Exhibit 99.2

Disclaimer

Certain statements included or incorporated by reference in this document may constitute forward-looking statements or information under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion’s ability to fund such expenditures; Vermilion’s additional debt capacity providing it with additional working capital; statements regarding the return of capital, the flexibility of Vermilion’s capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion’s 2024 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange and inflation rates; significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion’s future project inventory wells expected to be drilled in 2024; exploration and development plans and the timing thereof; Vermilion’s ability to reduce its debt; statements regarding Vermilion’s hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion’s hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion’s expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.

Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management’s expectations relating to the timing and results of exploration and development activities.

Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion’s financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates, interest rates, and inflation rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against or involving Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.

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

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

All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oiland Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves

Vermilion Energy Inc.  ■  Page 1  ■  2023 Management's Discussion and Analysis

estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

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Abbreviations

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

Vermilion Energy Inc.  ■  Page 3  ■  2023 Management's Discussion and Analysis

Management's Discussion and Analysis

The following is Management’s Discussion and Analysis (“MD&A”), dated March 6, 2024, 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, 2023 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, 2023 and 2022, together with the accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR+ at www.sedarplus.ca or on Vermilion’s website at www.vermilionenergy.com.

The audited consolidated financial statements for the year ended December 31, 2023 and comparative information have been prepared in Canadian dollars and in accordance with International Financial Reporting Standards (“IFRS” or, alternatively, “GAAP”) as issued by the International Accounting Standards Board ("IASB").

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

Product Type Disclosure

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

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

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

Guidance

On January 6, 2023, we released our 2023 capital budget and associated production guidance, which incorporated the March 31, 2023 close date of the acquisition of an incremental 36.5% interest in the Corrib Natural Gas Project (“Corrib”) in Ireland. On March 8, 2023, we decreased annual production guidance to 82,000 to 86,000 boe/d to reflect the southeast Saskatchewan asset sale and unplanned downtime in Australia, and decreased operating expense guidance to reflect the southeast Saskatchewan asset sale and lower European gas prices. On May 3, 2023, we updated royalty rate guidance to include Netherlands windfall royalties, which were previously included in windfall tax guidance, and provided revisions to 2023 guidance items to reflect the assumptions used in management's most recent forecast. On November 1, 2023, we increased capital expenditure guidance by $20 million primarily due to the acceleration of some Montney development as a result of the timely receipt of permits, and revised other 2023 guidance items to reflect the assumptions used in management's most recent forecast.

The Company’s guidance and results for 2023 are as follows:

Category	2023 Guidance (1)			2023 Actual (1)
Production (boe/d)		82,000 - 86,000			83,994
E&D capital expenditures ($MM)		590			590
Royalty rate, including windfall royalties (% of sales) (2)		10 - 12	%		9.5	%
Operating ($/boe)	$	16.50 - 17.50		$	17.03
Transportation ($/boe)	$	2.75 - 3.25		$	2.95
General and administration ($/boe)	$	2.00 - 2.50		$	2.68
Cash taxes (% of pre-tax FFO)		6 - 8	%		5.5	%
Windfall tax, excluding windfall royalties (% of pre-tax FFO) (3)		8 - 10	%		6.0	%

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On December 12, 2023, we released our 2024 capital budget and associated production guidance, which assumes a mid-year startup of the new BC Montney battery and Croatia gas plant. The Company’s guidance for 2024 is as follows:

Category	2024 Guidance (1)
Production (boe/d)		82,000 - 86,000
E&D capital expenditures ($MM)	$	600 - 625
Royalty rate (% of sales)		7 - 9	%
Operating ($/boe)	$	17.00 - 18.00
Transportation ($/boe)	$	3.00 - 3.50
General and administration ($/boe)	$	2.50 - 3.00
Cash taxes (% of pre-tax FFO)		5 - 7	%
Asset retirement obligations settled ($MM)	$	60
Payments on lease obligations ($MM) (4)	$	30 - 60

(1) Final 2023 guidance reflects foreign exchange assumptions of CAD/USD 1.35, CAD/EUR 1.46, and CAD/AUD 0.89. Actual 2023 results reflects foreign exchange rates of CAD/USD 1.35, CAD/EUR 1.46, and CAD/AUD 0.90. Current 2024 guidance reflects foreign exchange assumptions of CAD/USD 1.35,  CAD/EUR 1.47, and CAD/AUD 0.89.

(2) Royalty rate guidance includes the temporary windfall royalty that was enacted by the Netherlands in the fourth quarter of 2022. This royalty applies to 2023 and 2024 and, for natural gas sales, is calculated as 65% of the excess of the realized price for a subject year versus the threshold price of €0.50/Nm3 (€13.40/mcf).  This royalty is deductible against current income taxes.

(3) Windfall tax guidance incorporates windfall taxes as legislated in EU member states in which Vermilion does business. Windfall royalties in the Netherlands are excluded from windfall tax guidance, and have been included in royalty rate guidance, above.

(4) Payments on lease obligations includes contractual amounts owing on leases, as well as up to $30 million to account for accelerated principal payments that may be made in 2024.

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Vermilion's Business

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

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Consolidated Results Overview

			Q4/23 vs.				2023 vs.
	Q4 2023	Q4 2022	Q4/22		2023	2022	2022
Production (1)
Crude oil and condensate (bbls/d)	32,866	38,915	(16)	%	31,727	37,530	(16)	%
NGLs (bbls/d)	7,412	7,497	(1)	%	7,296	7,961	(8)	%
Natural gas (mmcf/d)	283.91	234.23	21	%	269.83	238.18	13	%
Total (boe/d)	87,597	85,450	3	%	83,994	85,187	(1)	%
Build (draw) in inventory (mbbls)	442	(242)			513	39
Financial metrics
Fund flows from operations ($M) (2)	372,117	284,220	31	%	1,142,611	1,634,865	(30)	%
Per share ($/basic share)	2.27	1.74	31	%	6.98	10.00	(30)	%
Net (loss) earnings ($M)	(803,136)	395,408	N/A		(237,587)	1,313,062	N/A
Per share ($/basic share)	(4.91)	2.42	N/A		(1.45)	8.03	N/A
Cash flows from operating activities ($M)	343,831	495,195	(31)	%	1,024,528	1,814,220	(44)	%
Free cash flow ($M) (3)	229,230	114,915	100	%	552,420	1,083,048	(49)	%
Long-term debt ($M)	914,015	1,081,351	(16)	%	914,015	1,081,351	(16)	%
Net debt ($M) (4)	1,078,567	1,344,586	(20)	%	1,078,567	1,344,586	(20)	%
Activity
Capital expenditures ($M) (5)	142,887	169,305	(16)	%	590,191	551,817	7	%
Acquisitions ($M) (6)	25,724	4,558			273,018	539,713
Dispositions ($M)	14,855	—			197,007	—

⁽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 respectively most directly comparable to net (loss) earnings and net (loss) earnings per share, respectively. The measures do not have a standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. FFO is comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, and realized loss (gain) 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.

⁽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 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. The measure is used to determine the funding available for investing and financing activities including payment of dividends, repayment of long-term debt, reallocation into existing business units and deployment into new ventures. 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 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 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.

⁽⁶⁾ Acquisitions is a non-GAAP financial measure that does not have a standardized meaning under IFRS 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.

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Financial performance review

Q4 2023 vs. Q4 2022

·We recorded net loss of $803.1 million ($(4.91)/basic share) for Q4 2023 compared to $395.4 million ($2.42/basic share) in Q4 2022. The increase in net loss was primarily due to impairment charges of $1.0 billion and decreases in unrealized derivative gains of $408.6 million due to changes in our mark-to-market position. The increase to net loss was partially offset by higher fund flows from operations primarily driven by a reduction in windfall tax expense in the quarter due to timing of recognition at the end of 2022 compared to throughout 2023.

● We generated cash flows from operating activities of $343.8 million in Q4 2023 compared to $495.2 million in Q4 2022 and fund flows from operations of $372.1 million in Q4 2023 compared to $284.2 million in Q4 2022. The increase in fund flows from operations was primarily driven by timing of windfall taxes, and partially offset by lower commodity prices. The variance between cash flows from operating activities and fund flows from operations is primarily due to non-cash working capital impacts of the full year windfall taxes payable recorded on higher pricing in the last quarter of 2022.

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2023 vs. 2022

·For the year ended December 31, 2023, we recorded net loss of $237.6 million compared to net earnings of $1,313.1 million for the comparable period in 2022. The net loss was primarily due to impairment charges of $1.0 billion compared to impairment reversal of $192.1 million, a decrease in FFO driven by lower commodity prices and lower production, and the loss recognized on the sale of assets. This was partially offset by the gain recognized on the Corrib acquisition.

·For the year ended December 31, 2023 as compared to 2022, cash flows from operating activities decreased by $789.7 million to $1,024.5 million and fund flows from operations decreased by $492.3 million to $1,142.6 million. The decrease in fund flows from operations was primarily driven by a 40% decrease in our consolidated realized price from $111.95/boe to $67.10/boe, and a decrease in sales volumes primarily driven by the Australian Wandoo platform shutdown for the first three quarters of the year. This was partially offset by decreases in tax expense, windfall tax expense and royalties due to the pricing and sales volume changes. Variances between cash flows from operating activities and funds flow from operations are primarily driven by working capital timing differences.

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Production review

Q4 2023 vs. Q4 2022

● Consolidated average production of 87,597 boe/d in Q4 2023 increased compared to Q4 2022 production of 85,450 boe/d. Production increased primarily due to the acquired 36.5% interest in the Corrib Natural Gas Project in 2023 and new production from our Mica Montney development, partially offset by the sale of non-core assets in southeast Saskatchewan and natural declines.

2023 vs. 2022

● Consolidated average production of 83,994 boe/d in the year ended December 31, 2023 decreased compared to the prior year comparative period production of 85,187 boe/d. Production decreased primarily due to unplanned downtime in Australia partially offset by increased production in Ireland due to the acquisition of an additional 36.5% interest in the Corrib Natural Gas Project. Production in Canada was relatively flat as growth in the Mica Montney assets offset unplanned downtime due to wildfires in the Deep Basin and the sale of non-core assets in southeast Saskatchewan.

Activity review

● For the three months ended December 31, 2023, capital expenditures were $142.9 million.

● In our North America core region, we invested capital expenditures of $58.7 million. In Canada, capital expenditures totaled $53.8 million as we drilled five (5.0 net), completed five (5.0 net), and brought on production four (4.0 net) Mannville liquids rich conventional natural gas wells in the Deep Basin. At Mica we drilled the initial four (4.0 net) Montney liquids-rich shale gas wells on our BC lands as part of our winter drilling program in advance of the expected start-up of our 8-33 BC battery in mid-2024. In Saskatchewan, we completed and brought on production one (1.0 net) light and medium crude oil well. In the United States, $4.9 million was incurred as we participated in the drilling of six (2.0 net) non- operated light and medium crude oil wells in Wyoming.

● In our International core region, capital expenditures of $84.2 million were invested during Q4 2023. In the Netherlands and France, we invested $10.8 million and $11.2 million, respectively, primarily on facilities and subsurface maintenance activities. In Germany, we invested $33.0 million as we advanced our deep gas exploration and development plans and commenced drilling activities. In Ireland, $11.9 million was invested on our Corrib plant refrigeration project. In Australia, $9.3 million was invested as we preformed routine maintenance and workover activities. In Central and Eastern Europe, $8.0 million was invested on construction for the gas plant on the SA-10 block and site preparation for the upcoming drilling program on the SA-7 block.

Financial sustainability review

Free cash flow

● Free cash flow of $552.4 million decreased by $530.6 million for the year ended December 31, 2023 compared to the prior year period primarily driven by decreased fund flows from operations on lower pricing, lower production and sales volumes, and higher expenditures on drilling and development activities.

Long-term debt and net debt

● Long-term debt decreased to $0.9 billion as at December 31, 2023 from $1.1 billion as at December 31, 2022 primarily as a result of revolving credit facility repayments of $146.3 million.

● As at December 31, 2023, net debt decreased to $1.1 billion (December 31, 2022 - $1.3 billion), primarily as a result of revolving credit facility net repayments of $146.3 million, funded by the disposition of our southeast Saskatchewan assets for $182.2 million, and $552.4 million of free cash flow generated during the year, and offset by spend on acquisition activities primarily due to the purchase of an additional 36.5% working interest in our operated Corrib project for $192.4 million (net of cash and working capital deficit acquired).

● The ratio of net debt to four quarter trailing fund flows from operations⁽¹⁾ increased to 0.9 as at December 31, 2023 (December 31, 2022 - 0.8) primarily due to lower four quarter trailing fund flows from operations on lower prices and lower production.

(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 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.

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Benchmark Commodity Prices

			Q4/23 vs.				2023 vs.
	Q4 2023	Q4 2022	Q4/22		2023	2022	2022
Crude oil
WTI ($/bbl)	106.67	112.24	(5)	%	104.77	122.62	(15)	%
WTI (US $/bbl)	78.32	82.65	(5)	%	77.63	94.23	(18)	%
Edmonton Sweet index ($/bbl)	99.60	109.85	(9)	%	100.37	120.25	(17)	%
Edmonton Sweet index (US $/bbl)	73.13	80.89	(10)	%	74.36	92.41	(20)	%
Saskatchewan LSB index ($/bbl)	97.12	106.05	(8)	%	97.97	118.22	(17)	%
Saskatchewan LSB index (US $/bbl)	71.31	78.09	(9)	%	72.59	90.85	(20)	%
Canadian C5+ Condensate index ($/bbl)	103.83	113.19	(8)	%	103.38	121.96	(15)	%
Canadian C5+ Condensate index (US $/bbl)	76.24	83.35	(9)	%	76.60	93.72	(18)	%
Dated Brent ($/bbl)	114.46	120.47	(5)	%	111.51	131.68	(15)	%
Dated Brent (US $/bbl)	84.05	88.71	(5)	%	82.62	101.19	(18)	%
Natural gas
North America
AECO 5A ($/mcf)	2.30	4.64	(50)	%	2.64	5.25	(50)	%
Henry Hub ($/mcf)	3.92	8.50	(54)	%	4.00	8.67	(54)	%
Henry Hub (US $/mcf)	2.88	6.26	(54)	%	2.74	6.66	(59)	%
Europe(1)
NBP Day Ahead ($/mmbtu)	16.69	26.09	(36)	%	16.63	31.78	(48)	%
NBP Month Ahead ($/mmbtu)	18.32	43.51	(58)	%	19.85	41.44	(52)	%
NBP Day Ahead (€/mmbtu)	11.38	18.82	(40)	%	11.39	23.21	(51)	%
NBP Month Ahead (€/mmbtu)	12.50	31.38	(60)	%	13.60	30.26	(55)	%
TTF Day Ahead ($/mmbtu)	17.45	38.36	(55)	%	17.40	48.35	(64)	%
TTF Month Ahead ($/mmbtu)	18.51	49.98	(63)	%	20.52	52.59	(61)	%
TTF Day Ahead (€/mmbtu)	11.90	27.67	(57)	%	11.92	35.30	(66)	%
TTF Month Ahead (€/mmbtu)	12.63	36.05	(65)	%	14.06	38.40	(63)	%
Average exchange rates
CDN $/US $	1.36	1.36	—	%	1.35	1.30	4	%
CDN $/Euro	1.47	1.39	6	%	1.46	1.37	7	%
Realized prices
Crude oil and condensate ($/bbl)	107.91	115.02	(6)	%	102.43	123.89	(17)	%
NGLs ($/bbl)	33.38	39.93	(16)	%	31.54	45.95	(31)	%
Natural gas ($/mcf)	8.48	17.43	(51)	%	8.17	18.99	(57)	%
Total ($/boe)	68.64	103.99	(34)	%	67.10	111.95	(40)	%

⁽¹⁾ NBP and TTF pricing can occur on a day-ahead ("DA") or month-ahead ("MA") basis. DA prices in a period reflect the average current day settled price on the next days' delivery and MA prices in a period represent daily one month futures contract prices which are determined at the end of each month. In a rising price environment, the DA price will tend to be greater than the MA price and vice versa. Natural gas in the Netherlands and Germany is benchmarked to the TTF and production is generally equally split between DA and MA contracts. Natural gas in Ireland is benchmarked to the NBP and is sold on DA contracts.

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

● Crude oil prices decreased in Q4 2023 relative to Q4 2022 after US production rose above expectations, which offset price support from improved demand growth and heightened geopolitical risks. Canadian dollar WTI and Brent prices both decreased by 5% in Q4 2023 relative to Q4 2022.

● In Canadian dollar terms, year-over-year, the Edmonton Sweet differential widened by $4.68/bbl to a discount of $7.07/bbl against WTI, and the Saskatchewan LSB differential widened by $3.36/bbl to a discount of $9.55/bbl against WTI.

● Approximately 34% of Vermilion’s Q4 2023 crude oil and condensate production was priced at the Dated Brent index, which averaged a premium to WTI of US$5.73/bbl, while the remainder of our crude oil and condensate production was priced at the Saskatchewan LSB, Canadian C5+, Edmonton Sweet, and WTI indices.

Vermilion Energy Inc.  ■  Page 12  ■  2023 Management's Discussion and Analysis

● In Canadian dollar terms, year-over-year, prices for European natural gas linked to NBP and TTF decreased by 36% and 55% respectively on a day-ahead basis. On a month ahead basis, NBP and TTF decreased by 58% and 63% respectively. Prices declined in response to low seasonal and industrial demand in Europe, strong LNG import volumes and historically high storage levels. While prices are off their Q3 2022 highs, they remained elevated compared to historical levels due to lost Russian pipeline supply, global LNG imports competitiveness, and weather related risk premiums.

● Year-over-year natural gas prices in Canadian dollar terms at NYMEX HH, and AECO decreased by 54% and 50% respectively. Both NYMEX HH and AECO prices declined due to strong production growth, weak seasonal demand and historically high storage levels.

● For Q4 2023, average European natural gas prices represented a $15.44/mcf premium to AECO. Approximately 41% of our natural gas production in Q4 2023 benefited from this premium European pricing.

North America

	Q4 2023	Q4 2022	2023	2022
Production (1)
Crude oil and condensate (bbls/d)	18,862	25,291	20,925	24,393
NGLs (bbls/d)	7,412	7,497	7,296	7,961
Natural gas (mmcf/d)	167.65	154.26	168.22	151.30
Total production volume (boe/d)	54,216	58,499	56,257	57,571

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

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	236,969	47.51	360,295	66.95	1,012,549	49.31	1,510,517	71.88
Royalties	(36,186)	(7.25)	(50,945)	(9.47)	(144,998)	(7.06)	(240,432)	(11.44)
Transportation	(12,151)	(2.44)	(13,014)	(2.42)	(43,914)	(2.14)	(45,467)	(2.16)
Operating	(57,368)	(11.50)	(72,694)	(13.51)	(256,841)	(12.51)	(268,271)	(12.77)
General and administration (1)	4,338	0.87	513	0.10	(4,267)	(0.21)	(20,651)	(0.98)
Corporate income tax expense (1)	1,164	0.23	(712)	(0.13)	(20)	—	(1,011)	(0.05)
Fund flows from operations	136,766	27.42	223,443	41.52	562,509	27.39	934,685	44.48
Drilling and development	(58,704)		(113,892)		(380,200)		(338,556)
Free cash flow	78,062		109,551		182,309		596,129

⁽¹⁾Includes amounts from Corporate segment.

Production from our North American operations averaged 54,216 boe/d in Q4 2023, a decrease of 4% from the previous quarter due to natural declines in both Canada and the United States.

In the Deep Basin, we drilled five (5.0 net), completed five (5.0 net), and brought on production four (4.0 net) Mannville liquids rich conventional natural gas wells. At Mica we drilled the initial four (4.0 net) Montney liquids-rich shale gas wells on our BC lands as part of our winter drilling program in advance of the expected start-up of our 8-33 BC battery in mid-2024. In Saskatchewan, we completed and brought on production one (1.0 net) light and medium crude oil well, while in the United States, we participated in the drilling of six (2.0 net) non-operated light and medium crude oil wells in Wyoming.

Sales

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	200,102	44.73	315,897	65.13	861,391	46.73	1,344,284	70.33
United States	36,867	71.65	44,398	83.51	151,158	71.97	166,233	87.46
North America	236,969	47.51	360,295	66.95	1,012,549	49.31	1,510,517	71.88

Sales in North America decreased for the three months and year ended December 31, 2023 versus the comparable prior year periods due to lower realized prices and a decrease in production.

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Royalties

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	(25,759)	(5.76)	(38,747)	(7.99)	(103,511)	(5.62)	(196,005)	(10.26)
United States	(10,427)	(20.27)	(12,198)	(22.94)	(41,487)	(19.75)	(44,427)	(23.38)
North America	(36,186)	(7.25)	(50,945)	(9.47)	(144,998)	(7.06)	(240,432)	(11.44)

Royalties in North America decreased on a dollar and per unit basis for the three months and year ended December 31, 2023 versus the comparable prior year periods primarily due to decreased sliding scale royalties on lower commodity prices and lower production. Royalties as a percentage of sales for the three months and year ended December 31, 2023 were 15.3% and 14.3% respectively, compared to the prior year comparative period of 14.1%. and 15.9% respectively.

Transportation

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	(11,701)	(2.62)	(12,919)	(2.66)	(43,163)	(2.34)	(44,849)	(2.35)
United States	(450)	(0.87)	(95)	(0.18)	(751)	(0.36)	(618)	(0.33)
North America	(12,151)	(2.44)	(13,014)	(2.42)	(43,914)	(2.14)	(45,467)	(2.16)

Transportation expense in North America remained relatively flat on a dollar and per boe basis for the three months and year ended December 31, 2023 versus the comparable prior periods.

Operating expense

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Canada	(51,129)	(11.43)	(63,305)	(13.05)	(233,417)	(12.66)	(240,899)	(12.60)
United States	(6,239)	(12.13)	(9,389)	(17.66)	(23,424)	(11.15)	(27,372)	(14.40)
North America	(57,368)	(11.50)	(72,694)	(13.51)	(256,841)	(12.51)	(268,271)	(12.77)

Operating expenses in North America decreased on a dollar and per boe basis for the three months and year ended December 31, 2023 compared to the prior year period primarily the disposition of the properties in southeast Saskatchewan in Q1 2023 combined with lower routine maintenance costs in the United States and lower fuel and electricity costs in Canada.

International

	Q4 2023	Q4 2022	2023	2022
Production (1)
Crude oil and condensate (bbls/d)	14,004	13,624	10,802	13,135
Natural gas (mmcf/d)	116.27	79.97	101.61	86.88
Total production volume (boe/d)	33,381	26,953	27,737	27,616
Total sales volume (boe/d)	28,598	29,585	26,330	27,506

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

Vermilion Energy Inc.  ■  Page 14  ■  2023 Management's Discussion and Analysis

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	286,000	108.70	482,398	177.23	1,010,006	105.09	1,965,877	195.81
Royalties	(8,962)	(3.41)	(17,358)	(6.38)	(46,696)	(4.86)	(65,585)	(6.53)
Transportation	(10,290)	(3.91)	(8,962)	(3.29)	(44,942)	(4.68)	(33,429)	(3.33)
Operating	(59,569)	(22.64)	(63,553)	(23.35)	(256,540)	(26.69)	(220,763)	(21.99)
General and administration	(24,148)	(9.18)	(13,857)	(5.09)	(76,449)	(7.95)	(37,026)	(3.69)
Corporate income tax expense	(20,538)	(7.81)	(41,246)	(15.15)	(91,912)	(9.56)	(207,142)	(20.63)
PRRT	20,860	7.93	(5,045)	(1.85)	20,860	2.17	(18,318)	(1.82)
Fund flows from operations	183,353	69.68	332,377	122.12	514,327	53.52	1,383,614	137.82
Drilling and development	(73,604)		(43,957)		(188,910)		(189,500)
Exploration and evaluation	(10,579)		(11,456)		(21,081)		(23,761)
Free cash flow	99,170		276,964		304,336		1,170,353

Production from our International operations averaged 33,381 boe/d in Q4 2023, an increase of 29% over the previous quarter primarily due to a full quarter of production at our Australia and Ireland operations following maintenance downtime in the prior quarter, as well as increased production in the Netherlands due to new production from our 2023 drilling program.

We continued to advance our deep gas exploration and development plans in Germany, with drilling operations nearly complete on our first well of our program. We expect to reach total depth in the coming weeks and will then move the rig to the next location, where the second well of our program will be drilled during Q2 2024.

Sales

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Australia	36,381	143.69	95,420	139.95	36,381	143.69	221,187	148.15
France	52,472	116.92	77,910	119.68	285,626	109.47	365,431	132.90
Netherlands	51,661	102.80	119,668	281.75	186,854	107.38	562,857	279.87
Germany	44,150	101.18	121,011	218.13	195,481	104.26	481,260	231.34
Ireland	100,430	102.28	64,753	162.16	302,404	97.24	324,345	194.05
Central and Eastern Europe	906	109.42	3,636	356.05	3,260	141.77	10,797	313.02
International	286,000	108.70	482,398	177.23	1,010,006	105.09	1,965,877	195.81

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 2023	Q4 2022	2023	2022
Australia	2,752	7,411	694	4,090
France	4,878	7,076	7,149	7,533
Germany	1,472	1,721	1,481	1,337
International	9,102	16,208	9,324	12,960

Sales decreased on a dollar and per unit basis for the three months and year ended December 31, 2023 versus the prior year comparable periods due to lower realized prices across all business units combined with lower sales volumes primarily due to downtime in Australia. For the three months ended December 31, 2023, France sales decreased versus the prior year comparable period due to timing of scheduled vessels.

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Royalties

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
France	(7,150)	(15.93)	(9,294)	(14.28)	(37,425)	(14.34)	(40,353)	(14.68)
Netherlands	(692)	(1.38)	(512)	(1.21)	(1,567)	(0.90)	(512)	(0.25)
Germany	(736)	(1.69)	(6,403)	(11.54)	(5,993)	(3.20)	(21,232)	(10.21)
Central and Eastern Europe	(384)	(46.38)	(1,149)	(112.51)	(1,711)	(74.41)	(3,488)	(101.12)
International	(8,962)	(3.41)	(17,358)	(6.38)	(46,696)	(4.86)	(65,585)	(6.53)

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

Royalties decreased on a dollar and per unit basis for the three months and year ended December 31, 2023 versus the comparable prior period primarily due to lower pricing, lower sales volumes, and adjustments for prior period royalties in Germany.

Transportation

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
France	(5,745)	(12.80)	(4,589)	(7.05)	(24,511)	(9.39)	(20,100)	(7.31)
Germany	(3,486)	(7.99)	(3,621)	(6.53)	(13,333)	(7.11)	(9,751)	(4.69)
Ireland	(1,059)	(1.08)	(752)	(1.88)	(7,098)	(2.28)	(3,578)	(2.14)
International	(10,290)	(3.91)	(8,962)	(3.29)	(44,942)	(4.68)	(33,429)	(3.33)

Transportation expense increased on a dollar and per unit basis for the three months and year ended December 31, 2023 versus the comparable prior periods primarily due to increased volumes in Ireland on acquisition production, and higher vessel costs in France. In addition to the above, for the year ended December 31, 2023, transportation expenses increased due to tariff adjustments in Germany.

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

Operating expense

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Australia	(10,677)	(42.17)	(21,291)	(31.23)	(52,360)	(206.80)	(57,478)	(38.50)
France	(17,021)	(37.93)	(12,638)	(19.41)	(80,134)	(30.71)	(57,588)	(20.94)
Netherlands	(9,143)	(18.19)	(11,229)	(26.44)	(39,157)	(22.50)	(45,903)	(22.82)
Germany	(8,233)	(18.87)	(13,292)	(23.96)	(43,857)	(23.39)	(41,523)	(19.96)
Ireland	(13,948)	(14.20)	(4,687)	(11.74)	(39,464)	(12.69)	(16,580)	(9.92)
Central and Eastern Europe	(547)	(66.06)	(416)	(40.74)	(1,568)	(68.19)	(1,691)	(49.03)
International	(59,569)	(22.64)	(63,553)	(23.35)	(256,540)	(26.69)	(220,763)	(21.99)

Operating expenses decreased for the three months ended December 31, 2023 primarily due to reduced volume driven costs on lower sales in Australia due to downtime and fuel and electricity savings in Germany, partially offset by increased working interest acquired in Ireland, and higher electricity costs in France.

Operating expenses increased for the year ended December 31, 2023 versus the prior comparable periods. On a dollar basis, increases were primarily due to the increased working interest acquired in Ireland, higher electricity costs in France, and increased processing fees in Germany and the Netherlands, partially offset by fuel and electricity savings in Germany and the Netherlands. On a per unit basis, the increase was primarily attributable to the shut-in of our Wandoo platform in Australia for maintenance, resulting in limited production as the platform resumed operations in early September and increased electricity rates in France.

Vermilion Energy Inc.  ■  Page 16  ■  2023 Management's Discussion and Analysis

Consolidated Financial Performance Review

($M except per share)	Dec 31, 2023	Dec 31, 2022	Dec 31, 2021
Total assets	6,235,821	6,991,058	5,905,323
Long-term debt	914,015	1,081,351	1,651,569
Petroleum and natural gas sales	2,022,555	3,476,394	2,079,761
Net (loss) earnings	(237,587)	1,313,062	1,148,696
Net (loss) earnings per share
Basic	(1.45)	8.03	7.13
Diluted	(1.45)	7.80	6.97
Cash dividends ($/share)	0.40	0.28	—

Financial performance

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	522,969	68.64	842,693	103.99	2,022,555	67.10	3,476,394	111.95
Royalties	(45,148)	(5.93)	(68,303)	(8.43)	(191,694)	(6.36)	(306,017)	(9.85)
Transportation	(22,441)	(2.95)	(21,976)	(2.71)	(88,856)	(2.95)	(78,896)	(2.54)
Operating	(116,937)	(15.35)	(136,247)	(16.81)	(513,381)	(17.03)	(489,034)	(15.75)
General and administration	(19,810)	(2.60)	(13,344)	(1.65)	(80,716)	(2.68)	(57,677)	(1.86)
Corporate income tax expense	(19,374)	(2.54)	(41,958)	(5.18)	(91,932)	(3.05)	(208,153)	(6.70)
Windfall taxes	(249)	(0.03)	(222,859)	(27.50)	(78,426)	(2.60)	(222,859)	(7.18)
PRRT	20,860	2.74	(5,045)	(0.62)	20,860	0.69	(18,318)	(0.59)
Interest expense	(22,909)	(3.01)	(22,506)	(2.78)	(85,212)	(2.83)	(82,858)	(2.67)
Realized gain (loss) on derivatives	78,737	10.33	(43,940)	(5.42)	234,365	7.77	(405,894)	(13.07)
Realized foreign exchange (loss) gain	(5,529)	(0.73)	18,845	2.33	(4,532)	(0.15)	15,195	0.49
Realized other income (expense)	1,948	0.26	(1,140)	(0.14)	(420)	(0.01)	12,982	0.42
Fund flows from operations	372,117	48.83	284,220	35.08	1,142,611	37.90	1,634,865	52.65
Equity based compensation	(7,871)		(5,377)		(42,756)		(44,390)
Unrealized gain on derivative instruments (1)	141,126		549,693		179,707		540,801
Unrealized foreign exchange gain (loss) (1)	4,834		(47,405)		12,438		(84,464)
Accretion	(19,469)		(16,501)		(78,187)		(58,170)
Depletion and depreciation	(259,012)		(171,926)		(712,619)		(577,134)
Deferred tax recovery (expense)	110,758		(196,733)		190,193		(288,707)
Gain on business combination	(5,607)		—		439,487		—
Loss on disposition	(125,539)		—		(352,367)		—
Impairment (expense) reversal	(1,016,094)		—		(1,016,094)		192,094
Unrealized other income (expense) (1)	1,621		(563)		—		(1,833)
Net (loss) earnings	(803,136)		395,408		(237,587)		1,313,062

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

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

General and administration

● General and administration expense increased for the three months and year ended December 31, 2023 versus the prior year comparable periods primarily due to increased activity and expected cash settlement of previously share-based settled expenses.

Vermilion Energy Inc.  ■  Page 17  ■  2023 Management's Discussion and Analysis

PRRT and corporate income taxes

● PRRT for the three months and year ended December 31, 2023 decreased versus the comparable prior periods due to downtime in Australia resulting in PRRT recoveries from lower taxable income.

● Corporate income taxes for the three months and year ended December 31, 2023 decreased versus the comparable prior periods primarily due to lower taxable income as a result of decreased commodity prices in 2023.

Windfall taxes

● Windfall taxes are the temporary taxes levied pursuant to the European Union’s temporary solidarity contribution. The contribution set out minimum amounts to be calculated on taxable profits starting in 2022 and/or 2023, which are above a 20% increase of the average yearly taxable profits for 2018 to 2021. For the two-year period of this policy Vermilion incurred $301 million of incremental taxes.

Interest expense

● Interest expense was consistent for the three months ended December 31, 2023 versus the comparable prior period.

● Interest expense increased for the year ended December 31, 2023 versus the comparable prior period primarily due to an increase in the percentage of our debt with fixed interest rates following the issuance of the 2030 senior unsecured notes, combined with the impact of a weaker Canadian Dollar on US Dollar interest payments.

Realized gain or loss on derivatives

● For the three months and year ended December 31, 2023, we recorded realized gains on our natural gas hedges due to lower commodity pricing compared to the strike prices.

● A listing of derivative positions as at December 31, 2023 is included in “Supplemental Table 2” of this MD&A.

Realized other income or expense

● In the 2022 periods, realized other income related to amounts for the funding under the Saskatchewan Accelerated Site Closure program. In the 2023 periods, realized other expense included insurance proceeds received related to insurance claims, offset by miscellaneous transaction costs and other provisional charges.

Net (loss) earnings

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

Equity based compensation

Equity based compensation expense relates primarily to non-cash compensation expense attributable to long-term incentives granted to directors, officers, and employees under security-based arrangements. Equity based compensation expense decreased for the year ended December 31, 2023 versus the comparable prior period primarily due to the lower value of LTIP awards outstanding in the current period and lower bonuses under the employee bonus plan in the current period.

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.

For the three months ended December 31, 2023, we recognized a net unrealized gain on derivative instruments of $141.1 million. This consists of unrealized gains of $73.4 million on our European natural gas commodity derivative instruments, $52.8 million on our North American crude oil derivative instruments, $25.9 million on our North American gas commodity derivative instruments and $3.6 million on our USD-to-CAD foreign exchange swaps, partially offset by losses of $14.6 million on our equity swaps.

For the year ended December 31, 2023, we recognized a net unrealized gain on derivative instruments of $179.7 million. This consists of unrealized gains of $154.0 million on our European natural gas commodity derivative instruments, $29.2 million on our North American crude oil derivative instruments, $24.7 million on our North American natural gas commodity derivative instruments and $1.7 million on our USD-to-CAD foreign exchange swaps, partially offset by losses of $29.9 million on our equity swaps.

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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 2023, unrealized foreign exchange gains and losses primarily resulted from:

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

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

For the three months ended December 31, 2023, we recognized a net unrealized foreign exchange gain of $4.8 million, primarily driven by the effects of the US dollar weakening 2% against the Canadian dollar on our USD senior notes partially offset by the Euro strengthening 2% against the Canadian dollar in Q4 2023 on our intercompany loans. For the year ended December 31, 2023, we recognized a net unrealized foreign exchange gain of $12.4 million, primarily driven by an unrealized gain on our USD senior notes.

Accretion

Accretion expense is recognized to update the present value of the asset retirement obligation balance. For the three months and year ended December 31, 2023, accretion expense increased versus the comparable prior periods primarily due to the impact of a higher asset retirement obligation balance at December 31, 2023 and the strengthening of the Euro against the Canadian dollar.

Depletion and depreciation

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

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

Depletion and depreciation on a per boe basis for the three months ended December 31, 2023 of $34.00 increased from $21.22 in the comparable prior period primarily due to higher future development costs increasing the depletable base, lower reserve estimates, and the strengthening of the Euro against the Canadian dollar, partially offset by the southeast Saskatchewan disposition completed at the end of Q1 2023 decreasing the depletable base.

Depletion and depreciation on a per boe basis for the year ended December 31, 2023 of $23.64 increased from $18.59 in the comparable prior period primarily due to higher future development costs increasing the depletable base, lower reserve estimates, acquisition activity, and 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.

For the year ended December 31, 2023, the Company recorded a deferred tax recovery of $190.2 million compared to a deferred tax expense of $288.7 million in the prior year period. The recovery recorded in the current year is primarily attributable to the Q1 2023 disposition of assets in southeast Saskatchewan and the impairment charges recorded in Saskatchewan, France, and United States cash generating units (“CGUs”).

Vermilion Energy Inc.  ■  Page 19  ■  2023 Management's Discussion and Analysis

Gain on business combination

On March 31, 2023, Vermilion purchased Equinor Energy Ireland Limited ("EEIL") from Equinor ASA. The acquisition adds an incremental 36.5% interest in the Corrib Natural Gas Project, increasing Vermilion's operated interest to 56.5%. The acquisition makes Vermilion the largest provider of domestic natural gas in Ireland.

The gain on the business combination primarily resulted from increases in working capital and the fair value of capital assets from when the purchase and sale agreement was entered into in November 2021 and when the acquisition closed in March 2023.

Loss on dispositions

In March 2023, Vermilion sold non-core assets in southeast Saskatchewan for net proceeds of $182.2 million. The book value of the net assets disposed of was $409.0 million resulting in a loss on disposition of $226.8 million.

In December 2023, Vermilion sold non-core assets in Wyoming for net proceeds of $16.3 million and resulted in a loss on disposition of $125.5 million. The book value of the net assets disposed of was $141.8 million and consisted of $142.5 million of capital assets and $0.7 million of asset retirement obligations.

Impairment

In the fourth quarter of 2023, indicators of impairment were present in our France CGU due to changes in forecasted cost assumptions and in our Saskatchewan and United States CGUs due to negative technical revisions. 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 13.0% for Saskatchewan and 15.0% for France and United States. Based on the results of the impairment tests completed, the Company recognized non-cash impairment charges of $1.0 billion. 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 and Germany. 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.

For 2023 and 2022, taxable income was subject to corporate income tax at the following statutory rates:

Jurisdiction	2023		2022
Canada	24.4	%	24.6	%
United States	21.0	%	21.0	%
France	25.8	%	25.8	%
Netherlands (1)	50.0	%	50.0	%
Germany	31.2	%	31.3	%
Ireland	25.0	%	25.0	%
Australia	30.0	%	30.0	%

⁽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.

Windfall Taxes

On October 6, 2022 the Council of the European Union adopted a regulation that implemented a temporary windfall tax on the profits of oil and gas producers resident in the European Union. This windfall tax was referred to as a temporary solidarity contribution and was calculated on the amount by which the taxable profits for the elected years exceeded the greater of zero and 120% of the average taxable profits for the 2018 to 2021 period. The regulation required Member States to implement the temporary solidarity contribution at a minimum rate of 33% while providing Member States with the option to apply the temporary solidarity contribution to fiscal years beginning on or after January 1, 2022, January 1, 2023, or both. The windfall tax does not apply to 2024 or later years.

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The following table summarizes the manner of implementation of the temporary solidarity contribution by the Member States in which Vermilion operates:

Jurisdiction	2023		2022
France (1)	N/A		33.0	%
Netherlands (2)	N/A		33.0	%
Germany	33.0	%	33.0	%
Ireland	75.0	%	75.0	%

(1) For 2022, France implemented a windfall tax; however, did not extend for 2023.

(2) For 2023 and 2024, Netherlands has implemented a windfall royalty which, for natural gas sales, is calculated as 65% of the excess of the realized price for a subject year versus the threshold price of €0.50/Nm3 (€13.40/mcf). This royalty is deductible against current income taxes.

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.

Most of the countries where Vermilion operates are in the process of enacting, or have enacted, tax legislation to comply with Pillar Two with effect from January 1, 2024. The Company expects that Pillar Two will not have a material impact on income tax expense.

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, 2023, we had the following tax pools:

($M)	Oil & Gas Assets		Tax Losses		Other	Total
Canada	1,511,948	(1)	1,385,458	(4)	28,433	2,925,839
United States	335,395	(2)	154,400	(6)	72,309	562,104
France	255,272	(2)	2,461	(5)	—	257,733
Netherlands	52,905	(3)	—		—	52,905
Germany	242,588	(3)	—		17,045	259,633
Ireland	—		1,512,603	(4)	—	1,512,603
Australia	157,455	(1)	133,480	(4)	—	290,935
Total	2,555,563		3,188,402		117,787	5,861,752

(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) Tax losses can be carried forward and are available to offset the first €1 million of taxable income and 50% of taxable profits in excess each taxation year.

(6) Tax losses of $49 million created prior to January 1, 2018 are carried forward and applied at 100% against taxable income, tax losses of $105 million created after January 1, 2018 are carried forward and applied to 80% of taxable income in 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 21  ■  2023 Management's Discussion and Analysis

As at December 31, 2023, we have a ratio of net debt to four quarter trailing fund flows from operations of 0.9. We will continue to monitor for changes in forecasted fund flows from operations and, as appropriate, will adjust our exploration, development capital plans (and associated production targets), and return of capital plans to target optimal debt levels.

Maintaining a strong balance sheet is a core principle of Vermilion and will remain a focus going forward. As debt reduction continues, we will plan to increase the amount of free cash flow that is available for the return of capital, while taking into account other capital requirements.

Net debt

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

	As at
($M)	Dec 31,2023	Dec 31,2022
Long-term debt	914,015	1,081,351
Adjusted working capital deficit (1)	164,552	265,111
Unrealized FX on swapped USD borrowings	—	(1,876)
Net debt	1,078,567	1,344,586
Ratio of net debt to four quarter trailing fund flows from operations	0.9	0.8

⁽¹⁾ Adjusted working capital is a non-GAAP financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers. It is defined as current assets less current liabilities, excluding current derivatives and current lease liabilities. The measure is used to calculate net debt, a capital measure disclosed above. Reconciliation to the primary financial statement measures can be found in the “Non-GAAP and Other Specified Financial Measures” section of this document.

As at December 31, 2023, net debt decreased to $1.1 billion (December 31, 2022 - $1.3 billion), due to debt repayments of  $146.3 million  funded by the disposition of our southeast Saskatchewan assets for $182.2 million and $552.4 million of free cash flow generated during the year offset by the acquisition of an additional 36.5% working interest in our operated Corrib project for $198.0 million (net of cash and working capital deficit acquired). The ratio of net debt to four quarter trailing fund flows from operations as at December 31, 2023 increased to 0.9 (December 31, 2022 - 0.8) due to lower four quarter trailing fund flows from operations, driven primarily by decreased commodity prices.

Long-term debt

The balances recognized on our balance sheet are as follows:

	As at
	Dec 31,2023	Dec 31,2022
Revolving credit facility	—	147,666
2025 senior unsecured notes	395,839	404,463
2030 senior unsecured notes	518,176	529,222
Long-term debt	914,015	1,081,351

Revolving Credit Facility

As at December 31, 2023, Vermilion had in place a bank revolving credit facility maturing May 29, 2027 with terms and outstanding positions as follows:

	As at
($M)	Dec 31,2023	Dec 31,2022
Total facility amount	1,600,000	1,600,000
Amount drawn	—	(147,666)
Letters of credit outstanding	(18,116)	(13,527)
Unutilized capacity	1,581,884	1,438,807

During the year, the maturity date of the facility was extended to May 28, 2027 (previously May 29, 2026) and the total facility amount of $1.6 billion was unchanged. As at December 31, 2023, there was no draw on the facility.

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As at December 31, 2023, the revolving credit facility was subject to the following financial covenants:

		As at
Financial covenant	Limit	Dec 31,2023	Dec 31,2022
Consolidated total debt to consolidated EBITDA	Less than 4.0	0.65	0.51
Consolidated total senior debt to consolidated EBITDA	Less than 3.5	—	0.07
Consolidated EBITDA to consolidated interest expense	Greater than 2.5	17.33	27.10

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

● Consolidated total debt: Includes all amounts 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) earnings 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.

In addition, our revolving credit facility has provisions relating to our liability management ratings in Alberta and Saskatchewan whereby if our security adjusted liability management ratings fall below specified limits in a province, a portion of the asset retirement obligations are included in the definitions of consolidated total debt and consolidated total senior debt. An event of default occurs if our security adjusted liability management ratings breach additional lower limits for a period greater than 90 days. As of December 31, 2023, Vermilion's liability management ratings were higher than the specified levels, and as such, no amounts relating to asset retirement obligations were included in the calculation of consolidated total debt and consolidated total senior debt.

As at December 31, 2023 and December 31, 2022, Vermilion was in compliance with the above covenants.

2025 senior unsecured notes

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

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

Subsequent to March 15, 2023, Vermilion may redeem some or all of the senior unsecured notes at a 100.000% redemption price plus any accrued and unpaid interest.

2030 senior unsecured notes

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

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

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

● 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.

● Prior to May 1, 2025, Vermilion may redeem up to 35% of the original principal amount of the notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the notes, together with accrued and unpaid interest.

● Prior to May 1, 2025, Vermilion may also 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.

Vermilion Energy Inc.  ■  Page 23  ■  2023 Management's Discussion and Analysis

Year	Redemption price
2025	103.438	%
2026	102.292	%
2027	101.146	%
2028 and thereafter	100.000	%

Shareholders' capital

The following table outlines our dividend payment history:

Date	Frequency	Dividend per unit or share
January 2003 to December 2007	Monthly	$	0.170
January 2008 to December 2012	Monthly	$	0.190
January 2013 to December 2013	Monthly	$	0.200
January 2014 to March 2018	Monthly	$	0.215
April 2018 to February 2020	Monthly	$	0.230
March 2020	Monthly	$	0.115
April 2022 to July 2022	Quarterly	$	0.060
August 2022 to March 2023	Quarterly	$	0.080
April 2023 onwards	Quarterly	$	0.100

In December 2023, we announced our plan to increase the quarterly dividend by 20% to $0.12 per share effective for the planned Q1 2024 distribution.

The following table reconciles the change in shareholders’ capital:

Shareholders’ Capital	Shares ('000s)	Amount
Balance at January 1	163,227	4,243,794
Vesting of equity based awards	3,657	23,575
Shares issued for equity based compensation	655	11,242
Share-settled dividends on vested equity based awards	64	1,179
Repurchase of shares	(5,332)	(137,224)
Balance at December 31	162,271	4,142,566

As at December 31, 2023, there were approximately 4.5 million equity based compensation awards outstanding. As at March 6, 2024, there were approximately 160.8 million common shares issued and outstanding.

On July 10, 2023, the Toronto Stock Exchange approved our notice of intention to renew our normal course issuer bid ("the NCIB"). The NCIB renewal allows Vermilion to purchase up to 16,308,587 common shares (representing approximately 10% of outstanding common shares) beginning July 12, 2023 and ending July 11, 2024. Common shares purchased under the NCIB will be cancelled.

In the fourth quarter of 2023, Vermilion purchased 1.7 million common shares under the NCIB for total consideration of $29.0 million. The common shares purchased under the NCIB were cancelled.

Contractual Obligations and Commitments

As at December 31, 2023, 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)	58,690	480,682	72,743	583,597	1,195,712
Lease obligations (2)	58,034	80,281	53,839	43,907	236,061
Processing and transportation agreements	42,127	54,205	27,493	151,777	275,602
Purchase obligations	32,087	13,519	2,374	105	48,085
Drilling and service agreements	18,572	49,784	—	—	68,356
Total contractual obligations and commitments	209,510	678,471	156,449	779,386	1,823,816

⁽¹⁾ Includes interest on senior unsecured notes.

Vermilion Energy Inc.  ■  Page 24  ■  2023 Management's Discussion and Analysis

⁽²⁾ Includes undiscounted IFRS 16 - Leases obligations of $59.7 million recognized in the financial statements as at December 31, 2023, future undiscounted IFRS 16 - Leases due to commence in 2024 of $117.5 million, and surface lease rental commitments of $56.5 million and other of $2.4 million that are not considered leases under IFRS 16 and are not represented on the balance sheet.

⁽³⁾ Commitments denominated in foreign currencies have been translated using the related spot rates on December 31, 2023.

Asset Retirement Obligations

As at December 31, 2023, asset retirement obligations were $1,159.1 million compared to $1,087.8 million as at December 31, 2022. The increase in asset retirement obligations is primarily attributable to the Company's lower credit spread at December 31, 2023 compared to December 31, 2022 and the acquisition of an additional 36.5% working interest in our Corrib project, partially offset by the disposition of our southeast Saskatchewan assets. The credit spread decreased to 3.6% at December 31, 2023 compared to 4.5% at December 31, 2022 due to a lower expected cost of borrowing.

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

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

	12/31/2023		12/31/2022		Change
Credit spread added to below noted risk-free rates	3.6	%	4.5	%	(0.9)	%
Country specific risk-free rate
Canada	3.0	%	3.3	%	(0.3)	%
United States	4.2	%	4.1	%	0.1	%
France	3.0	%	3.4	%	(0.4)	%
Netherlands	2.1	%	2.7	%	(0.6)	%
Germany	2.3	%	2.5	%	(0.2)	%
Ireland	2.7	%	3.2	%	(0.5)	%
Australia	4.0	%	4.2	%	(0.2)	%

Current cost estimates are inflated to the estimated time of abandonment using inflation rates of between 1.3% and 5.5% (as at December 31, 2022 - between 1.6% and 4.2%).

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. These risks and uncertainties are discussed further below.

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) earnings 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.

Vermilion Energy Inc.  ■  Page 25  ■  2023 Management's Discussion and Analysis

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.

Windfall taxes and royalties

Vermilion is exposed to increased taxation and royalties due to windfall taxes on profits. Windfall taxes have been substantively enacted within the European Union for oil and gas companies for 2022 and/or 2023 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.

Ukraine war / Middle East conflict

During 2022, Russian military forces invaded Ukraine resulting in a war between the two countries. The ongoing conflict between countries has impacted the supply of oil and gas from the region and has resulted in countries throughout the world imposing financial and trade sanctions against Russia which have had macroeconomic effects. The risks disclosed in our Annual Information Form for the year ended December 31, 2023 may be exacerbated as a result of the Ukraine war, 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 Ukraine war, hostilities in the Middle East could adversely affect the global economy and impact oil and gas prices.

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.

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

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 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.

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The carrying amount of asset retirement obligations

The carrying amount of asset retirement obligations ($1,159.1 million as at December 31, 2023) 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 $34.0 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 $70.1 million.

The fair value of capital assets acquired in business combinations

In preparing the purchase price allocation for the business combinations completed in 2023, we estimate the fair value of assets acquired. Assets acquired in an acquisition primarily relates 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 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, 2023, the deferred tax asset balance of $182.1 million relates to Ireland and Canada for $105.3 million and $76.8 million, respectively.

In Ireland, we have $237.1 million of non-expiring tax loss pools where $59.3 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 $136.9 million of non-expiring oil and gas tax pools where $33.4 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 2023, indicators of impairment were present in our France CGU due to changes in forecasted cost assumptions and in our Saskatchewan and United States CGUs due to negative technical revisions. 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

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future after-tax cash flows from proved plus probable reserves and an after-tax discount rate of 13.0% for Saskatchewan and 15.0% for France and United States. Based on the results of the impairment tests completed, the Company recognized non-cash impairment charges of $1.0 billion. 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 $80.1 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 $187.8 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

Vermilion did not adopt any new accounting pronouncements as at December 31, 2023.

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"

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

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

Health, Safety and Environment

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 a high-reliability 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 2023 we:

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

● 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 and corrective actions effectively implemented;

● Worked towards fulfilling our updated 2030 HSE Strategy;

● Developed a 2023 Top Quartile HSE Performance Plan;

● Completed Business Unit implementation plans as part of our Process Safety Management System implementation;

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

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● Advanced our Energy Safety Canada and International Oil and Gas Producers Life-Saving Rules implementation and competency development;

● Submitted our CDP Climate and Water reports;

● 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)

As an international company, Vermilion responsibly produces essential energy while delivering long-term value to our stakeholders. We believe that integrating sustainability principles into our business increases shareholder returns, enhances development opportunities, reduces long-term risks, and supports the well-being of key stakeholders including the communities in which we operate.

Vermilion has established a leadership position in sustainability performance and disclosure, launching our first CDP Climate submission and Sustainability Report in 2014, with data to 2012, aligned with the Global Reporting Initiative (GRI). We have since adopted recommendations from the Task Force on Climate-related Financial Disclosure (TCFD), the Sustainability Accounting Standards Board (SASB), and the International Sustainability Standards Board (ISSB).

In particular, we have applied the TCFD framework in the management of climate- and other sustainability-related risks and opportunities. This recognizes the importance of climate-specific disclosure while reflecting its intersection with other environment-related risks and opportunities, social factors such as safety and community engagement, and governance issues. Our Index follows:

● Governance	Information Circular
● Strategy	Annual Report MD&A
● Risk Management	Annual Report MD&A
● Metrics and Targets	Annual Report MD&A
● Consolidated Climate (TCFD) Report	www.vermilionenergy.com/sustainability/reports/

Sustainability and Climate-Related Strategy

Vermilion understands our stakeholders’ expectations that we deliver strong financial results in a responsible and ethical way. As a result, we align our strategic priorities in the following order:

● the safety and health of our staff and those involved directly or indirectly in our operations;

● our responsibility to protect the environment. We follow the Precautionary Principle introduced in 1992 by the United Nations "Rio Declaration on Environment and Development" by using environmental risk as part of our development decision criteria, and by continually seeking improved environmental performance in our operations; and

● economic success through a focus on operational excellence across our business, which includes technical and process excellence, efficiency, expertise, stakeholder relations, and respectful and fair treatment of staff, contractors, partners and suppliers.

Reflecting these priorities, we have positioned Vermilion purposefully within the energy transition. Our scenario analysis has consistently demonstrated that Vermilion can best contribute by focusing on producing energy responsibly: safely, reliably and cost-effectively. Our Sustainability Report provides further details at: www.vermilionenergy.com/sustainability.

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

Given the intersection of environmental and social issues, and their impact over varying timeframes, we have identified climate-related risks and opportunities within short-term (0-3 years), medium-term (3-6 years) and long-term (6-50 years) horizons. We describe these below, along with their potential company and financial impact (assessed using processes such as scenario analysis, cost projections and our Emissions Long-Range Planning tool), and our resulting management approach, including operations such as equipment upgrade, and capital allocation. Our annual CDP Climate Change and Water Security submissions provide additional information, including where in the value chain these risks and opportunities occur: see www.vermilionenergy.com/sustainability/reports/.

Category / Issue	Description of Impacts	Potential Financial Impact	Management Approach
Short-term Transition Risks (0-3 Years)
Policy and Legal: Increased Pricing of GHG Emissions e.g. Carbon Tax	Short-term impact is primarily in Canada and Ireland. Canadian Federal Greenhouse Gas Pollution Pricing Act has set carbon tax rates at $65 per tCO2e in 2023, rising to $170 by 2030, with provincial responses to keep pace with the federal system. Our Ireland operations are subject to the EU ETS and Ireland Carbon Tax systems. Longer-term impact rests on carbon pricing’s vulnerability to changes in government policy.	With our recent northeast British Columbia acquisition, our Canadian carbon tax liability is forecast at approximately $1.6MM in the near term. Our Ireland EU ETS liability is forecast at approximately $2.6MM in 2025 and $3.5MM in 2030. The Ireland Carbon Tax liability is expected to be an additional approximately $0.1MM/year over this period. All estimates are net Vermilion.	Our exposure is mitigated by provincial responses to the Act, including Alberta's Technology Innovation and Emissions Reduction (TIER) regulation and Output-Based Pricing Systems (OBPS) in Saskatchewan and forthcoming in British Columbia. Our ongoing efforts to reduce the energy and emissions intensity of our operations are integral to managing this risk, including our emission reduction targets. Vermilion continues to monitor and comply with taxation requirements.
Policy and Legal: Enhanced Emissions & Other ESG Reporting Obligations	Climate and other ESG reporting obligations are evolving rapidly, with Vermilion potentially subject to the IFRS Sustainability Standards (2025) and European Sustainability Reporting Standards (2028), U.S. Securities and Exchange Commission and Canadian Securities Administrators Climate-Related Disclosure Rules, and Canada's Modern Slavery Act. Although Vermilion's existing sustainability-related disclosure provides a sound foundation for compliance, there are costs to implement these, particularly potential requirements for increased levels of audit. The impact to Vermilion would be a decreased netback per BOE, due to increased expenses for staff time and system development and implementation.	The financial impact is an increase in operational cost associated with the management and quantification of emissions to meet new reporting requirements, and the administrative costs associated with reporting and audit obligations. This is estimated at $0.8MM annually.	Regulations in all of our business units are monitored on an ongoing basis, and assumptions/ scenario planning is used annually to assess risk. In Canada, we implemented an external emission data gathering software in 2021 to support the evolving regulatory landscape. Vermilion also engages stakeholders relating to emissions reporting obligations. Management of this risk is built into Vermilion's operations and our ERM. In addition, we expect to automate our emissions data gathering, aggregation and calculation processes in 2024, while ensuring audit-ready processes for all ESG data points to align with proposed regulatory requirements.
Policy and Legal: Changes in Mandates/Regulations re Products - Existing Production or Acquisition Impaired by Regulatory or Political Changes	Vermilion's operations are subject to regional regulatory changes that result in changes to equipment requirements such as engineering and equipment modifications to reduce carbon emissions and / or emissions of criteria air contaminants. The most likely short-term impact is regulations in Canada to reduce methane emissions, in France to reduce flaring and in Netherlands to reduce NOx. From a macro perspective, geopolitical impacts (e.g. war in Ukraine) have escalated diverging government and consumer viewpoints on the need for energy security vs energy transition. We expect demand for oil and natural gas to remain strong in the short term, while safety and environmental regulations governing its production will increase.	Operational changes to comply with existing methane reduction regulations are expected at approx. $1.5MM in the short term, with those associated with eliminating routine flaring in France subject to continuing review in 2024. The cost of compliance with proposed regulations, such as Canada's proposed regulatory framework for reducing oil and gas methane emissions to achieve a 75% reduction by 2030 is not yet established, and will depend on the final version of the framework.	Vermilion is closely monitoring regulatory and market changes to ensure its approach to resilience under evolving conditions remains appropriate. We provide feedback to governments on proposed regulations, as per our lobbying disclosures, and allocate resources, including staff and capital, to ensure that required operational changes can be effectively actioned. In the short term, tying in vented equipment to flaring infrastructure in Canada is an example of projects to address this risk; in Netherlands we have used NOx scrubbers and purchased NOx certificates to comply with new regulations. Our ongoing efforts to proactively reduce the energy and emissions intensity of our operations are integral to managing this risk, including our announcement of two emission reduction targets in 2021, and our work in 2023 to establish a net zero transition plan and 2030 emissions reduction target, which we expect to release in 2024. We are also working with external partners to further implement and develop emission reduction technologies that are economic to the Company, in part due to the potential generation of carbon credits. Based on stakeholder engagement, Vermilion believes that independent assessments of our operations by third parties are an important tool to demonstrate our responsible approach to production of essential energy. As a result, we have sought and achieved Equitable Origin responsible gas producer certification for 4 of our Canadian sites, the AFNOR CSR Committed label in France, and the Business Working Responsibly mark in Ireland.

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Category / Issue	Description of Impacts	Potential Financial Impact	Management Approach
	We have identified these risks as interconnected and existing in the short-term; however, they should be seen as medium- to long-term risks as well.
Reputation: Shareholder Divestment	Investors are raising concerns regarding risks related to emissions, environmental and biodiversity protection, water stewardship, and abandonment and reclamation liabilities.	Impact of divestment is estimated to be equal to 0.25X of 2023E FFO reducing market capitalization by $286MM. This estimate covers all significant sustainability risk scenarios including but not limited to water stewardship, biodiversity, modern slavery, and community relations.	In addition to our net zero transition plan development, we have set public targets to reduce ARO liabilities and internal targets to maintain freshwater intensity performance via water management plans where higher-intensity freshwater use is, or could become, an issue. We are also prioritizing compliance with incoming sustainability reporting requirements, which are largely investor- and financial institution-driven, and are actively engaging with investors to understand and respond to their concerns.
Reputation: Changes in Customer Behaviour and Legal Challenges	Government and community relationships are strongly linked to both social and regulatory licenses to operate. Communities where we operate also bear potential impacts, including noise, dust, lights, traffic, etc. Legal challenges against oil and gas industry are increasing, while adoption of EVs and opposition to fossil fuels reflects customer sentiment in some areas. Windfall tax/solidarity contributions are possible during times of particularly high commodity prices.	The impact of delays or shutdowns would be measured in terms of production per day, impacting revenues. The impact of the 2022-2023 EU windfall tax is already decreasing, to $78MM in 2023 under lower commodity pricing, with the EU signalling that it will not be extended.	We implemented our Non-technical Risk Management Policy and framework in 2023, providing guidelines for community/social impact assessments, along with our well-established strategic community investment program, Ways of Caring. We also implemented our Lobbying policy in 2023, guiding our engagement with governments, including on specific issues such as windfall tax.
Medium-term Transition Risks (3-6 Years)
Technology	Our emission reduction projects and net zero transition plan rely on technologies that are rapidly evolving, but in many cases unproven at larger scales and uneconomic for dispersed assets that are not, for example, near an electrical grid or pipeline gathering system. Assumptions by those outside the industry that broad generalizations on methane reduction are economical for all assets may be proven false. Some technology projects will fail; others will prove uneconomic.	Based on the capital and/or operating spend required to reduce our near-term carbon tax liability through emission reduction projects, this will be calculated as part of the net zero transition plan.	We are mitigating this risk through a careful and deliberate approach to new technology adoption. We have established sustainability project criteria that need to be met in order to move into the Vermilion Opportunity Development Process, providing various stage gates and off-ramps.
Market: Increased costs related to capital and financing	Pressure from stakeholders to limit access to, or increase the cost of, debt, capital or insurance without the use of sustainability-linked financing arrangements	A 100 bps increase to total debt would represent $10MM	We have established 2 emission reduction targets and 1 ARO target, and are developing our net zero transition plan and 2030 emission reduction target, which establish the foundation for sustainability-linked financing should it be required.

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Category / Issue	Description of Impacts	Potential Financial Impact	Management Approach
Medium-term Physical Risks (3-6 Years)
Acute: Increased Severity of Extreme Weather Events such as Cyclones and Floods	Vermilion's Wandoo field off northwestern Australia, Corrib project off the Irish coast and oil fields in the coastal area of SW France can be impacted by extreme weather events such as cyclones, resulting in down time or damage to infrastructure. Such events can also impact the downstream handling capacity of our partners, resulting in a limitation to the distribution and sale of our products.	Based on the value of the Wandoo Platform and a 1-in-10,000-year cyclonic event, the financial implications associated with damage due to a severe weather event is estimated at $274MM (total impact before insurance). The third-party costs associated with potential damages from extreme weather events are not tracked.	Vermilion maintains insurance as a mitigative measure to reduce the financial impact associated with damage to our assets due to severe weather events. We also have a robust asset integrity program that maintains our offshore facilities to their original design specifications of CAT 5 hurricane force. We also have protocols for monitoring and preparing for cyclones, and have invested in our emergency response capabilities in the event of damage to our assets due to severe weather.
Long-term Transition Risks (6-50 Years)
Technology: Substitution of existing products and services with lower emissions options, including market supply and demand	Although we see demand for oil and natural gas remaining robust in the short- to mid-term, it is likely that demand for oil and, to a lesser degree, natural gas will eventually fall as the energy transition evolves and various alternatives for renewable energy options become technologically and economically available. This could impact the need for our products in the longer term, post 2030 for oil and even further out for natural gas. As the past several years have demonstrated, it will be critical to maintain adequate supplies of both oil and natural gas during the energy transition, to provide both accessibility and affordability.	Given the uncertain timeline and progression of the energy transition, and supply-demand dynamics, we are not using a financial forecast for impact. We are, however, using our scenario analysis to identify potential opportunities that would mitigate the risk to our products.	Based on our scenario analysis, we identified the need to explore new and evolving technologies and processes to identify synergistic fits for our business in both traditional and renewable energy production. We are pursuing this via our established track record in geothermal energy from produced water, for which our internal expertise in engineering, geoscience and drilling is particularly well suited. We are also investing in early R&D in other areas, such as biogas and the conversion of traditional oil and gas assets to geothermal and hydrogen production, to better understand the long-term potential.
Long-term Physical Risks (6-50 Years)
Chronic: Changes in Temperature Extremes, Including Rising Mean Temperatures; Changes In Precipitation Patterns and Extreme Variability in Weather Patterns	Chronic Physical: Based on RCP4.5, which limits warming to 3C (overshooting 1.5-2C), our assets and operations could experience climate changes between 2041 and 2070 such as: North America: 2-3C increase, 12-14% increased precipitation, 7-8% increased aridity, >10 fewer frost days and <25% decrease in number of dry spells. Europe: 1-2C increase, 0-5% increased precipitation, 4-12% increased aridity, generally decreased frost days, with several areas seeing <25% increase in number of dry spells. Australia: 1C increase; 8% increased precipitation (SMHI, Climate Information, https://climateinformation.org/, last accessed: 9 July 2023). Overall warming temperatures, greater precipitation and generally drier conditions (due to increased evaporation) may increase capital costs for drilling, completion and workover operations due to increased timelines, equipment breakdown and restricted access in North America (fewer frost days). They may also impact the health and safety of workers, and create variability and potentially more severe weather events such as flooding, drought and wild fires. Flooding could result in limited access to locations; droughts could impact the availability of surface and / or groundwater required for drilling and completion. This could negatively impact growth by increasing timelines and capital costs to bring on new production.	The financial implications of a single time event (i.e. wildfire) have been assessed on a case-specific basis. Vermilion maintains insurance to mitigate the potential impact of precipitation-related extreme events (i.e. Wild fire, Flooding)	Each of our assets is assessed for potential risks and hazards, including those associated with weather events, from lightning to flooding to wild fires. These risks are reviewed at least annually on a case-by-case basis as part of our Enterprise Risk Management system. Mitigation approaches such as clearance of vegetation around facilities, and physical barriers to flooding, are implemented as per our HSE Management System, to protect the health and safety of our workers, contractors and the public, and to protect the environment.

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Category / Issue	Description of Impacts	Potential Financial Impact	Management Approach
Chronic: Rising Sea Levels	Chronic Physical: Potential rising sea levels could impact our Netherlands assets and operations due to issues such as flooding, transportation difficulties, supply chain interruptions and salinization of groundwater.	We have estimated that a rise in sea level could have a financial impact of $571MM before insurance at our main gas processing facility Garijp (GTC) in the Netherlands, caused by an extreme 1-in-10000-years tide/extreme wind event.	Physical measures such as conventional berms may not provide complete protection. Based on Vermilion's assessment of less than 0.05% probability over the next 5 years we have accepted this level of risk, reviewing it annually.
Short-term Opportunities (0-3 Years)
Products and Services, and Resilience: Development of New Products and Services through R&D and Innovation; participation in renewable energy programs	Directly related to the long-term transitional risk associated with the substitution of low-carbon products, we have the opportunity to participate in the development of those products. This has the potential to reuse our current infrastructure to provide alternative products, such as biogas or hydrogen, or to develop new products such as geothermal energy, creating new revenue streams.	As this opportunity is in the early stage of assessment, it is difficult to quantify the financial impact, but it is estimated at up to $2.0MM per year in revenue and returns on investment. Potential also exists for significant cost adjustments, as assets slated for abandonment would be repurposed to enable them to continue to generate energy.	We are leveraging our technical experts and partnerships to provide input into alternative and renewable energy projects as they are identified. An example of the development of low emission goods/services is our France-based industry partnership with Avenia to expand the use of geothermal energy production in oil production, and a geothermal association in Germany. We have also developed criteria for approving the move of these ideas into our Vermilion Opportunity Development Process, which provides clear gates and criteria for considering and implementing such projects.
Products and Services: Access to New Markets	More stringent global measures to reduce emissions from individual ships by 30% by 2030, established through amendments to MARPOL Annex VI, came into force on Jan 1 2020, limiting the sulphur content of bunker fuel to a maximum of 0.5%. Vermilion’s Australian Wandoo facility produces 4500 bbl/d of low sulphur crude oil that meets the needs of refineries in the short term to meet IMO regulations.	Vermilion conservatively foresees achieving a premium of $10/bbl for its Wandoo production over the next three years for cumulative incremental revenue of $49.3MM.	Vermilion continues to access local markets for our low sulphur production, while exploring regions to expand our operations. Our Marketing group ensures that Vermilion meets its contractual obligation with our buyers in terms of volumes, delivery dates and crude quality.
Medium-term Opportunities (3-6 Years)
Products and Services: Ability to Diversify Business Activities; Shift in Consumer Preferences	Vermilion maintains a diverse, stable global portfolio of oil and gas assets. Our strong record of safe and socially conscious development of energy resources has provided opportunities to access and develop these resources. We see our commitment to sustainability as core to our business, which has provided important organizational focus on emissions quantification and management. As consumers become more aware of and involved in the selection of their energy sources and associated carbon intensity, we believe that Vermilion will continue to be a top quartile choice, providing us with opportunities not available to peer organizations.	The financial impact of changing consumer preferences in difficult to quantify. We foresee revenue opportunities in two distinct areas. (1) In consumers selecting premium energy products, with these products demanding a higher price than other energy sources on the market; commodity pricing volatility now makes this difficult to estimate (2) Access to more stringent markets, supported by our environmental and sustainability performance. Vermilion has entered into German, Hungarian, Croatian and Slovak oil and gas operations, which our sustainability performance has supported.	Based on stakeholder engagement, Vermilion believes that independent assessments of our operations by third parties are an important tool to demonstrate our responsible approach to production of essential energy, and generate premium. As a result, we have sought and achieved Equitable Origin responsible gas producer certification for 4 of our Canadian sites, the AFNOR CSR Committed label in France, and the Business Working Responsibly Mark in Ireland. We are currently assessing the potential to expand these certifications.

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Category / Issue	Description of Impacts	Potential Financial Impact	Management Approach
Long-term Opportunities (6-50 Years)
Products and Services: Shift in Consumer Preferences	Under the Canadian Environmental Protection Act and based on commitments made by the Canadian and Alberta governments and energy utilities relating to COP21, there is a commitment to reduce emissions for coal-fired power generation. Based on this and with a number of power generating facilities in Alberta nearing the end of their service life, the demand for natural gas is likely to increase due to increased use of combined cycle gas turbine (CCGT) power generation.	The short term impact of this regulatory change on gas pricing is anticipated to be low and increase to medium in the mid- to long-term. As a natural gas and oil producer, Vermilion would benefit from an increase in marketable prices for natural gas in our Canadian operations.	As we move further into the energy transition, we foresee natural gas playing an impactful role as a less carbon intense fuel than other options (i.e. coal). Vermilion continues to focus on the identification of resources and assets where we have the opportunity to apply our industry leading expertise to optimize production while reducing emissions. An example of our strategy to realize this opportunity is our asset base in Alberta, which currently includes a large liquids rich gas play, and our entry into the Montney in northeast British Columbia. Vermilion's marketing team is also actively pursuing options for our natural gas production that will enable Vermilion to achieve the best netbacks on production.
Energy Source: Shift Toward Decentralized Energy Generation	The carbon intensity of energy used around the world has a direct relationship to where the energy product was generated. Vermilion’s business unit structure supports production and distribution of energy products into local markets. This strategy results in the significant reduction of the carbon footprint of our energy when compared to non-local sources.	The long-term financial impact of decentralized energy generation will depend on the speed of the energy transition balanced against the need for energy security. As such, we believe it is not possible to predict the financial impact at this time.	Vermilion continues to assess where we can access local markets for our production, while exploring regions to expand our operations. The actions taken in the past several years to realize this opportunity include alterations to our structure, our strategic objectives and our operational development plans to support Vermilion as a distributed energy provider, and exploration and development programs in regions with relatively low energy production as compared to consumption.

Resilience of the Company’s Strategy

Countries in all of our operating regions are implementing policies to create a low-carbon future for the world’s economy, consistent with a 1.5-2C or lower scenario. As a global energy producer, we contribute to the supply of safe, reliable and affordable energy during this transition. The Board of Directors and senior leadership therefore responded to our risk and opportunity identification using a robust scenario analysis.

Vermilion initially examined two energy transition scenarios from the World Economic Forum. These compared a Gradual versus Rapid low-carbon transition based on inputs that included the International Energy Agency’s New Policies Scenario (Gradual) and Sustainable Development Scenario (Rapid), which meets the Paris Agreement’s goal to limit global temperature increases to 1.5 to 2ºC. Vermilion examined key factors impacting the speed of the transition – including the influence of new energy technologies; potential speed of their adoption; anticipated changes in policy and regulation; and emerging market pathways such as India – and resulting factors that could impact the company, including economics (demand, supply, consumer behaviour, and costs of energy); technological advancement; capital availability; government policy; and Company reputation. Among these, government policy was seen as most influential in the near to mid-term.

We applied these findings to Vermilion’s strategy to 2050 and beyond, described below. In particular, the scenario analysis led us to develop two emission-related targets that were announced in 2021: an aspirational commitment to net zero emissions in our own operations, including Scope 1 and Scope 2 emissions, by 2050, and a near-term target to reduce Scope 1 emissions intensity from our operations by 15 to 20% by 2025, using a baseline year of 2019. See Metrics and Targets, below, for more information.

In 2023, we augmented this work with a new analysis of both climate-related transition risks and physical risks. It should be noted that these scenarios 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. We have used them to inform our discussions on short, mid- and long-term business strategy, along with risk identification and management.

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In our scenario analysis, our Executive Committee and Board of Directors reviewed an internally developed comparison of a diverse range of climate-related transition scenarios. We focused on changes in demand for oil and for natural gas based on a Reference (business as usual) case and a Climate Policy (government support for reduced greenhouse gas emissions) case for Global, Advanced Economy and Emerging Economy scenarios. Specific scenarios included the International Energy Agency (Stated Policy, Announced Pledges and Net Zero), Equinor (Walls, Bridges), and BP (New Momentum, Accelerated), with reference cases from Exxon, OPEC and the Energy Information Administration. The analysis showed the potential for energy demand declines over a 5- to 15-year horizon, but also showed greater impacts on specific assets based on government policies, location and logistics (landlocked vs waterborne), and proximity to petrochemical or carbon capture and sequestration capacities.

For example, our analysis for the Reference case in advanced economies points to strong policy uptake in Europe and Industrialized Asia, as well as energy efficiency improvements in the residential and commercial sectors. Oil demand declines as energy transition policy momentum pushes road transport towards electrification, which is further displaced by biofuels after 2030. Efficiency gains reduce consumption, while demographic trends work against oil demand. Climate Policy scenarios see advanced economies driving a rapid uptake of renewables to a near full phase-out of combustible natural gas use, leading to a finale in the role of natural gas as a transition fuel. Natural gas use in 2050 is mostly consumed by the petrochemical sector and for hydrogen production. Both scenarios rely on assumptions such as a continued improvement in advanced technology development for renewables (for example, battery improvement); and the addressing of supply chain human rights and environmental issues for critical minerals.

We also assessed the physical climate-related risks in each of our major operating regions using the International Panel on Climate Change’s Representative Concentration Pathway (RCP) 4.5 scenario. We selected RCP 4.5 because it reflects the physical risks our operations would face if CO2 emissions do not start declining until approximately 2045,  reaching approximately half of 2050 levels by the end of the century. This is more likely than not to result in rising global temperatures above 2C; specific geographic scenarios are summarized above in the Risks table.

While we have set emission reduction targets that are significantly more ambitious than this, using RCP 4.5 enabled us to identify impacts to operations such as rising temperatures, aridity and dry spells in many areas, rising precipitation in some areas, and rising sea levels. Since climate volatility would also increase, RCP 4.5 highlights the need to consider adaptation and mitigation tactics including changing work schedules for daily heat cycles, along with greater wind, storm and wildfire protection for our assets. We note that RCP 2.6 (which requires CO2 emissions to have started declining by 2020) relies not only on reducing emissions, but also on removing significant amounts of greenhouse gases from the atmosphere, and reflects similar physical risks as 4.5 in the next 10-15 years, with lesser effects in the period 2050-2100.

We incorporated the results of the discussions around these scenarios into our business strategy work in 2023, including working on our net zero transition plan (see Targets and Metric section) and our Risk identification and management process.

Overall, our strategy to ensure our resilience under various scenarios continues to rest on three strategic activities:

● Focusing on efficient and responsible production of oil and natural gas, viewing emissions as potential energy sources:

° Lower carbon fuels. Since 2012, we have shifted our production mix towards natural gas as a cleaner burning fuel than other fossil fuels. We also sell our fuels within the country of production wherever possible, reducing the carbon footprint associated with transportation of the fuel to consumers while increasing national energy security.

° Socially responsible fuels. We are committed to ensuring that our products are produced in an environmentally and socially responsible manner, respecting worker rights and community engagement. We operate in regions noted for their stable, well-developed fiscal and regulatory policies related to oil and gas exploration and development, and for their robust health, safety, environmental and human rights legislation.

° Transparency and reporting. We have established a strong record of reporting on greenhouse gas emissions, energy usage and other key environmental metrics, which has supported our emission reduction targets.

● Implementing technically and economically feasible options for emission reduction, covering combustion, flaring, venting and fugitive emissions:

° Greater energy efficiency. Many energy and operational efficiency initiatives go hand-in-hand, which in turn helps us minimize our carbon footprint and reduce greenhouse gas emissions.

° Lower greenhouse gas emission intensity. We are committed to reducing the greenhouse gas emissions associated with our production, with particular focus on methane.

● Exploring new and evolving technologies and processes to identify synergistic fits for our business in both traditional and renewable energy production:

° Alternative energy. We are continuing to develop our knowledge and use of alternative energy sources, including geothermal energy, for which our internal expertise in engineering, geoscience and drilling is particularly well suited. This work has begun with the geothermal potential of our produced water, supporting a circular economy model that conserves, reuses and recycles resources to better protect our environment. It is also expanding into areas such as biogas and the conversion of traditional oil and gas assets to geothermal and hydrogen production.

In addition, we identified two further pillars of our sustainability strategy that are integral to managing sustainability- and climate-related issues:

Vermilion Energy Inc.  ■  Page 35  ■  2023 Management's Discussion and Analysis

Conservation

We are committed to reducing the impact our operations have, beginning with regulatory compliance across all business units. Our conservation efforts are further focused in three areas:

● Water: We recognize water as a basic human right, and as a vital resource that is shared among many stakeholders in our communities. We are therefore committed to protecting both the supply and the quality of water sources in our areas of operation by:

° Proactively preventing harm and supporting healthy surface and groundwater bodies

° Reducing potable and freshwater usage to the lowest level practical, and

° Taking a lifecycle and circular economy approach to water, exploring opportunities to reuse and recycle products such as produced water

● Asset Retirement Obligations: We are adapting our long-term Asset Retirement Obligation management to include revitalizing or reusing assets to benefit our environment and our communities.

● Biodiversity: We are focusing on protecting the species and habitats around us by proactively identifying biodiversity risks and opportunities, and implementing associated plans.

Community

Our communities comprise a wide diversity of people and organizations, but they have one key thing in common: they care deeply about the safety, environmental stewardship and corporate citizenship that we bring to our local operations. In addition, our people care deeply about their communities - whether we work there or live there, these are the places we call home. We therefore steward our operations and relationships to demonstrate our commitment to being a responsible producer and a valued and trusted neighbor and business partner, including:

● Transparency with respect to safe and environmentally responsible operations, including our potential impacts on local communities

● Maintaining strong, genuine relationships with our communities, with engagement based on respect, listening and openness, and

● Creating a shared value focused on local economic and social development

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-related risks and opportunities, including those related to climate, are integrated into multi-disciplinary Company-wide risk identification, assessment, and management processes as part of our ERM system, based on the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework. This provides an integrated approach to managing risk as it impacts strategy and performance, and includes Operational, Market & Financial, Credit, Organizational, Political, Regulatory Compliance, Strategic and Reputational, and Sustainability categories.

Risk management is the responsibility of the Board and the Executive Committee based on a Top-Down, Bottom-Up approach to engage all staff. Top-Down begins with our Board and its committees with clear terms of reference, including oversight for identification and management of specific allocations of risk type. This is translated into action by our Executive Committee, which reviews and manages the ERM process through implementation of associated policies and procedures. Within our Executive Committee, the Vice President International and HSE and the Vice President North America have risk management responsibility on an operational level, while the Chief Financial Officer is responsible for overseeing risk management performance. Our staff help develop systems, standards and procedures. Bottom-Up is how staff implement, maintain and improve risk management processes, applying the hazard-risk-mitigation process in every part of our business.

Risks are identified by key staff across our Company, including our Operations, Finance, Health, Safety and Environment, Economics, Government and Public Relations, and Sustainability teams at corporate, business unit and asset levels. These employees have significant experience, and use a wide array of 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.

The results are incorporated into our Corporate Risk Register, which provides a consistent framework to ensure the effective tracking and communication of our material risks. Using our Risk Matrix as a prioritization tool, teams assess severity, likelihood, speed of onset, and vulnerability using scales from 1 to 5 for each factor, described in terms of 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. Our sustainability materiality analysis, which assesses issues with impact for both the Company and our key stakeholders, is integrated into our ERM system using the Corporate Risk Register through a collaboration between Finance, HSE, Operations and Sustainability teams. Every risk case includes whether climate-related risk is a contributing factor.

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The results are reviewed annually at minimum by the responsible teams, and provided to the Executive Committee and the Board and its Committees as appropriate, who further review and assess the risks including interdependencies based on the company’s risk tolerance.

Our risk management approach focuses on reducing the risk to a level as low as reasonably practicable, accepting the risk, and/or controlling it (such as insuring it). For example, if direct mitigation is not possible (e.g. changes in temperature extremes), we would adapt our business processes to reduce the potential impact (e.g. changing work hours to avoid extreme mid-day heat). In other situations (e.g. increasing risk of flood), we may take measures to protect against the risk (e.g. flood controls) while also insuring our operations. Financial impact is deemed substantive if it could cause a business loss of more than $10 million CAD (unrisked and before mitigation/recovery instruments).

To support climate risk identification and management, we use our internally developed Emissions Long-Range Planning Tool. This is based on our long-range planning tool for production, and allows us to forecast emissions, carbon taxes and the impact of various emission reduction projects. This supports our decision-making on production, capital allocation, budgeting, target setting, and merger, acquisition and divestment decisions.

Sustainability and Climate-Related Metrics and Targets

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

Our sustainability reporting (www.vermilionenergy.com/sustainability) 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 a sustainability contribution of 10% of the Corporate Performance Scorecard for our Long-term Incentive Plan, comprised of progress towards our 2025 emission intensity reduction target (5%) and 2027 ARO liability reduction target (3%), along with select ESG rating agency scores (2%).

We also track carbon pricing, and have identified actual and likely pricing scenarios for all of our operations based on current government policies and published research relating to the Paris Agreement. For example, in Canada, the 2023 carbon tax was $65 per tCO2e, and in Ireland, carbon pricing was 56.00€ per tCO2e. Further information is available in our CDP Climate submission, available at vermilionenergy.com/sustainability/reports/.

In addition, we benchmark our performance via third-party ESG rating agencies, including:

● CDP Climate Change and Water Security: Note that while we continue to submit these questionnaires, as of 2023 we no longer participate in the scoring process. In 2022, we received a  Climate Score of A- and Water score of “B”.

● ISS ESG QualityScore: Decile rating of “1” for Environmental and “2” for Social practices as of March 2024.

● MSCI ESG Rating: AAA in 2023.

● S&P Global Corporate Sustainability Assessment: Top of our peer group in 2023.

Scope 1, 2 and 3 GHG Emissions Disclosure

We report Scopes 1, 2 and 3 emissions, which are externally verified under ISO 14064-3. Historical, corporate and business unit data can be found in the Energy and Emissions Performance Metric document available at www.vermilionenergy.com/sustainability/, summarized in the charts below. The 2018 increase in emissions was associated with the acquisition of southeast Saskatchewan assets. Our Scope 1 and 2 emissions intensity and methane emissions intensity decreased in 2019 and 2020, primarily related to our first full year of operatorship for the Corrib gas asset in Ireland, and our focus on reducing post-acquisition emissions over time through superior operations, as we did in 2014 to 2017 following the acquisition of previous Saskatchewan assets. This has been achieved through a variety of gas conservation and recovery initiatives including construction of new infrastructure, operational changes and increased infrastructure runtimes. Additional decreases have been achieved through improved measurement and methodologies, projects such as replacing diesel or propane with compressed natural gas for boilers and water heating for the drilling program in Alberta, converting pneumatic devices from high- to low-bleed, installing solar-powered chemical injection pumps, and the purchase of renewable energy certificates for electricity use in Netherlands and Ireland. Emissions intensity flattened and methane intensity increased in 2022 as a result of

Vermilion Energy Inc.  ■  Page 37  ■  2023 Management's Discussion and Analysis

lower production; however, our Scope 1 emissions intensity continued to decrease in 2022, to 0.017 t/CO2e, reflecting a 10% decrease from our 2019 baseline of 0.019 t/CO2e and on track to our 2025 target (see below).

Related Targets and Performance

Vermilion has set two emission-related targets:

● Net zero emissions in our own operations, including Scope 1 and Scope 2 emissions, by 2050. We are transparent that this is an aspirational goal, and that we will build the plan to achieve this target over time.

● As a first step, we set a near-term target to reduce Scope 1 emissions intensity from our operations by 15 to 20% by 2025, using a baseline year of 2019. We intend to set new targets every five years at minimum, building on this foundation while exploring broader options, including the potential to reduce Scope 3 emissions.

We developed, and the Board approved, these targets following our climate scenario analysis and extensive internal assessment. There are significant inherent uncertainties in how the energy transition will accelerate over the next three decades. Our intention is to manage these by focusing on responsible production of essential oil and natural gas for as long as these forms of energy are needed, while developing opportunities in other areas that are an economic and synergistic fit for our business.

Committing to an aspirational net zero target was important, but setting a company-wide nearer term target as the first step in creating a clear pathway was even more so. We looked at our own operations – from how we manage emissions data to options for emission reduction – and at how our peers and the majors are approaching this. From this, we identified emissions intensities and opportunities for reduction within our business units, and set our 2025 target.

This is being achieved, starting with our business units with higher emissions intensities, with an initial focus on efficiency, including process changes, venting reductions, instrumentation upgrades from gas to air and power efficiency options, along with improved metering and field measurements.

All of these factors are also being considered as we worked on our Net Zero Transition Plan through 2023. Based on our scenario analyses, we have identified four key pillars to support both a Net Zero by 2050 target for Scope 1 and 2 emissions, and the establishment of our mid-term 2030 Scope and 2 emission intensity reduction target:

● Reduce emissions, with methane a priority, by reducing flaring, venting and fugitive emissions; driving operational and energy efficiencies; electrifying operations where grids are low-intensity; and assessing new technologies as they become viable.

● Convert higher emitting elements of our portfolio to lower intensity production, considering both divestment and end-of-life fields.

● 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.

● Offset as a solution for the emissions that cannot be eliminated.

We anticipate that our plan will be complete in 2024, and that it will constitute a living document - one that will be updated as economic, technological and regulatory landscapes evolve.

For more information on our sustainability- and climate-related performance, please see our 2023 Proxy Statement and Information Circular, online sustainability reporting, particularly the Index and Performance Metrics sections, and 2022 CDP Responses.

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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).

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, 2023, 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. 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, 2023. The effectiveness of Vermilion’s internal control over financial reporting as of December 31, 2023 has been audited by Deloitte LLP, as reflected in their report included in the 2023 audited annual financial statements filed with the US Securities and Exchange Commission. No changes were made to

Vermilion Energy Inc.  ■  Page 39  ■  2023 Management's Discussion and Analysis

Vermilion’s internal control over financial reporting during the year ended December 31, 2023, 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 Equinor Energy Ireland Limited, which was acquired on March 31, 2023. 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 tables below present the summary financial information of Equinor Energy Ireland Limited included in Vermilion's financial statements as at and for the year ended December 31, 2023:

($M)	As at Dec 31, 2023
Non-current assets	705,276
Non-current liabilities	91,954
Net assets	552,688

($M)	Year Ended Dec 31, 2023
Revenue net of royalties	161,663
Net earnings	43,581

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Supplemental Table 1: Netbacks

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

		Q4 2023			2023		Q4 2022	2022
	Liquids	Natural Gas	Total	Liquids	Natural Gas	Total	Total	Total
	$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Canada
Sales	79.86	2.65	44.73	79.92	2.91	46.73	65.13	70.33
Royalties	(12.93)	0.02	(5.76)	(12.06)	0.01	(5.62)	(7.99)	(10.26)
Transportation	(4.28)	(0.21)	(2.62)	(3.57)	(0.21)	(2.34)	(2.66)	(2.35)
Operating	(20.41)	(0.68)	(11.43)	(21.66)	(0.79)	(12.66)	(13.05)	(12.60)
Operating netback	42.24	1.78	24.92	42.63	1.92	26.11	41.43	45.12
General and administration			(5.65)			(5.22)	(1.37)	(1.50)
Fund flows from operations ($/boe)			19.27			20.89	40.06	43.62
United States
Sales	88.71	2.04	71.65	87.49	2.31	71.97	83.51	87.46
Royalties	(25.00)	(0.63)	(20.27)	(23.80)	(0.77)	(19.75)	(22.94)	(23.38)
Transportation	(1.13)	—	(0.87)	(0.45)	—	(0.36)	(0.18)	(0.33)
Operating	(15.01)	(0.35)	(12.13)	(13.56)	(0.36)	(11.15)	(17.66)	(14.40)
Operating netback	47.57	1.06	38.38	49.68	1.18	40.71	42.73	49.35
General and administration			(5.26)			(4.63)	(4.28)	(3.08)
Fund flows from operations ($/boe)			33.12			36.08	38.45	46.27
France
Sales	116.92	—	116.92	109.47	—	109.47	119.68	132.90
Royalties	(15.93)	—	(15.93)	(14.34)	—	(14.34)	(14.28)	(14.68)
Transportation	(12.80)	—	(12.80)	(9.39)	—	(9.39)	(7.05)	(7.31)
Operating	(37.93)	—	(37.93)	(30.71)	—	(30.71)	(19.41)	(20.94)
Operating netback	50.26	—	50.26	55.03	—	55.03	78.94	89.97
General and administration			(13.91)			(7.91)	(7.73)	(5.98)
Current income taxes			(13.12)			(5.49)	(7.69)	(10.87)
Fund flows from operations ($/boe)			23.23			41.63	63.52	73.12
Netherlands
Sales	106.81	17.12	102.80	83.23	17.96	107.38	281.75	279.87
Royalties	—	(0.23)	(1.38)	—	(0.15)	(0.90)	(1.21)	(0.25)
Transportation	—	—	—	—	—	—	—	—
Operating	(18.90)	(3.03)	(18.19)	(17.44)	(3.76)	(22.50)	(26.44)	(22.82)
Operating netback	87.91	13.86	83.23	65.79	14.05	83.98	254.10	256.80
General and administration			(1.15)			(4.78)	(4.75)	(2.12)
Current income taxes			(37.33)			(27.78)	(86.02)	(74.91)
Fund flows from operations ($/boe)			44.75			51.42	163.33	179.77
Germany
Sales	110.62	16.16	101.18	106.03	17.26	104.26	218.13	231.34
Royalties	3.33	(0.66)	(1.69)	(2.34)	(0.59)	(3.20)	(11.54)	(10.21)
Transportation	(14.56)	(0.84)	(7.99)	(14.39)	(0.69)	(7.11)	(6.53)	(4.69)
Operating	(20.63)	(3.01)	(18.87)	(23.79)	(3.87)	(23.39)	(23.96)	(19.96)
Operating netback	78.76	11.65	72.63	65.51	12.11	70.56	176.10	196.48
General and administration			(9.16)			(6.99)	(5.36)	(3.34)
Current income taxes			5.78			(15.22)	(3.53)	(15.15)
Fund flows from operations ($/boe)			69.25			48.35	167.21	177.99
Ireland
Sales	—	17.05	102.28	—	16.21	97.24	162.16	194.05
Transportation	—	(0.18)	(1.08)	—	(0.38)	(2.28)	(1.88)	(2.14)
Operating	—	(2.37)	(14.20)	—	(2.11)	(12.69)	(11.74)	(9.92)
Operating netback	—	14.50	87.00	—	13.72	82.27	148.54	181.99
General and administration			(9.25)			(6.13)	(0.78)	0.07
Current income taxes			(0.33)			(0.23)	—	—
Fund flows from operations ($/boe)			77.42			75.91	147.76	182.06

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		Q4 2023			2023		Q4 2022	2022
	Liquids	Natural Gas	Total	Liquids	Natural Gas	Total	Total	Total
	$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Australia
Sales	143.69	—	143.69	143.69	—	143.69	139.95	148.15
Operating	(42.17)	—	(42.17)	(206.80)	—	(206.80)	(31.23)	(38.50)
PRRT (2)	82.39	—	82.39	82.39	—	82.39	(7.40)	(12.27)
Operating netback	183.91	—	183.91	19.28	—	19.28	101.32	97.38
General and administration			(9.91)			(32.32)	(2.93)	(3.32)
Current income taxes			7.60			0.05	3.47	3.36
Fund flows from operations ($/boe)			181.60			(12.99)	101.86	97.42
Total Company
Sales	92.51	8.46	68.64	88.62	8.18	67.10	103.99	111.95
Realized hedging gain (loss)	0.78	2.92	10.33	0.48	2.31	7.77	(5.42)	(13.07)
Royalties	(13.08)	(0.09)	(5.93)	(13.28)	(0.09)	(6.36)	(8.43)	(9.85)
Transportation	(5.16)	(0.21)	(2.95)	(4.66)	(0.25)	(2.95)	(2.71)	(2.54)
Operating	(20.69)	(1.89)	(15.35)	(22.49)	(2.08)	(17.03)	(16.81)	(15.75)
PRRT (2)	6.39	—	2.74	1.52	—	0.69	(0.62)	(0.59)
Operating netback	60.75	9.19	57.48	50.19	8.07	49.22	70.00	70.15
General and administration			(2.60)			(2.68)	(1.65)	(1.86)
Interest expense			(3.01)			(2.83)	(2.78)	(2.67)
Realized foreign exchange gain (loss)			(0.73)			(0.15)	2.33	0.49
Other (expense) income			0.26			(0.01)	(0.14)	0.42
Corporate income taxes			(2.54)			(3.05)	(5.18)	(6.70)
Windfall taxes			(0.03)			(2.60)	(27.50)	(7.18)
Fund flows from operations ($/boe)			48.83			37.90	35.08	52.65

⁽¹⁾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.

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Supplemental Table 2: Hedges

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

The following tables outline Vermilion’s outstanding risk management positions as at December 31, 2023:

												Weighted
				Weighted		Weighted		Weighted		Weighted	Daily	Average
			Daily	Average	Daily	Average	Daily	Average	Daily	Average	Bought	Bought
			Bought Put	Bought Put	Sold 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
WTI
Q1 2024	bbl	USD	—	—	—	—	—	—	12,500	79.00	—	—
Q2 2024	bbl	USD	—	—	—	—	—	—	9,500	80.11	—	—
Q3 2024	bbl	USD	—	—	—	—	—	—	9,500	80.11	—	—
AECO
Q1 2024	mcf	CAD	4,739	3.17	4,739	4.22	—	—	4,739	3.69	—	—
Q2 2024	mcf	CAD	4,739	3.17	4,739	4.22	—	—	19,904	3.14	—	—
Q3 2024	mcf	CAD	4,739	3.17	4,739	4.22	—	—	19,904	3.14	—	—
Q4 2024	mcf	CAD	4,739	3.17	4,739	4.22	—	—	9,849	3.31	—	—
Q1 2025	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q2 2025	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q3 2025	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q4 2025	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q1 2026	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q2 2026	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q3 2026	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
Q4 2026	mcf	CAD	4,739	3.17	4,739	4.22	—	—	23,695	3.89	—	—
NYMEX Henry Hub
Q1 2024	mcf	USD	20,000	3.50	20,000	4.45	—	—	4,000	3.51	—	—
Q2 2024	mcf	USD	20,000	3.50	20,000	4.45	—	—	4,000	3.51	—	—
Q3 2024	mcf	USD	20,000	3.50	20,000	4.45	—	—	4,000	3.51	—	—
Q4 2024	mcf	USD	20,000	3.50	20,000	4.45	—	—	4,000	3.51	—	—
Q1 2025	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q2 2025	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q3 2025	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q4 2025	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q1 2026	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q2 2026	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q3 2026	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—
Q4 2026	mcf	USD	24,000	3.50	24,000	4.49	—	—	—	—	—	—

Vermilion Energy Inc.  ■  Page 43  ■  2023 Management's Discussion and Analysis

												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
NBP
Q1 2024	mcf	EUR	4,913	41.03	4,913	84.26	—	—	—	—	—	—
Q2 2024	mcf	EUR	—	—	—	—	—	—	2,457	14.65	—	—
Q3 2024	mcf	EUR	—	—	—	—	—	—	2,457	14.65	—	—
TTF
Q1 2024	mcf	EUR	35,623	37.85	35,623	71.90	—	—	7,370	41.19	—	—
Q2 2024	mcf	EUR	7,278	25.96	7,278	45.76	—	—	30,709	14.08	—	—
Q3 2024	mcf	EUR	7,278	25.96	7,278	45.76	—	—	30,709	14.08	—	—
Q4 2024	mcf	EUR	4,913	13.19	4,913	18.32	—	—	34,394	15.13	—	—
Q1 2025	mcf	EUR	4,913	13.19	4,913	18.32	—	—	34,394	15.13	—	—
Q2 2025	mcf	EUR	—	—	—	—	—	—	17,197	14.40	—	—
Q3 2025	mcf	EUR	—	—	—	—	—	—	17,197	14.40	—	—
Q4 2025	mcf	EUR	—	—	—	—	—	—	12,284	13.51	—	—
Q1 2026	mcf	EUR	—	—	—	—	—	—	12,284	13.51	—	—
Q2 2026	mcf	EUR	—	—	—	—	—	—	9,827	9.67	—	—
Q3 2026	mcf	EUR	—	—	—	—	—	—	9,827	9.67	—	—
Buy TTF, Sell NBP Basis
Q1 2024	mcf	EUR	—	—	—	—	—	—	22,111	(0.26)	—	—
THE
Q4 2024	mcf	EUR	—	—	—	—	—	—	2,457	14.95	—	—
Q1 2025	mcf	EUR	—	—	—	—	—	—	2,457	14.95	—	—
Q2 2025	mcf	EUR	—	—	—	—	—	—	2,457	14.95	—	—
Q3 2025	mcf	EUR	—	—	—	—	—	—	2,457	14.95	—	—

VET Equity Swaps		Initial Share Price		Share Volume
Swap	Jan 2020 - Apr 2025	20.9788	CAD	2,250,000
Swap	Jan 2020 - Jul 2025	22.4587	CAD	1,500,000

		Monthly Bought Put		Weighted Average	Monthly Sold Call		Weighted Average	Monthly Sold Swap		Weighted Average
Foreign Exchange		Amount		Bought Put Price	Amount		Sold Call Price	Amount		Sold Swap Price
Collar	Jan 2024 - Dec 2024	4,000,000	USD	1.3600	4,000,000	USD	1.3963	—		—
Forward	Jan 2024 - Dec 2024	—		—	—		—	4,000,000	USD	1.3531

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
Oct 2024 - Sep 2025	bbl	USD	29-Mar-2024	—	—	—	—	—	—	1,000	80.00

Vermilion Energy Inc.  ■  Page 44  ■  2023 Management's Discussion and Analysis

Supplemental Table 3: Capital Expenditures and Acquisitions

By classification ($M)	Q4 2023	Q4 2022	2023	2022
Drilling and development	132,308	157,849	569,110	528,056
Exploration and evaluation	10,579	11,456	21,081	23,761
Capital expenditures	142,887	169,305	590,191	551,817
Acquisitions, net of cash acquired	2,669	3,594	142,281	510,309
Acquisition of securities	17,448	964	21,603	23,282
Acquired working capital deficit	5,607	—	109,134	6,122
Acquisitions	25,724	4,558	273,018	539,713

Dispositions ($M)	Q4 2023	Q4 2022	2023	2022
Canada	—	—	182,152	—
United States	14,855	—	14,855	—
Total dispositions	14,855	—	197,007	—

By category ($M)	Q4 2023	Q4 2022	2023	2022
Drilling, completion, new well equip and tie-in, workovers and recompletions	68,285	112,755	373,304	418,284
Production equipment and facilities	76,937	49,286	198,331	105,722
Seismic, studies, land and other	(2,335)	7,264	18,556	27,811
Capital expenditures	142,887	169,305	590,191	551,817
Acquisitions	25,724	4,558	273,018	539,713
Total capital expenditures and acquisitions	168,611	173,863	863,209	1,091,530

Capital expenditures by country ($M)	Q4 2023	Q4 2022	2023	2022
Canada	53,791	111,483	288,223	275,203
United States	4,913	2,409	91,977	63,353
France	11,217	15,704	48,297	44,252
Netherlands	10,787	14,232	44,147	21,652
Germany	33,046	10,089	59,711	26,157
Ireland	11,850	1,323	20,283	3,030
Australia	9,331	5,753	26,005	95,173
Central and Eastern Europe	7,952	8,312	11,548	22,997
Total capital expenditures	142,887	169,305	590,191	551,817

Acquisitions by country ($M)	Q4 2023	Q4 2022	2023	2022
Canada	20,117	1,985	71,185	531,348
United States	—	—	3,808	1,075
Netherlands	—	—	—	707
Germany	—	(11)	—	3,857
Ireland	5,607	2,584	198,025	2,726
Acquisitions	25,724	4,558	273,018	539,713

Vermilion Energy Inc.  ■  Page 45  ■  2023 Management's Discussion and Analysis

Supplemental Table 4: Production

	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21	Q2/21	Q1/21
Canada
Light and medium crude oil (bbls/d)	11,614	12,054	12,901	16,674	17,448	16,835	17,042	15,980	16,388	16,809	16,868	17,767
Condensate (1) (bbls/d)	4,034	4,410	3,506	4,719	4,525	4,204	4,873	4,892	4,785	4,426	5,558	4,556
Other NGLs (1) (bbls/d)	6,281	6,219	5,513	6,875	6,279	6,870	7,155	7,286	7,073	6,862	7,767	7,016
NGLs (bbls/d)	10,315	10,629	9,019	11,594	10,804	11,074	12,028	12,178	11,858	11,288	13,325	11,572
Conventional natural gas (mmcf/d)	160.16	163.94	159.26	160.34	146.81	145.04	143.94	140.55	128.85	138.42	146.55	138.41
Total (boe/d)	48,623	50,007	48,464	54,991	52,720	52,080	53,060	51,584	49,720	51,168	54,618	52,407
United States
Light and medium crude oil (bbls/d)	3,187	4,404	3,349	2,824	3,282	2,824	2,846	2,675	2,647	3,520	1,888	2,322
Condensate (1) (bbls/d)	27	15	22	20	36	35	40	24	26	2	2	—
Other NGLs (1) (bbls/d)	1,131	1,124	1,025	1,020	1,218	1,031	958	1,056	1,388	1,206	928	1,058
NGLs (bbls/d)	1,158	1,139	1,047	1,040	1,254	1,066	998	1,080	1,414	1,208	930	1,058
Conventional natural gas (mmcf/d)	7.49	7.25	7.23	7.14	7.45	7.03	6.74	7.56	9.09	6.75	5.51	5.95
Total (boe/d)	5,593	6,751	5,601	5,055	5,779	5,062	4,967	5,014	5,575	5,854	3,736	4,373
France
Light and medium crude oil (bbls/d)	7,395	7,578	7,788	7,578	7,247	6,818	8,126	8,389	8,453	8,677	9,013	9,062
Total (boe/d)	7,395	7,578	7,788	7,578	7,247	6,818	8,126	8,389	8,453	8,677	9,013	9,062
Netherlands
Light and medium crude oil (bbls/d)	—	—	—	—	—	—	1	1	—	6	1	6
Condensate (1) (bbls/d)	119	39	61	66	49	74	60	83	97	104	95	92
NGLs (bbls/d)	119	39	61	66	49	74	60	83	97	104	95	92
Conventional natural gas (mmcf/d)	32.06	24.32	27.28	29.07	27.41	29.15	35.22	39.03	51.98	42.48	37.59	41.45
Total (boe/d)	5,462	4,091	4,607	4,910	4,617	4,933	5,930	6,589	8,761	7,190	6,362	7,006
Germany
Light and medium crude oil (bbls/d)	1,775	1,713	1,715	1,410	1,481	1,764	1,331	1,158	1,127	1,043	1,093	911
Conventional natural gas (mmcf/d)	19.62	20.29	22.05	25.85	25.86	26.54	25.36	26.95	18.00	16.19	15.60	13.40
Total (boe/d)	5,046	5,095	5,391	5,717	5,791	6,187	5,558	5,650	4,127	3,741	3,694	3,144
Ireland
Conventional natural gas (mmcf/d)	64.04	47.96	67.51	24.58	26.04	25.74	27.93	30.26	30.12	22.67	30.19	34.14
Total (boe/d)	10,673	7,993	11,251	4,096	4,340	4,290	4,655	5,043	5,020	3,778	5,031	5,690
Australia
Light and medium crude oil (bbls/d)	4,715	1,204	—	—	4,847	4,763	2,465	3,888	2,742	4,190	3,835	4,489
Total (boe/d)	4,715	1,204	—	—	4,847	4,763	2,465	3,888	2,742	4,190	3,835	4,489
Central and Eastern Europe
Conventional natural gas (mmcf/d)	0.54	0.05	0.30	0.64	0.67	0.63	0.64	0.34	0.12	0.22	0.28	0.63
Total (boe/d)	90	8	50	107	111	104	106	57	20	36	46	104
Consolidated
Light and medium crude oil (bbls/d)	28,685	26,952	25,753	28,485	34,305	33,003	31,811	32,091	31,356	34,245	32,698	34,556
Condensate (1) (bbls/d)	4,180	4,463	3,589	4,805	4,610	4,312	4,973	4,999	4,908	4,532	5,656	4,648
Other NGLs (1) (bbls/d)	7,412	7,344	6,538	7,896	7,497	7,901	8,113	8,342	8,461	8,068	8,695	8,074
NGLs (bbls/d)	11,592	11,807	10,127	12,701	12,107	12,213	13,086	13,341	13,369	12,600	14,351	12,722
Conventional natural gas (mmcf/d)	283.92	263.80	283.63	247.61	234.23	234.12	239.83	244.69	238.16	226.73	235.72	233.98
Total (boe/d)	87,597	82,727	83,152	82,455	85,450	84,237	84,868	86,213	84,417	84,633	86,335	86,276

Vermilion Energy Inc.  ■  Page 46  ■  2023 Management's Discussion and Analysis

	2023	2022	2021	2020	2019	2018
Canada
Light and medium crude oil (bbls/d)	13,293	16,830	16,954	21,106	23,971	17,400
Condensate (1) (bbls/d)	4,166	4,621	4,831	4,886	4,295	3,754
Other NGLs (1) (bbls/d)	6,220	6,895	7,179	7,719	6,988	5,914
NGLs (bbls/d)	10,386	11,516	12,010	12,605	11,283	9,668
Conventional natural gas (mmcf/d)	160.94	144.10	138.03	151.38	148.35	129.37
Total (boe/d)	50,503	52,364	51,968	58,942	59,979	48,630
United States
Light and medium crude oil (bbls/d)	3,445	2,908	2,597	3,046	2,514	1,069
Condensate (1) (bbls/d)	21	34	8	5	18	8
Other NGLs (1) (bbls/d)	1,076	1,066	1,146	1,218	996	452
NGLs (bbls/d)	1,097	1,100	1,154	1,223	1,014	460
Conventional natural gas (mmcf/d)	7.28	7.20	6.84	7.47	6.89	2.78
Total (boe/d)	5,754	5,207	4,890	5,514	4,675	1,992
France
Light and medium crude oil (bbls/d)	7,584	7,639	8,799	8,903	10,435	11,362
Conventional natural gas (mmcf/d)	—	—	—	—	0.19	0.21
Total (boe/d)	7,584	7,639	8,799	8,903	10,467	11,396
Netherlands
Light and medium crude oil (bbls/d)	—	—	3	1	3	—
Condensate (1) (bbls/d)	71	66	97	88	88	90
NGLs (bbls/d)	71	66	97	88	88	90
Conventional natural gas (mmcf/d)	28.18	32.66	43.40	46.16	49.10	46.13
Total (boe/d)	4,768	5,510	7,334	7,782	8,274	7,779
Germany
Light and medium crude oil (bbls/d)	1,654	1,435	1,044	968	917	1,004
Conventional natural gas (mmcf/d)	21.93	26.18	15.81	12.65	15.31	15.66
Total (boe/d)	5,310	5,798	3,679	3,076	3,468	3,614
Ireland
Conventional natural gas (mmcf/d)	51.12	27.48	29.25	37.44	46.57	55.17
Total (boe/d)	8,520	4,579	4,875	6,240	7,762	9,195
Australia
Light and medium crude oil (bbls/d)	1,492	3,995	3,810	4,416	5,662	4,494
Total (boe/d)	1,492	3,995	3,810	4,416	5,662	4,494
Central and Eastern Europe
Conventional natural gas (mmcf/d)	0.38	0.57	0.31	1.90	0.42	1.02
Total (boe/d)	63	95	51	317	70	169
Consolidated
Light and medium crude oil (bbls/d)	27,469	32,809	33,208	38,441	43,502	35,329
Condensate (1) (bbls/d)	4,258	4,721	4,936	4,980	4,400	3,853
Other NGLs (1) (bbls/d)	7,296	7,961	8,325	8,937	7,984	6,366
NGLs (bbls/d)	11,554	12,682	13,261	13,917	12,384	10,219
Conventional natural gas (mmcf/d)	269.84	238.18	233.64	256.99	266.82	250.33
Total (boe/d)	83,994	85,187	85,408	95,190	100,357	87,270

⁽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 47  ■  2023 Management's Discussion and Analysis

Supplemental Table 5: Segmented Financial Results

	Three Months Ended December 31, 2023
($M)	Canada	USA	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Drilling and development	53,791	4,913	11,217	10,788	30,018	11,850	9,331	400	132,308
Exploration and evaluation	—	—	—	(1)	3,028	—	—	7,552	10,579
Crude oil and condensate sales	142,924	30,892	52,472	1,073	15,028	42	36,381	—	278,812
NGL sales	18,196	4,567	—	—	—	—	—	—	22,763
Natural gas sales	38,982	1,408	—	50,588	29,122	100,388	—	906	221,394
Sales of purchased commodities	—	—	—	—	—	—	—	38,458	38,458
Royalties	(25,759)	(10,427)	(7,150)	(692)	(736)	—	—	(384)	(45,148)
Revenue from external customers	174,343	26,440	45,322	50,969	43,414	100,430	36,381	38,980	516,279
Purchased commodities	—	—	—	—	—	—	—	(38,458)	(38,458)
Transportation	(11,701)	(450)	(5,745)	—	(3,486)	(1,059)	—	—	(22,441)
Operating	(51,129)	(6,239)	(17,021)	(9,143)	(8,233)	(13,948)	(10,677)	(547)	(116,937)
General and administration	(25,259)	(2,706)	(6,245)	(578)	(3,999)	(9,085)	(2,508)	30,570	(19,810)
PRRT	—	—	—	—	—	—	20,860	—	20,860
Corporate income taxes	(53)	—	(5,888)	(18,758)	2,523	(325)	1,925	1,202	(19,374)
Windfall taxes	—	—	—	—	—	—	—	(249)	(249)
Interest expense	—	—	—	—	—	—	—	(22,909)	(22,909)
Realized gain on derivative instruments	—	—	—	—	—	—	—	78,737	78,737
Realized foreign exchange loss	—	—	—	—	—	—	—	(5,529)	(5,529)
Realized other income	—	—	—	—	—	—	—	1,948	1,948
Fund flows from operations	86,201	17,045	10,423	22,490	30,219	76,013	45,981	83,745	372,117

Vermilion Energy Inc.  ■  Page 48  ■  2023 Management's Discussion and Analysis

	Year Ended December 31, 2023
($M)	Canada	USA	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,805,049	254,884	587,824	237,326	425,532	1,137,648	280,532	1,507,026	6,235,821
Drilling and development	288,223	91,977	48,297	44,147	48,463	20,283	26,005	1,715	569,110
Exploration and evaluation	—	—	—	—	11,248	—	—	9,833	21,081
Crude oil and condensate sales	621,985	129,775	285,626	2,306	57,464	74	36,381	—	1,133,611
NGL sales	68,753	15,240	—	—	—	—	—	—	83,993
Natural gas sales	170,653	6,143	—	184,548	138,017	302,330	—	3,260	804,951
Sales of purchased commodities	—	—	—	—	—	—	—	177,000	177,000
Royalties	(103,511)	(41,487)	(37,425)	(1,567)	(5,993)	—	—	(1,711)	(191,694)
Revenue from external customers	757,880	109,671	248,201	185,287	189,488	302,404	36,381	178,549	2,007,861
Purchased commodities	—	—	—	—	—	—	—	(177,000)	(177,000)
Transportation	(43,163)	(751)	(24,511)	—	(13,333)	(7,098)	—	—	(88,856)
Operating	(233,417)	(23,424)	(80,134)	(39,157)	(43,857)	(39,464)	(52,360)	(1,568)	(513,381)
General and administration	(96,296)	(9,734)	(20,642)	(8,317)	(13,104)	(19,054)	(8,182)	94,613	(80,716)
PRRT	—	—	—	—	—	—	20,860	—	20,860
Corporate income taxes	(53)	—	(14,313)	(48,349)	(28,533)	(715)	13	18	(91,932)
Windfall taxes	—	—	—	—	—	—	—	(78,426)	(78,426)
Interest expense	—	—	—	—	—	—	—	(85,212)	(85,212)
Realized gain on derivative instruments	—	—	—	—	—	—	—	234,365	234,365
Realized foreign exchange loss	—	—	—	—	—	—	—	(4,532)	(4,532)
Realized other expense	—	—	—	—	—	—	—	(420)	(420)
Fund flows from operations	384,951	75,762	108,601	89,464	90,661	236,073	(3,288)	160,387	1,142,611

Vermilion Energy Inc.  ■  Page 49  ■  2023 Management's Discussion and Analysis

Supplemental Table 6: Operational and Financial Data by Core Region

Production volumes ⁽¹⁾

	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21	Q2/21	Q1/21
North America
Crude oil and condensate (bbls/d)	18,862	20,883	19,778	24,237	25,291	23,898	24,801	23,571	23,846	24,757	24,316	24,645
NGLs (bbls/d)	7,412	7,344	6,538	7,895	7,497	7,901	8,113	8,342	8,461	8,068	8,695	8,074
Natural gas (mmcf/d)	167.65	171.19	166.49	167.48	154.26	152.07	150.68	148.11	137.93	145.18	152.06	144.36
Total (boe/d)	54,216	56,758	54,065	60,046	58,499	57,142	58,027	56,598	55,295	57,022	58,354	56,780
International
Crude oil and condensate (bbls/d)	14,004	10,534	9,564	9,054	13,624	13,419	11,983	13,519	12,419	14,020	14,037	14,560
Natural gas (mmcf/d)	116.27	92.61	117.14	80.13	79.97	82.05	89.15	96.58	100.22	81.55	83.66	89.62
Total (boe/d)	33,381	25,969	29,087	22,408	26,953	27,095	26,840	29,616	29,123	27,612	27,981	29,495
Consolidated
Crude oil and condensate (bbls/d)	32,866	31,416	29,341	33,290	38,915	37,315	36,784	37,090	36,264	38,777	38,354	39,204
NGLs (bbls/d)	7,412	7,344	6,538	7,896	7,497	7,901	8,113	8,342	8,461	8,068	8,695	8,074
Natural gas (mmcf/d)	283.92	263.80	283.63	247.61	234.23	234.12	239.83	244.69	238.16	226.73	235.72	233.98
Total (boe/d)	87,597	82,727	83,152	82,455	85,450	84,237	84,868	86,213	84,417	84,633	86,335	86,276

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

Vermilion Energy Inc.  ■  Page 50  ■  2023 Management's Discussion and Analysis

Sales volumes

	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21	Q2/21	Q1/21
North America
Crude oil and condensate (bbls/d)	18,862	20,883	19,778	24,237	25,291	23,897	24,801	23,571	23,845	24,757	24,316	24,645
NGLs (bbls/d)	7,412	7,344	6,538	7,895	7,497	7,901	8,113	8,342	8,461	8,068	8,695	8,074
Natural gas (mmcf/d)	167.65	171.19	166.49	167.48	154.26	152.07	150.68	148.11	137.93	145.18	152.06	144.36
Total (boe/d)	54,216	56,758	54,065	60,046	58,499	57,142	58,027	56,598	55,295	57,022	58,354	56,780
International
Crude oil and condensate (bbls/d)	9,221	9,950	10,302	8,087	16,257	11,493	11,720	12,615	13,985	15,227	13,859	11,421
Natural gas (mmcf/d)	116.27	92.61	117.14	80.13	79.97	82.05	89.15	96.58	100.22	81.55	83.66	89.62
Total (boe/d)	28,598	25,386	29,824	21,442	29,585	25,169	26,578	28,712	30,689	28,820	27,802	26,357
Consolidated
Crude oil and condensate (bbls/d)	28,083	30,833	30,080	32,324	41,547	35,391	36,522	36,186	37,830	39,985	38,174	36,066
NGLs (bbls/d)	7,412	7,344	6,538	7,896	7,497	7,901	8,113	8,342	8,461	8,068	8,695	8,074
Natural gas (mmcf/d)	283.92	263.80	283.63	247.61	234.23	234.12	239.83	244.69	238.16	226.73	235.72	233.98
Total (boe/d)	82,814	82,144	83,889	81,489	88,083	82,312	84,607	85,310	85,984	85,841	86,156	83,138

Vermilion Energy Inc.  ■  Page 51  ■  2023 Management's Discussion and Analysis

Financial results

	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21	Q2/21	Q1/21
North America
Crude oil and condensate sales ($/bbl)	100.16	103.46	94.78	95.63	106.66	114.82	134.72	111.42	92.99	82.23	75.43	66.31
NGL sales ($/bbl)	33.38	27.77	28.11	36.24	39.93	44.64	51.86	46.94	47.26	35.55	25.43	29.39
Natural gas sales ($/mcf)	2.62	2.52	2.29	4.11	5.96	6.41	7.13	4.80	5.07	3.80	2.72	3.98
Sales ($/boe)	47.51	49.26	45.12	54.84	66.95	71.24	83.34	65.88	59.97	50.40	42.30	43.08
Royalties ($/boe)	(7.25)	(7.75)	(5.45)	(7.68)	(9.47)	(12.58)	(12.51)	(11.24)	(9.26)	(7.14)	(5.98)	(5.49)
Transportation ($/boe)	(2.44)	(2.08)	(1.57)	(2.44)	(2.42)	(2.16)	(2.15)	(1.91)	(1.86)	(1.92)	(1.90)	(2.05)
Operating ($/boe)	(11.50)	(12.09)	(12.22)	(14.10)	(13.51)	(14.00)	(11.58)	(11.95)	(11.68)	(11.02)	(10.89)	(11.21)
General and administration ($/boe)	0.87	(0.72)	0.10	(0.99)	0.10	(1.27)	(1.52)	(1.26)	(2.01)	(1.14)	(0.91)	(1.34)
Corporate income taxes ($/boe)	0.23	(0.01)	(0.10)	(0.12)	(0.13)	(0.03)	—	(0.02)	0.42	(0.05)	(0.04)	(0.04)
Fund flows from operations ($/boe)	27.42	26.61	25.88	29.51	41.52	41.20	55.58	39.50	35.58	29.13	22.58	22.95
Fund flows from operations	136,766	138,958	127,346	159,435	223,443	216,579	293,470	201,193	180,979	152,764	119,916	117,227
Drilling and development	(58,704)	(69,703)	(135,723)	(116,070)	(113,892)	(112,238)	(54,913)	(57,513)	(89,643)	(35,179)	(38,847)	(59,113)
Free cash flow	78,062	69,255	(8,377)	43,365	109,551	104,341	238,557	143,680	91,336	117,585	81,069	58,114
International
Crude oil and condensate sales ($/bbl)	123.77	114.26	100.23	107.57	128.02	140.09	146.67	136.69	103.53	94.91	85.41	81.40
Natural gas sales ($/mcf)	16.92	13.34	14.58	24.69	39.54	58.55	32.33	36.75	35.54	18.82	9.83	7.98
Sales ($/boe)	108.70	93.46	91.89	132.84	177.23	254.86	173.14	183.66	163.23	103.39	72.16	62.39
Royalties ($/boe)	(3.41)	3.55	(7.43)	(13.39)	(6.38)	(7.21)	(7.23)	(5.43)	(4.13)	(4.52)	(3.83)	(3.53)
Transportation ($/boe)	(3.91)	(4.53)	(5.23)	(5.11)	(3.29)	(3.51)	(3.64)	(2.91)	(3.40)	(3.47)	(4.64)	(2.76)
Operating ($/boe)	(22.64)	(25.58)	(28.24)	(31.41)	(23.35)	(22.63)	(22.11)	(19.86)	(18.86)	(17.55)	(16.56)	(16.42)
General and administration ($/boe)	(9.18)	(7.37)	(7.58)	(7.52)	(5.09)	(3.34)	(3.16)	(3.02)	(2.53)	(2.40)	(2.61)	(2.06)
Corporate income taxes ($/boe)	(7.81)	(13.42)	(6.79)	(11.20)	(15.15)	(21.97)	(28.73)	(17.63)	(12.17)	0.64	(0.19)	0.66
PRRT ($/boe)	7.93	—	—	—	(1.85)	(1.96)	(0.83)	(2.60)	(1.96)	(2.74)	(0.58)	(0.60)
Fund flows from operations ($/boe)	69.68	46.12	36.62	64.21	122.12	194.24	107.44	132.21	120.18	73.35	43.75	37.68
Fund flows from operations	183,353	107,704	99,377	123,893	332,377	449,771	259,840	341,626	339,286	194,505	110,654	89,403
Drilling and development	(73,604)	(49,701)	(28,347)	(37,258)	(43,957)	(65,640)	(54,575)	(25,328)	(29,359)	(27,994)	(38,856)	(20,399)
Exploration and evaluation	(10,579)	(6,235)	(2,775)	(1,492)	(11,456)	(6,137)	(3,665)	(2,503)	(26,805)	(3,277)	(1,473)	(3,851)
Free cash flow	99,170	51,768	68,255	85,143	276,964	377,994	201,600	313,795	283,122	163,234	70,325	65,153
	Q4/23	Q3/23	Q2/23	Q1/23	Q4/22	Q3/22	Q2/22	Q1/22	Q4/21	Q3/21	Q2/21	Q1/21
Consolidated
Crude oil and condensate sales ($/bbl)	107.91	106.94	96.64	98.62	115.02	123.02	138.55	120.23	96.88	87.05	79.06	71.09
NGL sales ($/bbl)	33.38	27.77	28.11	36.23	39.93	44.64	51.86	46.94	47.26	35.55	25.43	29.39
Natural gas sales ($/mcf)	8.48	6.32	7.37	10.77	17.43	24.68	16.50	17.41	17.89	9.20	5.24	5.51
Sales ($/boe)	68.64	62.92	61.74	75.36	103.99	127.39	111.55	105.52	96.82	68.19	51.93	49.20
Royalties ($/boe)	(5.93)	(4.26)	(6.16)	(9.18)	(8.43)	(10.94)	(10.85)	(9.29)	(7.43)	(6.26)	(5.29)	(4.87)
Transportation ($/boe)	(2.95)	(2.84)	(2.87)	(3.14)	(2.71)	(2.57)	(2.62)	(2.25)	(2.41)	(2.44)	(2.78)	(2.27)
Operating ($/boe)	(15.35)	(16.26)	(17.91)	(18.66)	(16.81)	(16.64)	(14.89)	(14.61)	(14.24)	(13.21)	(12.72)	(12.86)
General and administration ($/boe)	(2.60)	(2.77)	(2.63)	(2.71)	(1.65)	(1.90)	(2.04)	(1.85)	(2.20)	(1.56)	(1.46)	(1.57)
Corporate income taxes ($/boe)	(2.54)	(4.15)	(2.48)	(3.04)	(5.18)	(6.74)	(9.03)	(5.95)	(4.07)	0.18	(0.09)	0.18
Windfall taxes ($/boe)	(0.03)	(2.90)	(4.56)	(2.92)	(27.50)	—	—	—	—	—	—	—
PRRT ($/boe)	2.74	—	—	—	(0.62)	(0.60)	(0.26)	(0.87)	(0.70)	(0.92)	(0.19)	(0.19)
Interest ($/boe)	(3.01)	(2.68)	(2.65)	(2.98)	(2.78)	(3.23)	(2.74)	(1.93)	(2.06)	(2.37)	(2.41)	(2.57)
Realized derivatives ($/boe)	10.33	9.74	8.86	1.95	(5.42)	(18.22)	(10.36)	(18.78)	(23.97)	(9.19)	(5.05)	(3.43)
Realized foreign exchange ($/boe)	(0.73)	0.28	0.48	(0.65)	2.33	(0.28)	(0.30)	0.10	(0.30)	0.37	(0.25)	(0.69)
Realized other ($/boe)	0.26	(1.32)	0.53	0.49	(0.14)	0.80	0.36	0.70	1.29	0.48	0.35	0.73
Fund flows from operations ($/boe)	48.83	35.74	32.35	34.52	35.08	67.07	58.82	50.79	40.73	33.27	22.04	21.66
Fund flows from operations	372,117	270,214	247,109	253,167	284,220	507,876	452,901	389,868	322,173	262,696	172,942	162,051
Drilling and development	(132,308)	(119,404)	(164,070)	(153,328)	(157,849)	(177,878)	(109,488)	(82,841)	(119,002)	(63,173)	(77,703)	(79,512)
Exploration and evaluation	(10,579)	(6,235)	(2,775)	(1,492)	(11,456)	(6,137)	(3,665)	(2,503)	(26,805)	(3,277)	(1,473)	(3,851)
Free cash flow	229,230	144,575	80,264	98,347	114,915	323,861	339,748	304,524	176,366	196,246	93,766	78,688

Vermilion Energy Inc.  ■  Page 52  ■  2023 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 condensed 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 condensed Consolidated Financial Statements).

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

Total of Segments Measure

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

	Q4 2023		Q4 2022		2023		2022
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Sales	522,969	68.64	842,693	103.99	2,022,555	67.10	3,476,394	111.95
Royalties	(45,148)	(5.93)	(68,303)	(8.43)	(191,694)	(6.36)	(306,017)	(9.85)
Transportation	(22,441)	(2.95)	(21,976)	(2.71)	(88,856)	(2.95)	(78,896)	(2.54)
Operating	(116,937)	(15.35)	(136,247)	(16.81)	(513,381)	(17.03)	(489,034)	(15.75)
General and administration	(19,810)	(2.60)	(13,344)	(1.65)	(80,716)	(2.68)	(57,677)	(1.86)
Corporate income tax expense	(19,374)	(2.54)	(41,958)	(5.18)	(91,932)	(3.05)	(208,153)	(6.70)
Windfall taxes	(249)	(0.03)	(222,859)	(27.50)	(78,426)	(2.60)	(222,859)	(7.18)
PRRT	20,860	2.74	(5,045)	(0.62)	20,860	0.69	(18,318)	(0.59)
Interest expense	(22,909)	(3.01)	(22,506)	(2.78)	(85,212)	(2.83)	(82,858)	(2.67)
Realized gain (loss) on derivatives	78,737	10.33	(43,940)	(5.42)	234,365	7.77	(405,894)	(13.07)
Realized foreign exchange gain (loss)	(5,529)	(0.73)	18,845	2.33	(4,532)	(0.15)	15,195	0.49
Realized other (expense) income	1,948	0.26	(1,140)	(0.14)	(420)	(0.01)	12,982	0.42
Fund flows from operations	372,117	48.83	284,220	35.08	1,142,611	37.90	1,634,865	52.65
Equity based compensation	(7,871)		(5,377)		(42,756)		(44,390)
Unrealized gain on derivative instruments (1)	141,126		549,693		179,707		540,801
Unrealized foreign exchange gain (loss) (1)	4,834		(47,405)		12,438		(84,464)
Accretion	(19,469)		(16,501)		(78,187)		(58,170)
Depletion and depreciation	(259,012)		(171,926)		(712,619)		(577,134)
Deferred tax recovery (expense)	110,758		(196,733)		190,193		(288,707)
Gain on business combination	(5,607)		—		439,487		—
Loss on disposition	(125,539)		—		(352,367)		—
Impairment (expense) reversal	(1,016,094)		—		(1,016,094)		192,094
Unrealized other income (expense) (1)	1,621		(563)		—		(1,833)
Net (loss) earnings	(803,136)		395,408		(237,587)		1,313,062

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

Vermilion Energy Inc.  ■  Page 53  ■  2023 Management's Discussion and Analysis

Non-GAAP Financial Measures and Non-GAAP Ratios

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

($M)	Q4 2023	Q4 2022	2023	2022
Cash flows from operating activities	343,831	495,195	1,024,528	1,814,220
Changes in non-cash operating working capital	(651)	(227,483)	61,117	(216,869)
Asset retirement obligations settled	28,937	16,508	56,966	37,514
Fund flows from operations	372,117	284,220	1,142,611	1,634,865
Drilling and development	(132,308)	(157,849)	(569,110)	(528,056)
Exploration and evaluation	(10,579)	(11,456)	(21,081)	(23,761)
Free cash flow	229,230	114,915	552,420	1,083,048

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

($M)	Q4 2023	Q4 2022	2023	2022
Drilling and development	132,308	157,849	569,110	528,056
Exploration and evaluation	10,579	11,456	21,081	23,761
Capital expenditures	142,887	169,305	590,191	551,817

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

($M)	Q4 2023		Q4 2022		2023		2022
Dividends declared	16,227		13,058		65,248		45,769
Drilling and development	132,308		157,849		569,110		528,056
Exploration and evaluation	10,579		11,456		21,081		23,761
Asset retirement obligations settled	28,937		16,508		56,966		37,514
Payout	188,051		198,871		712,405		635,100
% of fund flows from operations	51	%	70	%	62	%	39	%

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

	Twelve Months Ended
($M)	Dec 31, 2023		Dec 31, 2022
Net (loss) earnings	(237,587)		1,313,062
Taxes	(40,695)		738,037
Interest expense	85,212		82,858
EBIT	(193,070)		2,133,957
Average capital employed	5,819,380		5,628,762
Return on capital employed	(3)	%	38	%

Vermilion Energy Inc.  ■  Page 54  ■  2023 Management's Discussion and Analysis

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

	As at
($M)	Dec 31, 2023	Dec 31, 2022
Current assets	823,514	714,446
Current derivative asset	(313,792)	(162,843)
Current liabilities	(696,074)	(892,045)
Current lease liability	21,068	19,486
Current derivative liability	732	55,845
Adjusted working capital	(164,552)	(265,111)

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

($M)	Q4 2023	Q4 2022	Q4 2023	Q4 2022
Acquisitions, net of cash acquired	2,669	3,594	142,281	510,309
Acquisition of securities	17,448	964	21,603	23,282
Acquired working capital deficit	5,607	—	109,134	6,122
Acquisitions	25,724	4,558	273,018	539,713

Capital Management Measure

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

	As at
($M)	Dec 31, 2023	Dec 31, 2022
Long-term debt	914,015	1,081,351
Adjusted working capital	164,552	265,111
Unrealized FX on swapped USD borrowings	—	(1,876)
Net debt	1,078,567	1,344,586
Ratio of net debt to four quarter trailing fund flows from operations	0.9	0.8

Supplementary Financial Measures

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

('000s of shares)	Q4 2023	Q4 2022
Shares outstanding	162,271	163,227
Potential shares issuable pursuant to the LTIP	4,185	5,389
Diluted shares outstanding	166,456	168,616

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

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

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

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

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

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

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

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