Vermilion Energy Inc. ("Vermilion", "We", "Our", or the "Company") (TSX: VET) (NYSE: VET) is pleased to provide an operational update on key projects.
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.
1- 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.
2- 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.
3- 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.
4- 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.
5- 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.
