Slides
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NOVEMBER 2025 VERMILION ENERGY INVESTOR PRESENTATION GLOBAL GAS PRODUCER FREE CASH FLOW FOCUSED FINANCIAL DISCIPLINE
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WHY INVEST IN VERMILION? 2 (1) Free cash flow (“FCF”) 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. Dominant Deep Basin o Unlocking significant operational synergies drives efficient development 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 FCF(1) growth Montney Momentum o Free cash flow inflection following infrastructure build-out Repositioned Global Gas Portfolio o More efficient, long-life assets with direct exposure to premium-priced European gas
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VERMILION AT A GLANCE Market Summary VET Trading Price (November 5, 2025) $10.35 (TSX), US$7.34 (NYSE) Shares Outstanding (October 31, 2025) 153.3 MM Average Daily Trading Volume (shares) 0.8 MM (TSX), 1.2 MM (NYSE) Quarterly Dividend $0.13/share Capital Structure Market Capitalization $1.6 B Enterprise Value $3.0 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 Global gas producer with top decile realized gas price (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 and FFO Sensitivity slide). (2) Non-GAAP financial measure or ratio.
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2026 BUDGET 4 0 1 2 3 4 5 6 Category 1 Category 2 Category 3 Category 4 Chart Title Canada European Gas Assets Legacy Oil 67% 18% 15% E&D CAPITAL ALLOCATION(2) (1) Subject to approval by the Company’s Board of Directors. (2) Based on company estimates as at October 27, 2025. Allocating 85% of capital to repositioned global gas assets 0 1 2 3 4 5 6 Category 1 Category 2 Category 3 Category 4 Chart Title Canada European Gas Assets Legacy Oil 78% 14% 8% PRODUCTION WEIGHTING(2)• 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) $600 – 630MM 67% Canada 33% International 118 – 122 mboe/d 70% Natural Gas 30% Liquids
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UPDATED 2025 GUIDANCE & 2026 BUDGET 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 $0.15-0.20/boe. CATEGORY 2025 CURRENT(1) 2026 CURRENT(1) Production (boe/d) 119,500 118,000 - 122,000 % Natural gas 65% 70% E&D capital expenditures ($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% Significant unit cost reduction and improved capital efficiency
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REPOSITIONED GLOBAL GAS PORTFOLIO
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$7,400 $5,100 2024 2026e IMPROVED CAPITAL INTENSITY (CAPEX/FLOWING BOE) 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. Exiting five non-core regions and increasing operational scale in our core areas 85 120 2024 2026e HIGHER PRODUCTION (MBOE/D) $21.41 $14.65 2024 2026e LOWER UNIT COSTS (OPEX + G&A/BOE) REPOSITIONED PORTFOLIO: MORE EFFICIENT 40% increase in boe/d >30% decrease in cost structure 30% decrease in capex/flowing boe Streamlining operating regions and increasing operational scale in our core areas to achieve:
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8 REPOSITIONED PORTFOLIO: LONG-LIFE ASSETS • 4th largest Alberta Deep Basin producer • 1.1 million net acres of land, >700 drilling locations • Inventory to grow production to 80,000 boe/d, maintain for 15+ years Deep Basin (15+ years of inventory) • Contiguous 80,000 acres of land, only 14,000 acres developed to date • Developing Middle Montney, future upside in Upper and Lower Montney • Inventory to grow production to 28,000 boe/d, maintain for 15+ years Montney (15+ years of inventory) • 700,000 net acres of land, 3D seismic in place • Nine discrete structures identified to date, potential for ~30 total locations • Inventory to grow production to >10,000 boe/d, maintain for 10+ years Germany (10+ years of inventory) Building scale through long-duration assets with depth, quality and resilience
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AVERAGE (EXCL VET) = $2.63 $0 $1 $2 $3 $4 $5 $6 VET Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 REALIZED NATURAL GAS PRICE ($/MCF) Q2 2025 REALIZED NATURAL GAS PRICE(1) 9 TOP DECILE REALIZED GAS PRICE (1) Q2 2025 realized natural price per company public disclosures, excludes hedging. (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. AECO 43% Canadian Gas Hedges 34% Alliance 5% Europe 18% NATURAL GAS PRICE EXPOSURE(3) Canada 82% Europe 18% GAS PRODUCTION BY REGION(2)
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$0 $10 $20 $30 $40 $50 2017 2018 2019 2020 2021 2022 2023 2024 2025e* 2026e* TTF GAS PRICES (C$/MMBTU) HISTORICAL AND FORWARD PRICING OF EUROPEAN GAS DIRECT EXPOSURE TO EUROPEAN GAS PRICES * 2017 – 2024: Actual prices. 2025e-2026e forward price as at October 27, 2025 strip pricing (see Pricing and FFO Sensitivity slide). 10 European natural gas prices trade at a significant premium to North American benchmarks Euro Gas 2025 2026 % Hedged 56% 49% Average Floor $17 $13
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* 2015 – 2024: Actual prices. 2025e-2026e forward price as at October 27, 2025 strip pricing (see Pricing and FFO Sensitivity slide). CANADA LIQUIDS-RICH GAS ADVANTAGE 11 Liquids-rich gas improves project economics across Canadian gas assets Over the past decade, Vermilion’s Deep Basin and Montney assets have realized pricing more than double the average AECO price $0 $2 $4 $6 $8 $10 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025e* 2026e* REALIZED PRICE (C$/MCFE) REALIZED PRICING (DEEP BASIN + MONTNEY) Liquids-Rich Gas Realized Price ($/mcfe) Average AECO Price ($/mcf) (2015-2024)
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KEY ASSET OVERVIEW 12 12
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DOMINANT ALBERTA DEEP BASIN POSITION 13 Prominent Deep Basin producer, over 1.1 million net acres of land with 15+ years of inventory Source: Land information sourced from XI Technologies Asset Book.
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ROBUST DEEP BASIN ECONOMICS 14 Upper Cretaceous Spirit River Lower Mannville Lateral Length (m) 2,800 2,900 2,800 DCET Cost ($MM) $5.0 – 5.5 $6.0 – 6.5 $5.5 – 7.5 IP365 (boe/d)(1) 450 750 475 EUR (mboe)(2) 770 1,050 610 Liquids % of Reserves(3) 32% 14% 47% IRR(4) 85% 75% 50% Payout (years) 1.3 1.4 1.4 NPV10 ($MM) $6.9 $6.4 $4.6 (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) Estimated ultimate recovery based on 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 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. Upper CretaceousSpirit RiverLwr Mnvl/ Jurassic
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15 DEEP BASIN SYNERGIES 15 • Closed Westbrick acquisition in February 2025, integration progressing ahead of plan • Identified ~$200 million (NPV10)(1) of post-acquisition synergies to date, including: o Extending planned one-mile locations to two-miles o High-grading legacy Deep Basin inventory o Improved natural gas marketing opportunities o Infrastructure optimization across our expanded land base o Proving up additional drilling locations o Reducing service costs with larger development program o Favourable terms on processing fees (1) 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. NPV10 of synergies associated with the Westbrick acquisition are expected to be realized within approximately 10 years.
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MONTNEY OVERVIEW 16 Focused on development of a long-duration, significant free cash flow(1) asset 4-3 Battery8-33 Battery • Contiguous 80,000 acres of land with only 14,000 acres developed to date • Multi-year development program based on long reach wells • Owned and operated oil infrastructure, utilize third-party gas infrastructure • Diversified gas transportation via Alliance, NGTL and Westcoast pipelines • Improved capital efficiency with >30% reduction in DCET costs since the start of development (1) Free cash flow (“FCF”) 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.
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PREMIUM MONTNEY ACREAGE 17 A significant and contiguous premium acreage block in the oil window of the Montney Source: Land information sourced from EVA. * Vermilion has ownership of, or control and direction over, approximately 21% of the issued and outstanding common shares of Coelacanth Energy Inc. (“CEI.V”). For additional detail, refer to Vermilion press release dated February 28, 2024. VET owns ~21% of CEI.V* (~$90 million)
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MONTNEY COST OPTIMIZATION 18 $- $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 ~$100 million (NPV10)(2) in future development costs o DCET cost savings are repeatable • Water hub and disposal infrastructure reduces cost of water handling o Allows for more recycled water to be used (1) Total cost to drill, complete, equip and tie-in (“DCET”) per well. (2) Net present value (“NPV10”) is a supplementary financial measure which represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate. Management uses this measure to determine the current value of long-term cash flow, considering the time value of money over the period assessed. Continuous improvement drives efficiencies on our BC Montney assets
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BC Middle Montney Lateral Length (m) 3,000 DCET Cost ($MM) $8.5 IP365 (boe/d)(1) 950 EUR (mboe)(2) 1,500 Liquids % of Reserves(3) 38% IRR(4) 95% Payout (years) 1.1 NPV10 ($MM) $10.0 MONTNEY WELL ECONOMICS (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) Estimated ultimate recovery based on estimates provided by McDaniel & Associates Consultants Ltd (“McDaniel”). (3) Estimated liquids (light and medium crude oil, tight 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 AECO pricing assumptions. Reflects deep cut economics and January 1, 2027 BC natural gas royalty framework. 19
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MONTNEY PIVOTS TO FCF IN 2028 20 Outlook • Plan to reach 28,000 boe/d target production rate in 2028 and hold flat for 15+ years(1) • 2026–2028: Forecast ~40 wells to be drilled, $100MM of infrastructure spend over 3-year period • 2029+: Forecast ~8 wells per year to maintain production, no further infrastructure expansion anticipated • Target production rate generates $125-150MM of FCF(1,2) on lower capital requirements (1) Based on company estimates as at October 27, 2025, target production financial estimates reflect flat US$70 WTI / $3 AECO pricing assumptions. All future development subject to receiving necessary permits. (2) Free cash flow (“FCF”) 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. 0 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) Acquired Mica Montney asset, spun out CEI.V Commissioned 8-33 battery, achieved DCET of $9.6MM/well Ph. 2 expansion, achieved DCET of $8.5MM/well Free cash flow generation Ph. 3 expansion Build infrastructure and reduce DCET costs Third-party West Doe gas plant construction complete Achieve 28,000 boe/d target rate, transition to sustaining capital
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GERMANY EXPLORATION POTENTIAL 21 Vermilion has ~700,000 net acres of land and an experienced technical team with 70% success rate drilling similar zones in the Netherlands (1) Estimated ultimate recovery based on internal estimates as at May 7, 2025. (2) Estimated natural gas included in reserve estimates as a percentage of total reserves. (3) After tax IRR based on internal estimates as at May 7, 2025, using flat €35/MWh pricing assumptions. (4) Payout is the point in time at which all costs associated with a well are recovered from the cash flows of the well, calculated using after-tax cash flows beginning at the on-stream date. (5) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as at May 7, 2025 and using flat €35/MWh pricing assumptions. Deep Gas Exploration Type Well (1.0 Net) Vertical Depth (m) ~5,000 DCET Cost ($MM) $40 – 50 EUR (Bcf)(1) ~30 Gas % of Reserves(2) 100% IRR(3) 40% Payout (years)(4) 1.5 NPV10 ($MM)(5) $60 Identified 9 structures to date and have drilled 3; potential for up to 30 total locations with success
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GERMANY 2024 EXPLORATION SUCCESS 22 0 1,000 2,000 3,000 4,000 5,000 6,000 2025 2026 2027 2028 2029 2030 BOE/D (NET)(3) POTENTIAL PRODUCTION FROM CURRENT DISCOVERIES OSTERHEIDE WISSELSHORST FFO at current pricing (C$MM)(4) $15 $20 $30 $60 $90 $90 • 2024 program resulted in NPV10 of $150MM(1), 60 Bcf (net) of 2P reserves discovered(2) • Target production from 1.6 net wells represents ~25% of current European gas production • Annual FFO contribution of $90 million(4) at target production rate with minimal capital requirement (1) Net present value 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. (2) Total proved plus probable conventional natural gas reserves, as evaluated by McDaniel & Associated Consultants Ltd. (“McDaniel”), a qualified reserves evaluator. Net reserves reflect 64% working interest in Wisselshorst well. Refer to Vermilion’s Q1 2025 report for the three months ended March 31, 2025 for additional information. (3) Production based on Company estimates as at October 27, 2025, reflects 64% working interest in Wisselshorst well. (4) Current pricing based on Company 2025 estimates and 2025 full year average reference prices as at October 27, 2025: TTF $16.98/mmbtu; CAD/EUR 1.58. All future development subject to receiving necessary permits. Adding meaningful European gas production through exploration success
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WISSELSHORST EXPLORATION UPSIDE 23 • Wisselshorst (64% WI) is the largest structure Vermilion has discovered in Europe, estimated to contain 380 Bcf gas in place (240 Bcf net)(1) • Identified up to 6 follow-up locations offsetting discovery well(2) o Plan to drill two follow-up locations in early 2027 • Potential to add meaningful production and reserves (1) Represents management’s estimate of the mid-point of the distribution of potentially discovered original-gas-in-place volume. (2) All future development subject to receiving necessary permits. (3) Total proved plus probable conventional natural gas reserves, as evaluated by McDaniel & Associated Consultants Ltd. (“McDaniel”), a qualified reserves evaluator. Net reserves reflect 64% working interest in Wisselshorst well. Refer to Vermilion’s Q1 2025 report for the three months ended March 31, 2025 for additional information. Graphic of Wisselshorst structure represents management’s interpretation of subsurface attributes and is not final. Discovery well 2P reserves 68 Bcf (44 Bcf net)(3)
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CAPITAL ALLOCATION 24
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(1) Non-GAAP financial measure, forward looking measure or ratio. Excess FCF defined as free cash flow less a deduction for asset retirement obligations settled and capital lease payments, which are ongoing costs associated with running our business, and more accurately reflects the free cash available to return to shareholders. (2) Shares purchased to October 31, 2025. CAPITAL ALLOCATION PRIORITIES 25 Plan to increase return of capital target to 50% when net debt reaches an appropriate level 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 less than 1.0x o Allocating 60% of EFCF to debt repayment o $1.1B of available liquidity o Repositioned global gas portfolio o Depth and quality of inventory o Long-duration, high- quality asset base o 40% return of EFCF(1) o Five consecutive years of dividend increases o Repurchased 20 million shares (2) (12% of Q2/22 shares outstanding) o Focus on increased operational scale in core areas o Committed to deep- value international acquisitions
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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 FINANCIAL LIQUIDITY 26 Committed to returning to 1.0x leverage (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 and 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. 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
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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 FFO & CAPITAL ALLOCATION 27 Improving business with lower cost structure and improved capital efficiency (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, available on SEDAR+ at www.sedarplus.ca. Production for 2024 reflects actual production per annual report. Estimates for 2025e and 2026e, including net debt to trailing 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.
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0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total PERCENTAGE OF PRODUCTION HEDGED (%)(1) 2025 WTI BRENT NATURAL GAS WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/mmbtu) N.A. Gas (C$/mmbtu) Avg. Sold Call $94.58 N/A $20.82 $3.93 Avg. Bought Put $84.08 N/A $13.61 $2.73 Avg. Swap $100.58 $105.15 $20.28 $2.84 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total PERCENTAGE OF PRODUCTION HEDGED (%)(1) 2026 WTI BRENT NATURAL GAS (1) Company estimates as at October 28, 2025, includes impacts of Westbrick acquisition, which closed February 26, 2025 and sales of Saskatchewan and United States assets, which closed in July 2025. Hedge percentages based on contract volumes as a percentage of net of royalty production and excludes basis swaps on North American natural gas. STRONG HEDGE POSITION 28 Visit vermilionenergy.com/Invest-with-us/hedging for more detailed hedging information WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/mmbtu) N.A. Gas (C$/mmbtu) Avg. Sold Call $96.70 N/A $18.93 $4.46 Avg. Bought Put $85.83 N/A $12.01 $3.11 Avg. Swap $87.46 N/A $15.68 $3.33
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COMPOUNDING RETURN OF CAPITAL 29 Decreasing share count with ratable dividend increases enhances value per share $0.00 $0.20 $0.40 $0.60 $0.80 2022 2023 2024 2025 2026e DIVIDENDS PER SHARE(1) ANNUAL DIVIDEND PER SHARE 145 150 155 160 165 2022 2023 2024 2025e 2026e SHARE COUNT (MM)(2) SHARE COUNT Announced 2026 dividend payout is <10% of FFO (1) Subject to approval by the Company’s Board of Directors. (2) 2022 – 2024 actual share count. 2025e-2026e based on company estimates and full year average reference prices as at October 27, 2025 (see Pricing and FFO Sensitivity slide).
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ADDITIONAL INFORMATION 30
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PRICING & FFO SENSITIVITY 31 (1) Commodity price assumptions listed have been reflected throughout this presentation using the October 27, 2025 strip, unless otherwise noted. (2) Annual FFO sensitivity based on company 2026 estimates, with 2026 full year average reference prices as at October 27, 2025. 2026 FFO SENSITIVITY (C$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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CANADA 32 MONTNEY • Targeting liquids-rich gas in the Peace River Arch straddling the AB and BC border • ~80,000 net acres of Montney rights in the Mica area in the Peace River Arch • Q3 2025 production = 85,698 boe/d (29% liquids) (Continuing operations) High-graded portfolio of long duration, liquids-rich gas assets with strong rates of return DEEP BASIN • Targeting light oil and condensate-rich natural gas • ~1.1 million net acres in West Pembina targeting the Upper Cretaceous, Spirit River, and Lower Mannville/Jurassic zones
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• 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 33 Over 70% of Vermilion’s Canadian production(2) underpinned by natural gas tailwinds CANADIAN GAS FUNDAMENTALS 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 (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 and FFO Sensitivity slide).
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EUROPEAN GAS 34 Premium-priced European gas production drives top decile realized gas price IRELAND • 56.5% operated interest in the Corrib Natural Gas Project • Corrib represents 100% of Ireland’s domestic gas production • Q3 2025 production = 8,139 boe/d (100% gas) CROATIA • Focused on under-invested basins prospective for both oil and natural gas that can benefit from new technology • ~230,000 net acres across two licenses in Croatia prospective for natural gas and oil • Q3 2025 production = 2,189 boe/d (100% gas) NETHERLANDS • #2 onshore gas producer • ~700,000 net acres of undeveloped land • Q3 2025 production = 3,381 boe/d (99% gas) GERMANY • ~700,000 net acres of undeveloped land • Q3 2025 production = 6,086 boe/d (72% gas)
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EUROPEAN GAS OPERATING NETBACKS (1) Based on company 2025 estimates and 2025 full year average reference prices as at October 27, 2025 (see Pricing and FFO Sensitivity slide), operating netback excluding hedging. 35 European gas assets generate strong netbacks due to direct exposure to premium pricing $0 $20 $40 $60 $80 $100 Ireland Netherlands Germany $/ BOE(1) VERMILION 2025E OPERATING NETBACK
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(20) - 20 40 60 80BCF/D EUROPEAN SUPPLY/DEMAND BALANCE HISTORY** Domestic production** Russia (incl. Turkey transit) LNG Storage draw/injection Consumption EUROPEAN GAS FUNDAMENTALS * Europe for the purposes of this discussion defined as EU27+UK ** Source: Refinitiv, November 2025, domestic production includes EU and UK production and direct pipeline supply from Norway, North Africa and Azerbaijan. *** Source: Bloomberg, May 2025 36 Strong LNG fundamentals point to elevated European gas prices • Europe* 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*** Winter 2023 demand down ~10 Bcf/d due to 2nd warmest winter, government policy, and extremely high prices
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LEGACY OIL ASSETS 37 Low decline oil assets generating free cash flow 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 • 100% operated interest in Wandoo, an offshore oil field approximately 80 km N.W. off the coast of Australia (55m water depth) • Horizontal well development with 23 producing wellbores and five dual lateral sidetracks tied into two platforms • New wells drilled every 2-4 years • Q3 2025 production = 3,693 boe/d (100% oil) • Wandoo crude currently sells at ~US$10/bbl premium to Dated Brent
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• Achieved 16% reduction in Scope 1 emissions intensity since 2019(1); now focused on reducing Scope 1+2 emissions intensity by 25-30% by 2030 • Asset high-grading and ARO spending has reduced well count by 50% since 2022 Environment • Geothermal energy for Parentis greenhouse supports 220 direct jobs • Geothermal energy for La-Teste eco-neighborhood reduces heating costs, avoids 250 tonnes/year of CO2(2)Social • Board diversity, including 30% female members • Executive and employee compensation linked to ESG metricsGovernance ENVIRONMENT, SOCIAL AND GOVERNANCE 38 Vermilion’s Purpose: To responsibly produce essential energy while delivering long-term value to our people, shareholders, customers, partners and communities (1) Emissions calculated in general accordance with GHG Protocol and IPCC guidance; reported intensities are based on operated throughput; Scope 1 and 2 emissions externally verified (limited assurance) in accordance with ISO 14064-3 standard. (2) Based on 2024 data. 0.015 0.020 0.025 0.030 2019 2020 2021 2022 2023 2024 EMISSIONS INTENSITY TREND Scope 1&2 tCO2e per BOE Read more at vermilionenergy.com/sustainability
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- 1,000 2,000 3,000 4,000 5,000 6,000 2022 2023 2024 2025e WELL COUNT (NET)(1) TOTAL WELL COUNT PRODUCING WELLS NON-PRODUCING WELLS ARO settled ($MM) $38 $57 $55 $60 (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. REDUCED WELL COUNT 39 Reducing well count and asset retirement obligations while growing production • 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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SUSTAINABILITY PROJECTS 40 Enhancing economic opportunities through innovation and partnerships 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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ADVISORY 41 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: well production timing and expected production rates and financial returns, including half-cycle internal rate of return, therefrom; wells expected to be drilled in 2025, 2026 and beyond; exploration and development plans and the timing thereof; petroleum and natural gas sales, netbacks, and the expectation of generating strong free cash flow therefrom; the effect of changes in crude oil and natural gas prices, and changes in exchange and inflation rates; statements regarding Vermilion’s hedging program, its plans to add to its hedging positions and the anticipated impact of Vermilion’s hedging program on the economics of the Westbrick Acquisition and other projects and free cash flows; capital expenditures including Vermilion’s ability to fund such expenditures in 2025 and future periods; Vermilion's debt capacity and ability to manage debt and leverage ratios and raise additional debt; the anticipated timing of the close of the Saskatchewan and United States assets, and the anticipated impact on production, capital expenditures, cash flows and debt levels therefrom; future production levels and the timing thereof, including Vermilion's 2025 guidance, and rates of average annual production 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 Vermilion’s normal course issuer bid; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance, including the ability of Vermilion to realize synergies from the Westbrick Acquisition; significant declines in production or sales volumes due to unforeseen circumstances; statements regarding the growth and size of Vermilion's future project inventory, including the number of future drilling locations expected to be available; acquisition and disposition plans and the economics and timing thereof; operating and other expenses, including the payment and amount of future dividends; 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: that all closing conditions to the United States asset sale will be satisfied and the closing of the transaction will occur as anticipated; that all closing conditions to the Saskatchewan asset sale will be satisfied and the closing of the transaction will occur as anticipated, including the ability of the buyer’s ability to obtain financing; 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 contained in this presentation are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, 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”, “FFO per share”, “net debt”, “net debt-to-FFO”, “net debt-to-trailing FFO”, “E&D capital expenditures”, “free cash flow”, “FCF”, “excess free cash flow”, “ECFC” and “EFCF 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 the MD&A 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 the AIF. 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 include “reserve life index” and “decline rates”. 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. Certain natural gas volumes have been converted on the basis of six thousand cubic feet of gas to one barrel equivalent 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.