Earnings Call: Q4 2020

Mar 18, 2021

This is a meeting organized with a hard mute. So meaning that if you want to pose a question, you will have to raise the tiny yellow virtual hand on the top of your screen. If you are chosen by the organizer, you will be notified on your screen that you are allowed to unmute, after which you will have to remember to unmute yourself too. Please state your name and position before asking your question. So okay, I think we are ready to go. Good afternoon. This is Bijan Mosavarramani. We have, I believe, over 100 participants that have come into the meeting. We can't see your faces. You can see ours, but I've seen some of the names and I recognize friends and investors and colleagues on the call and many others, of course, have joined. So all are welcome because of the number of participants in the call, which we anticipated, maybe not 100, but quite a few. Joostan has described how we will handle the Q and A session, but of course, you are welcome to raise questions on any matter that you wish and we'll try to respond as best as we can. This is again our fourth quarter twenty twenty and full year twenty twenty interim results presentation. We usually do these in Oslo. I'm sorry that given all of the restrictions posed by COVID, I can't be in Oslo. And those of you who are in Oslo or Savannah or elsewhere, in Europe or elsewhere that I know you face similar restrictions and it's been a obviously difficult and odd, but we continue as a DNO to conduct our business as best we can and as safely as we can under the circumstances. And knock wood, we've been able to conduct our operations where we operate and even where we don't operate in conjunction with our joint venture partners safely and have are pleased with our success in doing so. And hopefully, in due course, this pandemic will be behind us and we can join altogether in person. This has been a busy reporting day for us, both with respect to the release of the financial operational interim results, but also with respect to the additional release we put out today with respect to the acquisition of ExxonMobil's remaining interest in the Baeshiqa license in Kurdistan. And of course, we're prepared to speak to both of those. But let me start with the operational highlights. This is from a slide that was part of our presentation deck that we put on our website this morning. Perhaps many of you have seen it. And then for those who haven't, I'll just speak quickly to these points. Halk and Sandborg will talk to the financial summary slides. I will come back and say some words about the 2021, how we see it, and then we'll open it up to discussion and questions. And my colleagues can then, from other slides or not from other slides, respond to additional questions that you have. And I expect there will be quite a few. Our operational highlights, we telegraphed ahead of time in the last month. But so some of these statistics and figures and trends, you have may have already seen, but I'll just walk through them quickly to provide the context for our overall presentation. In 2020, our net production was just over 95,000 barrels of oil equivalent per day. It was a bit lower than in the past, but considering that we were operating in a very restricted COVID infected world, I think we've managed to do quite well. I mentioned COVID because both the restrictions in terms of getting people in and out of Kurdistan, in and out of other locations, it's been really quite complicated to make sure people are brought in safely, that they're quarantined, that they're safe during the time they are operating in the fields, that they are quarantined on the way out and on the way home. Unlike most of us who are able to work from home during this period, our oilfield staff cannot work from home and most of them have to be on location. So that creates all sorts of challenges for us and for them and for their families. And we've been able to navigate that well, thanks to my colleagues who lead the efforts in Kurdistan from Kurdistan and also from Dubai for allowing us to be as productive as we have been and as safely as we have been. So obviously logistical issues, not just affecting us, but affecting our suppliers, pose some restrictions to what we could do operationally in terms of drilling and maintenance and other surface equipment work that needed to be done. But also, of course, when the price of oil collapsed in last spring and with its panic set in in the industry, in our industry, as well as in every other industry and business and country and family. We have to tighten our belts, restrict our spending, given all the uncertainties as to how long oil prices remain depressed and what does it mean in terms of our the conduct of our business. So we were careful with our spending, cut it back and of course that had an impact on our production levels. Much of that is now behind us. So as I will speak in a few minutes to the 2021 forecast, we will now be able to step on the accelerator once again and recover a bit the lost time. Notwithstanding all of this turmoil and the uncertainty, gross production from the Tawke license averaged just over 110,000 barrels of oil per day, of which 77,700 barrels a day is net to DNO's interest. Our other operating units and the North Sea contributed 17,400 barrels of oil equivalent per day and the oil equivalents, of course, refers to the equivalent contribution of gas. It's not a large part of our business in the North Sea, but we do have gas production. So we convert those figures into barrels of oil equivalent basis as well. So we can have an apples and apples comparison. We were able to replace around 64% of our production in 2020. We produced 35,000,000 barrels of oil equivalent during the year. That's a huge amount of production on the larger back of, of course, of Tawke, but there are many oil companies that have 35,000,000 barrels of oil equivalent or wish they had that on their books. And that's what we produced last year and a typical year we would produce even more than that. So it's a very large number, certainly for a company of our size. And of course, we face the struggle every year. And so as every other company, but in our case, maybe even more than every other company, but in our case, maybe even more so to replace those reserves, replacing 35,000,000 barrels of oil equivalent every year is a major challenge. And the fact that we were able to replace 64% of it, I think is a tribute again to my colleagues and also to the nature of the TAOKI license fields. The 64%, I think is just around maybe slightly higher than the five year average replacement ratio, reserve replacement ratio that we have. So I think we do quite well in that respect. This is in reference to our proven plus probable reserves, our 2P reserves, which still the remaining reserves at the end of twenty twenty are in the order of three thirty million barrels of oil equivalent. These are based on preliminary numbers. We will be issuing our annual statement of reserves and resources sometime, I believe, in the early part of next week, once those numbers are approved for release internally. We have contingent resources, 2C is the way they're typically described by Norwegian companies or European companies, U. S. Companies do it slightly differently. But those are discovered, but not yet commercialized reserves. We have 152,000,000 barrels of oil equivalent. This is sort of unusual. Most companies have more of this 2C component in their reserves and less of the 2P, more certain ones, we're sort of in reverse, but we're hoping to change that and through our exploration activities, primarily in Norway, but also in Kurdistan to build up a large reserve of 2C contingent resources, which would then be a pool that we could draw on to commercialize those and move them into the 2P category. So we can have a discussion of that, but our Norwegian strategy is importantly about exploration and importantly about building up a 2C resource base for the company to ensure that we grow in the future. In 2020, we participated in the flooding and drilling of 17 wells across our portfolio, five in Kurdistan and the balance in the North Sea. Typically, we would have drilled more wells in Kurdistan in a given year. Last year, again, there were COVID restrictions, but also those of you who follow the company know that with the dramatic reduction in oil prices and COVID restrictions also, Kurdistan had a underwent or faced significant financial hardships and they deferred payments or withheld payments to all the oil companies of four months of entitlements and a bit longer for those companies that had royalty interests. And with that drop in the revenue stream from Kurdistan, I believe our arrears, our unpaid balance is around $260,000,000 It's a large figure for us. But in light of that and the challenges to our balance sheet, last year, we hit the brakes on much of the activity in Curtis found that we could hit the brakes on without interfering in wells that we're already drilling or without doing any longer term harm to our ability to recover production when conditions changed. So we will pick up on drilling and I'll come back to that in a few minutes. We drilled six exploration wells last year, drilled and completed or spud and drilled for the most part, six in our portfolio of which three were discoveries and these are not just small discoveries or oil shows, these are significant and exciting discoveries, two in Norway, Birknap and Rover Nord. These are two of the largest discoveries in Norway in the past since 2020. So we're pleased we participated in those. And of course, one in Kurdistan at the Zartik Well, which we also announced test results from today as part of our Baeshiqa license release. So with those operational highlights, I'll ask Hakan to speak to the financial highlights and I'll come back to 2021. Hakan, please. Good, thanks, Beidjan. Can you hear me okay? And again, hello, everyone, and thanks for attending our conference call, our earnings call today. As Birkran discussed, we had to manage through some, excuse me, very difficult market conditions last year. I think we were able to take early action and step up in a good way to meet these challenges that we saw. But I think it's pretty clear that our financial results for the year reflect a low global oil demand and a much lower average oil prices that we faced last year. As you can see here on the slide, we talked about our revenues. The 2020 revenues have dropped by around one third to a much lower level of $615,000,000 last year and that came down mostly on the lower oil prices. We also had significant impairments totaling $276,000,000 They came on across several North Sea assets And these impairments then in turn also contributed to the net loss for the year that came in at $286,000,000 But when we look at how we organize and how we run our business, we have a low cost structure and we took early action as we talked about to reduce our 2020 spend levels in view of the market conditions. And on the back of these actions and our operations, we still delivered a good operational cash flow last year that came in at $236,000,000 and we also reported a good strong EBITDA at $323,000,000 last year. So these are good levels for our cash flow and we were further strengthened by significant Norwegian tax refunds and also some refunds on The UK side. And with the tax coming in, returned to us, we had a strong netback over $500,000,000. You will recall that our netback is reported as an EBITDA adjusted for taxes paid or taxes received. So it's a useful metric in the oil business as we see it that you can sort of build on in addition to your EBITDA, look at what you have after you are done with your taxes. So with this cash flow coming in, we kept our robust cash balances of $477,000,000 intact at year end. And bear in mind that that level of cash came in after we had repaid $161,000,000 of bond debt. You see those mentioned there on this screen, DNO one, dollars one hundred and forty million and the previous Faroe bond, which we had paid back most of it, but we retired the last $21,000,000 last year. So that's helping us on the balance sheet, on the net interest bearing debt came down. So I think those were important achievements also. Furthermore, we bought back some more DNO shares. We had a target of coming to 10%, which is the max treasury shareholding in the Norwegian regulations, and we managed to hit that target by buying back more shares last year. And in September, we reduced our total number of outstanding shares by canceling this important treasury shareholding. If I wanted to just give a few comments on Q4 twenty twenty as well. We've seen in the quarter that we have increased revenues and we also have lower cost of goods sold, but we show a net loss for the quarter on impairments and some other items that we discussed in our report. But we again show Q4, we have strong operational cash flow again and good EBITDA. So we have further high tax refunds and we increased the cash significantly in Q4 alone. We have a lot of information around discussions to recover our outstanding receivables that Bijan mentioned that came about at the end of twenty nineteen and into the beginning of twenty twenty. And we now have seen a plan put in place by the Kurdistan Regional Government, the KRG, in respect of our license, the Tokyo license and how they will pay us for the outstanding arrears or receivables in our case, which is now at an amount of $259,000,000 share. And this will be done as a split of the incremental revenues when the oil prices exceed the $50 per barrel, but we will get our working interest share of that additional incremental revenue that is on top of the normal production sharing contract entitlement. I'm not sure if people have run these numbers on our current oil price, but with $60 per barrel oil price, we will see a pretty significant payment to us towards the outstanding receivables this year if we can keep that oil price up. At the same time, we will get paid now on a running basis on the full contractual entitlements, which is the possession sharing contract plus the override payment that was agreed back in 2017. So I think it's just important to know that this will be with the current occupancies, important incoming cash to DNO to get paid on the outstanding receivables. I think I covered the main points here. I like to always sort of say, and I can say that again this time that we remain in a solid financial position. Now with the outlook for 2021 of improved earnings and improved cash flow based on the guided production levels that we have given in our release this morning and with the current oil price and the repayment plan. So with that to be done, I will hand the floor over back to you again. Thank you. We started our slide on the 2021 outlook with a statement of who we are and where we're going. As you know, there's been a lot of rethinking and agonizing and reimagining and reimaging by oil companies in this post COVID period and the post COVID period as to what they are and what they'd like to become with a significant shift towards renewables among other things. So we thought it was just important to restate that DNO is and will remain a growth oriented oil and gas exploration production company. That's our ambition. That's what we do well. That's the business we want to continue to focus on. We will do so as we've done in the past. We will conduct our business in a socially and environmentally responsible manner. Again, as we have done, we will be sensitive to the needs of governments and countries in which we operate, will be respective of their laws. We will try to be a good corporate citizen. In Kurdistan at the height of the ISIS crisis, DNO stayed and produced because we were key to the Kurdistan's ability to have the funds with which to push ISIS back. I believe we're the only company that stayed on during that period that meant colleagues from Norway and elsewhere outside of Kurdistan and for the region going in during a very difficult time and continuing to work. This is key. This is part of the contract, the social contract, if you will, we have with the host countries in which we operate. That's an important part of what we do. On the ESG issues, everyone seems to be focused on E and not on the S and the G. And the S and the G are very important. All three are important, but the S and the G are often lost in the discussion, but they're critical to who we are as a company and how we operate and continue to do so. We are in Norway and now one of the most active explorers and pleased to be in that circle. We are prioritizing in terms of our exploration activities, lower risk prospects in mature areas with existing infrastructure, which means we can move more quickly to bring any discoveries to commercial production. That's important for us. And we believe there are still a lot of opportunities in the more mature basins in the North Sea, especially in the Norwegian continental shelf that are attractive for a company of DNO's size and our ambition. So we will do that, but we also are picking up more material stakes in these licenses. The portfolio we acquired previously and other acquisitions, including from Faroe Petroleum, tended to have smaller participating interests. So we had the discoveries that they were less material. The end of the larger company, we want to get larger still. So a larger stake in a lower risk prospects in mature areas, again, mature in the sense of having existing infrastructure, preferably that has capacity to take on additional production. And with the Rover Nord discovery, I think that's another indication that there is still more to be found in these mature areas. And that's not just true about Rover Nord, it's not just true about Norway, it's true everywhere I've worked and I've worked in a lot of countries and the surprise is sometimes some people are surprised when discoveries are made in areas that have been worked over by other companies, sometimes over many, many years that there's still quite a bit left that's to be discovered and that's our target rather than the more frontier regions, which could not be brought in production for quite some time. That's not something that's where we excel in terms of our resources, in terms of our ambition. So I think this is an important statement to make as well. That doesn't mean we won't shy away from occasional shots at large opportunities that perhaps a little bit step out of that comfort zone. We have two potentially high impact exploration wells in 2021. We have a number of exploration wells, but two that we're pretty excited about. One is the Edinburgh prospect, which straddles The UK Norway border. And I understand this is one of the last of the large undrilled prospects in the North Sea. And we have a significant portion of that. I believe we have 45% of that Shell operates and we hope to be doing that this year. So that's I think it's a potentially high impact well and there's a lot of anticipation not just that in DNO and among the partnership, but among others as to what that will how that well will go. There's a second well we're excited about, the Gomez prospect in Norway and where we operate and have an even larger interest. We're 85% of that currently and we're that's another one that we're looking forward to drilling this year. In addition to that, those of you familiar with the new Norway temporary Norwegian, not new anymore, but the temporary Norwegian tax program to incentivize additional activity in Norway. We are moving with partners, licensed partners to accelerate the assessments of existing discoveries and to try to sanction these developments ahead of the year end 2022 submission deadline to capitalize on these temporary tax incentives. And we've described in one of our slides in the presentation today what those opportunities are. Obviously, not all of those will be done in time for the 2022 submission. Some of them may not be some as high priority, but we expect and hope that a number of those will proceed and that will give us the opportunity to bring some of our contingent resources in the North Sea into our 2P category. We are going to be drilling at 27 wells this year, 10 more than last year. And the split is 15 in Norway and 12 in Kurdistan. In Kurdistan, these are mostly development wells and focus on Tawke, but also some additional work in Peshkabir and of course at the Baeshiqa license as well. With that program in Kurdistan, we are committed to retaining our position as the leading international oil company in that region in terms both of production activity, but also oil reserves. We expect that with the plans that we have in place for the TAPI license that we will average TAPI production over 100,000 barrels a day. And this will be the seventh consecutive year in which we produce over 100,000 barrels a day. And I think that's an important statement to make. We haven't given a precise number. That's not possible to give, but I would expect it will be over 100,000 barrels a day. We're not the 100,000 barrels a day isn't the cap, it's a floor. But of course, where, how much higher we will be depends on number of other factors with which most of you are familiar. But we do expect that Baeshiqa to fast track production. We will use the existing discovery wells. We'll do it the DNO way. We'll put those on production. We'll use temporary service facilities. We'll truck the oil as we did at Tom Key and then at Peshkabir, so that if all goes according to plan and we have approvals from the government with respect to our development program, we should have some early production before the end of the year from the Mexica license and then we'll ramp it up from there. The figures we're showing for Mexica are still in the 2C category because we haven't put them on production pursuant to development plan. The numbers are probably the modest side, but we'll see. Once we have the wells on production, we start producing from these two wells and perhaps add additional wells, we'll have a better sense as to what we're looking at, at Baeshiqa with the Zartik and the Baeshiqa wells and additional wells in terms of the medium term. We've already doing testing produced, I believe, about, Chris, you and the Nichols might correct me around 15,000 barrels of both lights and medium quality oil from these two wells. And rather than to flare them, we truck them to our export site at Fishgore and those were put into the export pipeline and exported from Kurdistan. So we've had proof of concept. We've had real oil and important volumes during testing. And the oil at Baeshiqa, some of these zones we tested and we described this in the subsequent slides are very lighter than Taoki. So that's probably a positive thing for lightening our overall blend, but also contributing to the lightening of the overall Kurdistan blend. So that's another positive. With that, I'd like to just quickly ask to have our reserve slide put on, Chris, if you could put that on. I spoke about our 2P reserve replacement ratio, 64% this year, 62% on average. That number moves around a bit depending on if you have discoveries or you're making investments, but that's on the left side, you see what the number looked like in the last five years. But I'd like to focus on these two doughnuts to the right, one that shows our 2P reserves and one that shows our contingent resources. And again, it's quite stark that the 2P reserves, the blue, which is Kurdistan, dominates and in the contingent resource, the red, that is the North Sea, dominates. And that's so that tells you where the opportunities are to commercialize existing resources and where we see more work to be done. Our Kurdistan number is basically once we know currently about Baeshiqa, I expect those numbers will grow. And as we start to produce, some of that will start to shift into the 2P reserves. We had a similar story at Peshkabir, although each Peshkabir is not Machigan, Machigan is not. Peshkabir, each one is different. But at Peshkabir, when we first started too, we had some modest contingent resources and with time those grew and shifted into the 2P reserve category and that's continuing. The major contributions in terms of additional 2P reserves this year were from Peshkabir in terms of the top e license overall. So hopefully, that would be our ambition that we would see that similar trend here, but we'd have to start producing it at Baeshiqa. And of course, we will keep you informed on how well that is proceeding. So I think that sums up the slides that I want to share with you in terms of the initiation of this discussion. And with that, I think we can open the floor to questions from the participants. Yes. Thank you, Biccan and Hakan. So for those who want to ask questions, please raise your hand and then I will unmute I will start with Anders Holte here. And Anders, you need to unmute yourself as well. Thank you, Bir and thank you for a well hosted Microsoft Teams presentation. It's the first quarterly one I've been at. It's good work, very well handled and congrats on a good quarter. It's just a rather simple question and it's probably somewhat difficult to answer, but if you could at least get a stab at it. And it's related to when you guide on production just north of 100,000 barrels per day for the Tawke license, what kind of decline rates do you then assume for the Tawke license as a whole when you start to look at 2021 versus 2020? Thank you. Anders, thank you. Again, I've never known you to be muted by anyone and you're not a self muter. So I'm glad you came on and thank you for your question. It's a very important one. I'll start that, but then I'll turn to Chris and Nicholas to see what views they have. As you know, Anders, in past discussions, we've talked about a decline rate of Tawke on the order of 20%, give or take. That's not unusual for a reservoir of this type. I think we've slowed that down somewhat in the past year with additional drilling. The more you drill, the more you can, of course, recover. But also importantly, we've had the Kreshkiguwita Tauke gas reinjection project and part of that was part of the reason for that was to stop flaring and we stopped flaring a couple of years before anyone else figured out that flaring is not a good thing, but also because we thought the injecting the gas at Tawke would improve the recovery rates there and that has been the case, but I'll ask again, Nicholas, perhaps you might say some words about the Tawke reinjection project and what we see, what numbers we've seen? Certainly. So I think 2020 was a year where we only brought on two additional wells at the Taube and Peshkabir, so one on each. And the real difference was we then implemented a gas injection where we are putting gas from Peshkabir, cleaning it and putting it into Tauke field to give us pressure support to dissolve in the oil, to expand the oil and to do many good things, suppress the water. I think we've been, whilst it's difficult to model, we've been pleasantly surprised by early outcomes of that gas and the effect we see. And the, I guess it's a little bit longer. We've got to see how it goes overall, but overall, it's been a good start. And Nicholas, you would say that our that the Taki license, our depletion rate has been, what, about 10% this past year? I mean, it's hard again to make sense of these numbers in isolation because there is a lot going on such as the injection project. But would that be a fair number that's sort of been slowed down a little bit from the 20% that we historically have expected? Yes, I think that's fair, Vijay. A few wells coming on, but also quite a few workovers to get old wells or wells that were suboptimum going again. And I think that has succeeded in certainly slowing the decline and we've seen very positive results at Peshkabir. Chris, do you want to say words about our five gs program for Tawke in 2021 and what that means in terms of further contributions and the efficiency of the development program, this next phase of development program? Certainly, yes. So we have a project, which we call the five gs well for the TAPI field, fifth generation of TAPI wells. And this is a natural step in the evolution of this giant field. It's now in the sort of middle age, we could say. And so we took a look at recent drilling and decided that we needed to change the frame of drilling to get much more what we call bang for the buck. So we set ourselves a target to cut the cost of infill wells in Tawke to $5,000,000 each, while still maintaining the same production per well. So that's the ambition level for the five gs well and we're planning to drill the first one this year. Thank you. So there's so Nicholas Stefano has raised his hand, so I'll unmute you if you have. Nicholas? So please unmute yourself as well. Hi, Casio. It's Nick from Randcap. Thank you so much for taking my question and for organizing this call today. I've got two, if I may. The first one is on the KG receivables mechanism. Would it be fair to assume that the current mechanism is the one that will be happening and there is no room for further improvements to it? Or would you are you still negotiating with AKG for better like terms? Because I spoke in the statements, you mentioned something about the potential interest as well. So if you could talk about that, that would be helpful. And the second question is with regard to Besheka Resources. You did mention that the 2C number especially looks a bit modest. But given you're doing two wells there, I would still expect that to be a bit higher. Is that because the reservoirs are quite stacked, so we could be looking at fairly like small reservoirs, but there could be quite more in this zone, so you need to drill more wells? Or is that purely on an uncertainty sort of like issue because of the fractured reservoirs? Thank you. On the KRG receivable, again, how comfortable we are with the current plan depends on how quickly we think the current plan will return those funds to us that have been withheld at $60 a barrel oil prices, that's $10 above the $50 rents floor that they have proposed and half of that would go to the Hitachi license joint venture partners. So in addition to benefiting from higher entitlement production because of the higher prices and higher entitlement revenues and getting the override revenues and getting the basically half of the difference over $50 I think we'd be seeing a rapid recovery of the full amount, rapid again, oil prices won't stay exactly at 60, then we go higher, then we go a bit lower and they'll move around a bit. But I think we're looking at something less than maybe two years for recovery, but that again will depend on oil price movements. We have indicated and KRG understands that we, and this is true of all the oil companies, are not banks, we're not on the lending business. And we're certainly not in the business of borrowing the bond market at 9% and lending it at zero to any party. That's not our business. And then we go out of business pretty quickly if that's how we conducted our affairs. At the same time, we are fully aware of the challenges facing Kurdistan. We face those challenges ourselves And we are partners with Kurdistan and we have to work together and our success is their success and their success is our success. So we have to work with them and accommodate their needs to the extent that they are that this is shared by all companies in much the same way and that where there is a recovery plan. We have raised the issue and other companies may have as well. I can't speak for the other companies, but we made it clear that, again, interest is something we pay for these funds and it's important to us. But having said that, I should also again make the point that the last time we had this arrears buildup because of it wasn't COVID that it was ISIS, where the Kurdistan couldn't pay us in full according to our contractual arrangements that built up. We were able, when we sat down to settle that, we were offered cash or we were offered some other currency. And the currency we preferred and chose was a greater stake in the hockey field, because had we received cash, what better place for us to have invested that cash with greater return than the hockey field itself. So there's some scope where there's a lot we want to do in Kurdistan. There's some scope for dealing with interest or some part of this package in a different way. And that may be the way we go. But one way or the other, I think everyone understands there has to be some consideration to cover any additional financial pain that we and the other companies have faced as a result of this COVID crisis. So I don't know if that adds some color to your question, but that's really where we stand. Issue short answer. So based on the current receivables you have on your financials, it looks like is that based on the strip prices or upfront prices like 56, 50 7 average for the year? The arrears? Yes. You separated that long term and current. So just I think that 95,000,000 figure is based on strip, I presume, right? Hakan? Sorry, I was distracted here. But yes, the question was on the prices for the what they have used for the outstanding receivables, so the $2.59, right? The 96,000,000, I think, for in your accounts. Okay. In total, we have right, and that's mostly I think we use the average monthly price in our invoices to the KRG for the deliveries that we have made. And we sort of do that on a daily basis in our invoices. We set out exactly what the Brent price was, what the applicable adjustments are to that daily price and then we average that out for the year for the month. And then we have those monthly prices used for the volumes we deliver into the KRG and our monthly invoices. So that is how we then invoice and then normally get paid in a month after the invoice month, but except for these arrears that we have been discussing today. So I hope that answers your question, Nicolas. Yes, that's fine. And then the other question on the Veshika, please? Did you perhaps I can take that one, Vijan? Or Please. So I think Bhishan mentioned at the beginning that Pashkabir is not Pashkabir, but if we look at how Pashkabir has changed since its discovery, had the volumes have increased and increased substantially. I think your question is, are volumes at Vashica too modest? Well, I mean, they're clearly what we feel they are at the moment. But I think it's fair to say that we have one well that's found the Triassic reservoirs and one well that's found the lower Jurassic reservoirs and those are wells on two large structures. So we have a single well on each and ultimately a single well on each and these are relatively crystal wells. And in addition, we don't have three d seismic. So, in my view, so technically put that together, we have good indications, we have good production, good oil, but ultimately there's plenty of unknowns. So is it conservatively what it's certainly what it is where we are at the moment? So to prove up that number then, it would be fair to assume that we're still going to need quite a few more potential appraisal wells. And then when we bring the volume the 2C volume at a certain level, they'll be thinking about a field development plan. Will that be fair to assume? I think we're going to pace ourselves. Our plan was to get the existing discovery wells on production, and we can do that. This will save us quite a bit of money. We'll get them on production. As we produce, we get more information and we get more revenue. And that information and the revenue can then help us drill the next wells. We're going to do this on a budget. We're not going to wait and then spend $500,000,000 doing a full field development. We're not there in terms of information nor are we there in terms of our the desirability of putting that kind of money in with what we know currently. So we're going to pay for ourselves as we've done before Tawke and Apache Beer and the first couple of wells will pay for the next three, four wells and we'll keep going. So fast tracking is importantly about doing that, getting what you can on production quickly and using the revenues to continue to build up to a full field development, which will take some years. So we'll take it a step at a time, but we do want to also manage our CapEx budget and take advantage of the fact that onshore, you can in fact do one of these phased developments. Offshore, you can't. You got commitment offshore to platforms and pipelines and sometimes the fields don't perform the way you hoped they would or prices collapse and you're at risk. Onshore, the beauty is you can take it one step at a time and keep building on it. And that's what's the key to the NO success in Kurdistan and we plan to continue to replicate that. Well, thank you, Niklas. I think we have a few minutes left. If there's anyone else would like to raise your hand? If not, I think we're coming to a conclusion. So then thank you to everyone for participating. There's one here. Oh, this one coming up. Here we are. Eduard Gennon from Carnegie. Hold on. And Oliver, you need to unmute yourself as well. Yes. Yes. Thanks for the guidance for 2021. And as you know, when you give something, we always want even more. So if you try to speculate about the CapEx level over the next three, four years and also how you look at dividends over that period, is it possible to give some kind of guidance on how you look at this? Let me start with that. First on dividends, obviously, we had to we felt we had cut dividends last spring because of the huge challenges and the uncertainties about where COVID was taking us with respect to oil prices. We want to protect the balance sheet and that's hopefully behind us. So as a shareholder myself, I mean, I love dividends, but we'll see we'll give the oil price some time to not to settle, but also to sort of progress. I think it's premature having a week of $60 oil prices, a few days of that jumping into conclusions about anything, or prices can inch upwards or they can then move down based on what happens with the next developments on the COVID side otherwise. So we're going to pace ourselves. We're going to be watching it very carefully. And obviously, as if again, our cash flow remains strong, that will be one thing we want to visit again. With respect to our CapEx beyond 2021, that's a hard one. It will depend in part on which is split between Norway and Kurdistan. As I've said, in Norway, it will depend on which of those projects are going to be sanctioned for PDOs at the end of twenty twenty two. Once we know that, we'll have a sense as to what 2023, '20 '20 '4 will look like in terms of our Norway CapEx requirements and will make decisions as to which of those projects to prioritize. But clearly, by saying we're going to be looking at those, we're committing to higher spending in Norway. But what the magnitude of that is, I don't know, it will likely be for a full program over several years in the many hundreds of millions of dollars of CapEx. In Kurdistan, it's really the Sheikah at this point is the driver of our CapEx program in terms of fresh funds coming in and we'll try to manage that in the way that I've described. So I don't see us having a significantly larger CapEx program in Kurdistan than the one we've already signaled. And I think we're comfortable with that. So 2020, if I had to guess, 2022 would look a bit more like 2021, '20 '20 '3 would start to look different, especially if we proceed with the some of the Norway sanctioned projects to be sanctioned projects. But beyond that, I can't say more. We've repeatedly said that in terms of onshore activity, we have one foot on the accelerator, one on the brake. We can accelerate or faster, we can hit the brake when necessary. Offshore, we're far more limited than that, but we'll try to manage the business as best we can in a prudent way and at the same time in a growth oriented way. So stay tuned. Yes. Thanks. That's helpful. Also again, I note we've gone through as many as 150 participants. Thank you. I expect some of that may have been driven also by the fact that this time we spent a bit more time in our presentation, the published presentations going over specific projects, specific fields, specific, particularly in the North Sea. We've had the investors and analysts asking us to do more of that. And this is the first time, I think, in quite some time that we did just that. So hopefully that was helpful to you and that prompted some of the interest in participating in this session. And I think we're going to do more to provide additional information on our very, very significant portfolio in the North Sea in future presentations. Thank you all very much. Bjorn, any final words on your part or others? No. Well, once again, thank you, everyone, for participating, and we'll see you around in Trimost