Good morning. My name is Svein Liknes. I'm the CEO of OKEA, and welcome to the presentation of the second quarter results for OKEA. As usual, I also have Birte Norheim, our CFO, with me. So I will take you through an operational status first, and then she will take you through the financial section. I will get back for a quick summary before we jump into the Q&A session thereafter. There is a link and also some numbers on our homepage that you can use to pose questions, so I hope that as many as possible of you can actually join us for the Q&A session thereafter. At the high level for the second quarter of 2024 for OKEA is that we've had solid operational performance on our assets, both our operated assets and also partner-operated assets. I will go through in more detail a bit later on each asset. So this has resulted in production of 38,400 barrels of oil equivalent per day. And this is, as you can see, also in the high, high range of what we have guided. So we have decided to narrow the guided range from 35-40 and then take that to 36-40 thousand, based on the performance that we now have seen both in Q1 and Q2. Draugen performance remains still very strong. We did have some production upsets on Brage with the gas cooler, so we had to take one week shutdown, which was unplanned for on Brage, but that is now back up running again. In addition, we have started some wells on Brage, which has more or less compensated for the lost volumes we saw when we had that fault on that cooler. On our partner-operated assets, we've seen stable production. We did have a planned shutdown due to maintenance on Statfjord that is now completed, that also lasted longer than originally planned. But we have also seen after restart of Statfjord Alpha, that they have increased the performance, and we are all seeing a general positive trend when it comes to the Statfjord performance that I will get back to a little bit later. When it comes to our development projects, the Bestla PDO was submitted in April this year. So that is now well underway. We do have the Power from Shore project, which is progressing also according to plan. The work there on Draugen started. Well, it actually started last year, but it was sanctioned just before Christmas, and there is full activity now and a full platform associated with the Power from Shore project, which we're doing for Draugen, but also from the Njord asset, which is the neighboring asset to Draugen. Financially, we had the EBITDA of NOK 1.6 billion and a net profit, OKEA, of NOK 87 million. We have taken an impairment relating to Statfjord and Yme of NOK 267 million, but Birte will take you through a little bit more of that in detail afterwards. And we have strengthened our liquidity position with the issuance of the NOK 125 million senior secured bond OKEA 05 in the quarter. Key operational figures for the quarter is, as you can see, the safety trend is positive. We are seeing a downward trend, both on the serious incident frequency that we show here, but also the total recordable incident frequency. So we're seeing a downward trend there, which is extremely important for us. If you can't do our operations safely, then you cannot be in business, basically. Production, you can see here that we have dropped from 42,100 in last quarter to 38.4, but that is also due to a correction of just above 1,100 barrels that was accounted for in Q1, which was from Q4 last year, so the drop is not that big. Production expense still hovers around NOK 200 per barrel, and production efficiency is 89%, predominantly affected by the increased shutdown on Statfjord Alpha, but also on the one-week production outage we had to take on Brage. But still, we know we are aiming to be in the 90s, but still a strong performance when it comes to production efficiency. And now our priorities is still operational excellence. That is what we focus on. We need to have capital discipline, and we are working to unlock value, something that I think we have demonstrated also in this quarter. Looking at this graph, you see that we have a good distribution of production from our assets. From Q1 to Q2, you see there's a drop on Draugen, but as I just mentioned, that is due to some corrections we did in Q1 on Draugen. But we are seeing some decline in all the assets that we had, and that is mainly due to both planned but also unplanned shutdowns. When you look on the bottom graph, you see that we have high production efficiency. As I just mentioned, we've seen a drop then from 89 to 85 on the Statfjord area, from Q1 to Q2, but that is predominantly due to the outage on Statfjord Alpha, which was planned, but of course, the extension of the revision, the tower was not planned for. You're also seeing a drop then on Brage from 96 to 89, which again relates to the one week that I just mentioned for the gas cooler repair work that we had to do in the quarter. So an operational update on all the assets we have. Well, let's start with the operated one, Draugen. Very strong and reliable operation throughout the quarter again. We are working with initiatives to ensure the integrity and continued stable production of Draugen. We have, as you remember from the last, reporting that we did, have now an approval to produce Draugen until 2040. So obviously we need to work now to ensure that Draugen is then in a position to actually produce safely until that point. We are working on the Power from Shore project, and that is now going according to plan. Work has started offshore, and we are also now planning to install the cable, and work will also start onshore just after summer. On the Brage asset, we did have the production upset in for the gas cooler that has been rectified and production has been restored. We started up the second Talisker well in commercial production, and we have further wells planned for the second half of 2024 with the Fensfjord well, which is coming now in Q3, which we are currently drilling. We did submit the PDO for the Bestla project. The Bestla project has had a very good start and has now established the project team, and we are well underway in cooperation with our main contractors for that project. That is the same project, team, both when it comes to internal resources, but also the contractors we are using externally, that actually delivered also on the Hasselmus project to Draugen, which was a huge success for us. On the Statfjord area, there was a planned shutdown on Statfjord A that was extended, as I've mentioned. Production efficiency is improving overall, not just on Statfjord Alpha, but also on Bravo and Charlie, so that is promising to see. We are now working very actively within the license, together with Equinor, but also Vår Energi, to relaunch and update the drilling plans for future value potential in the area, which then starts with identifying targets, drilling them out, and that is something we will try to map out now until August to have an approval so we can launch on that project to actually unlock the value in Statfjord. For Ivar Aasen has been very stable operation during the quarter. Hanz has been put into production as well, and we are now maturing again the IOR or the Infill Oil Recovery project for 2026, with the drilling campaign that will start then. On Nova, the water injection on the Nova field is still ongoing, so we are planning now to drill one more well in the second half on Nova. And we're also seeing some issues on some integrity on the valve, on the water injection system on Nova. So we have reduced production from Nova right now due to the lack of water injection. When it comes to the Ula field, we had some issues during the quarter or previous quarter as well with the E1 production well. That was rectified, so that is now producing as normal again. We're also looking into the greater area around Ula because Ula is a candidate for several tie-ins in the area that we are working actively together with the operator on, to see how we can extend the lifetime and also to have Ula as a very productive host in the area for other tiebacks. Yme, production efficiency has been improving, as you can see on my previous graph. We are currently drilling the C3 infill well, which will be started now early in Q3 this year. And we are again working to mature additional infill targets in the Beta template, which is now ongoing in the asset to ensure that we have more resource potential to produce also on the Yme for the future. So these are development projects that we have, or the biggest ones. We do have obviously a lot of infill drilling and other CapEx projects on both, particularly on Brage and Statfjord, but these are the two main development projects. We have the Power from Shore for Draugen, which is positioning Draugen for the future. We have to reduce the emissions. We are reducing the emissions, or the CO2 emissions, by 95% when we have electrified production from 2027. We are also then reducing the emissions by 200,000 cubic meters per day, no, tons, I mean, per day, and we are also increasing the gas export capacity because we are not using that gas for power generation. We can now actually sell that gas. And it also increases the production efficiency and reliability. Electrified assets is more reliable and has higher production efficiency compared to gas-powered assets. So, this is a project with a lot of positive contributions to the asset for the time to come. The second project is the Bestla development that we submitted the PDO for earlier this quarter. 24 million barrels of oil equivalent, which is recoverable, take it into Brage, and this will actually add 10,000 barrels of oil to net to OKEA when it comes into production in 2027. It is a healthy project with the break-even of around $40 per BOE, and we have a total CapEx budget of around $6 billion for this project. But again, this is also part of our strategy to identify resources around the assets that we operate, to ensure that we have an asset with high production efficiency and which is a reliable as a host, and then we can tie in these projects, which actually is in the area. So I think the Bestla development is a very good example for additional resources that OKEA will produce, which also shows that that part of our strategy works. So with that, I will hand over to Birte, that will take you through the financials for the quarter, and then I'll come back for a quick summary thereafter. Thank you, Svein. Before we dive into the details of the financial results, I'll start with a brief recap on the financing activities we have completed during the quarter. In May, we issued $125 million senior secured bond with a four-year maturity and a fixed coupon of 9.125%. The bond issue was well received in the market and was more than twice oversubscribed at final pricing. The bond, which is referred to as the OKEA zero five bond, matures in 2028, which is after the scheduled startup of the Bestla and Power from Shore projects. This means that it's only the OKEA zero four bond that matures prior to completion of our two most capital-intensive projects. In relation to the new bond issue, the tap option under the OKEA zero four bond was replaced by a tap option in the longer-dated OKEA zero five. The size of the tap remains the same at $125 million. As part of the financing process, we also increased the size of the revolving credit facility from $25 million to $37.5 million, which provides additional financial flexibility at a relatively low cost. In combination, these measures have strengthened liquidity and enhanced flexibility as we are heading into the most CapEx intensive period for our two development projects. Then, let's have a look at the financial figures for the quarter. We produced 38.4 thousand barrels of oil equivalents per day. The lower production was mainly due to a prior period adjustment of volumes produced from Hasselmus by about 1.1 thousand barrels per day, recognized in the previous quarter. In addition, a turnaround lasting 60 days at Statfjord A was completed during the quarter. We sold 33.3 thousand barrels of oil equivalents per day, and following the significant overlift in the previous quarter, equivalent to about 4.55 thousand barrels per day, we have a significant underlift in the current quarter, equivalent to about 5.11 thousand barrels per day. Lifted volumes follows production as well as lifting schedules, and will even out with produced volumes over time. Despite some fluctuations intra-quarter, the average realized oil prices have been relatively stable over the last few quarters, and the average realized price for liquids for the second quarter were just shy of $80 per barrel. Market prices for gas have also been relatively stable in recent quarter-on-quarter averages. However, OKEA's realized prices have benefited from hedging gains. This is also the case for this second quarter, where the realized price of natural gas of $65.7 includes a gain on fixed price contracts equivalent to $10.5 per barrel. The combination of volume sold and realized prices resulted in a total petroleum revenue of NOK 2,442 million. The graph to the left illustrates the OKEA liftings of crude over the last five quarters, as well as the average market prices, as marked by the red dots. The lower lifted volume in the quarter was mainly due to the underlift position, as described earlier. The graph to the right outlines the difference between the average market price of Brent for the quarter of $84.8 per barrel, compared to the average realized liquids price for OKEA of $79.7 per barrel. The NGL discount of $3.7 and the negative timing effect of $2.3 was partly offset by the positive non-price adjustments from prior periods and quality premium on the OKEA oil. On this graph, we illustrate the volumes of gas sold over the last five quarters, and the observable average market prices for NBP in the same period, as represented by the red dots. The recent increase in production from Hasselmus and Statfjord is partly offset this quarter by the planned maintenance as well as natural decline. So over to the profit and loss statement. We deliver operating income of NOK 2,584 million, consisting of the petroleum revenue of NOK 2,442 million, and other operating income of NOK 142 million. Other operating income mainly comprised tariff income at Gjøa and Statfjord of NOK 76 million, and a decrease in the fair value of the contingent considerations of NOK 60 million as a result of decreased forward prices for crude oil during the quarter. Production expenses amounted to NOK 689 million, or 229 kroner per barrel. The higher production expense per barrel was mainly due to high activity level on several assets, combined with somewhat lower production. As Svein mentioned, we recognize a net impairment of NOK 267 million in the quarter. A hundred and twenty-one million relates to impairment of technical goodwill of Statfjord, mainly due to risking of less mature projects. 144 million relates to the Yme asset, and is driven by reduced forward prices for crude oil. As a reminder, I will repeat that given that both Statfjord and Yme are carried at fair value, any adverse changes in macro conditions or asset performance will result in further impairments going forward. In the case of Yme, any potential positive adjustments will result in reversal of previous impairments. I can also repeat that the technical goodwill arises as an offset to deferred tax in a purchase price allocation. And rather than being depreciated as a fixed asset, technical goodwill is instead subject to impairment testing on a quarterly basis. As technical goodwill is not depreciated and Statfjord is carried at fair value, all else equal, further impairments of technical goodwill is expected as volumes are produced. Moving on to exploration and operating expense, amounted to NOK 243 million, and comprise SG&A expense of NOK 33 million, and exploration expense of NOK 210 million. The high exploration expense was due to expensing of NOK 168 million in previously capitalized cost on Calypso. Net financial expense amounted to NOK 23 million, and mainly relates to net expensed interest of NOK 33 million, and accretion on net removal obligations of NOK 34 million. This is partly offset by a net currency gain of NOK 49 million, following a somewhat strengthening of the kroner relative to the U.S. dollars. Tax expense amounted to NOK 526 million, which brings the net profit to NOK 87 million. The tax rate of 86% was higher than the expected 78%, mainly due to impairments of goodwill not being tax-deductible, as well as financial items being deductible at a lower tax rate. Moving on to the balance sheet. Goodwill amounted to NOK 1.9 billion, of which NOK 635 million relates to remaining technical goodwill at Statfjord. Cash and cash equivalents amounted to NOK 3.2 billion. The increase in cash was mainly due to the issuance of the OKEA zero five bond, and following the new bond, interest-bearing bond loans also increased to NOK 2.6 billion. Other interest-bearing liabilities of NOK 472 million relates to the financial lease of the Inspirer rig at the Yme field. Income tax payable of NOK 1.6 billion represents tax payable for the first half of 2024. Note that the asset retirement obligations of NOK 9.4 billion is partly offset by the asset retirement receivables from Shell, Equinor, and Wintershall DEA of NOK 4.2 billion. Cash generated from operations was just above NOK 2.1 billion. Taxes paid of NOK 1.4 billion relates to payment of the two last installments for 2023. The 882 million used in investment activities mainly relates to the investments in the Draugen Electrification Project and production drilling at Brage and in the Statfjord area. Net proceeds from the issuance of the OKEA zero five bond amounted to NOK 1.3 billion, and we end the quarter with a cash balance just shy of NOK 3.2 billion. Finally, some updates on guidance. Following end of the first half of the year, with operations as expected, we are now narrowing our production guidance somewhat by lifting the lower end from 35,000 to 36,000 barrels of oil equivalent per day, ending at the revised range of 36,000-40,000 barrels per day. We also narrow our CapEx guiding by lowering the high end from NOK 3.7 billion to NOK 3.6 billion, ending at the revised range of NOK 3.2 billion-NOK 3.6 billion. About one third of the CapEx relates to infill and production drilling at Statfjord and Brage, which has significantly shorter payback than the development projects. That's all from me for now, and I'll give the word back to Svein for some closing remarks. Thank you. Thank you, Birte. So Q2 then, in summary, we've seen continued strong production from our assets of 38.4 thousand barrels of oil equivalent per day. The Draugen field continues to deliver consistent production, and Hasselmus is adding volume to the asset, and we're also executing on the Power from Shore project, which is an enabler for Draugen to produce until 2040. We are seeing improved production efficiency on Statfjord. That is a long-term game, but we are working very closely with both Equinor and FLX and also with Worley in the license, to extend the lifetime, but also to increase the production efficiency from Statfjord, in addition to finding new resources. We did submit the PDO for Bestla, very important part of our strategy to develop the resources in the neighboring areas to our assets, and that will add 10,000 barrel of oil equivalents to Brage and to, well, to OKEA, net the portion to OKEA when it comes in production in 2027. We have strengthened our liquidity position by the issuance of the OKEA zero five bond. So with that, I think that is Q2 in a nutshell, and hope to see as many as possible of you in the Q&A session that will just start after this. Thank you very much. Thank you. We'll now start the Q&A session. If you wish to ask a question, please press five star on your telephone keypad. To withdraw your question, you may do so by pressing five star again. There'll be a brief pause while questions are being registered. The first question is from the line of Teodor Nilsen from SB1 Markets. Please go ahead. Your line will now be unmuted. Good morning, and thanks for taking my questions. Three questions from me. First, on the Draugen from Shore project, it looks like that is proceeding according to plan. But I just wonder if you could talk a little bit about the break-even power price or return on investment or something around profitability on that project. Second question is on Statfjord. So I know you mentioned that there's been some improvements there. I should interpret that we should expect higher production in the third quarter compared to second quarter this year. And my final question, that is around dividends. I'm fully aware you won't pay any dividends this year, but for 2025, I guess we should assume resumption of dividend payments. Then question is, on what basis will pay dividends? Will, will that be a percentage or income or cash flow or some other metric? Any kind of color on the 2025 dividends would be useful. Thanks. Yes, thank you, Theodor. Thank you for your questions. We've noted the three questions, and maybe I can take the first and the last, and Svein will answer the Statfjord question. So on the Draugen power from shore, I would say that that's quite a marginal project, but the real value in that is, of course, the ESG effects in and the increased robustness in the long-term potential of Draugen, as it will both increase gas export from the asset and reduce OpEx in the long term. You may also have noted that we have locked in the majority of the power usage expected in the first few years. So we don't guide on the break-even power price, but I think we have mitigated the risk of changes in power prices from locking in prices. And as for dividends, yeah, our capital allocation principles remain the same as before, which is healthy balance sheet, first and foremost, and then to balance direct distributions to shareholders and growth. And as you are aware, we are also subject to the restrictions under the bond terms of 50% of net profit after tax. So what I can say at this stage is that dividends remains a priority for OKEA, and the board intends to revert with a plan once we are in a position to resume dividend payments under these restrictions. Yeah, and when it comes to the Statfjord improvements, we've now had a very long shutdown or turnaround on Statfjord Alpha, but we have also seen positive results from, you know, the last wells that has been drilled. What we are doing on Statfjord then is we are not guiding on the production for the next quarter. That is, you know, as part of our overall guiding. But what we are working on in the asset is that we are maturing an updated plan, an updated drilling plan, based on updated drilling targets and also an updated draining strategy for the reservoir on the asset. That is something we will discuss the final terms on in August in the license, which will then be part of the approval processes and the budgeting as we go into Q3 and Q4. So I need to go back to that. But what is promising to see is that we are seeing increased production efficiency in the area, of Statfjord, and we are also seeing more positive results from the latest wells which has been drilled. So, so how this matures, we will need to get back to in the later quarters. Okay. Thank you. Thanks, Teodor. The next question will be from the line of Roald Hartvigsen from Clarkson Securities. Please go ahead. Your line will now be unmuted. Good morning, Birte, and good morning, Svein. Hope the Norwegian summer is treating you, treating you well, despite some rain. Unfortunately, we once again have to touch upon the impairment. So this is the seventh impairment on the Yme eight quarters, and it's the third impairment in a row on Statfjord. Obviously, different reasons for the different impairments between the different quarters, but this last one, you stated in a trading update last week that the impairment on Statfjord was due to a risking or change to risking of future projects. And I know there are limitations as to what you can and want to say publicly, but when you make such adjustments to risking of future projects on Statfjord, the market is clearly curious to know sort of what you see that make such adjustments appropriate. So any details you can give on that would be appreciated, and also if you could touch upon the remaining book values, pertaining to especially Yme, that would be appreciated. Thanks. Yes, thank you, Roald. Yes, we are again talking about impairments. Whereas we had the reversal of an impairment on Yme in the previous quarter, we have a new impairment this quarter. And that is solely due to changes in the forward prices for crude oil. As for Statfjord, it's a bit different. And as you know, Statfjord is a huge asset. It has a lot of potential that we are continuously working to realize, and the license partners are currently working through a lot of improvement initiatives that we believe will add value in the long run to the asset. And the adjustments that we have done in this quarter, it does not represent the change of the asset strategy, and we firmly still believe that we will be able to extract more value from Statfjord. But some of the plans include targeting less mature opportunities, which we have risked accordingly, and also then reducing the technical goodwill on remaining on the balance sheet. And I'd just like to emphasize that this does not imply that the value potential is lower than what we previously have assumed. So it's a more conservative view on the risking of the less mature profile, I would say. Thanks. The remaining book value on Yme. One second. We don't really disclose book values per asset, but yeah, so I don't think I should really comment on that, Roald. Okay. Thank you. That's it from my side today. Thanks. Thanks, Roald. As a reminder, if you have a question for the speakers, please press five star on your telephone keypad. There'll be a brief pause while questions are being registered. The next question will be from the line of Diogo Galler. Please go ahead, your line will now be unmuted. Hi. Hi, sorry, I have four questions for you. The first one is, looking at page 15 of your creditor presentation, when I look at your forward production profile, it looks like you're expecting your production to drop to roughly 30,000 barrels a day before the two new projects come online in 2037. And then to roughly go back to 35,000 barrels a day with those two new projects. My question is, is that correct? The second question is on Draugen. Besides the increase in the life of the asset and the ESG impact of the project, of electrification, my understanding is that you're also releasing natural gas that is currently used in the platform for export. Could you please indicate roughly what's the amount of barrel of oil equivalent per day that you're gonna be able to export because of releasing it? And my third question is on taxes. It seems that for 2024, your tax bill will, in terms of cash paid, be roughly NOK 3.5 billion. That's when I'm modeling your 2024 production and CapEx, I expect that tax bill to drop quite significantly into for 2025, roughly to, like, NOK 2 billion. Is that the case? Thank you very much. Thank you, Diogo. So let's try to answer each of them. So my understanding is that in the first question, you refer to the credit presentation from April, and you are correct that we provided an indicative forward-looking production there. But generally, we do not guide on the long-term production, so I would emphasize that it's indicative, and also it does not account for the work that we really do every day to arrest decline and to mature new volumes organically around our existing assets. As for the electrification question for Draugen, the additional gas export net to OKEA will be equivalent to about 500-600 barrels equivalent per day, net to OKEA. And for taxes, yes, it's more or less correct, the remaining tax for 2023. As you are correctly pointing out, and as we have guided also, the tax payments, estimated now for the next six months, is about half of what the previous installments were. So about NOK 349 million each installment, which is payable now in the second half of the year. Sorry to interrupt you, but would that... That answers. Thank you very much for those answers. That answers for 2024. But given your production guidance for the rest of the year, and also the really high CapEx that you're spending this year versus prior years, am I correct in assuming that the cash paid in 2025 will be much lower, around the kind of NOK 2-ish billion mark? Best estimate today is that each of the six installments will be NOK 349 million. So obviously, it depends on realized prices and, and other aspects, but, it will be significantly lower, our current estimate is significantly lower than what we paid in tax for 2023. Thank you so much. Thank you, Diogo. Thank you. As there are no more questions on the phone line, I will hand it back to the speakers. Thank you, and I see we have a question from Dag Henaug about when OKEA will be able to pay dividend again, and I think we already responded to that in the questions from Teodor. And I see that Diogo's questions are repeated here, so I will not state those again. And then Niklas Jonsson has a question about: There is a trend switching to renewable, no fossil energy sources. For how long do you think there will be an increased demand for the products of OKEA? Do you see increased tax or ban on oil as a potential risk? Yeah, I guess that is a quite, quite a big question. But, you know, looking on the energy mix out there, we are trending towards more renewables. But, you know, the demand also for non-renewables have not been higher than it is today. So the transition will happen, but it will actually take a long time, and I believe, especially our positioning as well on the Norwegian Continental Shelf as an energy provider to Europe, and you can also look on the long-term contracts, which has just been signed. I believe that is a very critical, you know, energy provider for, for the long time to come. So, so we continue to believe that oil and gas will be a very important part of that mix. We still believe Norway and the Norwegian continental shelf will have a very important role in it, but we are also working very hard to ensure that we are doing it as sustainable as possible with as little footprint as possible also, hence the reason for electrifying some of our operations on assets that will produce until 2040. Okay, and then we have two questions from Russell Searancke. Your planned exploration wells this year on Arkenstone and Mistral, what are your hopes for these wells? What are their locations and resource potential? And the second one is the new project of Ofelia, Gjøa North, and Cerisa, are you talking about the potential tie-in to Gjøa? Companies including Longboat and DNO have expressed frustration about the slow progress of these cluster developments. What makes you confident in your new project? Yeah, on the first question there, we are really excited about both the Arkenstone and the Mistral wells to be spotted later on this year. These are exploration wells. Arkenstone is further north, on the Norwegian Sea, while Mistral is more close to existing infrastructure, so they are two a little bit different. We need to get back to when it comes to the resource potential, but these are wells that will be drilled by the operator, Equinor, so we are really looking forward to take part in these two. And when it comes to the greater Gjøa area, Ophelia, Gjøa North, and Cerisa, we still believe that these are candidates for tying into to Gjøa. Gjøa has been an extremely good host for OKEA to be part of as well. So I think that Yo and the existing infrastructure on Yo is very suitable to actually produce these resources as well. When it comes to other comments on the progress on these developments, I will not comment on that. But we are really confident that when we are maturing more resources and are able also to look into joint developments, this will be an advantage for all involved parties that will drive exploration. No, development costs further down. So, we still believe, you know, these will be developed to Yo. Okay, so then we have a question from Sander Nielsen, or actually he has a few. How should we think about Brage production in the third quarter with a second Talisker well coming on stream? What is the expected gross flow rate of the new well, and how will it impact the existing production well? Second question is, do you have any planned maintenance for Q3 of significance? And can you elaborate on the rationale of expensing Calypso? What is the main driver here? And finally, you currently have a strong balance sheet, and M&A is rooted in your business model. Could we see another M&A coming this year? Yeah, I guess I can start on this one, and maybe Birte can jump in on question number 3. But the Brage production, what we should think about it, obviously, that it will increase. But we are not guiding well by well and how this is, this is part of the overall production guidance that OKEA is, is issuing. So, what is important for us is that we are continuing to mature resources into reserves and putting them into production on Brage. That is the success case for Brage and also the case that we're trying to replicate on the Statfjord area. So, so it will increase. When it comes to maintenance of Q3 for of significance, we do have some. Kårstø is shutting down for three weeks. So we do have some gas export that will cease during those three weeks to Kårstø, both for Brage and for Draugen, and also from Ivar Aasen, and all of these are scheduled for the third quarter. Those are the major maintenance activities that we have. When it comes to the expensing of the Calypso, Birte, maybe you can take it, and I'll jump in on the M&A afterwards. Yes, I can comment on that. So basically, we see now that with the volumes in Calypso alone, the project does not satisfy our investment criteria. However, there are work on nearby licenses that could mean that the project could become viable in the longer term as a joint development project. But as of what we have on the table right now, the project does not satisfy our investment criteria, and therefore, we do not have any current plans to continue developing Calypso, and hence we are expensing it. Yeah, and, when it comes to M&A, we can't be specific, obviously, when it comes to M&A, but inorganic growth is very important to us, and we are still maintaining our growth strategy as a company. We have chosen to be the leading mid to late life operator on the Norwegian continental shelf, and there will just be more of that segment on the Norwegian continental shelf, so that's why we have started on this journey. But again, it needs to fit our strategy, if we are doing any inorganic developments, and we need to ensure that we identify and can also unlock further value in these assets to ensure that they fit in our strategy, where we can actually do a better job than currently is being done on these assets. We are still focused on growth and M&A, and inorganic growth is an important part of it. Okay, then we have a question from Rune Grønnevik, who's asking: What will OKEA focus on to lower the OpEx cost in operated and non-operated assets in late life operations excellence? Yeah, well, I can mention that, and, obviously, the OpEx, sometimes you have to spend more OpEx to actually get more volumes out of the ground, but that is a more commercial, you know, solution, so it's a complex picture. But as we have said in the past with what we are trying to focus on as an operator, is that we are extremely focused on what are the value-adding activities in our value chain when it comes to operating these assets. But sometimes we have to spend that cash, obviously, but we then will call it investments. So, I don't have any single item on what we are focusing on. What is important for us is to drive the production efficiency up. We need to have a solid and good performing platform to produce the resource that we have. And then we need to focus on ensuring that we are only executing on the activities that actually leads to maintaining a reliable operations with high production efficiency. So, I think this is something we have achieved on the assets where we are operator now, and this is also experiences and learnings that we have, that we are also sharing openly with other operators where we are partner in the same segment of mid to late life assets. Okay, and then a question from a private investor: What about political risk on the NCS today? Is it stable? Do you see OKEA as a partner in development of future nuclear power? We do see that the NCS is a quite stable environment to be in compared to other continental shelves. In Norway as well, the oil and gas industry is a very important part of the nation's overall industry and income, so we believe that will continue. So we are not regarding the NCS to be any unstable environment as such. Development of future nuclear power is not part of the OKEA strategy as it is today. We are focusing on producing oil and gas as a company. That is what we are good at and that we will continue on. Okay, and then we have a question from David Mursell. What is the current outlook for Yme for the next 12 months? Are there plans for further drilling, brackets, exploration or development? Yeah, well, the outlook for Yme, as we mentioned in the presentation as well, is that we are completing a well now that will be put into production in Q3. And we are looking and trying to mature more infill targets in the better formation on Yme. So, maintaining high production efficiency and completing the well that we have already started on now, and maturing more wells to be matured in the Yme asset is the focus for the 12 months to come. Okay, and then we have another question from a private investor. Could you please highlight some of the major technological breakthroughs within oil production that will help OKEA and partners on Statfjord? Is it fluids, robots, tiebacks, et cetera? Well, I guess, what is generating value for an oil and gas company is what, what's in the ground. So any technological developments when it comes to seismic, when it comes to data interpretation, when it comes to big data processes, that is continuously improving. That is obviously a technology which is, you know, supporting, identifying more resources in the ground. And then thereafter, technology, which is supporting efficient drilling operations, is obviously also something which is very important as a technology. So I would say, data analysis, for identifying new resources, but also the drilling technology that can support, for example, geological steering or anything, is very important technologies. But mainly in the subsurface domain, I would say, is the most critical part. Okay. I think, Yeah A nswered all the questions. Yes U nless there are any new on the call. No, no, questions on the call. Okay, then that will conclude the Q2 presentation and Q&A from OKEA. Should there be any questions, obviously. Oh, we have one quick question from Diogo Galler on the phone. Please go ahead. Hi, sorry. Hi, sorry, just one more question. Regarding, I mean, you're spending quite a bit of money this year on the infills in Brage and Statfjord. I estimate from your guidance it's about NOK 1.1 billion-NOK 1.2 billion. Two quick questions. One is, could you please provide us a bit of a breakdown on how much in each of these fields? And then second, is this the level of expenditure, you know, in infill, that you think you're gonna have to keep carrying next year, or is this really just kind of very high 2024? Thank you. Yes, this varies a bit over time. I can say until, so far this year, about one third of those expenses relate to Brage and two thirds relate to Statfjord. There is expected to be a high activity level also going forward on both of these assets. We do not guide any longer than the current year, but both of these assets are depending on new volumes through further infill and production drilling. But as for guiding on a specific amount, we do not do beyond the current year. Thank you. If that was the last question, then thank you all for attending the presentation and also the Q&A session. So, wish you all a pleasant summer and, looking forward to see you all again on the other side. And if there should be any questions between the now and then, then, do not hesitate to contact us. We will be still available to answer any queries you may have. So thank you very much. Thank you.