Vermilion Energy Inc. Announces Results for the Three and Six Months Ended June 30, 2024

CALGARY, AB, July 31, 2024 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET) (NYSE: VET) is pleased to report operating and condensed financial results for the three and six months ended June 30, 2024.

The unaudited interim financial statements and management discussion and analysis for the three and six months ended June 30, 2024 will be available on the System for Electronic Document Analysis and Retrieval Plus ("SEDAR+") at www.sedarplus.ca, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.

Vermilion Energy Inc. Announces Results for the Three and Six Months Ended June 30, 2024 (CNW Group/Vermilion Energy Inc.)

Highlights

• Production during Q2 2024 averaged 84,974 boe/d⁽⁸⁾ (53% natural gas and 47% crude oil and liquids), comprised of 54,987 boe/d⁽⁸⁾ from our North American assets and 29,987 boe/d⁽⁸⁾ from our International assets. Production for the quarter was at the upper end of our Q2 2024 guidance range and represents an increase of 2% year-over-year, and 6% year-over-year on a per share basis, primarily due to Australia, as well as the start-up of the 8-33 BC battery on our Mica Montney asset, which facilitated higher production from our recent 16-28 BC Montney wells.
• Given the strong operational performance year-to-date, and anticipation of new production growth during the second half of the year in Mica and Croatia offsetting planned downtime, we are increasing our annual production guidance to 83,000 to 86,000 boe/d (from 82,000 to 86,000 boe/d previously), while maintaining our capital budget guidance of $600 to $625 million.
• Q2 2024 fund flows from operations ("FFO")⁽¹⁾ was $237 million ($1.48/basic share)⁽²⁾ and exploration and development ("E&D") capital expenditures⁽³⁾ were $111 million, resulting in free cash flow ("FCF")⁽⁴⁾ of $126 million ($0.79/basic share)⁽⁵⁾. The decrease in FFO from the prior quarter (Q1 2024 - $431 million) was primarily driven by lower realized commodity hedge gains.
• Vermilion returned $66 million to shareholders during Q2 2024, comprised of $19 million of dividends and $47 million of share buybacks, representing 62% of excess FCF ("EFCF")⁽⁴⁾. We repurchased and cancelled 2.8 million shares during Q2 2024 and plan to maintain a robust pace of share buybacks in the months ahead as we manage towards an annual return of capital target of 50% of EFCF. We have repurchased and cancelled 6.1 million shares year-to-date, and have reduced our outstanding common shares to 157.3 million at July 31, 2024.
• Net debt⁽⁶⁾ decreased by $38 million in Q2 2024 to $907 million, representing a net debt to trailing FFO ratio⁽⁷⁾ of 0.7 times and the lowest debt level in over a decade.
• In conjunction with our Q2 2024 release, we announced a quarterly cash dividend of $0.12 per share, payable on October 15, 2024 to shareholders of record on September 27, 2024.
• In Germany, we are currently equipping our first deep gas exploration well with production tubing in advance of a planned well test later this quarter. We continue to prepare for tie-in operations for this well, with an anticipated on-stream date of early 2025. We plan to commence drilling on the second exploration well (0.6 net) in the coming weeks.
• On the SA-10 block in Croatia, we completed construction of the gas plant and tied in the first of the two standing wells in late Q2 2024. The second well was tied in early Q3 2024 and production is ramping up, increasing our exposure to strong European natural gas prices.
• On the SA-7 block in Croatia, we drilled one (0.6 net) exploration well and completed two (1.2 net) wells from the prior quarter. The first well tested over 300 bbls/d⁽¹⁵⁾ of light oil, while the second well tested at 4.5 mmcf/d⁽¹⁵⁾ of natural gas. Subsequent to the quarter we completed drilling on the final well (0.6 net) of this four well program, and discovered hydrocarbons across multiple zones, representing a 100% success rate on this four-well exploration drilling campaign.
• In Canada, construction of the 16,000 boe/d BC Montney battery was completed during the quarter, with wells from our 16-28 pad tied-in prior to start-up. The completion of this battery was an important milestone in our BC Montney development and provides a runway for future production growth on our Montney asset. We anticipate the wells from our recently completed 9-21 BC pad to be on line by late Q3 2024. These wells were completed in significantly less time than previous wells and used approximately 30% less water, resulting in approximately 15% completion cost savings as we continue to drive efficiencies in our Mica Montney operations.
• We released the annual update to our sustainability reporting in July 2024. Our 2023 Scope 1 emission intensity is in line with our target to reduce our 2019 baseline by 15% to 20% by 2025. The full report is available at https://www.vermilionenergy.com/sustainability.

($M except as indicated)	Q2 2024	Q1 2024	Q2 2023	YTD 2024	YTD 2023
Financial
Petroleum and natural gas sales	478,925	508,035	471,356	986,960	1,024,054
Cash flows from operating activities	266,322	354,295	173,632	620,617	562,261
Fund flows from operations ^(1)	236,703	431,358	247,109	668,061	500,276
Fund flows from operations ($/basic share) ^(2)	1.48	2.68	1.51	4.16	3.05
Fund flows from operations ($/diluted share) ^(2)	1.47	2.64	1.48	4.11	2.99
Net earnings (loss)	(82,425)	2,305	127,908	(80,120)	508,240
Net earnings (loss) ($/basic share)	(0.52)	0.01	0.78	(0.50)	3.10
Cash flows used in investing activities	153,025	181,343	164,404	334,368	273,099
Capital expenditures^(3)	110,610	190,442	166,845	301,052	321,665
Acquisitions ^(9)	5,450	9,752	(9,716)	15,202	242,056
Dispositions	—	—	—	—	182,152
Asset retirement obligations settled	11,745	4,975	11,893	16,720	14,447
Repurchase of shares	46,555	36,409	24,316	82,964	54,457
Cash dividends ($/share)	0.12	0.12	0.10	0.24	0.10
Dividends declared	18,981	19,183	16,430	38,164	16,430
% of fund flows from operations ^(10)	8 %	4 %	7 %	6 %	3 %
Payout ^(12)	141,336	214,600	195,168	355,936	195,168
% of fund flows from operations ^(11)	60 %	50 %	79 %	53 %	39 %
Free cash flow ^(4)	126,093	240,916	80,264	367,009	178,611
Long-term debt	915,364	933,506	913,785	915,364	913,785
Net debt ^(6)	906,715	944,496	1,321,100	906,715	1,321,100
Net debt to four quarter trailing fund flows from operations ^(7)	0.7	0.7	1.0	0.7	1.0
Operational
Production ^(8)
Crude oil and condensate (bbls/d)	32,879	32,695	29,342	32,787	31,305
NGLs (bbls/d)	7,196	7,046	6,538	7,121	7,213
Natural gas (mmcf/d)	269.39	274.59	283.63	271.99	265.72
Total (boe/d)	84,974	85,505	83,152	85,240	82,805
Average realized prices
Crude oil and condensate ($/bbl)	108.93	104.26	96.64	106.49	97.66
NGLs ($/bbl)	31.61	34.16	28.11	32.87	32.53
Natural gas ($/mcf)	5.69	6.10	7.37	5.90	8.94
Production mix (% of production)
% priced with reference to WTI	32 %	32 %	32 %	32 %	35 %
% priced with reference to Dated Brent	15 %	15 %	12 %	15 %	11 %
% priced with reference to AECO	33 %	32 %	33 %	33 %	34 %
% priced with reference to TTF and NBP	20 %	21 %	23 %	21 %	20 %
Netbacks ($/boe)
Operating netback ^(12)	40.32	62.07	43.66	51.44	44.98
Fund flows from operations ($/boe) ^(13)	30.87	53.86	32.35	42.61	33.43
Average reference prices
WTI (US $/bbl)	80.57	76.96	73.80	78.76	74.97
Dated Brent (US $/bbl)	84.94	83.24	78.39	84.09	79.83
AECO ($/mcf)	1.18	2.50	2.45	1.84	2.84
TTF ($/mcf)	13.62	11.77	15.04	12.69	19.03
Share information ('000s)
Shares outstanding - basic	158,174	159,859	164,294	158,174	164,294
Shares outstanding - diluted ^(14)	161,672	164,044	168,530	161,672	168,530
Weighted average shares outstanding - basic	159,525	161,221	164,997	160,373	164,997
Weighted average shares outstanding - diluted ^(14)	161,069	163,648	167,364	162,022	167,364

^(1)	Fund flows from operations (FFO) is a total of segments measure comparable to net (loss) earnings that is comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, equity based compensation settled in cash, realized gain (loss) on derivatives, realized foreign exchange gain (loss), and realized other income (expense). The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations, and make capital investments. FFO does not have a standardized meaning under IFRS and therefore may not be comparable to similar measures provided by other issuers. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(2)	Fund flows from operations per share (basic and diluted) are supplementary financial measures and are not standardized financial measures under IFRS, and therefore may not be comparable to similar measures disclosed by other issuers. They are calculated using FFO (a total of segments measure) and basic/diluted shares outstanding. The measure is used to assess the contribution per share of each business unit. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(3)	Capital expenditures is a non-GAAP financial measure that is the sum of drilling and development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(4)	Free cash flow (FCF) and excess free cash flow (EFCF) are non-GAAP financial measures comparable to cash flows from operating activities. FCF is comprised of FFO less drilling and development and exploration and evaluation expenditures and EFCF is FCF less payments on lease obligations and asset retirement obligations settled. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(5)	Free cash flow per basic share is a non-GAAP supplementary financial measure and is not a standardized financial measure under IFRS and may not be comparable to similar measures disclosed by other issuers. It is calculated using FCF and basic shares outstanding.
^(6)	Net debt is a capital management measure comparable to long-term debt and is comprised of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current lease liabilities). More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(7)	Net debt to four quarter trailing fund flows from operations is a supplementary financial measure and is not a standardized financial measure under IFRS. It may not be comparable to similar measures disclosed by other issuers and is calculated using net debt (capital management measure) and FFO (total of segment measure). The measure is used to assess the ability to repay debt. Information in this document is included by reference; refer to the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(8)	Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion and Analysis for disclosure by product type.
^(9)	Acquisitions is a non-GAAP financial measure that is calculated as the sum of acquisitions and acquisitions of securities from the Consolidated Statements of Cash Flows, Vermilion common shares issued as consideration, the estimated value of contingent consideration, the amount of acquiree's outstanding long-term debt assumed, and net acquired working capital. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(10)	Dividends % of FFO is a supplementary financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers, calculated as dividends divided by FFO. The ratio is used by management as a metric to assess the cash distributed to shareholders. Reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(11)	Payout and payout % of FFO are a non-GAAP financial measure and a non-GAAP ratio, respectively, that are not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers. Payout is comparable to dividends declared and is comprised of dividends declared plus drilling and development costs, exploration and evaluation costs, and asset retirement obligations settled, while the ratio is calculated as payout divided by FFO. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(12)	Operating netback is a non-GAAP financial measure comparable to net earnings and is comprised of sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(13)	Fund flows from operations per boe is a supplementary financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers, calculated as FFO by boe production. Fund flows from operations per boe is used by management to assess the profitability of our business units and Vermilion as a whole. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
^(14)	Diluted shares outstanding represent the sum of shares outstanding at the period end plus outstanding awards under the Long-term Incentive Plan ("LTIP"), based on current estimates of future performance factors and forfeiture rates.
^(15)	Zbjegovaca-1 Istok well (60% working interest) tested at an average rate of 314 bbls/d during a 14-hour flow period with an average flowing wellhead pressure of 54psi on a 0.75 inch diameter choke. The flow test continued an additional 16 hours at reduced choke sizes (0.625" and 0.5") to obtain necessary reservoir information and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1077psi and bottom hole pressure of 2828psi were recorded following the flow test. The tested zone was the Okoli formation which was encountered at at 1991mMD and a 47.5m oil column was logged with 12m of net reservoir and average effective porosity of 14%.  Additional untested formations were also discovered. The Poljana was encountered at 1838mMD and a 63m oil column was logged with 39m of net reservoir and an average porosity of 11%, the Bujavica was encountered at 1194mMD and a 26m gas column was logged with 15.8m of net reservoir and average porosity of 21%. The test results are not necessarily indicative of long-term performance or ultimate recovery.
	Meduric-1 Istok well (60% working interest) tested at an average rate of 4.5 mmcf/d during a 2.5-hour flow period with a stabilized flowing wellhead pressure of 653psi on a 0.5 inch diameter choke. The flow test continued an additional 19 hours at reduced choke sizes (0.25", 0.3125", 0.375") to obtain necessary reservoir data and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1639psi and bottom hole pressure of 1784psi were recorded following the flow test. The tested zone was the Poljana formation which was encountered at 1236mMD and a 16m gas column was logged with 11.7m of net reservoir and an average porosity of 21%. Additional, untested formation were also discovered. The Bregi was encountered at 981mMD and a 23m gas column was logged with 13m of net reservoir and an average porosity of 27%, the Kutinski was encountered at 594mMD and a 14m gas column was logged with 10m of net reservoir and an average porosity of 32%.  The test results are not necessarily indicative of long-term performance or ultimate recovery.

Message to Shareholders

During the second quarter we achieved key operational milestones with the completion and startup of the Mica Montney battery in British Columbia and the SA-10 gas plant in Croatia. In Canada, we completed the Mica Montney battery and tied in production from the 16-28 pad during the second quarter, and subsequent to the quarter we completed fracking operations on the 9-21 pad which we expect to bring online in late Q3 2024. The startup of the Mica Montney battery will allow us to nearly double our Montney production to approximately 14,000 boe/d in 2025 and provides the platform for future expansion to 28,000 boe/d with further de-bottlenecking of infrastructure in the coming years. In Croatia, we commissioned the gas plant on the SA-10 block slightly ahead of schedule and currently have both wells on production. Bringing these wells on production will support the European gas weighting in our portfolio – approximately 40% of our corporate natural gas production, or over 100 mmcf/d – and allows us to take advantage of strong natural gas prices in Croatia, where gas sells at a premium to other European natural gas benchmarks. Over the past two years we have grown our European natural gas production by over 15%, and we continue to organically grow our European natural gas franchise. TTF Day Ahead natural gas prices averaged $13.62/mmbtu in Q2 2024, representing a 16% increase over Q1 2024, and are expected to further strengthen in the second half of this year and 2025, based on the forward strip. The TTF forward price is currently trading at approximately $17/mmbtu for 2025, which we have been actively hedging. For 2025 we have approximately 42% of our European natural gas production hedged at an average floor price of $17/mmbtu.

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

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

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

Q2 2024 Operations Review

North America

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

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

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

International

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

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

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

Outlook and Guidance Update

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

Commodity Hedging

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

(Signed "Dion Hatcher")

Dion Hatcher
President & Chief Executive Officer
July 31, 2024

^(1)	Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion and Analysis for disclosure by product type.
^(2)	Zbjegovaca-1 Istok well (60% working interest) tested at an average rate of 314 bbls/d during a 14-hour flow period with an average flowing wellhead pressure of 54psi on a 0.75 inch diameter choke. The flow test continued an additional 16 hours at reduced choke sizes (0.625" and 0.5") to obtain necessary reservoir information and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1077psi and bottom hole pressure of 2828psi were recorded following the flow test. The tested zone was the Okoli formation which was encountered at at 1991mMD and a 47.5m oil column was logged with 12m of net reservoir and average effective porosity of 14%.  Additional untested formations were also discovered. The Poljana was encountered at 1838mMD and a 63m oil column was logged with 39m of net reservoir and an average porosity of 11%, the Bujavica was encountered at 1194mMD and a 26m gas column was logged with 15.8m of net reservoir and average porosity of 21%. The test results are not necessarily indicative of long-term performance or ultimate recovery.
	Meduric-1 Istok well (60% working interest) tested at an average rate of 4.5 mmcf/d during a 2.5-hour flow period with a stabilized flowing wellhead pressure of 653psi on a 0.5 inch diameter choke. The flow test continued an additional 19 hours at reduced choke sizes (0.25", 0.3125", 0.375") to obtain necessary reservoir data and to minimize flaring. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1639psi and bottom hole pressure of 1784psi were recorded following the flow test. The tested zone was the Poljana formation which was encountered at 1236mMD and a 16m gas column was logged with 11.7m of net reservoir and an average porosity of 21%. Additional, untested formation were also discovered. The Bregi was encountered at 981mMD and a 23m gas column was logged with 13m of net reservoir and an average porosity of 27%, the Kutinski was encountered at 594mMD and a 14m gas column was logged with 10m of net reservoir and an average porosity of 32%.  The test results are not necessarily indicative of long-term performance or ultimate recovery.

Non-GAAP and Other Specified Financial Measures

This report and other materials released by Vermilion includes financial measures that are not standardized, specified, defined, or determined under IFRS and are therefore considered non-GAAP or other specified financial measures and may not be comparable to similar measures presented by other issuers. These financial measures include:

Total of Segments Measures

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

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

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

Non-GAAP Financial Measures and Non-GAAP Ratios

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

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

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

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

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

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

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

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

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

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

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

Capital Management Measure

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

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

Supplementary Financial Measures

Net debt to four quarter trailing 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.

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

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

Management's Discussion and Analysis and Consolidated Financial Statements

To view Vermilion's Management's Discussion and Analysis and Interim Condensed Consolidated Financial Statements for the three and six months ended June 30, 2024 and 2023, please refer to SEDAR+ (www.sedarplus.ca) or Vermilion's website at www.vermilionenergy.com.

About Vermilion

Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing assets in North America, Europe and Australia. Our business model emphasizes free cash flow generation and returning capital to investors when economically warranted, augmented by value-adding acquisitions. Vermilion's operations are focused on the exploitation of light oil and liquids-rich natural gas conventional and unconventional resource plays in North America and the exploration and development of conventional natural gas and oil opportunities in Europe and Australia.

Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized by leading ESG rating agencies for our transparency on and management of key environmental, social and governance issues. In addition, we emphasize strategic community investment in each of our operating areas.

Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.

Disclaimer

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

Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities; the impact of Vermilion's dividend policy on its future cash flows; credit ratings; hedging program; expected earnings/(loss) and adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and free cash flow and expected future cash flow and free cash flow per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; general economic and competitive conditions; ability of management to execute key priorities; and the effectiveness of various actions resulting from the Vermilion's strategic priorities.

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

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

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

This document contains metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

SOURCE Vermilion Energy Inc.