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Vermilion Energy — Vermilion Germany Overview (company IR deck)
Vermilion Energy (VET) · 32 slides · Filed Oct 29, 2026
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Slide 1 — VERMILION ENERGY
1 VERMILION ENERGY GERMANY OVERVIEW GLOBAL GAS PRODUCER FREE CASH FLOW FOCUSED FINANCIAL DISCIPLINE MAY 2026
Slide 2 — UNDERFUNDED BASIN PROVIDES OPPORTUNITY
2 BEB + MEEG 47% Harbour 30% Neptune 16% Vermilion 5% Others 2% Germany Production by Company(2) Vermilion’s acreage position allows us to leverage technology in this prolific and underfunded basin 2 o Post-war Germany saw a surge of exploration activity with significant discoveries and production o Under-investment followed as industry players reduced their capital allocations to Germany o Remaining producers have significantly reduced exploration activity over the last decade; provides opportunity to Vermilion 0.0 0.5 1.0 1.5 2.0 2.5 1953 1957 1965 1984 1988 1992 1996 2000 2004 2008 2012 2016 2020 2024 Bcf/d German Gas Production by Year(1) UNDERFUNDED BASIN PROVIDES OPPORTUNITY Potential for additional consolidation of acreage and infrastructure
Slide 3 — GERMANY'S ENERGY MIX
3 Germany continues to depend on imported natural gas – provides an opportunity for domestic gas growth 3 GERMANY'S ENERGY MIX o Germany's Energiewende phased out nuclear power in 2023, increasing reliance on renewables, oil, coal, and natural gas o Coal and lignite power plants are mandated to be phased out possibly by 2030, and latest by 2038 o Prior to 2022 Germany imported the majority of its gas from Russia and Norway o Natural gas represents more than 25% of Germany's total energy supply, while only ~5% was produced domestically(2) o Growth in Germany's domestic production is both required and supported by German government Oil and oil products 34% Natural gas 28% Coal and coal products 16% Biofuels and waste 13% Renewables and hydro 9% Total Energy Supply, Germany 2024(1)
Slide 4 — VERMILION
4 VERMILION IN GERMANY 4
Slide 5 — VERMILION HISTORY IN GERMANY
5 OSTH well on stream Mar. 31, 2025 WSSH well on stream Mid-2026 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026e Avg. Daily Production (boe/d)(1) Annual Production Oil Gas 5 VERMILION HISTORY IN GERMANY VET Enters Germany Exploration Farm-In Acquisition BGMR Z5 Drill Success Acquisition OSTH Drill Success (>17 mmcf/d test rate) WSSH Drill Success (>41 mmcf/d test rate) 2026 reflects partial year of asset acquisition, two months of downtime on non-operated gas assets Acquisition Over the last decade Vermilion has built a large land position and deep gas prospect inventory
Slide 6 — VERMILION IN GERMANY TODAY
6 VERMILION IN GERMANY TODAY 6 Overview Key Statistics Production: 25 mmcf/d gas / 1,600 bbl/d oil (2025)(1) Financial metrics: FFO ~ $100MM (2025)(1) Acreage: >1 million net acres(2) Employees: 58 (56 permanent, 2 contract) – includes 25 operations staff Gas facilities: 11 operated, 1 under construction and GK (non-op) Oil facilities: 8 (all operated) Pipelines: 400km oil, 159km gas, 63km water Outlook and Focus Start-up of Wisselshorst Z1a – Mid-2026(3) Prepare for drilling of Wisselshorst Z2/Z3 – planned spud Q1 2027(3) Progress permits for the Wisselshorst Phase 2 pipeline Advance drilling permits and prospect inventory Significant growth opportunity ahead; early days of our deep gas exploration and development program
Slide 7 — GERMAN EXPLORATION LAND POSITION
7 NET ACREAGE Developed: 100,851 acres Undeveloped: >1MM acres LICENCES Production Operated: 24 Production Non-Operated: 3 Exploration Operated: 12 Exploration Non-Operated: 1 7 Over 1MM net acres of land with over 30 drilling locations identified to date GERMAN EXPLORATION LAND POSITION
Slide 8 — PERMITTING &
8 PERMITTING & PROJECT TIMELINES 8
Slide 9 — REGULATORY STRUCTURE
9 REGULATORY STRUCTURE 9 o One Stop Shop: The Mining Authority (LBEG) operates as a comprehensive, centralized regulator that oversees every phase of operations, ensuring a transparent and predictable regulatory environment o Dual Advocacy and Oversight: Beyond regulation, the Mining Authority serves as a bridge between the industry and the state, promoting mining as a national interest o Strategic Relationship Management: Success in this jurisdiction requires proactive communication with the LBEG, and Vermilion continuously builds on this relationship European Law National Law National Regulations Federal State Law (Mining Authority) Stable and predictable regulatory regime
Slide 10 — TYPICAL PERMITTING TIMELINE
10 10 TYPICAL PERMITTING TIMELINE Approval process to drill a new well is normally within 12 months ~ 1-2 Months Prepare and submit UVP-VP (EIA screening) application ~ 4 Months UVP-VP review and decision process ~ 1-2 Months Prepare and submit application for site, drill, water handling plan ~ 4 Months Site construction and drilling approvals ~ 6-7 months up-front Bird-counting/environmental field work in area of potential drill Minimal cost
Slide 11 — PROJECT EXECUTION TIMELINE
11 11 PROJECT EXECUTION TIMELINE Time required from site construction to first production is typically 14 to 17 months ~ 4 Months Lease construction $1-4MM capex ~ 4 Months Drill, complete and test well $15-$25MM capex ~ 6-9 Months Complete additional facility and tie-in activity, bring well on-production $15-$25MM capex Ongoing Teams continually identifying and evaluating prospects on land base Minimal cost
Slide 12 — OPERATIONAL EXCELLENCE
12 Follow-up development benefits from improving cost structure and accelerated timelines 6 12 18 Discovery Well Additional Wells (Avg.) Months to Prod. Accelerated Follow-up Development $20 $40 $60 Discovery Well Additional Wells (Avg.) DCET ($000’s) Lower Cost Follow-up Development OPERATIONAL EXCELLENCE 12 Reducing capital cost o Using high-performance drilling rig, drilling two wells back-to-back or in batch sequence, utilizing existing infrastructure Improving cycle times o Optimize procurement of long-lead equipment, improved permitting times for additional wells
Slide 13 — ENVIRONMENTAL AND EIA REQUIREMENTS
13 ENVIRONMENTAL AND EIA REQUIREMENTS 13 o Full EIA’s are not typically required to drill, complete, equip or tie-in conventional gas wells o May be required in environmentally sensitive areas or extraordinary cases if protected species are found during the study phase o EIA screenings (UVP-VP) are required for various stages o Requires bird counting/environmental mapping but process is defined and managed by the regulator o We typically have ability to drill, construct facilities, and produce without an EIA up to site production limits of 500 E3m3/day (17.7 mmcf/day) o A standardized facility package has been designed to minimize regulatory impacts, optimize costs and allow for modular expansion if necessary o Sites requiring more than 500 E3m3/day of capacity will be developed with a phased approach, allowing for earlier production and revenue while a full EIA is conducted for facility expansion and higher rates Facility packages optimally designed to 500 E3m3/day to avoid early project overcapitalization Drill IF production is >500 E3m3/d gas Pre-EIA (UVP-VP) to determine if EIA is needed EIA Facility/ Pipeline Construction Production 0 10 20 30 40 0 5 10 15 20 0 24 48 72 96 120 144 EUR (Bcf) Gas Rate (mmcf/d) Months on Production GBU Deep Gas Type Curve(1) Gas rate Cumulate gas 17.7 mmcf/day design fits with our predicted type curve to hold production flat for ~2 years while still recovering all reserves in ~10 years – this is an optimal balance of capital If rate is 12 mmcf/d plateau is ~ 3years
Slide 14 — GAS MARKETING
14 GAS MARKETING OVERVIEW 14
Slide 15 — TYPICAL GAS TIE-IN PROCESS
15 TYPICAL GAS TIE-IN PROCESS 15 The tie in process is standard; applying learnings to reduce cycle times o Process very similar to Canada – same technology, different regulations and standards o Wet gas not typically transported in Germany, processing (dehydration) done at the wellsite o Permitting done in parallel allowing tie-in work to begin right after the well test o Facility is pre-designed in modular skids of optimal size for our type well, appropriate levels of capital invested early on to reduce cycle time post-drill o Utilize existing pipeline connections if available to limit capital and reduce construction time (Osterheide) o If required, pipeline construction is done in parallel to the facility construction (Wisselshorst)
Slide 16 — GERMANY INFRASTRUCTURE
16 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 16 Trench for Wisselshorst pipeline
Slide 17 — OPTIMIZING OSTERHEIDE GAS PRODUCTION
17 o Stable production since first gas, rates much higher than originally expected post-drill o Demand and blending capacity has exceeded expectations, working with third-party to maximize throughput o Recent acquisition provides control of infrastructure, should allow for higher production rates moving forward o Bottlenecks and restrictions are systematically worked through to remove them o Target gas as quickly as possible while working optimization options to avoid overcapitalization o Optimal strategy of production rates versus capital expenditure, leveraging existing pipeline infrastructure OPTIMIZING OSTERHEIDE GAS PRODUCTION Target production and revenue as fast as possible while systematically working to remove restrictions 17 ~8 mmcf/d First 12 Months Average Production from Osterheide >$30MM Excess FCF(1) Since Bringing Osterheide on Production
Slide 18 — GAS MARKETING
18 o Natural Gas Sales Agreement (“NGSA”) typical duration of 1 to 2 years then re-tendered to ensure maximum value o Price linked to THE benchmark which trades at a slight premium to TTF o Many potential buyers are active in Germany with large portfolios – significant interest for our gas o Sell 50/50 Day Ahead (“DA”) and Month Ahead (“MA”) to increase operational flexibility while maximizing value GAS MARKETING Significant buyer interest and competitive market results in THE-linked pricing with premium to TTF -0.50 - 0.50 1.00 1.50 2.00 2.50 3.00 Oct 21 Apr 22 Oct 22 Apr 23 Oct 23 Apr 24 Oct 24 Apr 25 Oct 25 Apr 26 €/MWh(1) Delivery month THE Premium to TTF THE-MA vs TTF-MA THE-DA vs TTF-DA 18
Slide 19 — INVENTORY &
19 INVENTORY & LONG-RANGE PLAN 19
Slide 20 — TRACK RECORD OF EXECUTION IN EUROPE
20 Leveraging decades of experience to unlock significant value from conventional assets TRACK RECORD OF EXECUTION IN EUROPE 20 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 21 — GERMANY ASSET ACQUISITION & LAND EXPANSION
21 Increasing operational scale and inventory depth in our key European gas growth asset GERMANY ASSET ACQUISITION & LAND EXPANSION 21 Gas-weighted, producing assets o Acquired ~1,000 boe/d (85% natural gas) of production and land adjacent to Osterheide well from Exxon affiliate Increased infrastructure control o Strategic value through increased control over gathering infrastructure surrounding our Osterheide well Exploration and development upside o Future upside on acquired land includes exploration drilling opportunities and operational synergies Addition of exploration acreage o Separate from the acquisition, added three land concessions offering potential upside for our deep gas exploration program
Slide 22 — CORE ACREAGE OFFSETTING LARGE DISCOVERIES
22 Small “e” exploration – finding gas where gas has been found 22 CORE ACREAGE OFFSETTING LARGE DISCOVERIES 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 23 — WISSELSHORST DISCOVERY
23 Vermilion’s largest discovery in over a decade is the latest significant discovery in the North German Basin Discovery Well 2P Reserves 67 Bcf Property Gross(1) 43 Bcf Gross to Vermilion WISSELSHORST DISCOVERY 23 Z2 Z3 Z1a Source: Petroleum Geological Atlas of the Southern Permian Basin Areas (2010), LBEG - “Erdgastabellen 1949-2024”, ESRI NORTH GERMAN BASIN
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(2) o Larger German prospects provide follow-up drilling opportunities
Slide 25 — INVENTORY FOR THE FUTURE
25 Laying the foundation… … for a decade-plus of development Resource Platform: > 1 million net acres(1), ~5000 mi2 3D seismic Massive acreage and data platform Growth Runway: 10 structures identified (and counting) > 10 years(3) of risked drilling inventory at two wells per year Early Validation: Discoveries in 2/3 exploration drills to date Repeatable exploration: adjacent analog pools delivering ~30 Bcf/well Significant Impact: Two (1.6 net) successes = ~60 bcf 2P reserves(2) Potential for significant reserve bookings across the next decade INVENTORY FOR THE FUTURE 25 Early success and disciplined development – a decade-long growth runway in Germany
Slide 26 — IMPACTFUL GERMANY WELLS
26 Germany exploration program provides meaningful long-duration cash flows IMPACTFUL GERMANY WELLS 26 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 Type curves reflect $3.50 AECO and $13.00 TTF Current pricing improves Germany economics, highlighting Vermilion’s unique ability to deploy capital to high-price commodity environments
Slide 27 — GERMANY OUTLOOK: ORGANIC GROWTH
27 Germany exploration program offers low-cost international exposure and long-duration EFCF GERMANY OUTLOOK: ORGANIC GROWTH 0 10 20 30 40 50 60 70 80 2023 2024 2025 2026 2027 2028 2029 2030+ MMCFE/D (NET) DEEP GAS PROGRAM PRODUCTION TIMELINE(1) Legacy Germany Deep Gas Success To-Date (1.6 net) Additional Wells 27 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) 2029+ Self-funded Growth & Capital Allocation Optionality EFCF generation Drilling and facility investment Production Forecast to Double by 2030 2.9 Net Wells of ~30 Gross Identified Prospects Grows VET European Gas Production to >110 mmcf/d(1)
Slide 28 — POSITIONED FOR EUROPEAN GAS GROWTH
28 28 POSITIONED FOR EUROPEAN GAS GROWTH ~105 mmcf/d European Gas Production in 2025 >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) More than offset by Germany growth Wisselshorst exploration success replaces production and reserves ~5,000 boe/d of organic growth (2026 - 2030)
Slide 29 — SUMMARY &
29 SUMMARY & KEY TAKEAWAYS 29
Slide 30 — KEY TAKEAWAYS
30 30 KEY TAKEAWAYS Focused on converting exploration success to meaningful long life EFCF growth Organic upside in Germany Robust development economics o $60MM NPV10(2), 4x payout, significant FCF generation at $13 European gas, current prices much higher Up to 30 high-impact locations identified o With success, 20 locations (risked) provide 10+ years(1) of drilling inventory, targeting 30+ Bcf prospects Progressing Bommelsen development o Building out infrastructure to facilitate production from initial discovery well and follow-up locations
Slide 31 — SLIDE NOTES
31 31 SLIDE NOTES 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. 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 months and year ended December 31, 2025, which information is incorporated by reference herein. Reserves Advisories Reserves estimates in this presentation are derived from an evaluation report dated March 3, 2026 with an effective date of December 31, 2025 are prepared by McDaniel & Associates Consultants Ltd. (the "McDaniel Report"), an independent qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. For a full description of the McDaniel Report, including the forecast price and cost assumptions used therein, please refer to Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2025. This presentation includes reference to certain metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Readers are cautioned as to the reliability of oil and gas metrics used in this presentation. These oil and gas metrics includes “DCET costs" and "decline rates". DCET costs includes all capital spent to drill, complete, equip and tie-in a well. Management uses these oil and gas metrics for its own performance measurements and to provide readers with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance, which may not compare to the Company's performance in previous periods, and therefore should not be unduly relied upon. Additional oil and gas metrics in this document may include, but are not limited to: Boe Equivalency: Certain natural gas volumes have been converted on the basis of six thousand cubic feet of gas to one barrel of oil. Barrels of oil equivalent (boes) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion of six thousand cubic feet of gas to one barrel of oil may be misleading as an indicator of value as the value ration between conventional natural gas and crude oil, based on the prices of natural gas and crude oil, differ significantly from the energy equivalency of six million cubic feet to one barrel of oil. Disclaimer: Estimates of drilling locations Drilling inventory reflects company estimates of future drilling locations and expected pace of future development, and includes locations evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") as well as unbooked locations. McDaniel has evaluated the Osterheide Z2-2 and Wisselshorst Z1a wells as part of Vermilion’s reserve report for the year ended December 31, 2025. The remainder of locations are unbooked. Unbooked drilling locations are the internal estimates of Vermilion based on Vermilion's prospective acreage and internal review of potential locations. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Vermilion's management as an estimation of Vermilion's multi- year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Vermilion will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Vermilion will actually drill wells, including the number and timing thereof, is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management of Vermilion has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Disclaimer: Multi-year estimates Elements of company 2026-2030 forecast derived by utilizing, among other assumptions, historical Vermilion production performance and current cost assumptions, adjusted annually after 2026. 2027 and beyond provided for illustrative purposes only. Budgets and forecast beyond 2026 have not been finalized and are subject to a variety of factors including prior year’s results. Included in this presentation are estimates of the Company's 2026-2030 production, excess free cash flow and excess free cash flow per share which are based on various assumptions as to business unit production levels, commodity prices, the anticipated receipt of drilling permits and other assumptions and in the case of the years other than 2026, such estimates are provided for illustrative purposes only. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in December 2025 and are included to provide readers with an understanding of the Company's anticipated excess free cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. Slide 2 (1) Source: Landesamt für Bergbau, Energie und Geologie (“LBEG”) data. (2) Source: LBEG data. Slide 3 (1) Source: IEA Germany - Countries & Regions - IEA. (2) Source: IEA Germany - Countries & Regions - IEA Slide 5 (1) 2014-2025 reflects actual production, estimates for 2026e based on Company estimates as at May 4, 2026. Slide 6 (1) Reported 2025 financial and operational results for Germany. Fund flows from operations 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 months and year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. (2) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. Germany acreage includes acreage associated with three concessions awarded in Q1 2026. For additional detail, refer to Vermilion press release dated April 7, 2026. (3) Based on company estimates as at May 4, 2026. Slide 12 (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 13 (1) Type curve, including production rates, production profile and estimated ultimate recovery based on internal estimates as at December 9, 2025. Slide 17 (1) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three months ended March 31, 2026, available on SEDAR+ at www.sedarplus.ca. Osterheide EFCF as of May 6, 2026. Slide 18 (1) THE/TTF basis by month as of April 2026.
Slide 32 — SLIDE NOTES
32 32 SLIDE NOTES Slide 20 (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 23 (1) Total proved plus probable conventional natural gas reserves at December 31, 2025, as evaluated by McDaniel, a qualified reserves evaluator, in a report dated March 3, 2026 with an effective date of December 31, 2025 (the “McDaniel Reserves Report”). Gross reserves reflect 64% working interest in Wisselshorst Z1a well. Slide 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) Acreage as per Vermilion’s Annual Information Form (“AIF”) for the year ended December 31, 2025, available on SEDAR+ at www.sedarplus.ca. Germany acreage includes acreage associated with three concessions awarded in Q1 2026. For additional detail, refer to Vermilion press release dated April 7, 2026. (2) Total proved plus probable conventional natural gas reserves at December 31, 2025, as evaluated by McDaniel, a qualified reserves evaluator, in a report dated March 3, 2026 with an effective date of December 31, 2025 (the “McDaniel Reserves Report”). Gross reserves reflect 64% working interest in Wisselshorst Z1a well. (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 26 (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 flat US$70 WTI / $3.50 AECO / €28/MWh European gas pricing assumptions. (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 flat US$70 WTI / $3.50 AECO / €28/MWh European gas pricing assumptions. Slide 27 (1) 2022-2025 reflects actual production. Company 2026-2030 forecast as of December 9, 2025, refer to the disclaimer on multi-year estimates. (2) Excess free cash flow (“EFCF”) is a non-GAAP financial measure, refer to the "Non-GAAP Financial Measures and Other Specified Financial Measures" section in Vermilion’s MD&A for the three months ended March 31, 2026, available on SEDAR+ at www.sedarplus.ca. Slide 28 (1) Company 2026-2030 forecast as of December 9, 2025, refer to the disclaimer on multi-year estimates. Slide 31 (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) NPV10 represents the total present value of future cash flows, discounted back to their present value using a 10% discount rate. 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 flat US$70 WTI / $3.50 AECO / €28/MWh European gas pricing assumptions.