specified Financial Measures” section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. * Realized hedge loss reflects post-tax impact of hedging losses, based on company estimates as at October 26, 2026. Slide 10 (1) Based on company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. (2) Based on company estimates as at October 26, 2026. Average E&D capital for 2028-2030 presented for information purposes only. Slide 11 (1) Vermilion corporate decline based on company estimates as at October 26, 2026. Corporate decline rate for peers based on Peters & Co. Limited August 24, 2026 Energy Overview. Peer group includes AAV, BIR, BTE, KEL, OBE, PEY, POU, SDE, TOU, WCP. Slide 12 (1) Based on company estimates as at October 26, 2026. (2) Based on company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. Slide 13 (1) Based on company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. Slide 15 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. (2) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. (3) Shares purchased to November 3, 2026. Slide 16 (1) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. Year-end 2026e and 2027e net debt based on company estimates and full year average reference prices as at October 26, 2026 (see Pricing & FFO Sensitivity slide). (2) Reflects outstanding borrowings and available liquidity at September 30, 2026. Revolving credit facility (“RCF”) balance includes letters of credit outstanding and may not agree to reported RCF balance at September 30, 2026. Refer to Vermilion’s financial statements for the three and nine months ended September 30, 2026, available SEDAR+ at www.sedarplus.ca for additional information. USD borrowings translated at September 30, 2026, FX rate of 1.4188. (3) Reflects period-end net debt to four quarter trailing fund flows from operations, for further information refer to the "Non-GAAP and Other Specified Financial Measures” section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. 2026e and 2027e based on company estimates and full year average reference prices as at October 26, 2026 (see Pricing & FFO Sensitivity slide).
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54 54 Slide 17 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to Disclaimer: Estimates of drilling locations. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 18 (1) Reserves per share represents estimated gross proved, developed and producing, total proved, and total proved plus probable reserves as evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) in a report dated March 3, 2026 with an effective date of December 31, 2025 (the “McDaniel Reserves Report”), divided by basic share count at December 31 of the given year. See Vermilion’s annual information form for the year ended December 31, 2025 for additional information. (2) F&D (finding and development) and FD&A (finding, development and acquisition) costs are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period. More information can be found in the “Non-GAAP and Other Specified Financial Measures” section in Vermilion’s MD&A for the three months and year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. (3) Operating Recycle Ratio is a non-GAAP ratio that is calculated by dividing the Operating Netback, excluding PRRT and realized hedging gains and losses, by the cost of adding reserves (F&D and FD&A cost). For the purposes of calculating 2025 Operating Recycle Ratio, this netback number was $26.60. More information can be found in the “Non-GAAP and Other Specified Financial Measures” section in Vermilion’s MD&A for the three months and year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. (4) Reserves replacement represents estimated reserves additions as evaluated by McDaniel in the McDaniel Reserves Report, divided by production in the year. See Vermilion’s annual information form for the year ended December 31, 2025 for additional information. (5) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to Disclaimer: Estimates of drilling locations. Slide 19 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to Disclaimer: Estimates of drilling locations. Slide 20 (1) Q2 2026 realized natural price per company public disclosures. Peer group includes AAV, BIR, BTE, KEL, OBE, PEY, POU, SDE, TOU, WCP. Realized hedge gains for VET and peers reflects realized gain for gas as disclosed. (2) Based on company 2027 estimates as at October 26, 2026. Price exposure reflects hedges in place October 26, 2026, as a percentage of 2027 production based on company 2027 estimates as at October 26, 2026. Slide 21 (1) 2017-2025 actuals. 2026e-2027e forward price as at October 26, 2026, strip pricing (see Pricing & FFO Sensitivity slide). JKM presented for information purposes only. Slide 22 (1) Based on company 2027 estimates as at October 26, 2026. Slide 23 (1) 2022-2025 actuals. 2026e and 2027e based on company estimates and full year average reference prices as at October 26, 2026 (see Pricing & FFO Sensitivity slide). Slide 24 (1) Dividend payout and dividend yield based on Peters & Co. Limited August 24, 2026 Energy Overview. Dividend payout calculated as 2027 base dividend as a percentage of 2027 cash flow. Dividend yield reflects 2027 base dividend yield as stated. Peer group reflects dividend paying Canadian energy companies and includes BIR, BTE, CJ, CNQ, CVE, HWX, IMO, PEY, PNE, POU, PXT, SCR, SGY, SU, TOU, TVE, WCP. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 25 (1) Production per share calculated as YTD production divided by basic weighted average shares outstanding. Production per share growth shown as Q2 2026 compared to 2022. Peer group reflects Canadian energy companies with over 30,000 boe/d of production for both periods and includes AAV, ATH, BIR, BTE, CNQ, CVE, IMO, IPCO, PEY, POU, PXT, SCR, SDE, SU, TOU, TVE, WCP. Slide 26 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 28 (1) 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 Peters & Co. Limited estimates as of September 8, 2026, and using US$70 WTI / US$3.75/Mcf NYMEX / $3.00/Mcf AECO pricing assumption. Slide 29 (1) Production for Q3 2026, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2026, 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, 2025, available on SEDAR+ at www.sedarplus.ca. Reported acreage in Canada includes Deep Basin and Montney acreage. (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 October 26, 2026. (5) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to Disclaimer: Estimates of drilling locations. Slide 30 (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. Slide 31 (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 32 (1) Production for Q3 2026, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2026, 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, 2025, available on SEDAR+ at www.sedarplus.ca. Reported acreage in Canada includes Deep Basin and Montney acreage. (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 October 26, 2026. (4) Based on company estimates as at October 26, 2026. (5) Based on company estimates as of October 26, 2026, refer to Disclaimer: Multi-year estimates. (6) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. SLIDE NOTES
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55 55 Slide 33 (1) Vermilion has ownership of, or control and direction over, approximately 9% 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 34 (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 35 (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 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 36 (1) 2022-2025 reflects actual production. Company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 37 (1) Gas production for Q3 2026, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. (2) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. Germany acreage includes acreage associated with three concessions awarded in Q1 2026. For additional detail, refer to Vermilion press release dated April 7, 2026. Slide 38 (1) 2P gross reserves based on internal estimates as at December 9, 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 December 9, 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 December 9, 2025, and using flat €28/MWh pricing assumptions. (7) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. EFCF presented as of September 30, 2026. Slide 39 (1) Total proved plus probable conventional natural gas reserves at December 31, 2025, as evaluated by McDaniel, a qualified reserves evaluator, in a report dated March 3, 2026 with an effective date of December 31, 2025 (the “McDaniel Reserves Report”). Gross reserves reflect 64% working interest in Wisselshorst Z1a well. Slide 40 (1) 2022-2025 reflects actual production. Company 2026-2030 forecast as of October 26, 2026, refer to Disclaimer: Multi-year estimates. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 42 (1) Commodity price assumptions listed have been reflected throughout this presentation using the October 26, 2026 strip, unless otherwise noted. (2) FFO sensitivity based on company estimates and full year average reference prices as at October 26, 2026 . Hedged sensitivities include impact of out-of-the-money swaptions at current strip. Slide 43 (1) 2026 guidance reflects foreign exchange assumptions of CAD/USD 1.39, CAD/EUR 1.60, and CAD/AUD 0.98. 2027 guidance reflects foreign exchange assumptions of CAD/USD 1.39, CAD/EUR 1.57, and CAD/AUD 0.97. (2) General and administration expense exclusive of expected cash-settled equity based compensation of $0.15-0.20/boe. (3) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 44 (1) Company estimates as at October 30, 2026. Hedge percentages based on contract volumes as a percentage of net of royalty production and excludes basis swaps on North American natural gas. Hedge percentages include out-of-the-money swaptions at current strip. Slide 46 (1) European gas inventories as per AGSI (Gas Infrastructure Europe – AGSI). Slide 47 (1) Europe for the purposes of this discussion defined as EU27+UK. (2) Source: Refinitiv, November 2026, domestic production includes EU and UK production and direct pipeline supply from Norway, North Africa and Azerbaijan. (3) Source: Bloomberg, January 2026. Slide 49 (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 2025 data. Slide 50 (1) Producing and non-producing well count for 2022-2025 per Vermilion’s Annual Information Form for the respective year. 2026e and 2027e based on company estimates as at October 26, 2026. SLIDE NOTES