Good morning, everyone, and welcome to the VAALCO Energy's Third Quarter 2025 Conference Call. Please note today's event is being recorded. At this time, I'd like to turn the floor over to Al Petrie, Investor Relations Coordinator. Sir, please go ahead.

Thank you, operator. Welcome to VAALCO Energy's Third Quarter 2025 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the third quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. I'd like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparison and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website and in the reports we file with the SEC, including our Form 10-K. Please note that this call is being recorded. Let me turn the call over to George.

Thank you, Al. Good morning, everyone, and welcome to our third quarter 2025 earnings conference call. For over two years, every quarterly earnings call, we have met or exceeded our production guidance, consistently leading to strong operational and financial results. The third quarter was no different with NRI production of 15,405 BOE per day, which was at the high end of guidance; working interest production of 19,887 BOE was above the midpoint of guidance, and NRI sales of 12,831 BOE per day, which was also at the high end of guidance. Our production and sales performance through the first 9 months of 2025 has been so strong that we have raised the midpoint of our full year production and sales guidance by about 5%, while also further reducing our capital guidance by almost 20% and maintaining our operating expenses virtually flat. Ron will go into more detail about our guidance later in this call, but we believe that maintaining operational excellence and consistent production across our portfolio is essential to continued strong adjusted EBITDAX generation, which will assist us in funding organic growth initiatives while positioning us as a larger player in the industry. In the first 9 months of 2025, we have delivered net income of $17.2 million or $0.0016 per share and adjusted EBITDAX of $130.5 million. It is important to remember that 2025 is a transitional year, and everything remains on track with our forecast. Production came offline in Q1 at Cote d'Ivoire due to the FPSO project, and we do not expect to start the drilling campaign in Gabon until late Q4 as we await the drilling rig's completion of its current commitments. This means that the meaningful production uplift we are projecting for these major projects won't begin until 2026 and into 2027. I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d'Ivoire. In line with the project timeline, the FPSO ceased hydrocarbon operations are scheduled on January 31, 2025, with the final lifting of crude oil from the vessel occurring in early February. The vessel departed from the field in late March and arrived at the shipyard in Dubai ahead of schedule in mid-May 2025. The FPSO refurbishment is well underway in the shipyard. Significant development drilling is expected to begin in 2026 after the FPSO returns to service with potential meaningful additions to production from the main Baobab field. We now have a 10-year extension of the license on CI-40, extending it to 2038. In March 2025, we announced a farm-in agreement for the CI-705 block offshore Cote d'Ivoire where we will operate with a 70% working interest and a 100% paying interest. In Q2, we received seismic data for the block, and we are conducting a detailed integrated geological analysis to assess and mature our understanding of the block's overall prospectivity as well as the basin's overall potential. We believe the block is favorably located in a proven hydrocarbon system and is approximately 70 kilometers to the west of our CI-40 block. We have demonstrated our ability to acquire, develop and enhance value through accretive acquisitions, and we are excited about the prospects in Cote d'Ivoire. Moving to Gabon; given that we haven't drilled a well in Gabon in over two years, we are very pleased with the positive overall production results, including strong production uptime and improved decline curves on the wells in 2025. In July, we successfully completed a planned full field maintenance shutdown of the Gabon platforms to perform safety inspections and necessary maintenance. This is the first time we have had to perform a full field shutdown in Gabon since the FSO was brought online in 2022. This has helped to contribute to the strong uptime numbers in Gabon that we have had over the past several years, which can be seen in our supplemental presentation. While we secured a drilling rig in December 2024 for our 2025-2026 drilling campaign, the timing of when we start the drilling program has always been dependent on the rig's completion of its existing commitments. The rig is now being released and moving to Gabon. As we discussed in the Capital Markets Day, we have some very strong drilling opportunities and the additional data gathered during the upcoming drilling program will help us high grade and derisk additional well locations that have already been identified. We plan to begin the drilling program on the Etame field platform, and we are currently planning on moving to the Ebouri wells later in the program because of the current robust production profile of these wells. In particular, we remain very pleased with the extended flow test on Ebouri 4H well, which is continuing to surpass our initial expectations. We originally wanted to gather information on the H2S concentrations at this location to aid in equipment design and to evaluate our chemical crude sweetening process. The 4H well has now flowed for all of 2025 at a gross average of around 1,000 barrels of oil per day with the H2S concentration within our modeling expectations, demonstrating our ability to chemically treat the oil. The wells production has helped Gabon exceed its production guidance in 2025 while adding some additional production costs for chemicals. Regarding our exploration blocks in Gabon, the Niosi Marin and the Guduma Marin, we are working in conjunction with our partners and the operator, BW Energy, on plans for the two blocks moving forward. A seismic survey to fulfill a work commitment on Niosi is being planned for acquisition in late 2025 or early 2026. Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks. Turning to Egypt; in the fourth quarter of 2024, we contracted a rig and drilled two wells starting a drilling campaign that has carried into the first 9 months of 2025. We have drilled and completed multiple wells in the first 9 months of 2025 and are continuing activity into the fourth quarter. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. We've been able to drill more wells faster and cheaper than what we had in the budget and for the same amount of capital, which has also positively impacted the production. We also continue to workover and recomplete wells in Egypt. Both the drilling program and the workover program in Egypt add solid production and are economic even in lower commodity price environments. We are continuing to evaluate the exploration results in South Ghazalat, where the wells are encountering both oil and gas net pay zones with different levels of reservoir pressure. We are incorporating well results and updating our understanding of the area with new mapping that will determine potential additional prospectivity for the area. In March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. This summer, we began our Front End Engineering Design or FEED study. The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risk and challenges from the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development, which would also significantly simplify the drilling operations and well design, and this is currently underway. We are very excited to proceed with our plans to develop, operate and begin producing from the discovery on Block P offshore Equatorial Guinea in the next few years. Turning to Canada; we successfully drilled and completed four wells in 2024. We also drilled a well in the Southern Acreage in late 2024 that could help us better understand the acreage and upside in that area. While we remain optimistic about the drillable inventory in Canada, we decided to postpone our Canadian drilling program in 2025 due to the current commodity price environment. We will continue to monitor the performance of our wells and plan for future drilling opportunities. Before I turn the call over to Ron, I would like to thank our hard-working team who continue to operate and execute our strategic vision and help us deliver these outstanding results. We are well-positioned to execute the projects in our enhanced portfolio and our proven track record of success in these past few years should instill confidence for our future. With that, I'd like to turn the call over to Ron to share our financial results.

Thank you, George. And once again, good morning. I will provide some insight into the drivers for our financial results with a focus on the key points. Let me begin by echoing George's comments about our continued success through the first 9 months of 2025, driven by our strong operational performance. We have met or exceeded production guidance for the past 2-plus years, driven by strong production in Gabon and Egypt despite Cote d'Ivoire being offline since late January. This performance has allowed us to positively adjust the midpoint of our full year production and sales guidance. In the supplemental deck on our website, you can see that NRI production is up 900 BOE per day and sales are up 750 BOE per day. You will also see that our full year capital midpoint guidance is down almost $60 million to around $240 million in total. Finally, we have worked hard to keep our absolute production expense in line with our original guidance. But with the increase to sales and production, our production expense on a per BOE basis is down about $1 per BOE. Our overall results and ability to manage multiple assets and high profile capital projects across multiple countries are reflected in our updated 2025 guidance. For Q4 2025, we are forecasting production to be between 20,300 and 22,200 working interest BOE per day and between 15,600 and 17,300 NRI BOE per day. This is up compared to the third quarter due to the planned maintenance turnaround that occurred in Gabon in July and continued strong production in Egypt. For the fourth quarter, we are forecasting our sales will also be higher compared to Q3 due to more offshore listings in Gabon. We also expect our absolute operating costs to be higher compared to Q3 due to the additional sales, but virtually flat on a per barrel of oil equivalent basis. Finally, looking at CapEx, our Q4 spend is expected to be higher than the third quarter as we begin the drilling campaign in Gabon. We are forecasting between $90 million and $110 million, and we anticipate continued spending in CDI and Egypt in Q4 more or less in line with Q3. In the third quarter, we generated $1.1 million in net income or $0.01 per share and $23.7 million in adjusted EBITDAX. Our NRI sales for the quarter were at the high end of guidance at 12,831 BOE per day. Both sales and pricing moved against us in the third quarter, with sales down 33% due to the fewer listings in Gabon, driven by the planned turnaround and pricing was lower by about 7% quarter-on-quarter. We have seen higher volatility in the commodity price environment thus far in 2025. Our hedging program has always looked to help mitigate risk and protect our cash commitments. But with the RBL now in place, we are moving towards a more programmatic hedging program that will be more consistent over a rolling time horizon. With this in mind, we took advantage of periods of higher oil prices during the third quarter to add more hedges for the 2026 hedging program. The company now has about 500,000 barrels of remaining 2025 oil production hedged with an average floor of approximately $61 per barrel and about 800,000 barrels of oil production hedged for the first half of 2026 with an average floor of approximately $62 per barrel. We are targeting around 40% of Half 1 2026 oil production to be hedged by year-end. Our full hedge positions are disclosed in the earnings release. Turning to costs; our production costs for the third quarter of 2025 were at the low end of guidance on an absolute basis and on a per barrel basis. Absolute expense was $29.87 million, a 26% reduction quarter-over-quarter and on a per barrel basis was $25.24. G&A costs were in line with guidance and remained relatively flat quarter-over-quarter. Our focus remains on keeping our costs low to enable us to maximize margins and increase our cash flow. Moving to taxes; we reported an income tax benefit of $3.6 million for Q3 2025, which was comprised of an $8.6 million current tax expense, offset by a deferred tax benefit from Gabon's allocation of profit oil between the time it was produced and the time it was taken in kind. Turning now to the balance sheet and cash flow statement. Unrestricted cash at the end of the third quarter was $24 million. Collections from the Egyptian General Petroleum Corporation, EGPC, since the 1st of January 2025 totaled over $103.6 million, and the company expects to receive further material payments against its arrears before year-end. We anticipate that our annual receivables balance will be half of what it was in 2024 by year-end. Monthly invoices are now paid in full and regular repayments are being made against the receivables balance. As we discussed last quarter, we added a reserves-based credit facility with an initial commitment of $190 million and the ability to grow to $300 million. Shortly after the third quarter, we successfully completed our semiannual redetermination with lenders and reaffirmed the initial commitments. As of September 30, 2025, VAALCO had $60 million outstanding borrowings, which is the same amount outstanding as we had at the end of the second quarter. In Q3, we spent $48.3 million in cash CapEx, well below our third quarter guidance of $70 million to $90 million. Additionally, we returned $6.7 million through dividends to our shareholders. We believe that our current dividend yield of around 7% is very attractive, especially considering the meaningful upside potential in production and reserve growth that we outlined in the Capital Markets Day over the next few years. In closing, we're continuing to see strong results. We are well-positioned to execute and fund a robust organic capital program that should help to increase production and reserves for 2026 and beyond. With that, I'll now turn the call back over to George.

Thanks, Ron. We will continue to execute a strategy focused on operating efficiency, investing prudently, maximizing our asset base and looking for accretive opportunities. As you have heard this morning, we continue to meet or exceed both our quarterly guidance and analyst estimates in the first 9 months of 2025 as we have done for the past several years. This has allowed us to increase our full year production guidance by about 5% while lowering our full year capital guidance by about 20%. By delivering on our commitments to the market, I believe we have earned the credibility with our shareholders, and we will continue to deliver on the exciting slate of projects that we have over the next few years. Our entire organization is actively working to deliver sustainable growth and strong results. We have multiple major projects underway that are anticipated to meaningfully grow production and reserves. Through the first 9 months of 2025, we have generated $130.5 million in adjusted EBITDAX, and this is with Cote d'Ivoire offline for the FPSO project and no new wells drilled in Gabon. In addition to funding our capital program, we have remained focused on returning value to our shareholders. In the first 9 months of 2025, we returned around $20 million to our shareholders through dividends. With the Q4 dividend announcement, we will deliver another $0.0025 per share annual dividend for 2025, which at our current share price is a dividend yield of about 7%. We are confident in our ability to execute on the many projects ahead, largely because we have been highly successful over the past several years developing and growing our assets. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserves and cash flow has led to outstanding results and has positioned us to continue to profitably grow in the future. Thank you. And with that, operator, we're ready to take questions.

Our first question today comes from Stephane Foucaud from Auctus Advisors.

I have two questions. The first is about capital expenditures. What will the capital expenditure mix look like across the assets in 2025, and what does the reduction in capital expenditures for 2025 imply for 2026? How will the capital expenditures in 2026 compare to those in 2025? My second question is regarding South Ghazalat. In your opinion, if successful, how significant could South Ghazalat be, and how do the results relate to the existing reserves in Egypt?

Hi Stephane, it's Ron here. I'll address the first question on CapEx and its guidance. Looking at the midpoint of our guidance, we've adjusted it by about $60 million. Out of that, $20 million has been removed, which was discretionary CapEx scheduled for 2025. We’ve seen a $10 million increase in CDI CapEx to keep the MV-10 project on track, which is great news as everything is progressing well with that project. The remainder reflects a shift in Gabon from the drilling campaign due to delays in moving the rig from 2025 to 2026. Regarding Egypt, the CapEx remains consistent with our original guidance, but we will have completed 8 additional wells during that timeframe for the same CapEx, showcasing the efficiency our team has achieved for 2025.

And on South Ghazalat, one of the additional wells, as you know, Stephane, was out there, and I tried to touch on it in my comments earlier. So what we've seen there in the well that we drilled, we entered the gas prone zone with lower pressures, which indicates that there's potentially some gas depletion there. And we also entered an oil proven zone that had no pressure. So what we're trying to establish now is the total extent of the oil zone, what that aerial extent could be and how large that could be for potential development and then understanding the reduced pressures around the gas zone and where that depletion may be. So having got the results of the well, we're going back to do our after-action review and establish where else within the existing structure that we understand, we'd want to drill additional wells there. There are a couple of things outstanding in South Ghazalat. Whilst we had some commitment wells that we've already completed to keep the acreage. But in addition to that, we've also got some commercial issues around the PSC that we have to discuss before we get anywhere close to some kind of preliminary field development plan. So there's more technical work to do, but there's also some more commercial work to do. We've always been hopeful that because it's such a prolific area out there in the Western Desert that this block will yield some interesting opportunities for us, but that's still to be developed and it's still to be evaluated at this time.

Our next question comes from Jeff Robertson from Water Tower Research.

Ron, can you confirm that approximately $20 million of the reduced guidance for CapEx is a permanent decrease? In other words, are we either achieving tasks at a lower cost than expected or accomplishing more with the same budget?

That's exactly right, Jeff. As you know, we took Canadian drilling CapEx out very early, I think, in Q2 guidance, we pulled that out. That was about half of that. The other half is just discretionary CapEx that we pulled out over the last 3 or 4 months.

Are the efficiency gains that have helped in Egypt, are those sticky? In other words, would you retain those types of efficiencies if you look at a CapEx program in Egypt in 2026?

Yeah. I mean what we've got, Jeff, as you know, we've reduced that spud to basically take an online cycle time quite considerably over the last three years. We continue to drill and complete and bring online those wells at a much lower level of days versus what our initial expectations were. So those efficiencies are real. They're there. And if they continue into 2026, we'll continue to see less AFE costs for drilling in Egypt.

Okay. And on the RBL Ron, I believe the electric commitments is going to go up to $240 million in January. Is that a reflection of asset performance?

I think it's more a reflection of the current market, Jeff. I mean liquidity is going to be key for all upstream companies as we move into 2026, with softening commodity prices. And from our point of view, we have the availability there. I'd rather lock it in when we've been in a position of strength than when in a position of need.

Our next question comes from Christopher Wheaton from Stifel.

I have a couple of questions. First, regarding Gabon production. As you mentioned, there hasn't been any drilling for two years. Even with the delayed Gabon drilling program, the production has been quite strong, even though uptime is slightly lower compared to last year. I'm curious if the geology has improved or if there are specific wells that are performing better than anticipated. What factors are contributing to that production uptime? My second question pertains to the 2026 capital expenditures and your flexibility with that, especially with more of the Gabon drilling campaign extending into 2026, along with the CapEx for Côte d'Ivoire as well. I'm interested in your key priorities for determining the 2026 capital budget considering there are several must-do items. Realistically, will we see much flexibility in CapEx below the levels projected for 2025 for the 2026 guidance? I'll stop there.

Let me start on Gabon. Since we've completed the reconfiguration, we have seen a significant reduction in back pressure into the reservoir, which has improved not only well performance but also overall field performance. We have been working on the brewery side to maintain production in 2-H and have also brought on 4H. This was done intentionally to assess the levels of H2S that can be managed through the scavenger program. We have continued to see 4H produce throughout 2025 with H2S levels well within our manageable range, which is encouraging. This will also enable us to explore the potential for 2H workovers and redrilling 5H in the drilling program. The test wells we are bringing back online are essential for understanding how we will manage potential future H2S issues. When examining production profiles for the Etame field, we see production exceeding the 1P decline curve and, in some instances, entering the 2P position. Questions arise regarding the size of the tank, with recovery factors increasing to the 50 percentile and above. Ongoing geological remapping work is necessary to improve our understanding of this field. I reflect on decisions made in the early 2000s, when this field had an expected lifespan of 5 years, and now, over 20 years later, it has produced nearly 150 million barrels and continues to perform. The studies we have planned for the next 6 months should provide a clearer understanding of the geology and whether there is connectivity between the Gamba and Dentale layers that is contributing to production levels. Regarding the 2026 CapEx position, as Ron mentioned, the delay in the rig coming to us for 2025 has pushed back our Gabon program. We have a firm commitment for 5 and 5 options in Gabon, allowing some flexibility in our drilling plans. However, we have been studying these drilling locations for a few years and have some strong targets, which should lead to meaningful production increases in Gabon. Although there may be less flexibility in the Gabon drilling campaign than we would prefer, it carries the advantage of substantial additional production. Concerning Cote d'Ivoire, as Ron indicated, we are allocating more CapEx in 2025 to ensure the FPSO sail away date at the end of March is met, and we have discussed this in detail with the operator. A drilling program is scheduled to begin in the second half of 2026, although its exact timing will depend on rig availability and equipment. Thus, there may be some flexibility. Nonetheless, these investments are expected to significantly boost production. In Cote d'Ivoire, all spending is recoverable, yielding $1.25 back for every dollar spent in cost oil. While the CapEx in 2026 may appear less flexible than in 2025, it comes with substantial benefits.

Our next question comes from Charlie Sharp from Canaccord.

Can you hear me?

Yes, we can hear you.

Sorry about that. I was on a separate phone and here we are. So the question really is regarding timetabling of events next year. And I think you've just provided some useful information there on the planned sale away of the Baobab FPSO. I'm guessing from that, that you still expect to be back on stream there before the middle of the year in order to facilitate drilling sometime in the second half. That's one small question. And then secondly, on Gabon, should we assume that you're drilling wells about one per quarter, in which case you'll probably be drilling into 2027? And will you be completing successful wells as you go or will you batch drill and batch complete?

I’ll begin by confirming your assumption. The sail away date remains set for the end of January after the second dry dock period. The hookup is planned for late March to early April, and we expect to be back in production by late April to early May, well ahead of the drilling program. As we approach 2026, we will align this with our guidance and provide more detailed information at that time. Currently, everything related to the project is on schedule. Regarding Gabon, we've dedicated considerable time to evaluating drill locations. The seismic imaging here isn't as clear as we would prefer due to salt interference. Nevertheless, we plan to drill pilot holes at selected locations to determine the exact levels of hydrocarbons, which will allow us to adjust and possibly redrill or complete in different zones. At this time, we are starting with two pilot holes in the Etame field. If both meet our positive geological indicators of over 80%, we will continue drilling and completing as we proceed. Therefore, we could potentially drill three wells in Etame, one in Seent, along with a workover not far from Ebouri.

Our next question comes from Bill Dezellem from Tieton Capital Management.

Relative to the Cote d'Ivoire drilling program, you'd mentioned that that will begin in the second half of next year. Given that the FPSO will be back in the field and reconnected in May, what's the swing factor or swing factors that would drive the drilling earlier in the second half versus later in the second half?

Okay. So the biggest swing factor is exactly what we face in Gabon is the drilling unit arriving on time. When we look at where we are today, though, all the long lead items, the trees and the equipment, et cetera, are all ready to go. So it's all around the drilling unit and the timing of that. So when it comes off its existing contract, as you know, we may have a scheduled date, but if it's halfway through drilling a well for a previous client, then it has to complete that well before it comes to us. So it's really just the rig move would be the swing factor.

That's helpful. And then relative to Equatorial Guinea, you'd mentioned that you're looking at a subsea completion application. Was that part of the FEED study or are you now needing to do essentially a sidebar FEED study?

What we aimed to achieve in the FEED study was to find ways to reduce the capital expenditures in the Plan of Development. We explored using a mobile offshore production unit, which is a self-elevating platform, instead of a capital unit. The study revealed that while it's possible to determine precise locations for the wells, the complexities of shelf drilling make it challenging, especially for two producers and a water injector with a long lateral for efficient production flow. Sweep efficiency is crucial for the recovery factors and production profiles we've projected for Venus. During the FEED process, we developed a new static and dynamic model, confirming the volumes we shared at our Capital Markets Day. The importance of water injector sweep efficiency is vital for reaching these production levels, so we assessed the associated risks. We found that switching to a vertical drillship would significantly reduce those risks compared to drilling from the shelf, and this approach indicated clear advantages. While it would lead to reduced drilling times, it would come with higher day rates. Overall, the economics favor the drilling approach. We are now examining our options for production, focusing on whether we can acquire a floating production storage and offloading unit at a reasonable price that meets our needs efficiently. There are numerous units available in the market currently at competitive prices due to a decline in other areas. Our goal is to determine whether we can minimize the drilling risks and align them with an effective production strategy.

Our next question comes from Jeff Robertson from Water Tower Research.

George, just a quick question in Cote d'Ivoire. When the FPSO gets back to Baobab, how long would it take do you anticipate for production in the field to go back to whatever the full rate will be?

We've got the vessel returning to the field, and we have the contract for the hookup and repositioning the flow lines, followed by commissioning. Right now, we expect that process to take about 6 to 8 weeks. However, we haven't yet determined the start-up sequence. After commissioning, we need to plan the start-up for the wells and identify the specific sequence for the injectors and producers. We'll provide more detailed guidance on the start-up sequence during our next call in early '26.

Just one more in Gabon. With the maintenance work that you did in July, what will that do to prepare the facilities, if anything, for the upcoming drilling campaign?

I think we made significant upgrades to Etame in terms of power and water handling. Everything is now completed and prepared for the upcoming drilling campaign. That's basically what was accomplished, along with the standard planned inspection.

And ladies and gentlemen, at this time, we've reached the end of today's question-and-answer session. I'd like to turn the conference call back over to George Maxwell for any closing remarks.

Thank you very much, operator. I'd just like to close, we've had a strong third quarter and some good results in the third quarter despite the reduced volumes in net sales because of the government liftings that took place this quarter. The position that we're in coming into 2026 with the execution of our projects leaves us in a strong position. There are no concerns around where we are in the main capital project around the FPSO for Cote d'Ivoire. That project remains on track, and we monitor it very closely with our partners. I'm very encouraged that we're finally getting going on the drilling campaign, albeit there's a 4-month delay in the rig arriving. But that's very encouraging, and it shows our commitment both to Gabon and our commitment to CDI for our investment. We've seen strong EBITDAX performance over and above guidance this quarter, which maybe was a bit masked by the revenue. But again, with the lower revenue and higher EBITDAX indicates the company's focus on its cost control during this period of softening commodity prices. So I'm encouraged that when we come to talk again early Q1 that we will complete 2025 on a successful basis. As you've seen, we've narrowed the guidance to give further confidence to the market as we see our position narrowing to improve the profile through Q4. And with that, I look forward to talking to you again in Q1 2026. Thank you.

And ladies and gentlemen, with that, we'll conclude today's conference call and presentation. We do thank you for joining. You may now disconnect your lines.