Good morning, and welcome to the presentation of the third quarter results for OKEA. We are reporting today from Råket, which is the operation center in Kristiansund for Draugen, because we are celebrating the thirtieth anniversary for Draugen this week. Last week was actually the thirtieth anniversary for Draugen, and it was not only Draugen who actually passed that milestone over the last month, but also Brage had its thirtieth anniversary last month. Fun fact there is actually that Brage had the same production, or more production actually, on that thirtieth anniversary than they've had over the last 10 years. So with that, we are presenting then from Råket, as I said, but we are now gonna dive into the details for the quarter. With me this morning, I have Birte Norheim, our CFO, who will take you through the finance section, but I will give you an operations update just before that, and we will then have question and answers afterwards. There should also be a link on our webpage, which will give you access to questions or a link to where you can ask questions. The third quarter in a nutshell. Our production is gradually increasing. We had an excess of 23,700 barrels of oil equivalent production last month. Brage has continued to deliver above plan. We've had both Draugen, Gjøa, and Ivar Aasen, and Nova on plan, and we've had lower production from Yme during the last quarter. The reason for these details, I will go into when we are going through each asset in detail. On the portfolio, I'm very glad to announce that we have now started the Hasselmus gas tieback to Draugen. We have said now since we sanctioned the project on the 31st of May, two years ago, we have said we're gonna start production on the fourth quarter in 2023, and we actually started production on the first day of the fourth quarter of 2023, and achieving plateau production already on the 6th of October, so this is going rapidly ahead. Pure gas, 4,400 barrels of oil equivalent to Draugen, which then again converts Draugen to a gas export facility. We have proven oil in the Sognefjord East formation at Brage, that was previously known as Askja. And we have in-place volumes of between 6-7 million, and that was actually discovered through the longest exploration well in Norway this year, which is 9,050 meters. So it was quite a quite an achievement, so we are now doing the analysis of how can we get these resources into reserves and produce it over Brage. Plus, as well, we passed DG2 during the last quarter actually in August, and OKEA took over as operator from the first of September, as we are then maturing that project further to hopefully take a successful investment decision in Q1 next year. On the financial side, we had a very strong EBITDA during the quarter of in excess of NOK 1.3 billion. Impairment was taken last quarter of NOK 475 million, which is then reducing the net profit after tax by NOK 104 million and takes the net profit after tax to NOK 32 million in total. We did a refinancing of the company, and that was successfully executed early in the quarter. That is then extending the maturity of our outstanding bond debt and is adding new liquidity source through the RCF of $25 million. This is also a new entry then into the bank market for OKEA. We are net cash positive. That is obviously an enabler for the settlement of the Statfjord deal during Q4. We did execute on the dividend payment in September, and we are also gonna pay the dividend of 1 NOK per share in December, as per our dividend plan for 2023. High-level production, serious incident frequency, as you can see, that is stable. That is the, you know, foundation of what we are doing, that we need to have safe operations, so I'm glad to see that we are maintaining that, and that is obviously a rolling average, so it will drop as we are not having more incidents. CO2 intensity, which is an annualized figure, still on 23 kg per BOE produced. Production, as I just mentioned, in above, in excess of 23,700, which is an increase from previous quarter. Production expense, we are glad to see that that is dropping from above 200 to below 200 NOK per BOE this quarter, which is somewhat related to more production volumes, but also reduced cost. The net cash flow from operations is NOK 748 million, mainly affected that we did a late lifting on Draugen during the quarter, which was good in relation to timing of the oil price, but the actual settlement for that lifting and that cargo will then happen in Q4. As I just mentioned, we executed on the dividend plan as we have said in the past. Production. As you can see here, we are gradually increasing production during the year. This is from our own assets. We have much more diversity in our portfolio now than we used to have in the past, so we are not so sensitive to operational upsets. So quite evenly distributed the production over the quarter. And as you can see here on the production reliability as well, very high reliability on our assets. Some upsets has happened. You can see on Draugen in particular, we have dropped from 94 to 88, and that was because we did a subsea pump changeout, which then ended up in July with 13 days of shutdown. Brage, very high uptime, which is, you know, we are glad to see. Gjøa had slightly lower uptime compared to previous quarter, which is mainly related to a planned shutdown, but also some issues with a shutdown in the St. St. Fergus reception terminal, where they are exporting gas. Ivar Aasen, very high uptime, and Yme had very high uptime in the last quarter, somewhat lower this quarter because of a seal on an export compressor that that started leaking in July that they had to fix.... and Nova is, you know, a tieback to Gjøa, so that very much relates to the performance of Gjøa. So again, the most important thing here, though, is the diversification of our portfolio as we have mentioned in the past. We are gradually increasing production, and these volumes are obviously not including the volumes which will be part of the Statfjord transaction, which will be closed in Q4. Quick operational update on our assets. Draugen, I just mentioned the Hasselmus production started on the 1st of October. A very quick bean up of that gas producer. So we are actually producing at the plateau production as we speak. We did have the 13 days of shutdown in July to install the new subsea pumps. You know, the water depth on Draugen is actually in excess of 250 meters, so we have subsea pumps that will aid with the lifting of the oil and water to the installation. And we also drilled 2 observation wells in July with Transocean. So evaluation of those observation wells is ongoing. We did see oil columns in both of those wells, and we are now assessing how those as well can be tied into Draugen for the future. Second operated platform, which is Brage, we add more wells on Brage. The success case on Brage is to continuously drill new wells, which we have done since we started. That's also the reason why the production of Brage has increased from 7,000 gross barrels per day to above 18,000-19,000, as we are seeing now. So we've had good success with that, and we have a net plateau production now of 6,000 barrels of oil equivalent to OKEA. So Brage is really delivering. We are putting more wells in Q4, more wells on stream in Q4 2023 on Brage. Brasse, we passed that DG2 on that Brage project. As we have said in the past, 30 million barrels of oil equivalent, which is 13 kilometers away from Brage, which we are working very hard with the other partners to mature to a financial to an investment decision next year. So we hopefully then can produce that over Brage. You are still a very good asset for for OKEA. Somewhat lower production in the quarter due to the scheduled shutdown, and also, as I mentioned, the St. Fergus issues that they had to reduce production on. Hamlet discovery is a tieback and a discovery that was done last year, and that is a potential tieback to Gjøa, and that is being matured and looked at now in relationship with other targets in the same area. How can we then maybe have an area development of these discoveries? Ivar Aasen, very good availability and production during the quarter. There are two wells which is planned to be converted into injectors. Ivar Aasen as well is maturing as an asset, so if there is more use of these wells as injectors rather than producers, that is something we are doing for the drainage strategy. And we are also then planning for the infill oil or increased oil recovery program, with more wells to be drilled from 2026. The Yme field, there was a reduction in the production in July, as I mentioned, due to this compressor seal. But the most notable thing with Yme during this quarter is that we have reduced our net reserves on Yme by 1.8 million barrels of oil, which is based on the data from new wells. We are doing decline analysis on these new wells, where we are looking at water cut, pressure, and how actually we are balancing the reservoir and the drainage strategy, and are using that to update our data and our modeling. So we then took a decision and based on these assessments and these, analysis to reduce our net reserves, on Yme. And we are also expecting then a plateau production to be 3,500 barrels of oil equivalents per day when we are at plateau. But there are still more wells to be drilled on Yme, so we have one injector, which is now planned for Q4 in 2023, and one producer, which is planned for early 2024. Then we have the full, planned well stock available for Yme, and then we will, together with the other partners in the license, see if there is other infill potential as well in the same area. But that's when we have the full picture of, of Yme. The Nova, which is a tieback to, to Gjøa. We have improved production during the quarter, because we have drilled, a water injector, to support the, the pressure on the reservoir and also to increase the drainage strategy. And we have also secured in the partnership, a rig for, for the fourth quarter or the second half of 2024, to drill the fourth water injector to actually again get more pressure support from the aquifer to increase production again from Nova. So with that, I will stop the operational update and my part... Well, I have one more slide. I have a Statfjord slide, which is being closed now in Q4. Again, this is a very significant transaction for OKEA. It will increase production for OKEA significantly. Statfjord has been and will still be a giant on the Norwegian continental shelf, where we can increase, increase recovery rate, and that will actually boost production even more. We are protected from any decommissioning until 2038 on this field, and we are working very closely already, as an integrated part of, of the Statfjord asset. Although we are not a partner yet, but we are working very closely within the license to see how can we mature, Statfjord going further. We are expecting a close of the contract or the SPA agreement on the thirtieth of November in 2023. But obviously, the effective date for the transaction will be first of January 2023. We have guided production on Statfjord from between 11,000 to 13,000 earlier this year. We have adjusted that to now be between 11,000 and 12,000. So we have taken down the upside, but we are maintaining the floor. So that is an adjustment we have made based on the 2023 numbers. There is also an updated RNB from the operator, which has been submitted, which indicates a reduction of around 3,000 barrels of oil from next year. So we are now working together with the operator and also Vår Energi to assess the data to give more details into the 2024 guiding and the impact that this will have. And we will then update the market on our 2024 guiding when we are presenting the Q4 2023 results in February next year. And we are working closely in the asset and in the license as well. How can we mitigate the impact of this reduction? How can we drill wells more effectively? How can we put them into production more effectively? And how can we actually increase the draining of the reservoir and start flow? So that is work ongoing. And with that, I will hand over to Birte, who will take you through the financials. I'll come back for a quick summary before we then dive into the Q&A session. Thank you. Thank you, Svein. The third quarter was characterized by an overall stable production, which also drives our unit production cost down. It was also characterized by a significant increase in crude prices, which had a positive impact on revenues, but also resulted in some unrealized losses in relation to hedging and contingent payments, which increases the effective tax rate. As Svein has already mentioned, we also recognize another impairment on the Yme asset, which is a non-cash item, but has a significant impact on our net profit after tax for the quarter. We were very pleased to have completed a successful refinancing, which extends the maturity of our outstanding bond debt, and I will revert to further details on all of these matters and more, starting with our production and sales. We produced 23.7 thousand barrels of oil equivalents per day in the quarter, which is an increase of 6% compared to the previous quarter. Draugen, Gjøa, Ivar Aasen, and Nova all produced according to plan. Production from Yme was impacted by technical issues in July. The Talisker East well at Brage continues to perform well and has sustained production above plan. We sold 26.7 thousand barrels of oil equivalents per day, and the increase compared to previous quarter was mainly due to crude liftings on both Brage and Nova, as well as higher gas volumes sold at Brage. Partly offsetting this was no crude liftings from Gjøa in the current quarter. Market prices for gas were relatively stable during the quarter. However, we do not have a repeat of the high hedging gain on physical gas contracts as previous quarter, when the hedging gain resulted in an increase in realized prices of more than $23 per barrel equivalent. The current quarter effect is an increase of less than one dollars per barrel in increase. The resulting average realized price for natural gas for third quarter amounted to $61.9 per barrel compared to the oil equivalent pricing. Oil prices fluctuated quite a bit during the quarter, and starting just above $75 per barrel and steadily moving upwards, touching nearly $100 at the end of the quarter. The average realized price for liquids amounted to $89 per barrel, and overall, this resulted in a total petroleum revenue of NOK 2,131 million. The graph to the left illustrates the Aker allocated liftings of crude over the last 5 quarters, marked by the light blue bars, as well as the market price, which is marked by the yellow line. Aker had 8 cargoes of crude lifted in third quarter. Four cargoes for a total of 201,000 barrels were lifted from Yme, and in August, we had 338,000 barrels from Ivar Aasen, and in September, we had 636,000 barrels from Draugen and 209,000 barrels from Nova being lifted. We also illustrate the completed and planned cargoes for the fourth quarter, marked in dark blue and in gray, respectively. Lifting of 78,000 barrels from Yme has already taken place in October. We also expect 330,000 barrels from Brage in October, and in addition, we expect a lifting of 615,000 barrels from Draugen and three liftings from Yme for a total of 144,000 barrels in November. In December, we expect a lifting of 374,000 barrels from Brage and a lifting of 66,000 barrels from Yme. The graph to the right outlines the difference between the average market price for Brent for the quarter of $86.7 per barrel, compared to the average realized liquids price for OKEA of $89 per barrel. The key driver for the positive differential relates to the timing of crude liftings, and particularly since the liftings from both Draugen and Nova took place at the end of September, when prices were peaking and towards the higher end, compared to the average. Following a period of extreme volatility in gas prices over the last year or so, prices were relatively stable during the quarter. On this graph, we illustrate the average volumes of gas sold per month since July last year and the observable average market prices for NBP in the same period. The increase in volumes of gas sold in the third quarter was due to higher gas production at Brage. So let's move to the profit and loss statement.... Petroleum revenue from sales of petroleum revenue was NOK 2,131 million, and total operating income was NOK 2,105 million. The differential is other operating loss of NOK 26 million. The operating loss was mainly a result of increased forward prices for crude, which resulted in an unrealized cost of NOK 39 million related to the estimated value of the contingent consideration to Wintershall Dea, and a net loss on financial hedging. These effects were partly offset by NOK 26 million in tariff income at Gjøa, and income from joint utilization of logistical resources of NOK 9 million. Production expenses amounted to NOK 465 million, or NOK 195 per barrel. Production expense was down by 28 NOK per barrel compared to previous quarter, due to the increase in produced volumes, combined with lower expenses following completion of the turnaround at Draugen in the previous quarter. We recognize an impairment of NOK 475 million related to the Yme asset, following the downward revision of reserves, which is in part offset by an increase in forward prices for oil. And we'd like to remind you again that as the Yme asset, in effect, is recognized at fair value, it means that any changes in macro conditions or in asset performance will result in further impairments, or alternatively, in full or partial reversal of previous impairments going forward. As such, there is a potential for some volatility to the profit and loss statement relating to the Yme asset in particular. Exploration and operating expenses amounted to NOK 80 million, and comprise SG&A expenses of NOK 46 million, and exploration expenses of NOK 34 million, mainly relating to various field evaluation activities and further development of the Brasse discovery. Net financial income amounted to NOK 24 million, and mainly relates to a net currency gain of NOK 49 million, as well as interest income of NOK 29 million. Net interest expense and fees of NOK 14 million relates to interest on the bonds, as well as the Yme bareboat charter. In relation to the refinancing executed in the quarter, the call premium of NOK 28 million for OKEA-03 were expensed. Tax expenses amounted to NOK 428 million, which brings the net profit to NOK 32 million, and the high tax rate of 93% was mainly due to the change in fair value of the contingent consideration to Wintershall Dea, as it is recognized on a post-tax basis. Moving on to the balance sheet. Cash and cash equivalents amounted to NOK 2.346 billion. Tax payable was NOK 1.748 billion, and it relates to accrued tax for 2023. Interest-bearing bond loans was NOK 1.3 billion, and comprised the OKEA-04 bond of $125 million. Other interest-bearing liabilities of NOK 511 million relates to OKEA's share of the future obligations under the bareboat charter of the Inspirer rig at the Yme field. Asset retirement obligations ended this quarter at NOK 5.6 billion, and this liability is partly offset by asset retirement receivables from Shell and Wintershall Dea of NOK 3.4 billion. Cash generation from operations were just above NOK 1 billion in the quarter. This is lower than the sales income should indicate, mainly due to the receivables from nearly 850,000 barrels lifted, from Draugen and Nova in September, being received in October. Taxes paid of NOK 276 million relates to the first tax installment paid for 2023. Cash used in investment activities amounted to NOK 534 million, and mainly relates to investments in Hasselmus, power from shore, modification work at Draugen, as well as the Brage infill drilling. Interest paid of NOK 42 million relates to the interest on the OKEA-03 bond, which was paid upon execution of the call in September, and also an element, the interest element on the bareboat charter. We paid 1 NOK per share in dividend in September, which amounts to a total of NOK 104 million, and the cash balance at quarter end was in excess of NOK 2.3 billion, and more than 1 billion NOK above the outstanding bond debt. Cash balance for the so far this year, steady performance and high sold volumes have resulted in cash generation from operating activities of as much as NOK 4.2 billion. Taxes paid of NOK 776 million relates to the last three installments of tax paid for 2022, as well as the first tax paid for 2023, and we expect a tax refund for 2022 of NOK 75 million in the fourth quarter. Cash used in investment activities amounted to NOK 1.5 billion for the first three quarters, and mainly relates to, again, investments in Hasselmus, power from shore, modification work at Draugen, and Brage drilling. Cash paid in business combination of NOK 297 million relates to the $25 million deposit paid to Equinor in relation to the Statfjord transaction of NOK 263 million kroner equivalent, and 34 million paid to the Wintershall Dea in the final pro rata contra settlement, as well as contingent consideration. In total, we generate cash equivalent to about 15 NOK per share in the first three quarters of the year, and dividend of 3 NOK per share amounts to a total dividend payment of 312 million NOK in the period. As Svein mentioned, in September, we completed a successful refinancing, which extended maturity of the outstanding bond debt to 2026. In addition, we have, for the first time, accessed the bank market in the form of a $25 million revolving credit facility. We issued a $125 million bond, which we refer to as the OKEA 04 bond, with a fixed interest of 9.125%, and it matures in September of 2026. I must say that we were very pleased to note a strong investor demand and a book that was oversubscribed more than two times at final pricing. Upon issuing the new bond, we called the OKEA 03 bond with original maturity in December of 2024 at a premium of 3.2%. The new financing structure is robust, with low leverage, and there is substantial additional debt capacity to fund potential additional future growth. The revolving credit facility provides for additional financial flexibility at a relatively low cost. In total, we paid dividends of NOK 2.90 per share in 2022. When we started the current year, we communicated an intention to pay NOK 4 per share in 2023. 3 NOK per share were paid in the first three quarters, and the board has now resolved to pay 1 NOK per share in December, in accordance with the stated plan. As for the dividend plan for 2024, as mentioned, we will revert to this in relation to the financial reporting for fourth quarter. With one quarter of the year remaining, we have narrowed our guiding interval for the year, and according to plan, production has ramped up in the third quarter, with the new wells coming on stream. Production guiding has therefore been narrowed from 22,000-25,000 barrels to 23,000-24,000 barrels of oil equivalents per day. CapEx guiding has also been narrowed from NOK 1.7 billion-NOK 2.1 billion, to a range of NOK 1.95 billion-NOK 2.1 billion. None of the guidance includes the effect from the Statfjord transaction, and as Svein has already mentioned, we expect production from Statfjord for the current year to be in the range of 11-12,000 barrels of oil equivalents per day, net to OKEA. So that's all from me for now, and I'll give the word back to you, Svein, for some closing remarks. Thank you. In summary then, for the quarter, OKEA is continuing to deliver on the growth strategy. We are closing the Statfjord acquisition in Q4 this year in November, which will add significant production volumes to OKEA. We have executed and delivered the Hasselmus tieback project to Draugen, as we have said we would do, and start the production from Hasselmus in Q4, the first day of Q4, which is now producing 4,400 barrels of oil equivalent in pure gas to Draugen, which has then enabled both the gas export and also NGL export from Draugen. Brage, the business case on Brage, was always identified to be drill more wells and put them in production. We have delivered on that strategy for Brage, and we have had a very good quarter from Brage, which is still sustainable. Draugen, Ivar Aasen, and Nova is also producing according to plan. We have done a successful refinancing during the quarter, which has given us more financial flexibility and robustness, and we are net cash positive, and we are delivering on the 2023 dividend plan, as we have said. So with that, I hope that you will join us for the Q&A session that will be, where I will be joined by Birte again. So, with that, I will thank you very much for your attendance in this, presentation, and I hope to hear from you in the Q&A session. Thank you. ... And half of the remaining payments to be settled through the netting of cash flow from production up until closing. And is there any reason to expect that the 3,000 barrel impact is purely related to 2024? Thank you. ... I apologize, but the line was a bit poor here. So, let's start with a few of your questions, and please repeat if we're not addressing all of your questions. But I can definitely confirm that we've had bacalao for lunch and dinner over the last couple of days. Always great. You asked about the target production of above 40 for 2024, and until we have full clarification in our expectations. So now we refer to what the operator has done in their 2 Revised National Budget reporting, which is a reduction of 3,000 barrels per day on average for next year, until we get full clarification in our view and and what is all issues driving this. But I do expect that we will end up in that area, around 40-ish, based on what we know today. And do you want to say something about the reserves versus, like, future beyond production of stuff beyond 2024 slide? Yeah, I can, I can do that, and that is also a bit early. You know, the evaluation of the effects of... It's quite technical, the reason why we have reduced the average production for next year from Statfjord, it is related to depressurization of the reservoir and Statfjord, and also the gas then liberated, which will be less and therefore, also less production. So that work is still ongoing, so we do not expect that there will be any impact on it, but obviously that work is still ongoing, but we have not made any assessments or analysis which supports that we should change that number. I do think you had a couple of more questions that we haven't addressed. Could I ask you to please repeat? Sure thing. Glad that you had the bacalao for lunch. The last question was on Yme. Can you share the remaining book value of Yme following the impairment? And would you say it's fair to assume that you impaired more than half of the book value this quarter? You mean in accumulated terms, I assume. We do not disclose book values on each asset, but in broad aspects, in accumulated terms, we have impaired around half of the book value or so. What we do always try to remind of is that when we do carry an asset, that fair value, any changes in macros or in asset performance or reserves will result in impairments or reversal of impairments going forward. But what we have accounted for in the third quarter financial statements is our best estimate as of today. All right. Thank you. I was referring to your comment in Q2 when you said that there was less than 1 billion NOK remaining book value at Yme, and then with the 475 million NOK this quarter, I assume it you have impaired more than half of what you had at Q2. Okay, I understand, but, the book values is on a post-tax basis. All right. Fair enough. All right. Thank you. Thank you, Vidar. The next question will be from the line of Roald Hartviksen from Clarkson Securities. Please go ahead. Your line is now unmuted. Good morning, and thank you for taking my questions. We saw you took a very open-optimistic view on gas hedging last year in the wake of the Ukraine-Russia war, when gas prices spiked. Now, in late September and early October, we've seen quite attractive levels on oil prices. Should we expect you to take a more active approach to hedging also oil going forward? And if yes, should we expect that to be mainly in terms of colors, where you also write call options, or would that be also in a degree of solid put options or other ways of hedging? Thanks. Thank you. I think it's a, it's a fair question. And as we have stated earlier this year, towards the closing of Statfjord and beyond, when we have, you know, significant overhang of tax liabilities that is to be settled in the first half of next year, we are undertaking a more conservative approach to hedging than what we normally do, or that what we have done in the past, I should say. And I think you will - we are assessing a combination of all of these factors, so I think it's unlikely that we will look in, for example, all of the upsides, but that we are focused on securing the downside, and at the same time trying to manage the premium. I think the answer is that you will see a combination of those instruments that you're referring to. Okay. Thank you. Thank you, Roald. As there are no more questions in this call, I will hand it over to the speakers for any written questions online. Thank you. First, two questions from a private investor. The first one, a lot has happened since OKEA announced their first dividend plan. For the next dividend plan, which will be presented next year, I assume OKEA are aiming for increasing dividends in 2024. Second question is, could you please elaborate a little bit about why investors should invest in OKEA instead of other operators on the NCS? Okay, thank you for the questions. Yes, you are correct that a lot has happened since we announced our first dividend plan, and I think until we communicate the dividend plan for 2024, I'd rather not comment on whether we're expecting to see an increase or not. But I can refer to our capital allocation principles, that the key target is to the base target is to maintain a solid balance sheet, and thereafter, to balance growth with direct distributions to shareholders. But, I guess stay tuned until the fourth quarter reporting in February, where more information will be given. Yeah, I can take question number two, which is, could you please elaborate a bit about why investors should invest in OKEA instead of other operators on the NCS? That's a good questions, but I should, you know, refrain from advising investors where to put their money. But what I can say, though, is I believe that OKEA has a very clear strategy. I believe that the strategy is so clear that investors at least know what they are putting the money in. And when it comes to valuation and when it comes to our portfolio and also an objective view of that, I would recommend to read the analyst reports, which is quite thorough out there. Thanks. Next question is from another private investor. What will be your expected all-in break-even cost once Statfjord is incorporated, and what was the quarterly investments for the quarter? Okay, I can take that. So the quarterly investments in the existing OKEA portfolio was just in excess of NOK 500 million, and mainly relates to Hasselmus, which, you know, has started operations now on the first of October, as well as the Brage infill drilling. So NOK 515 million, if I, if I recall correctly, was the total CapEx in the quarter. All-in break-even cost, yeah, as you have seen in our financial statements for this quarter, our OpEx per barrel has come down now that volumes is on the increase. And as you have also seen over the last few quarters, the cost also depends on what maintenance turnarounds is taking place. But on average, I would expect that our cost for our existing portfolio is roughly $20 a barrel. When we launched the Statfjord transaction, we also communicated in the same region for Statfjord. We do not guide on the all-in, but the information I now provide is for, was for the OpEx. All-in depends on, given our portfolio, the number of projects that we are undertaking and where they are in the phasing, could have a significant variation between quarters and as well as years. Next question is from Lars Heltne in Energi Watch. How do you see oil and gas prices developing into the new year? Again, another question which is very hard to predict. But obviously, our strategy and what we announced previously as well was that we believe in a strong market. We believe that oil and gas is in strong demand for Europe because they need the energy that we actually can provide. But obviously, it's quite fragile, the macro picture out there. So, but again, we believe that we will see strong demand, but obviously, we have always been a cyclical business and will always be a cyclical business, so we are also prepared for fluctuations in the oil price. But for the short term, we do believe that there is strong demand for our product, which will then dictate the prices wherever they will land. Next question, on the web is, from Daniel Stenslet in Arctic Securities. Can you elaborate on what drives the reduction in next year's Statfjord production? Do you see any risk to existing Statfjord reserves, or is this just delayed production? Well, I can answer that one. And, to take the last one first, we believe, that it will not, have any impact on reserves, but that analysis is obviously already going. When it comes to technical, why this is actually happening, there is a mix, obviously, of both oil and gas, being produced from Statfjord. The draining, drainage strategy on the reservoirs in Statfjord is that you are producing water, which will then decrease the pressure on the reservoir. The decreased pressure will then liberate more gas from the oil phase, therefore, you will have increased gas production. We've had issues on, to produce, that water, therefore, we have not had the depressurization as planned when the original forecast was. So that is the kind of the technical reason why we are seeing the reduced production. Other things is that, it has taken longer time than anticipated to get the wells into production on Statfjord, compared to what was planned for. There's a very ambitious plan for drilling more wells on Statfjord, and the whole strategy to drain the massive Statfjord reservoir is to get more wells online, and that has taken longer time to drill. And it all has also taken a bit longer time to, you know, take them into production once they are completed drilling. So, so it's a bit of a complex picture, but as I said, we are together with both the operator, Equinor, and also Vår Energi, reviewing that analysis now. So, so we'll get back to that when we get back to the guiding. Yeah. Next question is from Tom Erik Kristiansen in Pareto Securities. Also on Statfjord, can you provide additional details on the issues at Statfjord? Is this likely a temporary production issue, or should we expect reserves to be lowered? I think we answered that in the previous- Yeah ... question. The next question is from Ola Eikanger in SEB. In terms of capital allocation, how would you prioritize inorganic growth versus an increase in dividends? ... Yeah, it's also a good question, and I'm afraid, possibly a boring answer, but it, it is a, it's a balancing act, and it depends on, what kind of value accretive investments, we, see ahead. So we'd, we would not consider, staying, overly, capitalized, if we don't see any value accretive way to put those, that capital into work. Can you take back the question, please? Yeah. Yeah, so it's a balancing act, but the fact that we are investing in production, the majority of our investments has been in production. And with payback in about a year or less than a year for the biggest investments that we have undertaken over the last couple of years. That could be a temporary impact on dividends, but as dividend capacity is one of the key criteria we assess when we look into potential investments, that should come then in the form of increased dividends in the medium to long term. Next question is from Paul Dallin, SpareBank 1 Markets. "Can you please update on your growth outlook plans for company development and the factors impacting your likely success? Well, I can answer that one. Our growth outlook, we are obviously continuously looking for inorganic growth. But as we have said before, we want to grow. We want to grow where we can see we can add value, but we also want to demonstrate capital discipline as we are doing so. But obviously, we have taken this company now from 16,000 barrels of oil per day to close to 40,000, you know, next year. And therefore, we still believe that that is the right thing to do for the company. We have also demonstrated we can turn assets around, so that is something we want to do more of, but it needs to be something that fits our strategy and something that we regard as has a value potential. Like, for example, on Brage, which had 6-7,000 in production per day when we took over, and which is now hovering around 18-19,000 barrels per day. But we're also, you know, doing organic growth. We just started Hasselmus with 4,400 barrels of oil equivalents per day into Draugen on the first of October, so we must not forget the organic path either. We also announced, as you may have seen, the discovery of 6-12 million in place barrels of oil in the area around Brage. Then we are also evaluating how we can put into Brage and obviously also developing the Brasse from DG 2 to hopefully a robust financial or investment decision in Q1 next year. So we are doing both inorganic but also organic growth, and I believe, you know, for the last two years, we have demonstrated that we are able actually to grow, and also put actions behind our strategy. So that is something that continues. Then we have two questions from David Mirzai in SP Angel. "Can you give any further detail on the new asset and the reasons for the underperformance? Is there any upset to the field life?" Second question: "How does the board balance the competing capital allocation aims of reinvestment and shareholder returns? Yeah, I can do the first one on the Yme. The update on Yme is that we are still drilling more wells. The decline analysis that we have done, which resulted in the impairment, that is, you know, based on the results we have seen so far on the new wells drill, but also the performance of the existing wells that we have seen. We are working with the other partners now in the Yme license to evaluate our assessment, our analysis, to see, you know, what are the long-term implications of this. And there's no update to the field life as such. Our job is to ensure that we are producing, you know, commercially as long as possible on Yme, and you know, drilling of new wells to get more potential is still ongoing. As for the second question, I think we already responded to that- Yeah -when, for Ola Eikanger's question. Yeah. Then we have a new question from a private investor. What do you think of the future for exploration in the Barents Sea? Do you think OKEA's strategy can change in the future? Well, everything can change in the future. But our strategy when it comes to the Barents Sea is that that is not the in the core of what we are trying to focus on. That is also the reason we want to be very specific and very clear on our strategy, that we are mid to late life asset operator and want to be best in that one. Therefore, exploration in the Barents Sea falls outside of that strategy. So that is not on our list. But you know, depends on you know, in the future, nobody knows what will happen in the future, but that is not part of our core strategy currently, so we are not going there. Yeah. Another follow-up question: Are you experiencing increased interest from investors to know more about OKEA lately? Yeah, I would say yes to that. I was just looking at how our, the number of investors have increased since we launched our revised strategy back in October of 2021, and at the time, we were about- we had about 3,000 investors. As of today, we are nearing 6,000 investors, so nearly doubling. We also saw, as I mentioned, in the refinancing-... significant interest from all regions, all expected regions of the world, I should say. Asia, U.S., Europe, mainland Europe, U.K., as well as, as U.S. and, and the Nordics. So, actually nearly 2.5 times oversubscribed at final pricing. So I would say that we are experiencing increased investor interest, which I guess also makes sense that, when we are growing and becoming our market cap has increased. Yeah, we are seeing an increased interest. And a new question from Ola Eikanger. Follow on the capital allocation question. When you say you won't stay overly capitalized, what sort of liquidity metrics and levels are important to OKEA in defining where you think of yourselves as overly capitalized? It's a fair, fair follow-up question. And again, I'm afraid it's a boring question, Ola, but it depends on where we are at in our investment cycles, what kind of opportu... So I guess the better way to say it is that if we are confident in our liquidity position, if based on the certain stress testing on pricing developments and such, and we don't see potential- ... Okay. So I see Siri has some opinion on this, too. And if we don't have investment objects that we consider a value accretive to put the capital into work, then that is a balancing point, I would say. That was all questions online. I hand it back to the moderator to see if there are any new questions online. We don't have anyone queued in the call, so I'll hand it straight back to you. Okay. Thank you very much. Thank you very much for attending the presentation as well, and also for following OKEA. We really appreciate it. So, you know, the biggest milestones now coming up for us is to complete the transaction with Statfjord, and then I'm looking forward to speak to you again as we are presenting Q4 in February next year at latest. Thank you.