Hello, and welcome to the Tethys Oil Q2 earnings report 2021. Throughout the call, all participants will be in a listen-only mode, and afterwards, there will be a question and answer session. Today, I'm pleased to present Magnus Nordin, Managing Director, and Petter Hjertstedt, CFO. Please begin your meeting. Thank you very much and w elcome to the Q2 for 2021, a quarter which I think is surprisingly strong based on where we were a year ago, and in particular, with oil prices having recovered remarkably quickly. Let's go into the details of the numbers i f I start with the first slide here, we have the Q2 2021 highlights. Production of 11,000 bbl of oil per day has been affected by a few operational issues that have been resolved. We are still working with the possibility of being cut back, but we are certainly hopeful that we are going to maintain at least these levels or actually higher as we guide for the second half of this year. Production o f course, at these levels of the oil prices is quite important, and we are happy to see that we are at these levels and not lower, but we certainly would like to be higher. Oil price y es, 28% up quarter-on-quarter, and we are looking at an even stronger price as we can see for the Q3 of the year, which is indeed a remarkable recovery. Production, we expect to do a bit better than we did second half than the first half. Turning to our exploration blocks, Thameen-1 well drilled in the Q1, I should say came in way above expectations on the logs with a very substantial column of oil, d isappointed in not flowing, and we are now at the end of the technical evaluation where we can see that we have some very good porosity but low permeability in the reservoir. That's something we, of course, will have to deal with. Block 56 is moving ahead, drilling preparations ongoing as with preparations for seismic. And, in Block 58, we are beefing up the seismic operations. Turning to the next slide, just a reminder, during the quarter, we distributed SEK 15 million plus to our shareholders, another SEK 4 per share. That's the seventh consecutive year in the ups and downs of the oil market that we have given a solid dividend and cash distribution to our shareholders. Turning to the highlights, revenue and other income at SEK 26 million, giving us an EBITDA of SEK 14 million, which is better than the Q1, and in particular, an operating result that is very much better than the Q1, as is the Free Cash Flow. The achieved selling price, better, although not as dramatically better as it could have been, as we will see in the Q3. OpEx has come down, which we are grateful for. Netback is up and entitlement is down and w e are going to comment a little bit more on entitlement l et me just say that in this oil price environment, we do not expect to build a cost pool r ather, we expect an even further acceleration in the way we get back all our investments and our OpEx. The project is in a mode where it costs us very little cash to keep it going because we get it back literally within the same quarter that we spend it. As you will see, that of course, has a direct effect on the operating result being down, although the nominal cash flow is down given the entitlement. But we do see a strong profitability resilience and robustness from the Blocks 3 and 4, and if we can see an increase in production, that will translate immediately into better numbers on the top line, of course, and bottom line. A quick comment on the oil price. We have seen a remarkable recovery. We're seeing it from an increased demand perspective. As the pandemic recedes worldwide, if a little bit with ups and downs, we are still seeing a trend of demand recovery. We are seeing here, for example, that OPEC expects to be able to cut down on its quotas and go back to a normal situation over the course of 2022. The second slide here shows clearly that we have the inventory increase that we saw building in 2022 has come down, and we are back to normal levels. With the fiscal discipline we see from the U.S. oil patch and the cohesion within OPEC+, I'd say we feel confident that we are going to continue to see the oil market in balance, which should be able to lead OPEC to increase production while maintaining a reasonable price. With that, just a reminder that two years ago, before the pandemic set in, we were at 13,000 bbl of oil per day, w e have, of course, seen a reduction caused by the quotas that we had to be aware of. Although we have been allowed to produce more than our former quotas, and we sincerely hope that will continue. We've also seen that we have been affected by slightly lower investment. We are hopeful that the Q2 will see higher production and that we will also see increased investment in bringing production back closer to where it was before the pandemic set in. So much for the forward-looking. Now let's look at the quarter in question in some more detail. And for that, we'll return to the next slide, achieved price per barrel, and we'll return to our other speaker, Petter p lease. Thank you, Magnus and g ood morning, everyone. The achieved price per barrel in the quarter was $59.7, and as Magnus has already said, that's a significant improvement over the Q1 and the situation a year ago when you can see we were at $34 bbl. It's certainly a great place to be compared to where we were a year ago and the continued improvement that we've seen in previous quarters. Now, it's worth remembering, however, that in the quarter, there was some impact on the achieved price given the slight slippages in liftings and b ecause as you know, the achieved price is based on the actual oil sales in the quarter. That forms the basis of the revenue line. In the Q1, we had two liftings reflected in the achieved oil price as the March lifting slipped into the Q2. We saw a similar situation in the Q2 where the June lifting slipped into the early Q3. Had we had the normal state of April through June liftings, the achieved price would have been $63 as opposed to $59.7. That all evens out over the year, but that's worth noting in how the achieved oil price came out. On the subject of prices, the official selling price for the whole Q3 is, at this point, already known a s you can see to the right in the graph, the July through September OSPs gives a nice high number at around $68 bbl if unweighted. However you should remember that includes the June number. I believe it would probably be above $70, probably. It all depends on the final realized achieved price will, of course, depend on the weighting between the different liftings t hat's worth noting. A clear improvement to be expected in the Q3. Okay, moving forward, n et entitlement, w e have, in the quarter, 42% net entitlement out of the possible 52% w e had 50% in the Q1. Yesterday, we're at 46%. I think it's worth remembering that in the Q1, we recovered the remainder of what was in the cost pool. Going into the Q2, the cost oil that would be recovered was what was generated in the quarter. We did not use up the whole cost allowance, which meant we came to 42%. The nice benefit of that, of course, is seeing the profit oil portion increasing. It also means that we've recovered all costs that have been spent in the quarter. Moving into the next slide. I think this is worth highlighting that net entitlement as a gross number, of course, is made up of two components. It is the cost oil and the profit oil, and as the cost oil portion declines, the profit oil portion increases. While we had a very slight increase in the value of net entitlement, the profit oil portion increased significantly from the Q1, o f course, that is the name of the game, maximizing the profit oil, as the cost oil is simply recycling what we're spending. It's worth remembering the dynamics in this is that as the oil price goes up, the value of total production increases, of course. That means that if costs stay the same, they make up a smaller portion of the total value of production, and hence, fewer barrels are needed to recover that cost. So mathematically, we do get a lower entitlement in barrels, but while still recovering the same value. It does mean that the profit oil portion increases. Moving on to over a nd underlift, a s has been the case for many years now, we nominate our liftings two to three months ahead of time, which means that the lifting will not always match the exact production in the period, in the month, giving rise to an under a nd overlift effect. This is something that we need to neutralize over time. There periodically will be corrections done in the liftings to ensure that we are on balance and not selling more oil than we are entitled to or the opposite, not selling all that we should be. At the end of the Q2, we have an underlift position, as we did in the Q1 as well, but it has been reduced somewhat to now only 90,000 bbl. However, that's partly the effect of the June lifting slipping into July. Adding that back, we would've been overlifted by a few barrels so t hat's worth remembering. That will, of course, be reflected in liftings going forward throughout the year. It has been a bit unfortunate this year with the timing of those liftings, which has given rise to a bit more fluctuation than that would be normal. Moving on, revenue and other income, that is both the revenue portion and the value adjustment effect related to over and under lift. We had $26.1 million. That's up 3% versus the Q1, but it's a nice improving trend as we've seen since the Q3 last year. Moving on to expenses. I think we're pleased to see that we have a nice, fairly stable level of operating expenditure and also a relatively stable admin expense, overhead expense. There was some fluctuations in that in Q4 and Q1, but those effects are behind us. The $1.7 million is not disrupted by any one-time effects. The $9.9 million in OpEx reflects the current situation in the field with the slightly lower production. Remember that the Q1 does seasonally usually have a bit higher cost reflecting some of the one-off annual costs so a nnual cost in the joint operations relating to benefits and bonuses t his is a normal seasonal effect to see that the Q2 is slightly lower than Q1. OpEx and Netback per barrel, w e see the Netback per barrel improving significantly, reflecting the higher achieved oil price and the lower OpEx. We have a $15.2 bbl. You can also see that OpEx per barrel at $9.9. We're very pleased with that development and hope to be able to see this continue. Moving to EBITDA. This reflects, of course, the improvement in revenue and other income and lower OpEx, which results in the improved EBITDA to $14.5 million in the Q2. Now to investments. In the quarter, we had investments, oil and gas assets of $8.4 million. Majority of that in Blocks 3 and 4, picking up somewhat from the Q1. As we have indicated in the past, we do expect investments on Blocks 3 and 4 to increase gradually throughout the year. We also expect the investments on particularly Block 56 and Block 58 to pick up as the year moves along as activity picks up t he Q1 was impacted. We had a negative investment as related to the Block 49 farm out transaction, and the consideration we received there, giving rise to that one-off negative impact. That gives us actually a Free Cash Flow of $4.9 million t hat is the cash flow after investments. Year to date, we have over $7 million in Free Cash Flow, which is better than we had for all of last year so t hat's a nice improvement. I think is a key metric to keep an eye on as the company develops. Looking at the year-to-date situation, when it comes to cash flow, you can see that we have cash flow from operations of just above $26 million. We have a negative working capital change that's in part related to what we see in the EOG farm out transaction so w e expect that to balance out somewhat as the final consideration, which was paid after the close of the quarter came in, reducing that negative effect. We have investments of $9 million in a year, giving us a Free Cash Flow of $7 million so far. You can also see we have, of course, distributed $15.5 million in the past quarter, and with share buybacks were well above $16 million in distributions to shareholders. Which brings us to the balance sheet, which remains very solid. Oil and gas properties of just above $200 million, cash of just above $46 million, and no debt, leaving us with a very solid situation to weather both storms and to look at future opportunities irrespective of the environment we're acting in. With that, I'd like to hand over the word to Magnus again. Thank you very much. We quickly turn slide to the operation slide. This is the Sultanate of Oman. We see clearly the Omani land mass at the southern, southeastern edge of the Arabian Peninsula with adjacent waters. You note that now some of the waters have all also been put into blocks, and some of this has been licensed with the occasional offshore oil drilled also. Tethys, of course, is strictly onshore. We want to focus on the blue areas here, which is Tethys' acquisition in Oman, surrounding in particular the central part of Oman, the green area, which is run by PDO, the joint venture between the state of Oman and Shell and various other oil companies. Of course, at the dawn of time, the PDO concession encompassed all of the country, and which is to say that all Tethys concessions are previous relinquishments from PDO. Here's really the key to what we are trying to do for the long run, which we started with Block 3 and Block 4, a s we learned more about how the geology of Oman works and also how the geology of Oman has been interpreted in the past, we realized that there was a lot of overlooked opportunity on the flanks. Thus, we've built this position on the flanks of the central area of Oman, entering into separate basins and also new plays within the central Oman sort of basin. That has played out quite well for us so far from three and four, and that's, of course, what we're trying to do again in Block 56, Block 58, to a lesser degree in Block 49, which is the Rub'al Khali Basin, which is a completely different play, but where we of course had the success of Thameen-1 showing that there is indeed a working petroleum system also in Block 49. This is our long-term, our long run. This is where we hope to see future production come from while we continue to explore in Blocks 3 and Block 4 to maintain and increase production there also. We are not alone in Oman a part from PDO, we do have colleagues like Shell and BP, Eni, our partner EOG, Occidental, Total and PTTEP, all active to a larger or smaller extent in Oman. BP in point with the Khazzan gas field, which came on stream 25 years ago, which has changed the gas outlook for Oman dramatically. We are not the only ones seeing opportunity, continued opportunity, and possibly increased opportunity in Oman. Turning to the next slide, just to remind you quickly that we have a 30% stake in Blocks 3 and 4, from which we get our production. We have seen production from this block since 2012, peaking at least the latest peak was in 2019. CCED is the operator, Mitsui has 20%. Block 49, we are the operator, EOG 50%, w e announced the farm in late 2020. It completed in the Q1, we actually closed the final payment of the farm only a couple of days ago. Block 56, we operate as of half a year ago, with previous operator Medco staying in with 5%, and local Omani service company DIAC holding 25%, together with another Omani company, Taj. Block 51, Block 58 s orry, awarded to us in a bid round last year, w e have 100%, and we are the operator. Similar situation that we had with Block 49, which was awarded to us in a bid round in 2017. Blocks 3 and 4 producer saw some massive deferment of investment in 2020 due to the cutbacks and the quotas and the COVID situation. We have come back, w e are back to three drilling rigs active and 1 workover rig. We expect development well drilling to pick up in the second half. We expect exploration well drilling to pick up in the second half, and we also expect production to pick up in the second half, while of course, the continual work of infrastructure focus within Blocks 3 and 4 will continue. On the exploration side, we drilled the Safi well in the Q1. It's currently undergoing production testing, and the Suhail well we expect to see spudding within the next day or so, and definitely within the month. Safi is on the left-hand side of our Shahad field to the west of the main Shahad producing area, and Suhail is to the east. An exploration well between the Shahad field and the Al Khumr field in what we call near-field exploration. We also hope to see some far field wells drilled before the end of the year. 49, Thameen-1, now 50/50 between EOG and Tethys. Well, it went very well indeed. As I mentioned before, we know we have oil there. We know we have a petroleum system working. We know we have good source. We also now know that we have a workable reservoir. However, one with good porosity and low permeability. We are looking at the best way forward to further appraise the reservoir in question, and we will put the focus for the Q3 when the well for 49 comes up to see how best we are going to make use of the data we have in 49, and how to take the project forward. The current license extension expires in December, so it will indeed be focused during the Q3 how we're going to take this project further. Block 56, according to plan, we are gearing up to appraise the Al Jumd trend. We can turn immediately to the next slide, by the way, the one showing the multiple leads and 2D seismic. Block 56 really consists of two parts. We have the upper ring, the Al Jumd trend, where we have flow noise on surface, which is on trend with the producing Karim field to the immediate left of the block boundary. We will continue the appraisal with a view to get this on long-term production, before the end of the year and see how far we can take it while we prepare for an extensive seismic study in the southern rim, where we have a number of interesting leads, similar in nature, some of them to Blocks 3 and 4, but others also really being charged from a tertiary basin that extends from the offshore into our block. From what we know today, I would say, our probably most interesting exploration area. We are eagerly awaiting starting the seismic campaign there. Block 58, we are here in the extension of the Oman Salt Basin. It's part of the main Omani Fairway and turning to identified leads. We have now become more familiar with the seismic collected by previous operators. We have a number of leads and even a large number of potential leads. Most importantly, we are focusing on the ones highlighted here, and we are planning a new seismic acquisition to be done later this year over the (1), which as you can see is right adjacent to producing lookalikes in Block 6, operated by PDO. Given that we are well underway to get the seismic started in Block 58. That said, whereas the Q2 has seen some very strong numbers from the outside world, we are hopeful we'll see better production Blocks 3 and 4, we are hopeful we will continue to see good oil prices, and we already know that the Q3 price is going to be very good indeed. We will focus on how to take Thameen-1 further and do a proper continued appraisal, bearing in mind that we are dealing with a tight reservoir. The exploration program Block 56 and Block 58 continue. In Block 58, a little bit faster than expected. In Block 56, according to plan, and that is of course where we hope to see some very interesting developments over the next year to 18 months. On that note, I would like to open the floor for questions. Thank you. If you do wish to ask a question, please press zero one on your telephone keypad. If you wish to withdraw your question, you may do so by pressing zero two to cancel. Our first question comes from the line of Stephan Foukara from Octus. Please go ahead. Good morning, guys. A few questions for me. First, an accounting sort of question. You talk about the underlift position being quite hard, it would reverse over the coming quarter but i 've also noticed that the current payable are still quite low and probably that has an impact on working capital. Would you expect that to potentially reverse to higher figure next quarters that would have a positive impact on cash flow? That's my first question. On Thameen-1, what are your thoughts here? What would happen in Q3, Q4? Is there a situation where you could decide not to progress with Thameen-1 at all? Is it more how to progress rather than whether you will progress or not? Lastly, I noticed that there is this Suhail exploration well, that I think I was not carrying previously h ow? material could that be? Are we talking just over a few million barrel or could it be a bit more? Thank you. Okay. Thank you, Stephan. Petter, you want to deal with the overhead question first? Yes an underlift situation, which of course, y eah, w e have an underlift situation, that's mainly a consequence of that June liftings slipping into July. When it comes to payables, it's difficult to give any real guidance on that. That's usually impacted partly on the overlift and underlift situation as such but w e would expect, if you adjust for June, we're actually in more of an overlift situation, practically speaking. I think that situation, we're looking to balance out throughout Q3, but we'll see where we end the quarter, and that really depends on the production, which we don't know yet. It's difficult to give any real guidance on that. Okay. Thank you. In terms of receivables, the main section of receivables is, of course, related to the final consideration from EOG t hat we have received, so that will improve from that point of view on working capital. Thank you, Petter. If that was all right, Stephan, let me talk a little bit more about 49. Let me speculate, the obvious way forward here would, of course, be to, w e have an old column of some 30mi. Good porosity, so there's definitely something there, and then the permeability is lousy so i t's really an extraction issue. It's a matter of how to get the reservoir to flow in the best possible manner. And of course, the school book way of doing this, if you get your reservoir book out, it would say increase the volume of the well, i.e., drill horizontal, and crush the reservoir so that you increase permeability, i.e., frack. Most likely, we will have to look at various ways of horizontal sections, the best way of stimulating, i t's not a carbonate, it's a clastic, it's a sandstone. You would typically not look at acid, for example. You'll be looking at maybe some other way of fracturing the reservoir and making it stay open. There are, of course, ways also of chemically stimulating the clastics. So that's really what we're going to focus on for the Q3. What would be the best way of making this particular kind of clastic reservoir flow? As you know, we don't really have experience of this in the past. We have some creaky carbonates in 3 and 4, and we have some very thin difficult clastics, t hey have better permeability than we have seen here. We don't really have experience from this so w e obviously have to look at people that have experience and find the best people to help us with taking the project forward. Of course, we have to make up our minds before the end of November, really, and either enter into the second period for the license or ask for an exemption or, in the worst case, of course, drop out a s I say, there's definitely something there, and we have a clear idea of how we want to continue the work in understanding the reservoir. I would expect a lot of activity during the Q3. How does EOG feel about it, if you have communicated anything? I have to give you the obvious answer to that. You have to speak to EOG. Okay. Let me say, they are, of course, our 50% partner. Fair enough. Of course, we expect them to be supportive with the expertise they may or may not have in this particular regard. Their view will have to come from them. Okay. Any further questions, Stephan? Yeah. The last one was on the new exploration target. Oh, okay. I think it was the Khormakser field. Typically Hale is a near-field exploration well. Typically it's a lower risk, lower reward situation given that it is, and as I briefly showed on the map, it's right between the Shahd and Alfeen fields. We are right in an area where we have production. We would expect it to have a reasonably high chance of success and could reasonably quickly contribute to production. Size-wise, near-field wells are typically smaller in size than the far field wells where we look at bigger targets, but also with higher risk. Thank you. The next question comes from the line of Teodor Sveen-Nilsen from SpareBank 1 Markets. Please go ahead. Thank you, and good morning, Magnus, and good morning, Petter, and thank you for the update i have three questions from me, if I may. Petter, you briefly commented on the realized oil price this quarter a s far as I understand, the discount to the official selling price is mainly due to the timing of the lifting c an you please confirm that? If not, what other factors are behind that discount? Second question on the entitlement, are you in a position to provide any guidance going forward? You indicated maybe around 40 going forward, is that correct? Last, on CapEx guidance, is it still SEK 47 million you plan to spend this year? or could you provide an update on that figure? Thanks. Hi, Teodor. Yes, thanks for the questions. The achieved oil price we have is calculated on the basis of the revenues of the liftings recognized in the quarter. In this quarter, we had, of course, the March lifting, which slipped over from the Q1, April and May, and the June lifting slipping into the Q3 it's a slightly skewed price. It reflects those three months' sales, and o f course, when you look at the achieved price, well, that becomes weighted by the relative size of the different sales. If I recall correctly, I believe the March lifting was relatively big in relation to, say, the May lifting. That will have also balanced, shown through in the achieved price. We're not actually getting a discount to the OSP in any way e ach lifting is in fact priced very much in line with the OSP. The actual mix between the months does have an impact. As I indicated, had we had a normal setup of liftings with April through June, we would have been at SEK 63 for the Q2. It's more a question of timing and weighting t here's no money lost, so to speak, vis-a-vis the official selling price. When it comes to, what was your second question? Was that net entitlement? Yeah. The difficult part with net entitlement is that we don't know the oil price for the rest of the year, because as the oil price goes up and everything else stays the same, if costs don't increase, they do make up a smaller portion of the total value of the production. In that, it is very difficult to estimate what the final entitlement will be. As Magnus also mentioned earlier in the presentation, we're not expecting to be generating a cost pool this year. Most likely, we will be comfortably below the 52%. If oil prices continue to be strong, that does mean the value of our profit oil remains high as well t hat's a positive. We are looking in the future quarters to provide an update ahead of the quarterly release with some of this information to give you a bit of guidance as it is difficult to completely calculate the net entitlement on the basis of the publicly known information ahead of time. You can look forward to that in coming quarters. You had a final question. I don't exactly recall what that was. Yes, that was on CapEx y our previous guide for, I think it's $47 million for this year i s there any change to that number? Are you tempted to invest more given where the oil price sits right now? I think we haven't changed that guidance, w e haven't changed our investment guidance, w e will stick with that. I think the higher oil price certainly leaves a lot of room for more investment, given that there is more cost recovery on three and four to use. It's also a question of practicalities and also doing meaningful investments i t's not always a numbers game, it's also being able to actually deliver those investments. Yes, it does leave more room for it. If practical and there is a positive potential return from it, that would be considered. Okay, thank you. Just as a final reminder, if you do wish to ask a question, please press zero one on your telephone keypad now. We have another question from the line of Karl Petersen from ABG Sundal Collier. Please go ahead. Hi, guys. Thank you for your presentation. Just following up on the CapEx guidance and trying to look further down the road, how are you thinking about spending into 2022, and what will be the basis for your investment program when we look into 2022? Could you also provide some color on the allocation of capital between Blocks 3 and 4, where the spending is tightly linked to production and revenues versus the other more early-phase exploration areas? That's my first question. Okay. Well, let me see. Sorry w hen it comes to 2022, I think it is a difficult one i mean y ou can go back, and you can look at what has impacted our investments well in the past. Well, partly, of course, it is the macro environment. How comfortable are we with the oil prices and the profitability of the project? As we saw last year, seeing oil prices come down significantly, well, that led to a significant reduction i t also meant that picking up our investment has been a bit slow as there has been a great level of uncertainty. There certainly is room to keep investing in the project. There is lots more to do that we see as value accretive. But of course, we are still in a pandemic, so that creates some uncertainty, even though oil prices are looking very good and solid at the moment. In terms of the OPEC+ situation, what comfort we have in that. I think those are some main factors looking into 2022. It's a long planning process, and it's partly working from long-term plans and multi-year plans, then sort of fitting those into the more immediate context of oil prices and production possibilities. I think we're looking quite positively at the next year, where we're standing now. We're still some way away from 2022, it remains to be seen but c ertainly, the indications overall are on the positive side for us to feel more comfort. When it comes to allocation between the other projects, well, I think every project is viewed on its own merit. If we look at particularly Block 56 and Block 58, where we have more activities coming up, we will fulfill our commitments on those blocks and t hat is doing a proper exploration of what we have identified as the potential. We have seismic coming up on both of them in the next sort of 12 months, and some drilling. Everything beyond that really is very much a question of success based. It's difficult to predict what to do on those blocks before we've had any results of any drilling, I would say. We certainly will be properly exploring both those blocks, as we've done with 49, and we'll see where we go with 49 t hat's a question that I think Magnus has already addressed. I don't know, did that answer all your questions? or did I miss something? Yeah, if I may add another question as well, please. If we were to look at what do you view as the production capacity out of Block 3 and 4, meaning that in a scenario where all production quotas are lifted, what would be your run rate production level? Yeah, that's a difficult one, and I'm not sure there's one proper answer. Petter, I'll have a quick go. Yeah. Nothing has happened with the infrastructure of the field that in any way would have impaired the possibility of getting back to the levels that we saw in 2019. With, shall we say, a clear signal that produce as much as you possibly can for the next five years and no constraints, there would be ample room to increase investments and ramp up production. The theoretical upper bound is certainly up among the numbers we've seen in the past. Under what circumstances we'll be able to get there is now a different question, and that's where we have to look at oil prices, we have to look at OPEC + behavior, we have to look at the overall demand and a number of other factors. To give you some sort of flavor for what would be possible, certainly getting back to where we've been in the past, the circumstances that would take us there, to be determined. Okay, thanks so much. Very clear. As there are no further questions, I'll hand it back to the speakers. I think on that note, and being optimistic for the future with an interesting exploration program, we hope to see you again in about three months' time, when we are in November, and the Q3 is completed and evaluated. Many thanks. See you then. This concludes our conference call. Thank you all for attending. You may now disconnect your lines.