Dno ASA

OSE:DNO

Earnings Call Transcript 2020-Q4

[Bjørn Dale, Managing Director]

[Audio Gap] This is a meeting organized with a hard mute. [Operator Instructions] So okay. I think we are ready to go.

[Bijan Mossavar-Rahmani]

Good afternoon. This is Bijan Mossavar-Rahmani. 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, [ Bjørn ] has described how we will handle the Q&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 2020 and full year 2020 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 Stavanger or elsewhere, Europe or elsewhere, that I know you face similar restrictions, and it's been obviously difficult and odd. But we continue at DNO to conduct our business as best we can and as safely as we can under the circumstances. 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 all together in person. This has been a busy reporting day for us, both with respect to the release of the financial and 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 for those who haven't, I'll just speak quickly to these points. Haakon Sandborg will talk through 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 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 managed to do quite well. I mention COVID because both the restrictions in terms of getting people in and out of Kurdistan and a lot 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 had to tighten our belts, restrict our spending, given all the uncertainties as to how long oil prices remained depressed and what this would mean in terms of our -- the content 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. But 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 in the North Sea contributed 17,400 barrels of oil equivalent per day, and the oil equivalence, 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 a 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 million barrels of oil equivalent during the year. That's a huge amount of production on the large -- on the back of, of course, of Tawke, but there are many oil companies that have 35 million barrels of oil equivalent or which they have that on their books. And that's what we produced last year. In 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, as does every other company, but in our case, maybe even more so to replace those reserves. Replacing 35 million 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 Tawke license fields. The 64%, I think, is just around maybe slightly higher than the 5-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 or 2P reserves, which still the remaining reserves at the end of 2020 are in the order of 330 million barrels of oil equivalents. 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 in -- 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 million barrels of oil equivalent. This is sort of unusual. Most companies have more of this 2C component in the reserves, less of the 2P, more certain ones. We're sort of in reverse, but we're hoping to change that 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 proof 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 spudding and drilling of 17 wells across our portfolio, 5 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 underwent or faced significant financial hardships and they deferred payments or withheld payments to all the oil companies of 4 months of entitlements and a bit longer for those companies that had royalty interests. And with that drop in the revenue stream of Kurdistan, I believe our arrears -- our unpaid balance is around $260 million. 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 Kurdistan 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 change. So we will pick up on drilling, and I'll come back to that in a few minutes. We drilled 6 exploration wells last year, drilled and completed or spud and drilled for the most part 6 in our portfolio, of which 3 were discoveries. And these are not just small discoveries, or oil shows. These are significant and exciting discoveries, 2 in Norway, Bergknapp and Røver Nord. These are 2 of the largest discoveries in Norway in the past since 2020. So we're pleased we were -- we participated in those. And of course, 1 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 Haakon to speak to the financial highlights, and I'll come back to 2021. Haakon, please.

[Haakon Sandborg, Chief Financial Officer]

Thanks, Bijan. Can you hear me okay? And again, hello, everyone, and thanks for attending our conference call -- our earnings call today. As Bijan discussed, we had to manage through some 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 challenge that we saw. But I think it's pretty clear that our financial results for the year reflect the low global oil demand and the much lower average oil prices that we faced last year. As you can see here on the slide, we talk about our revenues. The 2020 revenues dropped by around 1/3 to a much lower level of $615 million last year, and that came down mostly on the lower oil prices. We also had significant impairments totaling $276 million. 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 million. But when we look at how we're organized 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 million. We also reported a good strong EBITDA at $323 million 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 U.K. side. And with the tax coming in, return to us, we had a strong netback of $559 million. If 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 million intact at year-end. And bear in mind that, that level of cash came in after we had repaid $161 million of bond debt. You see those mentioned there on this screen, DNO01, $140 million. And the previous Faroe bond, which we had paid back most of it, but we retired the last $21 million last year. So that's helping us on the balance sheet. 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 -- sorry, we reduced our total number of outstanding shares by canceling this important treasury shareholding. If I wanted to just give you few comments on Q4 of 2020 as well. We see 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 the impairments and some other items that we discussed in our report. But we again show Q4. We have a strong operational cash flow again and a good EBITDA. So we have further high tax refunds, and we increased the cash significantly in Q4 alone. We have information around discussions to recover our outstanding receivables that Bijan mentioned. That came about at the end of 2019 and into the beginning of 2020. And we now have seen a plan put in place by the Kurdistan Regional Government, the KRG, in respect of our license, the Tawke license, and how they will pay us for the outstanding arrears or receivables, in our case, which is now at an amount of $259 million, DNO share. And this will be done as a split of the incremental revenues when the oil prices exceed $50 per barrel. That we will get our working interest share of that -- the additional incremental revenue that is on top of the normal production sharing contract entitlements. 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 production 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 oil prices important incoming cash to DNO to get paid on the outstanding receivables. I think I covered the main points here. I'd like to always sort of say and we 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, Bijan, I will hand the floor over back to you again.

[Bijan Mossavar-Rahmani]

Haakon, 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 this 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 and 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. We'll 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 -- those 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 on the S and the G, and the S and the G are very important. All 3 are important. But the S and the G are often lost in the discussion, and -- but they're critical to who we are as a company and how we operate and continue to do so. We are in the Norway, now one of the most active explorers, 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'll 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, ended to have smaller participating interests. So we had discoveries, but they were less material. DNO is a larger company. We want to get larger still. So a larger stake and a lower risk prospect in mature areas, again, mature in the sense of having existing infrastructure, preferably that has capacity to take on additional production. And with the Røver 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 Røver Nord, and it's not just true about Norway. It's true everywhere I've worked, and I've worked in a lot of countries. And it surprises 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 -- to be discovered. And that's our target rather than the more frontier regions, which could not be brought on production for quite some time. That's not, again, something that 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 the large opportunities and perhaps a little bit step out of that comfort zone. We have 2 potentially high-impact exploration wells in 2021. We have a number of exploration wells, but 2 that we're pretty excited about. One is the Edinburgh prospect, which straddles the U.K. Norway border. And I understand this is long -- 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 drilling that this year. So that's -- I think that'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 that we're excited about, the Gomez prospect in the Norway, and where we operate and have an even larger interest with 85% of that currently. And that's another 1 that we're looking forward to drilling this year. In addition to that, those of you familiar with the new temporary Norwegian -- not new anymore, but the temporary Norwegian tax program to incentivize additional activity in Norway, we are moving with partners -- license partners to accelerate the assessment of existing discoveries and to try to sanction these developments ahead of the year-end 2022 submission deadline to capitalize on the -- 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 as high priority, but we expect and hope that a number of those will proceed. And that will -- gives the opportunity to bring some of our contingent resources in the North Sea into our 2P category. We are going to be drilling 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, 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 our production, activity, but also oil reserves. We expect that with the plans that we have in place for the Tawke license that we will average the Tawke production over 100,000 barrels a day. And this will be the seventh consecutive year in which we produced over 100,000 barrels a day. And I think that's an important statement to make. We haven't given a precise number. It'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 day isn't the cap. It's a floor. But of course, where -- how much higher we will be depends on a 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 Tawke 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 Baeshiqa license, and then we'll ramp it up from there. The figures we're showing for Baeshiqa are still in a 2C category because we haven't put them on production, pursuing the development plan. The numbers are probably the modest side, but we'll see. Once we have the wells on production and we start producing the -- from these 2 wells and perhaps add additional wells, we'll have a better sense as to what's -- what we're looking at Baeshiqa with the Zartik and the Baeshiqa wells and additional wells in terms of the medium term. We've already during testing produced, I believe, about -- and, Chris, you and, Nicholas, can correct me, around 15,000 barrels of both light and medium quality oil from these 2 wells. And rather than to flare them, we truck them to our export site at Peshkabir, and those were put into the export pipeline and exported from Kurdistan. So we've had proof of concept. We've had real oil -- important volumes during testing. And the oil at Baeshiqa -- some of these zones we vested, and we've described this in the subsequent slides, are very lighter than Tawke. So that's probably a positive thing for -- in terms of 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, can 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 look like in the last 5 years. But I'd like to focus on these 2 donuts to the right, one that shows our 2P reserves and 1 show -- 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 Baeshiqa and Baeshiqa is not Peshkabir. Each 1 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 Tawke license overall. So hopefully, the -- that would be our ambition that we would see that similar trend here, but we'd have to start producing at Baeshiqa. And of course, we will keep you informed on how well that is proceeding. So I think that sums up the slides we have 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.

[Bjørn Dale, Managing Director]

[Operator Instructions] I will start with Anders Holte here.

[Anders Torgrim Holte, Equity Research Analyst]

Thank you for a well hosted Microsoft Team presentation. It's the first quarterly 1 in that. It's good work. Very well handed, 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 '21 versus '20?

[Bijan Mossavar-Rahmani]

Anders, thank you, again. I've never known you to be muted by anyone, and you're not a self muter. So that's -- 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 at 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. And the more you drill, the more you can, of course, recover. But also importantly, we've had the Peshkabir and Tawke 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 injection of 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're seeing.

[Nicholas Whiteley, Group Exploration & Subsurface Director]

Certainly. So I think 2020 was a year where we only brought on 2 additional wells at the Tawke and Peshkabir, so one on each. And the real difference was we then implemented the gas injection, where we are putting gas from Peshkabir, cleaning it and putting into Tawke field to give us precious 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.

[Bijan Mossavar-Rahmani]

And Nicholas, you would say that our -- at the Tawke 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?

[Nicholas Whiteley, Group Exploration & Subsurface Director]

Yes. I think that's fair, Bijan. A few wells coming on, but also quite a few workovers to get old wells or wells that were suboptimal going again. And I think that has succeeded in certainly slowing the decline. And we've seen very positive results at Peshkabir.

[Bijan Mossavar-Rahmani]

Chris, do you want to say some words about our 5G 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 the development program?

[Christopher Spencer, Deputy Managing Director]

Certainly, yes. So we have a project, which we call the 5G well for the Tawke field, fifth generation of Tawke 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 million each, while still maintaining the same production per well. So that's the ambition level for the 5G well, and we're planning to drill the first 1 this year.

[Bjørn Dale, Managing Director]

So Nikolas Stefanou has raised his hand. So I'll unmute you up, Nikolas.

[Nikolas Stefanou, Research Analyst]

It's Nick from RenCap. I've got 2, if I may. The first one is on the KRG 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 seeing any caution with the KRG for better like terms? Because I saw in the statement, 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 Baeshiqa resources. You did mention that the 2C numbers especially looks a bit modest. But given you're drilling 2 wells there, I would still expect that to be a bit higher. Is that because the reservoirs have quite stopped? So we could be looking at fairly like small reservoirs, but there could be quite more in the zone, so you need to drill more wells? Or is that purely on an uncertainty sort of like issue because of the fractured reservoirs?

[Bijan Mossavar-Rahmani]

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 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 Tawke license joint venture partners. So in addition to benefiting from higher entitlement production because of the higher prices and higher type of 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. They may go higher. They may go a little bit lower and they will move around a bit. But I think we're looking at something less than maybe 2 years for recovery. And -- but that, again, will depend on the oil price movements. We have indicated and KRG understands that we -- and this is true of all the oil companies are not banks, are not lending business. And we're certainly not in the business of borrowing in the bond market at 9% and lending it at zero to any party. That's not our business. And then we'd 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's 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 build up because of -- it wasn't COVID then, it was ISIS, when the Kurdistan couldn't pay us in full according to our contractual arrangements and that builds 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 Tawke field because had we received cash, what better place for us to have invested that cash with greater return than Tawke field itself. So there's some scope. 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 add some color to your question, but that's really where we stand.

[Nikolas Stefanou, Research Analyst]

So in short, so based on the current receivables you have on your financials like -- is that based on the strip prices or a Brent price of like $56, $57 average for the year?

[Bijan Mossavar-Rahmani]

The arrears?

[Nikolas Stefanou, Research Analyst]

Yes. If you separate that long-term and current. So just -- I think that $95 million figure is based on strip I presume, right?

[Bijan Mossavar-Rahmani]

Haakon?

[Haakon Sandborg, Chief Financial Officer]

I'm sorry, I was just a bit distracted here. Yes. The question was on the prices for the -- what we have used for the outstanding receivables, the $259 million, right?

[Nikolas Stefanou, Research Analyst]

The $96 million, I think, for -- in your accounts?

[Haakon Sandborg, Chief Financial Officer]

Okay. In total, we have -- yes, right. And that's mostly -- I think we then 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 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 the month after the invoiced month, but except for these arrears that we have been discussing today. So I hope that answers your question, Nikolas.

[Nikolas Stefanou, Research Analyst]

Yes. That's fine. And then the other question on Baeshiqa, please.

[Nicholas Whiteley, Group Exploration & Subsurface Director]

Indeed that -- perhaps I can take that one. Bijan?

[Bijan Mossavar-Rahmani]

Please.

[Nicholas Whiteley, Group Exploration & Subsurface Director]

So I think Bijan mentioned at the beginning the Peshkabir is not Baeshiqa, but Baeshiqa is not Peshkabir. But if we look at how Peshkabir has changed since its discovery, the volumes have increased and increased substantially. I think your question is, are volumes at Baeshiqa too modest? Well, I mean, clearly what we feel they are at the moment. But I think it's fair to say that we have 1 well that's found the Jurassic reservoirs and 1 well that's found the lower Jurassic reservoirs. And those are wells on 2 large structures. So we have assume a well on each and, ultimately, single 1 on each. And these are relatively crystal wells. And in addition, we don't have 3D seismic. So in my view, sort of technically put that together, we have good indications. We have good production, good oil. But ultimately, there's plenty of unknowns. And so is it conservative? Well, it certainly one it is where we are at the moment.

[Nikolas Stefanou, Research Analyst]

So to prove up that number then, would be fair to assume, but we're still going to need quite a few more potentially appraisal wells? And then when we bring the volume, the 2C volume at a certain like level, then we'll be thinking about a field development plan? Would that be fair to assume?

[Bijan Mossavar-Rahmani]

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 give them our 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 million doing a full field development. We're not there in terms of information, nor are we there in terms of our desirability of putting that kind of money in with what we know currently. So we're going to pace ourselves, as we've done before at Tawke and at Peshkabir. And the first couple of wells will pay for the next 3, 4 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 the commitment offshore to platforms and pipelines. And sometimes the fields don't perform the way you hope they would or prices collapse, and you're at risk. Onshore, the beauty is you can take it 1 step at a time and keep building on it. And that's what has been key to DNO's success in Kurdistan, and we plan to continue to replicate that.

[Bjørn Dale, Managing Director]

Well, thank you, Nikolas. I think we have a few minutes left. [Operator Instructions] If not, I think we're coming to a conclusion. So then thank you to everyone for participating. There's one coming up. Here we are. Oddvar Bjørgan from Carnegie.

[Oddvar Bjørgan, Research Analyst]

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 3, 4 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?

[Bijan Mossavar-Rahmani]

Let me start with that. First, on dividends. Obviously, we have to -- we felt we had to cut dividends last spring because of the huge challenges and the uncertainties about where COVID was taking us with respect to oil prices, and we want to protect the balance sheets. 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. Oil prices can inch upwards or they can move down based on what happens with the next developments on the COVID side and 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 1 thing we'll want to visit again. With respect to our CapEx beyond 2021, that's a hard one. It will depend in part on -- it would be a 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 2022. Once we know that, we'll have a sense as to what's 2023, 2024 will look like in terms of our Norway CapEx requirements, and we'll 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 -- Baeshiqa 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 significant larger CapEx program in Kurdistan than the 1 we've already signaled. And I think we're comfortable with that. So 2025, yes, 2022 would look a bit more like 2021. 2023 would start to look different, especially if we proceed with the -- some of the Norway sanction projects -- to be sanctioned projects. But beyond that, I can't say more. We repeatedly said that in terms of onshore activity, we have 1 foot on the accelerator, 1 on the brake. We can accelerate, go faster. We 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 -- but at the same time, in a growth-oriented way. So stay tuned. But also, again, I note we've gone to 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 presentation going over specific projects, specific field specific -- particularly in the North Sea. We've had 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's 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 now portfolio in the North Sea in future presentations. Thank you all very much. Bjørn, any final words in your parts or others?

[Bjørn Dale, Managing Director]

No. Well, once again, thank you, everyone, for participating, and we'll see you around in 3 months' time. Okay. Thanks, everyone.

[Nicholas Whiteley, Group Exploration & Subsurface Director]

Bye-bye. Thank you.