Aker BP ASA (OTCQX:AKRBF) Q2 2024 Earnings Conference Call July 12, 2024 2:30 AM ET
Company Participants
Karl Hersvik – CEO
David Tonne – CFO
Kjetil Bakken – Head of IR
Conference Call Participants
John Olaisen – ABG
Sasi Chilukuru – Morgan Stanley
Lydia Rainforth – Barclays
Yoann Charenton – Bernstein
Teodor Sveen-Nilsen – Sparebank 1 Markets
Victoria McCulloch – RBC
Mark Wilson – Jefferies
Karl Hersvik
Good morning, everyone. With this intro from the sailaway of the Fenris jacket and predrill module from the Verdal yard a few weeks ago and the subsequent successful offshore installation on the Valhall area, we welcome you to Aker BP Second Quarter 2024 Presentation. It will be given by our CFO, David Tonne and myself followed by our usual Q&A session.
But before that, let me start with the highlights. Aker BP 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 CapEx 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 Aker BP, 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, Alvheim, Skarv and Valhall delivered stable production. At Edvard Grieg, we saw a reduction due to a combination of natural decline, planned maintenance and a shutdown linked to the startup of Hanz.
At Johan Sverdrup, it is 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 1 kilogram of CO2 per barrel.
In the second quarter, Aker BP’s share of production from Johan Sverdrup 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. Now, 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 Sverdrup continues to produce at the elevated plateau and the ongoing drilling activity will help to maintain this level until late ’24 or early ’25. 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 3. This is a project that will involve subsea wells tied back to the Johan Sverdrup field center, with production startup targeted from late ’27. At Aker BP, 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 costs to those of the relevant industry peers, Aker BP maintains a strong competitive position. As illustrated in the chart to the right, data from Wood Mac show that Aker BP has the lowest production cost among a group of 20 comparable companies.
Aker BP’s greenhouse gas emissions were below 3 kilograms 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, Aker 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 our operations by 2030. Beyond that point, we plan to offset the remaining emissions through nature-based carbon solutions.
[Video Presentation]
We are well underway with the execution of our large project portfolio, which will unlock nearly 800 million barrels of oil equivalent and grow Aker BP’s production to over 500,000 barrels per day in 2028. These projects have robust economics with breakeven oil prices as low as $35 to $40 per barrel and a rapid payback period of one years 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 Hanz. Another example is the Skarv satellite project, where all three subsea templates are now installed on the seabed. And 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 Hanz was bought 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.
[Video Presentation]
Impressive work from the entire team on the Frigg Gamma geopilot at Yggdrasil. Now, this initiative is crucial for optimizing volumes, operations and cost as we move into the production phase of the field. And as Hanna 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 Aker BP 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 Aker 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 wells 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 Skarv. It will follow up later this year with the Sabina well. The discovery at Trell North, although it is small, is already included in the Tyrving project with the first oil expected already in October. And Ringhorne North was also a discovery, which has a potential to tie-in to near-field infrastructure.
In the Wisting area in the Barents Sea, the exploration wells at Ferdinand and Hassel resulted in two small gas discoveries. We were primarily looking for oil, however the gas could still be valuable for future Wisting development. On a more positive note, Equinor recently drilled a successful appraisal well on the Wisting 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 West, which is a follow-up of the Storjo East discovery from 2022, and a potential tieback to Skarv. 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 up flank potential from this initial discovery.
Second, the Skrustikke and Kaldafjell 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.
David Tonne
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 remained 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 liquids 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 Valhall in the second quarter.
Exploration expenses were $108 million for the quarter, driven by high exploration activity, while depreciation remained stable at $588 million or $14.5 per barrel. We also recognized an impairment of technical goodwill this quarter on Valhall 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 Eurobond of [EUR750 million] (ph) and the payment of a quarterly dividend of $0.60 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’ll 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 EUR750 million Eurobond with an eight-year maturity at the 4% coupon rate. The issuance attracted significant interest from investors and was significantly oversubscribed. Following this transaction, we have less than 1 billion in debt maturing before 2028, with an average maturity of 6 years and an average coupon rate of 4%.
At the end of the quarter, other key balance sheet metrics remained very strong. Net interest-bearing debt ended at $3.4 billion. The increase from Q1 is primarily due to the two tax installments this quarter and the phasing 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 and 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 investments 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 $0.60 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 420,000 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.
Karl Hersvik
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 Aker BP 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 CapEx 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 are generating 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 web page. If you prefer to listen only, please stay tuned and we will resume in approximately 1 minute.
[Break]
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 Kjetil Bakken, which is Heading IR in Aker BP. Kjetil?
Question-and-Answer Session
A – Kjetil Bakken
Yes, good morning. We have a forest of hands in the Teams meeting. So, first question comes from John Olaisen from ABG. Please go ahead John.
John Olaisen
Yeah, good morning gentlemen. A question on Johan Sverdrup. You currently have — 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 other existing wells in order to give space for the new production from new wells? And how have the old wells reacted? Could you tell us a little bit about that, please?
Karl Hersvik
Okay, John. Yes, I think I got your question. So first of all, I think it is important to say that Johan Sverdrup is a really remarkable field, right? It is a pretty interesting story. Very low production cost, 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.
And this is essentially a question about optimization. So of course, you are distributing, as you’re pretty much utilizing the entire process capacity, you are distributing the available process capacity across the well stock. And that means that you are optimizing such things as well potential, water production, water handling, water injections. And this is a process that is continually ongoing. So, 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.
And 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 are 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 are 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 are also saying that we expect the current production rates at Johan Sverdrup to extend into very late ’24, early ’25.
John Olaisen
Okay. Thank you. And for ’25, 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 there all be these retrofits?
Karl Hersvik
Yes. So the whole idea with a retrofit multilateral is that you use the existing casing and your 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 3, where we’re planning or gearing up to, I would say, a concept select towards back end of this year, and a production start late ’27. And there are no new well slots available on the dry side. So any new well slots will have to be subsea.
John Olaisen
Okay, thank you very much. And have a nice summer.
Kjetil Bakken
Yes. Thank you, John. Then the next question comes from Sasikanth Chilukuru from Morgan Stanley. Please go ahead Sasi.
Sasi Chilukuru
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 million barrels of oil equivalent. 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 Johan Sverdrup. You highlighted 10 new production wells being brought on stream in this year, bringing the total number of wells to 41. I was just wondering, these 10 wells and the figure of 41, are they part of your initial development plan or has this figure actually increased more recently?
Karl Hersvik
Thank you, Sasi. I didn’t actually get your first question. Could you repeat that?
Sasi Chilukuru
Yes. So the Yggdrasil resources in this quarter — in slide pack is 413 million BOE net to Aker BP. Last quarter, it was 450 million BOE. But the 413 million was your original guidance as well. So I was just wondering what — if you could comment on this move.
Karl Hersvik
Yes. I think the difference between 450 million and 414 million is East Frigg. Whether we — so what you’re saying is, it actually reduced from the previous quarter?
Sasi Chilukuru
Yes. In your slide pack, you had it at 450 million. So that’s…
David Tonne
Yes. That’s a matter of if East Frigg or North 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 is no fundamental change in the resources or reserves there.
Karl Hersvik
So I think that the number you should assume on Yggdrasil in total, including East Frigg, is still 450 million, just for being absolutely clear. And then, Johan Sverdrup, and you ask 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.
Sasi Chilukuru
Okay, thank you very much.
Kjetil Bakken
All right. Then the next question is from Lydia Rainforth of Barclays. Please go ahead Lydia.
Lydia Rainforth
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 is 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 base side, I understand completely what you’re saying about the reduction in the second half of the year on the cost side, but is this really about being conservative now on the cost guidance? And I’ll leave it there. Thank you.
Karl Hersvik
Yes. Thank you, Lydia. It is all about the good, the bad and the ugly, isn’t it? Well, I think you are 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 projects on track. And of course, we are spending quite a lot of resources to do just that. 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, some in Norway, some abroad and the ramp-up of that activity is actually going as expected. I think I discussed this last quarter, 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. And that means that if one vendor is struggling, we are 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 what you would say, 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 Aker BP.
And then, of course this is a continuous battle. But at this point in time, we’re starting to see the horizon. And you ask 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 is where we spend the most resources at this point in time.
And then your final question was –.
David Tonne
On CapEx.
Karl Hersvik
Are we being conservative? No, we’re not. We try to be extremely transparent in Aker BP about what we actually believe in, and very clear both in terms of guidance on production on cost, on CapEx, and expenditure. So when we are putting out the number we are, it is because we believe that is the real number that the market should expect. And it is 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.
Lydia Rainforth
Brilliant. Thank you very much.
Kjetil Bakken
Thank you, Lydia. And now the next question is from Yoann Charenton of Bernstein. Is that right, Yoann?
Yoann Charenton
Yes. Good morning. Thank you Kjetil. 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 range? 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 this reasonable to expect a seasonal moderation in the third quarter because this is summer, before reacceleration of spend in the fourth quarter?
Karl Hersvik
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. So the first one is the maintenance activities in Q3. And 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 Edvard Grieg, Ivar Aasen and Alvheim. 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 Skarv, to do essential tieback work which will need hydrocarbon-free environment in order to execute it. So that’s basically driving that activity. And then for the 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, you have Tyrving 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 production guidance on the top and the bottom. And the reason that the span is what it is for the full year guidance, even though we have achieved 95%, is those two key factors, right? So it’s not really driven by production efficiency, it is driven by activities and the length of those activities during the maintenance activity.
I will leave the Dated Brent question to you, David.
David Tonne
Yes. So I assume you refer to the near-term tax payment slide, Yoann. So 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, right? And then you can actually infer the price that we have used for setting the tax installments for the first — sorry, second half of this year. So it is quite similar to the $80 scenario, right, for the average for next — or for the second half of 2024 sorry. And then we give the gas price assumption and the FX assumption also on the slide. So $9 per mmbtu and a US-NOK rate of 10 for the remaining of the year.
Karl Hersvik
And then for your third question regarding CapEx, and CapEx ramp-up I can actually assure you, and I do this with — I would say, a lot of subjectivity, there will be no summer break when it comes to CapEx execution or spend.
Yoann Charenton
All right, well noted. Still have a nice summer, if you can.
Karl Hersvik
Thank you, Yoann.
Kjetil Bakken
Thank you, Yoann. And now the next question is from Teodor Sveen-Nilsen from SpareBank 1. Are you there, Teodor?
Teodor Sveen-Nilsen
Good morning. Yes, I’m here. Congrats on yet another strong quarter. Three questions for me. First, on Barents Sea. Karl, you discussed the discoveries in the Barents Sea. I just wonder, how much more gas do you think we need to discover in the Barents Sea before we can justify our 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 Avaldsnes and how much has been produced from Aldous Major compared to the total 2P reserves? And then latest — my last question is what’s the latest on the court ruling on Yggdrasil and Tyrving? Thanks.
Karl Hersvik
Could you just repeat the third question, Teodor?
David Tonne
I think it was related to the court case — related to –.
Karl Hersvik
Court case. Okay, fine. Good. Let’s start with the Barents Sea. Yeah, 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 is a different case. Then you ask how much gas do we need to discover to get to a pipeline. Yes, that’s a good question. Will depend on cost of the infrastructure, the quality of the gas, how much oil is associated, et cetera. There is 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 on year yet on cumulative production from Avaldsnes and Aldous. 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 attacks. Of course, the court case in itself, Aker BP is not a party. So that is going on as it is. And then we are looking at a 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 hearing, and we are now about to finalize that piece of work. So regardless of how the appeal case turn out, we will be in a position to issue the information needed.
Teodor Sveen-Nilsen
Okay. Thank you. Just following up on the Barents Sea, you’re talking about 150 million to 200 million barrels oil equivalent, right?
Karl Hersvik
No. BCM of gas.
Teodor Sveen-Nilsen
BCM? Okay, BCM. Okay, that’s clear. Perfect. Thank you, and that’s all for me.
Karl Hersvik
I mean, these volumes are very, very difficult to assess because if you actually find a lot of associated oil, then of course you are subsidizing the field development. Then you might need less gas to complete that infrastructure.
Teodor Sveen-Nilsen
Sure. Absolutely. I understand it is difficult to assess that. Thank you.
Kjetil Bakken
All right. Then next question is from Victoria McCulloch from RBC. Please go ahead Victoria.
Victoria McCulloch
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 at that field? I appreciate there was a shutdown for Hanz at the field this quarter, but you’re more than 30% down from this time or this quarter last year. So maybe what your expectations are on maybe more of a medium term, or how we should see declines of that field? And then bigger picture, again question to you is, can you give me a bit more color in the CO2 story strategy for Aker BP? Is this optionality at the moment or something you think needs to be part of the company’s strategy and a bigger picture going forward? Thanks very much.
Karl Hersvik
Yes. So both details and big picture. That’s good, Victoria. On Edvard 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 are 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.
And right now we’re actually seeing that we are in that bend where you actually start tapering off the decline rate. And the models are actually working pretty well. So I’m more comfortable that for the remaining of 2024 and into 2025, we’ll see a more stable rate out of the Edvard Grieg-Ivar Aasen hub area. Hanz will offset it to a certain degree, but not entirely. But then there are also infill drills — infill wells to be drilled on Edvard Grieg in 2025. And then, of course, the satellites come on stream in ’27.
So this is kind of conventional oil field practice. It’s just that normally in Aker BP, when we take over these fields, they have already gone off-plateau and we do these kind of re-development cases. In this case, we’re actually following down the track before we’re deploying the redevelopment activities. So we’re just applying the Aker BP model also to the Edvard Grieg-Ivar Aasen hub.
In terms of CO2 storage, I see that as optionality at this point in time. I’ve been really, really clear that Aker BP is a pure play oil and gas company focused on the Norwegian Continental Shelf. And Aker BP 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’d 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 a 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 is a very cheap, call it insurance or optionality for us. Going forward, if this is to be an activity with a significant COP expand we will look at structures that are more optimal towards the Aker BP existing oil and gas activities.
Victoria McCulloch
Super, thanks very much.
Kjetil Bakken
Thank you, Victoria. Next question is from Mark Wilson from Jefferies. Please go ahead Mark.
Mark Wilson
Okay, good morning. Thank you. Good morning gents. My question — the first question is, we’re very clear on Johan Sverdrup oil production capacity, 755,000, and you say with gas it’s almost 800,000 barrels of oil a day. But can I ask what the water handling capacity is, given the discussion on water coming? 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.
Karl Hersvik
Yes. So water handling capacity, that is an interesting question. So right now we’re actually at liquid maximum, and that liquid maximum is being used for oil processing, essentially, right? 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 reinjection capacity could be an issue. At this point in time, we are injecting five times more than we are producing. So it’s unlikely to become a restriction in the short-term. And then you will have, call it, produced water quality issues, which are usually actually a case when you have a low water cut and not a high water cut, because then you get into a water continuous phase. So the way the process plant is set up I think this will essentially be driven by the water cut and the available well capacity and the wells are not driven by topside water handling capacity. I mean this is — to be honest, Mark this is so overdesigned that you can process almost anything.
Mark Wilson
Got it. Okay. Well, my second question and my last one now is, you reiterated expect plateau to extend into very late this year or early ’25. That would infer that those multilateral wells that you are going to bring on next year, you don’t expect them to be able to maintain the plateau in the manner that the new production wells you are bringing on this year do. It’d just be interesting to understand the difference there.
Karl Hersvik
Yes. So, the key difference is that when we are now drilling the last 10 wells, that means that we have a lot of experience with how the existing wells are performing. We are more uncertain on how these multilaterals will be performing when we put them on stream, right? And this is always the case. I mean, we start with being a little bit conservative and then we get more expectancy correct, if you want, as we get more experience. 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 10.75 inch bore production wells that we are currently producing.
Mark Wilson
That’s very clear. Thank you so much. My goodness, 10.75. Okay, I’ll hand it over. And well done so far.
Karl Hersvik
Thank you.
Kjetil Bakken
That was the last question, I believe. So that’s it.
Karl Hersvik
That’s good. And that means that we are not essentially logging off here from the Aker BP 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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