Good morning everyone, and thanks for tuning in to the Q4 report for Tethys Oil. Let's get straight to the juicy stuff. If I could have the first slide. Yes. After. Okay. Yeah. Have to look. Highlights for 2021. Production, 11,136 barrels of oil per day, slightly less than we saw in 2020, and a number that's a little bit lower than we were hoping for. There is a good reason, and that's the CapEx spending for 2021, which came in actually at $35.2 with the lowest spending on blocks three and four we have seen since 2010, compared to an overall CapEx of $45.4. The whole report and the full year of 2021 was quite affected by under investment and increasingly during the year, backlogs and bottlenecks caused by the continued COVID-19 restrictions. Financially however, we had quite a good year, not to say great year. EBITDA at $61.4 for the full year. Free cash of almost 30 compared to $6.7 for 2020. Net result, a magnificent $16.7 compared to $3.3 for 2020. Oil price, nice and sturdy at $62.8, came back very nicely throughout the year. That's of course part of the reason why it's looking so good, but there are other reasons also. Reserve replacement 82%, down from 120% a year ago. The first time since 2011 we have been below 100%. Again, I would attribute that very much to the low investment rate, which has affected both the production numbers and the reserve numbers for 2020, 2021. However, if we look at the overall picture, there is still ample potential to rectify that number and be back over true to form. If we look at 2P reserves and 2C resources actually increased to 41.77 million barrels of oil. Clear point at the project and three and four is still in good shape. Net cash SEK 67.8 million, one of the highest numbers we've ever had. Of course, we are all rejoicing in sharing this with our shareholders, proposing a distribution to shareholders of SEK 7 per share compared to SEK 4 per share last year. A yield announcement, this was 9.7%, and I think it has since the announcement about two hours ago, increased to 10.6% as we speak. That's for 2021. Now let's look at 2022. We guide production at 11 to 11.5, and I would say this is a rather cautious guidance, and we certainly would hope to increase that over the year. What we can see today, we don't dare guide more than between 11 and 11,500. A number to focus on, massive increase in CapEx spending. Almost threefold compared to the actual for 2021. We are going from $91 million. This is both to ramp up production, get back for lost time in the COVID years of 2021. As COVID restrictions recede also, we would drill more wells. We now work with three rigs and one workover rig fully in operation, complemented by a number of well intervention units in Blocks three and four to restart wells, clean out wells and get back to the trend where we were in the past. On top of that, the three and four focus, we are gearing up exploration work on Block 56. A three-well campaign has started. We are halfway through a 2,000 sq km 3D seismic study in 56, and we've already completed a smaller one on Block 58, where we're now maturing prospects. We continue to evaluate Block 49. We are back to 100% ownership after EOG advised that they do not want to stay in that block. When we saw 2021 being very much trying to stay stable and indeed during the COVID environment, a bit surprised by the increase in demand. For 2022 we are going all in to grow. To help us do that, we have reached a milestone of now 30 people in the Tethys Group, something we are both proud and happy about. To remind you, we are Tethys Oil. We're a self-funded, dividend-paying, onshore oil exploration production company. We've been focused on the Sultanate of Oman since 2006, and today we hold one of the largest acreage positions in the Sultanate, blocks 49, 56, 58 and 3 and 4. A quick look at the 2021 oil market. To the right here, you see the oil price which came back dramatically, in particular the H2 of 2021. That's, of course, explained partly by under-investment and partly by an increase in supply, demand as the COVID pandemic receded. We've actually been, as you can see from this slide, we have actually been under-supplied since the Q3 of 2020, and we've seen inventories come down, and we've seen prices rise. Turning to the next slide, this actually puts this in perspective. Even before the COVID situation, we've seen CapEx come down from, you know, as this slide shows from the selection of companies, close to $600 billion a year in investment, down to below $200 billion for 2021. This is a dramatic shift in investment, and we are seeing throughout the industry that companies, suppliers have a difficult time getting back to levels before shutdowns during the pandemic. That's partly, of course, a strong reason why prices are as they are. As this slide shows, the overall trend with under-investment in the face of an ongoing 5% decline worldwide from existing production shows that we may be in for a more sustained period of higher prices as demand is back to almost pre-pandemic levels, whereas under-investment in supply suggests we may have supply shortages. On that note, I'd like to leave the floor to Petter to do a more detailed review of our Q4 results. Petter? Thank you, Magnus. It will be my pleasure. Well, we ended the year on a strong note financially, which is quite clear by the headline numbers of revenue and other income of almost $32 million, EBITDA of $18 million and a net result of $4 million, and especially the free cash flow of almost $9.5 million. This is largely driven by oil price and cost control. Regular listeners to this webcast will be familiar with this trend as it's been the case for many quarters now, where production has been a bit disappointing and unexciting. Oil prices continually come up boosting revenues and costs have increased but at a slow pace. We've seen a clear trend of both revenues and EBITDA in lockstep increasing. Let's get on to the details. To start with production. Q4 production was 6% below Q3, and the full year number was in line with the guidance we provided in Q3. While it's disappointing to see production not picking up, it is clearly the effect of some of these operational issues that we've talked about that were experienced early in 2021. Simply ramping up and getting back from the pause and the cuts in 2020 as a result of the COVID-19 pandemic and the consequences of that on the oil price and oil market and the OPEC+ restrictions has meant it's been a bit difficult to come back to full speed with all those restrictions and under those conditions. One of the major factors in our case is that two of the three rigs that we usually have under contract were put on standby. Remobilizing those took a bit of time, a bit longer than we had expected. Really, it was only towards the sort of last third of the year that we were kind of back to full capacity. At that point, we did experience a number of other issues as well. A majority of these disrupting issues have, however, been remedied towards the end of Q4. As is evident, there is a time lag effect on some of these on production. We might have to wait to see the full results of that. We can go to the next slide, please. Well, thankfully, in the meantime, the prices have been soaring, and they've certainly helped us in making up some of the lost income that we were expecting from the production. You can see the official selling price in the Q3, if you average it, was almost 75, and in Q1, we're expecting it to be around 79. Now that means that we have the Q1 pricing for the liftings in January through March locked in at these prices. The achieved price of course will reflect the relative mix of the size of those liftings and some other quality adjustments in marketing premiums. Otherwise, in general, the Oman blend export quality crude is trading at around $2 per barrel below Brent on average. All right, moving on to my, one of my favorite subjects, net entitlement. We have had plenty of opportunity to talk about this in recent quarters. Net entitlement is actually one of the most important output parameters in an EPSA. However, it is quite difficult to capture in financial accounting, as it isn't captured in its entirety in any of the PNL or cash flow or balance sheet. However, with it being so important and a central output parameter financially for an EPSA, I think it's worth spending a bit of time highlighting it and explaining it. It's quite easy to measure this in volume, but it's actually best understood in value. You can see from the graph, on the line in the graph that the actual volume that we are receiving as net entitlement has been trending downwards. In the meantime, the value of it has increased, not least the gray area, the profit oil portion, which is the actual profit part of the EPSA. Whereas the blue is the cost that we are recovering dollar for dollar the costs we're incurring. An effect of the increasing oil prices is that it pushes down the volume entitlement that we receive, but it increases the value. I think it's worth keeping this in mind in this high oil price environment, where the soaring prices will simply mean fewer barrels are needed to recover the cost. We get a higher value for the remaining portion that is ours to as profit. Moving on. Of course, net entitlement, that is simply a measure of the oil we are entitled to sell, it's not actually the oil we ever really managed to sell. That is the actual oil sales that are nominated and lifted in any given month. As you can see, we have fairly volatile volumes here in the past few quarters, and that is a result of an effect we've talked a bit about, some delays in the logistics of the actual lifting. Meaning we don't necessarily get three liftings in every quarter. For example, in Q4, we had four liftings, boosting volumes and the income from it. You can also see the achieved price, which is the actual price we are receiving for the various listings, which doesn't always match up with the OSP for reasons of volume mix, and as in this case, four liftings representing four different months in one quarter. We believe, however, that these backlogs in the terminal has been remedied, and going forward, we expect to have three liftings per quarter and more comparable numbers going forward. It's worth noting that at the end of Q4, we were slightly overlisted by 11,800 barrels, which does mean we have to at some point make up during 2022. Moving on. OpEx levels have been quite stable overall the past few years, which has been very beneficial for us as the oil price and revenues have increased. We see the ending of the year with $11.5 per barrel, which is highest since the start of the year, and $11.3 million. Looking forward, however, we do expect about $12 per barrel in OpEx for 2022. I think this is a reflection of the increased activity that we see already in Q4. Some of the... Some input parameters like fuel prices coming up, some general cost inflation, and actually maybe some catch-up of the costs that were deferred and cut during the cutbacks in 2020, that kind of catch up. Of course, there is always a lead time in the output for some of the activities, so we quite often see costs lead before we see the results of what that cost is. Moving on to CapEx. As we had indicated, the CapEx for the year would be tilted towards the end of the year. That was the case, so we had the biggest CapEx spend in Q4, however, a bit lower than we had indicated. This is the result of some of the activities we had expected at the end of 2021 being pushed into 2022. For 2022, we are expecting a further increased CapEx of $91 million. We expect that to be tilted mostly to the H1 of the year. When it comes to free cash flow, an important measure to see how the overall health of and profitability of our operations. We can see that we have been free cash flow positive throughout 2021, despite the investment in both the producing assets and exploration assets, and with $9.5 million almost at the end of Q4. Going into 2021 with the heavy tilt of investments in the H1, we do expect this to be a bit impacted negatively in the H1 as the discretionary exploration spend becomes quite concentrated, in part due to the deferment of activities that were expected at the end of 2021. Here is just the cash flow bridge for the full year 2021, where you can see the cash we have generated, the free cash flow, almost $30 million and the $15.5 million we distributed to our shareholders, ending the year with an enviable cash position of about $68.5 million. With that, I turn the microphone back to Magnus. Thank you very much, Petter. Let's have a closer look at where this money comes from and where the new investments are going. We saw some interesting portfolio developments in 2021. Blocks 3 and 4, our main producing asset, were stable and will be ours to produce from until 2040. We are of course doing what we can to maintain the strong cash flow that we get from that asset. Block 49, we formally started the year at 100% working interest, dropped down to 50% as EOG Resources came in. They then decided to leave the block just a bit before the year end, and we are currently working the paperwork to get back up to 100% again. In the same period, the first exploration phase was extended by an additional six months from 2021 to 2022 in June. Block 56, we announced a farming transaction in October, completed it, and we increased to 65 percentage points and also took over operatorship. We are in the second exploration phase, which means that the license currently, the current phase expires in 2023. We have during 2021 made a very focused effort on getting 56, we're moving 56 forward and have already making progress with an assessment campaign and a drilling campaign. Block 58 we signed in 2020, and we maintain 100%, and the first exploration phase ends in 2023, and we are in the seismic phase, I should say. Looking at the map, of course, you see that, in the middle we have the green Block 6, which is Petroleum Development Oman, a joint venture between a number of oil companies, primarily Shell and the Sultanate of Oman. We have blocks belonging to OXY, we have blocks belonging to BP and Total, and we have Tethys' large acreage position on the flank of Block 6, both to the east and to the west. Blocks 3 and 4, lackluster investment, very stable production, if unexciting, despite low activity. We expect 2022 to see a lot more activity. During the Q4, we finally got 3 rigs, 1 workover rig and a number of other units up and running. We are still seeing some effects of COVID restrictions, mainly in getting people in and out of the field, but they are diminishing by the day, and we are looking forward to a very active work program. On the producing fields, we're drilling more producing wells. Between the producing areas and drilling additional appraisal and near field exploration wells, but also looking to go back to do exploration in the more far field areas of the block. We are also continuing increasing the seismic coverage of both blocks. We have done that in 2021. We will continue to do that in 2022. Block 3 and 4 remains very important to us. It is the mainstay of our production. It's where our cash comes from, the cash that we distribute to shareholders, but also reinvest in Blocks 3 and 4 to continue to grow that and also invest in our other blocks, the exploration blocks and the appraisal program on Block 56. Turning to, we have a more detailed look here at Blocks 3 and 4. It doesn't really say anything, but just zooming. Turning to, Blocks 3 and 4 and the dual aim of reducing emissions and while reducing emissions, also reducing diesel consumption. We currently flare and emit CO2 into the atmosphere. This is gas that we could use for electricity, and a project is moving along to make this into reality. With the current oil prices, where we are very happy to sell our product for a high price, we also have to pay more for the diesel we use today to generate electricity. This is really a double whammy in reducing our emissions and reducing diesel consumption, which is a highly prioritized program, project, which has made good progress under 2021, but will now come into a more operational phase, we expect in 2022. With that, we leave Block 56, Block 3 and 4, and turn to Block 56. We are dusting off an old moniker for 3 and 4, a smorgasbord of opportunity. When we first set out, now more than 10 years ago, we had a number of leads on 2D seismic. We had oil shows in a dozen wells. Ten years later, we have produced on block more than $ 100 million barrels of oil, and it has supplied us with enough cash to distribute more than $100 million to our shareholders. Block 56 is in a similar state. We have 2D coverage over what we call here the central area. We have a number of wells that have tested oil, and we have several very interesting and exciting leads that we now need to firm up by doing 3D seismic. The central area here is about 2,000 sq km large. We are halfway through the seismic acquisition here, and the rest of the year we will see interpretation and maturing of leads into prospects in that area where we see, as I say, ample exploration potential. This is complemented by a project that's slightly further along than we were at three and four in the early days, and that's the Al Jumd trend of discoveries. Just to the left, to the west of the yellow line delineating the block, we have the producing Karim small field. A trend of structures, or I should say the trend of structures that constitute Karim just continue into 56, and that's the Al Jumd area. If we turn to the next slide, we see a close-up of the 3D area covering Al Jumd. Number of structures. Several have actually been drilled, and in particular, the Al Jumd structure itself has tested oil in the past. The pro... Three well program we are currently drilling with the Al Jumd two well drilling to be followed by the Sarha and Sahab wells. We are trying to establish the commercial viability of Al Jumd and establish the reserve base of the entire trend, with a view of course, to try and get this into production as quickly as possible. It's run as a separate project to the central area and is really to be constituted as an appraisal project based on what previous operators have discovered. Let's look at the Al Jumd. Here we have a close up of the Al Jumd structure. Discovered as early as 2008 and appraised by our partner and previous operator Medco just over 2 years ago. Al Jumd tested oil, fairly heavy oil with a medium viscosity and well-defined on 3D seismic. What we are trying to do on the appraisal program, if we turn to the next slide. We have good seismic coverage. Given the heaviness of the oil, we are putting a horizontal or a lateral well, I should say, into the Al Jumd structure, into the sandstone that is oil-bearing. We are entering close to drilling through the Al Jumd one well, and then we are going to drill a horizontal section or a lateral section as far as we can along the sandstone line. The longer that section turns out to be, the more oil we will have, and hopefully, the higher the production will turn out to be. This is ongoing, and we would expect results in the reasonably near term. Depending on production results, we will then do a long-term production test, and that will be the basis for evaluating the commercial viability of Al Jumd, which of course will be supported by the two other wells, appraisal and exploration wells, to see how much reserves we could possibly have within the entire Al Jumd trend. Turning back to Block 49. We drilled the Thameen well here in just over a year ago. We came in with a nice 40-meter oil column, which refused to flow. We have since then ascertained that it's a sandstone reservoir that is quite tight. That's to say that the oil needs some kind of stimulus or possibly some kind of horizontal well to come out of the reservoir. We are currently conducting a detailed study of how best to do that, and we should have the results over the next couple of months. As I said, the current expiration period of the license will expire by June 2022. By that time, we will have to make up our minds how to proceed with the Thameen well and with the block in general. There could be other opportunities also. Let me take this opportunity to thank EOG for their excellent contribution and for being a very good partner to us throughout 2021. We are sorry to see them go, but of course, we wish them all the best, in their other ventures, which as you know, they are one of the world's largest operators in the United States, whereas we continue to work the Thameen well. In Block 58, just south of 49, just completed a seismic survey to further understand the South Lahan area, while we are maturing Farha into something drillable. We expect more activity, in particular of the drilling kind, towards the H2 of 2022 in this area. Leaving our blocks and turning to one of the most important areas for any oil company, reserves and resources. Without those, no production. We saw a small drop in reserves, in 2P reserves, I should say. Our 3P reserves increased. A small drop in 2P reserves in 2021, from 26.9 to 26.2 million barrels. Given the production of just over 4 million barrels in the year, that constitutes a reserve replacement ratio of 82% for the 2P, and 37% for the 3P. Adding the contingent resources, we actually saw the total reserve and resource base grow throughout the year. The 82% is certainly not a bad number. Given the circumstances, it's actually a great number. It's the first time we dropped below 100%, but we've also seen very little investment in the year, as we have discussed earlier. Taking a closer look, we can see from the 3P and from the resource base that the asset is very much intact with even the current producing fields, not counting the prospective resources and the potential. Given the circumstances, we are actually quite happy with achieving an 82% replacement and only a small drop in reserves, given the investment program we had. If we put this into perspective, we came above 26 in 2019, and we stay there now for three consecutive years. We have seen an increase throughout the year in combined reserves and resources. Of course, the work program for 2022 will be focused on continuing to grow the reserves and resource base, while also maturing resources through investment, through additional drilling, through further reservoir studies, mature those resources into reserves. Building reserve base, maintaining reserve base is among the highest priorities for any oil companies, because that's what turns into cash and reserves in production over time. On that note, Petter, you want to say a few words about our guidance for 2022 in slightly more detail? Yes. Thank you, Magnus. We have touched upon different areas of our production guidance and the work program throughout the presentation, but we thought it would be suitable to summarize here and give some extra detail on the assumptions. For 2022, we are expecting a daily average production on the full year of between 11,000 and 11,500 barrels per day. And that's to be compared to just above 11,100 in 2021. The outcome in the range is very much dependent upon the performance and the timing of the new wells being drilled during 2022. 'Cause as we saw last year, delays in drilling wells and disruptions to those operations, that does have an impact on the amount of new oil coming on stream. While no oil is ever being lost, the timing does have an impact on the total production number in a given period. For that reason, we have the range as it is today. When it comes to OPEC+, I think we're all aware that it is still very much around as an agreement. From our perspective, we do not expect any OPEC+ quotas to be a limitation on the production in the year. When it comes to operating expenditures, I touched upon that earlier. We do see a slight increase in dollars per barrel going into 2022. This is in part some of the catch up of costs that have been able to put off during 2020 and the cutbacks, but also natural increases from increased activity levels and some inflation in fuel prices. Of course, with production levels being at similar to last year, that does mean a higher dollar per barrel multiple. When it comes to the total 2022 work program and CapEx budget, we're looking at a quite sizable increase to $91 million compared to $35 million in 2021. We see this on at least three of the four blocks, some quite significant increases. On Block 3 and 4, we're looking at $62 million in CapEx, and this is really across the board, the full effect of three drilling rigs for the full year and the resulting facilities investments and also seismic. Block 49, quite modest, only half a million in that feasibility study to follow up the results from Thameen well before we make any further decisions on which way to go and what to pursue. Block 56, a significant investment of $20 million, which of course includes also portions of carry to our partners from Oman. This is primarily the drilling of the three wells currently ongoing in the Al Jumd area, but also the seismic and some of the follow-up costs from that. On Block 58, it's $8.5 million, and that's mainly related to a well to be drilled later this year. It's worth noting that some of these, and I think in total, around $10 million of the 2022 CapEx is really a deferral from 2021. It's all kind of coming into place at once here at the start of the year. We expect to be able to fund this through the cash on hand and the cash flow from the ongoing operations. That's another sign of the strength of the company's producing assets and the solidity of our balance sheet and being able to accelerate in this way at this point in time. Yes. Moving on. We can say a bit about the split here. We can see that about almost 70% of our CapEx is from three and four and 30% to our own operated blocks. You can see that the total number of $91 million, even if you compare it to the years of 2018 and 2019, which were relatively normal by today's standards, it is a sizable increase in the CapEx and a big I think sign of our confidence in our assets and our confidence in the future viability of the company and the belief in the oil industry in the coming years. We feel very, very confident in being able to invest this much at this point in time. Aside from that, we're not only investing, we're also returning cash to our shareholders. At the same time as we are dramatically increasing our investment and our investment in future growth, we are also being able to return or hopefully, if the AGM accepts it, be able to return 2 + 5 krona per share to our shareholders. Two krona ordinary dividend to be paid immediately after the AGM and a redemption shares, a split and share redemption, as has been done in previous years, of 5 krona in the month following the AGM. With that, I would like to hand the mic back to Magnus for further summary. Thank you, Petter. To summarize, operationally, 2021 was an adequate year. Taking into account the challenges we actually faced, it was a good year. Taking into account the opportunities we took of expanding the asset portfolio, it was an even better year. Financially, it was a great year. Oil prices came back, production remained stable in line with 2020, and we generated a lot of cash. For 2022, we already know that the Q1 oil price is gonna be close to $80. We have reasons to believe that oil price is gonna stay up for the Q2 also. We have a massive investment program, both in our producing assets, but also in our potentially producing assets or exploration assets. With that said, we have every reason to be quite excited about what we can offer you, our shareholders, for 2022. Thank you. Questions. Ladies and gentlemen, if you do wish to ask a question, please press zero and one on your telephone keypad. If you wish to withdraw your question, you may do so by pressing zero to cancel. There will be a brief pause while questions are being registered. We have our first question from Teodor Sveen-Nilsen from SpareBank 1 Markets. Please go ahead. Hello, sir. Good morning, Magnus, and good morning, Petter. My name is Teodor Sveen-Nilsen. Three questions from me, if I may. First one just on the CapEx, as you highlight, you increased CapEx substantially year-over-year and also compared to previous years. While production guidance is maintained roughly at the same level. I just wonder when should we expect the production increase from the CapEx you invested this year? Second question is on OpEx per barrel that has trended slightly upwards this year. I guess that is also related to activity, but also related to maybe underlying increase in energy costs. So I just wonder, is it possible to quantify that effect, the latter effect or higher energy costs? My last question is more on the oil market. You showed a graph, several graphs on the oil market, one showing huge underinvestment in the past few years. I'm not sure, do you have any thoughts around OPEC spare capacity and/or spare capacity generally in the Middle East and also in Oman specifically? That's all. Thanks. Thank you, Teodor. I'm gonna start with your last question. We certainly have some ideas on that. We will get back to you with more details on this, both in the corporate presentations in our Q1 report. We're actually doing some serious data gathering on this. We certainly see a trend that OPEC+ or a number of OPEC+ land countries seem to have difficulty reaching the levels they are now entitled under the OPEC+ quota system to produce at. We can only conclude that what we see in our microcosm of blocks 3 and 4 is also affecting the entire industry with shut-in wells, delays, more time and money needed to get back to where we were before shut-ins started. How long this trend is going to continue and whether this underinvestment, as we touched upon earlier, is actually systemic for the industry and will be until investment comes back, I think is too early to say. I think there is certainly a risk on the upside when it comes to oil prices, at least for the near term. Teodor, you probably know more on the macro environment than we do. We follow your research here with great interest. Commenting specifically on Oman, we have seen, once the OPEC limitations came, a product swap in Oman where gas and condensate production has increased and oil production dropped back. In particular, heavier oils have dropped back, I should say, in 2020 and a part of 2021. The Omani production today seems to be quite well balanced. There is scope for increasing, in particular, oil investments. We would expect to see, just like with ourselves, especially in this price environment, additional oil production come out of Oman also from other operators, not only from ourselves. Jumping back to your first question, when we will see the results in production from the investments we do. Well, first step, of course, is to get out of the slump that we saw in Q4 and back to the average for 2021. Depending on how quickly we see that, we would then be prepared to see how quickly we can get back to the higher range of our guidance. If the work program responds very well, we may even be hopeful maybe to be able to revise our guidance going forward. That's to be seen. First step is to continue to watch our monthly production reports as they come out for the Q1. We would be hopeful to see a stabilization reasonably soon. I can't really give any more details, mainly because we don't really have them. I would urge you again to follow our monthly production updates that will continue throughout the year. For the OpEx, that's much more a question for Petter. I'll happily hand the floor to you, Petter. Yeah, Teodor, can you please repeat your question on OpEx again? Yeah. The question is just observe that the OpEx is trending upwards during 2021, and I suspect that is partially related to activity, but also could be explained by higher energy costs. I just wonder if it's possible to quantify the effect of the latter, higher underlying energy costs. No, I think that's a bit difficult. I mean, it's certainly a trend we're seeing. I'm not sure we've seen so much of the energy costs, particularly in 2021, but we would see more of that in 2022, certainly. Yeah, you do have some general inflation in the region, and with higher activity comes higher cost and the output lags, so therefore you get some higher per barrel initially, at least per barrel, costs. Of course there were a lot of savings in 2020 and early 2021 on what would be, I think, normal expenditures such as training and other, you know, travel, which certainly hasn't been the case under lockdowns. That's expected to come back, and especially in the case where we're looking to ramp up activity and boost production. It's a bit of a leading indicator, I would say, across the board of many factors. Okay, thank you. That's all for me. We have another question from Stephane Foucaud from Auctus Advisors. Please go ahead. Good morning, guys. Three questions for me as well. The first one is around CapEx. Sorry. You said that the CapEx would be quite front loaded, and I was wondering whether it applies as well to Block three and four, and whether Block three and four was more spread across. If everything is front loaded, does that leave some room to perhaps add activity and CapEx in the second part of the year if oil price remain high? That's my first question. Back to production, slight different way to ask a bit the same question as the previous person. Where would you see production at Block three and four, say, directionally, in Q4 2021? Lastly, on reserve, so 2P reserve dropped, but 3P and 2C went up. I was wondering why was that? What was behind the increase of 3P and 2C? Was it drilling? Was it that you have different assumption of recovery factor? Just some color would be great. Thank you. Thanks, Stephane. If I may take the reservoir question first. The difference between the 2P and 3P is very much a recovery factor matter. The 3P of course has a lower probability of coming in. To move 3P, so to speak, into 2P, we need to see more data supporting a lesser decline curve than we currently have in the 2P. Continually, in particular for the Farha field, we have seen the more data we have done and the longer we produce the field, the decline curves diminish. The declines become less and less. I think one very simple answer to your question is that given the lower drilling activity in, among others, Farha this year, we simply did not get enough well data to maintain that trend that we have seen in the past. No guarantee that well data would have shown it, but it's factual that we drilled fewer wells, and it's factual that in previous years, more wells have given data that supported a slower decline than previously. That's at least one factor to explain why we are and also why the lower investment seems to have impacted the reserve replacement rate. What, sorry, what were your other questions? Thank you. The other one was around CapEx, and one whether Block 3 and 4 CapEx front loaded or not. Yeah. Yes. Sure, sure. Exit rate for 2022. Yes. Petter Hjertstedt, you want to have a stab at that? At the CapEx? Yeah. I mean, the three and four CapEx I think was a lot more tilted in 2021 towards the end of the year than we would expect under 2022. I don't think we're gonna see any very clear sort of upward trend, not by design at least, not that we're expecting. You know, as you know, there is always a lot of movement throughout the year as plans change and things get pushed. We don't expect any big shift in or big differences, let's say, between the quarters three and four spending. As for the production, I don't really wanna speculate on an exit rate, but let me just say that we start the year below 11,000 if we look at our December production numbers. We've guided for up to 11,500 so far. Typically we would expect to see production throughout the year increase as spending gives effect. How high we will get and where the exit rate actually will be, I think is a little bit premature to speculate on. Of course, as the work program evolves and we see a result of it, we'll be able to get back to comment going forward. If you take into account starting rates and the guidance, you would expect to see production increase continually over the year. Okay. Thank you. Back on the CapEx as a follow on. If oil price remains very high, and perhaps the question more therefore for the exploration side, would there be a scenario where the CapEx could be revised upwards in the second part of the year with more activity? Well, Stephane, I could say that there's certainly, if you look at Blocks 3 and 4, there might be a clear sort of view of a room to do so when it comes to cost recovery and such. But I'll leave that to Magnus. I'll just comment on our operated blocks and saying that in that case it's not so much a factor of oil price but more of operationally what happens. There are certainly plans to follow up whatever investments we are planning today, depending on the, especially, success, I would say. Of course that's always easier if we have significant cash flow to fund it, so we can always do it a bit quicker than otherwise. That in the end very much hinges on the outcome of the drilling. When it comes to three and four, I would say, Magnus. I think it's fair to say that it's a high priority for the partners of three and four to increase production and to make up for lost time. Anything is possible. Historically, we have come in recently where we've guided, but anything is possible. To re-emphasize Petter's point, I mean, if we have a rolling success in 56, we will certainly try to fast-track that into sustainable production. That could cost some money. That, of course, could call for higher output CapEx. As Petter said, that's more driven by the operational success than where the oil price is. Just to add to that, I think it's fair to say that one shouldn't see the finances as the only factor determining kind of the level of investment. There can be organizational limitations or you know other factors in terms of how fast you can ramp up. While finances is certainly important, it's not the only one. There are some lead times sometimes in terms of being able to significantly ramp up activity. Wonderful. Thanks, gents. I appreciate it. Thanks. Thank you, Stephane. We have no further questions, gentlemen. Ladies and gentlemen, I would like to remind you that if you wish to ask a question, you have to click 0 and 1 on your telephone keypad. We have no more questions, gentlemen. In that case, thank you so much for listening and talk soon again. Thank you. Thank you.