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Disclaimer

Certain statements included or incorporated by reference in this document may constitute “forward-looking information” and “forward-looking statements” within the meaning of applicable Canadian securities laws and the United States Private Securities Litigation Reform Act of 1995, respectively (collectively referred to herein as “forward-looking statements or information”). Such forward-looking statements or information typically contain statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “continue”, “on track”, “target”, “focus”, “grow”, “will”, “may”, “could”, or similar expressions or words suggesting future outcomes or statements regarding future events, performance, objectives, strategies or outlook. Forward-looking statements or information in this document may include, but are not limited to statements and information with respect to: capital expenditures and Vermilion’s ability to fund such expenditures; future fund flows from operations and free cash flows; shareholder returns; Vermilion’s anticipated future debt capacity and levels; Vermilion’s budget; statements regarding the return of capital, the flexibility of Vermilion’s capital program and operations; business strategies, objectives and priorities; operational and financial performance; estimated volumes of reserves and the discounted present value of future net cash flows from such reserves; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion’s 2026 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange and interest rates 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, number and production of Vermilion’s future wells expected to be drilled; exploration and development plans and the timing thereof; Vermilion’s aim and 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; ongoing contractual commitments; asset retirement obligations; emissions targets, including reductions; sustainability and environmental, social and governance (ESG) and sustainability plans; and the timing of regulatory proceedings and the receipt of regulatory and third - party approvals.

Such forward-looking statements or information are based on a number of assumptions of which all or any 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, government and third - party approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates and inflation rates; the accuracy of the McDaniel Reserves Report (defined below); the ability of the Company to identify, execute on and realize the anticipated benefits of attractive mergers and acquisitions opportunities; the ability of the Company to conduct operations in a safe manner; political stability of the areas in which the Company operates; the effects of changes to international trade policies; the accuracy of the Company’s 2026 budget; the ability of the Company to retain key employees; production and decline rates; the absence of significant adverse changes to the legislative and regulatory frameworks, including regarding royalties, taxes and environmental matters; the political, economic and social states of the capital markets; global economic conditions; the ability of the Company to execute plans, including exploration and development plans; the success of present and future wells; 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.

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 or information 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: commodity prices; exchange rates; production and sales volumes; interest rates; geopolitical tensions; global tariffs; volatility of oil and gas prices; constraints at processing facilities and/or on transportation; volatility of foreign exchange rates; volatility of market price of Common Shares (defined below); hedging arrangements; inflationary pressures; increase in operating costs or a decline in production level; operator performance and payment delays; weather conditions; cost of new technology; tax, royalty, and other government legislation; government regulations; policy and legal risks; political events and terrorist attacks; discretionary nature of dividends and share buybacks; additional financing; debt service; variations in interest rates and foreign exchange rates; environmental legislation; hydraulic fracturing regulations; climate change; competition; international operations and future geographical/industry expansion; acquisition assumptions; failure to realize anticipated benefits of prior acquisitions; reserves estimates; cyber security; accounting adjustments; ineffective internal controls; the potential for new and increased U.S. tariffs and protectionist trade measures on Canadian oil and gas imports; and other risks and uncertainties described elsewhere in this document or in Vermilion’s other filings with Canadian securities regulatory authorities.

Vermilion Energy Inc. ■ Page 1 ■ 2025 Management’s Discussion and Analysis

Many factors could cause Vermilion’s or any particular business unit’s actual results, performance, or achievements to vary from those described in this document, including, without limitation, those listed above and the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this document as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected, or targeted and such forward-looking statements included in this document should not be unduly relied upon. The impact of any one assumption, risk, uncertainty, or other factor on a particular forward-looking statement cannot be determined with certainty because they are interdependent and Vermilion’s future decisions and actions will depend on management’s assessment of all information at the relevant time. Such statements speak only as of the date of this document. The forward-looking statements or information contained in this document are made as of the date hereof and the Company 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. The forward-looking statements contained in this document are expressly qualified by these cautionary statements.

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, International Sustainability Standards Board 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.

All oil and natural gas reserve information contained in this document is derived from the McDaniel Reserves Report (as defined below) and has been prepared and presented in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). In this document: (A) the net present value of future net revenues attributable to reserves do not represent the fair market value of reserves; (B) the recovery and reserve estimates of crude oil, NGL and natural gas reserves provided in this document are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided in this document; and (C) the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Under NI 51-101, disclosure of production volumes should include segmentation by product type as defined in the instrument. In this document, references to “crude oil” and “light and medium crude oil” mean “light crude oil and medium crude oil” , “tight oil” or “heavy oil” and references to “natural gas” mean “conventional natural gas”, “shale gas” or “coal bed methane".

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.

This document discloses certain oil and gas metrics, including reserve life index, finding, development and acquisition (“FD&A”) costs, future development capital ("FDC”) costs, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the Company's performance in previous periods and therefore such metrics should not be unduly relied upon.

Vermilion Energy Inc. ■ Page 2 ■ 2025 Management’s Discussion and Analysis

Estimates of Drilling Locations: Unbooked drilling locations are the internal estimates of Vermilion based on Vermilion's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Vermilion's management as an estimation of Vermilion's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Vermilion will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Vermilion will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by Vermilion drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management of Vermilion has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

Financial data contained within this document are reported in Canadian dollars unless otherwise stated. References herein to “US$” or “USD” are to United States dollars.

Vermilion Energy Inc. ■ Page 3 ■ 2025 Management’s Discussion and Analysis

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)
bbl(s)/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
CO2	carbon dioxide
CO2e	carbon dioxide equivalent
GHG	greenhouse gas
GJ	gigajoules
mbbl(s)	thousand barrel(s)
mmboe	thousand barrels of oil equivalent
MMBtu	million British Thermal Units
mcf	thousand cubic feet
mmcf/d	million cubic feet per day
MD	measured depth
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
psi	pounds per square inch
tCO2e	tonne 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
US	the United States of America
WTI	West Texas Interme`diate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma

Vermilion Energy Inc. ■ Page 4 ■ 2025 Management’s Discussion and Analysis

Management's Discussion and Analysis

The following is Management’s Discussion and Analysis (“MD&A”), dated March 4, 2026, of Vermilion Energy Inc.’s (“Vermilion”, “we”, “our”, “us” or the “Company”) operating and financial results as at and for the three months and year ended December 31, 2025 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2025 and 2024, together with the accompanying notes (the "Consolidated Financial Statements"). Additional information relating to Vermilion, including its Annual Information Form for the year ended December 31, 2025 ("Annual Information Form"), is available on SEDAR+ at www.sedarplus.ca or on Vermilion’s website at www.vermilionenergy.com.

The Consolidated Financial Statements and comparative information have been prepared in Canadian dollars and in accordance with IFRS® Accounting Standards as issued by the International Accounting Standards Board ("IFRS Accounting Standards").

The operating results attributable to the Company’s Saskatchewan and United States operations have been classified and presented as discontinued operations, with all other operating results presented as continuing operations. The prior period results have been presented to conform with current period presentation. See Note 6 – “Discontinued Operations” of the consolidated interim financial statements for the year ended December 31, 2025, for additional information.

This MD&A includes references to certain financial measures which are not specified, defined, or determined under IFRS Accounting Standards 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 financial 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” , “tight oil” or “heavy oil” and references to “natural gas” mean “conventional natural gas”, “shale gas” or “coal bed methane".

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 5 ■ 2025 Management’s Discussion and Analysis

Guidance

On December 19, 2024, Vermilion released the 2025 capital budget and associated production guidance. On March 5, 2025, the Company updated the 2025 capital budget and associated production guidance following the close of the acquisition of Westbrick Energy Ltd. ("Westbrick"), with incremental capital expenditures and production from the acquired assets reflected in guidance for the remainder of the year. On June 5, 2025, the Company provided updated guidance reflecting the removal of all remaining E&D capital associated with the Saskatchewan and United States assets following the announcement of the sale of these assets. On November 5, 2025, the Company tightened 2025 production and E&D capital expenditure guidance and provided updated cost structure guidance, reflecting managements increased certainty on full-year estimates. The Company’s guidance and results for 2025 are as follows:


Category		2025 Guidance ⁽¹⁾			2025 Actual ⁽¹⁾
Production (boe/d)			119,500			119,919
E&D capital expenditures ($MM)		$	630 - 640		$	635
Operating ($/boe)		$	13.00 - 13.50		$	12.97
General and administration ($/boe) ⁽²⁾		$	2.25 - 2.75		$	2.71
Transportation ($/boe)		$	3.00 - 3.50		$	3.20
Royalty rate (% of sales)			8 - 9	%		7.9	%
Cash taxes (% of pre-tax FFO)			3 - 7	%		2.2	%
Asset retirement obligations settled ($MM)		$	60		$	62
Payments on lease obligations ($MM)		$	15		$	13

On November 5, 2025, the Company released the 2026 capital budget and associated production guidance. The Company’s guidance for 2026 is as follows:


Category		2026 Current⁽¹⁾
Production (boe/d)			118,000 - 122,000
E&D capital expenditures ($MM)		$	600 - 630
Operating ($/boe)		$	12.25 - 13.25
General and administration ($/boe) ⁽²⁾		$	1.65 - 2.15
Transportation ($/boe)		$	3.00 - 3.50
Royalty rate (% of sales)			7 - 9	%
Cash taxes (% of pre-tax FFO)			2 - 6	%
Asset retirement obligations settled ($MM)		$	55
Payments on lease obligations ($MM)		$	10

(1)

Current 2025 guidance reflects foreign exchange assumptions of CAD/USD 1.40, CAD/EUR 1.58, and CAD/AUD 0.90. Actual 2025 results reflect foreign exchange assumptions of CAD/USD 1.40, CAD/EUR 1.58, and CAD/AUD 0.90. Current 2026 guidance reflects foreign exchange assumptions of CAD/USD 1.38, CAD/EUR 1.63, and CAD/AUD 0.91.

(2)	General and administration expense exclusive of expected cash-settled equity based compensation of $0.15 - 0.20/boe.

Vermilion Energy Inc. ■ Page 6 ■ 2025 Management’s Discussion and Analysis

Consolidated Results Overview


						Q4/25 vs.						2025 vs.
		Q4 2025		Q4 2024		Q4/24		2025		2024		2024
Production ⁽¹⁾
Crude oil and condensate (bbls/d)		25,401		30,327		(16)	%	30,832		31,427		(2)	%
NGLs (bbls/d)		12,140		6,612		84	%	11,244		7,100		58	%
Natural gas (mmcf/d)		502.60		279.59		80	%	467.06		276.10		69	%
Total (boe/d)		121,308		83,536		45	%	119,919		84,543		42	%
(Draw) build in inventory (mbbls)		(49)		107				5		(220)
Financial metrics
Fund flows from continuing operations ($M) ⁽²⁾		240,533		227,634		6	%	926,688		1,015,841		(9)	%
Fund flows from discontinued operations ($M) ^{(2) (7)}		201		35,064		(99)	%	83,563		189,942		(56)	%
Fund flows from operations ($M) ⁽²⁾		240,734		262,698		(8)	%	1,010,251		1,205,783		(16)	%
Fund flows from operations per share		1.57		1.70		(8)	%	6.58		7.63		(14)	%
Net loss from continuing operations		(438,119)		(18,524)		2,265	%	(364,805)		(96,169)		279	%
Net earnings (loss) from discontinued operations ⁽⁷⁾		466		208		124	%	(288,796)		49,430		N/A
Net loss ($M)		(437,653)		(18,316)		N/A		(653,601)		(46,739)		1,298	%
Net earnings (loss) per share - continuing operations		(2.86)		(0.12)		2,283	%	(2.37)		(0.61)		289	%
Net (loss) earnings per share - discontinued operations ⁽⁷⁾		—		—		N/A		(1.88)		0.31		N/A
Net loss per share		(2.86)		(0.12)		2,283	%	(4.25)		(0.30)		1,317	%
Cash flows from operating activities ($M)		133,357		212,587		(37)	%	943,661		967,751		(3)	%
Free cash flow ($M) ⁽³⁾		48,982		62,039		(21)	%	375,329		582,803		(36)	%
Long-term debt ($M)		1,243,397		963,456		29	%	1,243,397		963,456		29	%
Net debt ($M) ⁽⁴⁾		1,342,390		966,882		39	%	1,342,390		966,882		39	%
Cash dividends ($/share)		0.13		0.12		8	%	0.52		0.48		8	%
Activity
Capital expenditures ($M) ⁽⁵⁾		191,752		200,659		(4)	%	634,922		622,980		2	%
Acquisitions ($M) ⁽⁶⁾		1,646		5,257		(69)	%	1,125,303		22,101		4,992	%
Dispositions ($M) ⁽⁷⁾		41,782		—		N/A		525,307		—		N/A

⁽¹⁾	Please refer to Supplemental Table 4 "Production" for disclosure by product type.

⁽²⁾

Fund flows from operations (FFO) and FFO per share are a total of segments measure and supplementary financial measure most directly comparable to net loss and net loss per share, respectively. The measures do not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. FFO is comprised of sales less royalties, transportation, operating, general and administrative (G&A), corporate income tax, PRRT, interest expense, equity based compensation settled in cash, realized gain (loss) on derivatives, plus realized gain (loss) on foreign exchange 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. A reconciliation to the primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A. Fund flows from continuing operations and fund flows from discontinued operations are calculated in the same manner as FFO and are most directly comparable to net earnings (loss) from continuing operations and net earnings (loss) discontinued operations, respectively.

⁽³⁾

Free cash flow (FCF) is a non-GAAP financial measure most directly comparable to cash flows from operating activities; it does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. FCF is comprised of fund flows from operations less drilling and development costs and exploration and evaluation costs. FCF 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. A reconciliation to primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A.

⁽⁴⁾

Net debt is a capital management measure 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 (defined as current assets less current liabilities, excluding current derivatives, current asset retirement obligations 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. A reconciliation to the primary financial statement measures can be found within the "Financial Position Review" section of this MD&A.

⁽⁵⁾

Capital expenditures is a non-GAAP financial measure that does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. The measure is calculated as the sum of drilling and development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows. 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. A reconciliation to the primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A.

Vermilion Energy Inc. ■ Page 7 ■ 2025 Management’s Discussion and Analysis

⁽⁶⁾

Acquisitions is a non-GAAP financial measure that does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. The measure is calculated as the sum of acquisitions, net of cash 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. A reconciliation to the acquisitions line item in the Consolidated Statements of Cash Flows can be found in "Supplemental Table 3: Capital Expenditures and Acquisitions" section of this MD&A.

⁽⁷⁾

Dispositions is a non-GAAP financial measure and is not a standardized financial measure under IFRS Accounting Standards and therefore may not be comparable to similar measures disclosed by other issuers. Dispositions is calculated as the sum of dispositions, and disposition of securities. Management believes that including these components provides a useful measure of the proceeds associated with our disposition activities and is most directly comparable to cash flows used in investing activities. More information and a reconciliation to dispositions and disposition of securities, the most directly comparable primary financial statement measures, can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

Financial performance review

Q4 2025 vs. Q4 2024

●

We recorded a net loss of $437.7 million ($2.86/basic share) for Q4 2025 compared to $18.3 million ($0.12/basic share) in Q4 2024. The increase in net loss was primarily due to a non-cash impairment charge of $572.2 million, higher deferred tax expense and higher depletion on increased production. The increase was partially offset by favourable changes in our mark-to-market derivative position driven by European gas contracts, foreign exchange gains on our US denominated senior notes and Euro denominated intercompany loans, higher fund flows from operations attributable to the newly acquired production from the Westbrick assets and a gain on the disposition of investments, recorded in other, above.

Vermilion Energy Inc. ■ Page 8 ■ 2025 Management’s Discussion and Analysis

●

Cash flows from operating activities decreased to $133.4 million in Q4 2025 compared to $212.6 million in Q4 2024, while fund flows from operations declined to $240.7 million from $262.7 million over the same period. The decrease in FFO was primarily due to lower realized pricing, net of derivatives, partially offset by higher sales volumes, net of operating costs, driven by higher production in the Deep Basin and Montney. Variances between cash flows from operating activities and fund flows from operations are primarily driven by working capital timing differences.

2025 vs. 2024

●

For the year ended December 31, 2025, we recorded a net loss of $653.6 million compared to $46.7 million for the 2024 comparable period. The increase in net loss was primarily attributable to impairment charges in the Australia, France and Ireland cash generating units, a net loss from discontinued operations driven by impairment charges, increased depletion and depreciation on higher production volumes and decreased fund flows from operations on lower realized derivative gains on European gas contracts. The decrease was partially offset by favourable changes in our mark-to-market derivative position, primarily on our European natural gas contracts.

Vermilion Energy Inc. ■ Page 9 ■ 2025 Management’s Discussion and Analysis

●

Compared to 2024, cash flows from operating activities in 2025 decreased by $24.1 million to $943.7 million and FFO decreased by $195.5 million to $1,010.3 million. The decrease in FFO was primarily driven by a reduction in realized gains on derivative contracts of $203.7 million, primarily on European natural gas contracts, lower crude oil pricing and higher interest expense on Q1 refinancing activities. The decrease was partially offset by stronger operational performance driven by the net impact of acquisition and disposition activity and lower taxes, partially offset by higher general and administrative expense on restructuring costs. Variances between cash flows from operating activities and fund flows from operations are primarily driven by working capital timing differences.

Production review

Q4 2025 vs. Q4 2024

●

Consolidated average production increased 45% to 121,308 boe/d in Q4 2025 compared to Q4 2024 production of 83,536 boe/d. Production increased as a result of the Westbrick acquisition which closed at the end of February 2025, combined with increased production in Germany. The increases were partially offset by the United States and Saskatchewan dispositions and natural well decline in Ireland and Australia.

2025 vs. 2024

●

Consolidated average production increased 42% to 119,919 boe/d in the year ended December 31, 2025 compared to 84,543 boe/d in 2024. Production increased primarily as a result of the Westbrick acquisition, partially offset by the United States and Saskatchewan dispositions. Organic growth was driven by the Deep Basin and Montney, partially offset by natural well decline in Ireland and in the Netherlands.

Activity review

For the three months ended December 31, 2025, capital expenditures were $191.8 million.

●	In our North America core region, we invested capital expenditures of $134.0 million in our liquids-rich gas assets in Canada:

o

In the Deep Basin, we drilled sixteen (16.0 net), completed fourteen (14.0 net), and brought on production seventeen (17.0 net) liquids-rich conventional natural gas wells.

o

In the Montney, we drilled four (4.0 net) liquids-rich shale gas wells that are expected to be completed and brought online in 2026.

●	In our International core region, capital expenditures of $57.8 million were invested:

o

In Germany, we invested $17.1 million, primarily in facilities to continue to advance our deep gas exploration program.

o

In the Netherlands, we invested $13.9 million, primarily on completion and facilities activities to bring two (1.2 net) conventional natural gas wells online.

o

In France, we invested $14.5 million, primarily on subsurface maintenance and facilities activities.

o

In Australia, $8.9 million was invested primarily on facilities activities.

o

In Central and Eastern Europe, we invested $2.5 million, primarily on asset enhancement and maintenance.

Vermilion Energy Inc. ■ Page 10 ■ 2025 Management’s Discussion and Analysis

o

In Ireland, $0.8 million was invested on facilities activities.

Financial sustainability review

Free cash flow

●

Free cash flow decreased by $207.5 million to $375.3 million for the year ended December 31, 2025 compared to the prior year primarily due to lower fund flows from operations on higher realized gains on derivative contracts realized in 2024 and lower FFO on discontinued operations, partially offset by strong operational performance from the Westbrick assets.

Long-term debt and net debt

●

As at December 31, 2025, long-term debt increased to $1.2 billion (December 31, 2024 - $1.0 billion) primarily due to financing activities related to the $1.1 billion Westbrick acquisition, partially offset by proceeds received from the disposition of the United States and Saskatchewan assets and repurchases of our senior notes. Long-term debt also decreased on the foreign exchange impact of the US dollar weakening against the Canadian dollar on our US denominated senior unsecured notes.

●

As at December 31, 2025, net debt totaled $1.3 billion, or an increase of $0.3 billion from December 31, 2024. The increase was primarily driven by the financing of the Westbrick acquisition in Q1 2025, partially offset by proceeds from dispositions of our U.S. and Saskatchewan assets and investments and strong excess free cash flow generation.

●

The ratio of net debt to four quarter trailing fund flows from operations⁽¹⁾ increased to 1.4 as at December 31, 2025 (December 31, 2024 - 0.8) primarily due to higher net debt on the 2025 acquisition and disposition activity, partially offset by higher four quarter trailing fund flows from continuing operations from the acquisition and disposition activity.

(1)

Net debt to four quarter trailing fund flows from operations is a supplementary financial measure that does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. It is calculated as net debt (capital measure) over the FFO from the preceding four quarters (total of segments measure). The measure is used to assess our ability to repay debt. Subsequent to February 26, 2025, net debt to four quarter trailing fund flows from operations is calculated inclusive of Westbrick Energy's pre-acquisition four quarter trailing fund flows from operations, as if the acquisition of Westbrick Energy occurred at the beginning of the four quarter trailing period, and exclusive of the four quarter trailing fund flows from discontinued operations to reflect the Company’s ability to repay debt on a pro forma basis.

Vermilion Energy Inc. ■ Page 11 ■ 2025 Management’s Discussion and Analysis

Benchmark Commodity Prices


						Q4/25 vs.						2025 vs.
		Q4 2025		Q4 2024		Q4/24		2025		2024		2024
Natural gas
North America
AECO 7A (CAD/Mcf)		2.34		1.46		60	%	1.86		1.44		29	%
Henry Hub (USD/Mcf)		3.55		2.79		27	%	3.43		2.27		51	%
Chicago (USD/Mcf)		3.55		2.47		44	%	3.47		2.01		73	%
Europe ⁽¹⁾
TTF MA (CAD/MMBtu)		15.05		17.65		(15)	%	17.46		14.68		19	%
TTF MA (EUR/MMBtu)		9.27		11.83		(22)	%	11.06		9.91		12	%
NBP MA(CAD/MMBtu)		14.88		17.95		(17)	%	17.14		14.53		18	%
NBP MA (EUR/MMBtu)		9.17		12.03		(24)	%	10.86		9.81		11	%
THE MA (CAD/MMBtu)		15.56		17.91		(13)	%	17.92		14.91		20	%
THE MA (EUR/MMBtu)		9.58		12.01		(20)	%	11.35		10.00		14	%
Crude oil
Dated Brent (USD/bbl)		63.69		74.67		(15)	%	69.06		80.76		(14)	%
WTI (US $/bbl)		59.14		70.27		(16)	%	64.81		75.72		(14)	%
Edmonton Sweet index (CAD/bbl)		76.57		94.92		(19)	%	85.60		97.54		(12)	%
Canadian C5+ Condensate index (CAD/bbl)		79.35		98.85		(20)	%	88.44		99.93		(11)	%
Average exchange rates
CAD/USD		1.40		1.40		—	%	1.40		1.37		2	%
CAD/EUR		1.62		1.49		9	%	1.58		1.48		7	%
Realized prices
Crude oil and condensate ($/bbl)		83.21		100.06		(17)	%	89.98		104.29		(14)	%
NGLs ($/bbl)		21.17		29.38		(28)	%	24.69		30.61		(19)	%
Natural gas ($/mcf)		5.13		8.47		(39)	%	5.38		6.72		(20)	%
Total ($/boe)		40.99		66.54		(38)	%	46.42		63.58		(27)	%

⁽¹⁾	Natural gas in the Netherlands and Germany is benchmarked to the TTF and THE and production is generally equally split between day ahead ("DA") and month ahead ("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 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.

●	Crude oil prices decreased in Q4 2025 relative to Q4 2024 due to views of global stockpiles growing in Q4 2025 and 2026. Canadian dollar WTI decreased by 16% and Dated Brent decreased by 15% in Q4 2025 relative to Q4 2024

Vermilion Energy Inc. ■ Page 12 ■ 2025 Management’s Discussion and Analysis

●

In Canadian dollar terms, year-over-year, the Edmonton Sweet differential tightened by $1.19/bbl to a discount of $4.99/bbl against WTI. This is due to decreased supply as a result of additional TMX flows off the Canadian West coast. In addition, seasonally low crude inventory in Western Canada and low levels of apportionment on pipelines into the United States have contributed to stronger Canadian differentials.

●

Approximately 47% of Vermilion’s Q4 2025 crude oil and condensate production was priced at the Dated Brent index, which averaged a premium to WTI of US$4.55/bbl; in Australia sales were executed at a $10.42/bbl premium to Dated Brent index. The remainder of our crude oil and condensate production was priced at the Canadian C5+, Edmonton Sweet, and WTI indices.

●

In Canadian dollar terms, year-over-year, prices for European natural gas at NBP and TTF increased by 18% and 19% respectively on a month ahead basis. Prices increased in response to lower stockpiles across the EU due to the colder winter months, additional geopolitical risk and additional demand entering the global LNG market.

●	Year-over-year natural gas prices in Canadian dollar terms at NYMEX HH increased by 54% and AECO 7A increased by 29%. AECO prices increased in Q1 2025 due to strong winter storage withdrawals and outlooks of the startup of LNG Canada and remained relatively steady for the year.

●

For Q4 2025, average European natural gas prices represented a $12.63/mcf premium to AECO 7A. Approximately 22% of our natural gas production in Q4 2025 benefited from this premium European pricing (Q4 2024 - 40%). The decrease in our realized natural gas price from the prior period is primarily due to increased North American natural gas pricing exposure on Westbrick assets acquired in Q1 2025.

North America

During the second quarter of 2025, Vermilion entered into agreements to dispose of the Company's non-core assets in Saskatchewan and the United States, which were subsequently sold in the third quarter of 2025. As a result, the operating results for these assets have been presented as discontinued operations throughout this MD&A in accordance with IFRS 5 "Non-current Assets Held for Sale and Discontinued Operations". Please refer to Note 6 "Discontinued operations" of the consolidated annual financial statements for the year ended December 31, 2025 for additional information. As a result, the continuing operations in North America consist of our Deep Basin and Mica Montney Canadian assets.


		Q4 2025		Q4 2024		2025		2024
Production ⁽¹⁾
Crude oil and condensate (bbls/d)		13,724		7,648		12,939		7,697
NGLs (bbls/d)		12,100		4,980		10,374		5,317
Natural gas (mmcf/d)		391.40		151.64		350.90		147.35
Production from continuing operations (boe/d)		91,053		37,898		81,794		37,570
Production from discontinued operations (boe/d)		118		14,395		8,268		15,972
Total production volume (boe/d)		91,171		52,293		90,062		53,542

⁽¹⁾	Please refer to Supplemental Table 4 "Production" for disclosure by product type.

Vermilion Energy Inc. ■ Page 13 ■ 2025 Management’s Discussion and Analysis

Fund Flows from Operations

Continuing Operations

 

Q4 2025

 

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$/boe

 

$/boe

Sales

215,707

 

25.75

107,409

30.81

771,802

25.85

413,939

30.10

Royalties

(17,923)

(2.14)

(6,840)

(1.96)

(63,834)

(2.14)

(39,152)

(2.85)

Transportation

(22,286)

(2.66)

(11,917)

(3.42)

(84,782)

(2.84)

(42,870)

(3.12)

Operating

(54,385)

(6.49)

(38,700)

(11.10)

(214,729)

(7.19)

(145,480)

(10.58)

General and administration ⁽¹⁾

(9,814)

(1.17)

(3,435)

(0.99)

(46,328)

(1.55)

(11,080)

(0.81)

Corporate income tax recovery (expense) ⁽¹⁾

464

0.06

2,081

0.60

(4,428)

(0.15)

1,370

0.10

Fund flows from continuing operations

111,763

13.35

48,598

13.94

357,701

11.98

176,727

12.84

Drilling and development

(134,523)

(85,682)

(392,179)

(301,651)

Free cash flow from continuing operations

(22,760)

(37,084)

(34,478)

(124,924)

⁽¹⁾

General and administration and corporate income tax include amounts from our Corporate segment. General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment and the prior period results have been presented to conform with current period presentation. The increase in general and administration was primarily due to non-recurring acquisition and restructuring costs in 2025 and lower corporate costs allocated to International segments. Corporate income tax expense primarily relates to income taxes on Corporate segment activities.

Discontinued Operations

 

Q4 2025

 

Q4 2024

YTD 2025

YTD 2024

 

$/boe

 

$/boe

 

$/boe

 

$/boe

Sales

827

76.83

94,334

71.23

210,643

69.80

434,914

74.40

Royalties

(205)

(19.04)

(18,321)

(13.83)

(40,591)

(13.45)

(85,034)

(14.55)

Transportation

(38)

(3.53)

(2,708)

(2.04)

(7,007)

(2.32)

(12,686)

(2.17)

Operating

170

15.79

(31,425)

(23.73)

(59,115)

(19.59)

(121,740)

(20.83)

General and administration

(553)

(51.37)

(6,815)

(5.15)

(20,367)

(6.75)

(25,493)

(4.36)

Corporate income taxes

—

(1)

—

(19)

—

Fund flows from discontinued operations

201

18.68

35,064

26.48

83,563

27.69

189,942

32.49

Drilling and development

561

(48,482)

(21,048)

(108,713)

Free cash flow from discontinued operations

762

(13,418)

62,515

81,229

Production from Vermilion's North American operations averaged 91,171 boe/d in Q4 2025, representing a 3% increase from Q3 2025. Production from Canadian continuing operations averaged 91,053 boe/d, representing a 6% increase from the prior quarter. The increase was primarily due to strong performance from recent Deep Basin wells and production from previously shut-in wells being brought back online.

In Q4 2025, the Company maintained a three-rig drilling program in the Deep Basin, drilling sixteen (16.0 net), completing fourteen (14.0 net), and bringing on production seventeen (17.0 net) liquids-rich gas wells. In the Montney, Vermilion drilled four (4.0 net) liquids-rich shale gas wells that are expected to be completed and brought online in 2026.

Sales

 

Q4 2025

 

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$/boe

 

$/boe

Canada

215,707

25.75

107,409

30.81

771,802

25.85

413,939

30.10

Discontinued operations:

Canada

331

75.99

68,421

73.75

146,895

72.09

297,351

76.61

United States

496

76.76

25,913

65.34

63,748

65.02

137,563

70.03

Total discontinued operations

827

76.83

94,334

71.23

210,643

69.80

434,914

74.40

North America

216,534

25.82

201,743

41.93

982,445

29.89

848,853

43.32

Vermilion Energy Inc. ■ Page 14 ■ 2025 Management’s Discussion and Analysis

Sales in North America increased for three months and year ended December 31, 2025 compared to the prior year primarily due to increased production in Alberta from the Westbrick acquisition and thirty six (33.3 net) new wells brought online subsequent to the acquisition and thirteen (13.0 net) new wells brought online in British Columbia in 2025. The increase was partially offset by decreased production in Saskatchewan and the United States due to disposition activity. Sales decreased on a per boe basis for the three months and year ended December 31, 2025 compared to the prior period primarily due to change in product mix on the acquisition and disposition activity.

Royalties

 

Q4 2025

 

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

Canada

(17,923)

(2.14)

(6,840)

(1.98)

(63,834)

(2.14)

(39,152)

(2.83)

Discontinued operations:

Canada

(127)

(29.16)

(10,562)

(11.38)

(22,671)

(11.13)

(45,185)

(11.64)

United States

(78)

(12.07)

(7,759)

(19.56)

(17,920)

(18.28)

(39,849)

(20.29)

Total discontinued operations

(205)

(19.04)

(18,321)

(13.83)

(40,591)

(13.45)

(85,034)

(14.55)

North America

(18,128)

(2.16)

(25,161)

(5.23)

(104,425)

(3.18)

(124,186)

(6.34)

Royalty rate (% of sales)

Canada

8.3

6.4

8.3

9.5

Discontinued operations

24.8

19.4

19.3

19.6

Royalties in North America decreased on a dollar basis for the three months and year ended December 31, 2025 compared to the same periods in the prior year primarily due to decreased crude production in Saskatchewan and the United States following the dispositions that closed in early Q3 2025 and lower realized liquids pricing. The decrease was partially offset by royalties on higher production from the Westbrick acquisition in Q1 2025 and new wells on production in British Columbia, and higher realized gas pricing. Royalties decreased on a per unit basis for the three months and year ended December 31, 2025 primarily due to lower realized crude prices and the higher gas weighting in our production mix on the acquisition and disposition activity, which are subject to lower royalty rates relative to liquids. The decrease was partially offset by higher realized gas pricing.

Transportation

 

Q4 2025

 

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

Canada

(22,286)

(2.66)

(11,917)

(3.45)

(84,782)

(2.84)

(42,870)

(3.10)

Discontinued operations:

Canada

(1)

(0.23)

(2,568)

(2.77)

(6,348)

(3.12)

(11,221)

(2.89)

United States

(37)

(5.73)

(140)

(0.35)

(659)

(0.67)

(1,465)

(0.75)

Total discontinued operations

(38)

(3.53)

(2,708)

(2.04)

(7,007)

(2.32)

(12,686)

(2.17)

North America

(22,324)

(2.66)

(14,625)

(3.04)

(91,789)

(2.79)

(55,556)

(2.83)

Transportation expense in North America increased on a dollar basis for the three months and year ended December 31, 2025 compared to the prior year comparable periods primarily due to transportation costs on acquired Westbrick assets in Q1 2025, partially offset by lower transportation costs in Saskatchewan and the United States on disposal in early Q3 2025. On a per boe basis, transportation expense decreased for the three months and year ended December 31, 2025, primarily due to lower pipeline fees on Montney production.

Operating expense

 

Q4 2025

 

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$/boe

 

$/boe

Canada

(54,385)

(6.49)

(38,700)

(11.19)

(214,729)

(7.19)

(145,480)

(10.53)

Discontinued operations:

Canada

188

43.16

(25,198)

(27.16)

(42,506)

(20.86)

(94,853)

(24.44)

United States

(18)

(2.79)

(6,227)

(15.70)

(16,609)

(16.94)

(26,887)

(13.69)

Total discontinued operations

170

15.79

(31,425)

(23.73)

(59,115)

(19.59)

(121,740)

(20.83)

North America

(54,215)

(6.46)

(70,125)

(14.58)

(273,844)

(8.33)

(267,220)

(13.64)

Vermilion Energy Inc. ■ Page 15 ■ 2025 Management’s Discussion and Analysis

Operating expenses in North America decreased for the three months ended December 31, 2025, mainly due to lower expenses in Saskatchewan and the U.S. from the asset dispositions completed in the third quarter of 2025 and reduced costs in the Montney for trucking and gas processing fees in the fourth quarter of 2025. The decrease was partially offset by the increased expenses in Alberta following the Westbrick acquisition in the first quarter of 2025.

Operating expenses in North America increased for the year ended December 31, 2025, mainly due to higher volumes associated with the Westbrick acquisition in the first quarter of 2025, partially offset by lower expenses in Saskatchewan and the U.S. from the asset dispositions recently completed and reduced costs in the Montney for trucking, downhole maintenance and gas processing. Operating expense decreased on a per boe basis for the three months and year ended December 31, 2025, primarily due to lower per unit operating costs on increased production impacted by the Westbrick acquisition and new wells coming on production in British Columbia.

International


		Q4 2025		Q4 2024		2025		2024
Production ⁽¹⁾
Crude oil and condensate (bbls/d)		11,621		12,502		11,940		12,362
Natural gas (mmcf/d)		111.07		112.44		107.49		111.83
Total production volume (boe/d)		30,137		31,243		29,857		31,001
Total sales volume (boe/d)		30,681		30,101		29,844		31,601

(1)	Please refer to Supplemental Table 4 "Production" for disclosure by product type.

Fund Flows from Operations

Q4 2025

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

Sales

243,015

86.09

302,609

109.27

1,048,949

96.30

1,132,554

97.92

Royalties

(14,444)

(5.12)

(14,888)

(5.38)

(55,290)

(5.08)

(53,764)

(4.65)

Transportation

(13,892)

(4.92)

(9,336)

(3.37)

(48,101)

(4.42)

(43,377)

(3.75)

Operating

(78,748)

(27.90)

(69,441)

(25.08)

(293,792)

(26.97)

(300,693)

(26.00)

General and administration

(15,884)

(5.63)

(17,210)

(6.21)

(52,122)

(4.78)

(62,930)

(5.44)

Corporate income tax expense

8,343

2.96

(18,077)

(6.53)

(21,616)

(1.98)

(67,793)

(5.86)

PRRT

8,391

2.97

3,226

1.16

2,955

0.27

(11,702)

(1.01)

Fund flows from operations

136,781

48.45

176,883

63.86

580,983

53.34

592,295

51.21

Drilling and development

(59,795)

(42,341)

(204,023)

(176,598)

Exploration and evaluation

2,005

(24,154)

(17,672)

(36,018)

Free cash flow

78,991

110,388

359,288

379,679

Production from Vermilion's International operations averaged 30,137 boe/d in Q4 2025, a decrease of 1% from Q3 2025 with new production in the Netherlands and increasing gas production in Germany largely offsetting natural declines in Ireland, Australia and Croatia.

In the Netherlands, Vermilion completed and brought on production two (1.2 net) conventional natural gas wells in Q4 2025. The Company also progressed preliminary work to facilitate drilling one (0.5 net) well in Netherlands in 2026, including receiving certain required permits. In Germany, the Company progressed infrastructure build-out on the Wisselshorst well during Q4 2025 and expects first production from this well in the first half of 2026. In addition, the Osterheide well (1.0 net) that was brought on production earlier in the year increased production in Q4 2025, with average production of 10 mmcf/d in the quarter.

Sales

Q4 2025

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

Australia

21,838

99.27

27,573

121.24

127,278

110.63

182,847

128.92

France

62,441

86.99

73,692

109.14

234,567

92.03

314,232

110.89

Netherlands

36,715

94.01

39,599

105.54

132,504

94.37

139,310

83.91

Germany

49,468

80.31

46,321

98.28

198,531

90.91

149,725

85.45

Ireland

59,079

81.91

97,735

115.22

294,109

98.42

311,325

87.84

Central and Eastern Europe

13,474

85.80

17,689

102.86

61,960

100.30

35,115

98.08

International

243,015

86.09

302,609

109.27

1,048,949

96.30

1,132,554

97.92

Vermilion Energy Inc. ■ Page 16 ■ 2025 Management’s Discussion and Analysis

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.


Crude oil sales volumes (bbls/d)		Q4 2025		Q4 2024		2025		2024
Australia		2,391		2,472		3,152		3,875
France		7,802		7,339		6,983		7,742
Germany		1,927		1,504		1,756		1,270
International		12,120		11,315		11,891		12,887

Sales decreased on a dollar and per boe basis for the three months and year ended December 31, 2025 compared to the prior year primarily due to lower realized commodity prices and inventory levels. Sales on a per boe basis for the year ended December 31, 2025 decreased compared to the prior year primarily due to lower realized oil pricing partially offset by higher realized European gas pricing.

Royalties

Q4 2025

 

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

France

(9,372)

(13.06)

(9,712)

(14.38)

(34,301)

(13.46)

(41,585)

(14.68)

Netherlands

—

(27)

(0.07)

(10)

(0.01)

(244)

(0.15)

Germany

(2,855)

(4.63)

(1,565)

(3.32)

(10,990)

(5.03)

(5,703)

(3.25)

Central and Eastern Europe

(2,217)

(14.12)

(3,584)

(20.84)

(9,989)

(16.17)

(6,232)

(17.41)

International

(14,444)

(5.12)

(14,888)

(5.38)

(55,290)

(5.08)

(53,764)

(4.65)

Royalty rate (% of sales)

5.9

4.9

5.3

4.7

Royalties in our International core region are primarily incurred in France, Germany, the Netherlands and Croatia, where royalties, depending on jurisdiction, 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 on a per boe basis decreased for the three months ended December 31, 2025 compared to the prior year primarily due to lower commodity pricing in France and lower sales volumes and royalty rates in Croatia, partially offset by higher royalties on the Osterheide startup volumes in Germany. On a dollar basis, royalties for the three months ended December 31, 2025 remained relatively flat compared to the prior year period. Royalties on a dollar and per boe basis increased for the year ended December 31, 2025, compared to prior year primarily due to higher royalties on the Osterheide startup volumes in Germany and higher production volumes from the SA-10 block in Croatia, which carried higher associated royalty rates.

Transportation

Q4 2025

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

France

(7,236)

(10.08)

(5,630)

(8.34)

(23,919)

(9.38)

(23,106)

(8.15)

Germany

(4,080)

(6.62)

(3,065)

(6.50)

(14,786)

(6.77)

(11,853)

(6.76)

Ireland

(2,576)

(3.57)

(641)

(0.76)

(9,396)

(3.14)

(8,418)

(2.38)

International

(13,892)

(4.92)

(9,336)

(3.37)

(48,101)

(4.42)

(43,377)

(3.75)

Transportation expense increased for the three months and year ended December 31, 2025 on a dollar basis compared to the prior year primarily due to a credit received in Q4 2024 in Ireland, the timing of vessels in France and gas transportation costs on the Osterheide startup volumes in Germany. On a per boe basis, transportation expense increased for the three months and year ended December 31, 2025 compared to the prior year primarily due to a credit received in Q4 2024 in Ireland and higher vessel costs in France.

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

Vermilion Energy Inc. ■ Page 17 ■ 2025 Management’s Discussion and Analysis

Operating expense

Q4 2025

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$boe

 

$boe

Australia

(12,823)

(58.29)

(10,866)

(47.78)

(68,246)

(59.32)

(80,347)

(56.65)

France

(19,131)

(26.65)

(18,597)

(27.54)

(68,516)

(26.88)

(69,376)

(24.48)

Netherlands

(12,338)

(31.59)

(11,921)

(31.77)

(38,742)

(27.59)

(41,127)

(24.77)

Germany

(19,180)

(31.14)

(13,544)

(28.74)

(59,354)

(27.18)

(53,129)

(30.32)

Ireland

(14,285)

(19.80)

(13,488)

(15.90)

(55,299)

(18.51)

(54,177)

(15.29)

Central and Eastern Europe

(991)

(6.31)

(1,025)

(5.96)

(3,635)

(5.88)

(2,537)

(7.09)

International

(78,748)

(27.90)

(69,441)

(25.08)

(293,792)

(26.97)

(300,693)

(26.00)

Operating expenses increased on a dollar basis for the three months ended December 31, 2025 compared to the same period in the prior year primarily due to prior period gas compression tariff adjustments in Germany and the timing of inventory in Australia. For the three months ended December 31, 2025, operating expenses increased on a per boe basis primarily due to costs spread across lower production volumes during a planned turnaround in Australia, fixed costs spread across lower production volumes in Ireland and prior period adjustments in Germany. During the year ended December 31, 2025, operating expenses decreased on a dollar basis primarily due to lower sales volumes in Australia and lower fuel and electricity fees in the Netherlands, partially offset by prior period adjustments in Germany. On a per boe basis, operating expenses remained relatively flat for the year ended December 31, 2025 compared to the prior year primarily due to increases from fixed costs spread across lower production volumes in Ireland and higher fuel and electricity costs in France, partially offset by costs spread across higher production volumes in Germany.

Consolidated Financial Performance Review


($M except per share)		Dec 31, 2025		Dec 31, 2024		Dec 31, 2023
Total assets		5,344,220		6,115,576		6,235,821
Long-term debt		1,243,397		963,456		914,015
Petroleum and natural gas sales		2,031,394		1,981,407		2,022,555
Net loss		(653,601)		(46,739)		(237,587)
Net loss per share
Basic		(4.25)		(0.30)		(1.45)
Diluted		(4.25)		(0.30)		(1.45)
Cash dividends ($/share)		0.52		0.48		0.40

Vermilion Energy Inc. ■ Page 18 ■ 2025 Management’s Discussion and Analysis

Continuing Operations

Q4 2025

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$/boe

 

$/boe

Sales

458,722

40.96

410,018

65.54

1,820,751

44.68

1,546,493

61.09

Royalties

(32,367)

(2.89)

(21,728)

(3.47)

(119,124)

(2.92)

(92,916)

(3.67)

Transportation

(36,178)

(3.23)

(21,253)

(3.40)

(132,883)

(3.26)

(86,247)

(3.41)

Operating

(133,133)

(11.89)

(108,141)

(17.29)

(508,521)

(12.48)

(446,173)

(17.62)

General and administration ⁽¹⁾

(25,698)

(2.29)

(20,645)

(3.30)

(98,450)

(2.42)

(74,010)

(2.92)

Corporate income tax expense

8,807

0.79

(15,996)

(2.56)

(26,044)

(0.64)

(66,423)

(2.62)

Petroleum resource rent tax

8,391

0.75

3,226

0.52

2,955

0.07

(11,702)

(0.46)

Interest expense

(27,670)

(2.47)

(23,965)

(3.83)

(132,748)

(3.26)

(84,606)

(3.34)

Equity based compensation

(627)

(0.06)

—

(6,319)

(0.16)

(14,361)

(0.57)

Realized gain on derivatives

21,037

1.88

28,795

4.60

141,648

3.48

345,318

13.64

Realized foreign exchange gain

0.01

2,442

0.39

1,223

0.03

7,735

0.31

Realized other expense

(844)

(0.08)

(5,119)

(0.82)

(15,800)

(0.39)

(7,267)

(0.29)

Fund flows from continuing operations

240,533

21.48

227,634

36.38

926,688

22.73

1,015,841

40.14

Equity based compensation

(5,693)

(7,499)

(18,847)

(15,569)

Unrealized gain (loss) on derivative instruments ⁽²⁾

53,894

(137,273)

116,299

(452,858)

Unrealized foreign exchange gain (loss) ⁽²⁾

30,421

(29,079)

(41,098)

(59,463)

Accretion

(19,202)

(17,112)

(71,629)

(66,179)

Depletion and depreciation

(209,384)

(131,139)

(697,461)

(563,982)

Deferred tax recovery (expense)

31,754

80,955

(16,901)

51,875

Impairment expense

(572,159)

—

(572,159)

—

Unrealized other income (expense) ⁽²⁾

11,717

(5,011)

10,303

(5,834)

Net loss from continuing operations

(438,119)

(18,524)

(364,805)

(96,169)

(1)	General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.

(2)	Unrealized gain (loss) on derivative instruments, Unrealized foreign exchange gain (loss), and Unrealized other income (expense) are line items from the respective Consolidated Statements of Cash Flows.

Discontinued Operations


		Q4 2025				Q4 2024				2025				2024
		$M		$/boe		$M		$/boe		$M		$/boe		$M		$/boe
Sales		827		76.83		94,334		71.23		210,643		69.80		434,914		74.40
Royalties		(205)		(19.04)		(18,321)		(13.83)		(40,591)		(13.45)		(85,034)		(14.55)
Transportation		(38)		(3.53)		(2,708)		(2.04)		(7,007)		(2.32)		(12,686)		(2.17)
Operating		170		15.79		(31,425)		(23.73)		(59,115)		(19.59)		(121,740)		(20.83)
General and administration		(553)		(51.37)		(6,815)		(5.15)		(20,367)		(6.75)		(25,493)		(4.36)
Corporate income tax expense		—		—		(1)		—		—		—		(19)		—
Fund flows from discontinued operations		201		18.68		35,064		26.48		83,563		27.69		189,942		32.49
Unrealized foreign exchange (loss) gain ⁽¹⁾		(207)				562				(308)				992
Accretion		—				(2,160)				(4,235)				(8,362)
Depletion and depreciation		585				(32,319)				(45,926)				(119,258)
Deferred tax (expense) recovery		(113)				(939)				54,482				(13,884)
Unrealized other expense ⁽¹⁾		—				—				(3,986)				—
Impairment expense		—				—				(372,386)				—
Net earnings (loss) from discontinued operations		466				208				(288,796)				49,430

Fund flows from operations		240,734		21.47		262,698		34.67		1,010,251		23.10		1,205,783		38.71

Net loss		(437,653)				(18,316)				(653,601)				(46,739)

(1)	Unrealized gain (loss) on derivative instruments, Unrealized foreign exchange (loss) gain, and Unrealized other expense are line items from the respective Consolidated Statements of Cash Flows.

Vermilion Energy Inc. ■ Page 19 ■ 2025 Management’s Discussion and Analysis

Consolidated Financial Performance Review

Fluctuations in fund flows from operations, including fund flows from continuing operations and fund flows from discontinued 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

●

For the three months ended December 31, 2025, total general and administration expense decreased compared to the same period in the prior year due to the timing of expenditures. General and administration expense increased for the year ended December 31, 2025 compared to 2024 primarily due to transaction costs related to the Westbrick acquisition and restructuring costs in Canada.

Equity based compensation

●

Equity based compensation included within funds flow from operations primarily relates to the settlement of withholding taxes on long-term incentives granted to directors, officers, and employees under security-based arrangements via cash, which were previously settled through the issuance and sale of shares from treasury. Equity based compensation settled in cash decreased for the year ended December 31, 2025 compared to the same periods in the prior year primarily due to the higher value of LTIP in the prior year.

PRRT and corporate income taxes

●

PRRT recoveries were higher for the three months and year ended December 31, 2025 compared to the same periods in 2024 due to lower sales and higher capital expenditures in Australia.

●

Corporate income taxes for the three months and year ended December 31, 2025 decreased compared to the prior year comparable periods mainly due to lower sales in France and in the Netherlands, accelerated asset retirement deductions in Germany and accelerated tax depletion deductions related to capital programs in Germany and in the Netherlands.

Interest expense

●

Interest expense for the three months and year ended December 31, 2025 increased due to higher debt levels driven by the issuance of the 2033 senior notes for US $400.0 million, draws on the revolving credit facility and $450.0 million term loan, which was drawn in Q1 2025 and subsequently repaid. The increases were partially offset by the repayment of the US $300.0 million 2025 senior notes.

Realized gain or loss on derivatives

●

For the three months and year ended December 31, 2025, we recorded realized gains on our natural gas and crude oil hedges due to lower commodity pricing compared to the strike prices.

●

A listing of derivative positions as at December 31, 2025 is included in “Supplemental Table 2” of this MD&A.

Realized other income or expense

●

Realized other expense for the three months ended December 31, 2025 remained relatively flat compared to the prior year. For the year ended December 31, 2025, realized other expense increased primarily related to an estimated provision recognized to satisfy work commitments.

Net earnings (loss)

Fluctuations in net loss 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 or losses resulting from acquisition or disposition activity or charges resulting from impairment or impairment reversals.

Equity based compensation

Equity based compensation expense relates included within net loss and excluded from funds flow from operations relates 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 months ended December 31, 2025 versus the prior year primarily due to lower value of LTIP awards outstanding in the current year. Equity based compensation increased for the year ended December 31, 2025, primarily due to the cash settlement of previously share-based settled expenses at a higher value of LTIP in the prior year.

Vermilion Energy Inc. ■ Page 20 ■ 2025 Management’s Discussion and Analysis

Unrealized gain or loss on derivative instruments

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.

Cross currency interest rate swaps and foreign exchange swaps may be entered into to manage foreign exchange and interest rate exposures on USD denominated debt. Unrealized gains and losses on these instruments are partially offset by the unrealized foreign exchange losses and gains on the underlying debt.

For the three months ended December 31, 2025, we recognized a net unrealized gain on derivative instruments of $53.9 million. This consists of unrealized gains of $25.1 million on our European natural gas commodity derivative instruments, $17.7 million on our crude oil and liquids commodity derivative instruments, $11.6 million on our North America gas commodity derivative instruments and $1.9 million on our equity swaps, partially offset by unrealized losses of $5.9 million on our USD-to-CAD foreign exchange swaps.

For the year ended December 31, 2025, we recognized a net unrealized gain on derivative instruments of $116.3 million. This consists of unrealized gains of $111.4 million on our European natural gas commodity derivative instruments, $24.8 million on our crude oil and liquids commodity derivative instruments and $4.8 million on our USD-to-CAD foreign exchange swaps, partially offset by unrealized losses of $12.1 million on our cross currency interest rate swaps, $8.1 million on our equity swaps and $8.0 million on our North American gas commodity derivative instruments.

Unrealized foreign exchange gains or 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.

In 2025, unrealized foreign exchange gains and losses primarily resulted from:

●

The translation of Euro and US dollar denominated intercompany loans to and from our international subsidiaries to Vermilion Energy Inc. An appreciation in the Euro and/or the US dollar against the Canadian dollar will result in an unrealized foreign exchange loss (and vice-versa). Under IFRS Accounting Standards, 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 reflects only the parent company's side of the translation.

●	The translation of our USD denominated 2030 senior unsecured notes and USD denominated 2033 senior unsecured notes.

●	The translation of USD borrowings on our revolving credit facility. The unrealized foreign exchange gains or losses on these borrowings are offset by unrealized derivative gains or losses on associated USD-to-CAD cross currency interest rate swaps.

For the three months ended December 31, 2025, we recognized a net unrealized foreign exchange gain of $30.2 million, primarily driven by the effects of the US dollar weakening 1.5% against the Canadian dollar on our US denominated debt combined with the effects of the Euro weakening 1.5% against the Canadian dollar on our Euro denominated intercompany loans. For the year ended December 31, 2025, we recognized a net unrealized foreign exchange loss of $41.1 million, primarily driven by the effects of the Euro strengthening 7.6% against the Canadian dollar on our Euro denominated intercompany loans, partially offset by the impact of the US dollar weakening 4.7% against the Canadian dollar on our US denominated debt.

Unrealized other income (expense)

Unrealized other income for the three months and year ended December 31, 2025 was primarily comprised of the $12.0 million gain on disposition of securities in Q4 2025, partially offset by a net $4.0 million unrealized loss on the dispositions of the United States and Saskatchewan assets.

Accretion

Accretion expense is recognized to update the present value of asset retirement obligations. For the three months and year ended December 31, 2025, accretion expense increased primarily due to the impact of the Euro strengthening against the Canadian dollar partially offset by lower asset retirement obligation driven by dispositions in Canada and the United States and changes in estimates in Germany.

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.

Vermilion Energy Inc. ■ Page 21 ■ 2025 Management’s Discussion and Analysis

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 months and year ended December 31, 2025 of $18.63 and $16.99 decreased from $21.56 and $21.92 in the same periods of the prior year primarily due to decreases in the depletable base on asset retirement obligation assets in Europe, in addition to the reserves and future development costs added as part of the Westbrick acquisition and increased reserves at Mica. The decrease was partially offset by the strengthening of the Euro against the Canadian dollar.

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.

The Company recorded a deferred tax recovery of $31.8 million on continuing operations for the three months ended December 31, 2025, compared to a deferred tax recovery of $81.0 million for the same period in the prior year. The deferred tax recovery for the three months ended December 31, 2025 was primarily driven by impairment charges in Australia, France and Ireland, partially offset by the derecognition of deferred tax assets in Ireland and Canada. In 2025, the Company recorded deferred tax expense $16.9 million on continuing operations compared to a deferred tax recovery of $51.9 million for the same period in the prior year. The deferred tax expense in 2025 mainly related to changes in our derivatives mark-to-market position, changes in temporary differences in Canada and Ireland, partially offset by the deferred tax recovery on impairment charges in Australia, France and Ireland.

For the year ended December 31, 2025, the Company recorded a deferred tax recovery of $54.5 million on discontinued operations compared to deferred tax expense of $13.9 million for the same period in the prior year. The deferred tax recovery for the year ended December 31, 2025 was driven by the impairment recorded for the Saskatchewan and U.S. assets disposed.

Impairment

In the fourth quarter of 2025, indicators of impairment were present in our Australia, France and Ireland CGUs due to changes in forecasted cost assumptions. As a result of the indicators of impairment, the Company performed impairment calculations on the identified CGUs and the recoverable amounts were determined using fair value less costs to sell, which considered future after - tax cash flows from proved plus probable reserves and an after - tax discount rate of 15.0%. Based on the results of the impairment tests completed, the Company recognized non - cash impairment charges of $572.2 million. Inputs used in the measurement of capital assets are not based on observable market data and fall within level 3 of the fair value hierarchy.

Taxes

Current income tax rates

Vermilion typically pays corporate income taxes in France, Netherlands, Australia, Germany and Croatia. In addition, Vermilion pays PRRT in Australia which is a profit based tax applied at a rate of 40% on sales less operating expenses, capital expenditures, and other eligible expenditures. PRRT is deductible in the calculation of taxable income in Australia.

Vermilion Energy Inc. ■ Page 22 ■ 2025 Management’s Discussion and Analysis

For 2025 and 2024, taxable income was subject to corporate income tax at the following statutory rates:


Jurisdiction		2025		2024
Canada		23.9	%	24.4	%
United States		21.0	%	21.0	%
France		25.8	%	25.8	%
Netherlands ⁽¹⁾		50.0	%	50.0	%
Germany		31.2	%	31.1	%
Ireland		25.0	%	25.0	%
Australia		30.0	%	30.0	%
Croatia		18.0	%	18.0	%

⁽¹⁾	In the Netherlands, an additional 10% uplift deduction is allowed against taxable income that is applied to operating expenses, eligible general and administration expenses, and tax deductions for depletion and abandonment retirement obligations.

Tax legislation changes

In December 2021, the Organization for Economic Co-operation and Development (“OECD”) issued model rules for a new global minimum tax framework (“Pillar Two”). The objective of Pillar Two is to ensure that large multinational enterprises are subjected to a minimum 15% effective tax rate in each jurisdiction in which they operate.

All of the countries where Vermilion operates have enacted tax legislation to comply with Pillar Two with effect from January 1, 2024. For the year ended December 31, 2025 and December 31, 2024, the Company recorded $6.5 million of income tax expense relating to Pillar Two.

In May 2023, the IASB issued amendments to IAS 12, “Income Taxes” (“IAS 12”) to address the impacts and additional disclosure requirements related to Pillar Two. Vermilion has applied the mandatory exception required by IAS 12 and accordingly has not accounted for any related deferred income tax assets or liabilities.

Tax pools

As at December 31, 2025, we had the following tax pools:


($M)		Oil & Gas Assets		Tax Losses		Other		Total
Canada		2,091,249	⁽¹⁾	1,052,062	⁽⁴⁾	29,454		3,172,765
France		268,314	⁽²⁾	—		—		268,314
Netherlands		83,557	⁽³⁾	7,097	⁽⁵⁾	—		90,654
Germany		292,415	⁽³⁾	7,411	⁽⁶⁾	14,327		314,153
Ireland		—		1,155,614	⁽⁴⁾	—		1,155,614
Australia		159,038	⁽¹⁾	137,608	⁽⁴⁾	—		296,646
Croatia		72,223	⁽²⁾	—		—		72,223
Total		2,966,796		2,359,792		43,781		5,370,369

(1)	Deduction calculated using various declining balance rates.

(2)	Deduction calculated using a combination of straight-line over the assets life and unit of production method.

(3)	Deduction calculated using a unit of production method.

(4)	Tax losses can be carried forward and applied at 100% against taxable income.

(5)	State Profit Share ("SPS") tax credit can be carried forward and applied at 100% against SPS taxes.

(6)	Tax losses can be carried forward and are available to offset the first €1 million of taxable income and 60% of taxable profits in excess each taxation year.

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.

Vermilion Energy Inc. ■ Page 23 ■ 2025 Management’s Discussion and Analysis

As at December 31, 2025, we have a ratio of net debt to four quarter trailing fund flows from operations of 1.4.

Net debt

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


		As at
($M)		Dec 31,2025		Dec 31,2024
Long-term debt		1,243,397		963,456
Adjusted working capital ⁽¹⁾		96,091		3,426
Unrealized FX on swapped USD borrowings ⁽²⁾		2,902		—
Net debt		1,342,390		966,882

Ratio of net debt to four quarter trailing fund flows from operations⁽³⁾		1.4		0.8

(1)

Adjusted working capital is a non-GAAP financial measure that is not standardized under IFRS Accounting Standards and may not be comparable to similar measures disclosed by other issuers. It is defined as current assets less current liabilities, excluding current derivatives, current asset retirement obligations and current lease liabilities. The measure is used to calculate net debt, a capital measure disclosed above. Reconciliation to the primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

(2)

Vermilion may enter into cross currency interest rate swaps to hedge the foreign exchange movements on USD borrowings on our revolving credit facility. Unrealized FX on swapped USD borrowings relates to the unrealized gains and losses on our cross currency interest swaps. At December 31, 2025, there was $196.7 million of USD borrowings on our revolving credit facility. (December 31, 2024 - $nil).

(3)

Subsequent to February 26, 2025, net debt to four quarter trailing fund flows from operations is calculated inclusive of Westbrick Energy's pre-acquisition four quarter trailing fund flows from operations, as if the acquisition of Westbrick Energy occurred at the beginning of the four quarter trailing period, and exclusive of the four quarter trailing fund flows from discontinued operations to reflect the Company’s ability to repay debt on a pro forma basis.

As at December 31, 2025, net debt increased to $1.3 billion (December 31, 2024 - $1.0 billion) primarily due to the financing of the Westbrick acquisition in Q1 2025. The increase was partially offset by the proceeds received from the disposition of the Saskatchewan and United States assets and strong free cash flow generation primarily driven by stronger operational performance from the Westbrick assets acquired.

The ratio of net debt to four quarter trailing fund flows from operations⁽¹⁾ increased to 1.4 as at December 31, 2025 (December 31, 2024 - 0.8) primarily due to higher net debt on acquisition and disposition activity.

Long-term debt

The balances recognized on our balance sheet are as follows:


		As at
		Dec 31,2025		Dec 31,2024
Revolving credit facility		222,724		—
2025 senior unsecured notes		—		398,275
2030 senior unsecured notes		504,962		565,181
2033 senior unsecured notes		515,711		—
Long-term debt		1,243,397		963,456

Revolving credit facility

As at December 31, 2025, Vermilion had in place a bank revolving credit facility maturing May 25, 2029 with terms and outstanding positions as follows:


		As at
($M)		Dec 31,2025		Dec 31,2024
Total facility amount		1,350,000		1,350,000
Amount drawn		(222,724)		—
Letters of credit outstanding		(49,263)		(22,731)
Unutilized capacity		1,078,013		1,327,269

Vermilion Energy Inc. ■ Page 24 ■ 2025 Management’s Discussion and Analysis

The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. As at December 31, 2025, $222.7 million of the revolving credit facility was drawn.

On June 9, 2025, the maturity date of the revolving facility was extended to May 25, 2029 (previously May 26, 2028). The total facility amount of $1.35 billion and accordion feature to aggregate amount available under the facility of $1.8 billion remain unchanged.

As at December 31, 2025, the revolving credit facility was subject to the following financial covenants:


				As at
Financial covenant		Limit		Dec 31,2025		Dec 31,2024
Consolidated total debt to consolidated EBITDA		Less than 4.0		1.14		0.72
Consolidated total senior debt to consolidated EBITDA		Less than 3.5		0.21		—
Consolidated EBITDA to consolidated interest expense		Greater than 2.5		8.44		16.59

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

●

Consolidated total debt: Includes all amounts classified as “Long-term debt”, “Current portion of long-term debt”, and “Lease obligations” (including the current portion included within "Accounts payable and accrued liabilities" but excluding operating leases as defined under IAS 17) on our consolidated balance sheet.

●	Consolidated total senior debt: Consolidated total debt excluding unsecured and subordinated debt.

●	Consolidated EBITDA: Consolidated net loss before interest, income taxes, depreciation, accretion and certain other non-cash items, adjusted for the impact of the acquisition of a material subsidiary.

●	Total interest expense: Includes all amounts classified as "Interest expense", but excludes interest on operating leases as defined under IAS 17.

As at December 31, 2025 and December 31, 2024, Vermilion was in compliance with the above covenants.

Term loan

Concurrent with the completion of the Westbrick acquisition on February 26, 2025, Vermilion's credit facility agreement was amended to incorporate a new $450.0 million term loan (the “Term Loan”) which was immediately drawn. The Term Loan balance was repaid in full in 2025.

2025 senior unsecured notes

On March 13, 2017, Vermilion issued US $300.0 million of senior unsecured notes at par. The notes bore interest at a rate of 5.625% per annum and were paid semi-annually on March 15 and September 15. During the year ended December 31, 2024, Vermilion purchased $31.6 million of senior unsecured notes on the open market which were subsequently cancelled. The notes matured on March 15, 2025 and the balance was repaid in full.

2030 senior unsecured notes

On April 26, 2022, Vermilion closed a private offering of US $400.0 million of senior unsecured notes, priced at 99.241% of par. The notes bear interest at a rate of 6.875% per annum, to be paid semi-annually on May 1 and November 1. The notes mature on May 1, 2030. 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.

●

On or after May 1, 2025, Vermilion may 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	%

During the year ended December 31, 2025, Vermilion purchased $34.9 million of the 2030 senior unsecured notes at a rate of 95.8% on the open market which were subsequently cancelled.

Vermilion Energy Inc. ■ Page 25 ■ 2025 Management’s Discussion and Analysis

2033 senior unsecured notes

On February 11, 2025 Vermilion closed a private offering of US $400.0 million of senior unsecured notes at par. The notes bear interest at a rate of 7.250% per annum, to be paid semi-annually on February 15 and August 15. The notes mature on February 15, 2033. 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.

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

●

Prior to February 15, 2028, Vermilion may redeem up to 40% of the original principal amount of the notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price of 107.250% of the principal amount of the notes, together with accrued and unpaid interest.

●

Prior to February 15, 2028, Vermilion may also 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,” together with applicable premium, accrued and unpaid interest.

●

On or after February 15, 2028, Vermilion may 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
2028		103.625	%
2029		101.813	%
2030 and thereafter		100.000	%

During the year ended December 31, 2025, Vermilion purchased $23.7 million of the 2033 senior unsecured notes at a rate of 95.3% on the open market which were subsequently cancelled.

Shareholders' capital

The following table outlines our dividend payment history:


Date		Frequency		Dividend per unit or share
April 2022 to July 2022		Quarterly		$	0.06
August 2022 to March 2023		Quarterly		$	0.08
April 2023 to March 2024		Quarterly		$	0.10
April 2024 onwards		Quarterly		$	0.12
April 2025 onwards		Quarterly		$	0.13

The following table reconciles the change in shareholders’ capital:


Shareholders’ Capital		Shares ('000s)		Amount ($M)
Balance at January 1		154,344		3,918,898
Shares issued for acquisition		1,104		13,363
Vesting of equity based awards		504		17,603
Share-settled dividends on vested equity based awards		75		682
Repurchase of shares		(3,077)		(78,632)
Balance at December 31		152,950		3,871,914

As at December 31, 2025, there were approximately 4.9 million equity based compensation awards outstanding. As at March 4, 2026, there were approximately 152.6 million common shares issued and outstanding.

On July 9, 2025, the Toronto Stock Exchange approved the Company's notice of intention to renew its normal course issuer bid ("the NCIB"). The NCIB renewal allows Vermilion to purchase up to 15,259,187 common shares (representing approximately 10% of outstanding common shares) beginning July 12, 2025 and ending July 11, 2026. Common shares purchased under the NCIB will be cancelled.

In the fourth quarter of 2025, Vermilion purchased 0.6 million common shares under the NCIB for total consideration of $6.5 million. The common shares purchased under the NCIB were cancelled.

Subsequent to December 31, 2025, Vermilion purchased and cancelled 0.3 million shares under the NCIB for total consideration of $4.3 million.

Vermilion Energy Inc. ■ Page 26 ■ 2025 Management’s Discussion and Analysis

Contractual Obligations and Commitments

As at December 31, 2025, we had the following contractual obligations and commitments:


($M)		Less than 1 year		1 - 3 years		3 - 5 years		After 5 years		Total
Long-term debt ⁽¹⁾		80,587		166,190		871,135		619,392		1,737,304
Lease obligations ⁽²⁾		21,183		34,920		32,375		42,702		131,180
Processing and transportation agreements		87,314		160,649		170,468		780,778		1,199,209
Purchase obligations		60,247		14,566		1,308		753		76,874
Drilling and service agreements		46,849		—		—		—		46,849
Total contractual obligations and commitments		296,180		376,325		1,075,286		1,443,625		3,191,416

⁽¹⁾	Includes interest on senior unsecured notes.

⁽²⁾	Includes undiscounted IFRS 16 - Leases obligations of $76.3 million as at December 31, 2025, surface lease rental commitments of $54.9 million.

⁽³⁾	Commitments denominated in foreign currencies have been translated using the related spot rates on December 31, 2025.

Asset Retirement Obligations

As at December 31, 2025, asset retirement obligations were $1.0 billion compared to $1.2 billion as at December 31, 2024. The decrease in asset retirement obligations is primarily attributable to changes in rates combined with the United States and Saskatchewan dispositions, partially offset by the foreign exchange impact of the Euro strengthening against the Canadian dollar and the acquisition of Westbrick asset retirement obligations. The credit spread increased to 4.4% at December 31, 2025 compared to 2.6% at December 31, 2024 primarily due to a higher 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:


		Dec 31, 2025		Dec 31, 2024		Change
Credit spread added to below noted risk-free rates		4.4	%	2.6	%	1.8	%
Country specific risk-free rate
Canada		3.9	%	3.2	%	0.7	%
United States ⁽¹⁾		5.0	%	4.8	%	0.2	%
France		4.5	%	3.7	%	0.8	%
Netherlands		3.2	%	2.7	%	0.5	%
Germany		3.4	%	2.6	%	0.8	%
Ireland		3.2	%	2.8	%	0.4	%
Australia		4.9	%	4.6	%	0.3	%
Central and Eastern Europe		4.8	%	4.7	%	0.1	%

(1)	Reflects the risk-free rate at time of disposition.

Current cost estimates are inflated to the estimated time of abandonment using inflation rates of between 1.4% and 3.5% (as at December 31, 2024 - between 1.5% and 3.6%).

Vermilion Energy Inc. ■ Page 27 ■ 2025 Management’s Discussion and Analysis

Risks and Uncertainties

Crude oil and natural gas exploration, production, acquisition and marketing operations involve a number of risks and uncertainties that have affected the financial statements and are reasonably likely to affect them in the future. Some of these risks and uncertainties are discussed further below. Many additional risks and uncertainties are outline in the Annual Information Form, which is available on our website at www.vermilionenergy.com and on SEDAR+ at www.sedarplus.ca. Additional risks and uncertainties, not discussed or that management may be unaware of, may become important factors which affect Vermilion.

Commodity prices

Crude oil and natural gas prices have fluctuated significantly in recent years due to supply and demand factors. Changes in crude oil and natural gas prices affect the level of revenue we generate, the amount of proceeds we receive and payments we make on our commodity derivative instruments, and the level of taxes that we pay. In addition, lower crude oil and natural gas prices would reduce the recoverable amount of our capital assets and could result in impairments or impairment reversals.

Exchange rates

Exchange rate changes impact the Canadian dollar equivalent revenue and costs that we recognize. The majority of our crude oil and condensate revenue stream is priced in US dollars and as such an increase in the strength of the Canadian dollar relative to the US dollar would result in the receipt of fewer Canadian dollars for our revenue. We also incur expenses and capital costs in US dollars, Euros and Australian dollars and thus a decrease in strength of the Canadian dollar relative to those currencies may result in the payment of more Canadian dollars for our expenditures.

In addition, exchange rate changes impact the Canadian equivalent carrying balances for our assets and liabilities. For foreign currency denominated monetary assets (such as cash and cash equivalents, long-term debt, and intercompany loans), the impact of changes in exchange rates is recorded in net loss as a foreign exchange gain or loss.

Production and sales volumes

Our production and sales volumes affect the level of revenue we generate and correspondingly the royalties and taxes that we pay. In addition, significant declines in production or sales volumes due to unforeseen circumstances may also result in an indicator of impairment and potential impairment charges.

Interest rates

Changes in interest rates impact the amount of interest expense we pay on our variable rate debt and also our ability to obtain fixed rate financing in the future.

Tax and royalty rates

Changes in tax and royalty rates in the jurisdictions that we operate in would impact the amount of current taxes and royalties that we pay. In addition, changes to substantively enacted tax rates would impact the carrying balance of deferred tax assets and liabilities, potentially resulting in a deferred tax recovery or incremental deferred tax expense.

Vermilion was exposed to increased taxation and royalties due to windfall taxes on profits in 2022 and 2023. Windfall taxes were enacted within the European Union for oil and gas companies at a minimum rate of 33% calculated on taxable profits above a 20% increase in the average yearly taxable profits as compared to 2018 to 2021. There is risk that windfall taxes or similar mechanisms will be re-enacted or similar legislation could be enacted in other jurisdictions that Vermilion operates in periods of extraordinary commodity prices.

Geopolitical tensions

Ongoing global geopolitical tensions, including the war in Ukraine, conflicts in the Middle East and heightened uncertainty related to developments in Venezuela, continue to contribute to uncertainty in global economic conditions and energy markets. These factors have continued to influence global oil and gas supply dynamics, trade flows, and sanctions regimes, contributing to ongoing volatility in commodity prices, foreign exchange rates, interest rates, and capital markets. In addition, heightened geopolitical uncertainty has increased the risk of disruptions to energy infrastructure, transportation routes, and global economic activity.

The risks disclosed in our Annual Information Form for the year ended December 31, 2025 may be exacerbated as a result of these tensions, including: market risks including volatility of oil and gas prices, volatility of foreign exchange rates, volatility of market price of common shares, hedging arrangements; regulatory and political risks including tax, royalty, and other government legislation; financing risks including additional financing, debt service, variations in interest rates and foreign exchange rates; acquisition and expansion risks including international operations and future geographical/industry expansion, acquisition assumptions, failure to realize anticipated benefits of prior acquisitions.

Vermilion Energy Inc. ■ Page 28 ■ 2025 Management’s Discussion and Analysis

Global tariffs

The global geopolitical landscape continues to be influenced by the current policies of the United States, particularly in relation to trade and tariffs. The potential imposition of tariffs, especially on Canadian goods, including crude oil, may create economic challenges for the oil and gas sector. These trade barriers if fully enacted may disrupt supply chains, raise costs, and impact the competitiveness of Canadian exports. The risks disclosed in our Annual Information Form for the year ended December 31, 2025 may be exacerbated as a result of these tensions, including: market risks including volatility of oil and gas prices, volatility of foreign exchange rates, volatility of market price of common shares, hedging arrangements; regulatory and political risks including tax, royalty, and other government legislation; financing risks including additional financing, debt service, variations in interest rates and foreign exchange rates; acquisition and expansion risks including international operations and future geographical/industry expansion, acquisition assumptions, failure to realize anticipated benefits of prior acquisitions.

In addition to the above, we are exposed to risk factors that impact our company and business. For further information on these risk factors, please refer to our Annual Information Form, available on SEDAR+ at www.sedarplus.ca or on our website at www.vermilionenergy.com.

Financial Risk Management

To mitigate the risks affecting our business whenever possible, we seek to hire personnel with experience in specific areas. In addition, we provide continued training and development to staff to further develop their skills. When appropriate, we use third party consultants with relevant experience to augment our internal capabilities with respect to certain risks.

We consider our commodity price risk management program as a form of insurance that protects our cash flow and rate of return. The primary objective of the risk management program is to support our return of capital and internal capital development programs. The level of commodity price risk management that occurs is dependent on the amount of debt that is carried. When debt levels are higher, we will be more active in protecting our cash flow stream through our commodity price risk management strategy.

When executing our commodity price risk management programs, we use derivative financial instruments encompassing over-the-counter financial structures, as well as fixed and collar structures to economically hedge a part of our physical crude oil and natural gas production. We have strict controls and guidelines in relation to these activities and contract principally with counterparties that have investment grade credit ratings.

Critical Accounting Estimates

The preparation of financial statements in accordance with IFRS Accounting Standards requires us to make estimates. Critical accounting estimates are those accounting estimates that require us to make assumptions about matters that are highly uncertain at the time the estimate is made and a different estimate could have been made in the current period or the estimate could change period-to-period.

The carrying amount of asset retirement obligations

The carrying amount of asset retirement obligations ($959.7 million as at December 31, 2025) is the present value of estimated future costs, discounted from the estimated abandonment date using a credit-adjusted risk-free rate. Estimated future costs are based on our assessment of regulatory requirements and the present condition of our assets. The estimated abandonment date is based on the reserve life of the associated assets. The credit-adjusted risk-free rate is based on prevailing interest rates for the appropriate term, risk-free government bonds adjusted for our estimated credit spread (determined by reference to the trading prices for debt issued by similarly rated independent oil and gas producers, including our own senior unsecured notes). Changes in these estimates would result in a change in the carrying amount of asset retirement obligations and capital assets and, to a significantly lesser degree, future accretion and depletion expense.

The estimated abandonment date may change from period to period as the estimated abandonment date changes in response to new information, such as changes in reserve life assumptions or regulations. A one year increase or decrease in the estimated abandonment date would decrease or increase asset retirement obligations (with an offsetting increase to capital assets) by approximately $57.5 million.

The estimated credit-adjusted risk-free rate may change from period to period in response to market conditions in Canada and the international jurisdictions that we operate in. A 0.5% increase or decrease in the credit-adjusted risk-free rate would decrease or increase asset retirement obligations by approximately $53.1 million.

The fair value of capital assets acquired in business combinations

In preparing the purchase price allocation for business combinations, we estimate the fair value of assets acquired. Assets acquired in an acquisition primarily relate to the crude oil and natural gas reserves. The estimated fair value of the crude oil and natural gas reserves acquired is based on the present value of proved plus probable reserves and forecast commodity prices. Changes in these assumptions, including the discount rate used, would

Vermilion Energy Inc. ■ Page 29 ■ 2025 Management’s Discussion and Analysis

change the amount of capital assets recognized and as a result may cause rise to goodwill or gains recognized on the acquisition and future depletion and depreciation expense.

The recognition of deferred tax assets

The extent to which deferred tax assets are recognized are based on estimates of future profitability. These estimates are based on estimated future commodity prices and estimates of reserves. As at December 31, 2025, the deferred tax asset balance of $19.0 million mainly relates to Ireland (December 31, 2024 - Canada for $162.1 million and Ireland for $33.8 million).

In Ireland, we have $758.8 million of non-expiring tax loss pools where $189.7 million of deferred tax assets has not been recognized as there is uncertainty on our ability to fully use these losses based on estimated future taxable profits. Estimated future taxable profits are calculated using proved and probable reserves and forecast pricing.

In Canada, we have $144.2 million of non-expiring oil and gas tax pools where $33.8 million of deferred tax assets has not been recognized as there is uncertainty on our ability to fully use these pools based on estimated future taxable profits. Estimated future taxable profits are calculated using proved and probable reserves and forecast pricing.

Depletion and depreciation

Capital assets are grouped into depletion units, which are groups of assets within a specific production area that have similar economic lives. Depletion units represent the lowest level of disaggregation for which costs are accumulated for the purposes of calculating depletion and depreciation.

The net carrying value of each depletion unit is depleted using the unit of production method by reference to the ratio of production in the period to the total proved and probable reserves, taking into account the future development costs necessary to bring the applicable reserves into production. Key judgments that are made to reserve estimates such as revisions in reserves, changes in forecast commodity prices, foreign exchange rates, capital or operating costs would impact the amount of depletion and depreciation recorded in a period.

The estimated recoverable amount of cash generating units

Each reporting period, we assess our CGUs for indicators of impairment or impairment reversal. If an indicator of impairment or impairment reversal is identified, we estimate the recoverable amount of the CGU. Judgment is required when determining whether indicators of impairment or impairment reversal exist, as well as judgments made when determining the recoverable amount of a CGU. Changes in any of the key judgments, such as a revision in reserves, changes in forecast commodity prices, foreign exchange rates, capital or operating costs would impact the estimated recoverable amount.

In the fourth quarter of 2025, indicators of impairment were present in our France, Australia and Ireland CGUs due to changes in forecasted pricing. As a result of the indicators of impairment, the Company performed impairment calculations on the identified CGUs and the recoverable amounts were determined using fair value less costs to sell, which considered future after-tax cash flows from proved plus probable reserves and an after-tax discount rate of 15.0%. Based on the results of the impairment tests completed, the Company recognized non-cash impairment charges of $572.2 million. Inputs used in the measurement of capital assets are not based on observable market data and fall within level 3 of the fair value hierarchy. A 1% increase in the assumed after-tax discount rate would reduce the estimated recoverable amount of assets tested and result in a higher impairment of $28.1 million while a 5% decrease in revenues (due to a decrease in commodity price forecasts or reserve estimates) would reduce the estimated recoverable amount of assets tested and result in higher impairment of $101.2 million.

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.

Cybersecurity

Vermilion has an information security training and compliance program that is completed at least annually. We have not experienced a cybersecurity breach in the last three years.

Recently Adopted Accounting Pronouncements

Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates

On January 1, 2025, Vermilion adopted the amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates, as issued by the International Accounting Standards Board ("IASB") that contains guidance as to when a currency is exchangeable and how to determine the

Vermilion Energy Inc. ■ Page 30 ■ 2025 Management’s Discussion and Analysis

exchange rate when it is not. The amendment also includes additional disclosure when a currency is not exchangeable. There was no impact to Vermilion's financial statements.

Vermilion did not adopt any new accounting pronouncements as at December 31, 2025 that would have a material impact on the Consolidated 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-related Disclosures" and European Corporate Sustainability Reporting Directive (CSRD)

In June 2023, the International Sustainability Standards Board (ISSB) issued its inaugural standards – IFRS S1 and IFRS S2.

The Canadian Sustainability Standards Board has issued Canada-specific version of IFRS S1 and S2 as Canadian Sustainability Disclosure Standards 1 and 2. While Canadian securities regulators have not mandated these standards, they have referenced them as a useful voluntary disclosure framework for sustainability and climate-related disclosure, and noted that securities legislation already requires issuers to disclose material climate-related risks. Australia has mandated the Australian version of IFRS S2 as Australian Accounting Standards Board S2 with mandatory disclosure for Vermilion in 2025, reporting in 2026. While the EU implemented the CSRD and its related European Sustainability Reporting Standards (ESRS) in 2024, the April 2025 “Stop-the Clock” directive delayed the CSRD reporting date for non-EU parent companies and the February 2026 Omnibus legislation simplified reporting requirements. These changes have delayed Vermilion’s parent-level reporting date from 2025 to 2028 (reporting in 2029); however, the parent company reporting details are still under discussion and may further adjust scope and timing. Vermilion is continuing to review the impact of the standards on its financial reporting.

IFRS 18 “Presentation and Disclosure in Financial Statements issued”

In April 2024, the IASB issued the new accounting standard, IFRS 18 'Presentation and Disclosure in Financial Statements'. IFRS 18 will replace IAS 1 'Presentation of Financial Statements' and provides a defined structure to the statement of net earnings (loss) and comprehensive income and related disclosure requirements. Key changes include a new operating profit subtotal and requires income and expenses to be classified into operating, investing, and financing categories, based on the entity’s main business activities. The new standard is effective for annual reporting periods beginning on or after January 1, 2027 and is required to be adopted retrospectively. Vermilion is currently reviewing income and expense classifications, management-defined performance measures, and contractual arrangements to assess the impact the standard will have on the consolidated financial statements.

Amendments to IFRS 9 - Financial Instruments and IFRS 7 Financial Instruments: Disclosure

In May 2024, the IASB issued amendments to IFRS 9 'Financial Instruments' and IFRS 7 ‘Financial Instruments: Disclosures’ relating to settling financial liabilities using an electronic payment system and assessing contractual cash flow characteristics of financial assets. The amendments will be effective for annual reporting periods beginning on January 1, 2026, but are not expected to have a material impact on the consolidated financial statements.

Health, Safety and Environment (HSE)

We are committed to ensuring we conduct our activities in a manner that protects the health and safety of our employees, our contractors and the public. Our HSE Vision is to consistently apply our core values of Excellence, Trust, Respect and Responsibility. Our goal is to create a workplace free of incidents by ensuring our proactive culture and behaviours create an organization where HSE is fully integrated into our business – it is our way of life. Our mantra is HSE: Everyone. Everywhere. Everyday.

Vermilion seeks to maintain health, safety and environmental practices and procedures that comply with or exceed regulatory requirements and industry standards. All of our personnel are expected to work safely and in accordance with established regulations and procedures, and we seek to reduce impacts to land, water and air. During 2025 we:

●

Maintained clear priorities around 5 key focus areas of HSE Culture, Communication and Knowledge Management, Management Systems, Environmental & Operational Stewardship, and Health;

●

Worked towards fulfilling our updated 2030 HSE Strategy;

●

Continued implementation of our Top Quartile HSE Performance Plan and progress a Serious Injury & Fatality Prevention Program;

●

Updated our Health, Safety & Environment Management System and initiated business unit gap assessments;

●

Advanced our Life-Saving Rules implementation and initiated a Control Verification program to assure controls for high-risk activities are effective and in place;

Vermilion Energy Inc. ■ Page 31 ■ 2025 Management’s Discussion and Analysis

●

Continued reinforcement of the “Vermilion High 5”, an individual safety awareness initiative aimed at keeping front-line workers safe;

●

Completed ongoing HSE performance monitoring through key performance indicator development, analysis and reporting;

●

Continued comprehensive investigations of our incidents and near misses to ensure root causes were identified, corrective actions effectively implemented and lessons shared across the organization;

●

Managed our waste products by reducing, recycling and recovering;

●

Reduced long-term environmental liabilities through decommissioning, abandoning and reclaiming well leases and facilities;

●

Continued the development of a robust hazard identification and risk mitigation program specific to environmentally sensitive areas;

●

Performed auditing, management inspections and workforce observations to measure compliance and identify potential hazards and apply risk reduction measures; and

●

Assessed the effectiveness of our performance management standards across multiple business units.

We are a member of several organizations concerned with environment, health and safety, including numerous regional co-operatives and synergy groups. In the area of stakeholder relations, we work to build long-term relationships with environmental stakeholders and communities.

Task Force on Climate-related Financial Disclosure (TCFD)

Environmental, Social and Governance (ESG)

Vermilion's purpose is to responsibly produce essential energy while delivering long-term value to our stakeholders. We believe that applying sustainability principles strengthens shareholder returns, expands opportunities, reduces risks, and supports the communities in which we operate.

Vermilion has reported on sustainability since 2014, originally aligned with the Global Reporting Initiative (GRI). Our report now incorporates guidance from the Task Force on Climate-related Financial Disclosure (TCFD), the International Sustainability Standards Board (ISSB) (including Sustainability Accounting Standards Board, SASB) and the Canadian Sustainability Standards Board (CSSB).

We use the TCFD framework to manage climate and broader sustainability risks and opportunities, acknowledging how climate issues connect with environmental impacts, social factors such as safety and community engagement, and governance issues. Index:

● Governance	Information Circular
● Strategy	Annual Report MD&A (Risks in Annual Information Form)
● Risk Management	Annual Report MD&A
● Metrics and Targets	Annual Report MD&A
● Consolidated Climate (TCFD) Report	www.vermilionenergy.com/our-sustainability/sustainability-report/

Sustainability and Climate-Related Strategy

Vermilion recognizes stakeholder expectations that we deliver strong financial performance responsibly and ethically. We prioritize:

●

the safety and health of everyone involved in our operations;

●

protecting the environment by applying the UN Precautionary Principle: assessing environmental risks in decision-making, and seeking to continually improve performance; and

●

achieving economic success through operational excellence, including efficiency, technical strength, strong stakeholder relations, and fair treatment of staff, contractors, partners and suppliers.

Description of Sustainability- and Climate-related Risks and Opportunities, and Impacts

We identify climate-related risks and opportunities across short-term (0–3 years), medium-term (3–6 years) and long-term (6–50 years) horizons, using scenario analysis, cost projections and our internally-developed Emissions Long-Range Planning tool to estimate potential impacts and inform management responses. Risk descriptions can be found in our Annual Information Form and in our Sustainability Report, both available at vermilionenergy.com.

Vermilion Energy Inc. ■ Page 32 ■ 2025 Management’s Discussion and Analysis

Resilience of the Company’s Strategy

The Board of Directors and Executive Committee have responded to our risk and opportunity identification using a scenario analysis that references models from the World Economic Forum, IEA, Equinor, BP, Exxon, OPEC, and EIA. Note that these analyses are neither predictions nor forecasts; while they rely on the work of credible third-party organizations, they are constructions based on circumstances and assumptions that are highly vulnerable to macroeconomic and geopolitical changes. While there are significant inherent uncertainties in how the energy transition will evolve, we have identified key influencing factors: government policy, technology adoption, energy demand/supply, consumer behavior, capital availability, and reputation. Physical climate risks have been modeled using IPCC RCP 4.5, identifying impacts such as rising temperatures, aridity, and sea levels.

These factors have informed our discussions on business strategy, resilience, and risk identification and management. Our resulting business model involves responsible production of essential oil and natural gas for as long as these forms of energy are needed, while exploring lower-carbon energy sources that are an economic and synergistic fit. Sustainability strategy is integrated into this model using three pillars: Climate (discussed below), Conservation and Community (see our Sustainability Report).

Climate Strategy

Due to uncertainties in policy, regulations, carbon taxation, technology development, geopolitics, methane reduction alternatives and costs, and carbon accounting changes, this strategy is dynamic, with annual data updates and comprehensive reviews every three to five years to adapt to evolving economic, technological, legal and regulatory landscapes. We are focused first on emission intensity reduction, integrating emissions considerations into acquisitions and divestments, and fostering research and development partnerships to support energy alternatives. This includes validating capital and carbon abatement costs in key business units, monitoring government and regulatory requirements and support for energy alternatives bearing higher economic risks, such as carbon capture and storage and hydrogen production, and implementing centralized emissions quantification for improved tracking and forecasting.

Our climate strategy includes four pillars:

Pillar	Focus	Estimated Contribution	2024-2030 Approach
Reduce	Reduce emissions⁽¹⁾ with methane a priority, by ● Reducing flaring, venting and fugitive emissions ● Driving operational and energy efficiencies ● Electrifying operations if economical where grids are low-intensity ● Assessing new technologies as they become feasible	35-40% by 2040	Achieve our emission-related targets compared to our baseline of 2019: ● 2025: Scope 1 emissions intensity reduction by 15-20% ● 2030: Scope 1+2 emissions intensity reduction by 25-30%
Calibrate	Calibrate our portfolio by considering emission intensity impact in acquisition and divestment decisions, including planning for field end-of-life	10-20% by 2040	Use acquisitions and divestments to impact achieving our targets, not our 2019 baseline. If we divest higher emitting assets or acquire lower emitting assets, this will reduce our intensity. If we divest lower emitting assets or acquire higher emitting assets, this will increase our intensity, and we will need to consider projected costs of emissions reductions in our financial decisions.
Adapt	Adapt our portfolio to new energy, considering carbon capture and storage, renewable energy associated with our core operations such as biogas, hydrogen and geothermal production, and other new technologies, often via partnerships	35-45% by 2050	Evaluate early-stage alternative projects through partnerships, including: ● Four existing geothermal energy from produced water projects in France ● Biogas production at our Harlingen Treatment Centre site in Netherlands ● Evaluating hydrogen production potential in France and Ireland, with potential for associated carbon capture and storage in France
Offset	Offset as a solution for the emissions that cannot be eliminated	10-15% by 2050	Consider in 2030-2050, when carbon markets are less volatile

⁽¹⁾

Emissions calculated in general accordance with the GHG Protocol and IPCC guidance; reported intensities are based on operated throughput; Scope 1 and 2 emissions externally verified (limited assurance) in accordance with the ISO 14064-3 standard; see also Targets and Metrics section for methodologies and dependencies in target setting.

Vermilion Energy Inc. ■ Page 33 ■ 2025 Management’s Discussion and Analysis

Sustainability and Climate-Related Risk Management

Process for Identifying, Assessing and Managing Sustainability- and Climate-related Risks, and Integration into the Company’s Enterprise Risk Management (ERM) System

Sustainability and climate-related risks and opportunities are integrated into multi-disciplinary Company-wide risk identification, assessment, and management processes as part of our ERM system. This is based on the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework, covering Operational, Market & Financial, Credit, Organizational, Political, Regulatory Compliance, Strategic and Reputational, and Sustainability categories. Risk management follows a Top-Down, Bottom-Up approach: the Board and its committees set clear terms of reference, including oversight for specific allocations of risk type. Our Executive Committee reviews and manages the ERM process by implementing associated policies and procedures; the Vice President International and HSE and the Vice President North America have operational risk management responsibility, while the Chief Financial Officer is responsible for overseeing risk management performance. Bottom-Up is how staff implement, maintain and improve risk management processes, applying the hazard-risk-mitigation process in every part of our business.

Key staff from various departments identify risks using diverse inputs, including operational and facility assessments, technical and research reports, external stakeholder organizations, government policy and regulation changes, industry initiatives, communities and landowners, and non-governmental entities. They are recorded using our Corporate Risk Register, where risks are prioritized by severity, likelihood, speed of onset, and vulnerability considering human, environment, financial, social license and cybersecurity impacts. In addition, risks such as commodity pricing, production and carbon taxes are stress-tested to identify the impact of changes over time. Every risk case includes whether climate-related risk is a contributing factor.

Risk assessments are reviewed annually by the responsible teams and escalated to the Executive Committee and the Board for evaluation including interdependencies and alignment with risk tolerance. The approach focuses on reducing risks to as low as reasonably practicable, and/or accepting or controlling risks (e.g., insurance). Adaption measures are used when direct mitigation is not feasible, such as changing work hours to avoid extreme mid-day heat or implementing flood controls.

To support climate risk management, we use our internally developed Emissions Long-Range Planning Tool, which forecasts emissions, carbon taxes and the impact of emission reduction projects, aiding decisions on production, capital allocation, budgeting, and strategic transactions.

Sustainability and Climate-Related Metrics and Targets

Metrics Used to Assess Sustainability- and Climate-Related Risks and Opportunities

Our sustainability reporting describes significant economic, environmental, social and governance measures, which are reported with reference to TCFD, SASB and GRI. These include but are not limited to:

●

Climate: energy consumption and intensity; investment in and generation of renewable energy; greenhouse gas emission and intensity, including flaring and venting, and avoided emissions; and water withdrawal, including from areas of high baseline water stress, and discharge.

●

Environment: Waste generation and management; Asset integrity and spills; and Environmental investment

●

Social: Health and Safety; People; and Community investment

●

Governance: Ethics

These metrics contribute to the 10% sustainability contribution to the Corporate Performance Scorecard for our Long-term Incentive Plan via ESG rating scores, along with emission intensity reduction and ARO liability reduction; as of 2025, the rating agency scores have been eliminated, relying instead on progress on emissions intensity and ARO liability.

We also track carbon pricing, identifying actual and likely pricing scenarios based on current and projected government policies.

Vermilion Energy Inc. ■ Page 34 ■ 2025 Management’s Discussion and Analysis

Scope 1 and 2 GHG Emissions Disclosure

We report Scope 1 and 2 emissions, calculated in general accordance with the GHG Protocol and IPCC guidance and externally verified (limited assurance) in accordance with ISO 14064-3; reported intensities are based on operated throughput. We have adopted the definitions of Scope 1 and 2 emissions as developed by the GHG Protocol, an international standard for corporate accounting and reporting emissions from the World Resources Institute and the World Business Council for Sustainable Development:

●

Scope 1 refers to direct GHG emissions from sources that are owned or controlled by a company

●

Scope 2 refers to indirect GHG emissions from the generation of purchased electricity consumed by a company

Historical, corporate and business unit data can be found in the Energy and Emissions Performance Metric document available at www.vermilionenergy.com/our-sustainability. A summary is included below. Note that 2025 data will be available in Q2 2026.

Related Targets and Performance

Vermilion has one active emission intensity reduction target:

●

In 2021, we set a target to reduce Scope 1 emissions intensity by 15 to 20% by 2025, using a baseline year of 2019.

o

Retired: approximately 16% reduction achieved at end 2024; given the changes to our operational structure in 2025, we are focusing on evaluating the emission profile of our new assets and looking ahead to 2030

●

In 2024, we set a target to reduce Scope 1+2 emissions intensity by 25 to 30% by 2030, using a baseline year of 2019.

o

On track: approximately 27% reduction achieved at end 2024

Our targets were developed, and Board-approved, following our climate scenario analysis and extensive internal assessment. To set targets, we assessed opportunities for economic emission reduction based on cost/tonne CO2e, and the approach from peers and majors. Overall, we are focusing on business units with higher emissions intensities, prioritizing capital efficiency: process changes, venting reductions, instrumentation upgrades from gas to air, converting pneumatic devices from high- to low-bleed, power efficiency options, infrastructure consolidation, solar-powered chemical injection pumps, micro-turbine installation, along with improved metering and field measurements. Additional decreases have been achieved through improved measurement and emission calculation methodologies, and the purchase of renewable energy certificates for electricity use in Netherlands, Germany and Ireland.

Corporate Governance

We are committed to a high standard of corporate governance practices, a dedication that begins at the Board level and extends throughout the Company. We believe good corporate governance is in the best interest of our shareholders, and that successful companies are those that deliver growth and a competitive return along with a commitment to the environment, to the communities where they operate, and to their employees.

We comply with the objectives and guidelines relating to corporate governance adopted by the Canadian Securities Administrators and the Toronto Stock Exchange ("TSX"). In addition, the Board monitors and considers the implementation of corporate governance standards proposed by various regulatory and non-regulatory authorities in Canada. A discussion of corporate governance policies is included each year in our proxy materials for our annual general meeting of shareholders, copies of which are available on SEDAR+ (www.sedarplus.ca).

Vermilion Energy Inc. ■ Page 35 ■ 2025 Management’s Discussion and Analysis

As a Canadian reporting issuer with securities listed on the TSX and the New York Stock Exchange (“NYSE”), Vermilion is required to comply with all applicable Canadian requirements adopted by the Canadian Securities Administrators and the TSX, and applicable rules for foreign private issuers adopted by the U.S. Securities and Exchange Commission that give effect to the provisions of the Sarbanes-Oxley Act of 2002.

Our corporate governance practices also incorporate many “best practices” derived from those required to be followed by US domestic companies under the NYSE listing standards. We are required by Section 303A.11 of the NYSE Listed Company Manual to identify any significant ways in which our corporate governance practices differ from those required to be followed by US domestic companies under NYSE listing standards. We believe that there are no such significant differences in our corporate governance practices, except as follows:

●

Shareholder Approval of Equity Compensation Plans. Section 303A.8 of the NYSE Listed Company Manual requires shareholder approval of all “equity compensation plans” and material revisions to those plans. The definition of “equity compensation plans” covers plans that provide for the delivery of newly issued securities, and also plans which rely on securities reacquired on the market by the issuing company for the purpose of redistribution to employees and directors. The TSX rules provide that equity compensation plans and material amendments thereto require shareholder approval only if they involve newly issued securities and the amendments are not otherwise addressed in the plan’s amendment procedures. In addition, the TSX rules require that every three years after institution, all unallocated options, rights or other entitlements under equity compensation plans which do not have a fixed maximum aggregate of securities issuable must be approved by shareholders. Vermilion follows the TSX rules with respect to equity compensation plan shareholder approval requirements.

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 December 31, 2025, 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.

Internal Control Over Financial Reporting

A company's internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

The Chief Executive Officer and the Chief Financial Officer of Vermilion have assessed the effectiveness of Vermilion’s internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings ("NI 52 - 109"). The assessment was based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Chief Executive Officer and the Chief Financial Officer of Vermilion have concluded that Vermilion’s internal control over financial reporting was effective as of December 31, 2025. The effectiveness of Vermilion’s internal control over financial reporting as of December 31, 2025 has been audited by Deloitte LLP, as reflected in their report included in the 2025 audited annual financial statements filed with the US Securities and Exchange Commission. No changes were made to Vermilion’s internal control over financial reporting during the three months ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Vermilion has limited the scope of design controls and procedures ("DC&P") and internal controls over financial reporting to exclude controls, policies

and procedures of Westbrick Energy Ltd., which was acquired on February 26, 2025. The scope limitation is in accordance with section 3.3(1)(b) of NI 52-109, which allows an issuer to limit the design of DC&P and ICFR to exclude controls, policies, and procedures of a business that the issuer acquired not more than 365 days before the end of the fiscal period.

The table below presents the summary financial information of Westbrick Energy Ltd. included in Vermilion's financial statements as at and for the year ended December 31, 2025:


($M)		Balance at December 31, 2025
Non-current assets		1,171,078
Non-current liabilities		(185,437)
Net assets		985,641

Vermilion Energy Inc. ■ Page 36 ■ 2025 Management’s Discussion and Analysis


($M)		Q4 2025		2025
Revenue		104,904		326,797
Net (loss) earnings		18,446		26,739

Supplemental Table 1: Operating 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.


				Q4 2025					2025		Q4 2024	2024
		Liquids		Natural Gas		Total		Liquids	Natural Gas	Total	Total	Total
		$/bbl		$/mcf		$/boe		$/bbl	$/mcf	$/boe	$/boe	$/boe
Continuing Operations
Canada
Sales		51.46		2.60		25.75		57.49	2.21	25.85	30.81	30.10
Royalties		(5.42)		(0.14)		(2.14)		(5.83)	(0.11)	(2.14)	(1.96)	(2.85)
Transportation		(5.20)		(0.27)		(2.66)		(5.07)	(0.32)	(2.84)	(3.42)	(3.12)
Operating		(12.97)		(0.65)		(6.49)		(15.89)	(0.62)	(7.19)	(11.10)	(10.58)
Operating netback		27.87		1.54		14.46		30.70	1.16	13.68	14.33	13.55
General and administration ⁽¹⁾						(1.17)				(1.55)	(0.99)	(0.81)
Corporate income taxes ($/boe)						0.06				(0.15)	0.60	0.10
Fund flows from operations ($/boe)						13.35				11.98	13.94	12.84

France
Sales		86.99		—		86.99		92.03	—	92.03	109.14	110.89
Royalties		(13.06)		—		(13.06)		(13.46)	—	(13.46)	(14.38)	(14.68)
Transportation		(10.08)		—		(10.08)		(9.38)	—	(9.38)	(8.34)	(8.15)
Operating		(26.65)		—		(26.65)		(26.88)	—	(26.88)	(27.54)	(24.48)
Operating netback		37.20		—		37.20		42.31	—	42.31	58.88	63.58
General and administration						(6.01)				(5.68)	(6.88)	(6.43)
Current income taxes						(0.02)				0.12	2.77	(4.31)
Fund flows from operations ($/boe)						31.17				36.75	54.77	52.84

Netherlands
Sales		62.94		15.72		94.01		74.31	15.76	94.37	105.54	83.91
Royalties		—		—		—		—	—	(0.01)	(0.07)	(0.15)
Operating		(29.89)		(5.27)		(31.59)		(30.18)	(4.59)	(27.59)	(31.77)	(24.77)
Operating netback		33.05		10.45		62.42		44.13	11.17	66.77	73.70	58.99
General and administration						(5.00)				(3.83)	(6.88)	(5.02)
Current income taxes						1.82				(9.45)	(23.26)	(19.63)
Fund flows from operations ($/boe)						59.24				53.49	43.56	34.34

Germany
Sales		83.09		13.20		80.31		91.24	15.13	90.91	98.28	85.45
Royalties		(2.91)		(0.89)		(4.63)		(2.43)	(1.02)	(5.03)	(3.32)	(3.25)
Transportation		(11.91)		(0.75)		(6.62)		(13.50)	(0.66)	(6.77)	(6.50)	(6.76)
Operating		(32.46)		(5.10)		(31.14)		(26.86)	(4.55)	(27.18)	(28.74)	(30.32)
Operating netback		35.81		6.46		37.92		48.45	8.90	51.93	59.72	45.12
General and administration						(6.87)				(6.49)	(9.33)	(7.45)
Current income taxes						15.16				(0.49)	(21.38)	(10.59)
Fund flows from operations ($/boe)						46.21				44.95	29.01	27.08

Ireland
Sales		—		13.65		81.91		—	16.40	98.42	115.22	87.84
Transportation		—		(0.60)		(3.57)		—	(0.52)	(3.14)	(0.76)	(2.38)
Operating		—		(3.30)		(19.80)		—	(3.08)	(18.51)	(15.90)	(15.29)
Operating netback		—		9.75		58.54		—	12.80	76.77	98.56	70.17
General and administration						(2.97)				(2.24)	(2.00)	(2.27)
Current income taxes						(0.83)				(0.43)	(0.54)	(0.40)
Fund flows from operations ($/boe)						54.74				74.10	96.02	67.50

Vermilion Energy Inc. ■ Page 37 ■ 2025 Management’s Discussion and Analysis


				Q4 2025						2025				Q4 2024		2024
		Liquids		Natural Gas		Total		Liquids		Natural Gas		Total		Total		Total
		$/bbl		$/mcf		$/boe		$/bbl		$/mcf		$/boe		$/boe		$/boe
Australia
Sales		99.27		—		99.27		110.63		—		110.63		121.24		128.92
Operating		(58.29)		—		(58.29)		(59.32)		—		(59.32)		(47.78)		(56.65)
PRRT ⁽²⁾		38.14		—		38.14		2.57		—		2.57		14.19		(8.25)
Operating netback		79.12		—		79.12		53.88		—		53.88		87.65		64.02
General and administration						(8.75)						(5.54)		(10.01)		(5.70)
Current income taxes						0.13						(0.66)		(3.05)		(2.13)
Fund flows from operations ($/boe)						70.50						47.68		74.59		56.19

Central and Eastern Europe
Sales		21.66		14.32		85.80		57.38		16.73		100.30		102.86		98.08
Royalties		—		(2.36)		(14.12)		(1.37)		(2.70)		(16.17)		(20.84)		(17.41)
Operating		—		(1.05)		(6.31)		—		(0.98)		(5.88)		(5.96)		(7.09)
Operating netback		21.66		10.91		65.37		56.01		13.05		78.25		76.06		73.58
General and administration						(8.41)						(8.14)		(9.39)		(20.17)
Current income taxes						(7.14)						(8.97)		0.04		0.02
Fund flows from operations ($/boe)						49.82						61.14		66.71		53.43

Discontinued Operations
United States
Sales		86.60		8.34		76.76		78.32		3.19		65.02		65.34		70.03
Royalties		(30.28)		6.23		(12.07)		(22.14)		(0.83)		(18.28)		(19.56)		(20.29)
Transportation		(7.83)		—		(5.73)		(0.87)		—		(0.67)		(0.35)		(0.75)
Operating		(3.18)		(0.29)		(2.79)		(20.32)		(0.88)		(16.94)		(15.70)		(13.69)
Operating netback		45.31		14.28		56.17		34.99		1.48		29.13		29.73		35.30
General and administration						(85.58)						(6.48)		(9.62)		(6.87)
Fund flows from operations ($/boe)						(29.41)						22.65		20.11		28.43

Canada - Saskatchewan
Sales		82.77		(0.48)		75.99		82.92		1.86		72.09		73.75		76.61
Royalties		(31.66)		—		(29.16)		(14.31)		1.13		(11.13)		(11.38)		(11.64)
Transportation		(0.25)		—		(0.23)		(3.38)		(0.27)		(3.12)		(2.77)		(2.89)
Operating		47.05		(0.48)		43.16		(24.07)		(0.46)		(20.86)		(27.16)		(24.44)
Operating netback		97.91		(0.96)		89.76		41.16		2.26		36.98		32.44		37.64
General and administration						—						(6.88)		(3.23)		(3.09)
Fund flows from operations ($/boe)						89.76						30.10		29.21		34.55

Total Company
Sales		63.43		5.13		40.99		72.53		5.38		46.42		66.54		63.58
Realized hedging gain		1.11		0.37		1.88		2.21		0.63		3.24		3.80		11.08
Royalties		(6.56)		(0.21)		(2.91)		(8.27)		(0.19)		(3.65)		(5.28)		(5.71)
Transportation		(6.17)		(0.32)		(3.23)		(5.37)		(0.34)		(3.20)		(3.16)		(3.17)
Operating		(18.21)		(1.50)		(11.86)		(20.33)		(1.50)		(12.97)		(18.41)		(18.22)
PRRT⁽²⁾		2.39		—		0.75		0.19		—		0.07		0.43		(0.38)
Operating netback		35.99		3.47		25.62		40.96		3.98		29.91		43.92		47.18
General and administration						(2.34)						(2.71)		(3.62)		(3.19)
Interest expense						(2.47)						(3.03)		(3.16)		(2.71)
Equity based compensation						(0.06)						(0.14)		—		(0.46)
Realized foreign exchange gain						0.01						0.03		0.32		0.25
Realized other expense						(0.08)						(0.36)		(0.68)		(0.23)
Corporate income taxes						0.79						(0.60)		(2.11)		(2.13)
Fund flows from operations ($/boe)						21.47						23.10		34.67		38.71

(1)	General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.

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

Vermilion Energy Inc. ■ Page 38 ■ 2025 Management’s Discussion and Analysis

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 December 31, 2025:


				Weighted		Weighted		Weighted		Weighted	Daily	Weighted
			Daily	Average	Daily	Average	Daily	Average	Daily	Average	Bought	Average
			Bought Put	Bought Put	Sold Call	Sold Call	Sold Put	Sold Put	Sold Swap	Sold Swap	Swap	Bought Swap
	Unit	Currency	Volume	Price	Volume	Price	Volume	Price	Volume	Price	Volume	Price
AECO
Q1 2026	mcf	CAD	78,195	2.81	78,195	4.33	—	—	120,847	3.38	—	—
Q2 2026	mcf	CAD	4,739	3.17	4,739	4.22	—	—	132,694	3.30	—	—
Q3 2026	mcf	CAD	4,739	3.17	4,739	4.22	—	—	132,694	3.30	—	—
Q4 2026	mcf	CAD	26,735	2.95	26,735	4.74	—	—	107,557	3.33	—	—
Q1 2027	mcf	CAD	33,174	2.90	33,174	4.85	—	—	99,521	3.16	—	—
Q2 2027	mcf	CAD	—	—	—	—	—	—	90,043	3.13	—	—
Q3 2027	mcf	CAD	—	—	—	—	—	—	90,043	3.13	—	—
Q4 2027	mcf	CAD	12,569	2.64	12,569	4.96	—	—	90,043	3.13	—	—
Q1 2028	mcf	CAD	18,956	2.64	18,956	4.96	—	—	—	—	—	—
NYMEX Henry Hub
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	—	—	—	—	—	—
Q1 2027	mcf	USD	—	—	—	—	—	—	24,000	3.76	—	—
Q2 2027	mcf	USD	—	—	—	—	—	—	24,000	3.76	—	—
Q3 2027	mcf	USD	—	—	—	—	—	—	24,000	3.76	—	—
Q4 2027	mcf	USD	—	—	—	—	—	—	24,000	3.76	—	—
Q1 2028	mcf	USD	—	—	24,000	6.29	—	—	—	—	—	—
Q2 2028	mcf	USD	—	—	24,000	6.29	—	—	—	—	—	—
Q3 2028	mcf	USD	—	—	24,000	6.29	—	—	—	—	—	—
Q4 2028	mcf	USD	—	—	24,000	6.29	—	—	—	—	—	—


																	Weighted
							Weighted		Daily		Weighted		Weighted		Weighted	Daily	Average
					Daily		Average		Sold		Average	Daily	Average	Daily	Average	Bought	Bought
					Bought Put		Bought Put		Call		Sold Call	Sold Put	Sold Put	Sold Swap	Sold Swap	Swap	Swap
	Unit		Currency		Volume		Price		Volume		Price	Volume	Price	Volume	Price	Volume	Price
TTF
Q1 2026	mcf		EUR		36,851		7.86		24,567		11.66	36,851	3.97	11,055	10.47	—	—
Q2 2026	mcf		EUR		24,567		7.39		24,567		11.66	24,567	3.02	20,882	9.77	—	—
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	12,284	8.91	—	—
Q1 2027	mcf		EUR		28,253		7.43		28,253		11.66	28,253	2.93	9,827	9.87	—	—
Q2 2027	mcf		EUR		—		—		—		—	—	—	18,153	9.09	—	—
Q3 2027	mcf		EUR		—		—		—		—	—	—	18,153	9.09	—	—
Q4 2027	mcf		EUR		—		—		—		—	—	—	18,153	9.09	—	—
Buy TTF, Sell THE Basis
Q1 2026	mcf		EUR		—		—		—		—	—	—	10,236	1.15	—	—
WTI
Q1 2026	bbl		USD		11,500		60.42		13,000		67.93	11,500	48.63	1,500	62.76	500	62.27
Q2 2026	bbl		USD		11,000		62.73		12,000		70.14	11,000	50.70	2,000	62.00	500	62.27
Q3 2026	bbl		USD		9,000		62.89		9,000		71.19	9,000	50.42	—	—	—	—
Q4 2026	bbl		USD		9,000		62.89		9,000		71.19	9,000	50.42	—	—	—	—
C5-WTI Differential
Q1 2026	bbl		USD		—		—		—		—	—	—	2,000	0.05	—	—
Q2 2026	bbl		USD		—		—		—		—	—	—	659	0.05	—	—
Conway
Q1 2026	bbl		USD		—		—		—		—	—	—	1,000	31.13	—	—
Q2 2026	bbl		USD		—		—		—		—	—	—	1,000	31.13	—	—

Vermilion Energy Inc. ■ Page 39 ■ 2025 Management’s Discussion and Analysis


VET Equity Swaps				Initial Share Price		Share Volume
Swap		Jan 2020 - Apr 2027		20.9788	CAD	2,250,000
Swap		Jan 2020 - Jul 2027		22.4587	CAD	1,500,000

Weighted

Monthly Sold

Weighted

Monthly Sold

Weighted

Foreign

Monthly Bought

Average Bought

Call

Average Sold

Swap

Average Sold

Exchange

Period

Put Amount

Put Price

Amount

Call Price

Amount

Swap Price

Collar

Sell USD, Buy CAD

Jan - Jun 2026

11,000,000

USD

1.3500

11,000,000

USD

1.4403

—

Collar

Sell USD, Buy CAD

Jan - Dec 2026

2,000,000

USD

1.3500

2,000,000

USD

1.4355

—

Cross Currency Interest Rate

 

Receive Notional Amount

 

Receive Rate

 

Pay Notional Amount

 

Pay Rate

Swap

Feb 2033

250,000,000

USD

7.250

357,870,000

CAD

6.099

Swap

Dec 2025 - Jan 2026

143,075,837

USD

SOFR + 2.350

200,000,000

CAD

CORRA + 2.206

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:


										Weighted				Weighted				Weighted				Weighted
								Daily		Average				Average				Average		Daily Sold		Average
						Option Expiration		Bought Put		Bought Put		Daily Sold		Sold Call		Daily Sold		Sold Put		Swap		Sold Swap
Period if Option Exercised		Unit		Currency		Date		Volume		Price		Call Volume		Price		Put Volume		Price		Volume		Price
WTI
Jul 2026 - Dec 2026		bbl		USD		30-Jun-2026		—		—		—		—		—		—		1,000		70.00
Jul 2026 - Jun 2027		bbl		USD		30-Jun-2026		—		—		—		—		—		—		2,000		70.00
Jan 2027 - Dec 2027		bbl		USD		30-Sep-2026		—		—		—		—		—		—		1,000		70.00
TTF
Apr 2026 - Dec 2026		mcf		EUR		31-Mar-2026		—		—		—		—		—		—		4,913		8.79
Jan 2027 - Dec 2027		mcf		EUR		30-Jun-2026		—		—		—		—		—		—		2,457		10.26
Jan 2027 - Dec 2027		mcf		EUR		31-Dec-2026		—		—		—		—		—		—		4,913		10.26
Apr 2027 - Dec 2027		mcf		EUR		30-Sep-2026		—		—		—		—		—		—		4,913		10.26
Jan 2028 - Dec 2028		mcf		EUR		30-Sep-2027		—		—		—		—		—		—		4,913		8.79
Jan 2028 - Dec 2028		mcf		EUR		24-Dec-2027		—		—		—		—		—		—		4,913		8.79

Supplemental Table 3: Capital Expenditures and Acquisitions


By classification ($M)		Q4 2025		Q4 2024		2025		2024
Drilling and development		193,757		176,505		617,250		586,962
Exploration and evaluation		(2,005)		24,154		17,672		36,018
Capital expenditures		191,752		200,659		634,922		622,980


Acquisitions ($M)		Q4 2025		Q4 2024		2025		2024
Acquisitions, net of cash acquired		1,646		5,257		1,088,761		12,728
Shares issued for acquisition		—		—		13,363		—
Acquisition of securities		—		—		—		9,373
Acquired working capital deficit		—		—		23,179		—
Acquisitions		1,646		5,257		1,125,303		22,101


Dispositions ($M)		Q4 2025		Q4 2024		2025		2024
Canada		—		—		392,619		—
United States		—		—		90,906		—
Disposition of securities		41,782		—		41,782		—
Dispositions		41,782		—		525,307		—

Vermilion Energy Inc. ■ Page 40 ■ 2025 Management’s Discussion and Analysis


By category ($M)		Q4 2025		Q4 2024		2025		2024
Drilling, completion, new well equip and tie-in, workovers and recompletions		97,050		134,813		384,741		392,986
Production equipment and facilities		83,402		56,747		220,393		206,997
Seismic, studies, land and other		11,300		9,099		29,788		22,997
Capital expenditures		191,752		200,659		634,922		622,980
Acquisitions		1,646		5,257		1,125,303		22,101
Total capital expenditures and acquisitions		193,398		205,916		1,760,225		645,081


Capital expenditures by country ($M)		Q4 2025		Q4 2024		2025		2024
Canada		134,523		85,682		392,179		301,651
France		14,517		11,901		42,138		45,671
Netherlands		13,913		12,037		54,954		25,905
Germany		17,136		33,191		72,684		94,588
Ireland		803		561		2,975		4,355
Australia		8,896		5,643		38,241		29,284
Central and Eastern Europe		2,525		3,162		10,703		12,813
Capital expenditures on continuing operations		192,313		152,177		613,874		514,267

Canada		—		28,922		6,724		73,241
United States		(561)		19,560		14,324		35,472
Capital expenditures on discontinued operations		(561)		48,482		21,048		108,713
Capital expenditures		191,752		200,659		634,922		622,980


Acquisitions by country ($M)		Q4 2025		Q4 2024		2025		2024
Canada		1,646		5,257		1,125,303		22,101
Acquisitions		1,646		5,257		1,125,303		22,101

Vermilion Energy Inc. ■ Page 41 ■ 2025 Management’s Discussion and Analysis

Supplemental Table 4: Production


		Q4/25		Q3/25		Q2/25		Q1/25		Q4/24		Q3/24		Q2/24		Q1/24		Q4/23		Q3/23		Q2/23		Q1/23
Continuing Operations
Canada
Light and medium crude oil (bbls/d)		5,494		6,092		5,812		4,136		4,102		4,843		4,288		3,252		3,294		3,572		869		2,768
Condensate ⁽¹⁾ (bbls/d)		8,230		7,804		8,366		5,768		3,546		3,338		3,595		3,815		3,696		4,046		3,194		4,459
Other NGLs ⁽¹⁾ (bbls/d)		12,099		10,579		11,072		7,695		4,980		5,715		5,374		5,200		5,390		5,333		4,215		5,871
NGLs (bbls/d)		20,329		18,383		19,438		13,463		8,526		9,053		8,969		9,015		9,086		9,379		7,409		10,330
Conventional natural gas (mmcf/d)		391.39		367.34		394.06		249.02		151.64		148.38		148.37		140.93		148.20		150.97		141.80		148.30
Total (boe/d)		91,053		85,698		90,926		59,104		37,898		38,625		37,987		35,753		37,081		38,113		31,912		37,813

France
Light and medium crude oil (bbls/d)		6,985		6,811		6,827		6,810		7,083		7,115		7,246		7,308		7,395		7,578		7,788		7,578
Total (boe/d)		6,985		6,811		6,827		6,810		7,083		7,115		7,246		7,308		7,395		7,578		7,788		7,578

Netherlands
Condensate ⁽¹⁾ (bbls/d)		45		27		35		34		44		39		51		165		119		39		61		66
NGLs (bbls/d)		45		27		35		34		44		39		51		165		119		39		61		66
Conventional natural gas (mmcf/d)		25.20		20.12		22.25		23.91		24.20		25.06		26.84		31.02		32.06		24.32		27.28		29.07
Total (boe/d)		4,245		3,381		3,744		4,020		4,078		4,216		4,524		5,336		5,462		4,091		4,607		4,910

Germany
Light and medium crude oil (bbls/d)		1,650		1,717		1,731		1,512		1,596		1,598		1,698		1,722		1,775		1,713		1,715		1,410
Conventional natural gas (mmcf/d)		28.61		26.21		25.49		21.05		21.71		21.41		18.41		22.87		19.62		20.29		22.05		25.85
Total (boe/d)		6,419		6,086		5,979		5,020		5,215		5,167		4,766		5,533		5,046		5,095		5,391		5,717

Ireland
Conventional natural gas (mmcf/d)		47.04		48.83		47.75		52.92		55.32		59.06		57.70		60.34		64.04		47.96		67.51		24.58
Total (boe/d)		7,840		8,139		7,959		8,820		9,220		9,844		9,616		10,057		10,673		7,993		11,251		4,096

Australia
Light and medium crude oil (bbls/d)		2,941		3,693		3,460		3,477		3,778		2,040		3,713		4,264		4,715		1,204		—		—
Total (boe/d)		2,941		3,693		3,460		3,477		3,778		2,040		3,713		4,264		4,715		1,204		—		—

Central and Eastern Europe
Conventional natural gas (mmcf/d)		10.22		13.13		9.90		7.24		11.21		11.13		0.69		0.29		0.54		0.05		0.30		0.64
Total (boe/d)		1,707		2,189		1,654		1,208		1,869		1,855		122		48		90		8		50		107

Discontinued Operations
United States
Light and medium crude oil (bbls/d)		3		1,151		2,977		2,261		2,449		2,909		3,817		3,483		3,187		4,404		3,349		2,824
Condensate ⁽¹⁾ (bbls/d)		9		4		12		19		34		12		27		29		27		15		22		20
Other NGLs ⁽¹⁾ (bbls/d)		39		308		792		795		848		1,064		988		1,078		1,131		1,124		1,025		1,020
NGLs (bbls/d)		48		312		804		814		882		1,076		1,015		1,107		1,158		1,139		1,047		1,040
Conventional natural gas (mmcf/d)		0.11		2.83		5.83		5.78		5.88		7.08		7.27		8.23		7.49		7.25		7.23		7.14
Total (boe/d)		70		1,934		4,752		4,039		4,311		5,164		6,044		5,962		5,593		6,751		5,601		5,055

Canada - Saskatchewan
Light and medium crude oil (bbls/d)		44		862		7,961		8,039		7,512		7,682		8,180		8,397		8,320		8,482		12,032		13,906
Condensate ⁽¹⁾ (bbls/d)		—		36		266		328		182		260		258		260		338		364		312		260
Other NGLs ⁽¹⁾ (bbls/d)		1		98		792		677		784		768		834		768		891		887		1,298		1,004
NGLs (bbls/d)		1		134		1,058		1,005		966		1,028		1,092		1,028		1,229		1,251		1,610		1,264
Conventional natural gas (mmcf/d)		0.02		0.80		10.09		9.44		9.63		8.62		10.11		10.91		11.96		12.97		17.46		12.04
Total (boe/d)		48		1,131		10,701		10,617		10,084		10,147		10,956		11,244		11,542		11,894		16,552		17,178

Consolidated
Light and medium crude oil (bbls/d)		17,117		20,326		28,768		26,235		26,521		26,188		28,948		28,426		28,685		26,952		25,753		28,485
Condensate ⁽¹⁾ (bbls/d)		8,284		7,871		8,681		6,151		3,806		3,649		3,931		4,269		4,180		4,463		3,589		4,805
Other NGLs ⁽¹⁾ (bbls/d)		12,140		10,985		12,656		9,167		6,612		7,547		7,196		7,046		7,412		7,344		6,538		7,896
NGLs (bbls/d)		20,424		18,856		21,337		15,318		10,418		11,196		11,127		11,315		11,592		11,807		10,127		12,701
Conventional natural gas (mmcf/d)		502.60		479.28		515.38		369.36		279.59		280.73		269.39		274.59		283.91		263.80		283.63		247.61
Total (boe/d)		121,308		119,062		136,002		103,115		83,536		84,173		84,974		85,505		87,597		82,727		83,152		82,455

Vermilion Energy Inc. ■ Page 42 ■ 2025 Management’s Discussion and Analysis


		2025		2024		2023		2022		2021		2020
Continuing Operations
Canada
Light and medium crude oil (bbls/d)		5,389		4,124		558		2,713		2,136		2,809
Condensate ⁽¹⁾ (bbls/d)		7,550		3,573		3,761		4,280		4,475		4,515
Other NGLs ⁽¹⁾ (bbls/d)		10,374		5,317		4,981		5,772		5,857		6,150
NGLs (bbls/d)		17,924		8,890		8,742		10,052		10,332		10,665
Conventional natural gas (mmcf/d)		350.89		147.35		144.26		130.44		122.90		131.22
Total (boe/d)		81,794		37,570		33,344		34,505		32,951		35,345

France
Light and medium crude oil (bbls/d)		6,859		7,188		7,584		7,639		8,799		8,903
Total (boe/d)		6,859		7,188		7,584		7,639		8,799		8,903

Netherlands
Light and medium crude oil (bbls/d)		—		—		—		—		3		1
Condensate ⁽¹⁾ (bbls/d)		35		75		71		66		97		88
NGLs (bbls/d)		35		75		71		66		97		88
Conventional natural gas (mmcf/d)		22.87		26.77		28.18		32.66		43.40		46.16
Total (boe/d)		3,847		4,536		4,768		5,510		7,334		7,782

Germany
Light and medium crude oil (bbls/d)		1,653		1,653		1,654		1,435		1,044		968
Conventional natural gas (mmcf/d)		25.36		21.10		21.93		26.18		15.81		12.65
Total (boe/d)		5,880		5,170		5,310		5,798		3,679		3,076

Ireland
Conventional natural gas (mmcf/d)		49.12		58.10		51.12		27.48		29.25		37.44
Total (boe/d)		8,187		9,683		8,520		4,579		4,875		6,240

		YTD 2025		2024		2023		2022		2021		2020
Australia
Light and medium crude oil (bbls/d)		3,392		3,446		1,492		3,995		3,810		4,416
Total (boe/d)		3,392		3,446		1,492		3,995		3,810		4,416

Central and Eastern Europe
Conventional natural gas (mmcf/d)		10.14		5.86		0.38		0.57		0.31		1.90
Total (boe/d)		1,692		978		63		95		51		317

Discontinued Operations
United States
Light and medium crude oil (bbls/d)		1,591		3,162		3,445		2,908		2,597		3,046
Condensate ⁽¹⁾ (bbls/d)		11		25		21		34		8		5
Other NGLs ⁽¹⁾ (bbls/d)		481		994		1,076		1,066		1,146		1,218
NGLs (bbls/d)		492		1,019		1,097		1,100		1,154		1,223
Conventional natural gas (mmcf/d)		3.62		7.11		7.28		7.20		6.84		7.47
Total (boe/d)		2,686		5,367		5,754		5,207		4,890		5,514

Canada - Saskatchewan
Light and medium crude oil (bbls/d)		4,195		7,941		12,735		14,117		14,818		18,297
Condensate ⁽¹⁾ (bbls/d)		156		240		405		341		356		371
Other NGLs ⁽¹⁾ (bbls/d)		389		789		1,239		1,123		1,322		1,569
NGLs (bbls/d)		545		1,029		1,644		1,464		1,678		1,940
Conventional natural gas (mmcf/d)		5.05		9.81		16.68		13.66		15.13		20.16
Total (boe/d)		5,582		10,605		17,159		17,859		19,017		23,597

Consolidated
Light and medium crude oil (bbls/d)		23,079		27,514		27,469		32,809		33,208		38,441
Condensate ⁽¹⁾ (bbls/d)		7,753		3,913		4,258		4,721		4,936		4,980
Other NGLs ⁽¹⁾ (bbls/d)		11,244		7,100		7,296		7,961		8,325		8,937
NGLs (bbls/d)		18,997		11,013		11,554		12,682		13,261		13,917
Conventional natural gas (mmcf/d)		467.06		276.10		269.83		238.18		233.64		256.99
Total (boe/d)		119,919		84,543		83,994		85,187		85,408		95,190

(1)

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. This table provides a reconciliation from "crude oil and condensate", "NGLs" and "natural gas" to the product types. 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". Production volumes reported are based on quantities as measured at the first point of sale.

Vermilion Energy Inc. ■ Page 43 ■ 2025 Management’s Discussion and Analysis

Supplemental Table 5: Segmented Financial Results


		Three Months Ended December 31, 2025
																		Continuing		Discontinued
($M)		Canada		France		Netherlands		Germany		Ireland		Australia		CEE		Corporate		operations		operations ⁽¹⁾		Total
Drilling and development		134,523		14,517		13,913		19,291		803		8,896		2,375		—		194,318		(561)		193,757
Exploration and evaluation		—		—		—		(2,155)		—		—		150		—		(2,005)		—		(2,005)

Crude oil and condensate sales		98,885		62,441		259		14,730		—		21,838		6		—		198,159		457		198,616
NGL sales		23,364		—		—		—		—		—		—		—		23,364		284		23,648
Natural gas sales		93,458		—		36,456		34,738		59,079		—		13,468		—		237,199		86		237,285
Sales of purchased commodities		—		—		—		—		—		—		—		3,731		3,731		—		3,731
Royalties		(17,923)		(9,372)		—		(2,855)		—		—		(2,217)		—		(32,367)		(205)		(32,572)
Revenue from external customers		197,784		53,069		36,715		46,613		59,079		21,838		11,257		3,731		430,086		622		430,708
Purchased commodities		—		—		—		—		—		—		—		(3,731)		(3,731)		—		(3,731)
Transportation		(22,286)		(7,236)		—		(4,080)		(2,576)		—		—		—		(36,178)		(38)		(36,216)
Operating		(54,385)		(19,131)		(12,338)		(19,180)		(14,285)		(12,823)		(991)		—		(133,133)		170		(132,963)
General and administration ⁽²⁾		(42,270)		(4,312)		(1,952)		(4,234)		(2,141)		(1,924)		(1,321)		32,456		(25,698)		(553)		(26,251)
Petroleum resource rent tax		—		—		—		—		—		8,391		—		—		8,391		—		8,391
Corporate income tax (expense) recovery		(1)		(14)		710		9,339		(600)		29		(1,121)		465		8,807		—		8,807
Interest expense		—		—		—		—		—		—		—		(27,670)		(27,670)		—		(27,670)
Equity based compensation		—		—		—		—		—		—		—		(627)		(627)		—		(627)
Realized gain on derivative instruments		—		—		—		—		—		—		—		21,037		21,037		—		21,037
Realized foreign exchange gain		—		—		—		—		—		—		—		93		93		—		93
Realized other expense		—		—		—		—		—		—		—		(844)		(844)		—		(844)
Fund flows from operations		78,842		22,376		23,135		28,458		39,477		15,511		7,824		24,910		240,533		201		240,734


		Year Ended December 31, 2025
																		Continuing		Discontinued
($M)		Canada		France		Netherlands		Germany		Ireland		Australia		CEE		Corporate		operations		operations ⁽¹⁾		Total
Total assets		2,708,214		386,041		136,136		553,048		491,483		128,300		82,112		858,886		5,344,220		—		5,344,220
Drilling and development		392,179		42,138		54,954		57,529		2,975		38,241		8,186		—		596,202		21,048		617,250
Exploration and evaluation		—		—		—		15,155		—		—		2,517		—		17,672		—		17,672

Crude oil and condensate sales		400,506		234,567		953		58,482		53		127,278		42		—		821,881		190,319		1,012,200
NGL sales		88,663		—		—		—		—		—		—		—		88,663		12,681		101,344
Natural gas sales		282,633		—		131,551		140,049		294,056		—		61,918		—		910,207		7,643		917,850
Sales of purchased commodities		—		—		—		—		—		—		—		63,514		63,514		—		63,514
Royalties		(63,834)		(34,301)		(10)		(10,990)		—		—		(9,989)		—		(119,124)		(40,591)		(159,715)
Revenue from external customers		707,968		200,266		132,494		187,541		294,109		127,278		51,971		63,514		1,765,141		170,052		1,935,193
Purchased commodities		—		—		—		—		—		—		—		(63,514)		(63,514)		—		(63,514)
Transportation		(84,782)		(23,919)		—		(14,786)		(9,396)		—		—		—		(132,883)		(7,007)		(139,890)
Operating		(214,729)		(68,516)		(38,742)		(59,354)		(55,299)		(68,246)		(3,635)		—		(508,521)		(59,115)		(567,636)
General and administration ⁽²⁾		(46,328)		(14,473)		(5,371)		(14,184)		(6,692)		(6,376)		(5,026)		—		(98,450)		(20,367)		(118,817)
Petroleum resource rent tax		—		—		—		—		—		2,955		—		—		2,955		—		2,955
Corporate income tax (expense) recovery		—		299		(13,272)		(1,069)		(1,274)		(761)		(5,539)		(4,428)		(26,044)		—		(26,044)
Interest expense		—		—		—		—		—		—		—		(132,748)		(132,748)		—		(132,748)
Equity based compensation		—		—		—		—		—		—		—		(6,319)		(6,319)		—		(6,319)
Realized gain on derivative instruments		—		—		—		—		—		—		—		141,648		141,648		—		141,648
Realized foreign exchange gain		—		—		—		—		—		—		—		1,223		1,223		—		1,223
Realized other expense		—		—		—		—		—		—		—		(15,800)		(15,800)		—		(15,800)
Fund flows from operations		362,129		93,657		75,109		98,148		221,448		54,850		37,771		(16,424)		926,688		83,563		1,010,251

(1)	Fund flows from discontinued operations is comprised of the fund flows from operations from the United States and Saskatchewan segments. The prior period results have been presented to conform with current period presentation. Refer to Note 6 - "Discontinued operations" for additional information.

(2)	General and administration expenses previously presented within the Corporate segment was reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.

Vermilion Energy Inc. ■ Page 44 ■ 2025 Management’s Discussion and Analysis

Supplemental Table 6: Operational and Financial Data by Core Region

Production volumes ⁽¹⁾


		Q4/25		Q3/25		Q2/25		Q1/25		Q4/24		Q3/24		Q2/24		Q1/24		Q4/23		Q3/23		Q2/23		Q1/23
Continuing operations:
North America
Crude oil and condensate (bbls/d)		13,726		13,894		14,178		9,904		7,648		8,181		7,883		7,067		6,990		7,618		4,063		7,227
NGLs (bbls/d)		12,099		10,579		11,072		7,695		4,980		5,715		5,374		5,200		5,390		5,333		4,215		5,871
Natural gas (mmcf/d)		391.39		367.34		394.06		249.02		151.64		148.38		148.37		140.93		148.20		150.97		141.80		148.30
Total (boe/d)		91,056		85,696		90,926		59,104		37,898		38,625		37,987		35,753		37,081		38,113		31,912		37,813
International
Crude oil and condensate (bbls/d)		11,621		12,248		12,055		11,835		12,502		10,792		12,714		13,459		14,004		10,534		9,564		9,054
Natural gas (mmcf/d)		111.07		108.29		105.39		105.12		112.44		116.66		103.64		114.52		116.27		92.61		117.14		80.13
Total (boe/d)		30,137		30,299		29,623		29,355		31,243		30,237		29,987		32,546		33,381		25,969		29,087		22,408
Discontinued operations:
North America
Crude oil and condensate (bbls/d)		56		2,052		11,216		10,647		10,177		10,863		12,282		12,169		11,872		13,265		15,715		17,010
NGLs (bbls/d)		40		406		1,584		1,472		1,632		1,832		1,822		1,846		2,022		2,011		2,323		2,024
Natural gas (mmcf/d)		0.13		3.63		15.93		15.22		15.51		15.70		17.38		19.14		19.45		20.22		24.69		19.18
Total (boe/d)		117		3,065		15,452		14,656		14,395		15,311		17,000		17,206		17,135		18,645		22,153		22,233
Consolidated
Crude oil and condensate (bbls/d)		25,401		28,197		37,449		32,386		30,327		29,837		32,879		32,695		32,866		31,416		29,341		33,290
NGLs (bbls/d)		12,140		10,985		12,656		9,167		6,612		7,547		7,196		7,046		7,412		7,344		6,538		7,896
Natural gas (mmcf/d)		502.60		479.28		515.38		369.36		279.59		280.73		269.39		274.59		283.92		263.80		283.63		247.61
Total (boe/d)		121,308		119,062		136,002		103,115		83,536		84,173		84,974		85,505		87,597		82,727		83,152		82,455

⁽¹⁾Please refer to Supplemental Table 4 "Production" for disclosure by product type.

Sales volumes


		Q4/25		Q3/25		Q2/25		Q1/25		Q4/24		Q3/24		Q2/24		Q1/24		Q4/23		Q3/23		Q2/23		Q1/23
Continuing operations:
North America
Crude oil and condensate (bbls/d)		13,726		13,894		14,178		9,904		7,648		8,181		7,883		7,067		6,990		7,618		4,063		7,227
NGLs (bbls/d)		12,099		10,579		11,072		7,695		4,980		5,715		5,374		5,200		5,390		5,333		4,215		5,871
Natural gas (mmcf/d)		391.39		367.34		394.06		249.02		151.64		148.38		148.37		140.93		148.20		150.97		141.80		148.30
Total (boe/d)		91,056		85,696		90,926		59,104		37,898		38,625		37,987		35,753		37,081		38,113		31,912		37,813
International
Crude oil and condensate (bbls/d)		12,168		14,018		10,344		11,145		11,360		12,580		11,998		15,938		9,221		9,950		10,302		8,087
Natural gas (mmcf/d)		111.07		108.29		105.39		105.12		112.44		116.66		103.64		114.52		116.27		92.61		117.14		80.13
Total (boe/d)		30,681		32,069		27,911		28,668		30,101		32,024		29,271		35,026		28,598		25,386		29,824		21,442
Discontinued operations:
North America
Crude oil and condensate (bbls/d)		56		2,052		11,216		10,647		10,177		10,863		12,282		12,169		11,872		13,265		15,715		17,010
NGLs (bbls/d)		40		406		1,584		1,472		1,632		1,832		1,822		1,846		2,022		2,011		2,323		2,024
Natural gas (mmcf/d)		0.13		3.63		15.93		15.22		15.51		15.70		17.38		19.14		19.45		20.22		24.69		19.18
Total (boe/d)		117		3,065		15,452		14,656		14,395		15,311		17,000		17,206		17,135		18,645		22,153		22,233
Consolidated
Crude oil and condensate (bbls/d)		25,946		29,968		35,738		31,698		29,185		31,624		32,163		35,174		28,083		30,833		30,080		32,324
NGLs (bbls/d)		12,140		10,985		12,656		9,167		6,612		7,547		7,196		7,046		7,412		7,344		6,538		7,896
Natural gas (mmcf/d)		502.60		479.28		515.38		369.36		279.59		280.73		269.39		274.59		283.92		263.80		283.63		247.61
Total (boe/d)		121,852		120,833		134,290		102,427		82,394		85,960		84,258		87,985		82,814		82,144		83,889		81,489

Vermilion Energy Inc. ■ Page 45 ■ 2025 Management’s Discussion and Analysis

Financial results


		Q4/25		Q3/25		Q2/25		Q1/25		Q4/24		Q3/24		Q2/24		Q1/24		Q4/23		Q3/23		Q2/23		Q1/23
Continuing operations:
North America
Crude oil and condensate sales ($/bbl)		78.32		85.25		83.86		91.67		93.50		94.81		101.35		89.71		99.69		94.82		156.65		98.34
NGL sales ($/bbl)		20.99		22.63		23.37		29.75		27.76		25.96		27.93		31.21		30.77		27.34		26.83		34.06
Natural gas sales ($/mcf)		2.60		1.37		2.25		2.77		1.99		0.97		1.31		2.11		2.64		2.47		2.33		4.17
Sales ($/boe)		25.75		22.51		25.67		31.26		30.81		28.11		30.60		31.01		34.46		33.20		35.09		40.89
Royalties ($/boe)		(2.14)		(1.39)		(1.97)		(3.51)		(1.96)		(3.22)		(2.83)		(3.42)		(3.98)		(3.39)		(2.31)		(4.96)
Transportation ($/boe)		(2.66)		(2.96)		(2.77)		(3.06)		(3.42)		(3.46)		(3.07)		(2.47)		(2.56)		(2.04)		(1.43)		(2.56)
Operating ($/boe)		(6.49)		(6.97)		(7.55)		(8.07)		(11.10)		(8.88)		(11.98)		(10.39)		(9.47)		(11.12)		(7.80)		(9.08)
General and administration ($/boe) ⁽¹⁾		(1.17)		(0.90)		(1.42)		(3.33)		(0.99)		0.20		(1.86)		(0.60)		2.94		0.71		1.65		0.04
Corporate income taxes ($/boe)		0.06		(0.27)		(0.28)		(0.08)		0.60		(0.47)		1.19		(0.97)		0.34		(0.01)		(0.17)		(0.19)
Fund flows from operations ($/boe)		13.35		10.02		11.68		13.21		13.94		12.28		12.05		13.16		21.73		17.35		25.03		24.14

Fund flows from operations		111,763		79,036		96,654		70,248		48,598		43,633		41,638		42,856		74,171		60,866		72,684		82,176
Drilling and development		(134,523)		(92,293)		(45,211)		(121,851)		(85,682)		(54,522)		(43,594)		(110,864)		(40,674)		(39,245)		(53,352)		(86,886)
Free cash flow		(22,760)		(13,257)		51,443		(51,603)		(37,084)		(10,889)		(1,956)		(68,008)		33,497		21,621		19,332		(4,710)

International
Crude oil and condensate sales ($/bbl)		88.68		98.71		90.82		108.97		110.31		114.16		116.24		119.68		123.77		114.26		100.23		107.57
Natural gas sales ($/mcf)		14.07		14.53		15.22		20.41		18.11		14.55		12.72		11.63		16.92		13.34		14.58		24.69
Sales ($/boe)		86.09		92.21		91.13		117.22		109.27		97.85		92.68		92.48		108.70		93.46		91.89		132.84
Royalties ($/boe)		(5.12)		(5.58)		(5.10)		(4.43)		(5.38)		(4.16)		(4.49)		(4.60)		(3.41)		3.55		(7.43)		(13.39)
Transportation ($/boe)		(4.92)		(3.91)		(4.22)		(4.63)		(3.37)		(3.81)		(4.20)		(3.65)		(3.91)		(4.53)		(5.23)		(5.11)
Operating ($/boe)		(27.90)		(28.32)		(23.84)		(27.50)		(25.08)		(27.11)		(26.56)		(25.30)		(22.64)		(25.58)		(28.24)		(31.41)
General and administration ($/boe)		(5.63)		(4.04)		(4.81)		(4.69)		(6.21)		(5.56)		(5.20)		(4.86)		(9.18)		(7.37)		(7.58)		(7.52)
Corporate income taxes ($/boe)		2.96		(0.86)		(3.46)		(7.22)		(6.53)		(3.74)		(6.08)		(7.06)		(7.81)		(13.42)		(6.79)		(11.20)
PRRT ($/boe)		2.97		(0.56)		(0.30)		(1.17)		1.16		(0.17)		(1.37)		(3.38)		7.93		—		—		—
Fund flows from operations ($/boe)		48.45		48.94		49.40		67.58		63.86		53.30		44.78		43.63		69.68		46.11		36.62		64.21

Fund flows from operations		136,781		144,366		125,486		174,350		176,883		157,048		119,310		139,054		183,351		107,706		99,377		123,893
Drilling and development		(59,795)		(54,377)		(53,197)		(36,654)		(42,341)		(40,638)		(47,830)		(45,789)		(73,604)		(49,701)		(28,347)		(37,258)
Exploration and evaluation		2,005		(771)		(4,251)		(14,655)		(24,154)		(2,460)		(1,260)		(8,144)		(10,579)		(6,235)		(2,775)		(1,492)
Free cash flow		78,991		89,218		68,038		123,041		110,388		113,950		70,220		85,121		99,168		51,770		68,255		85,143

Discontinued operations:
North America
Crude oil and condensate sales ($/bbl)		88.70		90.96		81.28		93.64		91.88		95.57		104.51		90.61		97.61		105.81		75.66		92.98
NGL sales ($/bbl)		77.17		32.39		33.83		47.63		37.41		35.94		46.43		46.90		45.49		33.84		34.03		46.92
Natural gas sales ($/mcf)		7.19		2.90		1.71		3.01		1.89		0.24		1.13		2.38		2.42		2.93		2.08		3.65
Sales ($/boe)		76.83		68.62		64.23		75.93		71.23		72.36		81.63		71.77		75.74		82.11		59.56		78.56
Royalties ($/boe)		(19.04)		(15.56)		(11.95)		(14.56)		(13.83)		(13.53)		(16.09)		(14.54)		(14.35)		(16.68)		(9.97)		(12.31)
Transportation ($/boe)		(3.53)		(3.64)		(2.13)		(2.23)		(2.04)		(2.26)		(2.26)		(2.11)		(2.18)		(2.18)		(1.76)		(2.24)
Operating ($/boe)		15.79		(19.81)		(18.36)		(21.14)		(23.73)		(19.44)		(18.14)		(22.27)		(15.89)		(14.08)		(18.59)		(22.65)
General and administration ($/boe)		(51.37)		(16.34)		(7.35)		(3.69)		(5.15)		(4.36)		(4.06)		(4.00)		(3.62)		(3.64)		(2.12)		(2.76)
Fund flows from operations ($/boe)		18.68		13.27		24.44		34.31		26.48		32.77		41.07		28.85		39.70		45.53		27.12		38.60

Fund flows from operations		201		3,742		34,362		45,258		35,064		46,160		63,549		45,171		62,595		78,094		54,662		77,259
Drilling and development		561		1,879		(12,830)		(8,959)		(48,482)		(23,649)		(17,926)		(25,645)		(18,030)		(30,458)		(82,371)		(29,184)
Free cash flow		762		5,621		21,532		36,299		(13,418)		22,511		45,623		19,526		44,565		47,636		(27,709)		48,075

		Q4/25		Q3/25		Q2/25		Q1/25		Q4/24		Q3/24		Q2/24		Q1/24		Q4/23		Q3/23		Q2/23		Q1/23
Consolidated
Crude oil and condensate sales ($/bbl)		83.21		91.93		85.07		99.36		100.06		103.55		108.93		104.26		107.91		106.94		96.64		98.62
NGL sales ($/bbl)		21.17		22.99		24.68		31.56		29.38		27.49		31.61		34.16		33.38		27.77		28.11		36.23
Natural gas sales ($/mcf)		5.13		4.36		4.88		7.80		8.47		6.57		5.69		6.10		8.48		6.32		7.37		10.77
Sales ($/boe)		40.99		42.18		43.71		61.71		66.54		61.97		62.46		63.45		68.64		62.92		61.74		75.36
Royalties ($/boe)		(2.91)		(2.86)		(3.77)		(5.35)		(5.28)		(5.40)		(6.08)		(6.06)		(5.93)		(4.26)		(6.16)		(9.18)
Transportation ($/boe)		(3.23)		(3.23)		(3.00)		(3.38)		(3.16)		(3.38)		(3.30)		(2.87)		(2.95)		(2.84)		(2.87)		(3.14)
Operating ($/boe)		(11.86)		(12.96)		(12.18)		(15.38)		(18.41)		(17.55)		(18.29)		(18.65)		(15.35)		(16.26)		(17.91)		(18.66)
General and administration ($/boe)		(2.34)		(2.13)		(2.80)		(3.76)		(3.62)		(2.76)		(3.46)		(2.96)		(2.60)		(2.77)		(2.63)		(2.71)
Corporate income taxes ($/boe)		0.79		(0.42)		(0.91)		(2.07)		(2.11)		(1.61)		(1.58)		(3.20)		(2.57)		(7.05)		(7.04)		(5.96)
PRRT ($/boe)		0.75		(0.15)		(0.06)		(0.33)		0.43		(0.06)		(0.47)		(1.35)		2.74		—		—		—
Interest ($/boe)		(2.47)		(3.10)		(3.08)		(3.58)		(3.16)		(2.68)		(2.75)		(2.30)		(3.01)		(2.68)		(2.65)		(2.98)
Equity based compensation ($/boe)		(0.06)		—		(0.47)		—		—		—		(1.87)		—		—		—		—		—
Realized derivatives ($/boe)		1.88		5.56		3.90		1.21		3.80		6.31		6.00		27.55		10.33		9.74		8.86		1.95
Realized foreign exchange ($/boe)		0.01		(0.08)		(0.04)		0.27		0.32		0.15		0.30		0.23		(0.73)		0.28		0.48		(0.65)
Realized other ($/boe)		(0.08)		0.01		(0.05)		(1.57)		(0.68)		(0.21)		(0.09)		0.02		0.26		(1.32)		0.53		0.49
Fund flows from operations ($/boe)		21.47		22.82		21.25		27.77		34.67		34.78		30.87		53.86		48.83		35.76		32.35		34.52

Fund flows from operations		240,734		253,810		259,678		256,029		262,698		275,024		236,703		431,358		372,117		270,218		247,109		253,167
Drilling and development		(193,757)		(144,791)		(111,238)		(167,464)		(176,505)		(118,809)		(109,350)		(182,298)		(132,308)		(119,404)		(164,070)		(153,328)
Exploration and evaluation		2,005		(771)		(4,251)		(14,655)		(24,154)		(2,460)		(1,260)		(8,144)		(10,579)		(6,235)		(2,775)		(1,492)
Free cash flow		48,982		108,248		144,189		73,910		62,039		153,755		126,093		240,916		229,230		144,579		80,264		98,347

(1)	General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.

Vermilion Energy Inc. ■ Page 46 ■ 2025 Management’s Discussion and Analysis

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 Consolidated 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 Consolidated Financial Statements).

In addition, this MD&A includes financial measures which are not specified, defined, or determined under IFRS Accounting Standards 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, FFO is a non-GAAP financial measure and total of segments measure comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, 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 by management 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 most directly comparable primary financial statement measures can be found below. Fund flows from continuing operations and fund flows from discontinued operations are calculated in the same manner as FFO and are most directly comparable to net loss from continuing operations and net loss discontinued operations, respectively.

Reconciliation of fund flows from continuing operations to net loss from continuing operations:

Q4 2025

Q4 2024

2025

2024

 

$/boe

 

$/boe

 

$/boe

 

$/boe

Sales

458,722

40.96

410,018

65.54

1,820,751

44.68

1,546,493

61.09

Royalties

(32,367)

(2.89)

(21,728)

(3.47)

(119,124)

(2.92)

(92,916)

(3.67)

Transportation

(36,178)

(3.23)

(21,253)

(3.40)

(132,883)

(3.26)

(86,247)

(3.41)

Operating

(133,133)

(11.89)

(108,141)

(17.29)

(508,521)

(12.48)

(446,173)

(17.62)

General and administration ⁽¹⁾

(25,698)

(2.29)

(20,645)

(3.30)

(98,450)

(2.42)

(74,010)

(2.92)

Corporate income tax expense

8,807

0.79

(15,996)

(2.56)

(26,044)

(0.64)

(66,423)

(2.62)

Petroleum resource rent tax

8,391

0.75

3,226

0.52

2,955

0.07

(11,702)

(0.46)

Interest expense

(27,670)

(2.47)

(23,965)

(3.83)

(132,748)

(3.26)

(84,606)

(3.34)

Equity based compensation

(627)

(0.06)

—

(6,319)

(0.16)

(14,361)

(0.57)

Realized gain on derivatives

21,037

1.88

28,795

4.60

141,648

3.48

345,318

13.64

Realized foreign exchange gain

0.01

2,442

0.39

1,223

0.03

7,735

0.31

Realized other expense

(844)

(0.08)

(5,119)

(0.82)

(15,800)

(0.39)

(7,267)

(0.29)

Fund flows from continuing operations

240,533

21.48

227,634

36.38

926,688

22.73

1,015,841

40.14

Equity based compensation

(5,693)

(7,499)

(18,847)

(15,569)

Unrealized gain (loss) on derivative instruments ⁽²⁾

53,894

(137,273)

116,299

(452,858)

Unrealized foreign exchange gain (loss) ⁽²⁾

30,421

(29,079)

(41,098)

(59,463)

Accretion

(19,202)

(17,112)

(71,629)

(66,179)

Depletion and depreciation

(209,384)

(131,139)

(697,461)

(563,982)

Deferred tax recovery (expense)

31,754

80,955

(16,901)

51,875

Impairment expense

(572,159)

—

(572,159)

—

Unrealized other income (expense) ⁽²⁾

11,717

(5,011)

10,303

(5,834)

Net loss from continuing operations

(438,119)

(18,524)

(364,805)

(96,169)

(1)	General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.

(2)	Unrealized gain (loss) on derivative instruments, Unrealized foreign exchange gain (loss), and Unrealized other income (expense) are line items from the respective Consolidated Statements of Cash Flows.

Vermilion Energy Inc. ■ Page 47 ■ 2025 Management’s Discussion and Analysis

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


		Q4 2025				Q4 2024				2025				2024
		$M		$/boe		$M		$/boe		$M		$/boe		$M		$/boe
Sales		827		76.83		94,334		71.23		210,643		69.80		434,914		74.40
Royalties		(205)		(19.04)		(18,321)		(13.83)		(40,591)		(13.45)		(85,034)		(14.55)
Transportation		(38)		(3.53)		(2,708)		(2.04)		(7,007)		(2.32)		(12,686)		(2.17)
Operating		170		15.79		(31,425)		(23.73)		(59,115)		(19.59)		(121,740)		(20.83)
General and administration		(553)		(51.37)		(6,815)		(5.15)		(20,367)		(6.75)		(25,493)		(4.36)
Corporate income tax expense		—		—		(1)		—		—		—		(19)		—
Fund flows from discontinued operations		201		18.68		35,064		26.48		83,563		27.69		189,942		32.49
Unrealized foreign exchange (loss) gain ⁽¹⁾		(207)				562				(308)				992
Unrealized other expense ⁽¹⁾		—				—				(3,986)				—
Accretion		—				(2,160)				(4,235)				(8,362)
Depletion and depreciation		585				(32,319)				(45,926)				(119,258)
Deferred tax (expense) recovery		(113)				(939)				54,482				(13,884)
Impairment expense		—				—				(372,386)				—
Net earnings (loss) from discontinued operations		466				208				(288,796)				49,430

Fund flows from operations		240,734		21.47		262,698		34.67		1,010,251		23.10		1,205,783		38.71

Net loss		(437,653)				(18,316)				(653,601)				(46,739)

(1)	Unrealized gain (loss) on derivative instruments, Unrealized foreign exchange (loss) gain, and Unrealized other expense are line items from the respective Consolidated Statements of Cash Flows.

Non-GAAP Financial Measures and Non-GAAP Ratios

Fund flows from operations per basic and diluted share: FFO per share and diluted share are non-GAAP ratios. 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 Accounting Standards. 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. Fund flows from continuing operations per basic and diluted share and fund flows from discontinued operations per basic and diluted share are calculated in the same manner as FFO per basic and diluted share.

Fund flows from operations per boe: Management uses fund flows from operations per boe to assess the profitability of our business units and Vermilion as a whole. Fund flows from operations per boe is calculated by dividing fund flows from operations (total of segments measure) by boe production. Fund flows from continuing operations per boe and fund flows from discontinued operations per boe are calculated in the same manner as FFO per boe.

Free cash flow (FCF): Most directly comparable to cash flows from operating activities, FCF is a non-GAAP financial measure calculated as fund flows from operations less drilling and development costs and exploration and evaluation costs. FCF is used by management 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)		Q4 2025		Q4 2024		2025		2024
Cash flows from operating activities		133,357		212,587		943,661		967,751
Changes in non-cash operating working capital		75,953		26,829		4,104		182,698
Asset retirement obligations settled		31,424		23,282		62,486		55,334
Fund flows from operations		240,734		262,698		1,010,251		1,205,783
Drilling and development		(193,757)		(176,505)		(617,250)		(586,962)
Exploration and evaluation		2,005		(24,154)		(17,672)		(36,018)
Free cash flow		48,982		62,039		375,329		582,803

Vermilion Energy Inc. ■ Page 48 ■ 2025 Management’s Discussion and Analysis

Capital expenditures: Most directly comparable to cash flows used in investing activities, capital expenditures is a non-GAAP financial measure calculated as the sum of drilling and development costs and exploration and evaluation costs as derived from the Consolidated Statements of Cash Flows. 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)		Q4 2025		Q4 2024		2025		2024
Drilling and development		193,757		176,505		617,250		586,962
Exploration and evaluation		(2,005)		24,154		17,672		36,018
Capital expenditures		191,752		200,659		634,922		622,980

Payout and payout % of FFO: Payout and payout % of FFO are, respectively, a non-GAAP financial measure and non-GAAP ratio. Payout is 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 divided by FFO. The measure is used by management to assess the amount of cash distributed back to shareholders and reinvested in the business for maintaining production and organic growth. Payout as a percentage of FFO is also referred to as the payout ratio or sustainability ratio. The reconciliation of the measure to the primary financial statement measure can be found below.


($M)		Q4 2025		Q4 2024		2025		2024
Dividends declared		19,895		18,521		79,907		75,327
Drilling and development		193,757		176,505		617,250		586,962
Exploration and evaluation		(2,005)		24,154		17,672		36,018
Asset retirement obligations settled		31,424		23,282		62,486		55,334
Payout		243,071		242,462		777,315		753,641
% of fund flows from operations		101	%	92	%	77	%	63	%

Return on capital employed (ROCE): A non-GAAP ratio, ROCE is a measure that management uses 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 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)		Dec 31, 2025		Dec 31, 2024
Net loss		(653,601)		(46,739)
Taxes		(14,492)		40,153
Interest expense		132,748		84,606
EBIT		(535,345)		78,020
Average capital employed ⁽¹⁾		5,120,536		5,464,037
Return on capital employed		(10)	%	1	%

(1)	Average capital employed includes the current portion of asset retirement obligations, previously presented on a combined basis as long-term. The prior period results have been presented to conform with current period presentation.

Adjusted working capital (deficit): Adjusted working capital (deficit) is a non - GAAP financial measure calculated as current assets less current liabilities, excluding current derivatives , current asset retirement obligations and current lease liabilities. The measure is used by management to calculate net debt, a capital management measure disclosed below.


		As at
($M)		Dec 31, 2025		Dec 31, 2024
Current assets		467,286		582,326
Current liabilities		(554,547)		(664,178)
Current derivative asset		(78,694)		(40,312)
Current asset retirement obligation ⁽¹⁾		54,504		53,588
Current lease liability		9,206		12,206
Current derivative liability		6,154		52,944
Adjusted working capital deficit		(96,091)		(3,426)

(1)	Asset retirement obligations previously presented as a combined balance have been reclassified into current and long-term portion of asset retirement obligations. The prior period results have been presented to conform with current period presentation.

Vermilion Energy Inc. ■ Page 49 ■ 2025 Management’s Discussion and Analysis

Acquisitions: Acquisitions is a non-GAAP financial measure and is calculated as the sum of acquisitions, net of cash acquired 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. Management believes 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.


($M)		Q4 2025		Q4 2024		2025		2024
Acquisitions, net of cash acquired		1,646		5,257		1,088,761		12,728
Shares issued for acquisition		—		—		13,363		—
Acquisition of securities		—		—		—		9,373
Acquired working capital deficit		—		—		23,179		—
Acquisitions		1,646		5,257		1,125,303		22,101

Dispositions: Dispositions is a non-GAAP financial measure and is calculated as the sum of dispositions, and disposition of securities from the Consolidated Statements of Cash Flows. Management believes that including these components provides a useful measure of the proceeds associated with our disposition activities and is most directly comparable to cash flows used in investing activities. A reconciliation to dispositions, and disposition of securities, the most directly comparable primary financial statement measures, can be found below.


($M)		Q4 2025		Q4 2024		2025		2024
Dispositions		—		—		483,525		—
Disposition of securities		41,782		—		41,782		—
Dispositions		41,782		—		525,307		—

Operating netback: Operating netback is non-GAAP financial measure and is calculated as sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses, and when presented on a per unit basis, is a non-GAAP ratio. Operating netback is most directly comparable to net loss. Management assesses operating netback as a measure of the profitability and efficiency of our field operations.

Net debt to four quarter trailing fund flows from operations: Management uses net debt (a capital management measure, as defined below) to four quarter trailing fund flows from operations to assess the Company's ability to repay debt. Net debt to four quarter trailing fund flows from operations is a non-GAAP ratio and is calculated as net debt (capital management measure) divided by fund flows from operations (total of segments measure) from the preceding four quarters.

Capital Management Measure

Net debt: Net debt is a capital management measure 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, current asset retirement obligations and current lease liabilities), and represents Vermilion's net financing obligations after adjusting for the timing of working capital fluctuations.


		As at
($M)		Dec 31, 2025		Dec 31, 2024
Long-term debt		1,243,397		963,456
Adjusted working capital ⁽¹⁾		96,091		3,426
Unrealized FX on swapped USD borrowings⁽²⁾		2,902		—
Net debt		1,342,390		966,882

Ratio of net debt to four quarter trailing fund flows from operations ⁽³⁾		1.4		0.8

(1)	Adjusted working capital is defined as current assets (excluding current derivatives), less current liabilities (excluding current derivatives, current asset retirement obligations and current lease liabilities).

(2)

(3)

Vermilion Energy Inc. ■ Page 50 ■ 2025 Management’s Discussion and Analysis

Supplementary Financial Measures

Diluted shares outstanding: The sum of shares outstanding at the period end plus outstanding awards under the Long-term Incentive Plan (“LTIP"), based on current estimates of future performance factors and forfeiture rates.


('000s of shares)		Q4 2025		Q4 2024
Shares outstanding		152,950		154,344
Potential shares issuable pursuant to the LTIP		4,663		3,493
Diluted shares outstanding		157,613		157,837

Vermilion Energy Inc. ■ Page 51 ■ 2025 Management’s Discussion and Analysis

DIRECTORS

Myron Stadnyk¹

Calgary, Alberta

Corey Bieber, ^{3, 7}

Calgary, Alberta

Dion Hatcher

Calgary, Alberta

James J. Kleckner Jr.^{5, 8}

Edwards, Colorado

Carin Knickel ^{7, 9}

Golden, Colorado

Stephen P. Larke^{3, 4}

Calgary, Alberta

Paul Myers ^{7, 9}

Calgary, Alberta

William Roby ^{6, 9}

Houston, Texas

Manjit Sharma ^{2, 5}

Toronto, Ontario

Judy Steele ^{3, 7}

Halifax, Nova Scotia

Chairman (Independent)

Audit Committee Chair (Independent)

Audit Committee Member (Independent)

Governance and Human Resources Committee Chair (Independent)

Governance and Human Resources Committee Member(Independent)

Safety & Sustainability Committee Chair (Independent)

Safety & Sustainability Committee Member (Independent)

Technical Committee Chair (Independent)

Technical Committee Member (Independent)

OFFICERS / CORPORATE SECRETARY

Dion Hatcher

President & Chief Executive Officer

Lars Glemser

Vice President & Chief Financial Officer

Lara Conrad

Vice President Business Development

Tamar Epstein

General Counsel & Corporate Secretary

Yvonne Jeffery

Vice President Sustainability

Darcy Kerwin

Vice President International & HSE

Geoff MacDonald

Vice President Geosciences

Randy McQuaig

Vice President North America

Averyl Schraven

Vice President People & Culture

Gerard Schut

Vice President European Operations

AUDITORS

Deloitte LLP

Calgary, Alberta

BANKERS

The Toronto-Dominion Bank

The Bank of Nova Scotia

Canadian Imperial Bank of Commerce

National Bank of Canada

Royal Bank of Canada

Wells Fargo Bank N.A., Canadian Branch

ATB Financial

Bank of America N.A., Canada Branch

Export Development Canada

Fédération des caisses Desjardins du Québec

Citibank, N.A., Canadian Branch

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

Travis Thorgeirson

Director, Investor Relations & Corporate Planning

403-476-8214 TEL

403-476-8100 FAX

1-866-895-8101 IR TOLL FREE

investor_relations@vermilionenergy.com

Vermilion Energy Inc. ■ Page 52 ■ 2025 Management’s Discussion and Analysis