Welcome to a warm and spring-like Stockholm, where the cherry trees in the Kungsträdgården are in full bloom, and the ferry traffic to the archipelago is picking up for summer. Operations have also picked up nicely in the first quarter for Tethys. The long-awaited extended well test on the Al Jumd discovery in Block 56 commenced once the Fiscal Meter was successfully installed in late March. We are currently evaluating the discovery and, of course, we hope that it will soon bring a second production stream to our asset base. We've also seen some significant exploration activities on Blocks 3 and 4, our still main producing asset, with 3 successful exploration wells that have encountered oil are now being evaluated. The seismic acquisition campaign that aim to cover the entire area of Blocks three and four with 3D seismic is moving ahead, and we expect to have it completed within about a year. We will then be in a position to, together with the operator, to fully evaluate the remaining potential of those blocks. We are moving on with the exploration drilling plan for Blocks 56 and 58, our operated blocks, which will take place consecutively in the second half of the year. Production came in at 9,411 barrels per day. Little bit less than Q4 2023, but certainly sufficiently in line to give us a good cash flow contribution. Revenue down a bit, primarily because oil prices dropped a bit. Cash flow from operations down a bit, the balance sheet still strong at 40, almost $40 million, roughly on par with the first quarter. We do look at a very eventful year ahead with a lot of operating activity. First, let us remember that Block three and four and the production from Block three and four continues to underpin a solid debt-free financial position and a substantial cash flow. Three potential exploration discoveries in three and four undergoing testing and evaluation, and this is the best exploration exploratory drilling results we've had for several years. We have a very ambitious exploration program in our operated blocks. That's Block 58, where we have 100%, and Block 56, where we have 65% interest, and Block 49, where we have the Thameen potential discovery under evaluation, also with 100% interest. So far, we've mapped about 200 million barrels of prospective resources that we will be in a position to test with the drill bits later this year. That will be the wells to be drilled in 56 and 58. While we are continuing to plan for the re-entry and retesting of Thameen-1, remember that we did encounter a hydrocarbon column in about 30 meters when we drilled the well in 2021. Tight reservoir, no flows. We need to create some fractures to see what we can get out of that well. Prospect maturation on 58 and 56 continues. We would expect to add more prospective resources as we finalize the seismic interpretation over 58 and 56. Not least important, of course, the extended well test on 56, where we evaluate the commercial potential of Al Jumd. For tomorrow's AGM, the AGM will resolve on a distribution to shareholders, we expect, where 3 SEK will be distributed through redemption share procedure and an additional 2 SEK as an ordinary dividend to be paid out in November. Turning to some detail on 56, the extended well test has commenced. We've opened up, Al Jumd-2 was the first well to start. We will evaluate that. The other wells will be opened in successive order, Al Jumd-3 and Al Jumd-4. The first lifting and sale of the produced oil is expected in July. The test will be ongoing until September. We would expect to be able to give a quite a reasonable update on results in our Q2 report out in August. Let's turn to the next slide and just have a look a little bit at what we are trying to do. What we're talking about is the Al Jumd structure, which was deemed an oil discovery already in 2009 but has been further appraised by Tethys with three wells, three horizontal well completed last year. The all wells flowed good oil to surface with, we'll be looking at flow, initial flows of well over 7,800,000 barrels of oil per day. What we're trying to do now is to get a better appraisal and understanding of the structure. Oil wells will be produced. We will monitor for pressure, we will monitor for connectivity. Of course, the aim of the structure is to ascertain how much oil is there in place, how much of this can we probably recover, and is this sufficient to commence commercial production from Al Jumd, and thus add a second production stream to Tethys production. That's what we are trying to do, as I said, we would expect to be in a position to give a detailed update in time for our Q2 report out in August. Al Jumd could be a nice contributor to cash flow and production, the most interesting parts of Block 56 is what we call the central area. We saw 2,000 square kilometers of 3D seismic last year. Processing has been completed, interpretation is ongoing. Data based on 2D suggests at least 50 million barrels of unrisked resources within the central area. We are looking at some 10, 12 leads that have potential to be matured into drillable prospects, that work is now accelerating. We expect to have it completed by mid-year, we will then be ready to both pick drilling sites and to release additional prospective resource numbers. An area that holds considerable potential, we expect to start testing for the drill bits in the second half of the year. Block 58, slightly further along, with prospective resources and reliable prospects identified along the Farhad trend. Most promising is the Farhad South prospect, which most likely will be drilled not next quarter, so during the third quarter. We have both the two additional prospects adjacent to Farhad, which are well-mapped and understood. All in all, of course, we do see some great potential in Farhad. We have 100% of the block, we are in an excellent position to get a partner if that's what we choose to do. Of course, in case of a discovery, we would have to look at financing opportunities. On the South Lahan area, we have identified a number of carbonate stringers. They're all ensconced in salt, and they are well-defined now on seismic. We're in the final stages of maturing them to drillable status and expect also to have prospective resources on those over the next month or so. Turning to 49, we have the seismic interpretation here, sewing showing the tight sandstone in the Thameen well. 30 meters of hydrocarbon identified from logs, no flows. We will try and create some artificial fractures in the sandstone and see what we can bring to surface. It's an area with considerable potential, and the main purpose now is just to get some flows to show that this is actually a viable working petroleum system. We expect operations to be carried out and completed during the second half of the year. Turning to three and four, we saw the most significant exploration drilling during the first quarter for several years. Some near field, near producing fields in the South, Farhad and Farhad South area, showed discoveries on logs and have flowed liquids to surface, now being evaluated for their potential. Whereas the Jari-1 well, long awaited, I should say, in the southern part of Block four, encountered oil in the Abu Mahara formation. It's a quite a prevalent formation in this part of the block. It's now, it will be evaluated, and most likely we need to create fractures there also to see what's in the reservoir. The main interest of that area is the sheer size of the Abu Mahara potential in the area. First step, again, establish flows to surface as part of the evaluation of the Jari-1, then we can return to fully assess the area, which is, as you can see from the slide, fully covered by 3D seismic. While we work on the exploration and growth opportunities, productions on the Block three and four came in virtually in line with the fourth quarter. We are down, we have had a falling trend for the last quarters, we see a stabilization around the 94,000 barrels-95,000 barrels of oil per day over the last 6 months. Of course, we stand by our guidance, which is in the range of 9,000 barrels- 10,000 barrels of oil per day for the full year 2023. Important is here to remember that this provides us with a substantial operating cash flow to both enhance further investments in three and four, but also allow us to spend cash on our other blocks. On that note, I'd like to turn the floor to Petter for a more detailed discussion of the quarter's financials. Good morning. Thank you, Magnus. Tethys Oil's first quarter in 2023 is a fairly straightforward one from a financial perspective. We can see that the achieved oil price of $81 per barrel is down somewhat versus the fourth quarter, as we have seen in the markets from the spot prices coming down at the end of last year. Remember, those prices reflect the market price is from two months prior, with the two-month lag. This results in a revenue another other income of $35 million compared to $43 million the previous quarter, and pretty much in line with the quarter a year ago. An EBITDA of $18.7 million, also somewhat lower than the previous quarter. What we can see is an inevitable bucking of the trend as oil prices came off their peaks at the end of last year. Our investments continue to be high, particularly in Blocks three and four, and as a result, free cash flow after investments, including the exploration investments, remains unchanged versus the previous quarter of just positive $400,000. In the quarter, we also repurchased shares for a total of $2 million. At the same time, we ended the quarter with almost $40 million in the bank, compared to $41.5 million at the end of last year. No major change in the cash position. Oil sales in the quarter were up compared to the previous quarter, but with oil prices coming down versus last year, the total value was down by about 3%. Achieved oil prices was $81.7, as I said before. There was a slight overlift in the quarter, selling more oil than we were entitled to, but we entered the quarter with an underlift position, and that was then reduced by 31,000 barrels. We remain underlifted by 35,000 barrels at the end of the first quarter. These are barrels to be lifted in the future. Net entitlement, the number of barrels decreased versus the last quarter, and that's mainly due to the lower or the unchanged production, but also increased recoverable costs and those exceeding the cost oil allowance. We should recall that Q4 had an exceptionally high Cost Oil Allowance with a catch-up effect at the throughout 2022. The comparability is not exact. Net Entitlement was at 52% in Q1, and as not all recoverable cost was recovered that was incurred, we have a Cost Pool Balance of $4 million at the end of the quarter of costs that are available for us to recover from cost oil in future periods. Moving on to OpEx and OpEx per barrel. As I'm sure you're all accustomed to at this point, the first quarter is usually one of the higher quarters in, when it comes to operating expenditure. This is mainly due to the annual costs relating to bonuses, benefits at the operator in Oman being paid out in that quarter. This quarter, we also saw the effect of increased fuel consumption in the field, increased consumption of diesel, driving pumps and diesel generators, as well as slightly higher fuel costs as diesel costs have come up throughout the year, and that had an impact on our OpEx. We had a $17.2 per barrel in operating expenditures, including the field costs, operator overheads, and the workovers. Moving on to cash flow. Cash flow from operations remained a very strong, almost $19 million before the changes in net working capital and over $20 million after the net working capital contribution of $1.4. The reduction in this quarter is mainly due to the lower revenue and income and increased OpEx. Investments, as I mentioned before, remain at high levels compared to the recent years. Particularly, we see a continued trend of increasing investments on Block three and four as we are investing to improve the performance of that field. In this quarter, slightly lower spending in project and infrastructure, but increased spending on drilling, and particularly exploration drilling. Very little spend on our operated blocks as we are gearing up for activities later in the year in the second half. The free cash flow, as I said before, unchanged at $0.4 million, and we ended the quarter on $39.9 million in cash. What have we done with some of that cash? Well, we have been repurchasing shares. We repurchased shares for a total of $2 million in the first quarter, that's 370,000 shares repurchased. In total, we have repurchased over 600,000 shares since the AGM last year, we currently hold over 1.1 million of Tethys Oil shares at the end of the quarter, that is 3.3% of the shares outstanding or in issue. The board of directors has proposed to the AGM to renew this mandate at the meeting tomorrow. Looking at dividends and redemptions, we have a strong track record of distributing cash to our shareholders, as I'm sure you're all aware, and this year is no different. Board of directors has proposed a distribution of SEK 3 per share by way of redemption and a SEK 2 per share dividend to be paid out in November this year. The redemption will be done during May, the record date of 25th of May, and trading period from between 26th of May and 9th of June, with payment in the middle of June, and the ordinary dividend to be paid out in November, the middle of November. I just want to reiterate that our guidance we provided at the last quarterly report remains unchanged. We expect production to be in the range of 9,000 barrels-10,000 barrels per day for the full year. The operating expenditure expected to be in the range of $14.5 per barrel, ±$1. Total investments to be in the range of $85 million-$95 million. You can see that on the pie chart on the right, the majority of that spending will be on drilling, both in the operated Block 56 and Block 58, but also on Blocks three and four, as we have mentioned. A large number of wells being drilled this year across the blocks, in intense activity, in investing for the future. The netback trend, which we like to just point your attention to, this is the net contribution from Blocks three and four, removing all the other blocks and impacts. You can see that the trend, while coming down somewhat due to the oil prices and lower entitlement, remains very positive with a netback, net of CapEx of $2.4 million. That is the underlying cash or profit contribution from Blocks three and four, and that is $2.9 per barrel. I just want to leave you with some oil price outlook. The average OSP in the first quarter for the oil that we are selling was $81 and a half, and we already now know what the official selling price for our listings in April, May and June were. The average is $81.3. That is unweighted with to any production, but basically in line with the level we had in the first quarter. Stable oil prices moving, going into the second quarter. With that, I want to hand the floor back to Magnus Nordin. Thank you very much, Petter. on the oil price net, I thought we'd contemplate a little bit what we think about the oil price for the future. Of course, oil price is a function of demand and supply. This slide shows some speculation about demand for some of the major actors in the forecasting field for oil. We have OPEC, we have the international EIA and the IEA. Usually confuse those. The main trend here of course, is that they are all three perfectly aligned on the fact that we are going to continue to see strong demand for the continuing years. We have seen demand come back very strongly after the 2021 hiatus. The trend line is for continued increase of use of oil and increase in demand. As you can see on the right-hand side of these, the graphs here, all three forecasting agencies expect demand to continue to grow for at least the next couple of years. This is irrespective of assumptions on potential recession or at least slowdowns in parts of the world, offset by very high expectations of growth in other parts of the world. I don't think we really see anything in the near term or long-term data that contradicts these forecasts. Demand is expected to continue to be buoyant for the next years. The second side of that equation, supply, well, the last 10 years of oil supply has been very much a tug-of-war between OPEC and the United States shale industry. With the formation of OPEC+, a couple of years ago, we've seen a strong discipline on maintaining a reasonable production so as not flood the market from the OPEC+ countries. We have seen signs in the United States of increased, dramatically increased fiscal discipline among the shale producers. What we have seen over, during the first quarter and now coming into May, is that if anything, shale production is slowing its growth and entering into a more of a plateau pattern. That said, with increasing demand and OPEC back in the driver's seat for a swing producer, we do believe we are going to see a comparatively stable oil price on the downside for the next couple of years. I think the current data certainly supports that view. Oil prices have come down from the peaks during 2022, but we've also seen a lot of bounces around the $70-$72 area and back to $75-$80. I think our expectations will be that we're going to stay somewhere in this area and with the risk primarily on the upside. Markets could very well turn tight in the second half of the year with limited possibility to increase on the U.S. shale side, and with strong discipline and possibly also limitations on the OPEC side, what actually can be achieved on the production side. We would be quite confident to have oil prices at least at these levels and with the risk on the upside. With that as the backdrop, again, let me remind you, Tethys for the year looks at a production between 9,000 and 10,000 barrels of oil per day, all from Blocks three and four. That will give us a sufficient financial basis to grow our business elsewhere, if not in Blocks three and four. Main growth focus is first 56, evaluate the Al Jumd discovery and the string of adjacent prospects, see if we can turn that into a second commercial production stream, while going for the big prize, transformative prizes of exploratory drilling in the central area of 56 and in Block 58. Of course, we have the dark horse 49, where the sole aim is to establish flows to surface to show that the Rub al Khali Basin in the western part of Oman can become a proven oil region. On that note, I would like to invite questions from the rest of you. Please. Thank you, sir. As a reminder to ask a question, please press star one and one on your telephone and wait for your name to be announced. To withdraw your question, please press star one and one again. Once again, please press star one and one if you have any questions or comments. We are now going to proceed with our first question. The questions come from the line of Teodor Sveen- Nilsen from SpareBank 1 Markets. Please ask your question. Good morning, Magnus and Petter, thanks for your presentation. Many questions, I think I'll limit myself to two to three here. Just first on Block 56. Can you just confirm that you're talking about the gross resource potential of 50 million barrels for Al Jufair, and what should we expect in terms of news flow in the next quarter or so for Block 56? Second question that is on OpEx. I just looked into my notes from your previous from the fourth quarter presentation, you said that you did not expect any cost inflation. That is fair, I still see that OpEx is up quarter on quarter, is that activity driven mainly related to fuel as you said, Petter, can you just confirm that? Third question, of course, that is a big topic that's on the oil market that I definitely agree with your view, Magnus, that in second half of this year you will probably see up to 2 million barrels of storage draw every day. What's your view on China demand and what kind of risks do you see around the recovery of China? Because of course, that is important part of the puzzle for that 2 million barrels per day storage draw. Thanks. Okay, thanks. First, to take the 56 question. The 50 million barrel prospective resources is for the central area, the entire block, not only the Al Jufair area of what we have defined so far. That is a gross number, correct, yes. OpEx, Petter, you want to- Yeah. Discuss that? Before we get to that, we could discuss the news flow on Block 56. We do expect to provide an update on the extended well test, presumably during the course of the summer or as soon as that review has come sufficiently far. We would also expect at some point, sort of around the middle of the year maybe, to provide an updated resource number on that central area based on the 3D design, as that $50 million was on the 2D design. Do expect some news flow in both those counts during the course of the summer, and not least around the second quarter report. When it comes to the OpEx, well, yes, I mean, we're not seeing any extreme cost inflation is I think what we're saying. There, there's always cost inflation and we've had that in Oman for many years, and I think we capture most of that in our guidance of $14.5 per barrel. Now, of course, this quarter when it comes to fuel, yes, fuel prices surprised a bit on the upside, but I think in particular what we saw was fuel consumption. That was really one of the quarters, few quarters recently where we have had a lot of the wells, or very few wells shut in. We have all the pumps out, working consistently throughout the quarter, and hence the higher consumption. I would say that we have kind of captured most of what cost increases we have seen in our guidance already. Yes, fuel is one of those that is a bit unpredictable. Okay. Just before we move to the oil market question, can you how much of the total OpEx of $17 million it's related to the fuel cost? Well, I'm not actually at liberty to say, but it is the most significant cost item within the category production cost. You have operator overheads, you have workovers, but in the big section, it's not the majority, but it is in certainly the biggest cost item, followed by staff cost. It is a significant cost item in that, but not the majority. Okay, understood. Yeah. Thank you. Okay. turning to China. Well, the shall we say OpEx view on China is that there will be continued robust demand. Given that OPEC sells, or I should say Saudi Arabia maybe, sells a lot of their oil to the Chinese market, I would give them a rather high credibility in assessing what's going on in China. Macro data otherwise, we do not look outside of what's available in the overall macro patch. See no immediate signals that a Chinese recovery and a rather rapid Chinese recovery should not continue. Based on OPEC's forecasting ability and historically, China's ability if anything, to surprise on the upside rather than the downside when it comes to oil demand and growth in general, I think we would be rather bullish on seeing the Chinese demand be strong support for oil demand throughout the year. Was that reasonable answer to your question? Yeah, yeah, definitely. Of course, we could have probably discussed that for four days, but I definitely share your views on the oil market. Yeah, I guess China is a, it's a big uncertain here in the recovery, so yeah. I'll leave it there. Thanks guys. Actually, can I just circle back to the OpEx? Just a final thing. It's worth remembering that we are working on a gas to power project that hopefully should reduce our dependence on diesel. By the end of this year or towards the end of this year, we expect to power most of the fields by consuming the associated gas. While that will incur another OpEx cost, it will certainly be more predictable and less exposed to price fluctuations. I think that's, it's certainly a situation we expected to see mitigated in the coming year. Okay. Thank you. We are now going to proceed with our next question. The question come from the line of Stéphane Foucaud from Auctus Advisors. Please ask your question. Morning, Magnus. Morning, Petter. Thanks for taking my questions. I've got two. The first one is around production. Reading, I think in the text of the press release, it talks about a lot of maintenance activity, I think, in 1Q. I assume that maintenance activity means quite a bit of downtime, and I was wondering if my assumption is correct, if we were to adjust to a normal quarter with a normal amount of downtime, what would have been the theoretical production? I guess probably a bit more than what you have reported. My second question is around Jari-1. How do you feel about those results? You found oil, it looks to be a bit tight. Were you expecting the reservoir to be tight? Is that a surprise? The fact you have oil, but the fact it's tight, does that make it feel better? Does the chance of commerciality is higher or not, given the risk of tightness? Thank you. Okay. To start with the Jari well, I'd say results are pretty much as expected. I mean, three wells have been drilled in the area. There's the one by the current JV, the Luja-1 well, which also encountered oil in tight carbonates. Previous ones by other operators, at least one real old structure, but also with oil fields. I mean, it was known that oil has been generated in that area. It was also known that it's likely the reservoir to be tight. Expectation was that for any flows to surface, we would have to rely on fractures. If there were no natural fractures in the reservoir, then those would have to be artificially created. There is readiness to do that, and that's certainly under expectation, within the expectations. I think what we will hope from the... Put it this way, I think the part of the evaluation will be to see a little bit, is this going to be a bad normal reservoir, a bad conventional reservoir, or is it going to be a good unconventional reservoir? That, I think, is a question that is going to be answered once we get the results from the current evaluation of the well. All in all, I'd say pretty much, reservoir certainly pretty much as expected. Turning to your other question on production, I mean, we're certainly within our guidance, and we stand by the guidance. Your reasoning of course, is correct with a lot of, shall we say, surface activity, that will be downtime. I don't think we're in a position to give a number on what we would have seen had there been no deferment whatever during the quarter. Clearly, of course, with maintenance activities, possibly becoming less going forward, we would expect to see less deferment, yes. Maybe if I ask the question slightly differently. Typically, what's the production efficiency? I mean, in terms of production and cap with, you know, typically in an OC4 platform, you have a percentage on what your theoretical production, what your typical production, and the companies tend to give. That percentage. Do you have typically maybe a way, a different way to ask the question is if you have that figure, how does the production efficiency this quarter compare to previous quarter? It's to give us a sense whether, you know, it's 10% lower than before or 5% or just negligible. Certainly an interesting question and of course we have a bit of view. I don't think we are in a position there to comment publicly on that. We see if we can come, can give some kind of guidance on this going forward. Currently, I think we'll have to leave you with saying that your reasoning is correct, of course, with maintenance activities there is deferment, but I don't think we want to comment on any percentages. Okay. Thank you. We are now going to proceed with our next question. The questions come from the line of Knut Martin Karlsen from Commandeer Capital. Please ask your question. Good morning, Magnus and Petter. It's great to observe the alignment between long duration business, long duration partnership, and long duration ownership in Tethys Oil. I have two questions. First, regarding Block 56 contingency liabilities. Could you give us a back of the envelope calculations, what cost will be if commercial is declared? Is it a one time or is it sort of a over time contingency liability, linked to production or reserve base or et cetera? Secondly, could you elaborate on your thoughts on partnership or financing for Block 58, given commerciality? Thanks. Good morning, Knut. I can take the first question on those liabilities. We are not, we're not at liberty to disclose exactly, those are confidential. There are, I would say that they are strictly defined, no moving parts, and that there are... I mean, the, I would say the, there are different types, but, I would say that it is something that we would be at liberty to perhaps to disclose were they to come into play. At this point, I don't believe it's something that is necessarily material for the bigger picture. Okay. On 58, well, I mean, we consider ourselves to be in quite a good position with 100% and we do not expect the hard well to be overly expensive. Clearly we have a lot of playroom both in farming down to a partner. In case of a commercial discovery, of course, we are within infrastructure and would be within trucking distance, so we could do an early production and use cash flow from early production to fund a larger scale development. Then of course, we would also expect to maybe have the possibility of taking out debt, if we need that for a fast track to larger development in case of a larger discovery. Given our 100% acreage position here, we have a lot of flexibility how we can fund any discovery going forward. Okay, thanks. We have no further questions at this time. I will now hand back the conference to Mr. Magnus Nordin for closing remarks. That case, thank you very much for listening and, stay tuned. Hope to see some of you at the AGM tomorrow. Thank you. Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect your lines. Thank you.