6-K - VET - Equibles

UNITEDSTATES

SECURITIESAND EXCHANGE COMMISSION

Washington,D.C. 20549

FORM6-K

REPORTOF FOREIGN PRIVATE ISSUER

Pursuantto Rule 13a-16 or 15d-16

Underthe Securities Exchange Act of 1934

Forthe month of July 2024

Commission File Number: 001-35829

VermilionEnergy Inc.

(Exact name of registrant as specified in its charter)

3500,520 – 3^rd^ Avenue S.W., Calgary, Alberta T2P 0R3

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form<br> 20-F ☐	Form<br> 40-F ☒

Exhibit

Exhibit	Description
99.1	Q2<br> 2024 Report
99.2	CEO Certificate
99.3	CFO Certificate

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VERMILION ENERGY INC.

By:	/s/ Lars Glemser
Title:	Lars Glemser, VP and Chief Financial Officer

Date: July 31, 2024

Exhibit 99.1

Disclaimer

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: capital expenditures and Vermilion’s ability to fund such expenditures; Vermilion’s additional debt capacity providing it with additional working capital; statements regarding the return of capital; the flexibility of Vermilion’s capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion’s 2024 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange and inflation rates; significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion’s future project inventory, wells expected to be drilled in 2024; exploration and development plans and the timing thereof; Vermilion’s ability to reduce its debt; statements regarding Vermilion’s hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion’s hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion’s expectations regarding future taxes and taxability; 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 document, assumptions have been made regarding, among other things: 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; and 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 earnings/(loss) and adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; 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 document or in Vermilion's other filings with Canadian securities regulatory authorities.

This document contains references to sustainability/ESG data and performance that reflect metrics and concepts that are commonly used in such frameworks as the Global Reporting Initiative, the Task Force on Climate-related Financial Disclosures, and the Sustainability Accounting Standards Board. Vermilion has used best efforts to align with the most commonly accepted methodologies for ESG reporting, including with respect to climate data and information on potential future risks and opportunities, in order to provide a fuller context for our current and future operations. However, these methodologies are not yet standardized, are frequently based on calculation factors that change over time, and continue to evolve rapidly. Readers are particularly cautioned to evaluate the underlying definitions and measures used by other companies, as these may not be comparable to Vermilion’s. While Vermilion will continue to monitor and adapt its reporting accordingly, the Company is not under any duty to update or revise the related sustainability/ESG data or statements except as required by applicable securities laws.

The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.

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This document contains 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. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) 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.

Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.

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Abbreviations

$M	thousand dollars
$MM	million dollars
AECO	the daily average benchmark price for natural gas at the AECO ‘C’ hub in Alberta
bbl(s)	barrel(s)
bbls/d	barrels per day
boe	barrel of oil equivalent, including: crude oil, condensate, natural gas liquids, and natural gas (converted on the basis of one boe for six mcf of natural gas)
boe/d	barrel of oil equivalent per day
GJ	gigajoules
LSB	light sour blend crude oil reference price
mbbls	thousand barrels
mcf	thousand cubic feet
mmcf/d	million cubic feet per day
NBP	the reference price paid for natural gas in the United Kingdom at the National Balancing Point Virtual Trading Point
NCIB	normal-course issuer bid
NGLs	natural gas liquids, which includes butane, propane, and ethane
PRRT	Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia
tCO2e	tonnes of carbon dioxide equivalent
THE	the price for natural gas in Germany, quoted in megawatt hours of natural gas, at the Trading Hub Europe
TTF	the price for natural gas in the Netherlands, quoted in megawatt hours of natural gas, at the Title Transfer Facility Virtual Trading Point
WTI	West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma

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Highlights

•	Production during Q2 2024 averaged 84,974<br>boe/d^(8)^(53% natural gas and 47% crude oil and liquids), comprised of 54,987 boe/d^(8)^ from our North American assets<br>and 29,987 boe/d^(8)^ from our International assets. Production for the quarter was at the upper end of our Q2 2024 guidance<br>range and represents an increase of 2% year-over-year, and 6% year-over-year on a per share basis, primarily due to Australia, as well<br>as the start-up of the 8-33 BC battery on our Mica Montney asset, which facilitated higher production from our recent 16-28 BC Montney<br>wells.
•	Given the strong operational performance<br>year-to-date, and anticipation of new production growth during the second half of the year in Mica and Croatia offsetting planned downtime,<br>we are increasing our annual production guidance to 83,000 to 86,000 boe/d (from 82,000 to 86,000 boe/d previously), while maintaining<br>our capital budget guidance of $600 to $625 million.
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•	Q2 2024 fund flows from operations (“FFO”)^(1)^<br>was $237 million ($1.48/basic share)^(2)^ and exploration and development (“E&D”) capital expenditures^(3)^<br>were $111 million, resulting in free cash flow (“FCF”)^(4)^ of $126 million ($0.79/basic share)^(5)^. The<br>decrease in FFO from the prior quarter (Q1 2024 - $431 million) was primarily driven by lower realized commodity hedge gains.
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•	Vermilion returned $66 million to shareholders<br>during Q2 2024, comprised of $19 million of dividends and $47 million of share buybacks, representing 62% of excess FCF ("EFCF")^(4)^.<br>We repurchased and cancelled 2.8 million shares during Q2 2024 and plan to maintain a robust pace of share buybacks in the months ahead<br>as we manage towards an annual return of capital target of 50% of EFCF. We have repurchased and cancelled 6.1 million shares year-to-date,<br>and have reduced our outstanding common shares to 157.3 million at July 31, 2024.
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•	Net debt^(6)^ decreased by $38<br>million in Q2 2024 to $907 million, representing a net debt to trailing FFO ratio^(7)^ of 0.7 times and the lowest debt level<br>in over a decade.
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•	In conjunction with our Q2 2024 release,<br>we announced a quarterly cash dividend of $0.12 per share, payable on October 15, 2024 to shareholders of record on September 27, 2024.
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•	In Germany, we are currently equipping<br>our first deep gas exploration well with production tubing in advance of a planned well test later this quarter. We continue to prepare<br>for tie-in operations for this well, with an anticipated on-stream date of early 2025. We plan to commence drilling on the second exploration<br>well (0.6 net) in the coming weeks.
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•	On the SA-10 block in Croatia, we completed<br>construction of the gas plant and tied in the first of the two standing wells in late Q2 2024. The second well was tied in early Q3 2024<br>and production is ramping up, increasing our exposure to strong European natural gas prices.
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•	On the SA-7 block in Croatia, we drilled<br>one (0.6 net) exploration well and completed two (1.2 net) wells from the prior quarter. The first well tested over 300 bbls/d^(15)^<br>of light oil, while the second well tested at 4.5 mmcf/d^(15)^ of natural gas. Subsequent to the quarter we completed drilling<br>on the final well (0.6 net) of this four well program, and discovered hydrocarbons across multiple zones, representing a 100% success<br>rate on this four-well exploration drilling campaign.
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•	In Canada, construction of the 16,000 boe/d<br>BC Montney battery was completed during the quarter, with wells from our 16-28 pad tied-in prior to start-up. The completion of this battery<br>was an important milestone in our BC Montney development and provides a runway for future production growth on our Montney asset. We anticipate<br>the wells from our recently completed 9-21 BC pad to be on line by late Q3 2024. These wells were completed in significantly less time<br>than previous wells and used approximately 30% less water, resulting in approximately 15% completion cost savings as we continue to drive<br>efficiencies in our Mica Montney operations.
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•	We<br> released the annual update to our sustainability reporting in July 2024. Our 2023 Scope 1<br> emission intensity is in line with our target to reduce our 2019 baseline by 15% to 20% by<br> 2025. The full report is available at https://www.vermilionenergy.com/sustainability.
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| --- | | (M except as indicated) | Q1 2024 | Q2 2023 | YTD 2024 | YTD 2023 | | --- | --- | --- | --- | --- | | Financial | | | | | | Petroleum and natural gas sales | 508,035 | 471,356 | 986,960 | 1,024,054 | | Cash flows from operating activities | 354,295 | 173,632 | 620,617 | 562,261 | | Fund flows from operations (1) | 431,358 | 247,109 | 668,061 | 500,276 | | Fund flows from operations (/basic share) (2) | 2.68 | 1.51 | 4.16 | 3.05 | | Fund flows from operations (/diluted share) (2) | 2.64 | 1.48 | 4.11 | 2.99 | | Net earnings (loss) | 2,305 | 127,908 | (80,120) | 508,240 | | Net earnings (loss) (/basic share) | 0.01 | 0.78 | (0.50) | 3.10 | | Cash flows used in investing activities | 181,343 | 164,404 | 334,368 | 273,099 | | Capital expenditures (3) | 190,442 | 166,845 | 301,052 | 321,665 | | Acquisitions (9) | 9,752 | (9,716) | 15,202 | 242,056 | | Dispositions | - | - | - | 182,152 | | Asset retirement obligations settled | 4,975 | 11,893 | 16,720 | 14,447 | | Repurchase of shares | 36,409 | 24,316 | 82,964 | 54,457 | | Cash dividends (/share) | 0.12 | 0.10 | 0.24 | 0.20 | | Dividends declared | 19,183 | 16,430 | 38,164 | 32,656 | | % of fund flows from operations (10) | 4 % | 7 % | 6 % | 7 % | | Payout (12) | 214,600 | 195,168 | 355,936 | 368,768 | | % of fund flows from operations (11) | 50 % | 79 % | 53 % | 74 % | | Free cash flow (4) | 240,916 | 80,264 | 367,009 | 178,611 | | Long-term debt | 933,506 | 913,785 | 915,364 | 913,785 | | Net debt (6) | 944,496 | 1,321,100 | 906,715 | 1,321,100 | | Net debt to four quarter trailing fund flows from operations (7) | 0.7 | 1.0 | 0.7 | 1.0 | | Operational | | | | | | Production (8) | | | | | | Crude oil and condensate (bbls/d) | 32,695 | 29,342 | 32,787 | 31,305 | | NGLs (bbls/d) | 7,046 | 6,538 | 7,121 | 7,213 | | Natural gas (mmcf/d) | 274.59 | 283.63 | 271.99 | 265.72 | | Total (boe/d) | 85,505 | 83,152 | 85,240 | 82,805 | | Average realized prices | | | | | | Crude oil and condensate (/bbl) | 104.26 | 96.64 | 106.49 | 97.66 | | NGLs (/bbl) | 34.16 | 28.11 | 32.87 | 32.53 | | Natural gas (/mcf) | 6.10 | 7.37 | 5.90 | 8.94 | | Production mix (% of production) | | | | | | % priced with reference to WTI | 32 % | 32 % | 32 % | 35 % | | % priced with reference to Dated Brent | 15 % | 12 % | 15 % | 11 % | | % priced with reference to AECO | 32 % | 33 % | 33 % | 34 % | | % priced with reference to TTF and NBP | 21 % | 23 % | 21 % | 20 % | | Netbacks (/boe) | | | | | | Operating netback (12) | 62.07 | 43.66 | 51.44 | 44.98 | | Fund flows from operations (/boe) (13) | 53.86 | 32.35 | 42.61 | 33.43 | | Average reference prices | | | | | | WTI (US /bbl) | 76.96 | 73.80 | 78.76 | 74.97 | | Dated Brent (US /bbl) | 83.24 | 78.39 | 84.09 | 79.83 | | AECO (/mcf) | 2.50 | 2.45 | 1.84 | 2.84 | | TTF (/mcf) | 11.77 | 15.04 | 12.69 | 19.03 | | Share information ('000s) | | | | | | Shares outstanding - basic | 159,859 | 164,294 | 158,174 | 164,294 | | Shares outstanding - diluted (14) | 164,044 | 168,530 | 161,672 | 168,530 | | Weighted average shares outstanding - basic | 161,221 | 164,997 | 160,373 | 163,798 | | Weighted average shares outstanding - diluted (14) | 163,648 | 167,364 | 162,022 | 167,343 |

All values are in US Dollars.

^(1)^

Fund flows from operations (FFO) is a total of segments measure comparable to net (loss) earnings that is comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, equity based compensation settled in cash, realized gain (loss) on derivatives, realized foreign exchange gain (loss), and realized other income (expense). The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations, and make capital investments. FFO does not have a standardized meaning under IFRS and therefore may not be comparable to similar measures provided by other issuers. More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

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^(2)^

Fund flows from operations per share (basic and diluted) are supplementary financial measures and are not standardized financial measures under IFRS, and therefore may not be comparable to similar measures disclosed by other issuers. They are calculated using FFO (a total of segments measure) and basic/diluted shares outstanding. The measure is used to assess the contribution per share of each business unit. More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(3)^	Capital expenditures is a non-GAAP financial measure that is the sum of drilling and development costs<br>and exploration and evaluation costs from the Consolidated Statements of Cash Flows. More information and a reconciliation to primary<br>financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(4)^

Free cash flow (FCF) and excess free cash flow (EFCF) are non-GAAP financial measures comparable to cash flows from operating activities. FCF is comprised of FFO less drilling and development and exploration and evaluation expenditures and EFCF is FCF less payments on lease obligations and asset retirement obligations settled. More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(5)^	Free cash flow per basic share is a non-GAAP supplementary financial measure and is not a standardized<br>financial measure under IFRS and may not be comparable to similar measures disclosed by other issuers. It is calculated using FCF and<br>basic shares outstanding.

^(6)^

Net debt is a capital management measure comparable to long-term debt and is comprised of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current lease liabilities). More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(7)^

Net debt to four quarter trailing fund flows from operations is a supplementary financial measure and is not a standardized financial measure under IFRS. It may not be comparable to similar measures disclosed by other issuers and is calculated using net debt (capital management measure) and FFO (total of segment measure). The measure is used to assess the ability to repay debt. Information in this document is included by reference; refer to the "Non-GAAP and Other Specified Financial Measures" section of this document.

^(8)^	Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion<br>and Analysis for disclosure by product type.

^(9)^

Acquisitions is a non-GAAP financial measure that is calculated as the sum of acquisitions and acquisitions of securities from the Consolidated Statements of Cash Flows, Vermilion common shares issued as consideration, the estimated value of contingent consideration, the amount of acquiree's outstanding long-term debt assumed, and net acquired working capital. More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(10)^

Dividends % of FFO is a supplementary financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers, calculated as dividends divided by FFO. The ratio is used by management as a metric to assess the cash distributed to shareholders. Reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(11)^

Payout and payout % of FFO are a non-GAAP financial measure and a non-GAAP ratio, respectively, that are not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers. Payout is comparable to dividends declared and is comprised of dividends declared plus drilling and development costs, exploration and evaluation costs, and asset retirement obligations settled, while the ratio is calculated as payout divided by FFO. More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(12)^	Operating netback is a non-GAAP financial measure comparable to net earnings<br>and is comprised of sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses. More information<br>and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures”<br>section of this document.

^(13)^

Fund flows from operations per boe is a supplementary financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers, calculated as FFO by boe production. Fund flows from operations per boe is used by management to assess the profitability of our business units and Vermilion as a whole. More information and a reconciliation to primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

^(14)^	Diluted shares outstanding represent the sum of shares outstanding at the period end plus outstanding<br>awards under the Long-term Incentive Plan (“LTIP”), based on current estimates of future performance factors and forfeiture<br>rates.

^(15)^

Zbjegovaca-1 Istok well (60% working interest) tested at an average rate of 314 bbls/d during a 14-hour flow period with an average flowing wellhead pressure of 54psi on a 0.75 inch diameter choke. The flow test continued an additional 16 hours at reduced choke sizes (0.625” and 0.5”) to obtain necessary reservoir information and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1077psi and bottom hole pressure of 2828psi were recorded following the flow test. The tested zone was the Okoli formation which was encountered at at 1991mMD and a 47.5m oil column was logged with 12m of net reservoir and average effective porosity of 14%. Additional untested formations were also discovered. The Poljana was encountered at 1838mMD and a 63m oil column was logged with 39m of net reservoir and an average porosity of 11%, the Bujavica was encountered at 1194mMD and a 26m gas column was logged with 15.8m of net reservoir and average porosity of 21%. The test results are not necessarily indicative of long-term performance or ultimate recovery.

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Meduric-1 Istok well (60% working interest) tested at an average rate of 4.5 mmcf/d during a 2.5-hour flow period with a stabilized flowing wellhead pressure of 653psi on a 0.5 inch diameter choke. The flow test continued an additional 19 hours at reduced choke sizes (0.25”, 0.3125”, 0.375”) to obtain necessary reservoir data and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1639psi and bottom hole pressure of 1784psi were recorded following the flow test. The tested zone was the Poljana formation which was encountered at 1236mMD and a 16m gas column was logged with 11.7m of net reservoir and an average porosity of 21%. Additional, untested formation were also discovered. The Bregi was encountered at 981mMD and a 23m gas column was logged with 13m of net reservoir and an average porosity of 27%, the Kutinski was encountered at 594mMD and a 14m gas column was logged with 10m of net reservoir and an average porosity of 32%. The test results are not necessarily indicative of long-term performance or ultimate recovery.'

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Message to Shareholders

During the second quarter we achieved key operational milestones with the completion and startup of the Mica Montney battery in British Columbia and the SA-10 gas plant in Croatia. In Canada, we completed the Mica Montney battery and tied in production from the 16-28 pad during the second quarter, and subsequent to the quarter we completed fracking operations on the 9-21 pad which we expect to bring online in late Q3 2024. The startup of the Mica Montney battery will allow us to nearly double our Montney production to approximately 14,000 boe/d in 2025 and provides the platform for future expansion to 28,000 boe/d with further de-bottlenecking of infrastructure in the coming years. In Croatia, we commissioned the gas plant on the SA-10 block slightly ahead of schedule and currently have both wells on production. Bringing these wells on production will support the European gas weighting in our portfolio - approximately 40% of our corporate natural gas production, or over 100 mmcf/d

and allows us to take advantage of strong natural gas prices in Croatia, where gas sells at a premium to other European natural gas benchmarks. Over the past two years we have grown our European natural gas production by over 15%, and we continue to organically grow our European natural gas franchise. TTF Day Ahead natural gas prices averaged $13.62/mmbtu in Q2 2024, representing a 16% increase over Q1 2024, and are expected to further strengthen in the second half of this year and 2025, based on the forward strip. The TTF forward price is currently trading at approximately $17/mmbtu for 2025, which we have been actively hedging. For 2025 we have approximately 42% of our European natural gas production hedged at an average floor price of $17/mmbtu.

We are also pleased to report test results from the first two wells on the SA-7 exploration block in Croatia. The first well tested over 300 bbls/d^(2)^ of light oil, while the second well tested at 4.5 mmcf/d^(2)^ of natural gas. We recently completed drilling the fourth well of our SA-7 exploration program and are pleased to report that we discovered gas in this well, representing 100% success rate on our four-well exploration drilling campaign. We plan to test the remaining two wells in the second half of 2024 while evaluating our future development plans for this block. These four new discoveries are very encouraging as they serve to prove up our exploration land and validate our geological evaluations, while setting the foundation for future growth in Croatia. In Germany, we are currently equipping our first deep gas exploration well with production tubing in advance of a planned well test later this quarter. Drilling of the second deep gas exploration well in Germany will commence in the coming weeks and is expected to extend into the fourth quarter. We are excited about the long-term development potential of our Germany and Croatia assets and expect these two countries to provide organic growth in the years ahead.

Production during the second quarter averaged 84,974 boe/d which was at the upper end of our quarterly production guidance range and represents an increase of 2% year-over-year, and 6% year-over-year on a per share basis, primarily due to Australia, as well as the start-up of the 8-33 BC battery on our Mica Montney asset, which facilitated higher production from our recent 16-28 BC Montney wells. We generated $237 million of fund flows from operations (“FFO”) during the second quarter and invested $111 million of E&D capital, resulting in free cash flow (“FCF”) of $126 million. During the second quarter we significantly increased our pace of share buybacks as we transitioned to a return of capital payout target of 50% of annual excess FCF (“EFCF”) beginning March 2024. We repurchased 2.8 million shares during Q2 2024 for total proceeds of $47 million and also paid out approximately $19 million in dividends for a total return of $66 million or 62% of EFCF. We have repurchased and cancelled 6.1 million shares year-to-date, and have reduced our outstanding common shares to 157.3 million at July 31, 2024. With the remaining EFCF being used primarily for debt reduction, our net debt decreased $38 million in the quarter to $907 million at the end of Q2 2024, representing a net debt to trailing FFO ratio of 0.7 times.

As a result of consistently strong operational performance across our asset base, production for the first half of the year averaged 85,240 boe/d, trending towards the upper end of our budgeted annual guidance range of 82,000 to 86,000 boe/d. With the startup of our new Mica Montney battery and Croatia gas plant we expect to ramp up production from these assets during the second half of the year, which will be partially muted by planned maintenance downtime and natural decline in other assets. Given the strong operational performance year-to-date, and anticipation of new production growth during the second half of the year in Mica and Croatia offsetting planned downtime, we have increased our annual production guidance to 83,000 to 86,000 boe/d, while maintaining our capital budget guidance of $600 to $625 million.

Q2 2024 Operations Review

North America

Production from our North American operations averaged 54,987 boe/d^(1)^ in Q2 2024, an increase of 4% from the previous quarter due to new production from our recent BC Mica Montney wells.

At Mica, we drilled one (1.0 net) and brought on production six (6.0 net) BC Montney liquids-rich shale gas wells in advance of the start-up of our 8-33 BC battery in late Q2 2024. In Saskatchewan, we drilled two (2.0 net) and completed one (1.0 net) light and medium crude oil wells, while in the United States we participated in the drilling and completion of five (0.2 net) non-operated light and medium crude oil wells.

Construction of the 16,000 boe/d 8-33 BC Montney battery was completed during the quarter. The completion of this battery was an important milestone in our BC Montney development as it provides the runway for future production growth on our Montney asset. During the second quarter we brought on production six (6.0 net) new wells from our 16-28 pad prior to start-up of the new battery, producing into existing infrastructure in order to optimize liquids production from the field. As a result, initial production from the new 16-28 wells was constrained due to limited throughput capacity and the commissioning of the new battery. Construction of our water hub infrastructure adjacent to the 8-33 battery was completed subsequent to the quarter. The startup of this water hub is expected to allow for up to 55% recycling of our water needs and reduce capital costs by approximately $650,000 per well. Our most recent wells on the 9-21 pad were completed in significantly less time than previous wells and used approximately 30% less water, resulting in approximately 15% completion cost savings as we continue to drive efficiencies in our Mica Montney operations.

| Vermilion Energy Inc.  ■  Page 8  ■  2024 Second Quarter Report |

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International

Production from our International operations averaged 29,987 boe/d^(1)^ in Q2 2024, a decrease of 8% from the previous quarter primarily due to natural declines and planned maintenance in Germany and Ireland.

In Germany, operations were focused on the successful discovery on our first deep gas exploration well where testing was rescheduled to Q3 2024. We continue to prepare for tie-in operations of the first well and have procured longer lead time components as we work towards an anticipated on-stream date of early 2025. We plan to commence drilling on the second deep gas exploration well (0.6 net) in the coming weeks. The second well is a higher risk prospect targeting a very large structure that is expected to take three to four months to drill. Success on this prospect could allow for follow-up development given the size of the target structure.

In Croatia, we completed construction of the gas plant on the SA-10 block in Q2 2024 and we commissioned the plant in late June. Both of the previously drilled gas wells are currently on production and ramping up which will increase our exposure to high netback European natural gas. On the SA-7 block, we drilled one (0.6 net) exploration well and completed two (1.2 net) wells from the prior quarter. The first well tested over 300 bbls/d^(2)^ of light oil, while the second well tested at 4.5 mmcf/d^(2)^ of natural gas. Subsequent to the quarter, we also completed drilling on the final well (0.6 net) of this four well program, and discovered hydrocarbons across multiple zones, representing a 100% success rate on our four-well exploration drilling campaign. Three of these four wells are natural gas wells, aligning with our intention to organically grow our European natural gas franchise. Testing operations on the remaining two wells are planned for the second half of 2024, while we continue to move forward with the permitting process and evaluating the long-term development potential of the SA-7 block.

Outlook and Guidance Update

Full-year production guidance has been increased to 83,000 to 86,000 boe/d (from 82,000 to 86,000 boe/d previously), reflecting our strong operational performance year-to-date. Our Q3 2024 capital program includes completing and bringing on production the five (5.0 net) wells from the 9-21 pad in the BC Montney and commencing our 2H 2024 drilling program in Alberta and Saskatchewan. In addition, we will commence drilling operations on the second exploration well in Germany while we conduct further evaluation and testing of the successful exploration wells in Germany and Croatia. We expect Q3 2024 production to be in the range of 83,000 to 85,000 boe/d taking into account the approximately 1,200 boe/d impact of planned turnaround activity, including a third-party turnaround deferred from Q2 2024, hot weather-related limitations impacting production, and the shut-in of approximately 800 boe/d of dry gas production in Alberta due to low gas prices. All other financial guidance remains unchanged.

Commodity Hedging

Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows. In aggregate, as of July 31, 2024, we have 39% of our expected net-of-royalty production hedged for the remainder of 2024. With respect to individual commodity products, we have hedged 44% of our European natural gas production, 43% of our crude oil production, and 31% of our North American natural gas volumes, respectively. Please refer to the Hedging section of our website under Invest With Us for further details using the following link:

https://www.vermilionenergy.com/invest-with-us/hedging.

(Signed “Dion Hatcher”)
Dion Hatcher
President & Chief Executive Officer
July 31, 2024

^(1)^	Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion<br>and Analysis for disclosure by product type.

| Vermilion Energy Inc.  ■  Page 9  ■  2024 Second Quarter Report |

| --- | | ^(2)^ | Zbjegovaca-1 Istok well (60% working interest) tested at an average rate of 314 bbls/d during a 14-hour flow period with an average flowing wellhead pressure of 54psi on a 0.75 inch diameter choke. The flow test continued an additional 16 hours at reduced choke sizes (0.625” and 0.5”) to obtain necessary reservoir information and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1077psi and bottom hole pressure of 2828psi were recorded following the flow test. The tested zone was the Okoli formation which was encountered at at 1991mMD and a 47.5m oil column was logged with 12m of net reservoir and average effective porosity of 14%. Additional untested formations were also discovered. The Poljana was encountered at 1838mMD and a 63m oil column was logged with 39m of net reservoir and an average porosity of 11%, the Bujavica was encountered at 1194mMD and a 26m gas column was logged with 15.8m of net reservoir and average porosity of 21%. The test results are not necessarily indicative of long-term performance or ultimate recovery. | | --- | --- |

| Vermilion Energy Inc.  ■  Page 10  ■  2024 Second Quarter Report |

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Non-GAAP and Other Specified Financial Measures

This report and other materials released by Vermilion includes financial measures that are not standardized, specified, defined, or determined under 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 financial measures include:

Total of Segments Measures

Fund flows from operations (FFO): Most directly comparable to net (loss) earnings, FFO is comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, equity based compensation settled in cash, realized gain (loss) on derivatives, realized foreign exchange gain (loss), and realized other income (expense). The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.

	Q2 2024		Q2 2023		YTD 2024		YTD 2023
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	478,925	62.46	471,356	61.74	986,960	62.97	1,024,054	68.42
Royalties	(46,610)	(6.08)	(46,993)	(6.16)	(95,163)	(6.07)	(114,337)	(7.64)
Transportation	(25,317)	(3.30)	(21,905)	(2.87)	(48,279)	(3.08)	(44,955)	(3.00)
Operating	(140,230)	(18.29)	(136,749)	(17.91)	(289,541)	(18.47)	(273,574)	(18.28)
General and administration	(26,537)	(3.46)	(20,058)	(2.63)	(50,240)	(3.21)	(39,947)	(2.67)
Corporate income tax expense	(12,096)	(1.58)	(18,928)	(2.48)	(37,738)	(2.41)	(41,190)	(2.75)
Windfall taxes	-	-	(34,784)	(4.56)	-	-	(56,224)	(3.76)
PRRT	(3,638)	(0.47)	-	-	(14,421)	(0.92)	-	-
Interest expense	(21,062)	(2.75)	(20,210)	(2.65)	(39,454)	(2.52)	(42,085)	(2.81)
Equity based compensation	(14,361)	(1.87)	-	-	(14,361)	(0.92)	-	-
Realized gain on derivatives	46,017	6.00	67,673	8.86	266,632	17.01	82,003	5.48
Realized foreign exchange gain (loss)	2,267	0.30	3,679	0.48	4,138	0.26	(1,092)	(0.07)
Realized other income	(655)	(0.09)	4,028	0.53	(472)	(0.03)	7,623	0.51
Fund flows from operations	236,703	30.87	247,109	32.35	668,061	42.61	500,276	33.43
Equity based compensation	3,860		(4,998)		(1,658)		(28,523)
Unrealized (loss) gain on derivative instruments ^(1)^	(125,789)		11,177		(314,533)		103,875
Unrealized foreign exchange gain (loss) ^(1)^	3,069		35,124		(18,572)		19,646
Accretion	(18,209)		(18,599)		(36,143)		(38,650)
Depletion and depreciation	(161,184)		(154,389)		(339,618)		(302,520)
Deferred tax (expense) recovery	(20,667)		480		(37,312)		36,946
Gain on business combination	-		12,544		-		445,094
Loss on disposition	-		-		-		(226,828)
Unrealized other expense	(208)		(540)		(345)		(1,076)
Net (loss) earnings	(82,425)		127,908		(80,120)		508,240
^(1)^	Unrealized (loss) gain on derivative instruments, Unrealized foreign exchange gain (loss), and Unrealized<br>other expense are line items from the respective Consolidated Statements of Cash Flows.
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Non-GAAP Financial Measures and Non-GAAP Ratios

Free cash flow (FCF) and excess freecash flow (EFCF): Most directly comparable to cash flows from operating activities, FCF is comprised of fund flows from operations less drilling and development costs and exploration and evaluation cost and EFCF is comprised of FCF less payments on lease obligations and asset retirement obligations settled. The measure is used to determine the funding available for investing and financing activities including payment of dividends, repayment of long-term debt, reallocation into existing business units and deployment into new ventures. EFCF is used to determine the funding available to return to shareholders after costs attributable to normal business operations.

| Vermilion Energy Inc.  ■  Page 11  ■  2024 Second Quarter Report |

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($M)	Q2 2024	Q2 2023	2024	2023
Cash flows from operating activities	266,322	173,632	620,617	562,261
Changes in non-cash operating working capital	(41,364)	61,584	30,724	(76,432)
Asset retirement obligations settled	11,745	11,893	16,720	14,447
Fund flows from operations	236,703	247,109	668,061	500,276
Drilling and development	(109,350)	(164,070)	(291,648)	(317,398)
Exploration and evaluation	(1,260)	(2,775)	(9,404)	(4,267)
Free cash flow	126,093	80,264	367,009	178,611
Payments on lease obligations	(7,830)	(4,665)	(11,932)	(9,064)
Asset retirement obligations settled	(11,745)	(11,893)	(16,720)	(14,447)
Excess free cash flow	106,518	63,706	338,357	155,100

Adjusted working capital: Defined as current assets less current liabilities, excluding current derivatives and current lease liabilities. The measure is used to calculate net debt, a capital measure disclosed above.

	As at
($M)	Jun 30, 2024	Dec 31, 2023
Current assets	740,882	823,514
Current derivative asset	(97,165)	(313,792)
Current liabilities	(679,478)	(696,074)
Current lease liability	28,136	21,068
Current derivative liability	16,274	732
Adjusted working capital	8,649	(164,552)

Capital expenditures: Calculated as the sum of drilling and development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows and most directly comparable to cash flows used in investing activities. We consider capital expenditures to be a useful measure of our investment in our existing asset base. Capital expenditures are also referred to as E&D capital.

($M)	Q2 2024	Q2 2023	2024	2023
Drilling and development	109,350	164,070	291,648	317,398
Exploration and evaluation	1,260	2,775	9,404	4,267
Capital expenditures	110,610	166,845	301,052	321,665

Operating netback: Most directly comparable to net (loss) earnings and is calculated as sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses presented on a per unit basis. Management assesses operating netback as a measure of the profitability and efficiency of our field operations.

Payout and payout % of FFO: A non-GAAP financial measure and non-GAAP ratio respectively most directly comparable to dividends declared. Payout is comprised of dividends declared plus drilling and development costs, exploration and evaluation costs, and asset retirement obligations settled. The measure is used to assess the amount of cash distributed back to shareholders and reinvested in the business for maintaining production and organic growth. The reconciliation of the measure to primary financial statement measure can be found below. Management uses payout and payout as a percentage of FFO (also referred to as the payout or sustainability ratio).

($M)	Q2 2024	Q2 2023	2024	2023
Dividends Declared	18,981	16,430	38,164	32,656
Drilling and development	109,350	164,070	291,648	317,398
Exploration and evaluation	1,260	2,775	9,404	4,267
Asset retirement obligations settled	11,745	11,893	16,720	14,447
Payout	141,336	195,168	355,936	368,768
% of fund flows from operations	60 %	79 %	53 %	74 %

Acquisitions: The sum of acquisitions and acquisitions of securities from the Consolidated Statements of Cash Flows, Vermilion common shares issued as consideration, the estimated value of contingent consideration, the amount of acquiree's outstanding long-term debt assumed, and net acquired working capital deficit or surplus. We believe that including these components provides a useful measure of the economic investment associated with our acquisition activity and is most directly comparable to cash flows used in investing activities. A reconciliation to the acquisitions line items in the Consolidated Statements of Cash Flows can be found below.

| Vermilion Energy Inc.  ■  Page 12  ■  2024 Second Quarter Report |

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Acquisitions, net of cash acquired	5,450	2,196	5,829	136,421
Acquisition of securities	-	632	9,373	2,108
Acquired working capital	-	(12,544)	-	103,527
Acquisitions	5,450	(9,716)	15,202	242,056

Capital Management Measure

Net debt: Is in accordance with IAS 1 "Presentation of Financial Statements" and is most directly comparable to long-term debt. Net debt is comprised of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital and represents Vermilion's net financing obligations after adjusting for the timing of working capital fluctuations.

	As at
($M)	Jun 30, 2024	Dec 31, 2023
Long-term debt	915,364	914,015
Adjusted working capital	(8,649)	164,552
Net debt	906,715	1,078,567
Ratio of net debt to four quarter trailing fund flows from operations	0.7	0.9

Supplementary Financial Measures

Net debt to four quarter trailing fundflows from operations: Calculated as net debt (capital management measure) over the FFO (total of segments measure) from the preceding four quarters. The measure is used to assess the ability to repay debt.

Dividends % of FFO: Calculated as dividends declared divided by FFO (total of segments measure). The measure is used by management as a metric to assess the cash distributed to shareholders.

Fund flows from operations per boe: Calculated as FFO (total of segments measure) by boe production. Fund flows from operations per boe is used by management to assess the profitability of our business units and Vermilion as a whole**.**

| Vermilion Energy Inc.  ■  Page 13  ■  2024 Second Quarter Report |

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Management's Discussion and Analysis

The following is Management’s Discussion and Analysis (“MD&A”), dated July 31, 2024, of Vermilion Energy Inc.’s (“Vermilion”, “we”, “our”, “us” or the “Company”) operating and financial results as at and for the three and six months ended June 30, 2024 compared with the corresponding period in the prior year.

This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2024 and the audited consolidated financial statements for the years ended December 31, 2023 and 2022, together with the accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR+ at www.sedarplus.ca or on Vermilion’s website at www.vermilionenergy.com.

The unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2024 and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standards Board ("IASB").

This MD&A includes references to certain financial measures which are not specified, defined, or determined under IFRS and are therefore considered non-GAAP and other specified financial measures. These financial measures are unlikely to be comparable to similar financial measures presented by other issuers. For a full description of these non-GAAP and other specified financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to “Non-GAAP and Other Specified Financial Measures”.

Product Type Disclosure

Under National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities", disclosure of production volumes should include segmentation by product type as defined in the instrument. In this report, references to "crude oil" and "light and medium crude oil" mean "light crude oil and medium crude oil" and references to "natural gas" mean "conventional natural gas".

In addition, in Supplemental Table 4 "Production", Vermilion provides a reconciliation from total production volumes to product type and also a reconciliation of "crude oil and condensate" and "NGLs" to the product types "light crude oil and medium crude oil" and "natural gas liquids".

Production volumes reported are based on quantities as measured at the first point of sale.

| Vermilion Energy Inc.  ■  Page 14  ■  2024 Second Quarter Report |

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Guidance

On December 12, 2023, we released our 2024 capital budget and associated production guidance, which assumed a mid-year startup of the new BC Montney battery and Croatia gas plant. On May 1, 2024, we increased 2024 guidance for royalty rate and cash taxes to reflect the impact of higher forward pricing for crude oil on these items. On July 31, 2024, we increased 2024 production guidance to reflect consistently strong operational performance across our asset base over the first half of 2024. The Company’s guidance for 2024 is as follows:

Category	Prior ^(1)^	Current ^(1)^
Production (boe/d)	82,000 - 86,000	83,000 - 86,000
E&D capital expenditures ($MM)	$600 - 625	$600 - 625
Royalty rate (% of sales)	9 - 11%	9 - 11%
Operating ($/boe)	$17.00 - 18.00	$17.00 - 18.00
Transportation ($/boe)	$3.00 - 3.50	$3.00 - 3.50
General and administration ($/boe)	$2.50 - 3.00	$2.50 - 3.00
Cash taxes (% of pre-tax FFO)	7 - 9%	7 - 9%
Asset retirement obligations settled ($MM)	$60	$60
Payments on lease obligations ($MM) ^(2)^	$30 - 60	$30 - 60
^(1)^	Current 2024 guidance reflects foreign exchange assumptions of CAD/USD 1.36, CAD/EUR 1.48, and CAD/AUD<br>0.91. Prior 2024 guidance reflects foreign exchange assumptions of CAD/USD 1.37, CAD/EUR 1.47, and CAD/AUD 0.89.
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^(2)^	Payments on lease obligations includes contractual amounts owing on leases, as well as up to $30 million<br>to account for accelerated principal payments that may be made in 2024.
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| Vermilion Energy Inc.  ■  Page 15  ■  2024 Second Quarter Report |

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Vermilion's Business

Vermilion is a Calgary, Alberta-based international oil and gas producer focused on the acquisition, exploration, development, and optimization of producing properties in North America, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices.

| Vermilion Energy Inc.  ■  Page 16  ■  2024 Second Quarter Report |

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Consolidated Results Overview

	Q2 2024	Q2 2023	Q2/24 vs. Q2/23	YTD 2024	YTD 2023	2024 vs. 2023
Production ^(1)^
Crude oil and condensate (bbls/d)	32,879	29,342	12%	32,787	31,305	5%
NGLs (bbls/d)	7,196	6,538	10%	7,121	7,213	(1)%
Natural gas (mmcf/d)	269.39	283.63	(5)%	271.99	265.72	2%
Total (boe/d)	84,974	83,152	2%	85,240	82,805	3%
Build (draw) in inventory (mbbls)	66	(30)		(161)	57
Financial metrics
Fund flows from operations ($M) ^(2)^	236,703	247,109	(4)%	668,061	500,276	34%
Per share ($/basic share)	1.48	1.51	(2)%	4.16	3.05	36%
Net (loss) earnings ($M)	(82,425)	127,908	N/A	(80,120)	508,240	N/A
Per share ($/basic share)	(0.52)	0.78	N/A	(0.50)	3.10	N/A
Cash flows from operating activities ($M)	266,322	173,632	53%	620,617	562,261	10%
Free cash flow ($M) ^(3)^	126,093	80,264	57%	367,009	178,611	106%
Long-term debt ($M)	915,364	913,785	- %	915,364	913,785	- %
Net debt ($M) ^(4)^	906,715	1,321,100	(31)%	906,715	1,321,100	(31)%
Activity
Capital expenditures ($M) ^(5)^	110,610	166,845	(34)%	301,052	321,665	(6)%
Acquisitions ($M) ^(6)^	5,450	(9,716)	N/A	15,202	242,056
Dispositions ($M)	-	-		-	182,152
^(1)^	Please refer to Supplemental Table 4 "Production" for disclosure by product type.
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^(2)^	Fund flows from operations (FFO) and FFO per share are a total of segments measure and supplementary financial<br>measure respectively most directly comparable to net (loss) earnings and net (loss) earnings per share, respectively. The measures do<br>not have a standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. FFO is<br>comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, equity<br>based compensation settled in cash, realized gain (loss) on derivatives, plus realized gain (loss) on foreign exchange and realized other<br>income (expense). The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary<br>to pay dividends, repay debt, fund asset retirement obligations and make capital investments. A reconciliation to the primary financial<br>statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A.
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^(3)^	Free cash flow (FCF) is a non-GAAP financial measure most directly comparable to cash flows from operating<br>activities; it does not have a standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other<br>issuers. FCF is comprised of fund flows from operations less drilling and development costs and exploration and evaluation costs. The<br>measure is used to determine the funding available for investing and financing activities including payment of dividends, repayment of<br>long-term debt, reallocation into existing business units and deployment into new ventures. A reconciliation to primary financial statement<br>measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A.
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^(4)^	Net debt is a capital management measure in accordance with IAS 1 "Presentation of Financial Statements"<br>and is most directly comparable to long-term debt. Net debt is comprised of long-term debt (excluding unrealized foreign exchange on swapped<br>USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current<br>lease liabilities), and represents Vermilion's net financing obligations after adjusting for the timing of working capital fluctuations.<br>Net debt excludes lease obligations which are secured by a corresponding right-of-use asset. A reconciliation to the primary financial<br>statement measures can be found within the "Financial Position Review" section of this MD&A.
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^(5)^	Capital expenditures is a non-GAAP financial measure that does not have a standardized meaning under IFRS<br>and therefore may not be comparable to similar measures presented by other issuers. The measure is calculated as the sum of drilling and<br>development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows. We consider capital expenditures<br>to be a useful measure of our investment in our existing asset base. Capital expenditures are also referred to as E&D capital. A reconciliation<br>to the primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section<br>of this MD&A.
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^(6)^	Acquisitions is a non-GAAP financial measure that does not have a standardized meaning under IFRS and<br>therefore may not be comparable to similar measures presented by other issuers. The measure is calculated as the sum of acquisitions,<br>net of cash and acquisitions of securities from the Consolidated Statements of Cash Flows, Vermilion common shares issued as consideration,<br>the estimated value of contingent consideration, the amount of acquiree's outstanding long-term debt assumed, and net acquired working<br>capital deficit or surplus. We believe that including these components provides a useful measure of the economic investment associated<br>with our acquisition activity. A reconciliation to the acquisitions line item in the Consolidated Statements of Cash Flows can be found<br>in "Supplemental Table 3: Capital Expenditures and Acquisitions" section of this MD&A.
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| Vermilion Energy Inc.  ■  Page 17  ■  2024 Second Quarter Report |

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Financial performance review

Q2 2024 vs. Q2 2023

•	We recorded net loss of $82.4 million ($(0.52)/basic<br>share) for Q2 2024 compared to net earnings of $127.9 million ($0.78/basic share) in Q2 2023. The decrease in net earnings was primarily<br>due to decreases in unrealized derivative gains of $137.0 million due to changes in our mark-to-market position, lower unrealized foreign<br>exchange gains, and an increase in deferred taxes.

| Vermilion Energy Inc.  ■  Page 18  ■  2024 Second Quarter Report |

| --- | | • | We generated cash flows from operating activities of $266.3 million in Q2 2024 compared to $173.6 million in Q2 2023 and fund flows from operations of $236.7 million in Q2 2024 compared to $247.1 million in Q2 2023. The decrease in fund flows from operations was primarily driven by lower pricing due to Euro gas, and higher unit costs combined with higher headcount and lower allocations to partners, partially offset by sales volume increases at Wandoo and lower windfall taxes. The variance between cash flows from operating activities and fund flows from operations is primarily due to working capital timing differences. | | --- | --- |

2024 vs. 2023

•

For the six months ended June 30, 2024, we recorded a net loss of $80.1 million compared to net earnings of $508.2 million for the comparable period in 2023. The change in net earnings (loss) was primarily attributable to the gain recognized on 2023 acquisition activity and changes in our mark-to-market position. The decrease in net earnings (loss) was partially offset by higher FFO driven by higher realized gains on commodity contracts, and the loss recognized on the sale of southeast Saskatchewan assets in Q1 2023.

| Vermilion Energy Inc.  ■  Page 19  ■  2024 Second Quarter Report |

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•	For the six months ended June 30,<br>2024 as compared to 2023, cash flows from operating activities increased by $58.4 million to $620.6 million and fund flows from operations<br>increased by $167.8 million to $668.1 million. The increase in fund flows from operations was primarily driven by realized gains on derivative<br>contracts, lower windfall taxes, organic growth and acquisitions and increased sales from liftings at Wandoo. This was partially offset<br>by cash-settled equity compensation in 2024, and other costs and taxes. Variances between cash flows from operating activities and funds<br>flow from operations are primarily driven by working capital timing differences.
Production review
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•

For the six months ended June 30, 2024 as compared to 2023, cash flows from operating activities increased by $58.4 million to $620.6 million and fund flows from operations increased by $167.8 million to $668.1 million. The increase in fund flows from operations was primarily driven by realized gains on derivative contracts, lower windfall taxes, organic growth and acquisitions and increased sales from liftings at Wandoo. This was partially offset by cash-settled equity compensation in 2024, and other costs and taxes. Variances between cash flows from operating activities and funds flow from operations are primarily driven by working capital timing differences.

Production review

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Q2 2024 vs. Q2 2023

•	Consolidated average production of 84,974<br>boe/d in Q2 2024 increased compared to Q2 2023 production of 83,152 boe/d. Production increased primarily due to production in Australia<br>coming online after downtime in 2023, and production from new wells coming online in North America, partially offset by lower production<br>in Ireland and Germany due to planned maintenance.

2024 vs. 2023

•

Consolidated average production of 85,240 boe/d in the six months ended June 30, 2024 increased compared to the prior year comparative period production of 82,805 boe/d. Production increased primarily due to unplanned downtime in Australia in 2023 and increased production in Ireland due to the acquisition of an additional 36.5% interest in the Corrib Natural Gas Project at the end of Q1 2023. This was partially offset by lower production in Canada due to the sale of non-core assets in southeast Saskatchewan in Q1 2023.

| Vermilion Energy Inc.  ■  Page 20  ■  2024 Second Quarter Report |

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•	For the three months ended June 30,<br>2024, capital expenditures were $110.6 million.
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•	In our North America core region, we invested<br>capital expenditures of $61.5 million, primarily comprised of $59.2 million of capital expenditure in Canada. At Mica, we drilled one<br>(1.0 net) and brought on production six (6.0 net) BC Montney liquids-rich shale gas wells in advance of the start-up of our 8-33 BC battery<br>in late Q2 2024. In Saskatchewan, we drilled two (2.0 net) and completed one (1.0 net) light and medium crude oil wells. In the United<br>States, we invested $2.3 million with focus primarily on the drilling and completion of five (0.2 net) non-operated light and medium<br>crude oil wells.
---	---
•	In our International core region, capital<br>expenditures of $49.1 million were invested during Q2 2024. In Germany, we invested $21.9 million as we advanced our deep gas exploration<br>and development plans and continued drilling activities. In France and the Netherlands, we invested $11.4 million and $4.0 million,<br>respectively, primarily on subsurface maintenance activities and equipment. In Australia, $8.8 million was invested as we performed<br>routine facilities maintenance. In Central and Eastern Europe, $2.6 million was invested as we completed construction of the gas plant<br>on the SA-10 block and drilled one (0.6 net) exploration well and completed two (1.2 net) wells on the SA-7 block, while in Ireland, $0.4 million<br>was invested.
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Financial sustainability review
---

Free cash flow

•	Free cash flow of $367.0 million increased<br>by $188.4 million for the six months ended June 30, 2024 compared to the prior year period primarily driven by increased fund flows<br>from operations and lower capital expenditures.

Long-term debt and net debt

•	Long-term debt remained relatively flat<br>at $915.4 million as at June 30, 2024 and December 31, 2023 and the revolving credit facility remained undrawn.
•	As at June 30, 2024, net debt decreased<br>to $906.7 million (December 31, 2023 - $1,078.6 million) as a result of strong free cash flow generation.
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•	The ratio of net debt to four quarter trailing<br>fund flows from operations^(1)^ decreased to 0.7 as at June 30, 2024 (December 31, 2023 - 0.9) primarily due to higher<br>four quarter trailing fund flows from operations on settlement of derivative contracts and lower windfall taxes.
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^(1)^	Net debt to four quarter trailing fund flows from operations is a supplementary<br>financial measure that does not have a standardized meaning under IFRS and therefore may not be comparable to similar measures presented<br>by other issuers. It is calculated as net debt (capital measure) over the FFO from the preceding four quarters (total of segments measure).<br>The measure is used to assess our ability to repay debt.
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| Vermilion Energy Inc.  ■  Page 21  ■  2024 Second Quarter Report |

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Benchmark Commodity Prices

	Q2 2024	Q2 2023	Q2/24 vs. Q2/23	YTD 2024	YTD 2023	2024 vs. 2023
Crude oil
WTI ($/bbl)	110.25	99.12	11%	107.00	101.03	6%
WTI (US $/bbl)	80.57	73.80	9%	78.76	74.97	5%
Edmonton Sweet index ($/bbl)	105.28	94.92	11%	98.66	96.98	2%
Edmonton Sweet index (US $/bbl)	76.94	70.67	9%	72.62	71.96	1%
Saskatchewan LSB index ($/bbl)	104.29	93.87	11%	96.88	94.02	3%
Saskatchewan LSB index (US $/bbl)	76.21	69.89	9%	71.31	69.76	2%
Canadian C5+ Condensate index ($/bbl)	105.56	97.18	9%	101.84	102.55	(1)%
Canadian C5+ Condensate index (US $/bbl)	77.14	72.36	7%	74.96	76.09	(1)%
Dated Brent ($/bbl)	116.23	105.29	10%	114.24	107.59	6%
Dated Brent (US $/bbl)	84.94	78.39	8%	84.09	79.83	5%
Natural gas
North America
AECO 5A ($/mcf)	1.18	2.45	(52)%	1.84	2.84	(35)%
Henry Hub ($/mcf)	2.59	2.82	(8)%	2.81	3.72	(24)%
Henry Hub (US $/mcf)	1.89	2.10	(10)%	2.07	2.76	(25)%
Europe^(1)^
NBP Day Ahead ($/mmbtu)	13.16	14.02	(6)%	12.47	17.97	(31)%
NBP Month Ahead ($/mmbtu)	12.50	15.74	(21)%	12.74	23.77	(46)%
NBP Day Ahead (#eu#/mmbtu)	8.93	9.58	(7)%	8.49	12.34	(31)%
NBP Month Ahead (#eu#/mmbtu)	8.48	10.76	(21)%	8.67	16.31	(47)%
TTF Day Ahead ($/mmbtu)	13.62	15.04	(9)%	12.69	19.03	(33)%
TTF Month Ahead ($/mmbtu)	12.61	16.72	(25)%	12.85	24.91	(48)%
TTF Day Ahead (#eu#/mmbtu)	9.24	10.28	(10)%	8.64	13.06	(34)%
TTF Month Ahead (#eu#/mmbtu)	8.56	11.43	(25)%	8.75	17.10	(49)%
Average exchange rates
CDN $/US $	1.37	1.34	2%	1.36	1.35	1%
CDN $/Euro	1.47	1.46	1%	1.47	1.46	1%
Realized prices
Crude oil and condensate ($/bbl)	108.93	96.64	13%	106.49	97.66	9%
NGLs ($/bbl)	31.61	28.11	12%	32.87	32.53	1%
Natural gas ($/mcf)	5.69	7.37	(23)%	5.90	8.94	(34)%
Total ($/boe)	62.46	61.74	1%	62.97	68.42	(8)%
^(1)^	NBP and TTF pricing can occur on a day-ahead ("DA") or month-ahead ("MA") basis. DA<br>prices in a period reflect the average current day settled price on the next days' delivery and MA prices in a period represent daily<br>one month futures contract prices which are determined at the end of each month. In a rising price environment, the DA price will tend<br>to be greater than the MA price and vice versa. Natural gas in the Netherlands and Germany is benchmarked to the TTF and production is<br>generally equally split between DA and MA contracts. Natural gas in Ireland is benchmarked to the NBP and is sold on DA contracts.
---	---

As an internationally diversified producer, we are exposed to a range of commodity prices. In our North America core region, our crude oil is sold at benchmarks linked to WTI (including the Edmonton Sweet index, the Saskatchewan LSB index, and the Canadian C5+ index) and our natural gas is sold at benchmarks linked to the AECO index (in Canada) or the Henry Hub ("HH") index (in the United States). In our International core region, our crude oil is sold with reference to Dated Brent and our natural gas is sold with reference to NBP, TTF, or indices highly correlated to TTF.

| Vermilion Energy Inc.  ■  Page 22  ■  2024 Second Quarter Report |

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•	Crude oil prices increased in Q2 2024 relative<br>to Q2 2023 on improved supply demand fundamentals and heightened geopolitical risk premium. Canadian dollar WTI increased by 11% and Brent<br>increased by 10% in Q1 2024 relative to Q1 2023.
•	In Canadian dollar terms, year-over-year,<br>the Edmonton Sweet differential widened by $0.77/bbl to a discount of $4.97/bbl against WTI, and the Saskatchewan LSB differential widened<br>by $0.71/bbl to a discount of $5.96/bbl against WTI.
---	---
•	Approximately 38% of Vermilion’s<br>Q2 2024 crude oil and condensate production was priced at the Dated Brent index, which averaged a premium to WTI of US$4.37/bbl, while<br>the remainder of our crude oil and condensate production was priced at the Saskatchewan LSB, Canadian C5+, Edmonton Sweet, and WTI indices.
---	---

•	In Canadian dollar terms, year-over-year,<br>prices for European natural gas at NBP and TTF decreased by 6% and 9% respectively on a day-ahead basis. On a month ahead basis, NBP and<br>TTF decreased by 21% and 25% respectively. Prices declined in response to lower seasonal and industrial demand in Europe, and historically<br>high storage levels to start the injection season.
•	Year-over-year natural gas prices in Canadian<br>dollar terms at NYMEX HH, and AECO decreased by 8% and 52% respectively. AECO prices declined due to strong production growth and historically<br>high storage levels, whereas NYMEX HH performed relatively better due to producer led supply curtailments and stronger US natural gas<br>demand.
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•	For Q2 2024, average European natural gas<br>prices represented an $11.79/mcf premium to AECO. Approximately 38% of our natural gas production in Q2 2024 benefited from this premium<br>European pricing.
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| Vermilion Energy Inc.  ■  Page 23  ■  2024 Second Quarter Report |

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North America

	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Production ^(1)^
Crude oil and condensate (bbls/d)	20,165	19,778	19,700	21,995
NGLs (bbls/d)	7,196	6,538	7,121	7,213
Natural gas (mmcf/d)	165.75	166.49	162.91	166.98
Total production volume (boe/d)	54,987	54,065	53,973	57,039
^(1)^	Please refer to Supplemental Table 4 "Production" for disclosure by product type.
---	---

	Q2 2024		Q2 2023		YTD 2024		YTD 2023
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	232,050	46.37	221,980	45.12	445,306	45.33	518,332	50.21
Royalties	(34,653)	(6.93)	(26,824)	(5.45)	(68,533)	(6.98)	(68,323)	(6.62)
Transportation	(14,124)	(2.82)	(7,704)	(1.57)	(25,457)	(2.59)	(20,885)	(2.02)
Operating	(69,486)	(13.89)	(60,116)	(12.22)	(138,158)	(14.06)	(136,335)	(13.21)
General and administration ^(1)^	(12,689)	(2.54)	514	0.10	(20,891)	(2.13)	(4,857)	(0.47)
Corporate income tax expense ^(1)^	4,089	0.82	(504)	(0.10)	947	0.10	(1,151)	(0.11)
Fund flows from operations	105,187	21.01	127,346	25.88	193,214	19.67	286,781	27.78
Drilling and development	(61,520)		(135,723)		(198,029)		(251,793)
Free cash flow	43,667		(8,377)		(4,815)		34,988
^(1)^	General and administration includes amounts from our Corporate segment. Corporate income tax expense primarily<br>relates to income taxes on Corporate segment activities.
---	---

Production from our North American operations averaged 54,987 boe/d in Q2 2024, an increase of 4% from the previous quarter due to new production from our recent BC Mica Montney wells.

Sales
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	189,635	42.58	187,789	42.58	364,680	41.77	451,886	48.28
United States	42,415	77.12	34,191	67.08	80,626	73.80	66,446	68.88
North America	232,050	46.37	221,980	45.12	445,306	45.33	518,332	50.21

Sales in North America increased for the three months ended June 30, 2024 compared to the prior year primarily due to higher production volumes combined with higher realized commodity prices. Sales in North America decreased for the six months ended June 30, 2024 compared to the prior year primarily due to lower production volumes following the sale of non-core southeast Saskatchewan assets in 2023 combined with lower realized commodity prices.

| Vermilion Energy Inc.  ■  Page 24  ■  2024 Second Quarter Report |

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	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	(22,166)	(4.98)	(18,000)	(4.08)	(44,721)	(5.12)	(50,896)	(5.44)
United States	(12,487)	(22.70)	(8,824)	(17.31)	(23,812)	(21.79)	(17,427)	(18.07)
North America	(34,653)	(6.93)	(26,824)	(5.45)	(68,533)	(6.98)	(68,323)	(6.62)

Royalties in North America increased on a dollar and per unit basis for the three months ended June 30, 2024 compared to the prior year primarily due to higher realized pricing combined with higher royalty rates on new wells in the Mica region. Royalties remained flat on a dollar basis and increased on a per unit basis for the six months ended June 30, 2024 compared to the prior year primarily due to new wells in the United States with higher royalty rates, partially offset by lower production volumes in Canada. Royalties as a percentage of sales for the three and six months ended June 30, 2024 were 14.9% and 15.4% respectively compared to the prior year comparative period of 12.1% and 13.2% respectively.

Transportation
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	(13,573)	(3.05)	(7,639)	(1.73)	(24,527)	(2.81)	(20,753)	(2.22)
United States	(551)	(1.00)	(65)	(0.13)	(930)	(0.85)	(132)	(0.14)
North America	(14,124)	(2.82)	(7,704)	(1.57)	(25,457)	(2.59)	(20,885)	(2.02)

Transportation expense in North America increased on a dollar and per boe basis for the three and six months ended June 30, 2024 compared to the prior year comparable periods primarily due to increased trucking expenses related to new activity on our Mica assets combined with pipeline fees incurred in the United States.

Operating expense
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	(63,140)	(14.18)	(53,430)	(12.12)	(123,598)	(14.16)	(123,097)	(13.15)
United States	(6,346)	(11.54)	(6,686)	(13.12)	(14,560)	(13.33)	(13,238)	(13.72)
North America	(69,486)	(13.89)	(60,116)	(12.22)	(138,158)	(14.06)	(136,335)	(13.21)

Operating expense in North America increased on a dollar and per boe basis for the three months ended June 30, 2024 compared to the prior year comparable period primarily due to production in the Mica region as we continue to bring more wells and infrastructure online. For the six months ended June 30, 2024, operating expense increased primarily due to production in the Mica region combined with higher United States production, partially offset by the disposition of properties in southeast Saskatchewan at the end of Q1 2023.

| Vermilion Energy Inc.  ■  Page 25  ■  2024 Second Quarter Report |

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International

	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Production ^(1)^
Crude oil and condensate (bbls/d)	12,714	9,564	13,087	9,310
Natural gas (mmcf/d)	103.64	117.14	109.08	98.74
Total production volume (boe/d)	29,987	29,087	31,267	25,767
Total sales volume (boe/d)	29,271	29,824	32,149	25,657
^(1)^	Please refer to Supplemental Table 4 "Production" for disclosure by product type.
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	Q2 2024		Q2 2023		YTD 2024		YTD 2023
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	246,875	92.68	249,376	91.89	541,654	92.57	505,722	108.90
Royalties	(11,957)	(4.49)	(20,169)	(7.43)	(26,630)	(4.55)	(46,014)	(9.91)
Transportation	(11,193)	(4.20)	(14,201)	(5.23)	(22,822)	(3.90)	(24,070)	(5.18)
Operating	(70,744)	(26.56)	(76,633)	(28.24)	(151,383)	(25.87)	(137,239)	(29.55)
General and administration	(13,848)	(5.20)	(20,572)	(7.58)	(29,349)	(5.02)	(35,090)	(7.56)
Corporate income tax expense	(16,185)	(6.08)	(18,424)	(6.79)	(38,685)	(6.61)	(40,039)	(8.62)
PRRT	(3,638)	(1.37)	-	-	(14,421)	(2.46)	-	-
Fund flows from operations	119,310	44.78	99,377	36.62	258,364	44.16	223,270	48.08
Drilling and development	(47,830)		(28,347)		(93,619)		(65,605)
Exploration and evaluation	(1,260)		(2,775)		(9,404)		(4,267)
Free cash flow	70,220		68,255		155,341		153,398

Production from our International operations averaged 29,987 boe/d in Q2 2024, a decrease of 8% from the previous quarter primarily due to natural declines and planned maintenance in Germany and Ireland.

Sales
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Australia	32,787	131.06	-	-	107,613	131.08	-	-
France	83,656	112.22	79,718	100.51	172,652	112.75	144,184	103.79
Netherlands	30,541	74.19	38,257	91.25	65,507	73.01	107,337	124.64
Germany	29,157	78.76	42,253	89.28	60,341	75.83	113,725	115.24
Ireland	69,793	79.76	88,689	86.63	134,257	74.99	138,176	99.23
Central and Eastern Europe	941	84.76	460	101.10	1,284	83.00	2,300	162.91
International	246,875	92.68	249,376	91.89	541,654	92.57	505,722	108.90

As a result of changes in inventory levels, our sales volumes for crude oil in Australia, France, and Germany may differ from our production volumes in those business units. The following table provides the crude oil sales volumes (consisting entirely of "light crude oil and medium crude oil") for those jurisdictions.

| Vermilion Energy Inc.  ■  Page 26  ■  2024 Second Quarter Report |

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Australia	2,749	-	4,511	-
France	8,192	8,716	8,414	7,675
Germany	1,000	1,525	932	1,462
International	11,941	10,241	13,857	9,137

Sales decreased on a dollar basis for the three months ended June 30, 2024 compared to the prior year primarily due to lower realized prices in multiple business units partially offset by an increase in sales volumes in Australia. On a per boe basis, sales increased due to the impact of realized prices on our Australian production partially offset by lower realized gas prices.

Sales increased on a dollar basis for the six months ended June 30, 2024 compared to the prior year primarily due to downtime in Australia in 2023, incremental volumes related to the Corrib acquisition in Ireland and timing of transportation in France. On a per boe basis, sales decreased due to lower realized gas prices, partially offset by the impact of realized prices on our Australian production.

Royalties
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
France	(10,283)	(13.79)	(10,833)	(13.66)	(23,335)	(15.24)	(17,924)	(12.90)
Netherlands	-	-	(6,653)	(15.87)	(217)	(0.24)	(21,482)	(24.94)
Germany	(1,435)	(3.88)	(2,496)	(5.27)	(2,790)	(3.51)	(5,399)	(5.47)
Central and Eastern Europe	(239)	(21.53)	(187)	(41.10)	(288)	(18.62)	(1,209)	(85.64)
International	(11,957)	(4.49)	(20,169)	(7.43)	(26,630)	(4.55)	(46,014)	(9.91)

Royalties in our International core region are primarily incurred in France, Germany and the Netherlands, where royalties include charges based on a percentage of sales and fixed per boe charges. Our production in Australia and Ireland is not subject to royalties.

Royalties decreased on a dollar and per unit basis for the three and six months ended June 30, 2024 compared to the prior year comparable periods primarily due to windfall royalties in the Netherlands in the prior year and lower gas pricing, partially offset by increased oil pricing.

Transportation
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
France	(6,401)	(8.59)	(8,215)	(10.36)	(11,764)	(7.68)	(14,415)	(10.38)
Germany	(2,386)	(6.45)	(3,409)	(7.20)	(5,578)	(7.01)	(6,173)	(6.26)
Ireland	(2,406)	(2.75)	(2,577)	(2.52)	(5,480)	(3.06)	(3,482)	(2.50)
International	(11,193)	(4.20)	(14,201)	(5.23)	(22,822)	(3.90)	(24,070)	(5.18)

Transportation expense decreased on a dollar and per boe basis for the three and six months ended June 30, 2024 compared to the prior year primarily due to lower vessel costs in France and lower sales volumes in Germany due to planned downtime.

Our production in Australia, Netherlands and Central and Eastern Europe is not subject to transportation expense.

| Vermilion Energy Inc.  ■  Page 27  ■  2024 Second Quarter Report |

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---
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Australia	(14,174)	(56.66)	(16,415)	-	(40,960)	(49.89)	(31,746)	-
France	(14,606)	(19.59)	(24,756)	(31.21)	(36,046)	(23.54)	(41,303)	(29.73)
Netherlands	(10,709)	(26.01)	(13,691)	(32.66)	(21,319)	(23.76)	(26,603)	(30.89)
Germany	(14,430)	(38.98)	(10,953)	(23.14)	(25,191)	(31.66)	(21,616)	(21.90)
Ireland	(16,453)	(18.80)	(10,526)	(10.28)	(27,057)	(15.11)	(15,144)	(10.88)
Central and Eastern Europe	(372)	(33.51)	(292)	(64.18)	(810)	(52.36)	(827)	(58.58)
International	(70,744)	(26.56)	(76,633)	(28.24)	(151,383)	(25.87)	(137,239)	(29.55)

Operating expenses decreased on a dollar basis for the three months ended June 30, 2024 primarily due to decreased fuel and electricity costs in France, partially offset by higher facility maintenance and turnaround costs for planned maintenance in Ireland.

For the six months ended June 30, 2024, operating expenses increased on a dollar basis primarily due to increased working interest acquired in Ireland at Q1 2023 and higher facility maintenance and turnaround costs for planned downtime in Q2 2024, and the resumption of production in Australia and associated liftings. This increase was partially offset by decreased power costs in the Netherlands.

Operating expenses decreased on a per boe basis for the three and six months ended June 30, 2024 compared to the prior year primarily attributable to lower power costs in the Netherlands, partially offset by planned downtime in Germany and Ireland resulting in lower volumes.

| Vermilion Energy Inc.  ■  Page 28  ■  2024 Second Quarter Report |

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Consolidated Financial Performance Review

Financial performance
	Q2 2024		Q2 2023		YTD 2024		YTD 2023
---	---	---	---	---	---	---	---	---
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	478,925	62.46	471,356	61.74	986,960	62.97	1,024,054	68.42
Royalties	(46,610)	(6.08)	(46,993)	(6.16)	(95,163)	(6.07)	(114,337)	(7.64)
Transportation	(25,317)	(3.30)	(21,905)	(2.87)	(48,279)	(3.08)	(44,955)	(3.00)
Operating	(140,230)	(18.29)	(136,749)	(17.91)	(289,541)	(18.47)	(273,574)	(18.28)
General and administration	(26,537)	(3.46)	(20,058)	(2.63)	(50,240)	(3.21)	(39,947)	(2.67)
Corporate income tax expense	(12,096)	(1.58)	(18,928)	(2.48)	(37,738)	(2.41)	(41,190)	(2.75)
Windfall taxes	-	-	(34,784)	(4.56)	-	-	(56,224)	(3.76)
PRRT	(3,638)	(0.47)	-	-	(14,421)	(0.92)	-	-
Interest expense	(21,062)	(2.75)	(20,210)	(2.65)	(39,454)	(2.52)	(42,085)	(2.81)
Equity based compensation	(14,361)	(1.87)	-	-	(14,361)	(0.92)	-	-
Realized gain on derivatives	46,017	6.00	67,673	8.86	266,632	17.01	82,003	5.48
Realized foreign exchange gain (loss)	2,267	0.30	3,679	0.48	4,138	0.26	(1,092)	(0.07)
Realized other (expense) income	(655)	(0.09)	4,028	0.53	(472)	(0.03)	7,623	0.51
Fund flows from operations	236,703	30.87	247,109	32.35	668,061	42.61	500,276	33.43
Equity based compensation	3,860		(4,998)		(1,658)		(28,523)
Unrealized (loss) gain on derivative instruments ^(1)^	(125,789)		11,177		(314,533)		103,875
Unrealized foreign exchange gain (loss) ^(1)^	3,069		35,124		(18,572)		19,646
Accretion	(18,209)		(18,599)		(36,143)		(38,650)
Depletion and depreciation	(161,184)		(154,389)		(339,618)		(302,520)
Deferred tax (expense) recovery	(20,667)		480		(37,312)		36,946
Gain on business combination	-		12,544		-		445,094
Loss on disposition	-		-		-		(226,828)
Unrealized other expense ^(1)^	(208)		(540)		(345)		(1,076)
Net (loss) earnings	(82,425)		127,908		(80,120)		508,240
^(1)^	Unrealized (loss) gain on derivative instruments, Unrealized foreign exchange gain (loss), and Unrealized<br>other expense are line items from the respective Consolidated Statements of Cash Flows.
---	---

Fluctuations in fund flows from operations may occur as a result of changes in production levels, commodity prices, and costs to produce petroleum and natural gas. In addition, fund flows from operations may be affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the consolidated balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized within profit or loss.

General and administration

•	General and administration expense increased<br>for the three months ended June 30, 2024 compared to the prior year primarily due to headcount costs, higher IT related costs and<br>lower recoveries.
•	General and administration expense increased<br>for the six months ended June 30, 2024 compared to the prior year primarily due to accounting for the cash settlement of previously<br>equity based settled compensation (previously accounted for as a share-based settled expense) and headcount costs.
---	---

Equity based compensation

•	Equity based compensation included within<br>funds flow from operations for the three and six months ended June 30, 2024 is a result of settling withholding taxes via cash which were<br>previously settled through the issuance and sale of shares from Treasury.

PRRT and corporate income taxes

•	PRRT for the three and six months ended<br>June 30, 2024 increased compared to the prior year due to downtime in Australia that resulted in no taxable income for the six months<br>ended June 30, 2023.
•	Corporate income taxes for the three and<br>six months ended June 30, 2024 decreased compared to the same periods in the prior year due to combined lower taxable income mainly<br>as a result of decreased commodity prices.
---	---

| Vermilion Energy Inc.  ■  Page 29  ■  2024 Second Quarter Report |

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Windfall taxes

•

Windfall taxes are the temporary taxes levied pursuant to the European Union’s temporary solidarity contribution. The contribution set out minimum amounts to be calculated on taxable profits starting in 2022 and/or 2023, which are above a 20% increase of the average yearly taxable profits for 2018 to 2021. For the two-year period of this policy Vermilion incurred $301 million of incremental taxes. Windfall taxes are not applicable to 2024 and future periods.

Interest expense

•

Interest expense for the three months ended June 30, 2024 increased compared to the same period in the prior year primarily due to interest incurred on higher right-of-use leases, partially offset by interest income earned on our cash position. Interest expense for the six months ended June 30, 2024 decreased compared to the same period 2023 due to the credit facility remaining undrawn throughout the period and higher interest income earned on our cash position, partially offset by interest incurred on higher right-of-use leases.

Realized gain or loss on derivatives

•	For the three and six months ended June 30,<br>2024, we recorded realized gains on our natural gas hedges due to lower commodity pricing compared to the strike prices.
•	A listing of derivative positions as at<br>June 30, 2024 is included in “Supplemental Table 2” of this MD&A.
---	---

Realized other income or expense

•	Realized other (expense) income for the<br>three and six months ended June 30, 2024 decreased compared to the same periods in the prior year primarily due to decreased amounts<br>for funding under the Saskatchewan Accelerated Site Closure program and proceeds received from insurance claims in 2023.
Net earnings (loss)
---

Fluctuations in net (loss) earnings from period-to-period are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include gains resulting from business combinations or charges resulting from impairment or impairment reversals.

Equity based compensation

Equity based compensation expense relates primarily to non-cash compensation expense attributable to long-term incentives granted to directors, officers, and employees under security-based arrangements. Equity based compensation expense decreased for the three and six months ended June 30, 2024 compared to the same periods in the prior year primarily due to the cash settlement of previously share-based settled expenses and the lower value of LTIP awards outstanding in the current period.

Unrealized gain or loss on derivativeinstruments

Unrealized gain or loss on derivative instruments arises as a result of changes in forecasts for future prices and rates. As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when future commodity price forecasts decline and vice-versa. As derivative instruments are settled, the unrealized gain or loss previously recognized is reversed, and the settlement results in a realized gain or loss on derivative instruments.

For the three months ended June 30, 2024, we recognized a net unrealized loss on derivative instruments of $125.8 million. This consists of unrealized losses of $120.8 million on our European natural gas commodity derivative instruments, $6.7 million on our equity swaps, $1.4 million on our USD-to-CAD foreign exchange swaps, partially offset by unrealized gains on $2.5 million on our crude oil commodity derivative instruments and $0.6 million on our North American gas commodity derivative instruments.

For the six months ended June 30, 2024, we recognized a net unrealized loss on derivative instruments of $314.5 million. This consists of unrealized losses of $272.4 million on our European natural gas commodity derivative instruments, $32.3 million on our crude oil commodity derivative instruments, $4.5 million on our USD-to-CAD foreign exchange swaps, $3.3 million on our equity swaps and $2.0 million on our North American gas commodity derivative instruments.

Unrealized foreign exchange gainsor losses

As a result of Vermilion’s international operations, Vermilion has monetary assets and liabilities denominated in currencies other than the Canadian dollar. These monetary assets and liabilities include cash, receivables, payables, long-term debt, derivative instruments and intercompany loans. Unrealized foreign exchange gains and losses result from translating these monetary assets and liabilities from their underlying currency to the Canadian dollar.

| Vermilion Energy Inc.  ■  Page 30  ■  2024 Second Quarter Report |

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In 2024, unrealized foreign exchange gains and losses primarily resulted from:

•

The translation of Euro denominated intercompany loans from our international subsidiaries to Vermilion Energy Inc. An appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange loss (and vice-versa). Under IFRS, the offsetting foreign exchange loss or gain is recorded as a currency translation adjustment within other comprehensive income. As a result, consolidated comprehensive income reflects the offsetting of these translation adjustments while net (loss) earnings reflects only the parent company's side of the translation.

•

The translation of our USD denominated 2025 senior unsecured notes and USD denominated 2030 senior unsecured notes.

---

For the three months ended June 30, 2024, we recognized a net unrealized foreign exchange gain of $3.1 million, primarily driven by the effects of the US dollar strengthening 2% against the Canadian dollar on our USD senior notes. For the six months ended June 30, 2024, we recognized an unrealized foreign exchange loss of $18.6 million, primarily driven by the effects of the USD dollar strengthening 3.5% against the Canadian dollar on our USD senior notes partially offset by gains on our USD denominated intercompany loans.

Accretion

Accretion expense is recognized to update the present value of the asset retirement obligation balance. For the three months ended June 30, 2024, compared to the three months ended June 30, 2023, accretion remained relatively flat. For the six months ended June 30, 2024, accretion expense decreased versus the prior year primarily due to lower North American asset retirement balance related dispositions completed in 2023, partially offset by the strengthening of the Euro against the Canadian dollar.

Depletion and depreciation

Depletion and depreciation expense is recognized to allocate the cost of capital assets over the useful life of the respective assets. Depletion and depreciation expense per unit of production is determined for each depletion unit (which are groups of assets within a specific production area that have similar economic lives) by dividing the sum of the net book value of capital assets and future development costs by total proved plus probable reserves.

Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes, and changes in depletion and depreciation per unit. Fluctuations in depletion and depreciation per unit are the result of changes in reserves, depletable base (net book value of capital assets and future development costs), and relative production mix.

Depletion and depreciation on a per boe basis for the three and six months ended June 30, 2024 of $21.02 and $21.67 increased from $20.22 and $20.21 in the same periods of the prior year, respectively, primarily due to higher future development costs increasing the depletable base and lower reserve estimates, partially offset by decreases to the depletable base related to the impairments and dispositions recorded in 2023.

Deferred tax

Deferred tax assets arise when the tax basis of an asset exceeds its accounting basis (known as a deductible temporary difference). Conversely, deferred tax liabilities arise when the tax basis of an asset is less than its accounting basis (known as a taxable temporary difference). Deferred tax assets are recognized only to the extent that it is probable that there are future taxable profits against which the deductible temporary difference can be utilized. Deferred tax assets and liabilities are measured at the enacted or substantively enacted tax rate that is expected to apply when the asset is realized, or the liability is settled.

As such, fluctuations in deferred tax expenses and recoveries primarily arise as a result of: changes in the accounting basis of an asset or liability without a corresponding tax basis change (e.g. when derivative assets and liabilities are marked-to-market or when accounting depletion differs from tax depletion), changes in available tax losses (e.g. if they are utilized to offset taxable income), changes in estimated future taxable profits resulting in a derecognition or recognition of deferred tax assets, and changes in enacted or substantively enacted tax rates.

For the three and six months ended June 30, 2024, the Company recorded deferred tax expense of $20.7 million and $37.3 million, respectively, compared to a deferred tax recovery of $0.5 million and $36.9 million in the comparative periods in the prior year. The expense recorded in the current year is primarily attributable to the derecognition of deferred tax assets in Ireland driven by the decrease in European gas prices. In 2023, the deferred tax recovery was driven by the disposition of assets in southeast Saskatchewan.

| Vermilion Energy Inc.  ■  Page 31  ■  2024 Second Quarter Report |

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Financial Position Review

Balance sheet strategy

We regularly review whether our forecast of fund flows from operations is sufficient to finance planned capital expenditures, dividends, share buy-backs, and abandonment and reclamation expenditures. To the extent that fund flows from operations forecasts are not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any shortfall by reducing some or all categories of expenditures, with issuances of equity, and/or with debt (including borrowing using the unutilized capacity of our existing revolving credit facility). We have a long-term goal of maintaining a ratio of net debt to four quarter trailing fund flows from operations of approximately 1.0.

As at June 30, 2024, we have a ratio of net debt to four quarter trailing fund flows from operations of 0.7. We will continue to monitor for changes in forecasted fund flows from operations and, as appropriate, will adjust our exploration, development capital plans (and associated production targets), and return of capital plans to target optimal debt levels.

Net debt

Net debt is reconciled to long-term debt, as follows:

	As at
($M)	Jun 30, 2024	Dec 31, 2023
Long-term debt	915,364	914,015
Adjusted working capital ^(1)^	(8,649)	164,552
Net debt	906,715	1,078,567
Ratio of net debt to four quarter trailing fund flows from operations	0.7	0.9
^(1)^	Adjusted working capital is a non-GAAP financial measure that is not standardized under IFRS and may not<br>be comparable to similar measures disclosed by other issuers. It is defined as current assets less current liabilities, excluding current<br>derivatives and current lease liabilities. The measure is used to calculate net debt, a capital measure disclosed above. Reconciliation<br>to the primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section<br>of this document.
---	---

As at June 30, 2024, net debt decreased to $906.7 million (December 31, 2023 - $1.1 billion) primarily due to strong free cash flow generation. The ratio of net debt to four quarter trailing fund flows from operations as at June 30, 2024 decreased to 0.7 (December 31, 2023 - 0.9) due to higher four quarter trailing fund flows from operations.

Long-term debt

The balances recognized on our balance sheet are as follows:

	As at
	Jun 30, 2024	Dec 31, 2023
2025 senior unsecured notes	378,471	395,839
2030 senior unsecured notes	536,893	518,176
Long-term debt	915,364	914,015

| Vermilion Energy Inc.  ■  Page 32  ■  2024 Second Quarter Report |

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Revolving Credit Facility

As at June 30, 2024, Vermilion had in place a bank revolving credit facility maturing May 26, 2028 with terms and outstanding positions as follows:

	As at
($M)	Jun 30, 2024	Dec 31, 2023
Total facility amount	1,350,000	1,600,000
Letters of credit outstanding	(20,234)	(18,116)
Unutilized capacity	1,329,766	1,581,884

On May 17, 2024, the maturity date of the facility was extended to May 26, 2028 (previously May 28, 2027) and the total facility amount of $1.6 billion

was reduced to $1.35 billion, with an accordion feature to increase the aggregate amount available under the facility to $1.6 billion. As at June 30, 2024, the revolving credit facility was undrawn.

As at June 30, 2024, the revolving credit facility was subject to the following financial covenants:

		As at
Financial covenant	Limit	Jun 30, 2024	Dec 31, 2023
Consolidated total debt to consolidated EBITDA	Less than 4.0	0.67	0.65
Consolidated total senior debt to consolidated EBITDA	Less than 3.5	0.05	-
Consolidated EBITDA to consolidated interest expense	Greater than 2.5	18.57	17.33

Our financial covenants include financial measures defined within our revolving credit facility agreement that are not defined under IFRS. These financial measures are defined by our revolving credit facility agreement as follows:

•	Consolidated total debt: Includes all amounts<br>classified as “Long-term debt”, “Current portion of long-term debt”, and “Lease obligations” (including<br>the current portion included within "Accounts payable and accrued liabilities" but excluding operating leases as defined under<br>IAS 17) on our consolidated balance sheet.
•	Consolidated total senior debt: Consolidated<br>total debt excluding unsecured and subordinated debt.
---	---
•	Consolidated EBITDA: Consolidated net (loss)<br>earnings before interest, income taxes, depreciation, accretion and certain other non-cash items, adjusted for the impact of the acquisition<br>of a material subsidiary.
---	---
•	Total interest expense: Includes all amounts<br>classified as "Interest expense", but excludes interest on operating leases as defined under IAS 17.
---	---

In addition, our revolving credit facility has provisions relating to our liability management ratings in Alberta and Saskatchewan whereby if our security adjusted liability management ratings fall below specified limits in a province, a portion of the asset retirement obligations are included in the definitions of consolidated total debt and consolidated total senior debt. An event of default occurs if our security adjusted liability management ratings breach additional lower limits for a period greater than 90 days. As of June 30, 2024, Vermilion's liability management ratings were higher than the specified levels, and as such, no amounts relating to asset retirement obligations were included in the calculation of consolidated total debt and consolidated total senior debt.

As at June 30, 2024 and December 31, 2023, Vermilion was in compliance with the above covenants.

2025 senior unsecured notes

On March 13, 2017, Vermilion issued US $300.0 million of senior unsecured notes at par. The notes bear interest at a rate of 5.625% per annum, paid semi-annually on March 15 and September 15, and mature on March 15, 2025. As direct senior unsecured obligations of Vermilion, the notes rank equally in right of payment with existing and future senior indebtedness of the Company.

The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance.

Subsequent to March 15, 2023, Vermilion may redeem some or all of the senior unsecured notes at a 100.00% redemption price plus any accrued and unpaid interest.

During the first quarter of 2024, Vermilion purchased $31.6 million of senior unsecured notes on the open market which were subsequently cancelled.

The Company has the right to roll over the senior unsecured notes under the existing revolving credit facility which matures May 26, 2028 thus has continued to classify the senior unsecured notes as non-current.

| Vermilion Energy Inc.  ■  Page 33  ■  2024 Second Quarter Report |

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2030 senior unsecured notes

On April 26, 2022, Vermilion closed a private offering of US $400.0 million 8-year senior unsecured notes. The notes were priced at 99.241% of par, mature on May 1, 2030, and bear interest at a rate of 6.875% per annum. Interest is paid semi-annually on May 1 and November 1, commencing on November 1, 2022. The notes are senior unsecured obligations of Vermilion and rank equally with existing and future senior unsecured indebtedness.

The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance.

Vermilion may, at its option, redeem the notes prior to maturity as follows:

•	Prior to May 1, 2025, Vermilion may redeem<br>up to 35% of the original principal amount of the notes with an amount of cash not greater than the net cash proceeds of certain equity<br>offerings at a redemption price of 106.875% of the principal amount of the notes, together with accrued and unpaid interest.
•	Prior to May 1, 2025, Vermilion may also<br>redeem some or all of the notes at a price equal to 100% of the principal amount of the notes, plus a “make-whole premium,”<br>together with applicable premium, accrued and unpaid interest.
---	---
•	On or after May 1, 2025, Vermilion may<br>redeem some or all of the senior unsecured notes at the redemption prices set forth below, together with accrued and unpaid interest.
---	---
Year	Redemption price
---	---
2025	103.438 %
2026	102.292 %
2027	101.146 %
2028 and thereafter	100.000 %
Shareholders' capital
---

The following table outlines our dividend payment history:

Date	Frequency	Dividend per unit or share
April 2022 to July 2022	Quarterly	$0.060
August 2022 to March 2023	Quarterly	$0.080
April 2023 to March 2024	Quarterly	$0.100
April 2024 onwards	Quarterly	$0.120

The following table reconciles the change in shareholders’ capital:

Shareholders’ Capital	Shares ('000s)	Amount
Balance at January 1	162,271	4,142,566
Vesting of equity based awards	996	9,998
Share-settled dividends on vested equity based awards	78	1,257
Repurchase of shares	(5,171)	(133,552)
Balance at June 30	158,174	4,020,269

As at June 30, 2024, there were approximately 4.5 million equity based compensation awards outstanding. As at July 31, 2024, there were approximately 157.3 million common shares issued and outstanding.

On July 8, 2024, the Toronto Stock Exchange approved our notice of intention to renew our normal course issuer bid ("the NCIB"). The NCIB renewal allows Vermilion to purchase up to 15,689,839 common shares (representing approximately 10% of outstanding common shares) beginning July 12, 2024 and ending July 11, 2025. Common shares purchased under the NCIB will be cancelled.

In the second quarter of 2024, Vermilion purchased 2.8 million common shares under the NCIB for total consideration of $46.6 million. Year-to-date, Vermilion purchased 5.2 million common shares under the NCIB for total consideration of 83.0 million. The common shares purchased under the NCIB were cancelled.

Subsequent to June 30, 2024, Vermilion purchased and cancelled 0.9 million shares under the NCIB for total consideration of $13.2 million.

| Vermilion Energy Inc.  ■  Page 34  ■  2024 Second Quarter Report |

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Asset Retirement Obligations

As at June 30, 2024, asset retirement obligations were $1,225.7 million compared to $1,159.1 million as at December 31, 2023. The increase in asset retirement obligations is primarily attributable to the Company's lower credit spread at June 30, 2024 compared to December 31, 2023 and accretion expense recognized. The credit spread decreased to 2.8% at June 30, 2024 compared to 3.6% at December 31, 2023 due to higher interest rates on government bonds and a lower expected cost of borrowing.

The present value of the obligation is calculated using a credit-adjusted risk-free rate, calculated using a credit spread added to risk-free rates based on long-term, risk-free government bonds. Vermilion's credit spread is determined using the Company's expected cost of borrowing at the end of the reporting period.

The risk-free rates and credit spread used as inputs to discount the obligations were as follows:

	Jun 30, 2024	Dec 31, 2023	Change
Credit spread added to below noted risk-free rates	2.8 %	3.6 %	(0.8) %
Country specific risk-free rate
Canada	3.3 %	3.0 %	0.3 %
United States	4.5 %	4.2 %	0.3 %
France	3.6 %	3.0 %	0.6 %
Netherlands	2.9 %	2.1 %	0.8 %
Germany	2.6 %	2.3 %	0.3 %
Ireland	3.1 %	2.7 %	0.4 %
Australia	4.5 %	4.0 %	0.5 %

Current cost estimates are inflated to the estimated time of abandonment using inflation rates of between 1.3% and 5.5% (as at December 31, 2023 - between 1.3% and 5.5%).

| Vermilion Energy Inc.  ■  Page 35  ■  2024 Second Quarter Report |

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Risks and Uncertainties

Vermilion is exposed to various market and operational risks. For a discussion of these risks, please see Vermilion's MD&A and Annual Information Form, each for the year ended December 31, 2023 available on SEDAR+ at www.sedarplus.ca or on Vermilion’s website at www.vermilionenergy.com.

Critical Accounting Estimates

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion’s consolidated financial statements. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions. There have been no material changes to our critical accounting estimates used in applying accounting policies for the six months ended June 30, 2024. Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2023, available on SEDAR+ at www.sedarplus.ca or on Vermilion’s website at www.vermilionenergy.com.

Off Balance Sheet Arrangements

We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.

Internal Control Over Financial Reporting

There has been no change in Vermilion’s internal control over financial reporting ("ICFR") during the period covered by this MD&A that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Recently Adopted Accounting Pronouncements

Vermilion did not adopt any new accounting pronouncements as at June 30, 2024 that would have a material impact on the Consolidated Interim Financial Statements.

Regulatory Pronouncements Not Yet Adopted

Issuance of IFRS Sustainability Standards- IFRS S1 "General Requirements for Disclosure of Sustainability-related Financial Information" and IFRS S2 "Climate-relatedDisclosures"

In June 2023, the International Sustainability Standards Board (ISSB) issued its inaugural standards - IFRS S1 and IFRS S2. The ISSB was formed as a new standard-setting board within the IFRS Foundation to issue standards that deliver a comprehensive global baseline of sustainability-related financial disclosures, operating alongside the International Accounting Standards Board.

IFRS S1 and IFRS S2 are effective for annual reporting periods beginning on or after January 1, 2024, with earlier application permitted, as long as both standards are applied. IFRS S1 provides a set of disclosure requirements designed to enable companies to communicate to investors about the sustainability-related risks and opportunities, while IFRS S2 sets out specific climate-related disclosures and is designed to be used in conjunction with IFRS S1. Canadian regulators have not yet mandated these standards; however, Vermilion is continuing to review the impact of the standards on its financial reporting.

IFRS 18 “Presentation and Disclosure in FinancialStatements issued”

In April 2024, the IASB issued IFRS 18 Presentation and Disclosure in Financial Statements issued which will replace IAS 1 Presentation of Financial Statements. Retrospective application of the standard is mandatory for annual reporting periods starting from January 1, 2027 onwards with earlier application is permitted. Vermilion is assessing the impacts of the standard on its financial reporting.

| Vermilion Energy Inc.  ■  Page 36  ■  2024 Second Quarter Report |

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Disclosure Controls and Procedures

Our officers have established and maintained disclosure controls and procedures and evaluated the effectiveness of these controls in conjunction with our filings.

As of June 30, 2024, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded and certified that our disclosure controls and procedures are effective.

| Vermilion Energy Inc.  ■  Page 37  ■  2024 Second Quarter Report |

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Supplemental Table 1: Netbacks

The following table includes financial statement information on a per unit basis by business unit. Liquids includes crude oil, condensate, and NGLs. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.

			YTD 2024			Q2 2023	YTD 2023
	Natural Gas	Total	Liquids	Natural Gas	Total	Total	Total
	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Canada
Sales	1.29	42.58	78.72	1.70	41.77	42.58	48.28
Royalties	0.41	(4.98)	(12.74)	0.23	(5.12)	(4.08)	(5.44)
Transportation	(0.31)	(3.05)	(4.49)	(0.23)	(2.81)	(1.73)	(2.22)
Operating	(0.40)	(14.18)	(26.72)	(0.57)	(14.16)	(12.12)	(13.15)
Operating netback	0.99	20.37	34.77	1.13	19.68	24.65	27.47
General and administration		(1.22)			(2.11)	(4.97)	(4.86)
Fund flows from operations (/boe)		19.15			17.57	19.68	22.61
United States
Sales	1.22	77.12	90.79	1.97	73.80	67.08	68.88
Royalties	(1.35)	(22.70)	(26.73)	(0.63)	(21.79)	(17.31)	(18.07)
Transportation	-	(1.00)	(1.08)	-	(0.85)	(0.13)	(0.14)
Operating	(0.66)	(11.54)	(16.47)	(0.31)	(13.33)	(13.12)	(13.72)
Operating netback	(0.79)	41.88	46.51	1.03	37.83	36.52	36.95
General and administration		(5.95)			(5.99)	(2.50)	(3.93)
Fund flows from operations (/boe)		35.93			31.84	34.02	33.02
France
Sales	-	112.22	112.75	-	112.75	100.51	103.79
Royalties	-	(13.79)	(15.24)	-	(15.24)	(13.66)	(12.90)
Transportation	-	(8.59)	(7.68)	-	(7.68)	(10.36)	(10.38)
Operating	-	(19.59)	(23.54)	-	(23.54)	(31.21)	(29.73)
Operating netback	-	70.25	66.29	-	66.29	45.28	50.78
General and administration		(5.11)			(5.87)	(9.89)	(9.13)
Current income taxes		(7.99)			(7.69)	(2.28)	(2.17)
Fund flows from operations (/boe)		57.15			52.73	33.11	39.48
Netherlands
Sales	12.31	74.19	89.29	12.11	73.01	91.25	124.64
Royalties	(0.09)	-	-	(0.04)	(0.24)	(15.87)	(24.94)
Transportation	-	-	-	-	-	-	-
Operating	(8.47)	(26.01)	(32.56)	(3.93)	(23.76)	(32.66)	(30.89)
Operating netback	3.75	48.18	56.73	8.14	49.01	42.72	68.81
General and administration		(4.31)			(4.14)	2.38	(1.29)
Current income taxes		(19.09)			(21.03)	(13.88)	(14.53)
Fund flows from operations (/boe)		24.78			23.84	31.22	52.99
Germany
Sales	11.46	78.76	108.66	11.16	75.83	89.28	115.24
Royalties	(1.57)	(3.88)	(0.95)	(0.70)	(3.51)	(5.27)	(5.47)
Transportation	(1.12)	(6.45)	(21.85)	(0.50)	(7.01)	(7.20)	(6.26)
Operating	(10.38)	(38.98)	(46.04)	(4.63)	(31.66)	(23.14)	(21.90)
Operating netback	(1.61)	29.45	39.82	5.33	33.65	53.67	81.61
General and administration		(8.27)			(7.08)	(9.81)	(7.48)
Current income taxes		(4.60)			(7.64)	(20.48)	(23.08)
Fund flows from operations (/boe)		16.58			18.93	23.38	51.05

All values are in US Dollars.

| Vermilion Energy Inc.  ■  Page 38  ■  2024 Second Quarter Report |

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			YTD 2024			Q2 2023	YTD 2023
	Natural Gas	Total	Liquids	Natural Gas	Total	Total	Total
	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Ireland
Sales	13.29	79.76	-	12.50	74.99	86.63	99.23
Transportation	(0.46)	(2.75)	-	(0.51)	(3.06)	(2.52)	(2.50)
Operating	(3.13)	(18.80)	-	(2.52)	(15.11)	(10.28)	(10.88)
Operating netback	9.70	58.21	-	9.47	56.82	73.83	85.85
General and administration		(1.67)			(2.03)	(4.65)	(4.34)
Current income taxes		(0.36)			(0.43)	(0.22)	(0.16)
Fund flows from operations (/boe)		56.18			54.36	68.96	81.35
Australia
Sales	-	131.06	131.08	-	131.08	-	-
Operating	-	(56.66)	(49.89)	-	(49.89)	-	-
PRRT (1)	-	(14.54)	(17.57)	-	(17.57)	-	-
Operating netback	-	59.86	63.62	-	63.62	-	-
General and administration		(8.01)			(4.56)	-	-
Current income taxes		(1.40)			(1.45)	-	-
Fund flows from operations (/boe)		50.45			57.61	-	-
Total Company
Sales	5.69	62.46	93.64	5.90	62.97	61.74	68.42
Realized hedging gain (loss)	10.71	6.00	0.55	5.30	17.01	8.86	5.48
Royalties	0.10	(6.08)	(13.16)	0.05	(6.07)	(6.16)	(7.64)
Transportation	(0.52)	(3.30)	(4.78)	(0.26)	(3.08)	(2.87)	(3.00)
Operating	(3.54)	(18.29)	(27.30)	(1.75)	(18.47)	(17.91)	(18.28)
PRRT (2)	-	(0.47)	(1.94)	-	(0.92)	-	-
Operating netback	12.44	40.32	47.01	9.24	51.44	43.66	44.98
General and administration		(3.46)			(3.21)	(2.63)	(2.67)
Interest expense		(2.75)			(2.52)	(2.65)	(2.81)
Equity based compensation		(1.87)			(0.92)	-	-
Realized foreign exchange gain (loss)		0.30			0.26	0.48	(0.07)
Other income		(0.09)			(0.03)	0.53	0.51
Corporate income taxes		(1.58)			(2.41)	(2.48)	(2.75)
Windfall taxes		-			-	(4.56)	(3.76)
Fund flows from operations (/boe)		30.87			42.61	32.35	33.43

All values are in US Dollars.

^(1)^	Vermilion considers Australian PRRT to be an operating item and, accordingly, has included PRRT in the<br>calculation of operating netbacks. Current income taxes presented above excludes PRRT.

| Vermilion Energy Inc.  ■  Page 39  ■  2024 Second Quarter Report |

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Supplemental Table 2: Hedges

The prices in these tables may represent the weighted averages for several contracts with foreign currency amounts translated to the disclosure currency using forward rates as at the month-end date. The weighted average price for the portfolio of options listed below may not have the same payoff profile as the individual contracts. As such, the presentation of the weighted average prices is purely for indicative purposes.

The following tables outline Vermilion’s outstanding risk management positions as at June 30, 2024:

	Unit	Currency	Daily Bought Put Volume	Weighted Average Bought Put Price	Daily Sold Call Volume	Weighted Average Sold Call Price	Daily Sold Put Volume	Weighted Average Sold Put Price	Daily Sold Swap Volume	Weighted Average Sold Swap Price	Daily Bought Swap Volume	Weighted Average Bought Swap Price
WTI
Q3 2024	bbl	USD	-	-	-	-	-	-	13,000	80.08	-	-
Q4 2024	bbl	USD	-	-	-	-	-	-	6,000	78.67	-	-
Q1 2025	bbl	USD	-	-	-	-	-	-	1,500	76.00	-	-
AECO
Q3 2024	mcf	CAD	4,739	3.17	4,739	4.22	-	-	19,904	3.14	-	-
Q4 2024	mcf	CAD	4,739	3.17	4,739	4.22	-	-	9,849	3.31	-	-
Q1 2025	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q2 2025	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q3 2025	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q4 2025	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q1 2026	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q2 2026	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q3 2026	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
Q4 2026	mcf	CAD	4,739	3.17	4,739	4.22	-	-	23,695	3.89	-	-
AECO Basis (AECO less NYMEX Henry Hub)
Q1 2025	mcf	USD	-	-	-	-	-	-	10,000	(1.15)	-	-
Q2 2025	mcf	USD	-	-	-	-	-	-	10,000	(1.15)	-	-
Q3 2025	mcf	USD	-	-	-	-	-	-	10,000	(1.15)	-	-
Q4 2025	mcf	USD	-	-	-	-	-	-	10,000	(1.15)	-	-
NYMEX Henry Hub
Q3 2024	mcf	USD	20,000	3.50	20,000	4.45	-	-	4,000	3.51	-	-
Q4 2024	mcf	USD	20,000	3.50	20,000	4.45	-	-	4,000	3.51	-	-
Q1 2025	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q2 2025	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q3 2025	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q4 2025	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q1 2026	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q2 2026	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q3 2026	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
Q4 2026	mcf	USD	24,000	3.50	24,000	4.49	-	-	-	-	-	-
NBP
Q3 2024	mcf	EUR	-	-	-	-	-	-	7,370	10.11	-	-

| Vermilion Energy Inc.  ■  Page 40  ■  2024 Second Quarter Report |

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---	---	---	---	---	---	---	---	---	---	---	---	---
Q3 2024	mcf	EUR	7,278	25.96	7,278	45.76	-	-	36,851	13.07	-	-
Q4 2024	mcf	EUR	11,055	9.95	11,055	14.65	6,142	3.28	34,394	15.13	-	-
Q1 2025	mcf	EUR	18,426	10.07	18,426	14.89	13,512	4.69	34,394	15.13	-	-
Q2 2025	mcf	EUR	22,111	8.31	22,111	12.86	22,111	4.01	19,654	13.67	-	-
Q3 2025	mcf	EUR	22,111	8.31	22,111	12.86	22,111	4.01	19,654	13.67	-	-
Q4 2025	mcf	EUR	31,938	8.05	31,938	12.49	31,938	3.67	15,969	12.37	-	-
Q1 2026	mcf	EUR	24,567	7.39	24,567	11.66	24,567	3.02	15,969	12.37	-	-
Q2 2026	mcf	EUR	24,567	7.39	24,567	11.66	24,567	3.02	13,512	9.36	-	-
Q3 2026	mcf	EUR	24,567	7.39	24,567	11.66	24,567	3.02	13,512	9.36	-	-
Q4 2026	mcf	EUR	28,253	7.43	28,253	11.66	28,253	2.93	4,913	8.54	-	-
Q1 2027	mcf	EUR	28,253	7.43	28,253	11.66	28,253	2.93	4,913	8.54	-	-
Buy TTF, Sell NBP Basis
Q3 2024	mcf	EUR	-	-	-	-	-	-	20,268	(0.37)	-	-
THE
Q4 2024	mcf	EUR	-	-	-	-	-	-	2,457	14.95	-	-
Q1 2025	mcf	EUR	-	-	-	-	-	-	2,457	14.95	-	-
Q2 2025	mcf	EUR	-	-	-	-	-	-	2,457	14.95	-	-
Q3 2025	mcf	EUR	-	-	-	-	-	-	2,457	14.95	-	-
VET Equity Swaps		Initial Share Price		Share Volume
---	---	---	---	---
Swap	Jan 2020 - Apr 2025	20.9788	CAD	2,250,000
Swap	Jan 2020 - Jul 2025	22.4587	CAD	1,500,000
Foreign Exchange		Period	Monthly Bought Put Amount		Weighted Average Bought Put Price	Monthly Sold Call Amount		Weighted Average Sold Call Price	Monthly Sold Swap Amount		Weighted Average Sold Swap Price
---	---	---	---	---	---	---	---	---	---	---	---
Collar	Sell USD, Buy CAD	Jul 2024 - Dec 2024	4,000,000	USD	1.3600	4,000,000	USD	1.3963	-		-
Forward	Sell USD, Buy CAD	Jul 2024 - Dec 2024	-		-	-		-	16,000,000	USD	1.3549

The following sold option instruments allow the counterparties, at the specified date, to enter into a derivative instrument contract with Vermilion at the detailed terms:

Period if Option Exercised	Unit	Currency	Option Expiration Date	Daily Bought Put Volume	Weighted Average Bought Put Price	Daily Sold Call Volume	Weighted Average Sold Call Price	Daily Sold Put Volume	Weighted Average Sold Put Price	Daily Sold Swap Volume	Weighted Average Sold Swap Price
WTI
Oct 2024 - Dec 2025	bbl	USD	31-Jul-2024	-	-	-	-	-	-	1,000	80.00
Jan 2025 - Dec 2025	bbl	USD	31-Dec-2024	-	-	-	-	-	-	2,000	80.00
NYMEX
Jan 2025 - Dec 2025	mcf	USD	23-Dec-2024	-	-	-	-	-	-	10,000	3.65
TTF
Oct 2024 - Sep 2026	mcf	EUR	30-Sep-2024	-	-	-	-	-	-	4,913	10.26
Apr 2025 - Mar 2027	mcf	EUR	30-Sep-2024	-	-	-	-	-	-	4,913	10.26

| Vermilion Energy Inc.  ■  Page 41  ■  2024 Second Quarter Report |

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Supplemental Table 3: Capital Expenditures and Acquisitions

By classification ($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Drilling and development	109,350	164,070	291,648	317,398
Exploration and evaluation	1,260	2,775	9,404	4,267
Capital expenditures	110,610	166,845	301,052	321,665
Acquisitions, net of cash acquired	5,450	2,196	5,829	136,421
Acquisition of securities	-	632	9,373	2,108
Acquired working capital	-	(12,544)	-	103,527
Acquisitions	5,450	(9,716)	15,202	242,056
Dispositions ($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Canada	-	-	-	182,152
Total dispositions	-	-	-	182,152
By category ($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Drilling, completion, new well equip and tie-in, workovers and recompletions	39,436	112,393	177,497	245,031
Production equipment and facilities	62,648	43,849	111,129	64,415
Seismic, studies, land and other	8,526	10,603	12,426	12,219
Capital expenditures	110,610	166,845	301,052	321,665
Acquisitions	5,450	(9,716)	15,202	242,056
Total capital expenditures and acquisitions	116,060	157,129	316,254	563,721
Capital expenditures by country ($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Canada	59,207	73,471	183,489	175,321
United States	2,313	62,252	14,540	76,472
France	11,389	11,326	22,404	23,011
Netherlands	4,033	5,815	8,631	16,198
Germany	21,897	7,853	45,925	16,017
Ireland	356	(619)	3,449	1,439
Australia	8,809	5,470	14,980	10,602
Central and Eastern Europe	2,606	1,277	7,634	2,605
Total capital expenditures	110,610	166,845	301,052	321,665
Acquisitions by country ($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Canada	5,450	680	15,202	45,830
United States	-	2,148	-	3,808
Ireland	-	(12,544)	-	192,418
Acquisitions	5,450	(9,716)	15,202	242,056

| Vermilion Energy Inc.  ■  Page 42  ■  2024 Second Quarter Report |

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Supplemental Table 4: Production

	Q2/24	Q1/24	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21
Canada
Light and medium crude oil (bbls/d)	12,468	11,649	11,614	12,054	12,901	16,674	17,448	16,835	17,042	15,980	16,388	16,809
Condensate ^(1)^ (bbls/d)	3,853	4,075	4,034	4,410	3,506	4,719	4,525	4,204	4,873	4,892	4,785	4,426
Other NGLs ^(1)^ (bbls/d)	6,208	5,968	6,281	6,219	5,513	6,875	6,279	6,870	7,155	7,286	7,073	6,862
NGLs (bbls/d)	10,061	10,043	10,315	10,629	9,019	11,594	10,804	11,074	12,028	12,178	11,858	11,288
Conventional natural gas (mmcf/d)	158.48	151.84	160.16	163.94	159.26	160.34	146.81	145.04	143.94	140.55	128.85	138.42
Total (boe/d)	48,943	46,997	48,623	50,007	48,464	54,991	52,720	52,080	53,060	51,584	49,720	51,168
United States
Light and medium crude oil (bbls/d)	3,817	3,483	3,187	4,404	3,349	2,824	3,282	2,824	2,846	2,675	2,647	3,520
Condensate ^(1)^ (bbls/d)	27	29	27	15	22	20	36	35	40	24	26	2
Other NGLs ^(1)^ (bbls/d)	988	1,078	1,131	1,124	1,025	1,020	1,218	1,031	958	1,056	1,388	1,206
NGLs (bbls/d)	1,015	1,107	1,158	1,139	1,047	1,040	1,254	1,066	998	1,080	1,414	1,208
Conventional natural gas (mmcf/d)	7.27	8.23	7.49	7.25	7.23	7.14	7.45	7.03	6.74	7.56	9.09	6.75
Total (boe/d)	6,044	5,962	5,593	6,751	5,601	5,055	5,779	5,062	4,967	5,014	5,575	5,854
France
Light and medium crude oil (bbls/d)	7,246	7,308	7,395	7,578	7,788	7,578	7,247	6,818	8,126	8,389	8,453	8,677
Total (boe/d)	7,246	7,308	7,395	7,578	7,788	7,578	7,247	6,818	8,126	8,389	8,453	8,677
Netherlands
Light and medium crude oil (bbls/d)	-	-	-	-	-	-	-	-	1	1	-	6
Condensate ^(1)^ (bbls/d)	51	165	119	39	61	66	49	74	60	83	97	104
NGLs (bbls/d)	51	165	119	39	61	66	49	74	60	83	97	104
Conventional natural gas (mmcf/d)	26.84	31.02	32.06	24.32	27.28	29.07	27.41	29.15	35.22	39.03	51.98	42.48
Total (boe/d)	4,524	5,336	5,462	4,091	4,607	4,910	4,617	4,933	5,930	6,589	8,761	7,190
Germany
Light and medium crude oil (bbls/d)	1,698	1,722	1,775	1,713	1,715	1,410	1,481	1,764	1,331	1,158	1,127	1,043
Conventional natural gas (mmcf/d)	18.41	22.87	19.62	20.29	22.05	25.85	25.86	26.54	25.36	26.95	18.00	16.19
Total (boe/d)	4,766	5,533	5,046	5,095	5,391	5,717	5,791	6,187	5,558	5,650	4,127	3,741
Ireland
Conventional natural gas (mmcf/d)	57.70	60.34	64.04	47.96	67.51	24.58	26.04	25.74	27.93	30.26	30.12	22.67
Total (boe/d)	9,616	10,057	10,673	7,993	11,251	4,096	4,340	4,290	4,655	5,043	5,020	3,778
Australia
Light and medium crude oil (bbls/d)	3,713	4,264	4,715	1,204	-	-	4,847	4,763	2,465	3,888	2,742	4,190
Total (boe/d)	3,713	4,264	4,715	1,204	-	-	4,847	4,763	2,465	3,888	2,742	4,190
Central and Eastern Europe
Conventional natural gas (mmcf/d)	0.69	0.29	0.54	0.05	0.30	0.64	0.67	0.63	0.64	0.34	0.12	0.22
Total (boe/d)	122	48	90	8	50	107	111	104	106	57	20	36
Consolidated
Light and medium crude oil (bbls/d)	28,948	28,426	28,685	26,952	25,753	28,485	34,305	33,003	31,811	32,091	31,356	34,245
Condensate ^(1)^ (bbls/d)	3,931	4,269	4,180	4,463	3,589	4,805	4,610	4,312	4,973	4,999	4,908	4,532
Other NGLs ^(1)^ (bbls/d)	7,196	7,046	7,412	7,344	6,538	7,896	7,497	7,901	8,113	8,342	8,461	8,068
NGLs (bbls/d)	11,127	11,315	11,592	11,807	10,127	12,701	12,107	12,213	13,086	13,341	13,369	12,600
Conventional natural gas (mmcf/d)	269.39	274.59	283.91	263.80	283.63	247.61	234.23	234.12	239.83	244.69	238.16	226.73
Total (boe/d)	84,974	85,505	87,597	82,727	83,152	82,455	85,450	84,237	84,868	86,213	84,417	84,633

| Vermilion Energy Inc.  ■  Page 43  ■  2024 Second Quarter Report |

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---	---	---	---	---	---	---	---
Canada
Light and medium crude oil (bbls/d)		12,058	13,293	16,830	16,954	21,106	23,971
Condensate ^(1)^ (bbls/d)		3,964	4,166	4,621	4,831	4,886	4,295
Other NGLs ^(1)^ (bbls/d)		6,088	6,220	6,895	7,179	7,719	6,988
NGLs (bbls/d)		10,052	10,386	11,516	12,010	12,605	11,283
Conventional natural gas (mmcf/d)		155.16	160.94	144.10	138.03	151.38	148.35
Total (boe/d)		47,970	50,503	52,364	51,968	58,942	59,979
United States
Light and medium crude oil (bbls/d)		3,650	3,445	2,908	2,597	3,046	2,514
Condensate ^(1)^ (bbls/d)		28	21	34	8	5	18
Other NGLs ^(1)^ (bbls/d)		1,033	1,076	1,066	1,146	1,218	996
NGLs (bbls/d)		1,061	1,097	1,100	1,154	1,223	1,014
Conventional natural gas (mmcf/d)		7.75	7.28	7.20	6.84	7.47	6.89
Total (boe/d)		6,003	5,754	5,207	4,890	5,514	4,675
France
Light and medium crude oil (bbls/d)		7,277	7,584	7,639	8,799	8,903	10,435
Conventional natural gas (mmcf/d)		-	-	-	-	-	0.19
Total (boe/d)		7,277	7,584	7,639	8,799	8,903	10,467
Netherlands
Light and medium crude oil (bbls/d)		-	-	-	3	1	3
Condensate ^(1)^ (bbls/d)		108	71	66	97	88	88
NGLs (bbls/d)		108	71	66	97	88	88
Conventional natural gas (mmcf/d)		28.93	28.18	32.66	43.40	46.16	49.10
Total (boe/d)		4,930	4,768	5,510	7,334	7,782	8,274
Germany
Light and medium crude oil (bbls/d)		1,710	1,654	1,435	1,044	968	917
Conventional natural gas (mmcf/d)		20.64	21.93	26.18	15.81	12.65	15.31
Total (boe/d)		5,149	5,310	5,798	3,679	3,076	3,468
Ireland
Conventional natural gas (mmcf/d)		59.02	51.12	27.48	29.25	37.44	46.57
Total (boe/d)		9,837	8,520	4,579	4,875	6,240	7,762
Australia
Light and medium crude oil (bbls/d)		3,989	1,492	3,995	3,810	4,416	5,662
Total (boe/d)		3,989	1,492	3,995	3,810	4,416	5,662
Central and Eastern Europe
Conventional natural gas (mmcf/d)		0.49	0.38	0.57	0.31	1.90	0.42
Total (boe/d)		85	63	95	51	317	70
Consolidated
Light and medium crude oil (bbls/d)		28,687	27,469	32,809	33,208	38,441	43,502
Condensate ^(1)^ (bbls/d)		4,100	4,258	4,721	4,936	4,980	4,400
Other NGLs ^(1)^ (bbls/d)		7,121	7,296	7,961	8,325	8,937	7,984
NGLs (bbls/d)		11,221	11,554	12,682	13,261	13,917	12,384
Conventional natural gas (mmcf/d)		271.99	269.84	238.18	233.64	256.99	266.82
Total (boe/d)		85,240	83,994	85,187	85,408	95,190	100,357
^(1)^	Under National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities", disclosure<br>of production volumes should include segmentation by product type as defined in the instrument. This table provides a reconciliation from<br>"crude oil and condensate", "NGLs" and "natural gas" to the product types. In this report, references to<br>"crude oil" and "light and medium crude oil" mean "light crude oil and medium crude oil" and references<br>to "natural gas" mean "conventional natural gas". Production volumes reported are based on quantities as measured<br>at the first point of sale.
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Supplemental Table 5: Operational and Financial Data by Core Region

Production volumes ^(1)^

	Q2/24	Q1/24	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21
North America
Crude oil and condensate (bbls/d)	20,165	19,236	18,862	20,883	19,778	24,237	25,291	23,898	24,801	23,571	23,846	24,757
NGLs (bbls/d)	7,196	7,046	7,412	7,344	6,538	7,895	7,497	7,901	8,113	8,342	8,461	8,068
Natural gas (mmcf/d)	165.75	160.07	167.65	171.19	166.49	167.48	154.26	152.07	150.68	148.11	137.93	145.18
Total (boe/d)	54,987	52,959	54,216	56,758	54,065	60,046	58,499	57,142	58,027	56,598	55,295	57,022
International
Crude oil and condensate (bbls/d)	12,714	13,459	14,004	10,534	9,564	9,054	13,624	13,419	11,983	13,519	12,419	14,020
Natural gas (mmcf/d)	103.64	114.52	116.27	92.61	117.14	80.13	79.97	82.05	89.15	96.58	100.22	81.55
Total (boe/d)	29,987	32,546	33,381	25,969	29,087	22,408	26,953	27,095	26,840	29,616	29,123	27,612
Consolidated
Crude oil and condensate (bbls/d)	32,879	32,695	32,866	31,416	29,341	33,290	38,915	37,315	36,784	37,090	36,264	38,777
NGLs (bbls/d)	7,196	7,046	7,412	7,344	6,538	7,896	7,497	7,901	8,113	8,342	8,461	8,068
Natural gas (mmcf/d)	269.39	274.59	283.92	263.80	283.63	247.61	234.23	234.12	239.83	244.69	238.16	226.73
Total (boe/d)	84,974	85,505	87,597	82,727	83,152	82,455	85,450	84,237	84,868	86,213	84,417	84,633
^(1)^	Please refer to Supplemental Table 4 "Production" for disclosure by product type.
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Sales volumes

	Q2/24	Q1/24	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21
North America
Crude oil and condensate (bbls/d)	20,166	19,235	18,862	20,883	19,778	24,237	25,291	23,897	24,801	23,571	23,845	24,757
NGLs (bbls/d)	7,196	7,045	7,412	7,344	6,538	7,895	7,497	7,901	8,113	8,342	8,461	8,068
Natural gas (mmcf/d)	165.75	160.07	167.65	171.19	166.49	167.48	154.26	152.07	150.68	148.11	137.93	145.18
Total (boe/d)	54,987	52,960	54,216	56,758	54,065	60,046	58,499	57,142	58,027	56,598	55,295	57,022
International
Crude oil and condensate (bbls/d)	11,998	15,938	9,221	9,950	10,302	8,087	16,257	11,493	11,720	12,615	13,985	15,227
Natural gas (mmcf/d)	103.64	114.52	116.27	92.61	117.14	80.13	79.97	82.05	89.15	96.58	100.22	81.55
Total (boe/d)	29,271	35,026	28,598	25,386	29,824	21,442	29,585	25,169	26,578	28,712	30,689	28,820
Consolidated
Crude oil and condensate (bbls/d)	32,163	35,174	28,083	30,833	30,080	32,324	41,547	35,391	36,522	36,186	37,830	39,985
NGLs (bbls/d)	7,196	7,046	7,412	7,344	6,538	7,896	7,497	7,901	8,113	8,342	8,461	8,068
Natural gas (mmcf/d)	269.39	274.59	283.92	263.80	283.63	247.61	234.23	234.12	239.83	244.69	238.16	226.73
Total (boe/d)	84,258	87,985	82,814	82,144	83,889	81,489	88,083	82,312	84,607	85,310	85,984	85,841

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Financial results

	Q2/24	Q1/24	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21
North America
Crude oil and condensate sales ($/bbl)	104.57	91.50	100.16	103.46	94.78	95.63	106.66	114.82	134.72	111.42	92.99	82.23
NGL sales ($/bbl)	31.61	34.16	33.38	27.77	28.11	36.24	39.93	44.64	51.86	46.94	47.26	35.55
Natural gas sales ($/mcf)	1.29	2.14	2.62	2.52	2.29	4.11	5.96	6.41	7.13	4.80	5.07	3.80
Sales ($/boe)	46.37	44.25	47.51	49.26	45.12	54.84	66.95	71.24	83.34	65.88	59.97	50.40
Royalties ($/boe)	(6.93)	(7.03)	(7.25)	(7.75)	(5.45)	(7.68)	(9.47)	(12.58)	(12.51)	(11.24)	(9.26)	(7.14)
Transportation ($/boe)	(2.82)	(2.35)	(2.44)	(2.08)	(1.57)	(2.44)	(2.42)	(2.16)	(2.15)	(1.91)	(1.86)	(1.92)
Operating ($/boe)	(13.89)	(14.25)	(11.50)	(12.09)	(12.22)	(14.10)	(13.51)	(14.00)	(11.58)	(11.95)	(11.68)	(11.02)
General and administration ($/boe)	(2.54)	(1.70)	0.87	(0.72)	0.10	(0.99)	0.10	(1.27)	(1.52)	(1.26)	(2.01)	(1.14)
Corporate income taxes ($/boe)	0.82	(0.65)	0.23	(0.01)	(0.10)	(0.12)	(0.13)	(0.03)	-	(0.02)	0.42	(0.05)
Fund flows from operations ($/boe)	21.01	18.27	27.42	26.61	25.88	29.51	41.52	41.20	55.58	39.50	35.58	29.13
Fund flows from operations	105,187	88,027	136,766	138,960	127,346	159,435	223,443	216,579	293,470	201,193	180,979	152,764
Drilling and development	(61,520)	(136,509)	(58,704)	(69,703)	(135,723)	(116,070)	(113,892)	(112,238)	(54,913)	(57,513)	(89,643)	(35,179)
Free cash flow	43,667	(48,482)	78,062	69,257	(8,377)	43,365	109,551	104,341	238,557	143,680	91,336	117,585
International
Crude oil and condensate sales ($/bbl)	116.24	119.68	123.77	114.26	100.23	107.57	128.02	140.09	146.67	136.69	103.53	94.91
Natural gas sales ($/mcf)	12.72	11.63	16.92	13.34	14.58	24.69	39.54	58.55	32.33	36.75	35.54	18.82
Sales ($/boe)	92.68	92.48	108.70	93.46	91.89	132.84	177.23	254.86	173.14	183.66	163.23	103.39
Royalties ($/boe)	(4.49)	(4.60)	(3.41)	3.55	(7.43)	(13.39)	(6.38)	(7.21)	(7.23)	(5.43)	(4.13)	(4.52)
Transportation ($/boe)	(4.20)	(3.65)	(3.91)	(4.53)	(5.23)	(5.11)	(3.29)	(3.51)	(3.64)	(2.91)	(3.40)	(3.47)
Operating ($/boe)	(26.56)	(25.30)	(22.64)	(25.58)	(28.24)	(31.41)	(23.35)	(22.63)	(22.11)	(19.86)	(18.86)	(17.55)
General and administration ($/boe)	(5.20)	(4.86)	(9.18)	(7.37)	(7.58)	(7.52)	(5.09)	(3.34)	(3.16)	(3.02)	(2.53)	(2.40)
Corporate income taxes ($/boe)	(6.08)	(7.06)	(7.81)	(13.42)	(6.79)	(11.20)	(15.15)	(21.97)	(28.73)	(17.63)	(12.17)	0.64
PRRT ($/boe)	(1.37)	(3.38)	7.93	-	-	-	(1.85)	(1.96)	(0.83)	(2.60)	(1.96)	(2.74)
Fund flows from operations ($/boe)	44.78	43.63	69.68	46.11	36.62	64.21	122.12	194.24	107.44	132.21	120.18	73.35
Fund flows from operations	119,310	139,054	183,353	107,704	99,377	123,893	332,377	449,771	259,840	341,626	339,286	194,505
Drilling and development	(47,830)	(45,789)	(73,604)	(49,701)	(28,347)	(37,258)	(43,957)	(65,640)	(54,575)	(25,328)	(29,359)	(27,994)
Exploration and evaluation	(1,260)	(8,144)	(10,579)	(6,235)	(2,775)	(1,492)	(11,456)	(6,137)	(3,665)	(2,503)	(26,805)	(3,277)
Free cash flow	70,220	85,121	99,170	51,768	68,255	85,143	276,964	377,994	201,600	313,795	283,122	163,234

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	Q2/24	Q1/24	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21
Consolidated
Crude oil and condensate sales ($/bbl)	108.93	104.26	107.91	106.94	96.64	98.62	115.02	123.02	138.55	120.23	96.88	87.05
NGL sales ($/bbl)	31.61	34.16	33.38	27.77	28.11	36.23	39.93	44.64	51.86	46.94	47.26	35.55
Natural gas sales ($/mcf)	5.69	6.10	8.48	6.32	7.37	10.77	17.43	24.68	16.50	17.41	17.89	9.20
Sales ($/boe)	62.46	63.45	68.64	62.92	61.74	75.36	103.99	127.39	111.55	105.52	96.82	68.19
Royalties ($/boe)	(6.08)	(6.06)	(5.93)	(4.26)	(6.16)	(9.18)	(8.43)	(10.94)	(10.85)	(9.29)	(7.43)	(6.26)
Transportation ($/boe)	(3.30)	(2.87)	(2.95)	(2.84)	(2.87)	(3.14)	(2.71)	(2.57)	(2.62)	(2.25)	(2.41)	(2.44)
Operating ($/boe)	(18.29)	(18.65)	(15.35)	(16.26)	(17.91)	(18.66)	(16.81)	(16.64)	(14.89)	(14.61)	(14.24)	(13.21)
General and administration ($/boe)	(3.46)	(2.96)	(2.60)	(2.77)	(2.63)	(2.71)	(1.65)	(1.90)	(2.04)	(1.85)	(2.20)	(1.56)
Corporate income taxes ($/boe)	(1.58)	(3.20)	(2.54)	(4.15)	(2.48)	(3.04)	(5.18)	(6.74)	(9.03)	(5.95)	(4.07)	0.18
Windfall taxes ($/boe)	-	-	(0.03)	(2.90)	(4.56)	(2.92)	(27.50)	-	-	-	-	-
PRRT ($/boe)	(0.47)	(1.35)	2.74	-	-	-	(0.62)	(0.60)	(0.26)	(0.87)	(0.70)	(0.92)
Interest ($/boe)	(2.75)	(2.30)	(3.01)	(2.68)	(2.65)	(2.98)	(2.78)	(3.23)	(2.74)	(1.93)	(2.06)	(2.37)
Equity based compensation ($/boe)	(1.87)	-	-	-	-	-	-	-	-	-	-	-
Realized derivatives ($/boe)	6.00	27.55	10.33	9.74	8.86	1.95	(5.42)	(18.22)	(10.36)	(18.78)	(23.97)	(9.19)
Realized foreign exchange ($/boe)	0.30	0.23	(0.73)	0.28	0.48	(0.65)	2.33	(0.28)	(0.30)	0.10	(0.30)	0.37
Realized other ($/boe)	(0.09)	0.02	0.26	(1.32)	0.53	0.49	(0.14)	0.80	0.36	0.70	1.29	0.48
Fund flows from operations ($/boe)	30.87	53.86	48.83	35.76	32.35	34.52	35.08	67.07	58.82	50.79	40.73	33.27
Fund flows from operations	236,703	431,358	372,117	270,214	247,109	253,167	284,220	507,876	452,901	389,868	322,173	262,696
Drilling and development	(109,350)	(182,298)	(132,308)	(119,404)	(164,070)	(153,328)	(157,849)	(177,878)	(109,488)	(82,841)	(119,002)	(63,173)
Exploration and evaluation	(1,260)	(8,144)	(10,579)	(6,235)	(2,775)	(1,492)	(11,456)	(6,137)	(3,665)	(2,503)	(26,805)	(3,277)
Free cash flow	126,093	240,916	229,230	144,575	80,264	98,347	114,915	323,861	339,748	304,524	176,366	196,246

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Non-GAAP and Other Specified Financial Measures

This MD&A includes references to certain financial measures which do not have standardized meanings and may not be comparable to similar measures presented by other issuers. These financial measures include fund flows from operations, a total of segments measure of profit or loss in accordance with IFRS 8 “Operating Segments” (please see Segmented Information in the Notes to the condensed Consolidated Interim Financial Statements) and net debt, a capital management measure in accordance with IAS 1 “Presentation of Financial Statements” (please see Capital Disclosures in the Notes to the condensed Consolidated Interim Financial Statements).

In addition, this MD&A includes financial measures which are not specified, defined, or determined under IFRS and are therefore considered non-GAAP financial measures and may not be comparable to similar measures presented by other issuers. These non-GAAP financial measures include:

Total of Segments Measure

Fund flows from operations (FFO): Most directly comparable to net (loss) earnings, FFO is comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, equity based compensation settled in cash, realized loss on derivatives, realized foreign exchange gain (loss), and realized other income. The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Reconciliation to the primary financial statement measures can be found below.

	Q2 2024		Q2 2023		YTD 2024		YTD 2023
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	478,925	62.46	471,356	61.74	986,960	62.97	1,024,054	68.42
Royalties	(46,610)	(6.08)	(46,993)	(6.16)	(95,163)	(6.07)	(114,337)	(7.64)
Transportation	(25,317)	(3.30)	(21,905)	(2.87)	(48,279)	(3.08)	(44,955)	(3.00)
Operating	(140,230)	(18.29)	(136,749)	(17.91)	(289,541)	(18.47)	(273,574)	(18.28)
General and administration	(26,537)	(3.46)	(20,058)	(2.63)	(50,240)	(3.21)	(39,947)	(2.67)
Corporate income tax expense	(12,096)	(1.58)	(18,928)	(2.48)	(37,738)	(2.41)	(41,190)	(2.75)
Windfall taxes	-	-	(34,784)	(4.56)	-	-	(56,224)	(3.76)
PRRT	(3,638)	(0.47)	-	-	(14,421)	(0.92)	-	-
Interest expense	(21,062)	(2.75)	(20,210)	(2.65)	(39,454)	(2.52)	(42,085)	(2.81)
Equity based compensation	(14,361)	(1.87)	-	-	(14,361)	(0.92)	-	-
Realized gain on derivatives	46,017	6.00	67,673	8.86	266,632	17.01	82,003	5.48
Realized foreign exchange gain (loss)	2,267	0.30	3,679	0.48	4,138	0.26	(1,092)	(0.07)
Realized other income	(655)	(0.09)	4,028	0.53	(472)	(0.03)	7,623	0.51
Fund flows from operations	236,703	30.87	247,109	32.35	668,061	42.61	500,276	33.43
Equity based compensation	3,860		(4,998)		(1,658)		(28,523)
Unrealized (loss) gain on derivative instruments ^(1)^	(125,789)		11,177		(314,533)		103,875
Unrealized foreign exchange gain (loss) ^(1)^	3,069		35,124		(18,572)		19,646
Accretion	(18,209)		(18,599)		(36,143)		(38,650)
Depletion and depreciation	(161,184)		(154,389)		(339,618)		(302,520)
Deferred tax (expense) recovery	(20,667)		480		(37,312)		36,946
Gain on business combination	-		12,544		-		445,094
Loss on disposition	-		-		-		(226,828)
Unrealized other expense ^(1)^	(208)		(540)		(345)		(1,076)
Net (loss) earnings	(82,425)		127,908		(80,120)		508,240
^(1)^	Unrealized (loss) gain on derivative instruments, Unrealized foreign exchange gain (loss), and Unrealized<br>other expense are line items from the respective Consolidated Statements of Cash Flows.
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Non-GAAP Financial Measures and Non-GAAP Ratios

Free cash flow: Most directly comparable to cash flows from operating activities and is comprised of fund flows from operations less drilling and development costs and exploration and evaluation costs. The measure is used to determine the funding available for investing and financing activities including payment of dividends, repayment of long-term debt, reallocation into existing business units and deployment into new ventures. Reconciliation to the primary financial statement measures can be found in the following table.

($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Cash flows from operating activities	266,322	173,632	620,617	562,261
Changes in non-cash operating working capital	(41,364)	61,584	30,724	(76,432)
Asset retirement obligations settled	11,745	11,893	16,720	14,447
Fund flows from operations	236,703	247,109	668,061	500,276
Drilling and development	(109,350)	(164,070)	(291,648)	(317,398)
Exploration and evaluation	(1,260)	(2,775)	(9,404)	(4,267)
Free cash flow	126,093	80,264	367,009	178,611

Capital expenditures: Calculated as the sum of drilling and development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows that is most directly comparable to cash flows used in investing activities. We consider capital expenditures to be a useful measure of our investment in our existing asset base. Capital expenditures are also referred to as E&D capital. Reconciliation to the primary financial statement measures can be found below.

($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Drilling and development	109,350	164,070	291,648	317,398
Exploration and evaluation	1,260	2,775	9,404	4,267
Capital expenditures	110,610	166,845	301,052	321,665

Payout and payout % of FFO: A non-GAAP financial measure and non-GAAP ratio respectively, most directly comparable to dividends declared. Payout is comprised of dividends declared plus drilling and development costs, exploration and evaluation costs, and asset retirement obligations settled, and payout % of FFO is calculated as payout over FFO (total of segments measure). The measure is used to assess the amount of cash distributed back to shareholders and reinvested in the business for maintaining production and organic growth. The reconciliation of the measure to the primary financial statement measure can be found below.

($M)	Q2 2024	Q2 2023	YTD 2024	YTD 2023
Dividends declared	18,981	16,430	38,164	32,656
Drilling and development	109,350	164,070	291,648	317,398
Exploration and evaluation	1,260	2,775	9,404	4,267
Asset retirement obligations settled	11,745	11,893	16,720	14,447
Payout	141,336	195,168	355,936	368,768
% of fund flows from operations	60 %	79 %	53 %	74 %

Return on capital employed (ROCE): A non-GAAP ratio**,** ROCE is a measure that we use to analyze our profitability and the efficiency of our capital allocation process; the comparable primary financial statement measure is earnings before income taxes. ROCE is calculated by dividing net (loss) earnings before interest and taxes ("EBIT") by average capital employed over the preceding twelve months. Capital employed is calculated as total assets less current liabilities while average capital employed is calculated using the balance sheets at the beginning and end of the twelve-month period.

	Twelve Months Ended
($M)	Jun 30, 2024	Jun 30, 2023
Net (loss) earnings	(825,947)	1,174,727
Taxes	(11,691)	667,200
Interest expense	82,581	89,046
EBIT	(755,057)	1,930,973
Average capital employed	5,906,288	5,816,057
Return on capital employed	(13) %	33 %

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	As at
($M)	Jun 30, 2024	Dec 31, 2023
Current assets	740,882	823,514
Current derivative asset	(97,165)	(313,792)
Current liabilities	(679,478)	(696,074)
Current lease liability	28,136	21,068
Current derivative liability	16,274	732
Adjusted working capital	8,649	(164,552)

($M)	Q2 2024	Q2 2023	Q2 2024	Q2 2023
Acquisitions, net of cash acquired	5,450	2,196	5,829	136,421
Acquisition of securities	-	632	9,373	2,108
Acquired working capital	-	(12,544)	-	103,527
Acquisitions	5,450	(9,716)	15,202	242,056

Capital Management Measure

Net debt: Is in accordance with IAS 1 "Presentation of Financial Statements" that is most directly comparable to long-term debt. Net debt is comprised of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current lease liabilities), and represents Vermilion's net financing obligations after adjusting for the timing of working capital fluctuations. Net debt excludes lease obligations which are secured by a corresponding right-of-use asset.

	As at
($M)	Jun 30, 2024	Dec 31, 2023
Long-term debt	915,364	914,015
Adjusted working capital	(8,649)	164,552
Net debt	906,715	1,078,567
Ratio of net debt to four quarter trailing fund flows from operations	0.7	0.9

Supplementary Financial Measures

Diluted shares outstanding: The sum of shares outstanding at the period end plus outstanding awards under the LTIP, based on current estimates of future performance factors and forfeiture rates.

('000s of shares)	Q2 2024	Q2 2023
Shares outstanding	158,174	164,294
Potential shares issuable pursuant to the LTIP	3,498	4,236
Diluted shares outstanding	161,672	168,530

| Vermilion Energy Inc.  ■  Page 50  ■  2024 Second Quarter Report |

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Fund flows from operations per basicand diluted share: Management assesses fund flows from operations on a per share basis as we believe this provides a measure of our operating performance after taking into account the issuance and potential future issuance of Vermilion common shares. Fund flows from operations per basic share is calculated by dividing fund flows from operations (total of segments measure) by the basic weighted average shares outstanding as defined under IFRS. Fund flows from operations per diluted share is calculated by dividing fund flows from operations by the sum of basic weighted average shares outstanding and incremental shares issuable under the equity based compensation plans as determined using the treasury stock method.

Operating netback: Most directly comparable to net (loss) earnings that is calculated as sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses presented on a per unit basis. Management assesses operating netback as a measure of the profitability and efficiency of our field operations.

**Fund flows from operations per boe:**Calculated as FFO (total of segments measure) by boe production. Fund flows from operations netback is used by management to assess the profitability of our business units and Vermilion as a whole.

Cash dividends per share: Represents cash dividends declared per share that is a useful measure of the dividends a common shareholder was entitled to during the period.

Covenants: The financial covenants on our revolving credit facility contain non-GAAP measures. The definitions for these financial covenants are included in Financial Position Review.

| Vermilion Energy Inc.  ■  Page 51  ■  2024 Second Quarter Report |

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Consolidated Interim Financial Statements

Consolidated Balance Sheet

thousands of Canadian dollars, unaudited

	Note	June 30, 2024	December 31, 2023
Assets
Current
Cash and cash equivalents	11	267,672	141,456
Accounts receivable		258,471	242,926
Crude oil inventory		45,374	57,333
Derivative instruments		97,165	313,792
Prepaid expenses		72,200	68,007
Total current assets		740,882	823,514
Derivative instruments		33,905	76,107
Investments	3	80,129	73,261
Deferred taxes		139,461	182,051
Exploration and evaluation assets	5	209,920	198,379
Capital assets	4	4,978,527	4,882,509
Total assets		6,182,824	6,235,821
Liabilities
Current
Accounts payable and accrued liabilities		361,151	380,370
Dividends payable	9	18,981	16,227
Derivative instruments		16,274	732
Income taxes payable		283,072	298,745
Total current liabilities		679,478	696,074
Derivative instruments		61,212	21,050
Long-term debt	8	915,364	914,015
Lease obligations		93,234	33,001
Asset retirement obligations	6	1,225,699	1,159,063
Deferred taxes		377,210	380,970
Total liabilities		3,352,197	3,204,173
Shareholders' Equity
Shareholders' capital	9	4,020,269	4,142,566
Contributed surplus		35,008	43,348
Accumulated other comprehensive income		107,871	109,302
Deficit		(1,332,521)	(1,263,568)
Total shareholders' equity		2,830,627	3,031,648
Total liabilities and shareholders' equity		6,182,824	6,235,821

Approved by the Board

(Signed “Manjit Sharma”)	(Signed “Dion Hatcher”)
Manjit Sharma, Director	Dion Hatcher, Director

| Vermilion Energy Inc.  ■  Page 52  ■  2024 Second Quarter Report |

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Consolidated Statements of Net (Loss) Earnings and Comprehensive (Loss) Income

thousands of Canadian dollars, except share and per share amounts, unaudited

		Three Months Ended		Six Months Ended
	Note	Jun 30, 2024	Jun 30, 2023	Jun 30, 2024	Jun 30, 2023
Revenue
Petroleum and natural gas sales		478,925	471,356	986,960	1,024,054
Royalties		(46,610)	(46,993)	(95,163)	(114,337)
Sales of purchased commodities		28,651	38,278	67,021	87,290
Petroleum and natural gas revenue		460,966	462,641	958,818	997,007
Expenses
Purchased commodities		28,651	38,278	67,021	87,290
Operating		140,230	136,749	289,541	273,574
Transportation		25,317	21,905	48,279	44,955
Equity based compensation		10,501	4,998	16,019	28,523
Loss (gain) on derivative instruments		79,772	(78,850)	47,901	(185,878)
Interest expense		21,062	20,210	39,454	42,085
General and administration		26,537	20,058	50,240	39,947
Foreign exchange (gain) loss		(5,336)	(38,803)	14,434	(18,554)
Other expense (income)		863	(3,488)	817	(6,547)
Accretion	6	18,209	18,599	36,143	38,650
Depletion and depreciation	4, 5	161,184	154,389	339,618	302,520
Gain on business combination		-	(12,544)	-	(445,094)
Loss on disposition		-	-	-	226,828
		506,990	281,501	949,467	428,299
(Loss) earnings before income taxes		(46,024)	181,140	9,351	568,708
Income tax expense (recovery)
Deferred		20,667	(480)	37,312	(36,946)
Current		15,734	18,928	52,159	41,190
Windfall taxes		-	34,784	-	56,224
		36,401	53,232	89,471	60,468
Net (loss) earnings		(82,425)	127,908	(80,120)	508,240
Other comprehensive (loss) income
Currency translation adjustments		(1,406)	(56,293)	(2,491)	(31,612)
Hedge accounting reserve, net of tax		1,631	1,634	3,263	3,789
Fair value adjustment on investment in securities, net of tax	3	-	5,884	(2,203)	151
Comprehensive (loss) income		(82,200)	79,133	(81,551)	480,568
Net (loss) earnings per share
Basic		(0.52)	0.78	(0.50)	3.10
Diluted		(0.52)	0.76	(0.50)	3.04
Weighted average shares outstanding ('000s)
Basic		159,525	164,997	160,373	163,798
Diluted		161,069	167,364	162,022	167,343

| Vermilion Energy Inc.  ■  Page 53  ■  2024 Second Quarter Report |

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Consolidated Statements of Cash Flows

thousands of Canadian dollars, unaudited

		Three Months Ended		Six Months Ended
	Note	Jun 30, 2024	Jun 30, 2023	Jun 30, 2024	Jun 30, 2023
Operating
Net (loss) earnings		(82,425)	127,908	(80,120)	508,240
Adjustments:
Accretion	6	18,209	18,599	36,143	38,650
Depletion and depreciation	4, 5	161,184	154,389	339,618	302,520
Gain on business combination		-	(12,544)	-	(445,094)
Loss on disposition		-	-	-	226,828
Unrealized loss (gain) on derivative instruments		125,789	(11,177)	314,533	(103,875)
Equity based compensation		(3,860)	4,998	1,658	28,523
Unrealized foreign exchange (gain) loss		(3,069)	(35,124)	18,572	(19,646)
Unrealized other expense		208	540	345	1,076
Deferred tax expense (recovery)		20,667	(480)	37,312	(36,946)
Asset retirement obligations settled	6	(11,745)	(11,893)	(16,720)	(14,447)
Changes in non-cash operating working capital		41,364	(61,584)	(30,724)	76,432
Cash flows from operating activities		266,322	173,632	620,617	562,261
Investing
Drilling and development	4	(109,350)	(164,070)	(291,648)	(317,398)
Exploration and evaluation	5	(1,260)	(2,775)	(9,404)	(4,267)
Acquisitions, net of cash acquired	4	(5,450)	(2,196)	(5,829)	(136,421)
Acquisition of securities	3	-	(632)	(9,373)	(2,108)
Dispositions	4	-	-	-	182,152
Changes in non-cash investing working capital		(36,965)	5,269	(18,114)	4,943
Cash flows used in investing activities		(153,025)	(164,404)	(334,368)	(273,099)
Financing
Net repayments on the revolving credit facility	8	-	-	-	(146,591)
Repurchases of senior unsecured notes	8	(27,592)	-	(31,561)	-
Payments on lease obligations		(7,830)	(4,665)	(11,932)	(9,064)
Repurchase of shares	9	(46,555)	(24,316)	(82,964)	(54,457)
Cash dividends	9	(19,183)	(16,226)	(35,410)	(29,284)
Changes in non-cash financing working capital		1,627	-	1,627	-
Cash flows used in financing activities		(99,533)	(45,207)	(160,240)	(239,396)
Foreign exchange (loss) gain on cash held in foreign currencies		(743)	(13,165)	207	(12,902)
Net change in cash and cash equivalents		13,021	(49,144)	126,216	36,864
Cash and cash equivalents, beginning of period		254,651	99,844	141,456	13,836
Cash and cash equivalents, end of period		267,672	50,700	267,672	50,700
Supplementary information for cash flows from operating activities
Interest paid		28,330	25,374	41,982	42,645
Income taxes paid		64,849	138,469	67,827	152,776

| Vermilion Energy Inc.  ■  Page 54  ■  2024 Second Quarter Report |

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Consolidated Statements of Changes in Shareholders' Equity

thousands of Canadian dollars, unaudited

		Six Months Ended
	Note	June 30, 2024	June 30, 2023
Shareholders' capital	9
Balance, beginning of period		4,142,566	4,243,794
Vesting of equity based awards		9,998	21,175
Equity based compensation		-	10,280
Share-settled dividends on vested equity based awards		1,257	1,051
Repurchase of shares		(133,552)	(78,112)
Balance, end of period		4,020,269	4,198,188
Contributed surplus	9
Balance, beginning of period		43,348	35,409
Equity based compensation		1,658	18,243
Vesting of equity based awards		(9,998)	(21,175)
Balance, end of period		35,008	32,477
Accumulated other comprehensive income
Balance, beginning of period		109,302	123,505
Currency translation adjustments		(2,491)	(31,612)
Hedge accounting reserve		3,263	3,789
Fair value adjustment on investment in securities, net of tax	3	(2,203)	151
Balance, end of period		107,871	95,833
Deficit
Balance, beginning of period		(1,263,568)	(1,001,650)
Net (loss) earnings		(80,120)	508,240
Dividends declared		(38,164)	(32,656)
Share-settled dividends on vested equity based awards		(1,257)	(1,051)
Repurchase of shares	9	50,588	23,655
Balance, end of period		(1,332,521)	(503,462)
Total shareholders' equity		2,830,627	3,823,036

| Vermilion Energy Inc.  ■  Page 55  ■  2024 Second Quarter Report |

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Description of equity reserves

Shareholders’ capital

Represents the recognized amount for common shares issued (net of equity issuance costs and deferred taxes) less the weighted-average carrying value of shares repurchased. The price paid to repurchase common shares is compared to the carrying value of the shares and the difference is recorded against deficit.

Contributed surplus

Represents the recognized value of unvested equity based awards that will be settled in shares. Once vested, the value of the awards are transferred to shareholders’ capital.

Accumulated other comprehensive income

Represents currency translation adjustments, hedge accounting reserve and fair value adjustments on investments.

Currency translation adjustments result from translating the balance sheets of subsidiaries with a foreign functional currency to Canadian dollars at period-end rates. These amounts may be reclassified to net (loss) earnings if there is a disposal or partial disposal of a subsidiary.

The hedge accounting reserve represents the effective portion of the change in fair value related to cash flow and net investment hedges recognized in other comprehensive income, net of tax and reclassified to the consolidated statement of net (loss) earnings in the same period in which the transaction associated with the hedged item occurs.

Fair value adjustment on investment in securities, net of tax, are a result of changes in the fair value of investments that have been elected to be subsequently measured at fair value through other comprehensive income.

Deficit

Represents the cumulative net (loss) earnings less distributed earnings and surplus of the price paid to repurchase common shares of Vermilion Energy Inc. over the weighted-average carrying value of the shares repurchased.

| Vermilion Energy Inc.  ■  Page 56  ■  2024 Second Quarter Report |

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Notes to the Condensed Consolidated Interim Financial Statements for the three and six months ended June 30, 2024 and 2023

tabular amounts in thousands of Canadian dollars, except share and per share amounts, unaudited

1. Basis of presentation

Vermilion Energy Inc. (the “Company” or “Vermilion”) is a corporation governed by the laws of the Province of Alberta and is actively engaged in the business of crude oil and natural gas exploration, development, acquisition, and production.

These condensed consolidated interim financial statements are in compliance with International Accounting Standard (“IAS”) 34, “Interim Financial Reporting”. These condensed consolidated interim financial statements have been prepared using the same accounting policies and methods of computation as Vermilion’s consolidated financial statements for the year ended December 31, 2023.

These condensed consolidated interim financial statements should be read in conjunction with Vermilion’s consolidated financial statements for the year ended December 31, 2023, which are contained within Vermilion’s Annual Report for the year ended December 31, 2023 and are available on SEDAR+ at www.sedarplus.ca or on Vermilion’s website at www.vermilionenergy.com.

These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on July 31, 2024.

| Vermilion Energy Inc.  ■  Page 57  ■  2024 Second Quarter Report |

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---
	Three Months Ended June 30, 2024
---	---	---	---	---	---	---	---	---	---
	Canada	USA	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Drilling and development	59,207	2,313	11,389	4,033	20,637	356	8,809	2,606	109,350
Exploration and evaluation	-	-	-	-	1,260	-	-	-	1,260
Crude oil and condensate sales	154,561	37,339	83,656	481	9,954	-	32,787	34	318,812
NGL sales	16,431	4,269	-	-	-	-	-	-	20,700
Natural gas sales	18,643	807	-	30,060	19,203	69,793	-	907	139,413
Sales of purchased commodities	-	-	-	-	-	-	-	28,651	28,651
Royalties	(22,166)	(12,487)	(10,283)	-	(1,435)	-	-	(239)	(46,610)
Revenue from external customers	167,469	29,928	73,373	30,541	27,722	69,793	32,787	29,353	460,966
Purchased commodities	-	-	-	-	-	-	-	(28,651)	(28,651)
Transportation	(13,573)	(551)	(6,401)	-	(2,386)	(2,406)	-	-	(25,317)
Operating	(63,140)	(6,346)	(14,606)	(10,709)	(14,430)	(16,453)	(14,174)	(372)	(140,230)
General and administration	(5,451)	(3,274)	(3,807)	(1,775)	(3,062)	(1,462)	(2,005)	(5,701)	(26,537)
PRRT	-	-	-	-	-	-	(3,638)	-	(3,638)
Corporate income taxes	(1)	-	(5,956)	(7,858)	(1,704)	(318)	(349)	4,090	(12,096)
Interest expense	-	-	-	-	-	-	-	(21,062)	(21,062)
Equity based compensation	-	-	-	-	-	-	-	(14,361)	(14,361)
Realized gain on derivative instruments	-	-	-	-	-	-	-	46,017	46,017
Realized foreign exchange gain	-	-	-	-	-	-	-	2,267	2,267
Realized other expense	-	-	-	-	-	-	-	(655)	(655)
Fund flows from operations	85,304	19,757	42,603	10,199	6,140	49,154	12,621	10,925	236,703
	Three Months Ended June 30, 2023
	Canada	USA	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Drilling and development	73,471	62,252	11,326	5,815	5,220	(619)	5,470	1,135	164,070
Exploration and evaluation	-	-	-	-	2,633	-	-	142	2,775
Crude oil and condensate sales	141,027	29,547	79,718	398	13,817	30	-	-	264,537
NGL sales	13,207	3,517	-	-	-	-	-	-	16,724
Natural gas sales	33,555	1,127	-	37,858	28,436	88,659	-	460	190,095
Sales of purchased commodities	-	-	-	-	-	-	-	38,278	38,278
Royalties	(18,000)	(8,824)	(10,833)	(6,653)	(2,496)	-	-	(187)	(46,993)
Revenue from external customers	169,789	25,367	68,885	31,603	39,757	88,689	-	38,551	462,641
Purchased commodities	-	-	-	-	-	-	-	(38,278)	(38,278)
Transportation	(7,639)	(65)	(8,215)	-	(3,409)	(2,577)	-	-	(21,905)
Operating	(53,430)	(6,686)	(24,756)	(13,691)	(10,953)	(10,526)	(16,415)	(292)	(136,749)
General and administration	(21,925)	(1,273)	(7,848)	996	(4,643)	(4,763)	(2,583)	21,981	(20,058)
Corporate income taxes	1	-	(1,805)	(5,818)	(9,690)	(227)	(886)	(503)	(18,928)
Windfall tax	-	-	-	-	-	-	-	(34,784)	(34,784)
Interest expense	-	-	-	-	-	-	-	(20,210)	(20,210)
Realized gain on derivative instruments	-	-	-	-	-	-	-	67,673	67,673
Realized foreign exchange gain	-	-	-	-	-	-	-	3,679	3,679
Realized other income	-	-	-	-	-	-	-	4,028	4,028
Fund flows from operations	86,796	17,343	26,261	13,090	11,062	70,596	(19,884)	41,845	247,109

| Vermilion Energy Inc.  ■  Page 58  ■  2024 Second Quarter Report |

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---	---	---	---	---	---	---	---	---	---
	Canada	USA	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,956,640	265,249	637,424	211,695	473,207	947,012	285,741	1,405,856	6,182,824
Drilling and development	183,489	14,540	22,404	8,631	41,047	3,449	14,980	3,108	291,648
Exploration and evaluation	-	-	-	-	4,878	-	-	4,526	9,404
Crude oil and condensate sales	283,049	69,005	172,652	1,755	18,431	-	107,613	34	652,539
NGL sales	33,764	8,839	-	-	-	-	-	-	42,603
Natural gas sales	47,867	2,782	-	63,752	41,910	134,257	-	1,250	291,818
Sales of purchased commodities	-	-	-	-	-	-	-	67,021	67,021
Royalties	(44,721)	(23,812)	(23,335)	(217)	(2,790)	-	-	(288)	(95,163)
Revenue from external customers	319,959	56,814	149,317	65,290	57,551	134,257	107,613	68,017	958,818
Purchased commodities	-	-	-	-	-	-	-	(67,021)	(67,021)
Transportation	(24,527)	(930)	(11,764)	-	(5,578)	(5,480)	-	-	(48,279)
Operating	(123,598)	(14,560)	(36,046)	(21,319)	(25,191)	(27,057)	(40,960)	(810)	(289,541)
General and administration	(18,448)	(6,540)	(8,996)	(3,713)	(5,634)	(3,632)	(3,743)	466	(50,240)
PRRT	-	-	-	-	-	-	(14,421)	-	(14,421)
Corporate income taxes	(2)	-	(11,781)	(18,869)	(6,076)	(769)	(1,190)	949	(37,738)
Interest expense	-	-	-	-	-	-	-	(39,454)	(39,454)
Equity based compensation	-	-	-	-	-	-	-	(14,361)	(14,361)
Realized gain on derivative instruments	-	-	-	-	-	-	-	266,632	266,632
Realized foreign exchange gain	-	-	-	-	-	-	-	4,138	4,138
Realized other expense	-	-	-	-	-	-	-	(472)	(472)
Fund flows from operations	153,384	34,784	80,730	21,389	15,072	97,319	47,299	218,084	668,061
	Six Months Ended June 30, 2023
	Canada	USA	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	2,412,745	665,025	809,150	204,546	380,429	1,185,195	251,980	1,270,918	7,179,988
Drilling and development	175,321	76,472	23,011	16,197	12,936	1,439	10,602	1,420	317,398
Exploration and evaluation	-	-	-	1	3,081	-	-	1,185	4,267
Crude oil and condensate sales	323,810	55,373	144,184	882	27,161	32	-	-	551,442
NGL sales	34,846	7,625	-	-	-	-	-	-	42,471
Natural gas sales	93,230	3,448	-	106,455	86,564	138,144	-	2,300	430,141
Sales of purchased commodities	-	-	-	-	-	-	-	87,290	87,290
Royalties	(50,896)	(17,427)	(17,924)	(21,482)	(5,399)	-	-	(1,209)	(114,337)
Revenue from external customers	400,990	49,019	126,260	85,855	108,326	138,176	-	88,381	997,007
Purchased commodities	-	-	-	-	-	-	-	(87,290)	(87,290)
Transportation	(20,753)	(132)	(14,415)	-	(6,173)	(3,482)	-	-	(44,955)
Operating	(123,097)	(13,238)	(41,303)	(26,603)	(21,616)	(15,144)	(31,746)	(827)	(273,574)
General and administration	(45,462)	(3,789)	(12,681)	(1,115)	(7,384)	(6,040)	(4,318)	40,842	(39,947)
Corporate income taxes	-	-	(3,015)	(12,512)	(22,772)	(227)	(1,515)	(1,149)	(41,190)
Windfall tax	-	-	-	-	-	-	-	(56,224)	(56,224)
Interest expense	-	-	-	-	-	-	-	(42,085)	(42,085)
Realized gain on derivative instruments	-	-	-	-	-	-	-	82,003	82,003
Realized foreign exchange loss	-	-	-	-	-	-	-	(1,092)	(1,092)
Realized other income	-	-	-	-	-	-	-	7,623	7,623
Fund flows from operations	211,678	31,860	54,846	45,625	50,381	113,283	(37,579)	30,182	500,276

| Vermilion Energy Inc.  ■  Page 59  ■  2024 Second Quarter Report |

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Reconciliation of fund flows from operations to net(loss) earnings:

	Three Months Ended		Six Months Ended
	Jun 30, 2024	Jun 30, 2023	Jun 30, 2024	Jun 30, 2023
Fund flows from operations	236,703	247,109	668,061	500,276
Equity based compensation	3,860	(4,998)	(1,658)	(28,523)
Unrealized (loss) gain on derivative instruments	(125,789)	11,177	(314,533)	103,875
Unrealized foreign exchange gain (loss)	3,069	35,124	(18,572)	19,646
Accretion	(18,209)	(18,599)	(36,143)	(38,650)
Depletion and depreciation	(161,184)	(154,389)	(339,618)	(302,520)
Deferred tax (expense) recovery	(20,667)	480	(37,312)	36,946
Gain on business combination	-	12,544	-	445,094
Loss on disposition	-	-	-	(226,828)
Unrealized other expense	(208)	(540)	(345)	(1,076)
Net (loss) earnings	(82,425)	127,908	(80,120)	508,240
3. Investments
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Adoption of accounting policy - Investment in associate

Associates are entities for which the company has significant influence, but not control or joint control over the financial and operational decisions. Investments in associates are accounted for using the equity method of accounting and are initially recognized at cost and adjusted thereafter for the change in the company’s share of the associate’s net income and comprehensive income less distributions received until the date that significant influence ceases, within other income on the consolidated statements of net earnings and comprehensive income.

Subsequent to February 29, 2024, Vermilion owns approximately 21% of the issued and outstanding common shares of Coelacanth Energy Inc. ("CEI"), an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in northeastern British Columbia, Canada. As such, Vermilion has concluded that it has significant influence over the entity and should be accounted for using the equity method of accounting. Prior to February 29, 2024, this investment was accounted for under IFRS 9 as an investment in securities using the fair value method of accounting. The transaction was treated as a disposal of the original investment at fair value and an acquisition of an investment in associate, with no resulting gain or loss recognized in the consolidated statement of net earnings.

The following table reconciles the change in Vermilion's investments:

	2024
Balance at January 1	73,261
Acquisition of securities	9,373
Fair value adjustment ^(1)^	(2,203)
Investment in securities prior to reclassification to Investment in associate	80,431
Investment loss ^(2)^	(302)
Balance at June 30	80,129

^(1) The investment was classified as a level 1 instrumenton the fair value hierarchy and used observable inputs when making fair value adjustments and was recorded until the date of significantinfluence, on February 29, 2024.(2) Investment losses are recognized within other income on the consolidated statements of net earnings and comprehensive income.^

The following tables summarize financial information of CEI and Vermilion's share based on their most recently available publicly available documents as at and for the three months ended March 31, 2024:

Current assets	64,539
Non-current assets	121,464
Current liabilities	(6,053)
Non-current liabilities	(7,604)
Net assets	172,346
Vermilion's share of net assets	35,865

| Vermilion Energy Inc.  ■  Page 60  ■  2024 Second Quarter Report |

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---	---
	June 30, 2024
Total Revenue	5,089
Net loss	(1,446)
Vermilion's share of net loss	(302)

At June 30, 2024, the fair value of Vermilion's investment in CEI is $82.6 million or $0.75/share (December 31, 2023 - $73.3 million or $0.75/share).

4. Capital assets

The following table reconciles the change in Vermilion's capital assets:

	2024
Balance at January 1	4,882,509
Acquisitions	5,829
Additions	291,648
Increase in right-of-use assets	78,410
Depletion and depreciation	(336,932)
Changes in asset retirement obligations	43,828
Foreign exchange	13,235
Balance at June 30	4,978,527

Right-of-use assets

The following table discloses the carrying balance and depreciation charge relating to right-of-use assets by class of underlying asset as at and for the six months ended June 30, 2024:

	As at Jun 30, 2024		As at Dec 31, 2023
($M)	Depreciation	Balance	Depreciation	Balance
Office space	4,102	26,344	8,115	25,893
Processing facilities	10,860	81,278	7,691	6,326
Oil storage facilities	1,300	5,248	2,667	7,037
Vehicles and equipment	794	5,053	5,433	9,760
Total	17,056	117,923	23,906	49,016

In May 2024, Vermilion recognized a seven-year lease for a processing facility in the Canadian Business Unit adding $76.4 million of right-of-use assets offset with lease liabilities ($4.3 million current; $72.1 million non-current). The rate implicit in the lease is 11.7%.

5. Exploration and evaluation assets

The following table reconciles the change in Vermilion's exploration and evaluation assets:

	2024
Balance at January 1	198,379
Additions	9,404
Depreciation	(75)
Foreign exchange	2,212
Balance at June 30	209,920

| Vermilion Energy Inc.  ■  Page 61  ■  2024 Second Quarter Report |

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---

The following table reconciles the change in Vermilion’s asset retirement obligations:

	2024
Balance at January 1	1,159,063
Additional obligations recognized	398
Obligations settled	(16,720)
Accretion	36,143
Changes in rates	43,430
Foreign exchange	3,385
Balance at June 30	1,225,699

Vermilion calculated the present value of the obligations using a credit-adjusted risk-free rate, calculated using a credit spread of 2.8% as at June 30, 2024 (December 31, 2023 - 3.6%) added to risk-free rates based on long-term, risk-free government bonds. Vermilion's credit spread is determined using the Company's expected cost of borrowing at the end of the reporting period.

The country-specific risk-free rates used as inputs to discount the obligations were as follows:

	Jun 30, 2024	Dec 31, 2023
Canada	3.3 %	3.0 %
United States	4.5 %	4.2 %
France	3.6 %	3.0 %
Netherlands	2.9 %	2.1 %
Germany	2.6 %	2.3 %
Ireland	3.1 %	2.7 %
Australia	4.5 %	4.0 %
7. Capital disclosures
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Vermilion defines capital as net debt and shareholders' capital. Net debt consists of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current lease liabilities). In managing capital, Vermilion reviews whether fund flows from operations is sufficient to fund capital expenditures, dividends, share buybacks, and asset retirement obligations.

The following table calculates Vermilion’s ratio of net debt to four quarter trailing fund flows from operations:

	Jun 30, 2024	Dec 31, 2023
Long-term debt	915,364	914,015
Adjusted working capital ^(1)^	(8,649)	164,552
Net debt	906,715	1,078,567
Ratio of net debt to four quarter trailing fund flows from operations	0.7	0.9

^(1) Adjusted working capitalis defined as current assets (excluding current derivatives), less current liabilities (excluding current derivatives and current leaseliabilities).^

| Vermilion Energy Inc.  ■  Page 62  ■  2024 Second Quarter Report |

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8. Long-term debt

The following table summarizes Vermilion’s outstanding long-term debt:

	As at
	Jun 30, 2024	Dec 31, 2023
2025 senior unsecured notes	378,471	395,839
2030 senior unsecured notes	536,893	518,176
Long-term debt	915,364	914,015

The fair value of the revolving credit facility is equal to its carrying value due to the use of short-term borrowing instruments at market rates of interest. The fair value of the 2025 senior unsecured notes as at June 30, 2024 was $378.4 million (December 31, 2023 - $392.7 million). The fair value of the 2030 senior unsecured notes as at June 30, 2024 was $538.0 million (December 31, 2023 - $511.7 million).

The following table reconciles the change in Vermilion’s long-term debt:

	2024
Balance at January 1	914,015
Repurchases of senior unsecured notes	(31,561)
Amortization of transaction costs	1,128
Foreign exchange	31,782
Balance at June 30	915,364

Revolving credit facility

As at June 30, 2024, Vermilion had in place a bank revolving credit facility maturing May 26, 2028 with the following terms:

	As at
	Jun 30, 2024	Dec 31, 2023
Total facility amount	1,350,000	1,600,000
Letters of credit outstanding	(20,234)	(18,116)
Unutilized capacity	1,329,766	1,581,884

The facility can be extended from time to time at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are due at the maturity date. The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion.

On May 17, 2024, the maturity date of the facility was extended to May 26, 2028 (previously May 28, 2027) and the total facility amount of $1.6 billion

was reduced to $1.35 billion, with an accordion feature to increase the aggregate amount available under the facility to $1.6 billion. As at June 30, 2024, the revolving credit facility was undrawn.

The facility bears interest at a rate applicable to demand loans plus applicable margins.

As at June 30, 2024, the revolving credit facility was subject to the following financial covenants:

		As at
Financial covenant	Limit	Jun 30, 2024	Dec 31, 2023
Consolidated total debt to consolidated EBITDA	Less than 4.0	0.67	0.65
Consolidated total senior debt to consolidated EBITDA	Less than 3.5	0.05	-
Consolidated EBITDA to consolidated interest expense	Greater than 2.5	18.57	17.33

The financial covenants include financial measures defined within the revolving credit facility agreement that are not defined under IFRS. These financial measures are defined by the revolving credit facility agreement as follows:

•	Consolidated total debt: Includes all amounts<br>classified as “Long-term debt” and “Lease obligations” (including the current portion included within "Accounts<br>payable and accrued liabilities" but excluding operating leases as defined under IAS 17) on the consolidated balance sheet.
•	Consolidated total senior debt: Consolidated<br>total debt excluding unsecured and subordinated debt.
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| Vermilion Energy Inc.  ■  Page 63  ■  2024 Second Quarter Report |

| --- | | • | Consolidated EBITDA: Consolidated net (loss) earnings before interest, income taxes, depreciation, accretion and certain other non-cash items, adjusted for the impact of the acquisition of a material subsidiary. | | --- | --- | | • | Consolidated total interest expense: Includes all amounts classified as "Interest expense", but excludes interest on operating leases as defined under IAS 17. | | --- | --- |

As at June 30, 2024 and December 31, 2023, Vermilion was in compliance with the above covenants.

2025 senior unsecured notes

On March 13, 2017, Vermilion issued US $300.0 million of senior unsecured notes at par. The notes bear interest at a rate of 5.625% per annum, to be paid semi-annually on March 15 and September 15. The notes mature on March 15, 2025. As direct senior unsecured obligations of Vermilion, the notes rank equally with existing and future senior unsecured indebtedness of the Company.

The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance.

Subsequent to March 15, 2023, Vermilion may redeem some or all of the senior unsecured notes at a 100.00% redemption price plus any accrued and unpaid interest.

During the first quarter of 2024, Vermilion purchased $31.6 million of senior unsecured notes on the open market which were subsequently cancelled.

2030 senior unsecured notes

The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance.

Vermilion may, at its option, redeem the notes prior to maturity as follows:

•	Prior to May 1, 2025, Vermilion may redeem<br>up to 35% of the original principal amount of the notes with an amount of cash not greater than the net cash proceeds of certain equity<br>offerings at a redemption price of 106.875% of the principal amount of the notes, together with accrued and unpaid interest.
•	Prior to May 1, 2025, Vermilion may also<br>redeem some or all of the notes at a price equal to 100% of the principal amount of the notes, plus a “make-whole premium,”<br>together with applicable premium, accrued and unpaid interest.
---	---
•	On or after May 1, 2025, Vermilion may<br>redeem some or all of the senior unsecured notes at the redemption prices set forth below, together with accrued and unpaid interest.
---	---
Year	Redemption price
---	---
2025	103.438 %
2026	102.292 %
2027	101.146 %
2028 and thereafter	100.000 %

| Vermilion Energy Inc.  ■  Page 64  ■  2024 Second Quarter Report |

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The following table reconciles the change in Vermilion’s shareholders’ capital:

	2024
Shareholders’ Capital	Shares ('000s)	Amount
Balance at January 1	162,271	4,142,566
Vesting of equity based awards	996	9,998
Share-settled dividends on vested equity based awards	78	1,257
Repurchase of shares	(5,171)	(133,552)
Balance at June 30	158,174	4,020,269

Dividends are approved by the Board of Directors and are paid quarterly. Dividends declared to shareholders for the six months ended June 30, 2024 were $38.2 million or $0.24 per common share (2023 - $32.7 million or $0.20 per common share).

Subsequent to June 30, 2024, Vermilion purchased and cancelled 0.9 million shares under the NCIB for total consideration of $13.2 million.

10. Financial instruments

The following table summarizes the increase (positive values) or decrease (negative values) to net (loss) earnings before tax due to a change in the value of Vermilion’s financial instruments as a result of a change in the relevant market risk variable. This analysis does not attempt to reflect any interdependencies between the relevant risk variables.

	Jun 30, 2024
Currency risk - Euro to Canadian dollar
$0.01 increase in strength of the Canadian dollar against the Euro	5,495
$0.01 decrease in strength of the Canadian dollar against the Euro	(5,495)
Currency risk - US dollar to Canadian dollar
$0.01 increase in strength of the Canadian dollar against the US $	4,406
$0.01 decrease in strength of the Canadian dollar against the US $	(4,406)
Commodity price risk - Crude oil
US $5.00/bbl increase in crude oil price used to determine the fair value of derivatives	(14,762)
US $5.00/bbl decrease in crude oil price used to determine the fair value of derivatives	14,762
Commodity price risk - European natural gas
#eu#5.0/GJ increase in European natural gas price used to determine the fair value of derivatives	(233,814)
#eu#5.0/GJ decrease in European natural gas price used to determine the fair value of derivatives	282,009

| Vermilion Energy Inc.  ■  Page 65  ■  2024 Second Quarter Report |

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The following table summarizes Vermilion’s cash and cash equivalents:

	As at
	Jun 30, 2024	Dec 31, 2023
Cash on deposit with financial institutions	263,977	140,795
Guaranteed investment certificates	3,695	661
Cash and cash equivalents	267,672	141,456

| Vermilion Energy Inc.  ■  Page 66  ■  2024 Second Quarter Report |

| --- | | DIRECTORS Robert Michaleski ^1,3,5^ Calgary, Alberta Dion Hatcher Calgary, Alberta James J. Kleckner Jr. ^7,9^ Edwards, Colorado Carin Knickel ^4,7,11^ Golden, Colorado Stephen P. Larke ^3,5,10^ Calgary, Alberta Timothy R. Marchant ^6,9,11^ Calgary, Alberta William Roby ^7,8,11^ Katy, Texas Manjit Sharma ^2,5^ Toronto, Ontario Myron Stadnyk ^7,9^ Calgary, Alberta Judy Steele ^3,5,11^ Halifax, Nova Scotia ^1^Chairman (Independent) ^2^Audit Committee Chair (Independent) ^3^Audit Committee Member (Independent) ^4^Governance and Human Resources Committee Chair __(Independent) ^5^Governance and Human Resources Committee Member __(Independent) ^6^Health, Safety and Environment Committee Chair __(Independent) ^7^Health, Safety and Environment Committee Member __(Independent) ^8^Technical Committee Chair (Independent) ^9^Technical Committee Member __(Independent) ^10^ Sustainability Committee Chair (Independent) ^11^ Sustainability Committee Member (Independent) | OFFICERS / CORPORATE SECRETARY **** Dion Hatcher * President & Chief Executive Officer Lars Glemser * Vice President & Chief Financial Officer Tamar Epstein General Counsel & Corporate Secretary Terry Hergott Vice President Marketing Yvonne Jeffery Vice President Sustainability Darcy Kerwin * Vice President International & HSE Geoff MacDonald Vice President Geosciences Randy McQuaig * Vice President North America Kyle Preston Vice President Investor Relations Averyl Schraven Vice President People & Culture Gerard Schut Vice President European Operations * Principal Executive Committee Member | AUDITORS Deloitte LLP Calgary, Alberta BANKERS The Toronto-Dominion Bank Alberta Treasury Branches Bank of America N.A., Canada Branch Canadian Imperial Bank of Commerce Export Development Canada National Bank of Canada Royal Bank of Canada The Bank of Nova Scotia Wells Fargo Bank N.A., Canadian Branch La Caisse Centrale Desjardins du Québec Citibank N.A., Canadian Branch - Citibank Canada Canadian Western Bank JPMorgan Chase Bank, N.A., Toronto Branch Goldman Sachs Lending Partners LLC EVALUATION ENGINEERS McDaniel & Associates Calgary, Alberta LEGAL COUNSEL Norton Rose Fulbright Canada LLP Calgary, Alberta TRANSFER AGENT Odyssey Trust Company STOCK EXCHANGE LISTINGS The Toronto Stock Exchange (“VET”) The New York Stock Exchange (“VET”) INVESTOR RELATIONS Kyle Preston Vice President Investor Relations 403-476-8431 TEL 403-476-8100 FAX 1-866-895-8101 IR TOLL FREE investor_relations@vermilionenergy.com | | --- | --- | --- |

Vermilion Energy Inc. ■ Page 67 ■ 2024<br> Second Quarter Report

Exhibit 99.2

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS - FULLCERTIFICATE

I, Dion Hatcher*, President and Chief Executive Officer ofVermilion Energy Inc.*, certify the following:

1.	Review: I<br>have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Vermilion Energy Inc.<br>(the “issuer”) for the interim period ended June 30, 2024.
2.	No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the<br>interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that<br>is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered<br>by the interim filings.
---	---
3.	Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim<br>financial report together with the other financial information included in the interim filings fairly present in all material respects<br>the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim<br>filings.
---	---
4.	Responsibility: The issuer’s other certifying officer and I are responsible for establishing<br>and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are<br>defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
---	---
5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s<br>other certifying officer and I have, as at the end of the period covered by the interim filings
---	---

(a) designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i) material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii) information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b) designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1	Control framework: The control framework the issuer’s other certifying officer and<br>I used to design the issuer’s ICFR is the Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations<br>of the Treadway Commission (COSO).
5.2	ICFR – material weakness relating to design: N\A
---	---
5.3	Limitation on scope of design: N\A
---	---
6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in<br>the issuer’s ICFR that occurred during the period beginning on April 1, 2024 and ended on June 30, 2024 that has materially<br>affected, or is reasonably likely to materially affect, the issuer’s ICFR.
---	---

Dated: July 31, 2024

(Signed: “DionHatcher”) ___________________________

Dion Hatcher, President and Chief Executive Officer

Exhibit 99.3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS - FULLCERTIFICATE

I, Lars Glemser*, Vice President andChief Financial Officer of Vermilion Energy Inc.*, certify the following:

1.	Review: I<br>have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Vermilion Energy Inc.<br>(the “issuer”) for the interim period ended June 30, 2024.
2.	No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the<br>interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that<br>is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered<br>by the interim filings.
---	---
3.	Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim<br>financial report together with the other financial information included in the interim filings fairly present in all material respects<br>the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim<br>filings.
---	---
4.	Responsibility: The issuer’s other certifying officer and I are responsible for establishing<br>and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are<br>defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
---	---
5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s<br>other certifying officer and I have, as at the end of the period covered by the interim filings
---	---

(a) designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i) material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

5.1	Control framework: The control framework the issuer’s other certifying officer and<br>I used to design the issuer’s ICFR is the Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations<br>of the Treadway Commission (COSO).
5.2	ICFR – material weakness relating to design: N\A
---	---
5.3	Limitation on scope of design: N\A
---	---
6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in<br>the issuer’s ICFR that occurred during the period beginning on April 1, 2024 and ended on June 30, 2024 that has materially<br>affected, or is reasonably likely to materially affect, the issuer’s ICFR.
---	---

Dated: July 31, 2024

(Signed: “LarsGlemser”) ___________________________

Lars Glemser, Vice President and Chief Financial Officer