Okay, I'll get started then. Good morning. Hello, everyone. Welcome now again to our second quarter earnings call. This has been quite an extraordinary and a challenging quarter as we, from the end of Q1, basically have had no production in Q2 from our operated assets in Kurdistan. This standstill for our main producing assets has obviously severely impacted our second quarter operational and financial results. On the other hand, we continue our outsta nding exploration success in the North Sea with a large discovery in the Carmen well. Our new West Africa assets are also performing well. In the current situation, we clearly benefit from having a diversified portfolio in addition to Kurdistan. Let's go to the next one. The production shutdown in Kurdistan that followed from the Iraq-Turkey, the closure of the Iraq-Turkey pipeline at the end of March, that was due to an arbitration ruling at the time in favor of Iraq against Turkey regarding exports of Kurdish oil. The pipeline closure led to a four-month stop in our production before we resumed partial oil production from the Tawke field in the mid-July for sales of our entitlement to local trading companies. With the buildup of local sales now in Kurdistan, we expect at least a doubling of net production in Q3 from the second quarter, which should again, strengthen our results for, for the current quarter. Looking at Q2, we had the actual net production at 14,400 barrels of oil equivalent per day. That is actually the lowest we have had in 13 years, dropping from 89,400 boe per day in the 1st quarter. Again, mainly due to the lack of Kurdistan production. The North Sea production was, however, also down to 10,800 boe per day in the 2nd quarter, from a level of 14,800 barrels per day in Q1. This drop was primarily due to an extended shutdown at the Norne FPSO in May-June. That impacted our production from our key Alvheim and Marulk assets. In addition, there was planned maintenance at Oda, in the Oda area in the quarter. We were pleased with the first production from the Fenja field, starting up in late April, and currently contributing around 2,000 boe per day net to DNO. With the resumption of the normal operations from July, our North Sea production is now back to the levels we had in the first quarter. Production from our new assets in Côte d'Ivoire in West Africa was high and stable at 3,500 boe per day net to DNO in Q2. We are pleased with the good operational performance of these assets. Otherwise, we maintain our strong financial position with the cash balances of $743 million, and the net cash at $177 million at the end of the second quarter. We're also pleased to announce today that the DNO board of directors has approved another dividend payment of NOK 0.25 per share, that is continuing the quarterly distribution program that we've been running for quite a while now. Next one. With no exports due to the pipeline closure, we are clearly facing a difficult, challenging situation in Kurdistan, as I said. We are taking prudent measures to cut spending and the cost with the aim of recovering the Kurdistan reduced spend by cash flow from local sales. This will be until we are in position to resume regular exports again. As we said, we restarted the partial production from the Tawke field in mid-July. This is done both for well integrity and reservoir testing, and of course, also to step up local sales. Current gross Tawke production is around 40,000 barrels of oil per day, and the contractor's entitlement represents around 50% of this volume, split 75% to DNO and 25% to Genel. Prices for the local sales vary by contract, but average around half of the net prices we achieved before the pipeline closure. These local sales are prepaid directly to DNO by the buyers before they take oil delivery to road tankers at our trucking terminal, so there is no payment risk here. We also run pretty efficient truck loading operations with capacity to load substantial volumes on a daily basis in Kurdistan. We have, we have the Peshkabir field, the remaining shut-in to minimize cost run rates. Other cost reduction and cash preservation measures include the release of the three large rigs, drilling rigs we have on the Tawke license. Unfortunately, we also have had to do staff reductions, and we have discussions with our suppliers to cut costs and extend the payments until the KRG's arrears to DNO are addressed. That was a brief, go on the next one, brief discussion on Kurdistan. We can revert, of course, to more in the Q&A session. I'm moving now to the, our new West Africa assets. We are, as mentioned, pleased to see strong and stable gas production from Block CI-27 in Côte d'Ivoire. We hold an indirect interest in the block of just over 9% since we acquired a one-third stake in the operator, Foxtrot International, in Q4 last year. As such, the Q2 gross production averaged 224 million cubic feet of gas per day and 1,700 barrels of oil per day. This was up 6% from 6% from the average production in 2022. Now, in Q2, DNO's share of profits from this block was $3 million, and free cash flow net to DNO was $6 million. Block CI-27 is a key asset for the country, producing more than 90% of total gas production in Côte d'Ivoire. This comes from offshore gas fields with the pipeline transport onshore for electricity generation. The gas is sold on a take-or-pay government contract, and discussions are ongoing now to increase the price formula cap from the current level of $6.5 per MMBtu. This would be, if agreed, would be in exchange for higher investments aimed at increasing gas production from the block. In addition, DNO also holds an 8% indirect interest in Block CI-12, where Foxtrot, as the operator, has secured a rig for drilling of two exploration wells, starting in Q4 this year. There's also a + 1 at optional well. As a new exploration area for DNO, we are excited about seeing the results from these wells going forward. Good. Let me now hand over to my good colleague, Ørjan, and he will review North Sea progress. Thanks, Haakon. Good morning, everybody. It's very good to meet you all. My name is, as mentioned, Ørjan Gjerde. I am the general manager of the North Sea business in DNO. Our strategy is to be an exploration-focused, full-cycle oil and gas company, which means delivering long-term growth in resources, reserves, and production through exploration success, and take part in profitable development projects for growth in future production. With our six to eight exploration and appraisal wells per year, we are more active than most other oil gas companies on the NCS, at least when you compare to size. Over the last three to four years, we have focused on our exploration efforts closer to existing infrastructure, with a meaningful participating interest and lower-risk prospects. Our largest core area is by far the position we have built in the north, northeast part of the North Sea, the Troll-Gjøa area. This position has been built over several years, starting already in the Origo Exploration times in 2015, enforced significantly after DNO's re-entry through the acquisition of Origo. The starting point was to acquire the best available data and to gain access to new acreage through APA application and targeted BD work. I would argue that 100 million barrels of oil equivalents we have found net to DNO over the last 2.5 years validates the strategy we have chosen to follow. These are discoveries with clear path to commercialization, some with several host platform alternatives, therefore carries high value. From the Norwegian Sea part of our portfolio, we have new gas production coming in in 2024 and 2028 from the developments of Andvare and Berling discoveries, both PDOed in 2022 and approved by the Ministry of Petroleum and Energy earlier this year. Our three discoveries, Røver Nord, Røver Sør, and Kvasir, are all part of an AMI, a cooperation agreement, with three other licenses representing the Grosbeak, Swisher, and Toppand discoveries, led by Equinor, where we are looking into the so-called Ringvei Vest development in the Troll-Gjøa area. The Ringvei Vest will be a reference project which other alternative development solutions will be measured up against. Other discoveries in the area, both current and future, will be taken into consideration during these discussions. It's important for us to assess other alternatives, development concepts than the Ringvei Vest to ensure maximum value from our discoveries and the area as a whole. During the first half of 2023, we have also spent a lot of time together with our new partner in the Brage discovery to identify a fast-track, lower-cost tieback to the Brage production facilities, where we aim for a final investment decision early next year. As previously also reported, we have concluded that the most efficient solution going forward is handing over the operatorship to OKEA, whom also is the operator of the Brage platform. Regarding discoveries, I'd like to add a few comments to the Carmen discovery. The next slide. As we previously have reported, this is the largest discovery in the Norway in a decade.... It's a significant gas and condensate discovery, with a midpoint volume of some 175 million barrels of oil equivalents, and with a significant upside potential. With a 30% holding interest, this discovery alone represent 53 million barrels of oil equivalent net to DNO. Carmen is the sixth discovery for DNO in the Troll-Gjøa area since 2021, following the Røver discoveries, Kveikje, Heisenberg, and Ofelia, as you, as you can see on the map to the right. The three discoveries not included in the current Ringvei Vest AMI are all targeted to be appraised this and next year. As you also can see from the map, there are discoveries. These discoveries are nearby several potential host platforms. We have the Uer, Bergelmir infrastructure to the northeast, Tiedemann to the west, Troll to the southeast, and even Oseberg to the south, which is under the label down in the left corner on the map. All these will be assessed for potential development solutions for the discoveries in this area. With many alternative development alternatives and potential synergies between these discoveries, we would argue these hydrocarbons carry a higher value than most other discoveries of the similar size. This is demonstrated by recent transactions in the area. Our active exploration is in the area, continues through this and next year, illustrated on the map with the yellow dots. These include our DNO-operated Kjøttkake prospect in the license PL1182S. You see the dot in the northernmost dot on the map, that represents the Cuvette prospect, which, in the success case, could unlock several smaller discoveries we have in the area, called BOSS, which means Beaujolais, Orion, Sierra, Synergies, a cluster of small discoveries operated by Wintershall Dea. It's not only here we are drilling exploration wells. Worth mentioning is the DNO-operated Norma exploration well, currently drilling further south in the North Sea. This is DNO's first op`erated HP/HD well, chasing light oil in the Alvheim, Valhall, Ringhorne neighborhood. I have further information of the, this year's drilling schedule on my next slide. Next, please, Christine. Here you can see the excellent start of the year with three discoveries. These were followed by two dry wells in the Røver license called Litago and Eggin. These prospects carry different characteristics than the Røver discoveries and hence, also a different risk. Even though the wells were dry, they were drilled at a relatively low cost and gained interesting information, partly de-risking other prospects in the license. On July 15, we spudded Bergknapp appraisal well after first drilling a pilot hole, checking the area for shallow gas. Even though no shallow gas was encountered in the pilot, we unexpectedly hit shallow gas in the main bore. On July 28, after an assessment of risk, the partnership agreed to suspend operation, permanently plug and abandon the well, replan, and then return to drill a new well at the nearby location later in the year. As mentioned, we have already spud the Norma well further south in the North Sea. Then next up is Ofelia appraisal. Finally, the Cuvette well, which may also slide into 2024. In total, we had a pre-drill estimated outcome of this campaign of 55 million barrels of oil equivalents net to DNO. The result so far is as much as 78 million barrels of oil equivalents. There are more to come. What can we expect from this, these successes when it comes to future production? It's early days and therefore hard to estimate exactly. We have made an attempt to illustrate the potential outcome on this slide you see now. What is obvious from all these discoveries is that we will have a material organic growth in production over the coming decade. As the discoveries are quite recent, detailed plans for development are not yet ready. Please read this graph as an indication of a potential future production curve based on the current discoveries, which are considered commercial. Short term, we have the restart of Trym gas production coming on early 2024, and the Alvheim development starting production later in 2024. Thereafter, in the medium term, we have Brage, Berling, and Bergknapp, which are estimated to come on production in the period from 2026-2027 and up until 2029. From the late 2020s, the Troll Ur discoveries should come in production. Timing will depend on host selection and development concept. As the graph shows, this may take us up to a production level north of 50,000 barrels a day within the next 7, 8 years. An impressive growth graph. From our exploration portfolio, we have 8 firm wells scheduled through 2025, in addition to 7 more currently under evaluation. These are not included in this outlook. My short summary of all this is that we successfully have followed our low-risk, near field exploration strategy, gaining high-value discovered volumes, which will give us material growth in production going forward. We are currently producing just below 5 million barrels of oil equivalents per year, and we had about 35 million barrels of oil equivalents in 2P reserves at the beginning of the year, this year. Over the last two and a half years, we have found 3x our 2P reserves and 20 x our current annual production net to DNO. I can say that at least I am very happy with the achievements delivered by the DNO North Sea team in Stavanger. With that, I hand over to my good colleague, Haakon. Good. Good. Thanks, thanks, Ørjan. It's time to look at a financial results now. Maybe not as fun as usual, but let's go through it anyway. The revenues dropping by $211 million in Q2. Kurdistan was down by $136 million, of course, due to the production shutdown. Also this time, North Sea revenues dropped by $75 million, mainly due to the shutdown of the Norne FPSO in the months of May and June. This, as we have talked about, reduced production from the Alve and the Marulk gas fields in the Q2. We also have an effect on North Sea revenues by lower oil and gas prices in the second quarter. With the lower production, our cost of goods sold were also lower by $48 million in the quarter. That came mostly from the reduced depreciation and lifting costs in Kurdistan. On the other hand, expense exploration was up by $10 million- $16 million in the quarter, explained by dry well costs and seismic acquisitions in the North Sea. When you look at the P&L, the other costs were fairly stable in Q2. On this basis, we show an operating loss of $15 million in Q2, again, primarily from much lower revenues, but with some offset from a reduced cost. We have a fairly stable net financial expenses this time in the quarter, but the tax expenses dropped by $68 million from Q1. That was due to lower revenues and lower taxable profits in the North Sea. All in, we show a net loss of $19 million for Q2. Just to also talk about the on the year-to-date basis through the first half of this year, revenues are down by around 50%. With help from reduced expense exploration and lower net finance expenses, we still show a net income of $69 million for the first six months. Next one. Here we look at the cash flow. We have a cash flow from operations of $16 million for the quarter, dropping from $155 million in Q1, again, from lower revenues. We have included here $18 million in the positive working capital adjustments, mainly coming from an increase in trade payables and accruals in the North Sea, driven by the high drilling activity and also oil prepayments. Shown on the slide under tax, we paid a further $80 million in North Sea tax installments in Q2. We have thereby completed the tax payments or installments for 2022. Looking forward for the second half of this year, we expect a tax refund this time of $6 million for Norway and a tax refund from the UK of around the equivalent to $30 million. On the investment side, we had $73 million in asset investments and capitalized exploration in Q2. This was split between the CapEx of $45 million in the Tawke PSC and for North Sea assets, $28 million for exploration drilling. We had the $7 million in the U.K. DECOM, where we are now finishing up the projects just now. We had the $6 million in the net cash inflow from Côte d'Ivoire. The net finance outflow this time of $27 million was driven by $22 million in dividends that we paid in the second quarter. Our cash balances were thereby reduced by $168 million in Q2, we have a strong remaining cash balance of $743 million at the end of the quarter. Again, looking forward to the coming quarters, we expect that cash flow and development in our cash balances in the second half of this year will be improving significantly from the first six months. This will be with the support of local sales in Kurdistan, higher North Sea production, and also that we have tax refunds of $36 million. That compares to payments of $123 million in the first half of this year. The outlook is now much better than we had, for the first six months. On the next one. Just to summarize what I talked about, the reduction in cash balances coming mainly from a production shutdown in Kurdistan, high NCS, tax payments, and also the dividend, the payments in the second quarter. With a remaining net cash position of $177 million, we maintain a robust balance sheet. Let me also please to note that the equity ratio is high and stable now at 50%. That's quite a strong level. This concludes our presentation today. You have heard that we are proactively managing the export shutdown in Kurdistan. We are building long-term value in the North Sea through successful exploration and development. Our new West Africa producing assets are performing well, we now also add exploration upside in this region. Finally, we maintain our solid financial strength. I think I'll hand it back to Jostein now to manage the Q&A session. Jostein? Thank you, Haakon and Ørjan, for your good presentations, and we're ready to take questions. I am seeing that Teodor Sveen-Nilsen, one of our, our, analysts are following us. He is already raising his hand, so please, ask your, go ahead, Teodor. We cannot hear you, Theodore. Good morning. Can you hear me? Yeah. Yes, yes. Perfect. Thanks for taking my questions. A few questions from me here. First, just on this deal with the local sales, which, by the way, looks pretty impressive. The deal with 50/50 split between KRG and Genel and yourself, is that linked to the PSA, or is that just an ad hoc deal? That's the first question. Second question, the price of the local sales, is that linked to any particular benchmark, or is that negotiated just on every, every lifting? Third question, that is on the North Sea, and the slide that you showed on, I think it was slide 8, Orion, the production profile. Just curious, how much of the production from the Troll area comes from Carmen? That's all. all. Thanks. Yeah. We have Bijan, our Chairman, Executive Chairman with us, but do you want me to, to cover the first question, Bijan? Yes, if you would, please. You asked here about the 50/50, you know, approximate split. This is very much linked to an exact calculation under the production sharing contract. We have calculated our cost oil entitlement and also our profit oil entitlement into that approximate 50% number. In reality, it's more like 51% something, but we're just for simplicity, calling it 50/50. It is based exactly on the production sharing contract terms. Second question was on the pricing for the local sales. These are negotiated contract by contract. There are several buyers, not just this one. We are in discussions, so I won't give away the position there, but we are discussing what the future prices will be. These discussions are ongoing now. We have a very solid position with our trucking operations and pipeline, et cetera, in Kurdistan, and can supply in a very competitive manner into the local market for the time being. It's a negotiation, the negotiated price on individual contracts with the owner. Third question, do you want to cover? Yeah. At the curve, towards the end there, around half the production is common. Remember, this is rough estimates, and an early phase, but it's a significant part of the production towards the end. Theodore, I hope that answered your questions. Yes, absolutely. Actually, I, I, even one more, and that is, of course, regarding pipeline. What outstanding issues are there before the pipeline can open? That will be my final question. Promise. Maybe, Bijan, you want to cover that? Yeah. You know, the first, just to add a little bit more cover, color to what Haakon said, yes, the 50/50 roughly is tracks the the the current PSC splits. In fact, we're probably following the PSC more closely than in a quite some time, in the sense that the government is taking its share of the oil, and we are taking our share of the oil, our entitlement share, and selling it to into the market and being paid directly. When you have these direct payments, these cash and carry payments, as Haakon mentioned in the presentation, you remove this problem that we've had from time to time, that the payments are locked up for a while, and then hopefully eventually released, but now we get paid directly. A local market is developing quite rapidly in Kurdistan. As you well know, other international oil companies are also selling into the market. I think we're selling to some of the same traders, but more traders will pop up because the margins are quite attractive. The difference between the pricing in the local market and the pricing on international markets, although there are some nuances where you can't do an absolute comparison. As more buyers come into the market, there's more competition and more bidding for prices, and prices are sort of inching up a bit to reflect the fact that there are now multiple sellers and multiple buyers and more of a market and more competition. All that is very good. You asked about the pipeline. The portion of the pipeline that gets up to the border has now, again, as you probably know, others may not, has been reversed. And we deliver the government's entitlement share, as I believe other companies do as well. At the pipeline, it flows south and is utilized by refineries down, down the line to the south. The pipeline through Turkey to Ceyhan and the Mediterranean market remains closed. Part of that has had to do, as been explained, by the pipeline operator to maintenance issues and some other related issues. Part of it, of course, has to do with the resolution of the of the the the the differences between the arbitrating parties with respect to the nature of the arbitration, the size of the arbitration, the payments, and so on. If the pipeline opens up, there still is a question as to what happens to the oil that's now going down south and feeding the refinery. Most of the other companies, maybe all the other companies or operators, will have difficulty putting oil into the line and shooting it north when the oil is going south. We, and more, we're at the border, so we will not have that problem. It gives us an advantage and an ability to move oil into the pipeline at such time as the pipeline is reopened. The fact that prices are inching up, that the market is strong, the market of Tawke oil is quite strong. We get requests for volumes now, more and more on the basis of prepayments to us before delivery. The market is probably for Tawke oil anyway, is probably greater... Well, it is greater than, than what Tawke can produce. We have to consider whether the timing is right to open up Peshkabir as well. We said that we're producing about 40,000 barrels a day. We can come back to the levels we had before the pipeline closure of around 100,000 barrels a day. Peshkabir has been closed. We had expected it to remain closed, but if it's- it can be opened under the right commercial terms on the same basis, it would be helpful, not just in terms of cash generation, for us and for our partner, Genel. It would mean more oil going to the pipeline south, that the government can use its one half entitlement oil to feed its refineries. It means that we can restart the gas reinjection program, where the Peshkabir gas was injected into the into the fields at Tawke, and that's another important part of the testing and reservoir modeling and reservoir work that we've been doing. That's that, you know, that may may be the the the next logical step in terms of operations, our operations in Kurdistan, that it put us on a much, much firmer footing if all these pieces fall into into place. I think that's exciting that we found a, and the other companies have found an alternative. The government has been supportive, and that the... our PSCs are being respected in the sense that we are getting our entitlement oil, and we're free to do it with our oil, what we want, and to shop it around and and get prepaid in advance for security of the revenue stream, but also for again, we get paid in advance. Even when we were getting paid previously, it was, it was always a several-month delay, and now that several-month delay has turned into a much, much longer delay. We feel pretty upbeat about the situation in Kurdistan now, but there's still a significant difference between the market prices of crude in the Mediterranean and the price that we're receiving, and we'd like to close that gap as best as market conditions and logistics and so on would, would permit. Stay tuned on that one as we develop these, these, and pursue these options. The next question comes from Nikolas Stefanou, of Renaissance Capital, I believe. Please go ahead and unmute yourself, Nikolas. Jeremy, hi. Good morning, and thank you for taking my questions. I've got a couple on this deal, and then one on the budget. You said that is exactly how the PSC terms are. If I recall correctly, the PSC terms had to do, you know, with specific price, then the KRG would give you. Now there's been a divergence because you've got the price you get from marketing your own crude, and then the price the KRG gets. Are you? How does that work? How does that reconcile for you to get a 50% entitlement, which I would also kind of like have thought of being a bit higher because you're effectively running a kind of like $40 oil price stick at this point now. That's kind of like, that's my first question, if you could clarify that. The second one is, I want to understand how consistent this, you know, marketing your own crude and other IOCs marketing their own crude, how consistent this is with the deal Erbil and Baghdad did on that SOMO should market the Kurdish crude? We're talking about almost 100,000 barrels per day now with, you know, with Kirkuk as well, that is not being given to SOMO, if I'm, if I'm kind of like correct now, but given kind of like locally to other marketers. Is this going to create a problem with, with the budget? Then my final question is on how you think of your own budget, because on some kind of like basic calculations I've done now, you, you, with maybe a $40 oil price realization you get at Tawke now, and based on the, on the cost base you've given in the previous quarter, I think maybe you make something like $10 million-$15 million from Kurdistan each quarter now. It's, it's, it is something, but it's not, it's not something like material. How do you factor this in with your broader budget, especially in the next few quarters, when you have to make some decisions in the, in the off season? Thank you. Good. Thanks, Nikolas, and lovely to speak with you again. I don't know, Bijan, should I discuss on the PSC calculation? Yes. Discuss on it with Theodore's question as well, Nikolas, it's the normal, if you follow the production sharing contract we have discussed with shareholders and investors in the past. You have a cost oil, oil, allocation under that, that goes to the contractors. It's up to 45% of production in a given period, less than a 10% royalty payable to the, to the MNR or KIG. The rest that is not going to cost oil, that covers the contractor's cost, is then going to a sharing of the profit oil between the, the KIG and the contractors. That profit oil has a sliding scale in terms of how much the government share will be in any given situation. We use and that sliding scale where we are now on the profit oil, and you sort of determine how much of the production in a quarter is going to cover cost, and the remaining is going to the sharing of the profit oil. I'm not going to go into the details on the exact calculation, but it's run on that basis. You run the percentage cost oil allocation, and then the rest is the percentage to the profit oil allocation between government and contractors. This is based on the, the, longstanding production sharing contract terms that we've had since we came into the region many years ago. I hope that that covers that question. Anything to add on that, Bijan? No, I think you've described it correctly. These PSCs, the calculation is as Hakan mentioned, it's very classic PSC fiscal regime. In terms of marketing, typically, under the PSCs, the operator markets on behalf of all the participants of the joint venture, including the government. Each one has the right to take their oil and to market it themselves as a service provided by the operator. I think the only important condition is that the sales and sales prices be on an arm's length basis, so some company doesn't sell to its own trading arm at a discount, and it gets some advantage that way. This is all fairly, fairly consistent with how PSCs work and should work. You asked about SOMO, we've not been a party to those discussions and deliberations and know as much about the, the, the current status and the changing status as you do, and you're also sort of reads the press on this. We know no more. We're not party to those discussions, either on the budget or on SOMO. The PSC gives us certain rights. Those rights are embedded in the PSC and are legally enforceable, and there's no reason to think this would be any different. You may have seen, some of you may have seen a statement by an association called APIKUR, The Association of the Petroleum Industry of Kurdistan, that came, I think, two or three days ago, in which these are the four probably largest producers or four of the largest producers in Kurdistan, ourselves, HKN, Gulf Keystone, and Genel. The statement said that we, you know, we encourage and that the that both in the budget discussions and any marketing discussions and any oil law, that the rights of the companies under the PSCs be observed and respected. That is our position as companies, and that's the correct way to approach it, and, you know, we've signed agreements, and those agreements create obligation and rights for the signatories, and we may agree to change those, but we have not done so. We've not been asked to do so. We've had no discussions about it. The situation is complicated, it's complex, and there's there are different parties involved, but we're just glad to be back in back in business and back in the game, and the government takes its oil, as I said, and under what terms it sells that oil or delivers that oil to refineries, we don't know. It's their concern. We have our, our share as determined by the PSC terms that Håkon described, to try to sell and in the best, the best possible price, to. We have every reason to do so, as do the other companies. The pricing is fairly because there are a few buyers, and they have perfect information about pricing and who produces how much, the quality of the pricing. They've circled the wagons, as, as, as we say, in the United States, and they're trying to hold prices at a level that is advantageous to them. We are trying to do the same and push for a price that that gives a fairer split in terms of the sharing of that margin between international prices and Kurdistan prices, recognizing that there are certain certain other considerations in this as well. I think all this is positive. You said $50 million is peanuts. It's not really peanuts, it's $50 million. I, I don't know if that's the right number. I think the right number is a little higher than that. The quality of the payment, again, is better. I'd rather have, let's say the figure is $15 million or $20 million, I'd rather have that money sitting in international bank accounts in Dubai, or in Norway, or in New York. That has more value to me than the $30 million, a much bigger figure, sitting in other bank accounts where I don't have access to it, and it's locked up for a long time to come, and not earning interest, that should be earning interest. The quality of the dollars is also different, and that gives an uplift to these figures, and that, that should be borne in mind as well. We expect this number to go up as we open up. There is a lot of demand, strong demand for oil, for Tawke oil, and I'm sure for some of the other crews as well. We have a couple of more questions. One more question from Nikolas that we haven't covered. I understood your third question, Nikolas, to be around assuming in your question, you had assumed a $40 per barrel oil price, local sales. How would that look for our cash flow and budget, as I think you called it, for the second half of this year in Kurdistan? As we talked about in the presentation, we are quite flexible on our cost structure and our spend levels in Kurdistan, and we will adapt the cost and the spend levels to what we see coming in, in terms of cash flow. In other words, we want to make sure that the local sales will be covering our spending in Kurdistan, covering all the cost. If you assume what you did, the $40 and the current volumes around 40,000 barrels per day gross, I think we, you know, should be in good shape to do what we're aiming to do to, to cover the spend by, by the local sales. Then that will be until we can start exporting again and get back to the normal earnings and cash flow in the DNO group. I don't think I'm going to go into a lot of detail, but, you know, really trying to adapt the spend level to what we see we can negotiate and get in terms of revenues and cash flows with the local buyers. I think we're on a very good, you know, footing and starting point for for those continued discussions on the on the buyer level and also on the pricing level for the for the oils, the oil we produce now currently for local sales. One more- So- Yeah, sorry, go ahead. Just a little bit more color. I mean, we've hit the brakes on costs, as we've announced previously, again, that we've let all the rigs go. We're not doing any drilling. Our crack team in Kurdistan use this downtime to do maintenance at Tawke, then that allows us to hit the accelerator now. We've had important redundancies. We don't like redundancies, we don't like letting colleagues go. I think our reduction in Kurdistan, in terms of the staffing in Kurdistan, we're down 300 individuals. Again, it's a difficult, difficult decisions, but I think they, they, they understand that the times are tough and everyone's taking something of a, of a, of a, of a, of a haircut as a result. More volume, better pricing, lower costs, and that goes a long way to increasing the, the, the, the, the cash coming out of Kurdistan. We bring additional production on downstream, we'll be in, I, I think, in, in, in quite solid shape. We have a couple of more questions coming up. I think we will wrap this up after about an hour. Please be a bit to the point in your questions. Tom Erik Kristiansen is the first one from Pareto. My question, Bijan, you touched on the quality of payments. With that regard, when, when the pipeline opens again, hopefully for exports, is it given that you will immediately just put all the production there? Or do you want to see payment mechanisms restored and some of the amounts owed to you for previous sales recovered before all the oil is, is going for export? So is that, call it, a DNO decision, or, or will it be a government decision in, in the Kurdistan region? Thank you. Well, it, it, it's. Our rights are pretty well established and not always negotiable. We've been now at two instances where we've delivered oil and haven't been paid. Three since my, dur-during my tenure at DNO. The one during the ISIS period, we eventually got paid back, and, and we got paid back with 20% of Tawke, the government's a piece of Tawke and its royalty. We resolved that. I expect we will find a resolution to the arrears as well. It may take longer, and what form it takes, I, I don't know, but that's certainly on the table. The Kurdistan government has repeatedly stated that they will honor that, that obligation to pay us the monies that are, are rightfully ours. We understand why those funds were held back to some extent, we do. We also expect that those funds will be released, but, you know, in, in tranches and so on, and over a period of time. I don't know, we'd like to see them released quickly and right away. That'll be part of a, a, a discussion with the government. Moving forward, again, I, I think, the, the, when the pipeline is opened, how that will... how, you know, what that means, what sort of volumes will go through that line, will depend, you know, on a number of factors, and not, it's not just relating to our commercial interest, but other considerations as well. We'd like to put the oil into markets that provide us the best netbacks, and the pipelining over these distances provides the best netback, rather than trucking and so on. A working pipeline is the most efficient and effective way to move these volumes over these distances. The market in the Mediterranean is quite strong. As you know, the Urals oil that is a comparable crude to Kurdistan Blend, thus feeding the Mediterranean refineries is not coming there as in the volumes that they would like. Those refineries are out looking for more oil. Our oil would be something that they'd love to get their hands on. There have been times, when this oil has sold at a premium to Brent. Typically, it would sell at a discount because of the quality. It's, it's heavier and, and, and more sour. Unfortunately, the timing has been not good. This is, this was the best time to be selling this oil, in that market. That, that this sort of period could, could, could continue. The pipeline is clearly, from a, the numbers point of view, the best way to move the oil. Again, if you pipe 1 million barrels and then don't get paid for it, and then 100,000, you do get paid for it, you're gonna go for the getting paid for it scenario. That has to be sorted out. Great. I think the last questions will come from Ina Golikja at Fearnley Securities. I should also say that press requests can be sent our way after the meeting, and we'll deal with that then. Inna, please go ahead. Thank you. Thank you very much for taking my question. I had just a couple of question remaining now. The first one, looking a little bit of the local market, you, you mentioned that there is demand for, for your oil, but I was wondering if you could give us a little, an estimate of, like, the capacity of that local market, and if, how much oil and, oil DNO can provide to that market is regulated somehow, or it just follows the, the demand during the weeks or, or the months. If you have a certain share of the total market that you can go up to, or... We also know that other IOCs are selling to the local market. We just want to understand how much you can increase your, your share. The second one was on the DNO03 bond. I was just wondering if you can provide some color, if you intend to, let's say, buy back that bond during, in the next quarters, or how do you expect to address that one? If you can give us a little more of color. Thank you. Let me start with the local sales one. I think we, we try to be careful by saying, we're saying we'll sell to local traders rather than to the local market as such, in the sense that it's not like demand for, by consumers for crude has suddenly jumped to these levels at the right price. At $2 a barrel, you know, the local market will extend from Houston to Singapore. I mean, as the oil will find a way to, to market in unlimited amounts. Also when I mean, we know that there's, there's demand for certain products in Kurdistan, not all products. A barrel is refined. The refiners will sell to the local market, the that part of the barrel, whether it's gasoline, or diesel, or naphtha, or whatever the part is, for that particular refinery market, and the rest they will they will sell, and sometimes that, it's, it's, it's those other derivatives that go to other markets. Especially if they were previously importing certain products from outside because they weren't producing enough of it, they can use the local oil, locally produced oil, to, to generate or produce or refine that component and then sell the rest. How that's working out, we don't know, but these are... That's how refineries typically work. I just wanna... Let's make a cautionary statement. It's not like the local market goes up and down of 40,000, 50,000, 60,000, 70,000 barrels a day be, you know, from, from a week, week to week. It's, it's the local traders taking this oil. Where they're placing it, we don't know. How much of it stays, what parts of it stay, what parts are re-exported or exported to other markets, we don't know. Surely, demand doesn't jump up and down by those levels, depending on what the, you know, DNO does or, or the other companies do at any given time. Haakon, would you like to address the bond issue? Yes, thank you. I think, Bijan, we should close the Q&A after this last question. Thank you, Ina. Good to speak to you again. As you know, we've been buying back in the DNO03 several times in the past, and the outstanding amount now is $131 million, with a maturity at the end of May next year. There isn't that much running room remaining on the remaining maturity. Yeah, we've been considering whether we should buy back ahead of time or wait for maturity. I've been trying to see if there is any volumes available for us to discuss with the bondholders in the market. In other words, could they approach us directly and see if we can make a deal on, on the buyback? We have done that, several other transactions in the past. It's a good way, in my mind, you know, finding out what the price level would be. So far, there's been very little coming our way from the bondholders, so they seem to, to like, and that's good that they're supportive of us and want to sit until we call or until maturity. I'm not gonna sort of say, absolutely, we're gonna call it now or later, or wait for maturity, but we're sort of looking at how things develop and taking the total picture of the company into the equation. We're clearly prepared to, you know, we're very well able to pay back at the end of May next year, and there's absolutely no problem on that. Or whether we may do ahead of time, we're coming down on the buyback premium under the bond agreement. That's also one thing to follow. I think mostly is to see whether we can see some movements in the marketplace with the current bondholders, if they wanna approach us, then we can maybe buy back some of the volumes ahead of time in that direction. I think I'll then finish up and hand back to Joost. Yeah. It's like you said, we are done for today. I hope you got your answers. It was great spending an hour with you. Okay. Take care. See you in three months. Thanks very much. Bye-bye. Bye.