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spk14: With this intro from the sale away of the Fenris jacket and pre-drill module from the Vardal yard a few weeks ago and the subsequent successful offshore installation on the Valhall area, we welcome you to AKBP's second quarter 2024 presentation. It will be given by our CFO, David Turner, and myself, followed by our usual Q&A session. But before that, let me start with the highlights. RKBP achieved excellent operational performance this quarter with high production efficiency. We continued to demonstrate strong cost discipline and maintained our position as a global industry leader in low emissions. I am pleased to report that our projects are progressing well. Fabrication and construction activities are underway at multiple sites in Norway and abroad, with the installation work offshore ramping up as shown in the intro. And the total COPEX estimate for our project portfolio remains unchanged. We maintain a strong financial position supported by robust cash flow from operations. This allows us to invest in our profitable projects while also providing attractive dividends to our shareholders. At Akabipi, we consistently deliver high production from our world-class asset portfolio. In the second quarter, we produced 444,000 barrels of oil equivalents per day, and the production efficiency increased to 95%, which is leading on the NCS, as we remained continually laser-focused on operational performance. Compared to the previous quarter, Alfheim, Skav and Valhalla delivered stable production. At Edvard Gregg, we saw a reduction due to a combination of natural decline, plant maintenance and a shutdown linked to the startup of Hans. At Johan Svardrup, it's a pleasure to see just how it keeps on performing. This giant field with almost 3 billion barrels in initial reserves was originally designed for a gross oil capacity of 660,000 barrels per day. Last year, this was increased to 755,000 barrels. If we also include natural gas, the field has a capacity to deliver close to 800,000 barrels of oil equivalents per day. And the performance has been nothing but remarkable, with high production efficiency, very low production cost of around $2 per barrel, and with maybe the lowest emission intensity in the industry of less than one kilogram of CO2 per barrel. In the second quarter, AKBP's share of production from Johan Svadrup increased to 241,000 barrels of oil equivalents per day. As we have previously discussed, water production has been increasing in some of the wells over the last year. This is as expected and something that the operator is managing, but continuously optimizing production on a well-by-well basis. We are also adding new wells, with four added in the first half of 2024, and a fifth well have been started up now in July. Another five wells are planned for the second half. As of today, Johan Sladrup continues to produce at the elevated plateau, and the ongoing drilling activity will help to maintain this level until late 2024 or early 2025. The next step is to drill additional laterals from existing wellbores to increase reservoir exposure and mitigate water production. We are also approaching a concept select for phase three. This is a project that will involve subsea wells tied back to the Johan Sverdrup Field Centre, with production start up targeted from late 27. At AKBP, we believe that maintaining low cost is crucial for gaining a competitive edge in the oil and gas industry. And we systematically work towards this goal. And I'm very pleased with the progress we've made. Our production cost for the quarter was $6.4 per barrel, well within our full year guidance of $7. This quarter, the production cost was positively impacted by high production volumes, limited maintenance activities, and favorable currency effect, but yet it marks a very strong start of 2024. When comparing our production cost to those of the relevant industry peers, Akka BP maintains a strong competitive position. As illustrated in the chart to the right, data from Woodback show that ArcaBP has the lowest production cost among a group of 20 comparable companies. ArcaBP's greenhouse gas emissions were below 3 kg of CO2 equivalents per barrel in the second quarter, marking a significant improvement over the last few years. This progress is driven by enhanced energy efficiency and an increased share of production from fields powered from shore. This outstanding performance cement our position as a global industry leader in greenhouse gas emissions intensity, a trend consistently demonstrated in the recent quarters. Among the approximately 300 largest upstream oil and gas companies worldwide, Akka BP stands out as one of the best in emission intensity, as shown in this chart. This position gives us an excellent starting point for further reductions. We are committed to continually reducing emissions from our operations, which is a crucial part of our strategy to achieve net zero emissions across operations by 2030. Beyond that point, we plan to offset the remaining emissions through nature-based carbon solutions.
spk05: The ASHA template installation is in the books, making a huge milestone in the Yggdrasil project. It's our first offshore construction on Yggdrasil, and we nailed it.
spk14: We are well underway with the execution of our large project portfolio, which will unlock nearly 800 million barrels of oil equivalent and grow ArcaBP's production to over 500,000 barrels per day in 2028. These projects have robust economics with break-even oil prices as low as $35 to $40 per barrel and a rapid payback period of one to two years at an oil price of $65 per barrel. The activity has now ramped up to full speed across the project portfolio, and fabrication and construction activities are progressing according to plan at all sites. We have also started offshore installation for several projects. The Fenris jacket featured in today's opening sequence is one example. With this jacket in place, we are now ready to start the drilling campaign at Fenris. Another example is the SKAV satellite project, where all three subsea templates are now installed on the seabed. As we saw in the last video, the first five subsea templates have now been installed in the Yggdrasil area. We have also completed one project in the quarter, as Hans was brought on stream back in April. In parallel with the construction and installation activity, we are also looking for further upsides. One very good example is the drilling of the Frigg Gamma Delta geopilot in the Yggdrasil area. Take a look at this.
spk01: We are drilling the Frigg Gamma geopilot to help develop and plan for the future wells on Yggdrasil. Since being on Frigg Gamma the last two months we've seen a step change in performance and vast improvements in our ability to drill the wells and what we do. So we're testing some parameters for future development for the Yggdrasil in some of the ROP and the drilling parameters we're using to help benefit how we plan the wells in 2025-26 and moving forward.
spk02: Frigamo Delta is a very important field for the Yggdrasil development and constitutes a large part of the oil production on the field. The Hugenaar platform will be placed right above Frig Gamma and you can see the planned laterals coming down to Gamma and Delta in total 18 laterals. What we're doing here today is to drill early geopilots on the Frigamo Delta field in order to figure out where we should place our producers in the upcoming drilling campaign next year. We are doing this by mapping the top of the reservoir and the oil column with a deep resistivity tool from Halliburton. The way we mapped the structure is by doing long horizontal wells similar to what we did on Östfrid. The data we've collected so far already has a large impact on where we want to place the wells and hence has a large impact on the value of the field. We are the same team, both from Express and Drilling & Wells. We know each other, we trust each other, which makes it possible for us to push boundaries, to be courageous, both in terms of drilling and in geosteering.
spk00: This well is usually named the mother of all science projects, as we are performing a series of technical testing for Rygdrasil. We have pushed the limits quite a bit further than last year on East Frigg, especially when it comes to good practice for hole cleaning. all of our simulation software and experience dictate that this can't be done but if you only look at the physics of it it should be possible so we we needed to try and it's been going really well we have proven that a lot of the good old oil field practice is just old and this has put us in a position to drill further cheaper and better production wells
spk09: The rig has been fantastic. Even with our out-of-the-box parameters we have been able to drill close to 1500 meters per day and that's an achievement which wouldn't be possible without the close cooperation we have had between Drilling & Wells, Express and the offshore team and the Alliance.
spk01: With the RKBP performance first, one of the key elements is the one team culture and the cooperation between Saipem, Halliburton, RKBP and other service providers is fantastic. The atmosphere on the rig is brilliant.
spk14: Impressive work from the entire team on the Frigg Gamma GeoPilot at Yggdrasil. This initiative is crucial for optimizing volumes, operations, and cost as we move into the production phase of the field. As Hanne mentioned in the film, we have proven that a lot of good old oil field practices is just old. And this has put us in a position to drill further, cheaper and better production wells. I absolutely love it. This really is the spirit of AKBP and our alliances. We continue to advance as the E&P company of the future. In conclusion, we are confidently on track to deliver our projects on time, on cost and on quality. Exploration for new oil and gas resources is an integral part of the Akka BP strategy to sustain and grow our business. One of our key exploration objectives is to make new discoveries that can add value to our existing assets. Around 80% of our exploration activity is focused on such near field opportunities, while 20% are focused on high risk, high reward wealth in new areas. In 2024, we have drilled eight wells so far and made several discoveries. The Adriana appraisal was a successful appraisal, and this discovery is now a candidate for tie-in to SKAV. It will be followed up later this year with the Sabina well. The discovery at Trell North, although small, is already included in the Tørving project, with the first oil expected already in October. And Ringhornet North was also a discovery, which has the potential to tie into near-field infrastructure. In the Visting area in the Barents Sea, the exploration wells at Fadiland and Hassel resulted in two small gas discoveries. We were primarily looking for oil. However, the gas could still be valuable for future Visting development. On a more positive note, Equinor recently drilled a successful appraisal well on the visiting reservoir to gather data both from the reservoir and the cap rock. This data is currently being analyzed and will be used in the ongoing work to establish a development concept for the field. We do have several exciting exploration wells coming up in the second half of this year. We are currently drilling Storjo Vest, which is a follow-up of the Storjo East Discovery from 2022, and a potential tie-back to SKAV. Let me also highlight a few of the upcoming wells. First, I would like to mention Bounty. This prospect features an intriguing structure with significant upside potential in the Norwegian Sea. A well was drilled in this license a couple of years ago with oil shows. This new well will test the upflank potential from this initial discovery. Second, the Skruestikke and Kallafjell wells are targeting additional volumes that might enhance the Garantiana development. It's also worth mentioning that following the Epsilon discovery in the Yggdrasil area last year, we have added a new prospect named Omega to the drilling plan for next year. This prospect features an interesting structure with a model similar to Epsilon, which could further contribute to future growth of the Yggdrasil resource base.
spk11: Good morning. I am pleased to see that another excellent operational quarter is also reflected in our financial results. We have achieved strong production and income in a fairly stable oil price environment while maintaining industry-leading low production costs. Operating cash flow before tax increased to over $3.2 billion. However, due to two tax installments this quarter compared to one in the previous quarter, post-tax cash flow decreased. Cash flow to investments increased as expected, reflecting good progress on our projects. This will also be evident in our tax payments in the second half of the year, which we anticipate will be reduced by around 50%. At the end of the quarter, our financial positions remain strong with a low leverage ratio of 0.3 and ample financial liquidity of 6.6 billion, including $3.2 billion in cash. I will now walk you through the key drivers behind the results, starting with a review of our revenues. Total income increased in the second quarter, driven by sustained high production and an overlift of 17,000 barrels per day. The average realized hydrocarbon price rose by 2% quarter on quarter, with liquid prices holding steady at $83 per barrel. The realized oil price was in line with the average dated Brent for the quarter, where slight positive crude differentials were offset by timing of cargoes. As a result, the average liquid price was slightly lower than the average Brent price, since liquid sales also include a small portion of NGL. Natural gas prices increased by 11% compared to the previous quarter, driven by higher European spot prices. and overall total income was then $3.4 billion. Production costs related to sold volumes ended at $290 million. The increase in Q2 is mainly due to the overlift compared to an underlift in the first quarter. The cost per barrel produced remains among the lowest in our industry at $6.4, well within our full year guidance of $7 per barrel. The increase from 6.1 in Q1 was due to higher planned well maintenance activity at Vallal in the second quarter. Expiration expenses were 108 million for the quarter, driven by high exploration activity, while depreciation remained stable at 588 million, or 14.5 dollars per barrel. We also recognized an impairment of technical goodwill this quarter on Vallal and Edvard Grieg. As previously discussed, technical goodwill is recognized on various assets upon acquisition. Since technical goodwill is not depreciated, we will see more such non-cash impairments in the future as production continues from acquired fields. The effective tax rate in Q2 was 75%, in line with the previous quarter, and then net profit was 561 million. We report strong operating cash flow before tax of $3.2 billion. However, we also paid $2.1 billion in taxes this quarter, covering the remaining tax installments for the fiscal year 2023. As expected, cash flow to investments increased to $1.4 billion, reflecting our progress on the development projects. In summary, this resulted in a negative free cash flow of $283 million. Cash flow from financing consisted of two main items, the issuance of a euro bond of 750 million and the payment of a quarterly dividend of 60 cents per share. Overall, the net cash position was largely unchanged from the previous quarter. As the tax payments for the fiscal year 2023 were completed in June, we will begin paying taxes for the fiscal year 2024 in the third quarter. The total tax to be paid in the second half of 2024 is currently set at approximately $1.5 billion, with one third due in Q3 and two thirds in Q4. As I mentioned, this amount is around half of what we paid in the first half of the year. This reduction is due in part to higher tax deductions from the increased investment level in 2024 compared to the previous year. Moving forward, we therefore expect lower cash taxes, assuming stable commodity prices. When analyzing cash flows, it's essential to understand the timing of tax payments and consider more than one accounting period. Focusing on a single period can distort the understanding of the underlying cash flow generation of the business. Maintaining a robust balance sheet and a strong liquidity is a top priority for Aker BP. we are committed to upholding our investment grade credit rating which ensures access to capital in the bond markets on competitive terms and we continuously work to optimize our capital structure this quarter we issued a 750 million euro bond with a eight year maturity at the four percent coupon rate the issuance attracted significant interest from investors and was significantly oversubscribed Following this transaction, we have less than one billion in debt maturing before twenty twenty eight with an average maturity of six years and an average coupon rate of four percent. At the end of the quarter, other key balance sheet metrics remain very strong. Net interest bearing debt ended at three point four billion. The increase from Q1 is primarily due to the two tax installments this quarter and the facing of tax deductions for investments made so far in 2024, as already discussed. Our leverage ratio continues to be low at 0.3 times net debt to EBITDAX, well within our stated internal threshold of 1.5 times. Lastly, we maintain a strong liquidity position with 3.2 billion in cash and additional 3.4 billion in available bank facilities. This compares favorably to the less than $3 billion after-tax capex of our investments planned from now until the end of 2028. Our strong underlying cash flow generation and robust financial position is also the basis for our dividend policy. In the period from 2023 to 2028, accumulated cash from operations after tax is expected to cover our total investment at oil prices less than $40, while the rest is cash for debt service and distribution to shareholders. In Aker BP, we are committed to returning the value we create back to our shareholders with dividends that reflect our underlying financial capacity through the cycle. We are currently paying 60 cents per share each quarter, and our ambition is to increase the annual dividend by 5% or more over the current investment cycle, supported by strong cash flow, profitable investments in an investment friendly tax regime and a robust balance sheet. To conclude the financial section, let me give a quick update on the guidance on key metrics. 2024 has been an excellent year so far. Production in the first half amounted to 446,000 barrels per day, which is above the high end of our full year guidance range. In the second half, maintenance activities are planned at several fields, and we still expect to stay within the original guidance range for the full year. However, given the performance in the first half, we have narrowed the range by raising the lower end. The updated full year guidance is therefore 420 to 440,000 barrels per day. Production costs were $6.4 per barrel in the second quarter, and the year to date average is 6.2. We continue to benefit from strong cost discipline and a favorable foreign exchange rate. On the other hand, as we expect somewhat lower production volumes and higher maintenance activity in the second half, we also expect the unit cost to trend slightly up. Hence, we are maintaining our guidance at $7 per barrel for now. On CAPEX, we have spent slightly less than half of the budget by mid-year. This is in line with expectations and reflects the increasing activity level in our projects as the year progresses. Therefore, we are maintaining our guidance unchanged. The same also goes for both exploration and abandonment spend, where both activities are developing in line with plan.
spk14: Thank you, David. And before we begin the Q&A session, I'd like to summarize our performance and achievements this quarter within the context of the RKBP strategy. In the second quarter, we successfully achieved our operational and financial targets, while further reducing our already industry-leading emissions intensity. Our development projects are progressing as scheduled and within budget. We confirm our CARPEX estimates, and our plan is to reach approximately 525,000 barrels per day of production by 2028. Additionally, this year's exploration results have resulted in discoveries with promising commercial potential, and we have a very interesting exploration program planned for the remainder of 2024. So far this year, we have generated strong cash flow, bolstering our balance sheet, and we're also returning value to our shareholders in line with the dividend plan. We will now take a short pause before opening the Q&A session. And as usual, to participate, please use the Teams link provided on the webpage. If you prefer to listen only, please stay tuned, and we will resume in approximately one minute. Welcome back. I hope you took an opportunity to fill up your coffee cup or prepare questions or whatever you'd like to do. And I just think we'll go ahead with the Q&A without further ado. And as usual, I'll hand you over to Ketel Bakken, which is heading IR in AKBP. Ketel.
spk03: Yes. Good morning. We have a forest of hands in the team's meeting. So first question comes from John Olaisen from ABG. Please go ahead, John.
spk04: Yeah, good morning, gentlemen. A question on Svadrup. You had four new wells in production in the first half. Could you tell us a little bit on the impact of the production level of the new wells? And also, if you have toned down the production from the existing wells in order to... give space for the new production for the new wells, and how have the old wells reacted? Could you tell us a little bit about that, please?
spk14: Okay, I think I got your question. First of all, I think it's important to say that Johan Sverdrup is a really remarkable field. It's a pretty interesting story. Very low production costs, very low emissions intensity, and exceptional uptime. And yes, you're right, we have added four wells so far in the quarter. We just added another well now in July and there are four more wells to be added for the rest of the year. This is essentially a question about optimization. Of course, you are distributing as you're pretty much utilizing the entire process capacity. You're distributing the available process capacity across the well stock. That means that you're optimizing such things as well potential, water production, water handling, water injections. This is a process that is continually ongoing. Of course, when you add new wells, you tune down the volumes from the other wells to manage that flow of oil and gas up to the platforms. The whole idea, and I think I've been over this quite a few times in these presentations before, is as you're adding new well stock, you're reducing the total exposure on the existing well stock. That is taking down the average production rate You have more wells. I think we'll end up at 41 wells when we finish this year. And you're distributing the production volumes across 41 wells rather than 31. So that means, of course, a slight reduction. The whole idea is, of course, to limit the water coning that I've been discussing on Johan Sverdrup. And so far, the wells have been reacting quite positively. And as a result of that, we're also saying that we expect the current production rates at Johan Sverdrup to extend into very late 24, early 25.
spk04: Okay, thank you. And for 2025, you're saying you're planning for retrofit multilaterals next year. Could you elaborate a little bit on that? And could you also comment, will you be drilling more new production wells as well next year? Or will it all be these retrofits?
spk14: The whole idea with a retrofit multilateral is that you use the existing casing and the existing wellhead and Christmas tree, of course, and then you drill basically a new lateral. In this case, you're just placing it a bit higher in the reservoir. and therefore further away from the water, less oil above the well, so to speak, which means less residual oil. So it's again, it's an optimization. And yes, we plan to do quite a few of those. And then, of course, the phase after that will be phase three, where we're planning or gearing up to, I would say, a concept select towards the back end of this year and a production start late 27. um and there i've there are no new well slots available on the dry side so any new well slots will have to be subsea okay thank you very much and have a nice summer yes thank you john then the next question comes from sassy count chilukuru from morgan stanley please go ahead sassy
spk06: Hi, thanks for taking my questions. I had two, please. The first one relates to Yggdrasil resources. It seems like in this quarter, you have brought back or reduced the net reserves back to 413 million barrels of oil equivalent from 450. And this is essentially going back to your original guidance. I was just wondering if you could comment on this move. The second one was, again, a clarification on Jansper Rupa, You highlighted 10 new production wells being brought on stream this year, bringing the total number of wells to 41. I was just wondering, were these 10 wells and the figure of 41 part of your initial development plan, or has this figure actually increased more recently?
spk14: Thank you, Sashi. I didn't actually get your first question. Could you repeat that?
spk06: Yeah, so the Jigdrasil resources in this quarter, and slide back, is 413 million BOE, net to AKRBP. Last quarter, it was 450, but the 413 was your original guidance as well. So I was just wondering if you could comment on this move.
spk14: I think the difference between 450 and 414 is East Frigg. So what you're saying is that it actually reduced from the previous quarter?
spk06: Yeah, in your slide back, you had it at 4.15.
spk11: It's a matter of if East Frigg or not is included in that slide or not. So I think that's just the difference between the two. So I think it's just a matter of how we represent the numbers. But there's no fundamental change in the resources or reserves there.
spk14: So I think that the number you should assume on Yggdrasil in total, including Ysfrigg, is still 450. Just for being absolutely clear.
spk06: Great, thanks.
spk14: And then Johan Sverdrup, and you asked whether we have added wells that we didn't plan. We always plan to use the entire capacity in terms of production wells. So it is a part of the initial development scope.
spk06: Thank you.
spk03: All right, then the next question is from Lydia Rainforth of Barclays. Please go ahead, Lydia.
spk07: Thank you very much and good morning, everybody. It is actually very impressive to see that the projects are on time, on budget, and the video showed us one area that has been better than expected. Can I just ask, where else are you excited about the work that you're doing? Where else is the room for upside? And the flip side to that is it's rare for things to work as perfectly as it sounds like they are doing. So is there anything that hasn't gone as you expected within the project process? And then secondly, on the cost-based side, I understand completely what you're saying about the production of the second half of the year and the cost side, but is this really about being conservative now on the cost guidance? And I'll leave it there. Thank you.
spk14: Yeah. Thank you, Lydia. It's all about the good, the bad and the ugly, isn't it? Well, I think you're absolutely right. I think that there has been, of course, many successes. And I think the overall message is, as we pointed out, it is about keeping the project on track. And of course, we're spending quite a lot of resources to do just that. um there are quite a lot of successes and just to mention a few we've been able to place all contracts we've been able to actually now start up both pre-fabrication and ultimately component fabrication as well on most of these yards um some in norway some abroad and the ramp up of that activity is actually going as expected this was i think i discussed this last quarter that that could be one of the focus areas for at least me as a ceo of this company And then, of course, we've had challenges. I mean, which project haven't had challenges? And it's certainly this kind of complexity. And most of this has been centered around deliveries from vendors, where we're standardizing across the entire portfolio. That means that if one vendor is struggling, we're struggling across the entire portfolio. But I'm happy to say that all of those situations have actually been resolved. as we're now entering into the summer of 2014, which is due to an extraordinary effort and an extraordinary competency, but not the least to the alliance model that we present to these companies, which allows them to resource, prioritize, and put focus on the projects in AKBP. And then, of course, this is a continuous battle. But at this point in time, we're starting to see the horizon. And you asked, where do I put my focus? Well, the most important thing right now is actually quality. So when you're done or at least have engineering under control, the whole project schedule is driven by quality if you can control quality you can control schedule if you control schedule you control cost once the procurement is done and the project is settled so that's where we spend the most resources at this point in time then your final question was are we being conservative um no we're not we try to be extremely transparent in our kbp about what we actually believe in and very clear both in terms of guidance on production on cost on carpex and expenditure so when we're putting out the number we are It is because we believe that is the real number that the market should expect. And it's not a surprise that we end up with a little bit lower burn rate in the first half than the second half. If you see the ramp up of activities across the different yards as they are now adding manning, adding steel and adding all the components from the vendors and therefore adding into payment schedules as we approach the back end of 2024. Brilliant.
spk07: Thank you very much.
spk03: Thank you, Lydia. And now the next question is from Johan Charenton of Bernstein. Is that right, Johan?
spk10: Yes. Good morning. Thank you, Jethil. Good morning, everyone. I would like to ask three questions. So one would be on the production guidance for the full year. Would it be possible to know what are the assumptions for production efficiency for both the bottom and the top ends of the ranch? So that's the first question. Second question is on slide 17, which has just been updated. Is it possible to spell out the dated Brent and up gas price assumptions you have used to derive the combined 1.5 billion tax installments falling due in the second half of this year? And then the third question will be with regards to CapEx. So we have seen this uptick in the second quarter. Is it reasonable to expect a seasonal moderation in the third quarter because this is summer before a reacceleration of spend in the fourth quarter?
spk14: Okay. Production guidance. I think what we have included in the production guidance and the remaining part of the production guidance is essentially driven by two components. The first one is the maintenance activities in Q3. There are two separate activities or separate drivers, I would say. The first one is a SAGE shutdown, which will mean no gas export from uh edward greg eva austin and alfheim and the length of that shutdown that sage shutdown will drive the length of the shutdown on the fields and then second we have a turnaround on scav to do essential tieback work which will need a carbon hydrocarbon free environment in order to execute it so that's basically driving that that activity and then for the third fourth quarter it is about how much of this production will ramp up how quickly after we start up the fields again and then of course that you have turbine coming on stream and there are a bit of another moving bits and pieces right so it's not as easy as explaining that there is a there is a production guidance on the top and the bottom um The reason that the span is what it is for the full year guidance, even though we've achieved 95%, is those two key factors. It's not really driven by production efficiency, it's driven by activities and the length of those activities during the maintenance activity. I'll leave the dated Brent question to you, David.
spk11: I assume you referred to the near-term tax payments slide, Johan. The rule of thumb here is that you can look at the tax payments that we illustrate for the second half of this year and the first half of next year as sort of a full year guidance. And then you can actually infer the price that we have used for setting the tax installments for the second half of this year. So it's quite similar to the $80 scenario for the average for the second half of 2024. Then we give the gas price assumption and the FX assumption also on the slide. $9 per mm BTU and a US knock rate of 10 for the remaining of the year.
spk14: Then for your third question regarding Carpex and Carpex ramp-up, I can actually assure you, and I do this with a lot of subjectivity, there will be no summer break when it comes to Carpex execution or spend.
spk10: All right, well noted. Still, have a nice summer if you can. Thank you so much.
spk03: Same to you, Johan. Thank you, Johan. And now the next question is from Theodor Nilsen from Sparbank 1. Are you there, Theodor?
spk13: Good morning, yes, I'm here. Congrats on the yet another strong quarter. Three questions for me. First on balance, Kalle, you discussed the discoveries in the balance. I just want, how much more gas do you think you we need to discover in the Barents Sea before we can justify a pipeline development in the Barents Sea. So that's the first question. And the second question, which actually is not important for estimates, but it's just out of my curiosity. This far on Sverdrup, how much has been produced from Aval's nest and how much has been produced from Aldus Major compared to the total 2P reserve's And then latest, my last question is, what's the latest on the slow court ruling on Yggdrasil and Thurving? Thanks.
spk14: Could you just repeat the Fed question again, Theodore?
spk11: I think it was related to the court case.
spk14: Oh, the court case. Okay, fine. Good. Let's start with the Barents Sea. Well, the gas discoveries at Ferdinand and Hassel has little to do with infrastructure and more to do with tie back on this thing. So it's a different case. Then you ask how much gas do we need to discover to get to a pipeline? Yeah, that's a good question. It will depend on cost of the infrastructure, the quality of the gas, how much oil is associated, etc. So lots of different parameters. My guess in the range of 150, maybe even as high as 200, certainly not below 100. I don't remember off the top of my head the percentage split yet on cumulative production from Avalsnes and Aldus, so we'll have to get back to you on that. And then on the court case, well, in reality, we're following two different tacks. Of course, the court case in itself where Akamipi is not a party. So that is going on as it is. And then we are looking at the situation where we're trying to repair the discussions around what kind of information is missing in the current KU. I'm actually quite calm around this issue. At this point in time I think we have a pretty good handle on what is needed and how to assemble that data. We've sent the program for a new revised KU at the hearing and we're now about to finalize that piece of work. regardless of how the appeal case turns out, we will be in a position to issue the information needed.
spk13: Okay, thank you. Just following up on the bar and say, you're talking about 150 to 200 million barrels of oil and crude, right?
spk14: No. BCM of gas.
spk13: BCM. Okay, BCM. Okay, that's clear. Perfect. Thank you.
spk14: That's all for me. I mean, these volumes are very, very difficult to assess because if you actually find a lot of associated oil, then, of course, you're subsidizing the field development. Then you might need less gas to complete an infrastructure.
spk13: Sure. I absolutely understand. It's difficult to assess that. Thank you.
spk03: All right. Then next question is from Victoria McCulloch from RBC. Please go ahead, Victoria.
spk08: Thanks. Good morning. So a couple of questions remaining for me. So firstly, on Edvard Grieg, can you give us a little bit more color about what's going on in that field? I appreciate there was a shutdown for hands. at the field this quarter, but we're more than 30% down from this quarter last year. So maybe what your expectations are on maybe more of a medium term for how we should see declines in that field. And then... Bigger picture, again, question. Can you give me a bit more color in the CO2 storage strategy for AquaVP? Is this optionality at the moment or something you think needs to be part of the company's strategy on a bigger picture going forward? Thanks very much.
spk14: Yeah. So, both details and big picture. That's good, Victoria. On Edward Grieg, I think we have been quite clear that we, even last year, that we were approaching the end of the plateau. And then of course the decline on these fields, they're actually the strongest just after you go off plateau. And then of course as you kind of get down towards the, I wouldn't say tail, but as the decline tapers off, the decline rates in percentage per time unit declines. so to speak. Right now, we're actually seeing that we're in that bend where you actually start tapering off the decline rate. The models are actually working pretty well. I'm more comfortable that you, for the remaining of 24 and into 25, will see a more stable rate out of the Edvard Grieg Ivar-Rosen hub area. HANZ will offset it to a certain degree, but not entirely. but then there are also infill wells to be drilled on Edvard Grieg in 2025. Then, of course, the satellites come on stream in 2027. This is conventional oil field practice. It's just that normally in AKBP when we take over these fields, they have already gone off plateau and we do these redevelopment cases. In this case, we're actually following down the track before we're deploying the redevelopment activities. applying the AKBP model also to the Ivar Grieg, Ivar Åsson hub. In terms of CO2 storage, I see that as optionality at this point in time. I've been really, really clear that AKBP is a pure play oil and gas company focused on the Norwegian continental shelf. And AKBP will remain a pure play oil and gas company focused on the Norwegian continental shelf. The reason that we are looking at this with, I would say, a fairly small number of people is one, it gives us optionality. If there are regulation changes, potential to store CO2, it could potentially be used to offset rather than nature based offset mechanisms. you will see in the net zero act for example so we don't really know how that game will play out and therefore it's a very cheap call it insurance or optionality for us going forward if this is to be an activity with a significant copy spend we will look at structures that are more optimal towards the aka bp existing oil and gas activities thanks very much
spk03: Thank you, Victoria. Next question is from Mark Wilson from Jefferies. Please go ahead, Mark.
spk12: Okay, good morning. Thank you. Morning, gents. My question, the first question is, we're very clear on Johan Saverdrup oil production capacity 755, and you say with gas, it's almost 800,000 barrels oil a day. But can I ask what the water handling capacity is, given the discussion on water coning And then if you are at that water handling capacity, which meaning that optimization is really the one variable you have as you bring on new production wells. I have one follow up. That's my first question.
spk14: Water handling, that's an interesting question. Right now, we're actually at liquid maximum. That liquid maximum is being used for oil processing, essentially. We could handle significant amounts of water. So in terms of processing plant, water handling capacity would probably never be the main restriction on Johan Sverdrup. It will be more about how you maximize the total liquid handling capacity at Johan Sverdrup. And then of course, we are re-injecting all the produced water. So re-injection capacity could be an issue. At this point in time, we're injecting five times more than we are producing. It's unlikely to become a restriction in the short term. Then you will have produced water quality issues, which are usually a case when you have a low water cut and not a high water cut because then you get into a water continuous phase. The way the process plant is set up, I think this will essentially be driven by the water cut and the available well capacity in the wells and not driven by topside water handling capacity. I mean, this is, to be honest, Mark, this is so over-designed that you can process almost anything.
spk12: Got it. Okay. Well, my second question, and my last one now, is you reiterated, you know, expect plateau to extend into very late this year or early 2025. That would infer that those multilateral wells that you're going to bring on next year are You don't expect them to be able to maintain the plateau in the manner that the new production wells you're bringing on this year do. It'd just be interesting to understand the difference there.
spk14: The key difference is that when we're now drilling the last 10 wells, that means that we have a lot of experience with how the existing wells are performing. We're more uncertain on how these multilaterals will be performing when we put them on stream. This is always the case. We start with being a little bit conservative and then we get more expectancy correct, if you want, as we get more experience. So so we could end up actually with multilaterals that are really, really good. It's just that the modeling right now shows that we will probably not have the flow area in these multilaterals that we used to in the big ten and three quarter inch bore production wells that we're currently producing.
spk12: That's very clear. Thank you so much. My goodness. Ten and three quarter. Okay. I'll hand it over. And I'm well done so far.
spk02: Thank you.
spk03: That was the last question, I believe. That's it.
spk14: That's good. And that means that we're not essentially logging off here from the AKBP headquarters, but at least we wish you an excellent summer break for those who are about to go out into a summer break. And for those who are not, I wish you a good weekend. And I usually say that I wish people a safe weekend, so I'll do that too. Thank you, everybody.
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