Good day, and thank you for standing by. Welcome to the Tethys Oil second quarter earnings report, 2023 conference call. At this time, all participants are in listen-only mode. After the speaker presentation, there will be the question and answer session. To ask a question during the session, you need to press star one one on your telephone keypad. You will then hear an automatic message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to a speaker today, Magnus Nordin. Please go ahead. Thank you very much, good morning, everyone. We are looking out at the coastal area of Block 56, onshore Oman, as just south of there, where we have had a lot of activity during this quarter. Let's go straight for the presentation. Could I have the first slide, please? Very good. We have had significant activity, particularly in our operator blocks. Of course, Blocks three and four is still where most of the production comes from. We are not the operator, but we'll discuss that, of course, also in some detail. On Block 56, we've seen the results now of the long-awaited extended well test on the Al Jumd discovery, which has yielded some very encouraging and positive results. On Block 58, we have continued prospect maturation now with the South Lahan area, and we are in the process of tendering for a rig and also looking for a potential partner in 58, as we will try and unlock exploration success there later this year and early next year. Production came in as somewhat disappointing, 8,994 barrels of oil per day. That's down almost 500 barrels per day from the first quarter. We are seeing the decline Block three and four continue, however, at a much lower rate and stabilizing. As you have seen, we are guiding for around 9,000 for the full year, 2023. Still giving us good cash flow, and cash flow from operations stood at $25.7 million. A lot of that has been reinvested, particularly, in particular in Block three and four. We remain one of the largest, largest acreage sellers in Oman, as you can see on the next slide, with interests in Block three and four, 30% since 2007, in production since 2011, and commercial production license since 2012. We're now 100% in Block 49, where we have drilled one well that encountered hydrocarbons, and we are eager to try and do a hydraulic frack of the tight sandstone and see if we can get some hydrocarbons to surface. Block 56 is where the most activity is there. We've drilled several wells. We've acquired lots of seismic, and of course, the proof is in the pudding. You have to get oil to surface in commercial, in commercial viable quantities to create value. That's what we are hoped we are on the cusp of viewing in 56. 58, seismic acquisition completed in 2021 and successful interpretation since then. That said, let's move on and look at Block 56. Let me take one step back and just remind us a little bit what we have here. What you're seeing is, the blue line is the border between Block six, which is the central block in Oman, owned and operated by PDO. Right where approximately the Al Jumd sign is, and along that side of the border, Indonesian company, Medco, on behalf of PDO, operates the Karim Small Fields project. Karim is a cluster of discrete structures that have been in production for more than 10 years, and what we are seeing on our Block 56 is simply the continuation of that same kind of structures into 56. That's why we are seeing the blobs here is the from seismic identified structures that are on our side. Some are leads, some are prospects. Al Jumd is the one where we have done most of the work and where we, where we have drilled three horizontal wells and now carried out an extended well test for more than three months. We have varied the production to try and optimize it, to try and get an idea of what would be an optimal rate, what can one well, horizontal well produce over time, and how can that be related to the estimates of the oil in place that we have made? A combination of these data, and we produced some 35,000 barrels during the quarter as part of this extended well test. This is also oil that we lifted in July, and there will be some proceeds that will be divided between the government and ourselves and our joint venture partners. Apart from the drilling of Al Jumd and testing it, we started doing serious interpretation of the 2,000 square kilometer state-of-the-art 3D seismic we acquired in 2022. We are really interested in looking at the central part of the block, where we have an interesting fault system with several leads identified on 2D. We've also took a closer look at what's around Al Jumd, with now additional 3D. We can confirm that the trend continues along the Block six border. I think we now count up to 12 leads, and we have identified a new prospect that is a direct analog to Al Jumd. However, it's somewhat larger. We are quite encouraged by what we have seen, and if I should draw a parallel to Block three and four, this is starting to look a little bit like what the Farha South trend looked like some 12, 12, 10, 12 years ago. What we then saw was a number of discrete structures, some of which have tested oil along a fairway, along a trend. Farha turned out to be a set of adjacent fault blocks, that each compartment contained oil and is now still the mainstay of Block three and four production. Al Jumd, we see a number of discrete structures, all with similar characteristics. If we turn to the next slide, we are going to continue to work to work on this on this trend and to try and bring this block into commercial production. Some of the major milestones are there, the milestone of the ex- extended well test. We have the Sarha-3 discovery that we've driven appraisal well on. We want to retest some zones that weren't tested, although we got oil from the deeper zone. We want to drill the new prospect that we have done, that we have discovered. All this we would like to do over the next couple of months before the end of the year. We have instigated discussions with the ministry to extend the exploration part of the license. We are in the final exploration phase, the second exploration phase. The next step is to bring the block into commercial production and declare commerciality of the block. We believe we are very well on the way of doing that after this extended well test. We would like to do a bit more appraisal, we would like to retest Sarha, we would like to drill a new prospect while start working on a field development plan. Are we going to plan to di- first produce Al Jumd, but also are we also planning to integrate other Al Jumd trend prospects into a production system? Today, we are trucking the oil from Al Jumd to the Simsim facility, and we will look at other that as an opportunity, but also if it would be s- sufficiently economic to, say, build a pipeline and a processing facility somewhere in the middle of the Al Jumd trend. All this is to be found out with additional work, and we expect to see a very active fall here in Block 56, in the Al Jumd area. Not least, given the continued disappointing results Block three and four, bringing a second field, giving us a second production stream from Oman, remains a very high priority for us and one that hopefully we will bring to fruition in the course of 2024. That said, on Al Jumd, of course, we are still continuing to mature leads in the central area, and there we see a possibly completely separate petroleum system that will be appraised once we have the Al Jumd area up and running with our current plans. On Block 56, let's move into Block 58. The main excitement on Block 58 last quarter was the announcement of prospective resources over the Fahd area in the Block. This quarter, we focused on the South Lahan prospect area, where we have a set of carbonate stringers, a analog to the PDO fields that you see as green blobs here on the side. Again, we are flanking PDO. The orange yellowish line here to the left is our Block 58, to the right is Block six, where PDO themselves operate. They have wheel cluster of carbonate stringers. We are quite encouraged that we have been able to firm up a number of prospects in the area. They are clearly visible on seismic. They are deep, around 4,500-5,000 meters. They are encased in salt and do present a bit of a drilling challenge. That's why they are certainly not our first choice to be drilled, although, we expect to see possibly a higher geological chance of success in Lahan than we have in Farhad. Farhad remains, the first, drilling location. We expect to drill Farhad, later this year or early next year. We are tendering for a rig. We had one rig in mind, when that was delayed, we also noticed that the rig market had opened up a bit, and we are now tendering for further with, with a number of participants, and hoping that we can get maybe a slightly more adequate rig and also at a slightly lower price. At the same time, we are testing the waters for a farmout. We have 100% of Block 58, so we have ample room to farm out to a suitable partner, if such a partner can be found, and of course, at good commercial terms for ourselves. Leaving 58 and moving slightly to the northwest, we are back to Block 49. Focus here has been to get the operations going so that we can do the reentering of the Thameen well, and see if we can fracture the sandstone and get some oil to surface. It has taken longer than we expected. There are a number of moving parts in conducting an operation like this, and initially, we set out to try and tender for those separate parts independently. Turned out to be time-consuming and possibly slower than trying to go for a, an integrated contract for every, for a contractor capable of doing everything from reentering the well to actually conducting the fracking operation, and also doing the testing of the well. We are currently evaluating the results of that tender, and we'll get back to you as soon as we have a clearer plan for what and when we are going to be able to action the Block 49 reentry. With that, we move over to Block three and four, where our producing well, where we are producing a block, where we have a 30% interest and have had that since 2010, when we farmed down 20 percentage points to our still partner, Mitsui. The diagram is pretty self-explanatory. We have seen ever since we came back from the COVID lockdowns, we have seen production fall. We are stabilizing now around 9,000, we are hoping. There are a number of reasons for this. We have seen surface issues that have been mitigated. We have seen wells that have not quite performed as they were expected to. We are seeing work in them being worked over, recompleted. All in all, there is still a lot of activity in trying to stabilize and of course, eventually also increase production in three and four. However, we must conclude that some of these fields have been in production since the early teens, and we would expect a natural decline. You would also expect increased water handling. We are seeing all of this, but we would also expect production to maybe stabilize at least these levels for the coming quarters. Of course, with an active exploration program that we can look at further on the next slide, we have seen actually three exploration wells come in positively. Maybe the most interesting one is the Jari-1 in the southern part of Block four, where there appears to be a rather large resource base in Precambrian carbonates. We are now trying to establish and understand how best to produce the, among others, Abu Mahara sandstone. Oil has been brought to surface and there is definitely an active petroleum system. It's a tight reservoir, and we knew that, and we now, and the operator is now working on the best way to try to evaluate and see how best we can bring this to production. Needless to say, a new discovery to the... and particularly a large area of Block three and Block four that can be developed for new production, will be instrumental in getting Block three and Block four production to stabilize and to eventually increase. To sum up, and we can move to the next slide, we've had a very active quarter and a very encouraging quarter, in particular in Block 56. We are working hard to get a second production stream online in Oman, and we are hopeful we will be able to supply-... you, our shareholders and market, with news of how Block 56, like, and how Block 56 materializes over the, the, over the year, the rest of the year, then, of course, that we can bring it towards commercial production in the course of 2024. While waiting for that production stream to materialize, we are having our, all our financials, income, related to Block three and four. We had an okay oil price of $81 per barrel, giving us revenue of $34.7 million, quite close to where we were in first quarter. EBITDA at $16.9 million, investment in oil and gas properties, $21.4 million, giving a free cash of $4 million. A lot of investment in three and four, both to meet, to finally upgrade the surface, but also now to rework some wells to increase production. We had our share redemption, we have had repurchase, share repurchase, and the combination of these revenue streams, the investments, and the distribution, left us with a still quite healthy cash balance of $33.9 million at the end of June. On that, I would actually like to turn to the next slide and hand the floor to our Chief Financial Officer, Petter, to do a more detailed rundown of the quarter's financials. Petter, please. Thank you, Magnus. I think we'll stick on the financial highlights slide for just a moment and try to summarize the bigger picture of what we see here. The quarter, the second quarter compared to the first quarter, is relatively flattish in development, particularly on revenues, down a little bit, as production came down somewhat and oil prices were stable. However, we do see a slightly lower, slightly lower earnings on the EBITDA level. The 2023 is so far in a flatter trend than the increasing trend we in earnings and sorry, in revenues and earnings that we had through 2021 and 2022. There are a number of reasons for this, and we will come back to that in more detail. I would say otherwise, we are very satisfied with the free cash flow and the net cash position of almost $34 million at the end of the quarter. Oil sales in terms of barrels, as fairly flat compared to the first quarter, as was the oil price. Just a slight single-digit downtick in those volumes. As a result, revenues were relatively unchanged. However, as we know, production was down somewhat, and we have now moved to a minor overlift position compared to being underlifted for quite some time. We can see that the current production trends and the oil price will be reflected in Q3 that we, and that will impact, of course, the oil sales and revenues from that. We will touch on that a bit further down as well. If we go to net entitlement, that is the oil that we are entitled to sell from the total production. We are currently at a net entitlement of 52% of total production. That is the maximum allowed under the PSA. Also, consequently, we are not recovering all the costs that we are generating at the moment, so we do have a cost pool. For the end of the quarter, we had $10 million of costs unrecovered that we are entitled to, to receive through oil in the future. You, you can see in the graph to the left that, that the value of a net entitlement is somewhat lower this year than last year. That is primarily a consequence of two things: the lower oil price and the lower production. But much as we see in the profit and loss statement, it, we, it's a kind of flattish development in the year so far. The fact that we are operating at full net entitlement does have an impact also on the cash flow, which is notable if you compare it year-over-year. Moving to operating expenditure, that we've seen that the trending upwards for quite some time now, both in absolute terms and per barrel. In absolute terms, what we see is the effects of increased fuel consumption and fuel costs, and also the, which is primarily driven by the increased water handling, relating to the maturity of the field. We also see increased cost for workovers, which is both an effect as well of the high activity on the field, but also that some of those costs have recently been a bit more expensive than planned due to using a slightly heavier equipment than normally would be necessary. That is, is an effect we hope to, to, to see recede going forward. The OpEx per barrel in the quarter was $17.4. That is, of course, a combination of the slightly higher absolute costs and, and the lower production rates than, than, than in previous years. And going forward for that to come down, we really need to see a turnaround in particular production. But in the meantime, we are looking at how, how we can improve the, the cost in absolute terms. This quarter, there is the first, we actually see the inclusion of some OpEx related to, to something other than Block three and four. That is the, the Block 56 extended well test added $700,000 in, in OpEx in the quarter. It's worth reminding you that there was no revenue recognized or production recognized in as commercial production in the quarter. That is not included in the $17.4 per barrel. That is the $700,000 is the current run rate of OpEx from the extended well test. We expect to see some proceeds from that, as Magnus mentioned, in the coming quarter. Otherwise, the Block three and four CapEx was down sequentially as expected, with Q1 being burdened by the annual bonus and benefits payments that by the operator in Oman. Moving on to cash flow. Operating cash flow before working capital was around $18 million. We had a positive working capital effect of, of $7.5, leaving us with, with, about $25 million in operating cash flow. That is primarily the effect of, of, the move to overlift, being one of the big shifts in, in the positive, working capital effect. CapEx, we, we are, we are continued high spending on Block three and four, that is particularly on drilling. We're seeing a lot of drilling going on this year. We have 4 rigs operational, and, we have, we drilled 3 exploration wells this year so far, 1 more to come. The 3 have been successful in, in encountering hydrocarbons, so there has been some incremental testing costs related to those. At the same time, we are acquiring some more 3D seismic, getting, particularly in the southern areas of the block, where we see a lot of potential. A lot of work going on to ensure the production integrity of the field and improving performance, and the results of which we hope to see in the coming quarters. When it comes to our operated Blocks 49, 56, and 58, as we've said, there has been some quite low level of operational activity in the field, and that's reflected in the relatively low CapEx. We do expect some of that to pick up in the second half of 2023, particularly relating to Block 56, as we've seen Block 58 drilling being pushed into next year. That means for the quarter, we have a free cash flow of $4 million. That is a nice uptick, having had a couple of quarters of almost no free cash flow, we're happy to see that. It is worth remembering, we are in an investment phase, focus is really to deploy the capital and cash that we have and create value in the field, particularly through the drill bits and using rather than having the cash sitting on our balance sheet. We're happy with that performance in the quarter, it shows the strength of the model, business model we apply. Now, netback, we usually talk about being an indicator of, of sort of the performance, of, of over time in, in terms of the sort of the profit oil generated from Block three and four, and free cash flow, without the sort of fluctuations that we see. We see this quarter, that netback, net of CapEx, is in fact negative. That is due to us being unable to recover the full costs for generating three and four. Conversely, we have the $10 million cost pool, so this is the effect of when we are at full cost recovery and recoverable cost exceeding that cost allowance. That is cash that is being deferred, and we will receive in the future. Moving on to guidance for 2023, we have made some revisions to this, particularly the production. We have seen that in the monthly releases, trending, trending, the production guidance is a reflection of what we believe the full year average to be in light of performance year to date, and that's 9,000 barrels per day ±200 barrels on the yearly average. OpEx, as calculated on the basis of Block three and four, is expected to be around $17 per barrel ±0.5 barrel. That is, of course, not including extended well test. We now expect the investments in oil and gas assets to be somewhat lower than previously, in the range of $81 million-$86 million, rather than the previously $85 million-$95 million. That is particularly due to the deferred drilling on Block 58, being the main swinging factor in that. Before I, before I hand over to, back to Magnus, I just wanted to remind you about the effects of oil pricing in Oman. As you know, the prices are set with a two-month lag, so we already, at this point, know what the unweighted average price will be in the third quarter, and that is $76.8, so that is somewhat lower than we had in the second quarter. Third quarter revenues will be reflecting that lower, lower price that we have seen a few months back. However, currently, Oman Export Blend is trading at $87 per barrel. That is a $3 per barrel premium to Brent. Those effects we expect to see coming into the fourth quarter. The very strong oil price trend currently will be reflected in our achieved price during the beginning of the fourth quarter. Just, just as a reminder. With that, I just wanna hand back to Magnus. Thank you very much, Petter. If we can have the next slide, just a quick note on overall oil price. It has been quite firm, as you all know, over the last six months. Every time we've seen $70, it's bounced up to $75, and now we are in solid territory above $80. Certainly get the impression that OPEC, with Saudi Arabia at the helm, is very focused on maintaining prices at a level they consider reasonable. This slide just illustrates that both the way the quotas are set, and we should say that we are in no way impacted by any, any OPEC+ quotas. We are allowed to produce as much as we can and encouraged to increase production as much as we can. We are seeing that the overall quotas are set at quite low levels, and actual production is even coming in below those low levels. On top of that, Saudi Arabia has now extended a unilateral 1 million barrel per day additional limitation up to another month. The both what we see in action and what it seems that OPEC is able to produce, as long as Saudi Arabia maintains this discipline, we are quite convinced that we are not going to see any serious drop in oil prices. Rather, maybe if there is some kind of supply disruption, we may see risk on the upside. That said, let me just sum up what we can expect. Hopeful to see Block three and four stabilize around the 9,000, as per our guidance. Also, very keen to get updates on the evaluation of the exploration wells that have been drilled so far this year. In our own blocks, of course, lots of focus on Block 56. We have approached the, the ministry for an extension of the second phase. We would expect to be able to do the work we need to bring it towards commerciality over the next 2 months. That's by far the main focus of the activities for the quarter. The rest is progressing according to plan with the possible maturation in 58. We'll see if there is an interest for a farmout in the due to farm out 58. Could be of interest to, to form a stronger partnership there. Of course, we are also eager to see the first block we've drilled, eight well drilled, but probably not going to happen until late this year or early next year. On that note, we are happy to take questions if there are any. Please. Thank you. Dear participants, as a reminder, if you wish to ask a question, please press star one one on your telephone keypad and wait for your name to be announced. To withdraw your question, please press star again. Please stand by. We will compile the Q&A roster. This will take a few moments. Now we're going to take our first question from the line of Knut Martin Carlson from Commandeer Capital AS. Your line is open. Please ask your question. Good morning, Magnus and Petter, and congratulations on the success on Block 56. I was just wondering on the prospective resources on South Lahan and the central area of Block 56, do, do you have a number on that, on the P50 mean? Okay. We don't as yet. Lahan, we are done with, with our work and are currently working with the peer review, which would result in an independent report on the activity of Lahan, which then, of course, we will add to Block 58. When it comes to Block 56 central area, we are delaying that a bit with the focus on the Al Jumd trend. Would not expect any prospective resources on Block 56 central area until towards the end of this year, or probably most likely during Q1 next year. Okay. Thanks. That was all the question. Thanks. Okay, thanks. Thank you. Now we'll go and take our next question. Just give us a moment. The next question comes from line of Stephane Foucaud from Auctus Advisors. Your line is open. Please ask your question. Good morning, guys. Thanks for taking my question. I've got a few on 56 and 58. If that's okay, we'll get a follow on three and four. On 56, various activities taking place on appraisal, looking at the commercial development, when would you expect to be able to be in a position to sanction the block for commerciality, assuming everything work and start deploying CapEx for production? Is it 2024? Is it beyond that? What's your best view? Okay. First, thanks, thanks for the question, Stefan. If we first look at the licensing situation, we are in the final stage of technical evaluation. Typically, the next phase forward would be to declare commerciality. Now, declaration of commerciality needs a field development plan. That first shows how you are going to, what kind of resources you have, how you expect to drain it, over what time, what kind of method, what kind of investment, and what kind of value does your field development plan expect to have? Of course, the provisional work of that has already started. We have heard idea about Al Jumd. We need to do a bit more work on the Al Jumd 4 horizontal well. We then come up, have come up with an optimization of how best to drain Al Jumd. Do we need more wells? Do we need, are the ones we have sufficient? Et cetera, et cetera. It's work that will be done most likely over the course of, over the next 3 or 4, 5 months. We would like to be able to add Farha to the development plan, and we would also very much like to drill at least one more prospect, most likely the one that we just identified, and put all this into one comprehensive development plan for the Al Jumd part, Block 56. Typically, this will not take more than, say, 6 months, if 6 months, if we are reasonably successful and, and then keep the pace up. The next step would then be to, to commercialize the block. From the planning perspective, we would certainly have to, to get this done during the course of 2024. Great. Thank you. My second question is on 58. You talk about looking to farming, to farm out the block, and the vision for that being the cost of the South Lahan deeper well. Would the intention be to just farm out the South Lahan area or the entire block, including Fahd? That's my second question. I, I would say, I mean, we, we, I'd say we are totally pragmatic. I mean, we have 100%, and we have the money to drill the Farhan well. We most likely have the money to drill the South Lahan well also. The, there, there's always risk in, in these ventures. In case of success, there would also be development, and we, we, we are just curious and eager to see what kind of partner could be attracted to Block 58 at this stage. If a, a good partnership could be formed, that, that would be, it depend entirely on, on, what's achievable and, and what, what the terms would be. But most likely, I mean, the farm-down would be of the block, say, and would, I mean, typically what we have done in the past is found out exponentially, twice as we did with 49, as we did with three and four. I'd say that's the most likely scenario. But, I mean, it's entirely up to what's, what, what... If there is interest at all, and in that case, what that interest can, can result in, what kind of a deal that can result. We're totally committed. It's by, yeah, it's by no means a foregone conclusion that, that there will be a deal, as Magnus said, we are, we are able to finance the drilling ourselves. It, it's really, it is exploratory to see if, if, if we can get a deal that we're happy with. Okay. Thank you. My last question is on Block three and four, and around the Elaf-1 and Rabab-1 discovery. I think you talked about that those two wells brought oil to surface. Are they now in production? I mean, some more work to do, and if they are not in production yet, what is the uncertainty? What prevents that to happen? Thank you. Okay. They are not hooked up to the production system as yet. They both flow, flowed hydrocarbons to the surface, and we are looking at fairly light light hydrocarbon. It's really a matter of optimization, how best to get the best value given the perceived product mix, how to best bring it to into the current the current system. It, it, it's a business evaluation optimization exercise, we understand. We would expect that to take at least another couple of months before we have more certainty as to when and how they can be brought, can be brought on stream. Is it because the oil is a bit different from what you have on the rest of the field, because there is a bit of water, because a bit of gas? Why not hooking them up? So what is the specific way you can't hook them up fairly quickly? Well, it's really a question for the operator, of course, but we understand that it has got to do somewhat with the product mix and to optimize production from that particular product mix. Okay. Okay. Thank you. That's it for my question. Thanks for taking the time. Thank you. Now we're going to take our next question. The next question comes from line of Teodor Sveen-Nilsen from SB1 Markets. Your line is open. Please ask your question. Good morning, Magnus and Petter. Thanks for taking my, my questions. I have three questions. First, on 2024 investment level, it seems like at least you, Magnus, you are pretty constr- constructive on your oil price view. Just one, should we expect investments next year to be higher than, than this year, assuming that the oil price will at least remain at, at this level? That's the first question. Second question is on your balance sheet. Historically, you have a, a very strong balance sheet with, with net cash position. I just noticed now you have the lowest net cash position since 2018. Should we interpret that as you, you're actually now managing the company towards a zero net, net cash, or should we interpret anything around that? Final question is just generally on, on cost inflation. I think we discussed that previously, but, but what, what's the latest development in the local market in Oman? What kind of cost inflation do you see, and, and which part of the value chain do you see the most cost inflation on? Thanks. Hmm. Thanks, Teodor. Let's see. Let's start from the beginning. I mean, we haven't done a budget or done any guidance for 2024, I think typically, we would want to see a little bit less of CapEx in block three and four, especially if we are going to see production on these levels and not higher. If we go into a full-fledged development on Block 56, that would certainly demand an element of cash flow. Although, of course, we would try to, to, to use cash flow from operations as much as we can, we would expect an element of cash sink into a Block 56 development. Obviously, as a field development plan and I think rational commerciality would give ample guidance as to how much cash we would expect to see, and also how much production we expect to see when, we could then calculate a capital need based on that. Otherwise, I think, we are in a business that, that is often we do see the occasional risk that needs to be mitigated. Oil prices are always volatile. We have a lot of opportunity, but also CapEx into wells, et cetera. I think we would expect to see the cash position maybe fluctuate a bit based on our needs, and we'll be able to be much clearer on what we expect for next year once we do our budget and guidance for 2024. Turning to cost inflation, in our operated blocks, we're not really seeing that much of an impact. When it comes to the rig, that's actually opened up a bit. There has been tightness which has attracted additional players, and they have also to bring new rigs into country. I think, apart from the, apart from the moving costs, for example, diesel on three and four, we are not really seeing any, any clear trends. Possibly a little bit on the manpower in that, there is a lot of activity, and that has, of course, increasing demand on a group of people. Otherwise, there is not really... I, I can add, sorry, I can add to that. I mean, I, I think, I think what, what, what we're seeing is we're not seeing any particular inflation in Oman as such, that, that is un- that is, sticks out from, from what we're seeing internationally. However, on certain long lead import items where there is tightness globally from time to time, that, that kind of pops up. I'd, I mean, we've seen that in the case with some, some steel tubing and casing at times, and we've seen it on, on certain components, but it's not something we're seeing across the board. So it's, it's, it's more, I think, supply chain disruption related. Sorry to break in, but just. No, no. It's fine. Inflation pressures in, in Oman are such that, that deviate from historical patterns or, or, or, otherwise. Just to add also, I mean, on the cash position, yes, it is the lowest cash position that, that we've had for a long time, and, and, rightfully so. The cash is to be put to work. I think at times we've had a higher cash, cash, net cash than we, we had planned or intended to, due to, to both sometimes fortuitous reasons, you know, higher oil price than planned or, or delays in, in, in operations. Now we're putting it to, to work, and we expect to do so going forward. As Magnus said, as we look into next year and the moving parts on both three and four... a cash generation, but also in Block 56 needs, given the development, we'll, we'll make appropriate plans to, to, to, to address that. Historically, we've, we've had a very, very strong cash generation to support all our operations. Okay, thank you. Just one follow-up on, on the, on the balance sheet question, Magnus, you were clipping a little bit when you discussed that. Should we expect the company to move towards a zero net cash position going forward as you develop Block 56, in particular, maybe 58? Well, I can respond there instead. I mean, we have no intention to. There is no explicit target to move to any like zero, zero cash position. I mean, we will finance developments as appropriate. I mean, if we feel that it's prudent to take on debt to do so, and that's suitable to the returns on the project, we'll certainly consider it. I think it's fair to say that if we see success on 58 and 56, there will be a, you know, consistent development CapEx and long-term CapEx requirements to be, that are consistent over time that we needed to plan for. We're not targeting any particular kind of net cash position. I mean, it's, it's really dependent on, on what, what cash generation we can see from, from Block 3 and Block 4, and what's appropriate for those projects. I think it's worth reminding also, I mean, we have 100% on Block 58, we have 65% on Block 56. That means we, we, we go into these projects with high interest stakes, and I would expect at the end of a development cycle, we will probably sit with lower interest stakes. That's certainly part of the, the equation in terms of financing and, and, meeting those requirements. Understood. That, that's very, very helpful. Thank you. That's all from me. Thank you. Dear participants, as a reminder, if you wish to ask a question, please press star one one on your telephone keypad. We're going to take the next question from Martin Melbye from ABG Sundal Collier. Your line is open. Please ask your question. Yes. Thank you. Good morning, morning, everybody. Thanks for having my questions. The first question is on Block three and four. Given the revised production guidance, it's still reasonable to assume a slight increase in production levels in the second half of the year compared to Q2, or should I expect a more flat, development? The second question is on Block 56. On the extended well test at Al Jumd, should I expect to see some revenue contribution from this in Q3? The third question is on Block 58 and the potential farm out. How much are you looking to farm down on the block, and what would be the ideal ownership stake, in your opinion, after a farm out? Thank you. Right. Thank you, Martin. I'll start with the revenue recognition. Yes, we on Block 56. Yes, we did have a lifting, a first lifting of oil from Block 56 in July, so we are expecting to see some revenue recognized in the third quarter from that. However, I would caution that not to have too high expectations and as the volumes are modest and those that we have reported are including both government and partner shares. The exact determination of that is to be determined. We're not at liberty to give any guidance on exact entitlement share at this point. Sorry, Petter, if I, if I may interject there also. In general, I should say, I mean, an extended well test is an extended well test, we are allowed to sell the oil, not, not just give it away, but serious revenue would not be able to be calculated until we have a close to commerciality. Of course, once we are in commercial production, we will. It will be, it will be transparent and predictable what kind of entitlement we will have. While it's still an early extended well test situation, there will be some revenue, it, it will be incremental, if I put it that way. Sorry about that. Yeah, yeah. No, that, exactly, exactly. Magnus, do you, do you want to comment on the production guidance question about the production levels in the second half? Sorry, could, could you repeat that question? Yes. Given the revised production guidance, is it reasonable to assume a slight increase in the production levels in the second half compared to Q2, or should I expect a more flat, flat-ish development? Okay. Okay, I mean, we, we've guided for around 9,000, and that, that's the best part, the guidance we can give based on, on, the work program that we have from the operator and the operator's numbers of expectation from the wells, and also from our, from our own experience with wells. As, as, as, we've commented on earlier, there were exploration focus during the first quarter, so there were fewer development wells drilled during the first half of the year than there will be during the second half. Typically, that should speak in favor of, more, development wells should bring more production wells in the second half. I mean, we are confident that, that, the guidance will stand, and, we will see how, how far, how, how far it can be taken, so to speak. Martin, what was your final question? Please remind us. Yeah. The third question was on the Block 58 and the potential farmout. I was wondering how much you're looking to, to farm-down on the block, and what would be, like, the ideal ownership stake, in your, in your view? I, I think, I think I mean, we remain quite open-minded in terms of interest stakes. It really depends on what is on offer, in terms of, yeah, what an interested party offers and what they bring to the table, I would say. We would like to keep a significant, if not a high stake at this early stage. We, I mean, we are yet to drill, so we wanna go into that drilling with a material exposure to that drilling. I mean, we are very excited about it. So it, it's, from that respect, we are, we, we don't wanna be letting go of too much, of course, but in the end, it really depends on, on, on what's being offered and, and on the table and, and what the, the, the, the whole package, 'cause as we're saying, we're looking to build a strong partnership for, for not just for the one-off well, but for, for a, for a full campaign and hopefully also development. So I think we'll be quite open-minded in that. Then again, you know, we don't wanna dilute ourselves too early here either. So it, it's gonna be a balancing act between that. Yeah, that remains to be seen. We're. It's early days yet. Okay. That was quite clear. That was it for me. Thank you. Thank you. There are no further questions, and I would like now to hand the conference over to Magnus Nordin for any closing remarks. Thank you very much. Well, thank you very much for listening. I think it's been some excellent questions, and we are keen to talk to you again, if not before, so in early November, where hopefully we are much further along in Block 56, see the contours of the new production stream, and we are seeing stable and hopefully slightly increasing production from Block 3 and Block 4. Stay with us, and speak again soon. Thank you very much. That does conclude our conference for today. Thank Thank you for participating. You may now all disconnect. Have a nice day.