Welcome to the BW Energy's Q3 presentation for 2023. For the first part of this call, all participants are in a listen-only mode. Afterwards, there'll be a question-and-answer session. To ask a question during the Q&A, please press five star on your telephone keypad. This call is being recorded. I'll now turn the call over to the speakers. Please begin. Thank you. This presentation will be, as usual, hosted by Knut Sæthre, our CFO, Lin Espey, our Chief Operating Officer, and myself, Carl Arnet. Then on to our disclaimer. Please note it, and then we go on to the highlights of the third quarter. Q3 gave us a gross production from Gabon and Brazil of 27,400 barrels per day. We had four producing Hibiscus wells at the end of the quarter, and we in the quarter assumed 100% ownership and operatorship of Golfinho. That was from late August. We also made a subsequent discovery of oil in the Hibiscus South, which we will cover in more detail later in the presentation. Q3 gave us a EBITDA of $49.7 million, with a net profit of $500,000. We did one lifting in the quarter of 950,000 barrels, with a lifting price of $79 per barrel. The Golfinho prepayment facility was completed and drawn in the quarter, as well as our cash position, which was $198 million, which is healthy. We delivered in the quarter a strong production growth, with an 80% increase in gross production, from operated assets, compared to the second quarter. We also, in the quarter, achieved a combined production milestone of 50,000 barrels per day gross production. We achieved that on 20th October. That's equivalent to approximately 40,000 barrels net to BW Energy. And this shows the very strong reservoir performance from Dussafu. This is the good news, that our wells and the reservoir is performing very well, but we still have ESP challenges, and these impact, of course, the overall production availability. And we will cover that in more detail later in the presentation. We had no recordable lost time incidents from the Hibiscus/Ruche project all the way to first oil, and we're extremely proud of that record. But unfortunately, we had one lost time incidents in the third quarter, giving us a total recordable incident rate of 1.5. We had, again, no environmental incidents in the third quarter, and we have had none year to date. Then on to the Dussafu asset and cover developments there in a bit more detail. So the production update is that the Q3 gross production was 2.14 million barrels, which is equal to 23,200 barrels per day. We had production from two new Hibiscus wells, and we started up the gas lift compressor on Adolo, which is of course helping the Tortue production. The OpEx declined to about $28 per barrel on the increased production. We have ongoing troubleshooting efforts with the ESPs. These ESPs are wireline retrievable ESPs. They are of a new but tested design. We're working very closely with Baker, the supplier, to identify and resolve the situation, but we have to carry out a lot of tests, and we are monitoring, of course, the operation. The problem seems to be in electrical, either connections or in the motors, which may cause us to start pulling the ESPs to do further, let's say, investigation into what is the basis of these problems we're having. Then on to the drilling program for Hibiscus/Ruche. Drilling results so far in the Hibiscus asset shows that we have a slightly larger resource than what was the anticipation. While the drilling results from the Ruche shows a slightly smaller resource than previously modeled. But the net is a positive of about 10 million barrels oil in place, which is, of course, good. Our firm drilling program is now 8 wells. We have already completed four Hibiscus wells and put them in production. We were in about to complete the first Ruche well as well. It's been drilled, but we had a stuck casing, and we needed to find an alternative casing. So that has been suspended. We have, in the meantime, drilled the Hibiscus prospect, so that's an appraisal prospect, and which came in, and I'm going to cover that in more detail later. We plan to substitute the second Ruche well with a fifth Hibiscus well, the DHIBM-07H, and we plan to sidetrack and complete the new discovery on Hibiscus South with a production well. And then the last well of the current drilling program will be drilling of the Bordeaux Prospect or Prospect B, as it was called earlier, and that will be the second and appraisal prospect in this campaign. The oil discovery in Hibiscus South was made with a long-reach well from MaBoMo. We drilled to a total depth of 6,000 m, which is one of the longest wells ever drilled in Gabon. The well data shows 20 m of pay in a hydrocarbon column of about 26.5 m in the Gamba formation. Preliminary evaluation indicates a gross recoverable reserve of 6 million-7 million barrels. The Hibiscus South is a separate compartment. It's not a continuation of the Hibiscus. We expect then to complete it, as I said, with a production well early in 2024, and we plan to do this in the current drilling program. This is, of course, a very low cost and low-risk expansion to production and to increase our reserves. But it also underpins the very prolific nature of the Dussafu license. Production outlook. The production outlook is affected by our ESP problems. We plan two liftings in the fourth quarter. 950,000 barrels in October at $79, and then another lifting 650,000 barrels in November, early December. The production expectation is 6.7 million barrels with an annualized average of $30 per barrel. For 2024, we expect to be still affected by the ESP issues, although we do expect to solve these issues. We expect to have some effects of that in 2024, and we think a reasonable estimate for our production in 2024 will be 10 million-12 million barrels. We will obviously work hard to achieve better, but that is how we see things today. You see the lifting schedule in the bottom left-hand corner and the new production profile in the bottom right-hand corner of this slide. Then on to Golfinho. We took over as operator of the Golfinho assets in Brazil, late August. We have 100% interest, as I previously told you in these presentations, in the Golfinho and Camarupim clusters, and now as 76.5% in Brigadeiro. One of the parties in the Brigadeiro license has relinquished the license and given their share to the two remaining owners. And this is in the process of being approved by ANP. We're also in the process of taking over the FPSO Cidade de Vitória from Saipem, and the... We are just about to take over. Again, waiting for a final approval from ANP, which we expect to receive shortly. The field production has stabilized well after an extended shutdown. And, well, good for us that there, there was an extended shutdown because we could then monitor the recovery of the reservoir, and our modeling shows that this gives us an increased or shows an increased resource, recoverable resource than compared to previous plans. So we have a slight increase in the recoverable resource. And, we are now working with a program where we expect to drill two infill wells, one oil well and one gas well, and resulting in a significant increase in production, from late 2026.... In terms of production update from Golfinho, we had a production of 381,700 barrels from 28 August until 30 September, end of quarter. That was equal to 11,200 barrels per day. We expected, or our expectations were around 9,000 barrels per day. The production cost, excluding royalties, averaged $48 per barrel. We had no liftings in the third quarter, and we are planning two liftings in the fourth quarter. The first we did early November, so it's already been done. It was 521,500 barrels, and then we're planning a second lifting in December. In the right-hand caption, you see the Golfinho gas production and the forecast going forward there. Then on to Maromba. We are optimizing or continuing to optimize the development plan. The current prospect or concept is to build a dry tree unit and still based on the Polvo, a refurbishment of the Polvo facility. We have now paid the first installment of the FPSO, and we are continuing to define the refurbishment and upgrade project. The final investment decision, project start, remains subject to conclusion of project financing. We expect to have our revised plan and financing completed by the second quarter 2024. The plan is still to produce around 30,000-40,000 barrels per day from this field. Then on to Kudu. Kudu is probably one of the most exciting things in BW Energy these days. We are just, or we are in the process of digesting the new 3D seismic. And, I must say it's amazing, the quality of 3D seismic these days. And, comparing that to early day 2D seismic, I'm amazed that they found oil in the old days. But, what we're seeing today is allowing us to have a much clearer picture of the potential of the Kudu license. And, we have already made the decision to order long lead items to prepare for a exploration program. This is basically to put us in the position that we could use a rig of opportunity, or we could find a rig slot in the not too distant future. We are continuing to work on the planned Kudu gas-to-power. Again, underlining, this is the project that is based on the already discovered and proven gas resource in the Kudu reservoir. So, all in, very, very exciting developments in this very active basin. Our neighbor, Galp, is planning to drill two wells. They have just started, and we expect to have results from the Galp two -well campaign, as well in the course of this quarter and next quarter. So a very exciting place to be, the Orange Basin in Namibia. So that was an update on all the assets. Then I leave the word to Knut, who will take you through the financials and also wrap up this presentation. Knut, over to you. Thank you, Carl. Good morning or good afternoon to everybody. I'll take you through the financials of the third quarter of 2023, where the main happenings in our company was the takeover of Golfinho, which happened late August. And of course, that is influencing a lot of our financial numbers. However, nothing on the revenue side. There is nothing in there for Golfinho. We did our first lifting now early November, so that will then come in the Q4 figures. So for Q3, we had operating revenues of $97.1 million. That was the $75 million from the lifting. And just as a reminder, we also recorded the state profit oil as revenues. The 17 million you see as tax expense is flowing through as the government is taking their taxes that they are paid in kind. Operating expenses, $38.2 million, somewhat lower than in the second quarter. Golfinho, there is an inventory adjustment, and we also have a rather large inventory adjustment for Dussafu due to the fact that we only did one lifting in the quarter, and the partners and government had two liftings. So, that gave us an EBITDA of $49.7 million. As you can also see, we had some losses from oil derivatives of $9.1 million in the quarter. And also, just to remind you, on the year-to-date figures, we have substantial costs related to the Golfinho transaction that stands at $22 million year-to-date, and some of those costs also came into the third quarter. So, depreciation also increased somewhat because of a little bit more than a month on Golfinho. And then the operating profit was $26.1 million. Interest expense continued to increase. We have fully drawn Dussafu RBL of $300 million and also now the Golfinho prepayment facility of $80 million. So interest expense will stay at a higher level also going forward. Net financials then in total $8.6 million, and which gave us then a profit before tax of $17.5 million in the quarter, and taxes of $17 million. There's an increase there due to the higher production from Dussafu, mainly in the third quarter. Giving us finally then a net profit for the period of $0.5 million. And here, there are more adjustments in the balance sheet due to the Golfinho transactions. Firstly, it's the right of use assets is declining. We have changed the assumption for lease term and discount rate for the BW Adolo with all the recent success in finding more oil. We also expect to stay longer on the field. E&P tangible assets, that is increasing with Golfinho, the Golfinho acquisition, and also then the continuous Dussafu investments, mainly related to the drilling campaign. Then we have a number here in other non-current assets. That is the asset retirement obligation for Golfinho, and namely Petrobras are taking over some responsibility for the wells in the area. So that's the number that you can see there, of $37 million. As mentioned, inventories goes up because of our underlift position, both in Golfinho and Dussafu. Trade receivables has gone up because of the FPSO prepayment to Saipem. As earlier mentioned in the call, we expect to take over the FPSO now in the fourth quarter and but have already paid or prepaid some of that amount to Saipem. And then it will be adjusted then in the next quarter. On the equity side, equity ratio now stands at 39%, down from 45%, mainly because of the growth in balance sheet due to Golfinho. Again, asset retirement obligations, also Golfinho, we take over the wells that are currently producing and also potential new wells, and Petrobras takes over responsibility for abandoned wells and some of the wells that are currently not producing. On the trade and other payables, also increasing due to Golfinho. You can see here the prepayment facility under interest-bearing debt. And finally, then we have a net interest-bearing debt of $181 million. To the cash flow, so we started off with cash of $233.5 million at the start of the third quarter. We had operating cash flows of $10.4 million, and we had pretty substantial investments in Dussafu and Golfinho, mainly, 50/50 split, plus on some hours on Maromba and Kudu. All in total, $102 million. And then we have the net financing activities. That is, the prepayment facility and also then adjusted for the normal quarterly lease on Adolo, giving us a net $56 million, and finally then a position of... a cash position of $197.7 million at the end of the quarter. For the whole year of 2023, we expect to see around $370 million-$380 million. A couple of hundred million dollars will be the investments this year in Dussafu. Then we have six station in Golfinho and another six station in Maromba. And just to remind you, the Maromba is now including the first payment of the total of $30 million that we undertook now in October. That takes us over to the summary slide. As Carl mentioned, we are... Our main focus is, of course, to optimize and assess the situation on the ESPs and stabilize the Dussafu output, as well as also keeping the Golfinho output at a good level. Then on the exploration side, it's to drill the Bordeaux appraisal well, and then complete the 3D seismic evaluation of the Kudu asset, and prepare for the exploration well, as Carl just mentioned. On the development side, it is to complete the Hibiscus/Ruche drilling campaign, bring Hibiscus South into production, hopefully in the first quarter of next year. We have already started to prepare the Golfinho infill well campaign. That will take a while until those two wells get into production. Then, the Maromba team is optimizing and finalizing the development plan, and we are working hard on the financing initiatives. Also in Namibia, we are progressing the Kudu gas-to-power project. On the corporate side, the focus is to ensure a good operational cash flow, supported by our reserve-based lending facility and the prepayment facility to fund further investments. On the right-hand side here, you can see the big jump we had in production from Q2 to Q3. We had hoped to see more towards the end of Q4. But as mentioned, the ESP issues, they are continue to drive down the expectation on the Hibiscus/Ruche production. We're very happy though with the Golfinho output. Q4, this is what we expect. So with that, I leave it back to the operator for questions, and then we will also take questions from the web. So over to you, operator. Thank you. If you wish to ask a question, please press five star on your telephone keypad. To withdraw your question, you may do so by pressing five star again. We will have a brief pause while questions are being registered. The first question will be from the line of Tom Erik Kristiansen from Pareto Securities. Please go ahead, your line will now be unmuted. Thanks for taking my question. The cost on Golfinho was $80 million, based on the $48 per barrel guiding the first month of production. Is this monthly cost expected going forward, or do you expect it to come down quite a lot once you own the FPSO? Can you kind of break that down for us? And then secondly, on the ESP issues, is it only related to two wells, or could it be all of the new wells drilled? And can you talk a bit about timing and kind of the range of how fast this can be fixed on a per well basis? And then thirdly and lastly, looking at 2025, should we expect production then to be higher than 2024, given that these issues are resolved? How much or how many additional wells will you need to kind of get to capacity that year? Thank you. Thank you, Tom Erik. To your first question on the Golfinho OpEx, I mean, we just had one month of operations in September. So, that is not a representative number for the Golfinho OpEx, and we expect that to be reduced going forward, in particular also when we take over the FPSO, then we will not pay the lease rate to Saipem anymore. So just by doing that, this OpEx will come somewhat down. And then to the ESPs, there are also several questions from the web on the ESPs. So maybe you could go into some details, Lin, and say something about the current status and what our plans are going forward. Sure, sure. As Carl mentioned, we still have some challenges with the ESPs, and we are working with the vendor. These ESPs are a relatively new product line by Baker, which Baker is a major supplier of ESPs, and very, you know, quite experienced on that. But we're also working with other operators, and one of them is a major who's installing the similar product line or the same product line, and so we have dialogue with them. And then, we brought in some external advisors as well. We're doing a whole holistic review of the system, starting with the top sides, electrical systems. And so the next step is to start doing more diagnostics of the ESP downhole. Now, that involves we'll need to pull, retrieve, shut down the well, and pull the equipment out and do an inspection on it and to further our understanding. And that we've got a program underway to do that. First step is we'll do a couple of wireline interventions on a couple of the wells to pull them out and see if we've further understanding, and then get to the root cause of it, so we can sort out the permanent solution. But you know, it's not unheard of with new product lines with ESPs, there'd be some issues to sort through it. But I think we're confident in we'll get it all sorted out. I think the question from Tom Erik also was about the number of wells. Is it only the two first or all four wells? Well, we think it's ultimately it could be all the ESP systems that we've installed. We've seen it in various degrees of issues, electrical issues, in each well, but ultimately, it could be all the wells. Yeah, drilled to date, Lin. I think we should add that. So- Sure ... as we don't know the exact cause yet, of course, we will quickly try to resolve the situation so that the permanent solution can be implemented as quickly as possible. But now it affects all the wells that have been drilled and completed. There is also a follow-up question here on the timing of when do we expect to have resolved this issue. I guess the situation is somewhat fluid, and it's difficult to put an exact timing on a full recovery of all these ESPs. And it has... That's leading also to the next question from Tom Erik on production outlook for 2024, and maybe you can take that call, and- Well, yeah, or maybe, Lin, this... I mean, until we have found the root cause and identified a permanent solution, it's a bit difficult to speculate, but I think we have put forward a reasonable expectation, given that we do expect to solve the problems. We absolutely expect that this is a technical issue that will be resolved. As I said in my presentation, the good news is that the reservoir is performing very well. I mean, all the wells are performing above our expectations when the ESPs are working. So that's the good news. We know that we have a good reservoir, but we do not have the root cause. I don't know if you want to add anything to that, Lin? No. Yeah, just to echo that, reaffirm that. You know, we were with all the ESPs working with just four wells, we were close to 40,000 barrels a day, and coming out of Dussafu, which is wonderful, tremendous. The reservoir is working very well. Well productivity is in line or actually a little bit above expectations. So our expectations are when we add the additional wells and, you know, we've got the ESPs sorted out, and we're adding another well, Hibiscus South well, that you know, we could potentially be above our forecast. But I think we're being perhaps a bit conservative with our guidance based on the learnings that we've seen to date with these ESPs. So, being a bit prudent on, factoring in some downtime as we sort out the, these ESPs issues. So, but big picture, I think we're very pleased with the, certainly the reservoir performance of, from what we're seeing from Dussafu. So we Thank you. Just to follow-up- Yeah. Just to- Go ahead. Just to follow-up, if possible. Is there any insurance that's kicking in here or potential claims against Baker for these issues? When it's quite costly, both in terms of loss of production and potentially if you have to change these or things like that. I don't think we are forecasting a loss of production. We will have deferred production, but not a loss. As to how to settle these issues, and how, you know, the one thing is, of course, the rig time and delay to the overall drilling program, that this well may affect to a smaller or larger degree, depending on what the final solution will be. The other thing is the kit. The kit itself is a fairly, let's say, I wouldn't call it insignificant, but it's, of course, a smaller portion of the overall cost of this. So yes, there will be some costs associated with this resolving these issues, but we do not. Well, at this stage, before we know the root cause and the final solution, it's difficult to speculate about that cost, but I don't think the equipment cost as such will be the major issue. It will be time to resolve it, but it will not be lost production, it will be deferred production. Okay, Tom Erik- Okay, thank you. Thank you, Tom Erik. Thank you, Tom Erik. The next question will be from the line of Nick Renane. Please go ahead, your line will now be unmuted. Hi, thanks for taking my questions. I had a few, maybe a couple, reasonably quick. I think for the October listing, you've already done the investor presentation states a $79 price. The results release states a $90 price. I'm not sure if the $79 is just repeating the actual from Q3, but maybe you could clarify that. I can do that right now, Nick. It is $90, that's the correct number. The $79 was the July list. Yeah. It's just- Yeah. Typo in the investor press. Okay. Yeah. And on the Golfinho OpEx, the $48—I mean, I understand some aspects of the OpEx, you know, it's hard to know how they turn out when you work on them, but how much of the $48 is just the lease payment on the FPSO? Yeah, sorry, the lease payment on the FPSO. I don't have that number in front of me, Nick. I think we can take that offline, and I can go take you through a little bit more. As I said, it's only one month of OpEx and, you know, with the situation now taking over from Petrobras and then later on from Saipem, there might be, of course, also some additional cost until we have taken over and see how the OpEx per barrel will develop going forward. But as stated, you know, with the lease rate disappearing, it will certainly go down. Yeah. Okay. And one, just on the production profile that you show, and I don't know exactly how much thought was kind of put into the latest version of the production profile, but when I look at it, the 2024 number has come down, but looks like it's about maybe 32, 33, so it's actually above the stated guidance. The 2025 number hasn't moved at all. It's about 30, and the 2026 number, as far as I can tell, hasn't moved from what it was before. So you're kind of explaining a story that the reserves are actually more than you thought overall and reservoir performance is better, but in the production profile you show, like, there's no sign of that. 2024 goes down, nothing else goes up. Lin, we had a lot of meetings in Houston, so, about this with partners and government as well over the last- Sure ... few weeks. So maybe you can add some more flavor to, to our production numbers. Yeah, I think the 2024, as we've described, has gone down to reflect a little bit more of the issues with the ESP, and I think that's very appropriate. I think going out further, longer term, we would expect those issues to go away, and so you sense that perhaps those out more in 2025, 2026 are very similar. But, you know, these reserves then go on for another 15 years or so, so we don't forecast that we'd lose any reserves, if not, with the fields get bigger, might it, we, we'd see the reserves go up, perhaps a small tick. Now, exactly the short-term forecast, there might be a, you know, we might see an uptick of those reserves going forward, but right now, that's, that's how we've chosen to characterize the profile. Okay, just... Sorry. No, Nick, please go ahead. You estimated net impact, kind of management estimate of 10 million barrels original oil in place, kind of Hibiscus and Ruche together. Can I just clarify that that excludes Hibiscus South? So Hibiscus South is additional to that, and- Hibiscus South is an additional. It is an- Okay ... an additional. That's correct. Correct. Yep. And then the 10 million barrels oil in place, like, what is the recovery factor you're using for Hibiscus or were originally using for Hibiscus? Yeah. calibrate that to- They're in the ballpark, 40-ish%, up to 50, 40%-50% from what we see in the Gamba formation. Okay. And maybe just one more on Ruche. So you're basically saying slightly less reserves or oil in place than you had originally expected. In the original Phase II plans, Hibiscus/Ruche Phase II plans, there were a number of wells, ultimately in Phase II, going into Ruche. I think one more in the Gamba, two, one in the Dentale, two in Ruche Northeast. What's the read across to that? Yeah, I mean, is there any read across to Ruche Northeast or to a Ruche Dentale well from the fact that the first well indicates less reserves and you're now not planning to drill a second one? It's good, good question. What we'll need to do is, after we finish the first campaign, the drilling, the results of the 6- wells, plus we've got the Hibiscus South discovery, we'll need to do a review of what the Ruche Phase II... Ruche Hibiscus Phase II drilling program is up to 6 additional wells, and where is the best place to place those? And if you recall, from what Carl mentioned, we've also these longer extended reach wells are also a bit challenging, and we're having to review our casing and specifications on how we run and complete those wells. So all that's gonna go into the mix, and as we review our... You know, what's the best optimal and effective way to implement a Phase II, and we'll take a review of that. But I don't think as of right now, there's any wholesale changes to that plan, but there will certainly be some optimizations to it. Okay, thanks for taking my question. That's, that's it for now here. Thank you, Nick. Thank you. Thank you, Nick. As a reminder, if you wish to ask a question, please press five star on your telephone keypad. We'll have a brief pause while questions are being registered. As we have no further questions on the telephone line, I will hand it back to the speakers to handle any written questions. Thank you, operator. Just to continue a little bit, on, on Dussafu, there are questions about the, the current drilling program, which, well, we're, we're drilling now, and, and what's the remainder of, of the planned drilling program? Maybe you could take that, Lin. You want me to take that? Okay. Yeah, so the drilling program, remainder drilling program is, we're gonna be conducting some of these ESP diagnostic tests on a couple of wells initially, and then after that, the intention is to drill the Hibiscus seven-well, and that's a relatively medium range well that'll target into the Hibiscus formation or Hibiscus field. And then after that, the intention is either to complete the Ruche well or complete the Hibiscus South well. Or those are the last two wells of the plan campaign development wells, and that'll take us to seven development wells, as Carl outlined previously. And then the next... Then we'll move the rig off the platform, and then we'll go drill the Bordeaux exploration prospect. Maybe as a follow-up there, Lin, Can I just add that- Yes, sure ... of course, one thing we should mention in that respect is also that pending the root cause analysis of the ESP problems and what we will do to resolve it, we may also, of course, use rig time to do what we find we need to do. And that may be, may be inserted into that overall program that Lin mentioned, or we may do it towards the end, depends on what is the solution and when we can implement it. Isn't that correct, Lin, to say that? Absolutely. So there may be a workover in that program as well. Yep. Yep. As a follow-up, Lin, maybe we can say something more about what we expect to find in Bordeaux, and why we're drilling that as part of this campaign. Well, the Bordeaux Prospect, we're very excited about, that was formerly called Prospect B, for those who have been following this for some time. And, Bordeaux Prospect is an accumulation in between where the Hibiscus field is and the original Tortue discovery. It's got a combined Gamba formation target, as well as an underlying Dentale target, and, it's, you know, the size of the prospect, it's... There's a variety, a range of it, but, you know, in an ideal world, hopefully we achieve something that's in terms of the Gamba, similar to what we've discovered at Hibiscus. Good. And I'm trying to find the final Dussafu related questions here from the web. Can you say something about the FPSO capacity? In the past, we have talked about nameplate capacity of 40,000 barrels for the BW Adolo, but that might be some extra capacity and squeeze out something more. Right. So the nameplate capacity is 40,000 barrels a day, and we have, with the weeks when all the wells or ESPs were running, we were right at that 40,000, and in actuality, in a, you know, in a per hour per basis, we've exceeded that occasionally. So I think we're, we and FPSO operator, BWO, are becoming more comfortable that we can, we'll be able to operate at that full nameplate capacity. There's also work and studies underway to see how we can increase above 40,000 barrels a day. So I think we're hopeful that we'll be able to navigate that and find a way to ultimately increase it when our well stock and our production capacity allows us to do that. Good. Operator, I see that there might be another question on the call. Can you see if that is correct? Yes. So we have a follow-up from Tom Erik. Please go ahead, Tom Erik. Your line will now be unmuted. Thanks, Knut, for taking an additional question from me. I just wanted to ask you a question about Slide 10 in the production overview that you have there. It looks, if you look at the phase one of the Hibiscus/Ruche, it declines quite rapidly from current peak. This looks like underlying decline factor to 26-27, or more than 20% per year. Is that just to be very conservative, or is that kind of what we should model in there? That's our latest production outlook. I don't know if you have any additional comments, Lin? Yeah, I don't. We'll have to take that perhaps offline, but we certainly do not see a 26% decline due to reservoir performance. If that's shown, that's got to be due to some sort of mechanical overlay that we've applied to it, such as some sort of downtime, et cetera. We'll have to take that offline. Okay. Okay, thank you. Thanks, Tom Erik. Let's see. There is another Dussafu question from the web. Why does the Ruche well need a different casing? Is it related to the ESP issue seen in the Hibiscus wells, or is it something different? No, this is a separate issue, so it's not ESP related. It's related to the fact that these Ruche wells are very far away from where the platform is. So these are the longest extended reach wells ever drilled, certainly ever drilled in offshore southern Gabon, not ever drilled worldwide, but certainly offshore southern Gabon. And the hydraulics, the tectonics of... And we have a very large salt section to drill through. Our casing design, which has gotten us through, you know, offshore southern Gabon, is being tested, and we'll need to, you know, based on the results of what we found with Ruche, the recommendation is to alter the configuration of the casing. So we're implementing that. We hit pause on that Ruche well. The additional equipment's already been ordered, it's on its way down, so once it arrives, we'll restart that campaign. Good. And then I think that's the final question to the Dussafu. Despite the technical issues, how are the wells producing now? Are they producing despite the issues? Yeah. Well, yes, they are, but it's a little bit... You know, some of the wells still flow naturally as well, 'cause it's early life and the you know water cut's low. But, we're you know we wanna solve the long-term issue of these ESPs, and kind of a little bit of a stark stop with these ESPs. So we're looking to solve this issue long-term, and we will. I think this is the final question to Gabon, at least. The question is, is there any progress in the two exploration blocks in Gabon? I guess that's the G and H that we have mentioned previously. We, we allowed the government, I think, some time to reorganize itself, and we expect to restart discussions around that as soon as they have their new people in place and get back on track. Good. If we then leave Gabon and Dussafu, there are some more questions on the web. Let me see. There is one question here, "What hedges do you have in Q4, and what price, and what's your strategy in 2024 regarding hedges?" So we have about 2.5 million barrels of oil hedged. That's mostly we've used zero cost collars, where we have puts in the range of 55-ish, 55-60, and the calls are between 90-100. We have a few swaps as well. Going forward, there is a requirement in our reserve-based lending facility, that we must hedge 40% of the year one production and 25% year two, and that's the requirements we will follow. We have not yet placed all the hedges for the new Ruche production, and we'll do that in the course of the first quarter next year. That's basically also our strategy to be in compliance with the RBL requirements. Then there is a question about... Let's see. Is there anything here on Golfinho about the liftings, how much have been lifted? I think that was covered by Carl in the presentation. And the price of the lifting is not final yet. The lifting we did now, early November in Golfinho, the price will be the dated Brent average for November, which is obviously not there yet, and then with a differential. Then there is again a question from the call operator. Can you see if you can connect? That is correct. Nick, please go ahead. Your line will now be unmuted. Thanks. I just wanted to ask if anyone maybe can give a bit more color on the, what prospects you see in Namibia? I mean, you're ordering long lead items, so that suggests you have some specific prospects in mind. If you can give a little color on them, that would be helpful. Yeah. It's early days in completing the analysis of the seismic, of course, but the early shows are that we see significant potential in the northern corner. It's an undrilled area, previously undrilled, and it's looking very promising in actually several layers. So there's some gas possibilities, so additional gas, and there's also interesting oil prospects further up in the stack. So both gas and oil possibilities. So, the... One of the, let's say, just to give a bit of flavor, one of the ideas is that we can actually drill one well and have multiple bites at the apple, which is, of course, extremely promising and interesting. But this is early days, we will continue the seismic analysis of the data. We also expect, of course, to learn more when Galp has completed their campaign. That may be, let's say, that may feed into our analysis. So yeah, I think that's about where we are today. For the Galp campaign, what specifically is the read across? Is that to these northern prospects, and is it close to the Galp wells, or one in particular? Well, they are going to drill into some of the same layers where we are actually up dip from them. Okay. Okay, thanks for that. Thanks, Nick. So then to continue on the questions, from the web, we say that we will order some long lead equipment to prepare for a potential exploration well in Namibia. If we can say something more about what type of equipment it is and size of CapEx? Size of CapEx is $10-ish so far, and it's basically to have the long lead kit that you need for the drilling campaign. Well, wellheads, mainly. Yeah. Yeah. Subsea well heads, exactly. Yeah. Some engineering, upfront engineering. Upfront engineering of the casing program for exploration well, and the well heads is the main, the main, let's say, content of the early investment. The point is to trigger this as early as possible, because then we can look at the potential of using a rig of opportunity, or, of course, we could also, if the area gets very active, we can then get a space in the queue for rigs that are in the area. But it gives us a lot more flexibility to, let's say, be a bit more opportunistic on the timing of drilling this exploration well. Good. We're coming to the end of the call. I'll just take a couple of questions before we close. One question is related to CapEx outlook for 2024, and a split on the assets. We have around $400 million currently planned. However, some of that is firm, some is contingent. Here we have Golfinho CapEx and Maromba CapEx included. We obviously on Maromba, we haven't taken FID anymore, but we're spending some time on the development concepts and optimizing it, as was mentioned in the presentation. We have the $20 million we will pay for Polvo in the second quarter... And then, as I said, some of that is contingent. Also on Kudu, there are some contingent payments. We will mostly spend USD, but also then the CapEx for the long lead equipment. So $400 million-ish is, with some firm, some contingent. Dussafu is pretty firm. There we have about $120 million planned for next year. Golfinho could be another $100 million. We're also working on an extension of the financing or, let's say, we have the prepayment facility, but we're also evaluating to add on additional financing for Golfinho. And Maromba and Kudu is the remainder here. So that's quickly to CapEx. Then there are some working capital questions. I just wanted to guide you to our website or the press release, where there are some earnings tables with income statements, balance sheets, and cash flow statements. I think most of the answers are given out of those earnings tables. If not, then you can reach out to us on our IR email. And then there is a final question here from the web that is from Christophe Pettenati-Auzière. He says, "There's a big step change in production in Q3, but it's not reflected in bottom line. Shall we get full impacts next quarter?" The answer to that is yes, there is very little on the bottom line. We had a lot of costs, one-off costs related to the preparations to take over Golfinho. So year to date, we have $22 million expensed for all the Golfinho preparations, as more like one-offs and extraordinary costs. For the fourth quarter, we have more liftings, both in Gabon and in Brazil. So we definitely hope to see a more positive development there going forward. So by that, Carl, I think we can close. Okay. As usual, I would like to thank everybody for listening in and asking us interesting questions. I hope that our answers have elucidated your understanding of our progress. Of course, as I said, just to repeat, we are extremely pleased with the reservoir. We don't see any problems there, and that's the thing you cannot fix. If the reservoir doesn't work, you have a more fundamental problem, so that's good. Of course, not having these production issues related to the ESPs is not good, but we are very confident we will resolve that with the supplier, Baker. I'm very confident that we will find the root cause and solutions. The difficulty is, of course, saying how and when will this all be resolved at this point, but we will keep you updated. So thank you again, and look forward to hear from you next time. Thank you. Bye-bye.