Vermilion Energy Inc. Provides Operational Update

CALGARY, AB, Sept. 10, 2024 /CNW/ – Vermilion Energy Inc. (“Vermilion”, “We”, “Our”, or the “Company”) (TSX: VET) (NYSE: VET) is pleased to provide an operational update on key projects.

Vermilion Energy Inc. Provides Operational Update (CNW Group/Vermilion Energy Inc.)

In Germany, we successfully completed testing operations for our first deep gas exploration well drilled earlier this year. The well was completed in the Rotliegend zone at a depth of approximately 5,000 meters and flow tested at a restricted rate of 17 mmcf/d⁽¹⁾ of natural gas with a wellhead pressure of 4,625 psi. Given the high pressure reading from this well, we believe deliverability would have been higher without testing equipment limitations. These results are very encouraging and validate our initial assessment of the reservoir. Tie-in operations are progressing to bring the well on production in the first half of 2025. We expect this well to produce into a third-party system at a restricted rate.

Following the success of our first deep gas exploration well, we began drilling our second deep German exploration well in August 2024, a process that will continue through the fourth quarter. Recently, we signed an agreement with a third-party to farm down half of our working interest in this well to 30% (previously 60%) which will reduce our risked capital requirements and further enhance project returns. Consequently, along with deferring our 2024 drilling program in France to 2025, we have accelerated the drilling of a third deep gas exploration well (100% working interest) in Germany, which we expect to spud in the fourth quarter of 2024. Based on our technical evaluation, we expect this well to be a higher chance of success prospect, which is further supported by development in adjacent fields. We believe there is potential resource-in-place to justify follow-up drilling in the success case. We do not anticipate the results from the second and third wells will be known until the first half of 2025.

In Croatia, we successfully increased production on the SA-10 block after commissioning the gas plant in late June 2024. Current production levels now exceed 2,000 boe/d (100% gas). This high valued natural gas sells at a premium to the TTF benchmark contributing to strong operating and cash flow netbacks. We plan to maintain production on the SA-10 block in future years to maximize free cashflow and have identified prospects for future development. On the SA-7 block, we completed testing on the third well of our four-well program, which flow tested at 5.6 mmcf/d⁽²⁾ of natural gas. We plan to test the fourth and final well in Q4 2024. We are very encouraged with the four-well exploration results in Croatia, which have proven up multiple producing zones and de-risked future development and exploration targets across four discrete areas.

European natural gas production comprises 22% of our corporate production and 40% of our gas production. The primary benchmarks for European natural gas, TTF and NBP, are strong, with 2025 forward pricing of approximately $17/mmcf or approximately seven times higher than AECO. This pricing dynamic supports 2024 operating netbacks in excess of $55/boe⁽³⁾ from our European natural gas operations. We continue to actively hedge this period and have approximately 45% of European natural gas hedged with protection of $17/mmcf for 2025. Our continued operational successes in 2024 are supportive of near and long-term European natural gas exposure.

In Canada, on our Mica Montney asset, we recently brought five wells (5.0 net) on production from our 9-21 pad that were drilled and completed earlier this year. The wells produced at an average IP30 rate of over 1,000 boe/d⁽⁴⁾ per well (52% liquids)⁽⁴⁾ which is in line with our type curve. We continue to realize cost savings on each consecutive pad as we apply past learnings and incorporate new infrastructure and processes. The total drill, complete and tie-in cost for the 9-21 pad was approximately $9.6 million per well as we continue to make progress towards our normalized targeted cost range of $9.0 to $9.5 million per well. The new battery and water infrastructure have achieved 99% run time since starting up and are contributing to these cost savings.

In Australia, we accelerated annual turnround activity originally planned for Q4 2024 into Q3 2024 resulting in approximately one month of downtime during the quarter. We are currently restarting, and we expect the Q3 2024 production impact to be largely offset by the deferral of a third-party facility turnaround in Canada from Q3 2024 to Q4 2024. Our Q3 2024 capital program is progressing as planned and we remain on track to achieve our Q3 2024 production forecast of 83,000 to 85,000 boe/d and full year guidance range of 83,000 to 86,000 boe/d. Our 2024 E&D capital expenditure guidance remains unchanged.

We continue to be active under our NCIB program having repurchased 1.4 million shares during the month of August 2024. This increases our year-to-date total share buybacks to 7.5 million shares, representing a net share count reduction of 4.6% since the start of the year to 155.9 million shares at August 31, 2024. As we steward to our annual return of capital target of 50% of EFCF⁽⁵⁾ we plan to continue repurchasing shares through the balance of the year in addition to paying our quarterly dividend , which is reaffirmed at $0.12 per share for October 15, 2024, to shareholders of record on September 27, 2024.

We plan to release our Q3 2024 results on November 6, 2024, after the close of North American markets.

Osterheide Z2-2 well (100% working interest) is currently being tested. Flow rates, during the initial clean-up phase, of up to approx. 490,000 m3(Vn)/d with a flowing wellhead pressure of 4,625 psi on an adjustable choke were achieved. These initial flow results translate into an AOF of 986,000 m3(Vn)/d. The completion fluid was recovered during the clean-up flow period. The zone being tested is the Rotliegend Wustrow formation which was encountered at 5,757m MD and a 42.0 m gas column was logged with 13.8 m of net reservoir and average effective porosity of 8.3%. Test results are not necessarily indicative of long-term performance or ultimate recovery.
Gojlo-1 Jug well (60% working interest) tested at rate of 5.6 mmcf/d and flowing wellhead pressure of 692 psi during a well cleanup on a 0.5938” diameter choke. The well was shut-in and then flow tested for 24 hours on 3 choke sizes (0.25″, 0.3125″, 0.375″) to obtain necessary reservoir data and to minimize flaring. Gojlo-1Jug well tested 8.5 hours at an average rate of 2.9 mmcf/d with a flowing wellhead pressure of 861 psi on a 0.375” diameter choke. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1009 psi and bottom hole pressure of 1070 psi were recorded following the well test. The tested zone was the Mramor Brdo formation which was encountered at 885mMD and a 17.6m gas column was logged in the well to the base of the reservoir with 15.6m of net reservoir and an average porosity of 31%. Test results are not necessarily indicative of long-term performance or ultimate recovery.
2024 operating netback based on Company estimates using September 3, 2024, strip pricing: Brent US$80.84/bbl; WTI US$75.55/bbl; LSB = WTI less US$6.31/bbl; TTF $14.56/mmbtu; NBP $14.22/mmbtu; AECO $1.52/mcf; CAD/USD 1.35; CAD/EUR 1.47 and CAD/AUD 0.89. 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 presented on a per unit basis. Management assesses operating netback as a measure of the profitability and efficiency of our field operations. Operating netback per boe is not a standardized financial measure under IFRS and, therefore may not be comparable with the calculation of similar financial measures disclosed by other entities.
Initial 30-day production (“IP30”) for the Company’s most recent five (5.0 net) wells drilled on our British Columbia lands averaged 1,000 boe/d per well. IP30 consisted of 44% light and medium crude oil, 8% NGLs, and 48% shale gas, using a conversion of six mcf of gas to one barrel of oil, based on field level estimates for the first 30 full days of production following the tie-in of the well. Production rates presented are for a limited timeframe only and may not be indicative of future performance or the ultimate recovery for a given well or pad.
Excess free cash flow (“EFCF”) is comprised of free cash flow (“FCF”) less asset retirement obligations settled and capital lease payments, which are ongoing costs associated with running our business, and more accurately reflects the free cash available to return to shareholders. EFCF payout % reflects shareholder returns as a percentage of EFCF.

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: well production timing and expected production rates therefrom; wells expected to be drilled in 2024, 2025 and beyond; exploration and development plans and the timing thereof; petroleum and natural gas sales, netbacks, and the expectation of generating strong free cash flow therefrom; the effect of changes in crude oil and natural gas prices, changes in exchange and inflation rates; statements regarding Vermilion’s hedging program, its plans to add to its hedging positions and the anticipate impact of Vermilion’s hedging program on project economics and free cash flows; capital expenditures including Vermilion’s ability to progress towards its normalized targeted cost range and Vermilion’s ability to fund such expenditures; future production levels and the timing thereof, including Vermilion’s 2024 guidance, and rates of average annual production growth; statements regarding Vermilion’s normal course issuer bid; the release of Vermilion’s Q3 results and the timing thereof; 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; significant declines in production or sales volumes due to unforeseen circumstances; statements regarding the growth and size of Vermilion’s future project inventory, 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; 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; 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; constraints at processing facilities and/or on transportation; 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 and uncertainties related to environmental legislation, hydraulic fracturing regulations and climate change; 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; weather conditions, political events and terrorist attacks; 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 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.