Good morning, and welcome to Aker BP's first quarter 2021 presentation. My name is Kjetil Bakken, and I'm heading investor relations in Aker BP. Speakers today are CEO, Karl Johnny Hersvik, and CFO, David Torvik Tønne. When they have delivered their prepared remarks, we will have a Q&A session. If you have further questions or queries about the first quarter report or about Aker BP in general, the IR team is always at your service. I assume that you're all familiar with our standard disclaimer, so now let's get started. Karl, I leave the floor to you. Thank you, David. That was a promotion. Thank you, Kjetil. A very good morning to all of you who are following us on web or on the phone. First quarter of 2021 was a quarter that, in my mind, once again demonstrate the core quality, at least some of the core qualities of this company. We maintained a high production level from the previous quarters, and we delivered this with high safety, low cost, and a low CO2 footprint. Our field development project progressed according to schedule despite some workforce challenges due to COVID restrictions. We have now successfully completed the plugin campaign at Valhall in an excellent way, both faster and cheaper than originally expected. We are working hard to mature our portfolio of upcoming field developments within the deadline set by the temporary tax system. In the coming few months, we will take a final investment decision for Froskelår and Kobra East & Gekko in the Alvheim area, and others will follow. We are also on track for the concept select for NOAKA project in Q3. Strong operational performance also translates into strong financial performance. Helped by oil recovery or price recovery in the quarter, we delivered a new record cash flow this quarter. When it comes to things that are within our control, our financial guidance for 2021 remain unchanged. The key message is that we are following our plan. Now, let's start by reviewing the main performance indicators for the quarter as we usually do. On the production side, we ended up with a production of 222,000 barrel of oil, which is basically unchanged since Q4. Behind these number, there are, of course, some pluses and minuses. We saw increased volumes from several fields, while other fields have not delivered this quarter. At Johan Sverdrup, we saw a positive effect of the capacity increase announced in December. At Ivar Aasen, the startup of two new wells contributed positively, and at Skarv, production also increased driven by Ærfugl, even though we had one week of unplanned downtime due to technical issues with the fire water lifting system during the quarter. At Alvheim, on the other hand, production was lower in Q1. This was partly due to natural decline, but also impacted by a shut-in well at Froskelår pending well intervention. The Skarv shutdown was the main reason for the drop in overall production efficiency in the quarter, but we maintain our goal for the entire 2021. In Q2, we expect lower production due to planned maintenance shutdowns and our full-year production guidance of 210,000-220,000 barrels of oil equivalents remain unchanged. Let me also briefly comment on the financial performance. In Q1, we delivered the strongest cash flow ever for a quarter in Aker BP history. This was, of course, helped by high volume and increased oil and gas prices, but it's also supported by strong and continued cost control. Production costs ended up at $8.60 per barrel produced in line with our guidance range. The capital spend was only around NOK 400 million, which might look low compared to our full-year guidance of NOK 2.2 billion-NOK 2.3 billion. The simple reason is that the phasing of the different activities throughout the year, and thus, our guidance remain unchanged for 2021. On the HSE side, we continued our strong performance in Q1. Our safety record has improved significantly over the last year, particularly related to total recordable injury frequency. It compares very favorably to the rest of the industry. We had two recordable injuries in the quarter, and while none of them was classified as serious, we are still some way to go until we are at our goal of zero incidents. When it comes to CO2 emissions, we ended up just above 4 kg per barrel. This is less than 1/3 of the industry average and represents an important quality parameter of our asset portfolio. We are working hard to further improve this, both through power from shore solutions, through continuous improvement of energy efficiency, through collaboration with partners like Aker Offshore Wind to develop new and clean energy supply to our assets. With our current plans, we expect our gross emissions to be reduced by 50% in the early 2030s, and by 2050, we expect to be close to zero. Let's move on to our development projects. We have a lot of activity on the way. The three largest project in the execution phase are listed on this page. At Alvheim phase I, we started production in Q4. We're now working on phase II. This was originally planned to start production in 2023. We were able to accelerate this by approximately two years with some bottlenecking and hard effort from the alliances. The first well in phase II scope was even started before the phase I last year. Now in the first quarter, we have drilled the remaining two wells. We are on track to start production in Q4 this year. For Johan Sverdrup phase II, the message from the operator, Equinor, is very simple. We are on schedule and on cost in accordance with plan. The picture on this page show the main support frame for the second processing platform at Johan Sverdrup just before sail away from Thailand to Norway, where it will be integrated with two other modules and prepared for offshore installation. The Hod project is also progressing as planned with construction of a wellhead platform ongoing at Kværner Verdal. We have seen some challenges related to the available manning due to COVID restrictions, but through good collaboration with our alliance partners, we've been able to mitigate these effects, and the overall schedule is still intact. As I said initially, we are also working hard to mature our portfolio of upcoming field developments. The list on this page is the same as we showed on our capital markets update in February, with one new column to show the status of each project. I am not in this presentation going to talk you through all these project, the common denominator is that we aim to sanction all these projects by the end of 2022, hence make sure they qualify for the temporary tax system. In total, these projects represent more than 500 million barrels, with an average estimated breakeven oil price of around $27 per barrel. The two projects that are closest to FID are both in the Alvheim area. Back in 2018, we drilled two successful exploration wells in the Alvheim area, the Froskelår and the Gekko well. These two discoveries are now the basis for two upcoming field development decisions in this area, which are expected to add about 40 million barrels of net reserves to Aker BP. Meanwhile, we also continue to drill infill wells in this area. The Boa Attic South well started production in March, and we're planning two more wells this year. The third Alvheim related project on our list is Trell and Trine. Here, we are currently doing subsea and tie-in studies. We have also done a couple of business development deals in the quarter in this area. One of them was with Lundin, who is our partner at Alvheim, Volund, and Bøyla. Lundin come in as a partner on Trell and Trine, while Aker BP increases its stake on the Froskelår discovery and the Lyderhorn prospect. This will ease the tie-in negotiations between the Alvheim license and the Trell and Trine licenses. The other deal involved a 50% share in a license on the U.K. side of the border as a partner to Eni. The new license is bordering our existing acreage on the Norwegian continental shelf, including the Rumpetroll discovery, and the purpose is continued exploration. If we move a little bit north of the Alvheim area, we of course come to NOAKA. On NOAKA, we are continuing to work full speed ahead in line with the previously communicated plan. We are now on the final stretches of the technical concept studies, which will be completed by the end of May. The next milestone will be the formal concept select decision, which are planned in Q3. By then, we will also have drilled an appraisal well to test the producibility of the Liatårnet discovery. We have established a very strong and highly capable team for the NOA Fulla project, and we are working closely and very integrated with our alliance partners such as Aker Solutions, Subsea 7, Odfjell Drilling, Maersk Drilling, and Halliburton, as well as our license partners, Lotos, to mature a technically robust concept that will maximize resource recovery and value creation. We have established an excellent collaboration with Equinor, who is operating the Krafla project. One of the key focus area is to ensure that all the interfaces between the two processing hubs are well defined and with robust technical solutions. Once in production, it is our goal that the PDQ platform will operate with a high degree of digitalization and automation to deliver low OPEX and high regularity. We are also working closely with Aker Solutions, Cognite, and Aize to digitize the project execution phase. The purpose is to drive improved quality and reduce waste and cost in the project. A more digital project execution will also contribute to populate data in the NOA and Fulla digital twin. This will enable new ways of working and robust but reduced OPEX when the field start production in 2027. Based on all the progress we've made and where we are right now, I remain confident that we will be able to deliver the PDO before the end of 2022. With that, make sure that the NOA development is covered by the temporary tax rules that we have covered extensively in the previous presentations. At Valhall, we have recently completed the last planned campaign of plugging old wells. In total, 30 wells have been plugged here since 2014, of which 18 have been done after the merger with BP in 2016. Compared to the plan we put in place in 2016, we have completed this program six years earlier and around NOK 5 billion, or 45% lower than originally planned. I'm also proud to say that we have done this with near zero CO2 emissions, as we've been running the rig with clean power from shore via the Valhall Field Center. This achievement has also been enabled by pioneering new technology, including the use of bismuth plugs, which help us solve the challenge of potential methane leaks from the old wells, of course, result in lower CO2 emissions compared with conventional cementing technology. We share this success with our alliance partners, Maersk and Halliburton, who've been working together with Aker BP as one team to deliver these remarkable results. I want to take the opportunity to thank Maersk and Halliburton for their contribution. On the exploration side, the Bask well was completed in Q1 and was classified as dry. Right now, we have two ongoing exploration wells, both operated by Equinor. The Garantiana West well is targeting additional resources to Garantiana, which is one of the upcoming project in our list. Even if this is a relatively small prospect, it could have meaningful positive effect on the Garantiana development. The Kenshu well is a larger prospect located in the Barents Sea, and when Kenshu is completed, the rig will move east to Stangnestind, where we will drill our final well in the Barents Sea for now. As you can see from this list, we currently have five more wells coming up throughout the year, and we will, of course, keep you updated as we progress. This concludes the operational update. Now, David, even though I stole some of your thunder, will go through the financial for this quarter. Thank you, Karl, good morning, everyone. Aker BP's net production in the first quarter was 222,000 barrels of oil equivalents. Due to a small overlift, the sold volumes ended at 223,000 or 20.1 million barrels in total for the quarter, up roughly 2% from Q4. The realized crude price ended at $61.1 per barrel, in line with the average Brent dated in the period. Adjusting for NGL, Aker BP's average liquids price was $60.1 per barrel, up 36% from Q4. If we include gas, the realized average hydrocarbon price was up approximately 34%, consequently, we report a record high total income of $1,133,000,000 in the first quarter, up 36% from Q4. Production cost related to oil and gas sold in the quarter amounted to $176 million. The increase from Q4 is mainly driven by adjustment for over/underlift the last two quarters. The cost of produced volumes has been quite stable over the period, with the small uptick mainly driven by an increase in well maintenance activity at Valhall in Q1 compared to Q4. Production cost per produced unit amounted to $8.6 per barrel of oil equivalents, in line with the full year guidance of $8.5-$9 per barrel. If we take a look at the other main items in the P&L, subtracting production cost and other operating expenses of NOK 8 million from total income, we get an EBITDAX of NOK 949 million. Exploration expenses amounted to NOK 71 million, where NOK 41 million was field evaluation costs, mainly related to NOAKA studies as the project is maturing as planned toward concept selection later this year. In addition, we had NOK 12 million in dry well costs, mainly related to the Lundin-operated Bask well. This gives an EBITDA of NOK 878 million, up 41% from the last quarter. Depreciation was NOK 258 million or $12.9 per barrel. The decrease in depreciation rate from Q4 is mainly driven by year-end reserve updates and decreased estimates for future abandonment cost on some fields. In the first quarter, we also recorded an impairment amounting to net NOK 30 million, driven by Ula-Tambar and partly offset by reversal of previous impairments on Ivar Aasen. The main reasons for the impairment charge are the effect of updated phasing of production and cost profiles on Ula offset by the increase in short-term prices. Net financial expenses were NOK 90 million and included NOK 19 million in costs related to early redemption of the company's $500 million senior notes maturing in 2025. Apart from that, the other reason for the increase in net financial expenses from the fourth quarter is related to change in fair value of currency contracts. There was a loss of NOK 6 million in Q1 while a gain of NOK 42 million in Q4 as the Norwegian kroner strengthened late last year. Summing up the items so far gives a profit before tax of NOK 501 million, up 113% from the fourth quarter. Tax expenses amounted to NOK 374 million, which means an effective tax rate for the quarter of approximately 75%. Net profit in the first quarter ended at NOK 127 million or NOK 0.35 per share. With higher prices, stable production, low cash tax, and spending in line with our plan, both operating cash flow and free cash flow was very strong in the quarter. Cash flows from operations amounted to NOK 900 million. Investments, including payments on lease debt, amounted to NOK 343 across the various spend categories, with CapEx being over 60%. Free cash flow before financing was thus NOK 558 million, an increase of 141% compared to Q4. As already mentioned, during the quarter, we redeemed the bond and including the call premium, this redemption amounted to NOK 515 million and was paid from cash. Interest paid was NOK 63 million and purchase of treasury shares was NOK 13 million. Dividend paid was NOK 112.5 million and we then ended the quarter with a cash balance of NOK 392. In addition to the small change in cash on the balance sheet, there are a few things to note on the left-hand side of the balance sheet. Property, plant, and equipment increased by NOK 126 million. We had additions of NOK 306 where investments at Valhall and Alvheim was roughly 60%, while Skarv and Johan Sverdrup made up roughly 25%. Depreciation amounted to NOK 233 million, and we had a net impairment reversal of NOK 53 million. Furthermore, other intangible assets decreased by NOK 165 million. Other intangible was impaired with NOK 83 million while we reclassified exploration assets of NOK 74 million to PP&E related to the Frosk test producer. On the right-hand side, tax payables has increased with NOK 289 million up to NOK 452 million, and bonds and bank debt has decreased with almost NOK 500 million down to NOK 3.5 billion. In Q1, we have taken several steps to further optimize the capital structure, improving our financial flexibility for the years ahead. In February, Moody's upgraded Aker BP's company credit rating to investment grade. As a result, all three main rating agencies now have an investment-grade credit rating with stable outlook on the company. Following this, the focus this quarter has been on extending our maturity profile, adjusting liquidity position, and reducing financing costs. Firstly, we have redeemed one of our last two outstanding callable bonds, removing maturities from the CapEx-heavy period of NOAKA in 2025. This bond was issued in 2018 with a coupon of almost 5.9%, significantly above what we expect to achieve if we were to issue a new bond today. Secondly, the maturity of our working capital facility has been extended from 2022- 2024 with the option to further extend to 2026. Given the diversification of funding sources and successful issues of long-dated bonds in 2020 and the strong free cash flow generation expected in 2021 and 2022, we have scaled down the working capital facility from NOK 2 billion- NOK 1.4 billion as planned when the facility was established in 2019 and to reduce commitment costs. Lastly, we have utilized the remaining extension option on the NOK 2 billion liquidity facility to extend the maturity from 2025- 2026. Both of these bank facilities are currently 100% undrawn and are established to provide financial flexibility, supporting both our organic investment program and enables us to react quickly to any potential inorganic opportunity. The refinancing done in Q1 was oversubscribed and allowed us to upsize from the initial invitation of NOK 1.25 billion, which we view as a strong testament to the credit and business profile of Aker BP and the good relationship we have with a very supportive bank group. The result of the strong cash flow generation and the refinancing activities are that at the end of the first quarter, net debt has been reduced from Q4 with roughly NOK 350 million down to NOK 3.1 billion. Leverage has been reduced down to 1.2x EBITDAX, which is back to pre-COVID levels. Our available liquidity remains industry-leading, ending the quarter at NOK 3.8 billion. Furthermore, apart from the $750 million of senior notes maturing in 2024, which is callable in June this year, Aker BP now have only $1 billion of debt maturing before 2030. Combined, this provides the company with superior financial flexibility, supporting both our investment program in high return barrels, as well as allow us to capture value-accretive inorganic opportunities that may arise. Before closing off with a summary of our key guiding parameters, let me say a few words on forecasted cash tax payments the next five quarters. In Q2 this year, we expect a small refund, which is the remaining installments for the fiscal year 2020. For the fiscal year 2021, we expect to be cash tax break-even at roughly $50 Brent for the remaining of the year. At current oil prices, we expect to pay roughly NOK 150 million- NOK 200 million on average per quarter in the H2 of 2021 and the H1 of 2022. Now, to round off my presentation, let me walk you through the key guiding parameters for 2021. In short, we keep all our guiding parameters unchanged from our capital markets update in February. Production in Q1 was strong and slightly above the guiding range. As we now move into a maintenance season, we expect a bit lower production in Q2 before picking up again towards the end of the summer. Capital spend was roughly NOK 400 million, and as our project activity is progressing as planned, we expect capital spending to pick up in the coming months. Production cost of $8.60 per barrel in Q1 was as expected. On a per barrel basis, we expect cost to increase in the second quarter as production slightly decreases. We expect cost per barrel to trend downwards again during Q3 and Q4. Lastly, our proposed dividends of $450 million for 2021 remains unchanged, and the board of directors has resolved to pay a quarterly dividend of $112.5 million in May. I will now leave the word back to Karl for some concluding remarks before we move on to Q&A. Thank you, David. Solid delivery and solid results, as usual. Before we open up for questions, let me round off this presentation with reiterating our key priorities as they stand at the end of Q1, as I usually do. Let's start. Operational excellence is, of course, the fundament for everything we do. This means running our assets with the highest safety standards and the highest possible efficiency. This is always the number one priority for Aker BP. With a high activity level on the field development side, it's also extremely important to make sure that we're doing the right things right. Flawless project execution means delivering our projects on time and on budget, which is essential to ensure we generate the desired returns on our investments. I have not mentioned our new operating model in today's presentation, but the implementation of this model is a key priority in order to further improve operational efficiency and drive down cost in our operations. The other main improvement theme is the digital project execution model, which I touched upon in connection with the NOAKA project. This will be the first full-scale implementation ever on a fully digitally integrated project execution. We aim to launch this in connection with the DG II decision on NOAKA later this year. Continuing on NOAKA, it is of course a key component of our growth story, and a key priority right now is to land the development concept that is both technically, economically, and environmentally robust. That can be ready for FID within the deadline of the temporary tax system. As communicated previously, I am confident that we will be able to do this. Alongside NOAKA, we are running full speed ahead with a dozen or so other projects that will also contribute to continued growth and value creation for Aker BP and its stakeholders. This concludes our pre-prepared remarks and we're now open for questions. Thank you. Ladies and gentlemen, if you would like to ask a question please start by pressing star one on your telephone keypad. If you are using a speaker phone please make sure your mute function is turned off to lower your speaker to reach your question. Once again that's is star one for your question today. We would pause for a brief moment. Our first question today comes from Teodor Sveen-Nilsen from SB1 Markets. Please go ahead. Hey, good morning, and thanks for taking my questions, and thank you for the update. I have three quick questions. First of all, on Sverdrup, good to see that seeing good performance there. What should we expect of production from Sverdrup going forward? Is it fair to assume around 60,000 barrels per day, flat-ish until Q4 2022? Should we expect some maintenance works this summer? Second question is on Ula-Tambar. What's the book value after impairment? My last question is on exploration. What's the commercial threshold for the Stangnestind and also Kenshu well in the Barents compared to the pre-drill estimate that you presented on the slides? Thanks, Teodor. Regarding the Johan Sverdrup, we haven't normally disclosed the forward predictions on the individual fields. There will of course, be some discussions and possible interruption related to the installation of the new process platform. I don't think you're too far off with your estimations. With regards to remaining asset value on Ula, Teodor, I will refer you to the notes. The book value recoverable amount is roughly NOK 600 million. I think it's worth noting that does not then include the asset retirement obligations and deferred taxes. Your question for commercial threshold, that will of course depend on phase and reservoir quality in addition to volumes. I think it would be fair to say that if this ends up as a standalone field development, volumes significantly lower than around 150 million barrels is probably difficult to do on a standalone field development, depending on reservoir qualities in the reservoir. That would probably be equal both for Kensui and for Stangnestind. Okay. Thank you. That's clear. Thank you. We move on to our next questioner, Yoann Charenton from Société Générale. Please go ahead. Good morning, everyone. Thank you for the update this morning. I would just like to go back on a few detail, if you don't mind. First, on the phasing of CapEx throughout the year, is that possible to provide just an update on the level of manning offshore when it comes to personnel that is currently involved offshore? That would be great. A second point will be on production. You say that in the second quarter, we should expect lower output from the company overall. Are you able to provide just a bit more granularity, what sort of asset is impacted by lower production levels? The last question will be more about business development. You have signaled this agreement with Eni in the U.K. North Sea. Are you able just to provide a few more comments on potential work ongoing in the H2 of the year in the U.K. North Sea? Thank you. Okay. Do you want to start with fast phasing of CapEx, David? Yeah. I think the comment there is that we expect CapEx to pick up as mentioned throughout the year and increase gradually with drilling both on Valhall and also the Hod project towards the end of the year. With regards to manning specifically offshore, I don't know, Karl, if you have any sort of commentary on that. The phasing, the majority of the personnel offshore is OPEX personnel or related to drillex. I think on the operation side it's around 380 in total, which is pretty normal for this kind of situation. We are currently operating two- three rigs which would probably amount to about 100 per rig. You probably end up in right 750-ish. That's not really the reason why we have a different phasing in the CapEx profile. When it comes to production in Q2, as we already indicated also at the capital markets, there will be variations throughout the year. As mentioned, as we move into maintenance season now, production in the second quarter will be slightly towards the lower end of the guiding range before picking up again, as mentioned towards the end of the summer. I don't go into any more specific details on that. Yeah. Then regarding the entry into U.K. as a partner alongside Eni. I don't intend to comment on possible future activities, neither in the license nor in other possible activities, but I can provide you with a little bit of insight into how this came about. As you may be aware, we have spent quite a lot of time mapping the subsurface in the greater Alvheim area, with particular focus on injectites, and particularly the injectites in the Heimdal Formation. That has led us to be aware of an opportunity, which we have now captured both on the Norwegian side and on the U.K. side. I think you can draw the conclusion that we are continuing to work with potential in this area. I'm not going to comment on specifics to this regard. This is great. Thank you for the insight. Thank you. We now move on to Anders Holte from Kepler for our next question. Please go ahead. Can you hear me? Yes, we can now. Please go ahead. Okay, very good. Thank you for taking my questions. I actually just have two small ones as the main ones have been covered already. Just if you could, Karl, is there anything more you could share with us on the progress of NOAKA? More specifically on the timelines and how comfortable you and Equinor feel by making the clearly all-important deadline to hand in the plan for development towards end of next year. Also looking at your slide number nine here. I know you just said that you're not going to comment on future business development ideas or endeavors here, clearly when you look at the Rumpetroll and the Froskelar discoveries, they both spill over to the U.K. sites. Is it a far-fetched thought that you will expand your presence on the U.K. continental shelf, just given your exposure on the Norwegian side of those specific discoveries? Thank you. When it comes to NOAKA, maybe I should have been more direct in my comments in the presentation. First of all, I've personally spent quite a lot of time now diving into the concept, the cost estimates, the timeline, et cetera, following Easter. I must say, I'm really impressed by the team who has been working on this in the alliance setting. In a very short period of time, they have been able to mature the major technical solutions to a level that at least I haven't seen at this stage in a project before. On that basis, I'm extremely confident that we will be able to deliver the NOAKA project according to the timelines we have previously announced. Just to reiterate what those are, we do plan for a formal DG2 in Q3. Right now, and probably even before summer, the main technical elements will be locked in place, which means that there will only be costing long lead items and that kind of work remaining. Since this is an alliance project, and we don't have to work on competitive feed and tender processes following DG2, the technical teams will immediately, after making the technical concept selection, progress with maturity into the detailed engineering phase. We are actually also saving about six months compared to a normal project execution, which increases robustness in this timeline. In total, Anders, this is not on the top of my worry list for the moment. When it comes to the U.K., of course, there are reasons for us expanding into the U.K., and it's mostly, as I commented on Yoann's question, related to the injectite expanding across the border. If you put that as a kind of a basis for answering your question, it is of course clear that this system does not expand infinitely on the U.K. continental shelf. This is a standalone effort to continue tracking a system that we have been successfully exploiting on the Norwegian continental shelf and do not constitute a strategic change or a bigger strategic effort on the U.K. side. Thank you. Thank you. We go to our next question from Al Stanton from RBC. Please go ahead. Yes. Good morning, guys. I get that Aker BP is a sort of technology-led company. We're very focused on efficiency and at four kilos, your emissions are very good and leading. It strikes me that net zero doesn't get much attention. I'm just wondering why, Karl, it's not perhaps more prominent on your worry list. 2050 seems to be some way off given, particularly in the last month, everyone has been fighting to bring the date as far forward as possible, yet it doesn't feature in Aker BP schedule that prominently. Thanks, Al. The first part of your question is very correct. I don't know if we are technically led, but we are at least driven by performance and trying our best to lead in terms of performance in every major segment. When it comes to net zero, I think the way we think about it in Aker BP is that we will do our best and do everything we can to reduce the emissions that we are directly impacting on the climate, right? Which means that we have power from shore from Aker Offshore Wind, which will reduce emissions. We're continually working with smaller, I would say, it's more continuous energy efficiency improvement activities. This year will probably be around 10,000-15,000 tons, again, from the same base in terms of reduction. Then we try to focus on the things we can in fact impact. By minimizing our footprint, by maximizing our performance, we're paying back to both society and stakeholders, which can, of course, decide to invest on negative CO2 measures, which they are probably better at position on executing than we are. You won't really find Aker BP working very hard to develop offset mechanism to further reduce this scope if it doesn't directly impact how we operate our units. We do believe that our shareholders are better positioned to allocate that kind of funds than we are as a company. Okay. That's very clear. Thank you. Thank you. As a reminder, ladies and gentlemen, that is star one for your questions today. We now move on to James Hosie from Barclays for our next question. Please go ahead. Hi. Good morning. Just a couple of questions from me. Your comments on the debt profiles. Are you actually planning to refinance the 2024 notes when they become callable in a few months? On your comments about being able to respond quickly to acquisition opportunities, is it still challenging to find compelling deals in the Norwegian asset market? That's something you've mentioned previously. What's the likelihood that the next material transaction sees Aker BP export its successful business model to a new geography? I'm not just referring to the U.K. on that. Thank you. Maybe I'll start with the refinancing call, and then you do the M&A questions. Yeah. I think what I can say on this is that the 2024 bond is something that we are of course evaluating currently, and then, of course, we can't go into specifics on that, but it's of course natural to evaluate given that it's the last of the callable bonds that we have, and also when we look at the economics of that. The decision will be taken in due time. Moving on to M&A and starting with the Norwegian Continental Shelf. I think the key issue we have, and we have to ask ourselves, and are continually asking ourselves in the management team is, what will create the most value for Aker BP shareholders? There are a number of transaction opportunities on the Norwegian Continental Shelf that are either coming to the market or ongoing at the moment. The key issue for us is to understand how that is value accretive to the story we have. I think there are basically two lines of thought there, right? The first one is to acquire production, which seems to be quite expensive, and it's very hard to find that that's value accretive to our shareholders. The other one is to acquire more CapEx. We are going to invest quite a lot into the organic hopper. We don't normally see a need to further deepen that hopper. That being said, there might be combined opportunities that we will find attractive. We'll come back to that as we progress these discussions. When it comes to, let's say, exporting the Aker BP model, it's a question I get quite regularly. I would say both from domain expertise in other basins, national oil companies, et cetera. My answer has always been that our main focus for this period is to deliver on the project execution scope, deliver on the cost reduction we have planned, and the emissions reduction. Right now there are no plans to export, as you stated it, James, to other regions for the moment. I think we have plenty on our plate. Thanks very much. Thank you. At this time, we have no further questions in the queue, gentlemen. I guess then we can cash in those last 10 minutes that we had allocated, and wish you all a continued fantastic day wherever you are. Hope you all stay safe and that I know that many of you have already got your vaccines, and that's good, and we look forward to meet you all in person in the not too distant future. With that, we thank you all, and please, if you have any follow-up questions, you know where to find us. Thank you.