Good day, and thank you for standing by. Welcome to the Tethys fourth quarter earnings report 2022 conference call. At this time, all participants are in listen- only mode. After the speaker's presentation, there will be the question- and- answer session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automatic message advising your hand is raised. To withdraw your question, please press star one and one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to our first speaker today, Mr. Magnus Nordin, Managing Director. Please go ahead. Good morning, everyone, or good afternoon or good evening, depending on what part in the world you are when you listen to this webcast. Thank you for listening. Tethys Oil is representing its full- year report for 2022 as well as the result for the fourth quarter of 2022. I'm actually going to start to talk about a number that used to be important in the world, and that's the P/E ratio of a company. Our net earnings for the year are actually up quite a bit. In 2021, we earned $0.51 a share, and in 2022, that increased to $1.79 per share. That's an increase of 350%, which by any measure is quite a substantial achievement for the year. That gives us actually a P/E ratio below 3. If we look a little bit further down the line, we can conclude that we had an operating cash flow. That is the cash flow from our oil production in Blocks 3 and 4 of $86, $87 million for the year. At current exchange rates, that translates to more than SEK 900 million, which, at today's share price, gives us a price cash flow on operating cash flow of actually almost exactly 2. I think any disappointment in 3 and 4 from a cash flow generation perspective is rather misplaced. The 3 and 4- asset continues to generate excellent cash. Our free cash flow for the year, however, is negative, -2.3. That's because we have invested a lot of money in 2022. $89 million, actually, in oil and gas assets. $63 million of those $89 million went into Blocks 3 and 4 to try and maintain production, increase production. As the year moved on, a number of bottlenecks occurred. Drilling rigs were late in commissioning, and we had a fair amount of problems resulting in a somewhat disappointing, if yet quite profitable production. We're going to look in some detail at this call, what we expect from Blocks 3 and 4 for next year. But do remember that the cash flow generation from the asset continues to be quite strong. We also invested in our exploration assets, Block 49, Blocks 56, and Block 58 in Oman. In particular, 56 was quite heavy in investment with $24 million. The bulk of that went into seismic and drilling wells for the Al Jumd discovery, which we had hoped to have in early production before the end of the year. It has taken longer than expected. We are now hoping to be up and running by March 1st, and of course, we'll happily provide some more details during the call. All in all, it has been a strong year. Obviously, Tethys being an E&P company, has been helped by strong oil prices, but the underlying production from Block 3 and 4 and the exploration potential of exploration blocks has taken several steps forward. We are particularly pleased to be able to report prospective resources on part of Block 58 to the tune of well over 100 million barrels unrisked. The risked numbers for one of the prospects here, the Fahad prospect, as you've seen, is actually quite impressive that also. I think on balance, we are quite satisfied with 2022. We are happy with what we've seen from 3 and 4. We're hopeful 3 and 4 will deliver even better with increased investment in 2023, and we are very excited about the exploration potential that we are going to offer. Let's turn into some detailed numbers here. Production Q4 number down a bit from Q3, again, primarily due to late wells and bottlenecking in the surface structures. We have been expecting this, but we do see some good progress from the operator. Problems have been identified. They were not identified, six months ago, and we are confident that they will be solved as 2023 moves on. Revenue, $43 million, and an EBITDA of $27 million for the quarter. Very strong and healthy numbers giving us a very strong base when we enter 2023. Of course, the Fahd prospect maturation completed on Block 58. 184 million barrels is an impressive number. We're certainly not going to target all those reserves in 2023, but we should have at least one highly prospective and quite interesting exploration well for 58 in the second half of the year. Al Jumd will not be commercial production first. It will give us a lot of data, hopefully, once it's up and running. See if we can take Al Jumd to commerciality. First, we need to get the fiscal meter installed, and we are now targeting March 1st after some pretty good progress in January 2023. The full year, average production for the full year, a little bit better than production in the third, fourth quarter. Reflecting, of course, where we came from with 11,000 in 2022, and we've seen the slide in production throughout the year for reasons that we have discussed. Very strong revenue, $156 million with an EBITDA of almost $100 for the year. Block 56, for the $24 million we spent, five wells drilled and more than 2,000 square kilometers of state-of-the-art 3D seismic acquired. We are in the process now of interpreting said seismic. There was significant investment in 3 and 4, in 2024, some in 58 and a little bit in 49, and $24 million was distributed to shareholders. We end the year with 2P reserves of 23.9 million barrels. That's a 37% replacement ratio. One of the lowest we have seen for years from 3 and 4, but for reasons that are understandable. Let me already here mention that the risked resources, prospective resources in the Fahd prospect of Block 58 is more than we have in 2P reserves remaining in Blocks 3 and 4. Let's continue. Reserves and resources year end 2022. Impressive streak from 2016 through 2020 of more than 100% reserve replacement. Reflecting young reservoirs coming on stream, delivering better than expected, and an abrupt change in 2021 and also in 2022. The abrupt change in 2021 coincides with the corona pandemic, which brought activity on 3 and 4, not to a standstill, but to a minimum of exploration and appraisal activity, focusing on drilling development wells and keeping production up. The results of doing that in 2021 continued into 2022. The rather low the 37% reserve replacement ratio reflects more a lack of effort than a lack of success in maintaining that reserve replacement ratio. Given the lack of effort, we are actually rather pleased with having replaced as much as a third of the production that we produced in 2022. That third comes almost entirely from revisions within the producing fields that are actually continue to produce better than we originally expected. For 2023, with increased exploration efforts, increased appraisal drilling, we are hopeful that we are going to return towards the triple-digit reserve replacement ratio for 2023. Moving on to the production sliding scale from Q1 2021 to Q4 2022. We are guiding for between 9,000 and 10,000 barrels of oil per day. We expect continued monthly fluctuations. The slide we saw during 2021 and continued in 2022, was aspirated in 2022, is a direct result of the fewer wells, lower drilling intensity, but also the bottlenecks that identified on the surface. Within those 9,000 and 10,000 barrels of oil per day that we guide for, we expect monthly fluctuations. We are, of course, hopeful that as the year moves on, we will move towards the higher end of that range. Turning to the next slide. This is a familiar picture of Blocks 3 and 4. Seismic acquisition is ongoing, and before the end of, or by mid next year, we expect to have 3D seismic coverage over the entire area of Blocks 3 and 4. In 2023, we are going to see considerably more exploration and appraisal activity geared at finding more oil and increasing reserve total. Four exploration wells, six appraisal wells, roughly with at least one a month that could add new reserves. Among the most notable is the Jari exploration well, to be drilled in early 2023. We would expect to spud within a month. It's in the southern part of Block 4, close to where the Luja-1 well was drilled a couple of years ago. This is an area that holds some large prospects, a proven oil system, underexplored. Luja was drilled slightly off and in a difficult reservoir. Jari should hopefully be better drilled in a better place and with better testing equipment at the site when we drill it. Of course, if Jari-1 comes in and is a discovery, it will be a game changer for, in particular, Block 4. The southern area contains, as I mentioned, a number of prospects. It's reasonably far away from infrastructure, so we would not expect a Jari discovery to contribute to production in 2023, but we could certainly see a reserve impact. Block 56, our largest investment last year, with $24 million seismic and wells. The Al Jumd area, with the Al Jumd discovery and a number of similar leads and prospects. Al Jumd is sitting there waiting to be produced and if we get going by March 1st, we should be in a position to add at least some contingent resources from Al Jumd before the end of the year. Depending on results of the test, we may also have Al Jumd as a commercial discovery. That's something that, of course, we're working on, and the sooner we can start that test, the better. We've been waiting for approval and certification of a fiscal meter, which we are required to have in order to sell this oil for money. If we just produced it without selling it, that would not have been needed. The certification process has turned out to be considerably more complicated than we believed. We believe now that we have mastered what's going on, and some good progress in January. We are now hopeful that we will be able to move the meter and its skid from the construction yard in Abu Dhabi, in the United Arab Emirates, across the border and into the Al Jumd area on facilities into Block 56. Stay tuned. We will keep you updated of any progress. The central area, seismic, quite substantial area, 2,000 sq km, state-of-the-art seismic, covering an area of at least a dozen leads identified on older seismic. All substantial, and as we mature them, we hope to present a good inventory and some also impressive prospective resource numbers during the course of the first half of 2023. Block 56 will also be the focus for exploration drilling in the second half. Block 58, we've come further on the prospect mature maturation. Three prospects in the Fahd area in the northeastern part of the block, Fahd South and Fahd Southwest. Seismic interpretation is ongoing in the South Lahan area, where we have up to half a dozen plus leads identified as so-called salt stringers below a salt layer at 3,000+ meters depth. The South Lahan pay, play is a well-known play. It is in this area over man, and similar stringers are in production, just a few tens of kilometers away from South Lahan in Block 6. Initial focus will be on the Fahd and the South Fahd prospect. Let's turn to some numbers. This is the first time that we are in a position to announce prospective resources. If we turn just to, if we look at the Pmean unrisked numbers, we have, for example, in the Buah area of South Fahd, we have 45.4 million barrels P50, 62 million Pmean. Just looking at the risked Pmean resources, they amount to more than 25 million barrels. Just the risked number for the Fahd is on par with our total number of reserves in Blocks 3 and 4. This will indeed be a very exciting time for Tethys when we drill in Block 58. If any of these comes in, it would have quite a transformative impact on Tethys. Last but not least is the continued work on Block 49. The Thameen-1 well was drilled in 2021, encountered a 30-meter- plus- hydrocarbon- bearing zone in the Hasirah Sandstone. On test, nothing came to surface. The petrophysical studies of sidewall cores coupled with log analysis, et cetera, suggests that the oil is trapped in a very tight sandstone reservoir. The best way to try and get something out is to re-enter the well and retest it, but this time to create artificial fractures in the sandstone to create permeability to allow the hydrocarbons trapped in the sandstone to come to surface. Work is ongoing, and we expect to mobilize to re-enter and retest Thameen by mid this year. 30-meter- hydrocarbon- bearing zone is quite substantial, and the porosity and the quality of the sandstone is quite good. If we are able to successfully create fractures in the sandstone, Thameen could turn out to be quite an interesting well after all. On that, I would like to leave the floor to Petter to give a more detailed discussion of our financial numbers for Q4 and for the full year 2022. Thank you, Magnus. Yes, 2022 was certainly a very remarkable year in the oil market. Financially, you can see the effects of that on our income and earnings quite clearly. The fourth quarter caps that year with revenue and other income of $43 million and an EBITDA of $27.8. You can see the trend was strong throughout the year as oil prices increased, and we kept good cost control throughout. The full year, we saw an achieved price of $94 per barrel, up significantly versus the year before, and with revenues of $156.5 million, even that was a big jump from 2021. Even more, you can see that in EBITDA, which almost reached $100 million for the full year. Of course, the P&L doesn't tell the whole story. As we have spoken about quite a lot, we have had quite some significant investments the past year, and in total, we invested $89 million. Almost all of our EBITDA actually went into oil and gas assets during the year, building for future growth in the P&L. As a result, our free cash flow was a negative $2.3 compared to the positive number we had the year before. That is all investment that we hope will build for future growth and can be harvested in the years to come. Looking more closely at the fourth quarter in oil sales, we saw flat sales in Q4 versus Q3. We saw oil prices come down a bit from the highs early in 2022, still at a very high level in recent years of $93 per barrel. As we had net entitlement that grew in the fourth quarter, we had significantly versus the third quarter, driven by the increased cost oil and lower oil prices. We also ended up being under lifted. This can be seen in revenue and other income that we have an under lift adjustment. You see in the fourth quarter, our share of production, entitlement was 54%, which is a big jump from the 40%-42% in the third quarter, as we caught up some of that cost oil allowance that was available for early in the year. As you can see that entitlement barrels are down year-over-year, but the proportion is higher, and that's a consequence of the slightly lower production. Moving on, OpEx per barrel, we have two major impacts there towards the end of the year. We did see some cost increases. There was some catch-up spending, of course, in some areas as operations picked up, particularly within maintenance. There is a lot of work going on in the field in 3 and 4 to improve the reliability of production. We also saw cost of energy and consumables, all very important to run an oil field operation of this size, all coming up a bit at the end of the year. At the same time with the disappointing production numbers that resulted in a higher OpEx per barrel, where cost increases and lower production in equal measures led to that increase to $15 per barrel. The trend, however, throughout the year was significantly flatter than if you compare to the revenue line and the earnings line. You can see that cost has not been growing at all at equal pace with our income. Now cash flow, a favorite subject of ours. Here, you once again can see quite clearly that trend from the revenue line and EBITDA line transforming into the operating cash flow. A strong trend. The end of the year, we had $28 million in operating cash flow before changes in working capital, which was almost the same as the previous quarter, with about $3 million. If we look for the full year, we had operating cash flow almost $100 million, which of course is brought down somewhat by the changes in net working capital, which is all part of the normal course of our business. As we said, with increasing oil prices, the effect of oil sales do also not only increase our revenues, but they do increase the size of the working capital movement. That is to be expected. This is the highest operating capital since 2018 on an annual basis. A very, very strong underlying cash generation. Of course, the cash doesn't stop there. We invest, and we have invested significantly during this past year, and not least in our own assets. Early in the year, when we invested in some quite significant seismic during the first quarter from Block 56, but also on drilling throughout the year. Towards the end of the year, you could see the CapEx on Block 3 and 4 catching up somewhat, jumping in the fourth quarter as a fourth rig was added and the activity picked up in both seismic and also in the field operations relating to facilities and maintenance and such. That means that from a full year basis, we had a significant jump year-over-year in total spending, reaching just shy of $90 million. What does that mean for free cash flow? Well, we have prided ourselves for many years of having very strong free cash flow. In the underlying assets, the potential is still there, and the generation certainly is. During this past year, with that significant exploration spend that is yet to yield any income, that has, of course, impacted our free cash flow. That is a natural part of the investment cycle for a company like ours, and it does tend at times to be quite lumpy. We saw that during this year with some negative movements early in the year and improvements later. Towards the end of the year, as the general operations picked up in 3 and 4, as well as some other investment in our operating assets, the free cash flow came down somewhat. It's worth remembering that while we still have those significant investments of almost $90 million, we also managed to return over $24 million to shareholders at the same time and end the year with over $40 million in the bank. I think that is a true testament to the financial solidity of the company's operations, even in a year where we have sometimes described our cash-generating asset as struggling somewhat, in terms of production. Good cash flow generation enabling us to invest solidly for the future, setting the scene for some very exciting development in the years to come. Netback, I think, highlights that trend as well that we've spoken about. Here you can especially see the effect on the profitability of Blocks 3 and 4, and the impact of what happens when we increase cost oil. We saw a slight dip in netback after CapEx as the increased cost oil offset that somewhat in the fourth quarter. That is something of a year-end effect. Before that, you can see a quite solid netback after CapEx throughout the year and the underlying trend being very, very strong. Looking a bit forward into the first quarter, as I would like to remind you, and I'm sure many of you are aware, our pricing of the oil that we sell does lag with a few months because of the way oil prices are set for exports out of Oman, which means at already this point, we know what the official selling prices are for the liftings of all the months in the first quarter. As you can see, this is the expected average of $81.5 is somewhat lower than the average OSP that we had in the fourth quarter. That reflects the somewhat weaker market we prices in oil that we saw at the end of 2022. That brings us to a completely different subject, but one of our favorites anyhow. We have a strong tradition of returning cash to shareholders while being able to grow and invest, and this year is no different. The Board of Director proposes an ordinary dividend of SEK 2 per share and an extraordinary distribution of SEK 3 per share by way of redemption, the same procedure that we have had in recent years. The slight difference this year is that we will split the timing of the two distributions to smooth the cash flow and the yield effect, meaning that after the AGM, on the 10th of May, we'll begin the redemption process, which will result in a split and redemption share of a value of SEK 3 per share. Six months later, after the AGM, a regular dividend of SEK 2 per share will be distributed to shareholders. Combined, SEK 5 per share, which is a solid and very healthy distribution, we believe, not least in a year of some quite significant investments with more investments to come. Giving a very balanced approach to both growth and returns. On that subject, we reinitiated share buybacks during the year. In Q3, we started and continued to the end of the year, and it is a good complement to dividends and other distribution given the flexibility, especially when we see that there is more cash on hand and an ability for the company to buy back shares. 260,000 shares in total we've purchased since the AGM in 2022. At the end of the year, we had treasury shares of 738,000 held by the company. That's about 2% of our total outstanding shares. We repurchased shares in 2022 for an average price of SEK 60, somewhat higher than the year before. Certainly higher than 2020, where we were significantly more aggressive. I think this is a signal of how different the markets view companies like ours in terms of valuation. Irrespective, we will keep share buybacks as a tool in our toolkit for the future to be able to complement the distribution, especially with added flexibility than the other tools. When we're speaking of the future, I would like to take us through the production and financial guidance for 2023. We believe we expect the production for the full year to be in the range of 9,000 to 10,000 barrels per day at Tethys. The range, of course, is depending on a number of factors, but including sort of the timing of drilling and the success of wells. We're happy to say that this year we do expect to drill significantly more wells on Blocks 3 and 4 than the previous year, given we have a fourth rig. We of course will continue to release production updates on a monthly basis. OpEx we expect to be at $14.5 per barrel ±$1, that really depends on where we end up in the range of production, but also in the range of different cost estimates on the field. Investments in oil and gas, in total, we expect to be in the range of $85 million-$95 million, the bulk of which will be from Blocks 3 and 4. That really depends on the spending related to the success of exploration and appraisal wells, which will generate more need for more development. Also, the timing of some facilities investments, and which in these days can be a bit more uncertain given supply and service constraints in the industry due to high- level activity. There will be continued focus on drilling development wells and improving the surface facilities to ensure that we do get, we do bring the oil that is in the ground out to the pipeline and eventually to the market. Block 49, very modest spending, but that could have significant impact with the re-entry and retesting of the Thameen-1 during Q2. We see a lot of potential for what is a modest amount of money. On Block 56, we expect one exploration well in the central area for $8 million, our share of that. In the far area of Block 58, we expect to spend roughly $10 million on an exploration well, that's on a 100% basis, also in Q3. All in all, we expect full year CapEx of $85 million-$95 million. We believe we will be able to finance this with our cash flows and the cash we have on hand. With that, I think I hand over to Magnus for some outlook and summary. Thank you, Petter. Let's have a quick look at 2023. Operate student focus at the moment, get that Al Jumd discovery into long-term production tests. Hopefully will happen within weeks as we speak from today. Fahd, interesting numbers. Not that much will happen in the Fahd area. These numbers will stay until we actually drill the well, and depending on the well result, they will change and either disappear or move into contingent resources awaiting development. 56, prospect maturation based on the new seismic. High hopes for some high numbers. Thameen retest, reentry, and retesting preparations ongoing. Expect operations to start late Q2. All of this continues to be underpinned by Blocks 3 and 4, which will continue to provide substantial operating cash flow to fund both the extensive but needed investment program within Blocks 3 and 4 themselves, including an increased focus for the first time in four years, really on exploratory and appraisal drilling, which should have a certain impact. Development willing to increase production, and providing free cash to invest in 56 and 58, and eventually to be part of the future dividends and distribution to shareholders. To stay with us, we are trying to offer something to everyone, from the yield player to the explorationist. Question? Dear participants, as a reminder, to ask a question you will need to slowly press star one one on your telephone and wait for a name to be announced. To withdraw your question, please press star and one and one again. Please stand by while we compile the Q&A roster. This will take a few moments. We're going to take our first question. The first question comes to line of Stéphane Foucault from Auctus Advisors. Your line is open. Please ask your question. Yes, morning gents, and thanks for taking my questions. I have a few, but perhaps I'll start with production at the Block 3 and 4. I think the press release talk about Q4 being disappointing compared to, I guess, the expectation set at the time of the Q3 results. Could you come back on what was disappointing? What didn't work compared to what you said at the time of Q3? Maybe give us at the same time a sense of why you would expect the production to be volatile month on month in 2023. Thank you. Thanks, Stéphane. Well, we saw production drop in Q4 compared to Q3. B y early Q3, we would have expected the backlogs of workovers and the backlogs for development wells to have been to start to disappear. We saw the third drilling rig that was commissioned should have been up and running by late July, early August, didn't start really until early October. Continual problems with the workover hoist, delayed workovers and kept wells at a lower productivity rate than otherwise would have been would been the case. We saw delays in improving water handling, leading to shut-ins of high water cut wells, which in its turn led not to an increase in production, but a flattening of production as what seemed to be back pressure issues and other issues in the production facility system occurred. These were, we thought this was something that would be a part of the past as we entered Q4. Clearly that was not the case. It took longer to get things going. It took longer to get to replace pumps. It took longer to get pumps into the field than we had expected. Instead of seeing maybe the peak of or the lowest production point in Q3, production continued to drop for Q4. Efforts were then made to get as much of this work done and in Q4, so as to be able to offer a strong production outlook for 2023. That's sort of where we left last year. We believe that the operator has a much better grip on what were production bottlenecks on the surface side and what's needed on the drilling of development wells than they had, say, half a year ago. We would still expect that there would be a monthly fluctuations, but we are hopeful that we're going to see a trend of increasing production this year, except different from last year's decrease in production trend. Sorry, go ahead. Yeah, no, go ahead. No, please, Stéphane, go ahead. Why were there so many delays in your view in Q4? Was it supply chain? Was it technical problem? Mishandling of operations by the operator? No, I think supply chain is a good summary. Things simply took longer. It took longer to get people in the field to commission the rig than expected. There's certainly a corona effect. It took longer to mobilize the rig. It took longer to have it certified. Say that everything that occurred in Q3 took 20% more time than we expected for it to do. Then as the fourth quarter progressed, things improved. As I say, that's what we now hope that we are going to see 2023 bear the fruits of that investment. With the problems identified and the rather hefty investment program for the current year, we would certainly expect that to bear fruit. Yes. Thank you. That takes me, lead me to my sort of related, but next question that's about the CapEx for Block 3 and 4. How do you see that in the following year? I guess there'll be a bit of captured CapEx in 2023, given all the problems you described that need to be addressed. How would you see then the CapEx run rate in, say, 2024, 2025? Similar amount? Lower? G ood question, Stéphane. I think I'll duck that for now. We should be able to have a much better idea and a much, much more accurate idea on that by the Q1. We're already seeing some of the effects from the mitigation program in Q4. Give it another quarter, and we should be able to give a much better idea of where we would hope 3 and 4 go over the next, say 2024 and 2025. The other thing I think we are reasonably certain of is that it will continue to generate good operating cash flow for us to spend on shareholders and growth. Yes. Great. thank you. I've got some exploration, but, I'll perhaps joining, leave the opportunity first to other people to ask question. Thank you. Thank you. Thank you. Now, we're going to take our next question. The next question comes the line of Teodor Sveen-Nilsen from Fuglemyra Invest. Your line is open. Please ask your question. Good morning, Magnus. Good morning, Petter. This is Teodor Nilsen from SpareBank 1 Markets, actually. A few questions from me. I'll follow up on Stéphane's questions on production. As far as I interpret you, Magnus, you expect that maybe a higher exit rate for 2023 compared to fourth quarter 2022. Please confirm that then. Next question is on net entitlement. Of course, that's also higher this quarter, as Petter explained. That is, of course, a function of investments. Could you give a guidance, do you expect to the net entitlement to stay at 64% over the next couple of quarters? Final question, that is on dividends. I interpret that the dividend for 2022 will be a total SEK 5 per share, which is down from SEK 7 last year, and of course employing then also a much lower payout ratio compared to the EPS. Should we interpret this as you will more actively use a share buyback as a part of the shareholder distribution mix more than before? Final question is on cost inflation. You already gave some comments on cost inflation, where we see it in the figures now. What do you see going into 2023? Do you still expect cost inflation this year, or should we expect it to stabilize at the current level? Thanks. Okay. Let's see here. I think, on your three first questions, yes, and yes. On the fourth question, I think I'll pass it to Petter. Cost inflation is not my department. First there was a question about net entitlement, I believe. I think it's worth remembering a net entitlement on three and four is a bit of a rubber band. The total for a full year is about 52%, is 52%. It can actually for the full year never go above that. If it does go below early in the year, whatever is not used, of course, till early in the year can be used later in the year. Hence, we have individual periods of higher than 52%, as we had in the fourth quarter, 54%. My expectation is not to start the year with 54%, of course, as that would be a bit difficult. But given that we do see high run rates of OpEx, we're guiding for continued high investments, with oil prices being you know, predicted lower in the first quarter than in the fourth quarter, all else being equal, I mean, that does have an effect that we expect to have a higher net entitlement than what has been sort of the average rate throughout the quarters in 2022. Remember that the cap is 52%, we do have some significant spending in the beginning of the year on 3 and 4. You know, we have a number of exploration wells. We have our seismic ongoing. I do expect that we would have a high net entitlement, all else being equal. Let's remember, there's always another factor, and that's also production, and that's an unknown for that period. It's yet to be seen. Keep those different factors in mind. When it comes to cost inflation, I think we have actually seen that throughout 2022. It's not been entirely obvious always, because there's so many moving parts, especially in OpEx. The number of categories of costs for running an operation this size and scale in a remote place in Oman means that you have quite a big operation, not least in terms of support and logistics. We have seen continual cost inflation, there's also been some offsetting factors. I mean, looking at the Q4 run rate, I would not anticipate any significant jumps from that going forward. We will see variation in cost depending on activity levels. I mean, there will be some volatility, but I would not expect the overall run rate for the year to go up significantly. Then again, I mean, and here's the important to remember that oil prices do are a leading indicator of that. Would we see another sharp rise in oil prices during the rest of the year? It's not to say that we wouldn't see, you know, diesel prices coming up and other prices in the service industry following suit. As I've said in the past, we see a quite slow trickle of those effects through in Oman, and for this operation with relatively long contract being the basis for it. I think that answered most of the questions. Was there anything else, Sveen? No. That's clear. Thank you. Thank you. Dear participants, as a reminder, to ask a question, you will need to slowly press star one one on your telephone and wait for a name to be announced. Now we're going to take our next question. The next question comes line of Knut Martin Karlsen from Commandeer Capital. Your line is open. Please ask your question. Good morning, Magnus and Petter. Thank you for being good stewards of capital for us shareholders, and it's nice to see a potential Spindletop 2.0 developing at Block 58. I have three questions. The first one is regarding share buybacks. As you Magnus alluded to at the start of the call, the share price is at least not overpriced, but the share buybacks have been perhaps a bit moderate in 2022. Is tender offers a part of the toolbox that you would consider when buying back, or is that sort of out of the picture for you? That's the first one. No, I think that's certainly something we could consider. Historically, I mean, we have been using buybacks as one tool and cash distribution as another tool. Certainly with a slightly lower cash distribution, we have more ammunition to deploy in buybacks. Depending on how things evolve, it would certainly be something that could be considered, yes. Okay, thanks. The second question is regarding the CapEx. In Q3, Petter commented that the back of the envelope, it was roughly split 50/50 between maintenance and growth, even though it's hard to know the exact number. Would you say that the same is true for 2023 with a back of the envelope approach? No. I think we're tilting a bit more towards growth this year than we did in the previous year. Yes. Yes. Say 60/40-ish on growth versus maintenance, with the a not insignificant element of potential one-offs as bottlenecks, et cetera, continue to be removed. Bear in mind, I mean, the range does also signal that there is an element of flexibility in the spending to react and spend where it makes the most difference. That split is quite... It's a moving target, so to speak. Yeah. As a reminder, the difference between growth and maintenance can sometimes be a bit blurry. Yes, I certainly think we have a more growth-oriented tilt this year. All right. Thanks. The final question is regarding the drilling campaign on Block 58. In Q3, I think you mentioned that there were gonna be a minimum of two wells, but it seems that there's only 1 well planned for this year. Is it being pushed into 2024 or has it been canceled or? I mean, we'll try and be as cost-efficient as we can. We would plan to do well, drill wells both on 58 and 56. We are keeping a slot for a potential appraisal well on 58, if that's warranted. The drilling program is certainly not set in stone. We will maintain flexibility. Clearly there will be a strong focus on getting the most interesting prospect in the Fahad area drilled this year. Okay. I appreciate the answers. Thanks. Thank you. Thank you. Now we're going to take our next question, and the question comes to line of Stéphane Foucault from Auctus Advisors. Your line is open. Please ask your question. Yes, hi again. Stéphane Foucault. Moving to exploration. On Block 58, are the three prospects you have identified in any way correlated, or are they independent? What do you think would be driving your selection process on whether to drill among the three that you've got, one versus the other. Thank you. Okay. They are separate structures, but they of course rely on the same charge and reservoir properties should be similar. As far as the risking for charge and reservoir goes, a successful well into one of them would de-risk the others also. two, on selection, I mean, we would try to go for the biggest target with the highest chance of success. Just looking at the prospective resource table would give an idea of where that would point us. Yes. There will be fine tuning. There will also be, I mean, drilling considerations, appraisal well, contingent appraisal well planning, all sorts of other things going into that. I'd certainly say that the main criteria will be size and chance of success. Okay. Thanks for that. Among the three risks that you highlighted, so the reservoir quality, the charge, and then maybe trap, what do you think is the main risk or main area of concern with this? The, shall we say, given the rather limited well data we have, there is certainly uncertainty on reservoir. I wouldn't necessarily say that it's negative, but there is certainly uncertainty on it. It, and an advantage of course is, as you do notice, that it's both the Khufai and the Buah that are reservoir targets. Those are, of course, rocks that we know quite well from three and four. We should be in a good position, provided they are saturated and there's oil there, we should be in a good position to flow hydrocarbons out of those reservoirs. The trap integrity, I mean, seismic coverage is good and I think we will have a good idea of trap integrity and then how risky the trap is. Clearly, I mean, for a first well, we would certainly want to go for something with a pretty high trap integrity, as we would naturally like to have a discovery. That will be part of the geological risk and will be completed there. Great. Thank you very much, Magnus. That's it for me. Right. Thank you, Stéphane. Thank you. Dear participants, as a reminder, if you wish to ask a question, please press star one one on your telephone keypad. Dear speakers, there are no further questions at this time. I would now like to hand the conference over to our speakers for closing remarks. Thank you very much for listening. Do stay tuned and, if not before, looking forward to addressing you again on the 9th of May. Thank you. Thank you. That does conclude our conference for today. Thank you for participating. You may now all disconnect. Have a nice day. Thank you.