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Vermilion Energy — Vermilion Energy Investor Day 2025 (company IR deck)
Vermilion Energy (VET) · 80 slides · Filed Oct 29, 2026
Every slide of this earnings presentation, with the text as published. Open the original deck ↗ · All VET deck slides
Slide 1 — VERMILION ENERGY
VERMILION ENERGY INVESTOR DAY 2025 GLOBAL GAS PRODUCER FREE CASH FLOW FOCUSED FINANCIAL DISCIPLINE
Slide 2 — AGENDA
2 AGENDA 2 1 Introduction 2 Corporate Overview 3 Asset Quality & Duration 4 European Gas Assets – Germany & Netherlands 5 Liquids-Rich Gas Assets – Deep Basin & Montney 6 Portfolio Management 7 Outlook & Capital Allocation 8 Summary & Key Takeaways
Slide 3 — GLOBAL GAS PRODUCER: FREE CASH FLOW FOCUSED
3 GLOBAL GAS PRODUCER: FREE CASH FLOW FOCUSED Allocating capital to assets that will drive material Excess Free Cash Flow growth 3 Deep Basin Liquids-Rich Gas Montney Liquids-Rich Gas European Gas Legacy Assets Excess Free Cash Flow • Large, established land and production base with infrastructure for growth • Long duration of highly economic inventory(1) drives strong Excess Free Cash Flow (“EFCF”)(2) generation • Infrastructure build-out nearly complete, enabling significant pivot to EFCF • Depth and quality of inventory support sustained asset profitability • New discoveries in Germany, positioned for European gas and EFCF growth • Leveraging 20+ years of exploration success in the Netherlands, delivering premium-price European gas • Ireland, France and Australia assets delivered significant EFCF over 25+ years • Focused on harvesting EFCF from low-decline assets via operational excellence and product diversification ~85% of 2026-2030 Exploration & Development (“E&D”) capital expenditures(3,4) planned to be allocated to Global Gas assets
Slide 4 — VERMILION AT A GLANCE
4 VERMILION AT A GLANCE Global gas producer with top decile realized gas price 4 Market Summary VET Trading Price (Dec. 9, 2025) $12.46 (TSX), US$8.99 (NYSE) Shares Outstanding (Nov. 30, 2025) 153.1 MM Average Daily Trading Volume (shares) 0.8 MM (TSX), 1.3 MM (NYSE) Quarterly Dividend (2026 planned) $0.135/share Capital Structure Market Capitalization $1.9 B Enterprise Value $3.3 B Year-End 2025 Net Debt(1) $1.4 B Year-End 2025 Net Debt-to-FFO Ratio(1) 1.4 x 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(2) $630 – 640MM $600 – 630MM All financial data is reported in Canadian dollars, unless otherwise stated Commodity Price Forecast(3) TTF ($/MMBtu) $13.00 NBP ($/MMBtu) $13.00 AECO ($/GJ) $ 3.50 Henry Hub (US$/MMBtu) $ 4.00 Brent (US$/bbl) $74.00 WTI (US$/bbl) $70.00 MSW = WTI less (US$/bbl) $ 4.00 CAD/USD 1.38 CAD/EUR 1.60 CAD/AUD 0.90 EUR/GBP 1.13
Slide 5 — PRESENTING EXECUTIVES
5 Lars Glemser Vice President & Chief Financial Officer Randy McQuaig Vice President North America Darcy Kerwin Vice President International & HSE Geoff MacDonald Vice President Geosciences PRESENTING EXECUTIVES Dion Hatcher President & Chief Executive Officer Lara Conrad Vice President Business Development 5
Slide 6 — CORPORATE OVERVIEW
CORPORATE OVERVIEW
Slide 7 — EXECUTIVE LEADERSHIP: CEO
7 EXECUTIVE LEADERSHIP: CEO 7 Dion Hatcher President & Chief Executive Officer 30+ Years of Experience / 20 Years Vermilion Experience Vermilion o President o VP, North America o VP, Canada o Director, Alberta Deep Basin o Development Manager, Canada o Exploitation Manager, France Prior Experience o Various engineering, operations, exploitation and project management roles with Chevron
Slide 8 — OUTSIZED EXCESS FREE CASH FLOW GROWTH
8 OUTSIZED EXCESS FREE CASH FLOW GROWTH 8 0.20 0.22 0.24 0.26 0.28 0.30 0.32 0.34 0.36 2026E 2028E PRODUCTION / SHARE(1,2) $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 2026E 2028E EXCESS FCF / SHARE(1,3) STRIP PRICING INVESTOR DAY PRICING Large Resource Depth of inventory with repeatable economics Operational Excellence Continuous improvement driving increased profitability Per Share Value Growing EFCF(4) per share supports return of capital
Slide 9 — WHAT VERMILION OFFERS INVESTORS
9 Montney Momentum o Excess free cash flow(1) inflection following infrastructure build-out WHAT VERMILION OFFERS INVESTORS 9 Dominant Deep Basin o Depth and quality of inventory with infrastructure in place drives profitable growth Germany Production Growth o Positioned for organic growth with production from new discoveries, upside from additional prospects Return of Capital o Long-term return of capital underpinned by excess free cash flow growth Repositioned Global Gas Portfolio o Profitable, long-life assets delivering top decile realized gas price
Slide 10 — REPOSITIONED PORTFOLIO: KEY GROWTH ASSETS
10 25+ Years Drilling Inventory(1) High-return, multi-zone development with existing infrastructure to support production growth Generating EFCF(2) through efficient development 20+ Years Drilling Inventory Lower capital and unit OPEX, progressing infrastructure to support long term liquids-rich production Pivoting to EFCF following infrastructure build-out 10+ Years Drilling Inventory Lowest cost international gas exposure through material deep gas exploration prospects Growing EFCF with Deep Gas Exploration program REPOSITIONED PORTFOLIO: KEY GROWTH ASSETS Deep Basin Montney Germany Enhanced profitability through long-life assets and improved capital efficiency 10
Slide 11 — DIRECT GLOBAL GAS PRODUCTION
11 … vs. how Vermilion does it DIRECT GLOBAL GAS PRODUCTION 11 Liquefaction Transport Regasification $15/MMBtu Realized Price(2) Exceeds North American Benchmarks Lowest Cost to Market Attractive Development Cost Metrics Without LNG Cost Structure ~100 mmcf/d of Premium-Priced Domestic European Gas Exposure(1) How they do it… Wisselshorst drill site
Slide 12 — REPOSITIONED PORTFOLIO: IMPACT 2026
12 Streamlining operating regions and increasing operational scale in our core areas 12 REPOSITIONED PORTFOLIO: IMPACT 2026 $7,400 $5,100 2024 2026e IMPROVED CAPITAL INTENSITY (CAPEX/FLOWING BOE) 85 120 2024 2026e HIGHER PRODUCTION (MBOE/D) $21.41 $14.65 2024 2026e LOWER UNIT COSTS (OPEX + G&A/BOE) >40% increase in boe/d >30% decrease in cost structure >30% decrease in capex/flowing boe
Slide 13 — REPOSITIONED PORTFOLIO: IMPACT 2028+
13 Building operational scale in quality global gas assets with resilience to drive long-term shareholder value 13 Repositioning the portfolio… Deep Basin acreage and production Tripled Deep Basin inventory quality and duration High-Graded Saskatchewan and USA oil assets Divested Montney excess free cash flow(1) inflection Approaching Germany excess free cash flow growth Incoming Exit of Croatia, Hungary, and Slovakia In-Flight … to significantly grow Excess Free Cash Flow REPOSITIONED PORTFOLIO: IMPACT 2028+ Moderating Base Decline Rate Long-Duration Assets Improved Capital Efficiency
Slide 14 — FIVE-YEAR OUTLOOK: GROWING EFCF
14 54-60% 21-23% 14-16% 5-7% 2030E PRODUCTION(2) Deep Basin Montney European Gas Legacy Oil 65% 13% 14% 8% 2026E PRODUCTION(1) Deep Basin Montney European Gas Legacy Oil ~130 mboe/d ~40% increase in production per share(5) ~120 mboe/d FIVE-YEAR OUTLOOK: GROWING EFCF $600-630 million Annual capex(2,3) $1.7 billion Cumulative EFCF(2,4) 8-10% Annual production per share growth(2) Robust five-year outlook drives outsized Excess Free Cash Flow growth 14
Slide 15 — EXCESS FREE CASH FLOW GROWTH
15 $0 $100 $200 $300 $400 $500 2026e (Strip) EFCF Inflection 2028+ Run Rate EXCESS FREE CASH FLOW ($MM) 2026-2028 EFCF OUTLOOK(1,3) EFCF OPERATIONAL EXCELLENCE PRICING VS. STRIP Key growth assets drive Excess Free Cash Flow growth in 2028 and beyond 15 EXCESS FREE CASH FLOW GROWTH How Do We Get There?(2,3) Germany Deep Gas Drilling Program (2026-2028) Wisselshorst online (mid-2026) and debottleneck (2027-2028) Additional drilling (2027) and production brought online (2H 2028) Montney Build-Out (2026-2028) Complete infrastructure and start-up 3rd party deep cut gas plant Drill ~40 wells to reach target rate, then ~8 wells/year to maintain Deep Basin Drilling Program (2026-2028) Drill ~40 wells per year, utilize existing infrastructure Australia Drilling Program (2027) Drill two wells, adding high-value production and extending field life Structural Lift in EFCF Growing European gas and Montney/Deep Basin liquids-rich gas
Slide 16 — ASSET QUALITY &
ASSET QUALITY & DURATION
Slide 17 — EXECUTIVE LEADERSHIP: GEOSCIENCES
17 EXECUTIVE LEADERSHIP: GEOSCIENCES 17 Geoff MacDonald Vice President Geosciences 20+ Years of Experience / 6 Years Vermilion Experience Vermilion o Chief Geoscientist, Canada Prior Experience o VP, Exploration – Velvet Energy o Various senior technical, business development, and leadership roles at Encana, Enerplus and EOG Resources
Slide 18 — BETTER WELLS THROUGH TECHNICAL RIGOR
18 Talented people + quality rock + robust workflows = better wells IP (m/s*g/cc) Vp/Vs BETTER WELLS THROUGH TECHNICAL RIGOR 18 Geology o We work with the actual rock, every day Geophysics o We employ in-house and 3rd party expertise on every shoot Geomechanics o We build robust target and completion models for every well Geochemistry, Hydrodynamics, Petrophysics o We integrate petroleum system attributes into every workflow
Slide 19 — VERMILION’S CANADIAN POSITION
19 VERMILION’S CANADIAN POSITION 19 Vermilion has been a pioneer in developing liquids-rich gas zones in Canada since the ‘90s
Slide 20 — DEEP BASIN INVENTORY DEPTH
20 DEEP BASIN INVENTORY DEPTH Upper Cretaceous Spirit River 20 Inventory depth through areal extent and stacked zones – the Deep Basin delivers continuous opportunity 501 704 257 DEEP BASIN INVENTORY JURASSIC/LWR CRETACEOUS SPIRIT RIVER UPPER CRETACEOUS 25+ Years . of Inventory(1) Jurassic/Lwr Cretaceous INVENTORY FAIRWAYS For illustrative purposes only
Slide 21 — MICA MONTNEY INVENTORY DEPTH
21 AB BC AB BC 21 Lower well cost, higher liquids yield, enhanced deliverability – Mica is a Montney sweet spot MICA MONTNEY INVENTORY DEPTH 190 58 MONTNEY INVENTORY D1 UPPER MONTNEY 20+ Years . of Inventory(1) MIDDLE MONTNEY ATTRIBUTES Thickness Liquids Distribution For illustrative purposes only
Slide 22 — GERMANY & NETHERLANDS GAS
22 GERMANY & NETHERLANDS GAS 22 A significant position covered by 3D seismic – a massive resource with abundant inventory
Slide 23 — CORE ACREAGE OFFSETTING LARGE DISCOVERIES
23 23 CORE ACREAGE OFFSETTING LARGE DISCOVERIES Small “e” exploration – finding gas where gas has been found Rotliegend, Zechstein, and Carboniferous acreage in the core of the Permian North German Basin Source: Petroleum Geological Atlas of the Southern Permian Basin Areas (2010), LBEG - “Erdgastabellen 1949-2024”, ESRI
Slide 24 — A STEP CHANGE IN OUR EXPLORATION PORTFOLIO
24 9 Last 30 wells Next 30 Wells + PROSPECTS: HISTORIC & FUTURE 9 Bcf avg per well(1) 24 A STEP CHANGE IN OUR EXPLORATION PORTFOLIO Vermilion’s future prospectivity is significantly larger than our past success Developing larger exploration targets in Germany and the Netherlands provides better risk-adjusted outcomes Track Record of Exploration Success o Since 2004, 70% of Vermilion’s exploration wells have found gas Future Portfolio Improvements o Larger German prospects provide follow-up drilling opportunities
Slide 25 — INVENTORY FOR THE FUTURE
25 16% GERMANY & NETHERLANDS GAS INVENTORY FOR THE FUTURE 25 Vermilion’s growth assets have decades of development ahead that is not reflected in our reserves ~31 . Accumulations 7% 14% DEEP BASIN ~1,450 . Locations(1) 20% BOOKED LOCATIONS EVALUATION LOCATIONS UNBOOKED LOCATIONS 29% MONTNEY ~250 . Locations
Slide 26 — EUROPEAN GAS ASSETS
EUROPEAN GAS ASSETS GERMANY & NETHERLANDS
Slide 27 — EXECUTIVE LEADERSHIP: INTERNATIONAL
27 EXECUTIVE LEADERSHIP: INTERNATIONAL 27 Darcy Kerwin Vice President International & HSE 25+ Years of Experience / 20 Years Vermilion Experience Vermilion o VP, Strategic Planning o Managing Director, Ireland o Managing Director, France o Facilities Engineering Manager, Canada o General Manager, Australia Prior Experience o Various engineering and project management roles with Chevron in Canada, Houston and Nigeria
Slide 28 — EUROPEAN GAS ASSETS: GERMANY & NETHERLANDS
28 EUROPEAN GAS ASSETS: GERMANY & NETHERLANDS 28 Overview Key Statistics Gas Production: 46 mmcf/d (57% Germany / 43% Netherlands)(1) Acreage: 1.45 million acres (50% Germany / 50 % Netherlands)(2) History Proven track record of development with 30+ exploration wells at 70% success rate over 20 years Significant undeveloped land base in Germany from 2015 farm-in agreement, 3D seismic coverage throughout Outlook Building out Germany infrastructure and developing material gas discovery; exploration upside from long runway of prospects Significant undeveloped land base with long runway of high-return projects across Germany and Netherlands Source: ESRI, SRTM Worldwide Elevation Data
Slide 29 — TRACK RECORD OF EXECUTION IN EUROPE
29 TRACK RECORD OF EXECUTION IN EUROPE Leveraging decades of experience to unlock significant value from conventional assets 29 0 50 100 150 200 250 300 350 2P RESERVES / PRODUCTION (BCFE) NETHERLANDS ORGANIC RESERVE ADDITIONS ACQUIRED RESERVES (2004-2024) 2024 RESERVES PRODUCTION (2004-2024) European Exploration Expertise Netherlands ~30 wells over 20 years, ~70% success rate Significant reserve additions, 180 Bcf since 2004(1) Pivoting back to larger pool development Germany Deep gas exploration targeting 30+ Bcf pools Large prospects, potential for additional drilling Recent wells (1.6 net) are >20% of 2024 reserves(2) Future Development 3D seismic and strong technical team in place Receiving permits, working with governments 10+ years of identified development prospects(3)
Slide 30 — SIZE OF THE PRIZE
30 Discovery Well 2P Reserves 68 Bcf Property Gross(1) 44 Bcf Gross to Vermilion SIZE OF THE PRIZE Vermilion’s largest discovery in over a decade is the latest significant discovery in the North German Basin 30 Source: Petroleum Geological Atlas of the Southern Permian Basin Areas (2010), LBEG - “Erdgastabellen 1949-2024”, ESRI NORTH GERMAN BASIN
Slide 31 — PATHWAY TO ORGANIC GAS GROWTH
31 PATHWAY TO ORGANIC GAS GROWTH 31 Successful exploration and development in Germany has the potential to replace all European gas reserves - 50 100 150 200 250 300 350 2P RESERVES (BCF)(1) 2024 EUROPEAN GAS RESERVES Germany Netherlands Ireland CEE Organic upside in Germany Targeting 30+ Bcf prospects Progressing Bommelsen development Up to 30 locations identified
Slide 32 — IMPACTFUL GERMANY WELLS
32 IMPACTFUL GERMANY WELLS Germany exploration program provides meaningful long-duration cash flows 32 Germany (2.0 Net) Deep Basin (12.0 Net) DCET Cost ($MM)(1) $80 – 100 $60 – 90 EUR (mboe)(2) ~10,000 ~10,000 NPV10 ($MM)(3) $120 $70 – 100 Lifetime Payout(4) 4x 3x TWO (2.0 NET) GERMANY DEEP GAS WELLS TWELVE DEEP BASIN LIQUIDS-RICH GAS WELLS Our Germany drilling program is comparable to running a drilling rig for one year in the Deep Basin, with wells that have higher NPV and pay out 4 times
Slide 33 — GERMANY GAS: OPERATIONAL EXCELLENCE
33 6 12 18 Discovery Well Additional Wells (Avg.) MONTHS TO PROD.(2) ACCELERATED FOLLOW-UP DEVELOPMENT $20 $40 $60 Discovery Well Additional Wells (Avg.) DCET ($000’S)(1) LOWER COST FOLLOW-UP DEVELOPMENT GERMANY GAS: OPERATIONAL EXCELLENCE 33 Follow-up development benefits from improving cost structure and accelerated timelines Reducing capital cost o Using high-performance drilling rig, drilling two wells back-to-back, utilizing existing infrastructure Improving cycle times o Optimize procurement of long-lead equipment, improved permitting times for additional wells
Slide 34 — GERMANY INFRASTRUCTURE
34 GERMANY INFRASTRUCTURE Osterheide surface facility What’s in place… Osterheide Facility and Pipeline Tie-In Currently On-Stream Wisselshorst Production Pipeline Under Construction Wisselshorst Metering Station Under Construction … and what’s to come Wisselshorst Gas Processing Facility Under Fabrication Wisselshorst Capacity Increases Permitting Bommelsen Exploration Wellsites Permitting 34 Trench for Wisselshorst pipeline
Slide 35 — GERMANY OUTLOOK: ORGANIC GROWTH
35 GERMANY OUTLOOK: ORGANIC GROWTH - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2023 2024 2025 2026 2027 2028 2029 2030+ BOE/D (NET) DEEP GAS PROGRAM PRODUCTION TIMELINE(1) Legacy Germany Deep Gas Success To-Date (1.6 net) Additional Wells Germany exploration program offers low-cost international exposure and long-duration EFCF 35 2024-2026 Success & First Production o Osterheide (OSTH) and Wisselshorst (WSSH) discoveries o OSTH online Q1 2025 at restricted rates o Initial WSSH infrastructure build-out o WSSH target on-stream date mid-2026 2027-2028 Follow-up Activity o Drill two (1.3 net) additional wells o Infrastructure debottlenecking to accelerate production and EFCF(2) Self-funded Growth o Full contribution from 2.9 net wells drives organic Euro Gas growth, EFCF and additional capital allocation optionality Excess free cash flow generation Drilling and facility investment
Slide 36 — POSITIONED FOR EUROPEAN GAS GROWTH
36 36 POSITIONED FOR EUROPEAN GAS GROWTH ~105 mmcf/d European Gas Production in 2025(1) ~110 mmcf/d European Gas Production by 2030(1) ~100 mmcf/d European Gas Production in 2020 Ireland – Moderating Decline Mature asset; decline moderating (~14%/year) 2026 – planned 32-day turnaround, 2027 production in-line with 2026 ~2,000 boe/d decline (2026 - 2030)(1) More than offset by Germany growth Wisselshorst exploration success replaces production and reserves ~5,000 boe/d of organic growth (2026 - 2030)(1)
Slide 37 — LIQUIDS-RICH GAS ASSETS
LIQUIDS-RICH GAS ASSETS DEEP BASIN
Slide 38 — EXECUTIVE LEADERSHIP: CANADA
38 EXECUTIVE LEADERSHIP: CANADA Randy McQuaig Vice President North America 38 30+ Years of Experience / 12 Years Vermilion Experience Vermilion o Director, Canadian Assets o Manager, Saskatchewan o Business Development Prior Experience o Founding member and President & CEO of several successful junior oil and gas companies
Slide 39 — CANADIAN LIQUIDS-RICH GAS FOCUS
39 CANADIAN LIQUIDS-RICH GAS FOCUS Source: Peters & Co. Limited Fall 2025 Energy Overview. Estimates based on ~US$65.00/B WTI, ~US$4.00/Mcf NYMEX, ~$3.25/Mcf AECO. 39 Vermilion’s Canadian assets are focused in two of the top four North American gas plays - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Montney Oil Marcellus Montney Liquids Rich Deep Basin Duvernay Kaybob Montney Dry Gas Permian Delaware Haynesville Permian Midland PAYOUT (YEARS)(1) HALF-CYCLE PAYOUT PERIOD Canadian Plays (Median 1.1 Years) U.S. Plays (Median 1.4 Years)
Slide 40 — DEEP BASIN: OVERVIEW
40 DEEP BASIN: OVERVIEW Overview Key Statistics Production: 70,000 boe/d (Q3 2025)(1) Acreage: 1.1 million net acres(2) Infrastructure: >100,000 boe/d nameplate capacity(3) History Vermilion has operated in the Deep Basin since 1995 and has grown to be one of the largest producers in this prolific basin Recent acquisition significantly increased size and quality of our Deep Basin position 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 40
Slide 41 — DOMINANT DEEP BASIN POSITION
41 DOMINANT DEEP BASIN POSITION Vermilion’s extensive Deep Basin asset offers robust well results across the asset base and through the stack 41 Notikewin IP30 2,700 boe/d 22% liquids Wilrich IP30 2,600 boe/d 14% liquids Rock Creek IP30 720 boe/d 78% liquids Ellerslie IP30 650 boe/d 49% liquids Notikewin IP30 1,570 boe/d 31% liquids Vermilion’s Deep Basin Attributes Top five Deep Basin producer by volume Top five Deep Basin producer by land base Higher liquids weighting than peers Recent well results exceeding expectations Contiguous acreage with high WI% Significant infrastructure capacity facilitates growth LAND LEGEND VERMILION LAND WELL LEGEND VERMILION 2025 DRILLED WELLS Ellerslie IP30(1) 870 boe/d 55% liquids
Slide 42 — MULTI-ZONE DEEP BASIN INVENTORY
42 MULTI-ZONE DEEP BASIN INVENTORY Decades of stacked zone inventory supported by existing infrastructure 42 34% 48% 18% DEEP BASIN INVENTORY JURASSIC/LWR CRETACEOUS SPIRIT RIVER UPPER CRETACEOUS ~1,450 . Locations Identified Stacked Zone Optionality o Utilizing existing surface infrastructure improves capital efficiency Excess Free Cash Flow Generation o Strong returns and minimal infrastructure spend maximizes EFCF(3) Infrastructure Availability o Significant available capacity on existing infrastructure supports growth Decades of Inventory o Current inventory(1) supports 70,000 - 90,000 boe/d(2) production for 25+ years
Slide 43 — PROFITABLE GROWTH: OPERATIONAL EXCELLENCE
43 $1,000 $1,500 $2,000 $2,500 $3,000 2023 2024 2025 $ / HORIZONTAL METRE(1) DRILLING COST – VET VS. PEERS DEEP BASIN PEERS VERMILION PROFITABLE GROWTH: OPERATIONAL EXCELLENCE Culture of continuous improvement converts operational wins into material cost savings 43 Shallower target depths Consistent three-rig drilling program Longer laterals at a lower per-metre cost
Slide 44 — PROFITABLE GROWTH: STRONGER WELL RESULTS
44 Vermilion’s H2/25 drilling program has produced some of the best wells in Alberta 0 200 400 600 800 1,000 1,200 0 6 12 18 24 30 BOE/D(1) PRODUCTION MONTH DEEP BASIN PRODUCTION BY DRILL YEAR 2022-2025 AVG (39 TOTAL) 2026 BUDGET (43 TOTAL) POST-CLOSE 2025 IP30 (13 TOTAL) PROFITABLE GROWTH: STRONGER WELL RESULTS Current drilling program results are significantly above historical averages, adding confidence to outlook 44
Slide 45 — PROFITABLE GROWTH: ECONOMIC INVENTORY
45 PROFITABLE GROWTH: ECONOMIC INVENTORY Competitive well economics + minimal infrastructure requirements = profitable full-cycle development 45 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 Longer Laterals Improve Economics o ~30% longer wells than peers offset higher cost Significantly Higher Liquids % o Liquids-rich gas enhances economics and provides natural diversification Vermilion’s Efficient Deep Basin Asset Vermilion delivers competitive DCET costs and production rates with significantly higher liquids
Slide 46 — LIQUIDS-RICH GAS ASSETS
LIQUIDS-RICH GAS ASSETS MONTNEY
Slide 47 — MONTNEY: OVERVIEW
47 MONTNEY: OVERVIEW 47 Overview Key Statistics Production: 16,000 boe/d (Q3 2025)(1) Acreage: 80,000 acres(2) Infrastructure: >30,000 boe/d nameplate capacity (H2/2027 Est.)(3) History Entered the Montney in 2022, grew production from ~4,000 boe/d to ~16,000 boe/d currently Reduced DCET capital by >30% since 2022 Outlook Plan to reach 28,000 boe/d target production rate in 2028(4), will pivot to EFCF(5) generation with ~8 wells per year to maintain production
Slide 48 — INFRASTRUCTURE NEARING COMPLETION…
48 INFRASTRUCTURE NEARING COMPLETION… Major infrastructure investment is complete, smaller scale projects support target production rates 48 Water Handling Allows for up to 55% recycling of water, reduces capital costs on water handling Q3 2024 In-Service $650,000 Per Well Savings ~$15MM Capital 8-33 Battery Ph. 3 Expansion Adding compression and liquids handling, bringing owned infrastructure to target capacity H2 2027 (Est.)(1) In-Service 6,000 boe/d Capacity ~$40MM Capital 8-33 Battery Liquids handling battery facilitating the first growth leg of our BC Montney asset Q2 2024 Start-up 16,000 boe/d Capacity ~$100MM Capital 8-33 Battery Ph. 2 Expansion Adding compression and expanding sales gas line to handle increasing volumes Q1 2025 In-Service 5,000 boe/d Capacity ~$30MM Capital
Slide 49 — … PIVOTING TO LONG-TERM EXCESS FREE CASH FLOW
49 … PIVOTING TO LONG-TERM EXCESS FREE CASH FLOW Approaching Excess Free Cash Flow inflection, with majority of infrastructure spend completed 49 Long-Duration Inventory o 20+ years of inventory(2) after reaching target production Production Growth Plan in Place o Forecast ~40 wells to be drilled to achieve target production(1) Long-Term Excess Free Cash Flow(3) o Strong cash flow generation with lower ongoing capital commitments
Slide 50 — MONTNEY OPERATIONAL EXCELLENCE
50 $400 $600 $800 2023 2024 2025 $/METRE … LEADING TO LOWER COSTS 200 400 600 2023 2024 2025 METRES MD/DAY IMPROVED DRILLING SPEED… Optimized Drilling fluid and drill bit MONTNEY OPERATIONAL EXCELLENCE 50 Continuous operational improvements driving significant, sustainable cost reductions Reduced Water used in completions Leveraged Water infrastructure in place 0 2,000 4,000 2023 2024 2025 TONNES/DAY IMPROVED FRAC EFFICIENCY… $500 $750 $1,000 2023 2024 2025 $/TONNE … LEADING TO LOWER COSTS
Slide 51 — MONTNEY WELL ECONOMICS
51 MONTNEY WELL ECONOMICS Leading DCET costs in the oil window of the Montney BC Middle Montney Lateral Length (m) 3,000 DCET Cost ($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 51 Top Quartile DCET for Montney Oil Robust IP Rates High Liquids Rates, Predominantly Oil Vermilion’s High-Return Montney Asset Well economics are competitive within Vermilion’s portfolio and across all peers; moving to half-cycle returns with infrastructure nearing completion and egress contracted
Slide 52 — MONTNEY PIVOT TO EFCF
52 MONTNEY PIVOT TO EFCF 52 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) Target production rate generates $125-150MM of EFCF on lower capital requirements Pivot to Excess Free Cash Flow o Achieve 28,000 boe/d target rate, transition to sustaining capital with minimal infrastructure o 2029+ drill ~8 wells/yr to maintain production 2026-2028 Plan o Phase 3 expansion, owned infrastructure build-out complete o $70MM total infrastructure spend o Forecast drilling ~40 wells to reach target production rate 2022-2025 Execution o Acquired Mica Montney, spun out CEI.V o Commissioned 8-33 battery in Q2 2024 o Phase 2 expansion complete Q1 2025 o Reduced average well cost from $12MM to $8.5MM on first 4 pads Excess Free Cash Flow(2) generation Build infrastructure and reduce DCET costs
Slide 53 — PORTFOLIO
PORTFOLIO MANAGEMENT
Slide 54 — EXECUTIVE LEADERSHIP: BUSINESS DEVELOPMENT
54 EXECUTIVE LEADERSHIP: BUSINESS DEVELOPMENT 54 Lara Conrad Vice President Business Development 25+ Years of Experience / Joined Vermilion Team in 2025 Vermilion o VP, Business Development Prior Experience o SVP, Chief Development Officer – ARC Resources o Responsible for Business Development, Development & Reservoir Engineering, Geosciences, Strategic Planning, Mineral Land, Legal o Led fiscal, regulatory, and environmental policy at Encana o Diverse roles in development engineering across all components of the asset life cycle
Slide 55 — OPERATIONAL SCALE SUPPORTS OPPORTUNISTIC A&D
55 OPERATIONAL SCALE SUPPORTS OPPORTUNISTIC A&D Building scale across our portfolio 55 • Strong asset base will continue to grow through strategic investment and Acquisition and Divestiture (“A&D”) activity • Focus on assets with high netback margins that compete with organic development o Canada: Inventory duration and operational efficiencies o Germany and Netherlands: Low cost of entry with exploration upside
Slide 56 — BUILDING ON THE VERMILION PORTFOLIO
56 BUILDING ON THE VERMILION PORTFOLIO Opportunity to build on quality assets in Montney, Deep Basin and Europe 56 Depth of knowledge in conventional and unconventional development, onshore and offshore operations, all stages of lifecycle (exploration / development / production) Established in prolific liquid-rich gas plays Natural acquiror of cash flowing assets Harvesting EFCF(1) from legacy oil assets
Slide 57 — ACQUISITION STRATEGY
57 ACQUISITION STRATEGY Enhancing Excess Free Cash Flow(1) generation through strategic portfolio management o In Canada, focused on Montney and Deep Basin o 30 years of experience in efficient stacked zone development, track record of identifying and successfully integrating acquisitions o Experienced operator with jurisdictional expertise: operations in Europe since 1997 o Relationship depth with international players o Benefit from diversified commodity markets o Inorganic must compete with high-return organic growth o Complementary opportunities: multiple jurisdictions and basins where synergies can be identified and realized Liquids-Rich Plays European Advantage Must Compete with Organic Development 57
Slide 58 — OUTLOOK &
OUTLOOK & CAPITAL ALLOCATION
Slide 59 — EXECUTIVE LEADERSHIP: CFO
59 EXECUTIVE LEADERSHIP: CFO 59 Lars Glemser Vice President & Chief Financial Officer 20+ Years of Experience / 10 Years Vermilion Experience Vermilion o Director, Finance o Investor Relations o Operations Controller Prior Experience o Diverse roles in finance/treasury, corporate planning and corporate development
Slide 60 — THE VERMILION OPPORTUNITY
60 THE VERMILION OPPORTUNITY Vermilion offers an improved core business and a unique investment opportunity 60 o Multi-commodity portfolio ensures resilience and upside potential o Debt per boe reduced ~50% from 2021 to YE 2026e(1), strengthening the balance sheet o Robust commodity marketing strategy enhances margins o Effective hedging program o Positioned for EFCF(2) growth driven by structural tailwinds o Committed to sustainable shareholder returns through disciplined capital allocation Resilience Sophistication Opportunity
Slide 61 — RESILIENCE: FINANCIAL
61 $1.1B Undrawn $0.2B CREDIT CAPACITY(3) Undrawn Capacity on RCF Drawn on RCF (Incl. LOC) RESILIENCE: FINANCIAL $0 $200 $400 $600 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 OUTSTANDING DEBT ($MM) DEBT MATURITY PROFILE(2) Revolving Credit Facility ("RCF") Sr. Notes 61 No near-term debt maturities… 0.0x 0.5x 1.0x 1.5x 2.0x 2021 2022 2023 2024 2025e 2026e NET DEBT TO FFO(1) Committed to returning to 1.0x leverage - 5 10 15 20 25 2021 2022 2023 2024 2025e 2026e NET DEBT ($MM) / BOE/D NET DEBT TO PRODUCTION(1) … with $1.1B of liquidity on RCF
Slide 62 — RESILIENCE: OPERATIONAL
62 RESILIENCE: OPERATIONAL 62 - 2,000 4,000 6,000 2022 2023 2024 2025e WELL COUNT (NET) TOTAL WELL COUNT(1) Producing Wells Non-Producing Wells - 5 10 15 20 2022 2023 2024 2025e (MBOE / WELLBORE) PRODUCTION PER WELLBORE(3) - 25 50 75 100 125 2022 2023 2024 2025e 2026e (MBOE/D) PRODUCTION FROM GLOBAL GAS ASSETS(4) $0 $10 $20 $30 $40 $50 $60 2022-2025 (Avg.) 2026e 2027e-2030e (Avg.) ($MM) MONTNEY INFRASTRUCTURE INVESTMENT(2) Production from our global gas assets grew from ~60% of our total production in 2022 to ~90% in 2026 Production per wellbore is up 275% from 2022
Slide 63 — SOPHISTICATION: MARKETING
63 SOPHISTICATION: MARKETING 63 Global gas diversification balances gas exposure and improves netbacks Direct Access to Global Gas Markets o Actively monitor global hubs to optimize price Long-Duration Assets Complement Market Access o Multi-year basis hedges to manage exposure Direct Access to Multiple North American Markets o Recently extended Alliance capacity until 2035 o Station 2 exposure added in 2026 through West Coast Pipeline Optimize Value of Montney Development o Contracted capacity in non-operated deep-cut plant o Enhances liquids weighting to ~35%, ~55% of revenues derived from liquids(1) 33% 28% 2% 5% 5% 8% 7% 5% 7% NATURAL GAS PRICE EXPOSURE(2) Financial Hedges AECO Basis Physical Hedges Alliance Station 2 (from Oct/26) Europe (TTF) Europe (THE) Europe (NBP) AECO Exposure Diversification Euro Gas
Slide 64 — SOPHISTICATION: HEDGE PROGRAM
64 SOPHISTICATION: HEDGE PROGRAM 64 Hedge gains enhance Vermilion’s peer leading realized gas price AVERAGE (EXCL VET) = $2.63 $0 $1 $2 $3 $4 $5 $6 REALIZED NATURAL GAS PRICE ($/MCF) Q3 2025 REALIZED NATURAL GAS PRICE(1) REALIZED GAS PRICE REALIZED HEDGE GAIN 0% 20% 40% 60% 80% 100% Crude Oil European Natural Gas N.A. Natural Gas Corporate Total 2026 PRODUCTION HEDGED(3) WTI BRENT NATURAL GAS Effective Financial Hedging Program $700 million of realized hedge gains over 2023-2025 (YTD)(2) Currently have 43% of production hedged for 2026 WTI (C$/bbl) Brent (C$/bbl) Euro Gas (C$/mmbtu) N.A. Gas (C$/mmbtu) Avg. Sold Call $95.36 N/A $18.85 $4.49 Avg. Bought Put $85.47 N/A $11.96 $3.03 Avg. Swap $85.89 N/A $15.59 $3.33
Slide 65 — OPPORTUNITY: UNIQUE PORTFOLIO
65 OPPORTUNITY: UNIQUE PORTFOLIO 65 Vermilion’s capital markets relevance increases as investors seek global gas exposure 0% 5% 10% 15% 20% % INTERNATIONAL EXPOSURE(1) GAS PRODUCERS WITH INTERNATIONAL EXPOSURE (Q3 2025) Uniquely positioned as only mid-cap entity with meaningful global gas price exposure and long-duration international gas reserves. Offering capital allocation flexibility into core areas with geographic and commodity diversification. Canada Gas European Gas Crude oil + Liquids Production(2) 57% 13% 30% Sales(2) 30% 21% 49% Portfolio composition provides balanced revenue stream from current production mix
Slide 66 — LOWEST COST OF GAS TO GLOBAL MARKET
66 LOWEST COST OF GAS TO GLOBAL MARKET $- $2.00 $4.00 $6.00 $8.00 $10.00 CANADA WEST COAST LNG (TO ASIA) US GULF COAST LNG (TO ASIA) US GULF COAST LNG (TO EUROPE) GERMANY FIELD DEVELOPMENT USD/MCF INTERNATIONAL GAS SUPPLY ECONOMICS(1) SHIPPING COST LIQUEFACTION COST TRANSPORT COST TO TIDEWATER FULL-CYCLE DEVELOPMENT COSTS 66 Vermilion’s capital allocation model provides unique exposure to global gas margin capture West Coast Canada offers strong LNG economics Vermilion’s domestic production: Lowest cost to access global gas market $28MM +/- C$1/MMBtu Euro Gas Price $136MM +/- $1/MMBtu AECO Gas Price 2026 Unhedged EFCF Gas Sensitivities(2) Positioned for resilience through the commodity cycle
Slide 67 — ADDING PER SHARE VALUE
67 ADDING PER SHARE VALUE Adding more Excess Free Cash Flow behind every share 67 0.20 0.22 0.24 0.26 0.28 0.30 0.32 0.34 0.36 2026E 2028E PRODUCTION / SHARE(1,2) $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 2026E 2028E EXCESS FCF / SHARE(1,3) STRIP PRICING INVESTOR DAY PRICING
Slide 68 — CAPITAL ALLOCATION PRIORITIES
68 CAPITAL ALLOCATION PRIORITIES Disciplined capital allocation focused on creating long term shareholder value Provide Compounding Shareholder Returns Target long-term value-add acquisition opportunities Maintain Robust Asset Base Maintain Strong Balance Sheet o Targeting net debt to FFO ratio(1) less than 1.0x o Allocating 60% of EFCF(2) to debt repayment o $1.1B of available liquidity o Repositioned global gas portfolio o Depth and quality of inventory o Long-duration, profitable asset base o 40% return of EFCF o Five consecutive years of dividend increases o Repurchased 20 million shares(3) (12% of Q2/22 shares outstanding) o Focus on increased operational scale in core areas o Committed to deep-value international acquisitions 68
Slide 69 — FIVE-YEAR OUTLOOK: CAPITAL ALLOCATION
69 FIVE-YEAR OUTLOOK: CAPITAL ALLOCATION 69 $1.7 Billion Cumulative EFCF(1,2) Shifting enterprise value to shareholders Increasing balance sheet resiliency $1.4B $0.6-0.9B 2025E 2030E NET DEBT(1,3) Post 2030: 20+ years Deep Basin inventory, 15+ years Montney inventory, Germany production growing 153MM 100-125MM 2025E 2030E SHARE COUNT(1) $2.70/share at current dividend 2026E-2030E CUMULATIVE DIVIDENDS PER SHARE(1) Material EFCF provides optionality for return of capital Ability to grow the dividend within 10% payout(4) while reducing share count Room to grow
Slide 70 — SUMMARY &
SUMMARY & KEY TAKEAWAYS
Slide 71 — SUMMARY & KEY TAKEAWAYS
71 SUMMARY & KEY TAKEAWAYS 71 Montney Momentum Dominant Deep Basin Germany Production Growth Return of Capital Repositioned Global Gas Portfolio $0 $100 $200 $300 $400 $500 2026e (Strip) EFCF Inflection 2028+ Run Rate EXCESS FREE CASH FLOW ($MM) 2026-2028 EFCF OUTLOOK(1,2) EFCF OPERATIONAL EXCELLENCE PRICING VS. STRIP Structural Lift in EFCF Growing European gas and Montney/Deep Basin liquids-rich gas
Slide 72 — APPENDIX
APPENDIX
Slide 73 — PRICING & FFO SENSITIVITY
73 73 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 $1MM PRICING & FFO SENSITIVITY Commodity Price Forecast(3) TTF ($/MMBtu) $13.00 NBP ($/MMBtu) $13.00 AECO ($/GJ) $ 3.50 Henry Hub (US$/MMBtu) $ 4.00 Brent (US$/bbl) $74.00 WTI (US$/bbl) $70.00 MSW = WTI less (US$/bbl) $ 4.00 CAD/USD 1.38 CAD/EUR 1.60 CAD/AUD 0.90 EUR/GBP 1.13
Slide 74 — ANALYST COVERAGE
74 74 Firm Analyst ATB Capital Markets Amir Arif, CFA, CMT BMO Capital Markets Jeremy McCrea, CFA Canaccord Genuity Capital Markets Mike Mueller, P.Geo., CFA CIBC Capital Markets Dennis Fong, P.Eng. Desjardins Capital Markets Chris MacCulloch, CFA National Bank of Canada Capital Markets Travis Wood Peters & Co. Limited Conrad Bereznicki, P.Eng. RBC Capital Markets Greg Pardy, CFA Scotia Capital Inc. Kevin Fisk, CPA, CBV TD Securities Inc. Menno Hulshof, CFA ANALYST COVERAGE
Slide 75 — ADVISORY
75 ADVISORY This presentation is for information purposes only and is not intended to, and should not be construed to constitute, an offer to sell or the solicitation of an offer to buy, securities of Vermilion Energy Inc. ("Vermilion", the "Company", "we", or "us"). This presentation and its contents should not be construed, under any circumstances, as investment, tax or legal advice. Any person viewing this presentation acknowledges the need to conduct their own thorough investigation into Vermilion and its activities before considering any investment in its securities. All references are to Canadian dollars unless otherwise specified. Forward-Looking Statements Certain statements included or incorporated by reference in this document may constitute forward-looking statements or information under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward- looking statements or information in this document may include, but are not limited to: duration and life of inventory and assets; well production timing and expected production rates and financial returns, including half-cycle internal rate of return, therefrom; future production and costs; repositioning of portfolio and its impact to 2028 and onward; five year outlook; wells expected to be drilled and impact on production and total wells; exploration and development plans, and the timing and effects thereof; estimated recoverable gas; effects of infrastructure build out in Montney; outlook for Vermilion’s key assets and geographies, including production and EFCF growth, targets and forecasts; petroleum and natural gas sales, netbacks, and the expectation of generating strong free cash flow therefrom; exposure to and the effect of changes in crude oil and natural gas prices, and changes in exchange and inflation rates; commodity price and exchange rate forecasts; statements regarding Vermilion’s hedging program including the anticipated impact of Vermilion’s hedging program on free cash flows; unhedged EFCF gas sensitivities; capital expenditures including Vermilion’s ability to fund such expenditures in 2025 and future periods; future production levels and the timing thereof, including Vermilion’s future guidance, and rates of total and per share production growth and EFCF growth, including Vermilion’s ability to maintain or grow production; future production weighting, including weighting for product type or geography; estimated volumes of reserves and resources; statements regarding the return of capital and share buybacks; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; declines in Ireland including timing; statements regarding the growth and size of Vermilion's future project inventory, including the number of future drilling locations expected to be available and infrastructure; acquisition and disposition strategy and plans; operating and other expenses, including the payment and amount of future dividends; lifetime payout of wells; future construction, infrastructure build-outs, planning and permitting, including costs and effects on production and EFCF; reduction of debt per boe, net debt, net debt to FFO and net debt to production; anticipated DCET costs; sustainable shareholder returns; debt maturity; credit capacity; future investments; future pipeline capacity; capital allocation and effects therefrom; EFCF run rate; drilling programs; WSSH target on-stream timing; and the timing of regulatory proceedings and approvals. Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this presentation, assumptions have been made regarding, among other things: the accuracy of the McDaniel & Associates Report; the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; management’s expectations relating to the timing and results of exploration and development activities; the impact of Vermilion’s dividend policy on its future cash flows; credit ratings; hedging program; expected future cash flows and free cash flow and expected future cash flow and free cash flow per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; general economic and competitive conditions; ability of management to execute key priorities; and the effectiveness of various actions resulting from the Vermilion's strategic priorities. Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion’s financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates, interest rates and inflation; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against or involving Vermilion; and other risks and uncertainties described elsewhere in this presentation or in Vermilion's other filings with Canadian securities regulatory authorities. References to Vermilion or the Company in this document include Westbrick Energy Inc. which amalgamated with Vermilion Energy Inc. on February 26, 2025. The forward-looking statements or information, including financial outlooks, contained in this presentation are made as of December 10, 2025, and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, including financial outlooks, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws. Non-GAAP Financial Measures and Ratios This presentation includes references to certain financial measures that are not standardized, specified, defined, or determined under International Financial Reporting Standards ("IFRS") and are therefore considered non-GAAP or other specified financial measures and may not be comparable to similar measures presented by other issuers. These measures and ratios include “FFO”, “net debt”, “net debt to production”, “net debt-to-FFO”, “E&D capital expenditures”, “free cash flow”, “EFCF”, “EFCF per share”, “Unhedged EFCF” and “payout”. Management believes that, in conjunction with results presented in accordance with IFRS, these measures and ratios assist in providing a more complete understanding of certain aspects of Vermilion's results of operations and financial performance. Readers are cautioned, however, that these measures and ratios should not be construed as an alternative to measures determined in accordance with IFRS as an indication of our performance. For a full description of these financial measures and ratios and a reconciliation of these measures and ratios to their most directly comparable GAAP measures and ratios, please refer to the "Non-GAAP and Other Specified Financial Measures" section of Vermilion’s MD&A for the three and nine months ended September 30, 2025, which information is incorporated by reference herein. Reserves Advisories Reserves estimates in this presentation are derived from an evaluation report dated March 4, 2025 with an effective date of December 31, 2024 are prepared by McDaniel & Associates Consultants Ltd. (the "McDaniel Report"), an independent qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. For a full description of the McDaniel Report, including the forecast price and cost assumptions used therein, please refer to Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024. This presentation includes reference to certain metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Readers are cautioned as to the reliability of oil and gas metrics used in this presentation. These oil and gas metrics includes “DCET costs" and "decline rates". DCET costs includes all capital spent to drill, complete, equip and tie-in a well. Management uses these oil and gas metrics for its own performance measurements and to provide readers with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance, which may not compare to the Company's performance in previous periods, and therefore should not be unduly relied upon. Additional oil and gas metrics in this document may include, but are not limited to: Boe Equivalency: Certain natural gas volumes have been converted on the basis of six thousand cubic feet of gas to one barrel of oil. Barrels of oil equivalent (boes) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion of six thousand cubic feet of gas to one barrel of oil may be misleading as an indicator of value as the value ration between conventional natural gas and crude oil, based on the prices of natural gas and crude oil, differ significantly from the energy equivalency of six million cubic feet to one barrel of oil. 75
Slide 76 — SLIDE NOTES
76 Disclaimer: Estimates of drilling locations Drilling inventory reflects company estimates of future drilling locations and expected pace of future development, and includes locations evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") as well as unbooked locations. Of the locations disclosed in this presentation, 365 have been evaluated by McDaniel, as part of either Vermilion’s reserve report for the year ended December 31, 2024, or a report prepared by McDaniel for the evaluation of the acquisition of Westbrick Energy Ltd. with an effective date of November 30, 2024. The remainder of locations are unbooked. Unbooked drilling locations are the internal estimates of Vermilion based on Vermilion's prospective acreage and internal review of potential locations. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Vermilion's management as an estimation of Vermilion's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Vermilion will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Vermilion will actually drill wells, including the number and timing thereof, is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management of Vermilion has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Slide 3 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. (3) E&D capital expenditures is a non-GAAP 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. (4) Based on company estimates as of December 9, 2025. Slide 4 (1) For information relating to this measure incorporated by reference into this presentation, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Net debt includes net working capital. Year-end 2025 net debt based on company estimates as of December 9, 2025, and full year average reference prices as at October 27, 2025, as follows: WTI US$65.17/bbl, AECO $1.86/mcf, TTF $16.98/MMBtu, USD/CAD 1.40. (2) E&D capital expenditures is a non-GAAP measure, refer to footnote (3) on slide 3, above. (3) Investor Day pricing used in this presentation is based on approximate strip pricing for gas benchmarks and foreign exchange, and approximate historical average pricing for oil benchmarks. Slide 8 (1) Elements of company 2026-2030 forecast derived by utilizing, among other assumptions, historical Vermilion production performance and current cost assumptions, adjusted annually after 2026. 2027 and beyond provided for illustrative purposes only. Budgets and forecast beyond 2026 have not been finalized and are subject to a variety of factors including prior year’s results. Included in this presentation are estimates of the Company's 2026-2030 production, excess free cash flow and excess free cash flow per share which are based on various assumptions as to business unit production levels, commodity prices, the anticipated receipt of drilling permits and other assumptions and in the case of the years other than 2025 or 2026, such estimates are provided for illustrative purposes only. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in December 2025 and are included to provide readers with an understanding of the Company's anticipated excess free cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. (2) 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 based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). (3) Unhedged EFCF per share represents unhedged EFCF divided by weighted average basic shares outstanding based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). Unhedged EFCF is a non-GAAP financial measure, comprised of EFCF excluding realized gain (loss) on derivatives. Refer to footnote (2) on slide 3, above. (4) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 9 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 10 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 11 (1) Based on company estimates as of December 9, 2025. (2) Realized price reflects approximate full-year 2025 realized European gas price in Canadian dollars per MMBtu based on company estimates as of December 9, 2025. Slide 12 (1) Production, unit costs and capital intensity for 2024 reflects actuals per annual report. 2026e based on company estimates as of December 9, 2025. Slide 13 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 14 (1) Based on company estimates as of December 9, 2025. (2) Based on company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (3) Based on company estimates as of December 9, 2025, excludes Australia drilling, which is typically every 2-4 years and is currently scheduled for 2027. (4) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Refer to Pricing & FFO Sensitivity slide for pricing assumptions used. (5) 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 based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). 76 SLIDE NOTES
Slide 77 — SLIDE NOTES
77 Slide 15 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. EFCF presented based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). Strip pricing reflects full year average reference prices as at October 27, 2025, as follows: WTI US$59.98/bbl, AECO $3.26/mcf, TTF $14.66/MMBtu, USD/CAD 1.38. (2) Based on company estimates as of December 9, 2025. All future development subject to receiving necessary permits. (3) Based on company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. Slide 19 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). Slide 20 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). Slide 21 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). Slide 22 (1) Rate represents disclosed test rate, which may not necessarily be indicative of long-term performance or ultimate recovery. For additional information on test results and conditions for Osterheide (“OSTH”) refer to Vermilion’s Q1 2024 report for the three and nine months ended September 30, 2024, and for Wisselshorst (“WSSH”) refer to Vermilion’s annual report for the three months and year ended December 31, 2024, both available on SEDAR+ at www.sedarplus.ca. Slide 24 (1) Average per well is based on average cumulative production to year end 2024 of 5.6 Bcf per well and average gross 2P reserves of 3.2 Bcf per well as evaluated by McDaniel at year end 2024. (2) Future potential is dependent on unbooked locations, refer to the disclaimer on estimates of drilling locations (above). Slide 25 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). Evaluation locations comprise locations included in the report prepared for the acquisition of Westbrick Energy Ltd. with an effective date of November 30, 2024. Slide 28 (1) Gas production for Q3 2025, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. (2) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024, available on SEDAR+ at www.sedarplus.ca. Slide 29 (1) Reserve additions calculated as gross reserves as of December 31, 2024, as evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel"), plus reported production for the annual periods from 2004 to 2024 as per Vermilion’s Annual Information Form (“AIF”) for the applicable years, less acquired gross reserves from 2004 to 2024 as per Vermilion’s AIF for the applicable years. Acquired reserves from 2004 to 2024 were evaluated by an independent qualified reserves evaluator appointed pursuant to NI 51-101 during the year in which they were acquired. (2) Gross reserves assigned to Osterheide (1.0 net) and Wisselshorst (0.6 net) include 22.7 Bcf of 2P reserves at Wisselshorst that were assigned subsequent to December 31, 2024, and are therefore not included in Vermilion’s reserves at December 31, 2024, as evaluated by McDaniel. Total gross reserves assigned of 60.2 Bcf represent over 20% of Vermilion’s gross European gas reserves at December 31, 2024, excluding the gross reserves assigned to the discovery wells, which totals 281.8 Bcf. (3) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). Slide 30 (1) Total proved plus probable conventional natural gas reserves, as evaluated by McDaniel, a qualified reserves evaluator. Gross reserves reflect 64% working interest in Wisselshorst Z1a well. Refer to Vermilion’s annual report for the three months and year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 31 (1) Total gross proved plus probable conventional natural gas reserves, as evaluated by McDaniel, as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024, available on SEDAR+ at www.sedarplus.ca. (2) Average recovery of identified Germany prospects based on internal estimates as of December 9, 2025. Slide 32 (1) Total cost to drill, complete, equip and tie-in (“DCET”) per well based on internal estimates as of December 9, 2025. (2) Estimated ultimate recovery for Germany based on internal estimates as of December 9, 2025, and for Deep Basin based on estimates provided by McDaniel & Associates Consultants Ltd (“McDaniel”). (3) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as of December 9, 2025, and using Investor Day pricing (see Pricing & FFO Sensitivity slide). (4) 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 and Deep Basin development based on Company estimates as of December 9, 2025, and using Investor Day pricing (see Pricing & FFO Sensitivity slide). Slide 33 (1) Total cost to drill, complete, equip and tie-in (“DCET”) per well based on internal estimates as of December 9, 2025. (2) Months to production reflects the time required to bring a well from rig release to first production, based on internal estimates as of December 9, 2025. Slide 35 (1) 2023-2024 reflects actual production, 2025 based on company estimates as of December 9, 2025. Company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. 77 SLIDE NOTES
Slide 78 — SLIDE NOTES
78 Slide 36 (1) 2025 based on company estimates as of December 9, 2025. Company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. Slide 39 (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 per the published Fall Energy Overview, using US$65.00/B WTI, US$4.00/Mcf NYMEX, and $3.25/Mcf AECO pricing. Slide 40 (1) Production for Q3 2025, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Reported production in Canada includes Deep Basin and Montney production. (2) Acreage includes approximately 770,000 net acres of land from the acquisition of Westbrick Energy Ltd., which closed on February 26, 2025, and was not included in Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024. (3) Infrastructure nameplate capacity reflects Vermilion owned and operated infrastructure, including gas plants, major compressors, and oil batteries. Vermilion has available capacity on owned processing infrastructure and has existing connections to third-party infrastructure with significant available capacity. (4) Based on company estimates as of December 9, 2025. (5) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). Slide 41 (1) Initial 30-day production (“IP30”) based on field level estimates for the first 30 full days of production following the tie-in of the well. IP30 rates are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Short- term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Although such rates are useful in confirming the presence of hydrocarbons, they are preliminary in nature, are subject to a high degree of predictive uncertainty as a result of limited data availability and may not be representative of stabilized on-stream production rates. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Production over a longer period will also experience natural decline rates, which can be high in certain plays in which the Company operates, and may not be consistent over the longer term with the decline experienced over an initial production period. Initial production or test rates may also include recovered "load" fluids used in well completion stimulation operations. Actual results will differ from those realized during an initial production period or short-term test period, and the difference may be material. Slide 42 (1) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). (2) Based on company estimates as of December 9, 2025. (3) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 43 (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 44 (1) Well results for 2022-2025 based on average actual well results, 2026 budget based on company estimates as of December 9, 2025. Initial 30-day production (“IP30”) based on field level estimates for the first 30 full days of production following the tie-in of the well. Refer to footnote (1) on slide 41, above. Slide 45 (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 Investor Day pricing (see Pricing & FFO Sensitivity slide). 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 Investor Day pricing (see Pricing & FFO Sensitivity slide). (6) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as of December 9, 2025, and using Investor Day pricing (see Pricing & FFO Sensitivity slide). Slide 47 (1) Production for Q3 2025, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Reported production in Canada includes Deep Basin and Montney production. (2) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2024, available on SEDAR+ at www.sedarplus.ca. (3) Infrastructure nameplate capacity includes existing Vermilion owned and operated facilities as well as future expansion, the timing of which is based on company estimates as of December 9, 2025. (4) Based on company estimates as of December 9, 2025, refer to footnote (1) on slide 8, above. (5) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 48 (1) Based on company estimates as of December 9, 2025. Slide 49 (1) Based on company estimates as of December 9, 2025. (2) Drilling inventory reflects company estimates of future drilling locations and expected pace of future development. Refer to the disclaimer on estimates of drilling locations (above). (3) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. 78 SLIDE NOTES
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79 Slide 51 (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 Investor Day pricing (see Pricing & FFO Sensitivity slide). 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 Investor Day pricing (see Pricing & FFO Sensitivity slide). (6) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate based on Company estimates as of December 9, 2025, and using Investor Day pricing (see Pricing & FFO Sensitivity slide). Slide 52 (1) 2022-2024 reflects actual production, 2025 based on company estimates as of December 9, 2025. Company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 55 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 56 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 57 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 60 (1) Based on company estimates as of December 9, 2025. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. Slide 61 (1) Net debt is a capital management measure and net debt to four quarter trailing fund flows (“net debt to FFO”) is a non-GAAP ratio. For additional information on these measures refer to footnote (1) on slide 4, above. 2025e-2026e based on company estimates as of December 9, 2025, using strip pricing for 2025e and Investor Day pricing for 2026e (see Pricing & FFO Sensitivity slide). Strip pricing reflects full year average reference prices as at October 27, 2025, as follows: WTI US$65.17/bbl, AECO $1.86/mcf, TTF $16.98/MMBtu, USD/CAD 1.40. (2) Reflects outstanding borrowings 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 on SEDAR+ at www.sedarplus.ca for additional information. USD borrowings translated at September 30, 2025, FX rate of 1.3921. (3) Reflects outstanding borrowings and available liquidity at September 30, 2025, refer to Vermilion’s financial statements for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca for additional information. Slide 62 (1) Producing and non-producing well count for 2022-2024 per Vermilion’s Annual Information Form for the applicable years. 2025e reflects the acquisition of producing and non-producing wells from Westbrick Energy and the divestment of producing and non-producing wells in Saskatchewan and the United States. (2) 2022-2025 average reflects actual Montney infrastructure investment, 2026e and 2027e-2030e average based on company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (3) Production per wellbore reflects annual production per wellbore, 2022-2024 reflects actual production per annual reports, 2025e based on company estimates as of December 9, 2025. (4) Represents production from Global Gas Assets (Canada – Deep Basin, Canada – Montney, Germany, Netherlands, Ireland, and CEE), 2022-2024 reflects actual production per annual reports, 2025e-2026e based on company estimates as of December 9, 2025. Slide 63 (1) Based on company estimates as of December 9, 2025. (2) Price exposure reflects hedges in place December 9, 2025, as a percentage of estimated 2026 production based on company 2026 estimates as at place December 9, 2025. Station 2 exposure reflects contracted daily volumes from October 2026 as a percentage of estimated 2026 daily production. Slide 64 (1) Q3 2025 realized natural price per company public disclosures. Realized hedge gains for peers reflects realized gain for gas as disclosed, or full realized hedge gain for Q3 2025 if gain by product type not disclosed. (2) 2023 – 2025 YTD hedge gains reflects realized gain on derivatives per company disclosures, for additional information refer to Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. (3) Company estimates as of December 9, 2025. Hedge percentages based on contract volumes as a percentage of net of royalty production and excludes basis swaps on North American natural gas. Slide 65 (1) Current international exposure per company disclosures, based on volumes receiving JKM and/or TTF-linked pricing as a percentage of actual Q3 2025 volumes. (2) Based on company 2026 estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). Slide 66 (1) Supply economics based on TD Securities research and company estimates as of December 9, 2025. Full-cycle development costs include capital and operating costs, and royalties. Full-cycle costs for industry participants reflects average of peers with current or future LNG exposure, Vermilion Germany field development costs based on company estimates as of December 9, 2025. (2) Annual FFO sensitivity based on company 2026 estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). 79 SLIDE NOTES
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80 Slide 67 (1) Company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (2) 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 based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). (3) Unhedged EFCF per share represents unhedged EFCF divided by weighted average basic shares outstanding based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). Unhedged EFCF is a non-GAAP financial measure, comprised of EFCF excluding realized gain (loss) on derivatives. Refer to footnote (2) on slide 3, above. Slide 68 (1) Net debt to four quarter trailing fund flows (“net debt to FFO”) is a non-GAAP ratio. For additional information refer to footnote (1) on slide 4, above. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. (3) Shares purchased to November 30, 2025. Slide 69 (1) Company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. (3) Net debt is a capital management measure, for additional information refer to footnote (1) on slide 4, above. (4) Payout is a non-GAAP financial measure most directly comparable to dividends declared. Refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three and nine months ended September 30, 2025, available on SEDAR+ at www.sedarplus.ca. Slide 71 (1) Company 2026-2030 forecast as of December 9, 2025, refer to footnote (1) on slide 8, above. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to footnote (2) on slide 3, above. EFCF presented based on company estimates as of December 9, 2025, and Investor Day pricing (see Pricing & FFO Sensitivity slide). Strip pricing reflects full year average reference prices as at October 27, 2025, as follows: WTI US$59.98/bbl, AECO $3.26/mcf, TTF $14.66/MMBtu, USD/CAD 1.38. Slide 73 (1) Investor Day pricing used in this presentation is based on approximate strip pricing for gas benchmarks and foreign exchange, and approximate historical average pricing for oil benchmarks. (2) Annual FFO sensitivity based on company 2026 estimates as of December 9, 2025, and Investor Day pricing. 80 SLIDE NOTES