Good morning, ladies and gentlemen, and welcome to the Jadestone Energy PLC Management Briefing Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we'll conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, April 30th, 2021. I would now like to turn the conference over to Paul Blakeley. Please go ahead. Very good. Thank you very much, Colin. Ladies and gentlemen, good day to you, and thank you for joining this Jadestone Energy Management briefing, during which we will discuss this morning's announcement of the signing of a sale and purchase agreement with SapuraOMV Upstream for Jadestone to acquire interests in four licenses in shallow water offshore Peninsular Malaysia. I'm Paul Blakeley, Jadestone's CEO, and I'm joined on this call from Singapore by Dan Young, Director and Chief Financial Officer, Michael Horn, EVP of Corporate and Business Development, and by Henning Hoeyland, Group Head of Subsurface based in Kuala Lumpur, and Robin Martin, Investor Relations Manager, who's with us by phone from Calgary. In this call, I'll be referencing slides in a presentation which you can find on our corporate website by logging on to www.jadestone-energy.com, where it was very recently loaded under the investor relations section. If you're using the webcast, the slides should be available via the link on your screen now. I'm going to start with some introductory remarks and background on this transaction, followed by a discussion from Henning on the subsurface aspects and the opportunity that's presented by this portfolio. Dan will provide some thoughts on the impact within Jadestone Energy's portfolio, some explanation of how an R/C production sharing contract works, and a timeline to closure. All of this will be listen in only, and after that, with the help of the operator, we'll take any questions that you might have. As usual, we include our standard disclaimers and advisories, which are provided on slides two and three at the front of the presentation, and draw your attention to the cautionary remarks regarding forward-looking statements and non-GAAP measures used in this discussion. I'd also like to explain at this time that we are bound by strict confidentiality rules on certain data or information which might be regarded as proprietary or sourced from activity which is not publicly available. Therefore, for this reason, we may not be able to answer some of your questions. Thank you. Okay, let's turn to slide four, where we summarize the highly accretive acquisition metrics associated with this deal. Adding 12.5 million barrels of 2P reserves and at around 6,000 barrels of oil per day of production, and at an acquisition cost of around $0.72 per BOE in a low-cost, shallow water environment that we know well from prior experience. Importantly, I'd add that we have always viewed Malaysia as a highly prospective jurisdiction for upstream development with an open and transparent regulatory environment, with clear operating guidelines and processes. Of course, we're delighted to be working with PETRONAS again. Having looked at a number of entry opportunities into Malaysia over the past couple of years, this represents an ideal starting point, working both as an operator as well as a partner with PETRONAS Carigali. We're grateful for the pragmatism and cooperation of SapuraOMV as they look to pursue their own strategy with emphasis on gas developments in Sarawak. Like all our acquisitions to date, this is an opportunity that we expect will leverage off our core strengths. With a deep knowledge and experience of operating in Peninsular Malaysia, and in the typical stacked fluvial channels and shallow marine sands of the Miocene age. Given this, we can expect to find upside in well recompletions and new infill drilling programs. I'm going to let Henning talk about that. This is also a low-cost operation given where it is in its life cycle, being accretive to group operating costs at around $18 per BOE and likely to pay back in less than 12 months. As we continue to expand the Jadestone business across the region, the addition of the SapuraOMV Peninsular Malaysia assets represents another strategic move, taking advantage of our historical knowledge and relationships, efficiently deploying some of our existing technical resource from the KL office, and as an established operator in country, being able to access further opportunities to grow and to add value. Slide five summarizes some thoughts on how these assets fit within our sustainability model, which centers around energy efficiency, maximum reuse of existing infrastructure and maximum recovery of already discovered resource. As always, we consider our framework of environmental, social, and human capital, and governance and leadership essential in the decisions we make to add value responsibly, reflecting on our impact and how it can be managed in the most beneficial ways, both socially and environmentally. I've already touched on the idea of minimizing new infrastructure while extracting maximum resource and providing locally sourced product for local use, both in transportation and petrochemicals. This minimizes carbon footprint because no matter how you project future energy use through transition to a lower carbon future, even in the most optimistic scenarios, industrial consumption will still require hydrocarbon-based product for another 20 years at least. Also, pursuing operations as efficiently as possible reduces emissions, discharges, and flaring, and we strive to continuously improve in this aspect of our business. We're also pleased to re-engage with the local community and workforce where we've previously built strong relationships. The assets are very close to the PM3 Commercial Arrangement Area, which many of us were involved with in our prior experience, for example. Our approach then, as it will be now, will be to ensure we support local employment both directly and indirectly, support the local supply chain, as well as the more lasting effect of training and development of the local workforce who are a key part of the operating team. By carrying out new investment that adds reserves and extends field life, we provide for extended employment as a benefit to the national labor. We're also pleased to have an opportunity to demonstrate, once again, our values at work and our leadership through asset operations in Malaysia. We're hopeful that through our corporate approach, we'll provide the highest standards of transparency and open dialogue for the benefit from local communities all the way through to the regulator at all levels. Let's now turn to slide six, which provides a technical overview of the Peninsular Malaysia assets. I've already introduced the idea that this is an old backyard of ours, and the team across all disciplines are very familiar with the rocks, with the operating environment, and with the regulatory processes. With a significant presence already in KL, we anticipate a seamless and efficient transfer of interest and of operatorship. With that introduction and overview, I'm going to hand over to Henning now to give you some sense of the subsurface opportunity, the reserves, and production outlook. Henning, over to you. Thanks, Paul. Hi everyone. I think we are on slide five, actually. We are still on slide five. We can see the four PSCs that we are talking about on the map there. You can see the two operated PSCs, PM323 and PM329. You can see the two, which we will come into more details later on. You can also see PM318 and AAKBNLP, which are the non-operated licenses. We have already very clear views on how we can work together with PETRONAS Carigali with a view of increasing recovery factors through a combination of well interventions and potentially future infill drilling. We are very excited by some of the recent success with well interventions that Carigali have had that boosted production significantly in second half of last year, and that gives us a lot of hope for these assets also going forward. Moving on to slide six. Slide six provides some context to the basin. Before I get into describing the assets in more detail Sorry. We have always said that we have a preference for basins where a team has unique knowledge or expertise. That makes the Malay Basins a really good fit for us. Our Vietnam assets are in fact part of the same basin and shown at the top of the map circled in green. With our technical team in Malaysia, like Paul mentioned, we have extensive experience with the basin across all disciplines, both in terms of development and producing assets. You can see the Talisman assets on the map. That's PM3 to the north and PM3-05, 3-14 to the south. To get into just a bit more detail, the Malay Basin deposition environment is coastal plain deposits consisting of Oligocene and Miocene fluvial to shallow marine reservoir sands. Our subsurface team have extensive experience with these type of reservoirs, both in Malaysia and elsewhere. I'd like to point out that the Malay Basin itself is a very prolific one and with significant remaining upside for a mid-life-focused operator like Jadestone. This basin has been the main focus of development in Malaysia since 1960s. Today most of the assets are still held primarily by majors. We're only now really starting to see some of those players exit. That's obviously good news for us and creates an opportunity set for us to look at more assets as they come to market. Slide seven describes PM323. Let's get into more bit on detail on the reservoir. There are three fields there, Chermingat, West Belumut, and East Belumut. Each one has a wellhead platform which are connected to a CPP at East Belumut, which is then tied into the Tapis pipeline, which takes oil to shore. About three-quarters of the production is from East Belumut. We also see most of the upside on East Belumut. This is a thin oil rim without gas cap, strong aquifer support, and excellent reservoir properties. The oil is medium heavy, 22 degrees API, which is not too different from the Stag fields in Australia. As we see with our Stag fields, the development options here is around tightening the well patterns. We see a significant running room for this and East Belumut with the potential for several drilling campaigns over the next few years. Combining this with low drilling costs makes this opportunity very attractive to Jadestone. Slide nine describes PM329, which has the East Piatu field. This one has a wellhead platform and CPP as well, which is connected to both the Tapis pipeline for oil and a gas pipeline. This is a channelized reservoir, which is supported by aquifer drive and reinjection of the produced gas. We see opportunities for reservoir optimization through gas injection. See potential to restore idle wells to production, as well as the potential for some infill drilling. We have seen some excellent reservoir performance recently, that combined with excellent reservoir properties there and very good performance, we expect to achieve very high recovery factors. I'll just finish off the technical section by saying to me, it's very exciting to add something of this to the portfolio, get immediate uptake in production and reserves, still see a lot of running room. With that, I'm going to hand the call over to Dan. Thanks, Henning. Good morning, everyone. I get to present the most exciting topic for today, which is, of course, tax. On the next slide, we present a generalized overview of the Malaysian fiscal regime. I'll just emphasize the word generalized. This is a WoodMac-based illustration of a generic Malaysian revenue cost PSC that is in its current cost phase. That is where recoverable costs are below the maximum cost recovery threshold. Those of you who have followed the company for some time will recognize this format of slide, which we've provided for every jurisdiction in which we operate. Malaysia's regime is one of the more sophisticated in our region, and so I'll take a minute to walk through the key fiscal elements summarized here on the left-hand side. Firstly, there is a 10% royalty on hydrocarbon production. Production that is effectively allocated to PETRONAS. The revenue cost or RC ratio defines the cost recovery portion of production. The chart on the right-hand side assumes an RC ratio in the 1.4x to 2.0 x range, which in the sliding scale implies a 50% cost recovery oil amount or 50 barrels in this waterfall of the initial 100 barrels. The assumption here on the right-hand side, and noting my earlier comments about being in the current cost phase, is that only 80% of the cost recovery oil barrels of half of the total gross production is required to fully cover costs, and thus, we have 40 barrels in the chart of cost recovery oil. The sharing of the unrecovered amount of cost recovery oil of 50 barrels or the 20% surplus above the current actual costs, meaning 10 barrels, is then split both according to where you are on the RC ratio scale and where the total cumulative production exceeds threshold volume. In this example, the contractor has not exceeded the threshold volume, and in the 1.4x to 2.0 x RC range, 70% of those 10 barrels goes to the contractor under the sliding scales and the balance to the government, or seven and three barrels respectively, as shown in the waterfall. Profit oil splits follow the same mechanism subject to the RC ratio and where the cumulative production is above or below the threshold volume, but with different sliding scales. Here, this results in a 60/40 split between the contractor and the government. There are some additional taxes that apply if oil is exported and a supplementary tax which is applied to the difference between actual prices and an escalated base price. Here that is illustrated at around 7% or seven barrels. The final piece is income tax applied at 38% on contractor entitlement. The unused cost oil, the profit oil, and less the other taxes. This results in a final split of around 45/55 between the government and the contractor. The other attribute I'll touch on is decommissioning. This is an important aspect for any midlife or mature asset and something we always focus on when evaluating assets. Under the terms of the PSC, the contractor must pay into a facilities abandonment cess fund during the production phase of the project. For the four PSCs we are acquiring, the cess funds are fully paid up, meaning there's no further obligations on us to pay for facilities decommissioning. We are, however, required to abandon the wells, which is obviously a much smaller piece of the overall abandonment expense, and something we're exploring to find ways to optimize on costs. That could include using on-platform facilities to abandon wells and doing this on a piecemeal basis as wells water out. For the avoidance of doubt, under the PSC mechanism, abandonment wells expense is cost recoverable. The next slide demonstrates just how material this acquisition is to the Jadestone portfolio. Adding the Peninsular Malaysia assets will immediately increase average production by around 50%. We're not adding this to our guidance right now, but rather illustrating the production impact in the right-hand column of the production chart if we aggregate full-year guidance and the current 6,000 BOEs a day of the acquired assets, and noting the economic effective date is January 1st, 2021. That means when we close the deal in the second half of this year, production will effectively come to us as a mix of equity production barrels from closing onward, plus a closing adjustment to the purchase price. The impact on reserves is material as well and adds 34% to our year-end 2020 figure. We are growing the reserve base of the company by more than a third and growing production by nearly a half, and doing this while remaining entirely debt-free, as we recently announced, and with some very strong deal metrics. The next slide lays out a flow of key events, starting with our signed sale and purchase agreement from this morning. The next step will be to satisfy the deal's closing conditions. There are really just two items to point out here. We need PETRONAS' consent for the transaction, and we will also wait for Carigali to waive their preemption rights across each of the PSCs. Thereafter, we will proceed to closing, which we expect will be in the second half of this year. At that time, we'll pay the headline consideration of $9 million as adjusted for the economic benefits dating back to January 1st this year. We also have contingent payments that can be triggered in upside oil price scenarios and could amount to a total of an additional $6 million. $3 million if we see average Brent oil prices above $65 a barrel in 2021. Separately, another $3 million if we see average Brent oil prices above $70 a barrel in 2022. It's a relatively straightforward sequence of events, and we are very much looking forward to closing the transaction with SapuraOMV and recommencing our working relationships with PETRONAS. With that, I'll hand the call back to Paul. That's great. Thank you very much, Dan. To summarize, I think we're on the last slide now. I'll just say, once again, that we're delighted to announce the acquisition of SapuraOMV's Peninsular Malaysia assets. They're such a natural fit for our strategy, accretive on all metrics, and for which we add significant immediate production cash flow and reserves to the core portfolio, bringing more breadth to the business, improving diversity within the portfolio, flexibility, and further upside value potential. As we've said before, our screening criteria is very strict. We probably discard 90% of what we look at. This was something we really liked. Places us opportunely into the Malaysian upstream environment, that in itself is likely to provide further running room for growth. By acquiring this asset, we're also reestablishing a foothold in a key hydrocarbon province in Southeast Asia, which offers exactly the sort of characteristics we see across the region, with maturing fields and an NOC which is looking for new operators to support the next phase of activity in the basins. Therefore, this becomes a platform we can use to grow from. We already have the leadership team on the ground, and we're very much looking forward to rebuilding our operating presence in-country, re-engaging with PETRONAS, and establishing a significant business in the future there. The final thought for you is that given the purchase price will come from existing cash and our cash generation for the remainder of this year looks strong, this acquisition in no way inhibits our appetite or capacity to take on more significant acquisitions if we find them. I'm really encouraged by the M&A landscape, but we will remain focused on our strict investment criteria as we look for more early or immediate cash flow to underpin further investment and growth through infill drilling and our gas developments. Ladies and gentlemen, it's a really exciting time for us, and we hope you can appreciate the value story ahead. With that, I'll thank you, and let's turn the call back to the operator, and we'll try and take any questions that you may have. Thank you very much. Your first question comes from Chris Wheaton from Stifel. Chris, please go ahead. Thank you very much indeed. Two or three questions, if I may first. Could you talk about sort of what the ongoing level of maintenance CapEx is in the assets? It seems that these don't need very much spend to keep them going, but I'm just interested in whether you can put some numbers around that. Secondly, you talked about decommissioning. There's clearly a cess fund has been established from the historic production going all the way back to a decade or more. Could you talk about how big that fund is and whether that stays with the assets or whether the decommissioning is going to be retained by SapuraOMV and therefore would retain the cess fund? Also, if you can give any information on the sort of split of decom versus platform versus wells, that would be super helpful. Also, just looking at the, Dan, you are right. Sort of the tax is the most thrilling topic we can possibly talk about today. I just wonder if you could sort of help us understand at current oil prices, what sort of unit cash flow the assets are making or what kind of cash the assets have generated year to date. That would be really helpful in terms of being able to cross-check against slide nine. Thanks very much. Okay, Chris. Thanks for the long list of questions. We'll do the best we can. As I said at the outset, there may be some things that we just simply can't tell you currently, whilst we're not the operator and interest owner, but we'll do what we can. In the context of ongoing maintenance spend, I'm not going to break down or get into any details around that. What I might do just perhaps to give you some guidance is suggest that operating cost for this year, which will include a component of maintenance and so on, is across the whole portfolio that the net operating cost to Jadestone for this year would be in the order of just under $40 million, just to give you a sense. Which, of course, divided by the production is where we get our cost metric of around $18 would be operating costs. All I would say on maintenance is the facilities are in good condition. Mostly relatively small wellhead platforms, but with one manned, and they're unmanned, and one manned processing facility. The condition is good. Uptime performance is good. On decommissioning, if you don't mind, I'm actually not going to tell you what the size of the cess fund is currently. It's a quite substantial number. As you say, and this is quite typical within the PSC environment in Southeast Asia. Decommissioning costs are covered by an ongoing cess which is taken from the asset during the production phase. There are a number of different ways in which this is assessed, but most often it's done on a units of production basis. As Dan said, it is, if you like, fully paid up against estimates of facility decommissioning costs. That account is actually not held by the operator. It's held by the government, by PETRONAS, and it stays with the asset. When you acquire an interest in a PSC, any accumulated decommissioning cess stays with the asset, stays with you. I hope that answers that part of the question. As to the split between facilities and wells, it's probably about three to one in our view. Dan made the point that this is an area where, and we have time, where I think we can do some more work and improve on cost efficiency for decommissioning wells. I think we'll leave more of that to later. On cash flow, Dan, can I hand that question over to you? The way I'll answer that question, Chris, is to say that at closing in the second half of the year, we don't anticipate that we will be making a net payment after working capital and other customary closing adjustments and the $9 million headline consideration. I think over time, again, as we're operator, once we close the transaction, we can probably talk more specifically around that. Okay. I understand, guys. Thank you very much indeed. Your next question comes from Nathan Piper from Investec. Nathan, please go ahead. Please. Thank you. Morning, everyone, or good afternoon, rather. Thanks for the presentation. I think what would be helpful to understand, if you can, is just how you've managed to secure such an attractive acquisition. Clearly, OMV is a bit of a strategic seller when it comes to oil, and so maybe that accounts for part of it. It would be good to understand how this deal came together. It'd also be helpful to understand. What scale of packages that you are seeing in Malaysia? I know there's a couple of processes which are public, so maybe give us a bit of a preview for what might be coming through the region. Not that you're going to necessarily do it, but a flavor of the scale of things that you might see. Maybe lastly, and it's maybe a slightly different question to the one before, what do you see as the scale of CapEx that you're going to have to invest here, to either do the infill drilling plan that you've got envisaged, and therefore what the kind of average well cost would be, so we can get a bit of a sense for that. Also what these reactivation works could be. I realize it'll depend upon what you decide to do, and it'll be in your choice to do it. It'd be useful to get a sort of a sense of scale of the spending on an infill well offshore Malaysia. Thank you. Very good, Nathan. Thanks. I might answer the first question. How is this so attractive? Maybe we'll touch a little bit on the M&A, how the M&A market is evolving. I'm going to ask Henning if he could speak a little bit to well costs, and perhaps put a context of around what an annual program might look like. Hopefully that will get the answers to your questions. I think you answered almost your own question when you say, look, there's a strategic context around this transaction. Which for the seller, was an important deal to close, just simply because. I'll take you back even to the OMV side of this partnership, particularly. As you know, in the sale of Maari to us, even at the time in New Zealand, OMV declared an intent to be moving their business far more towards gas and looking to divest what they see as non-core, non-strategic oil production, and hence Maari in New Zealand, and now in fact these assets here in Malaysia. I think there's a very simple principle. It's not necessarily about maximizing proceeds. In any event, these are not large. Very much more about achieving a bigger objective. Of course, if you actually think about OMV's position in Malaysia, they have multi-Tcf gas discoveries under development in offshore Sarawak. That absolutely is their focus. From my perspective, I can easily see how they would want to avoid the distraction of this kind of business, which of course is our bread and butter. At this price, perhaps you're asking, why wasn't there a lot of competition? I think the point I'd make about this is, of course, in that sense, PETRONAS r epresents They set a very high bar for operators to be accepted into Malaysia. I think by that very fact, there was probably relatively limited number of companies that were able to attend the data room. I don't know that for sure, Nathan, I can only imagine. Moving to M&A, I think it's a really exciting time. I think there are signals of much greater deal flow occurring. I think there is still always the traditional challenges of sellers' expectations on price being met and numbers of counterparties still perhaps not, certainly not nearly as much as you might see in a process in the U.K. or elsewhere. I think that's challenging. I won't say anything about other complications with regulators and such like. The underlying point is there's a strategic shift going on right now beyond the regular maturing asset time for the major to move on because it's no longer material kind of story, which we've seen historically. There's now this greater influence, perhaps, of lower carbon strategies which may be accelerating divestment. I think that's really exciting for us. I don't want to get any more specific than that. We see things from $10 million to $1 billion. In the end, it always remains around our investment criteria. Can we create value that differentiates us from the seller and from other bidders? If so, that excites us. I think we'll see how the next 12 to 24 months play out. Now to scale of capital. Let's say, on an annualized basis, typically, what might that look like? Henning, would you like to provide some thoughts? Yeah. I'll provide some thoughts around the drilling cost. East Belumut is likely where we'll see the more continuous ongoing drilling for several years. We've looked at the historical costs and historical drilling campaigns. We're probably going to be looking around four wells per campaign. Of course, it's too late for us to get something ready for next year, but 2023 will be the first year we would consider. Those four wells will probably cost in the region of $20 million for all four combined, so around $5 million a pop. That is also in line with recent drilling performance from the current operator. We're of course going to look at potential savings there, and we already identified a few areas where we can potentially push costs even lower. The significance of these kind of lower costs, of course, is compared to other areas where it is more expensive, is that you can drill a lot more wells, and you can tighten the well pattern a lot more and still make it economic and still add value. That's really exciting for us. It means that we can have a lot of drilling campaign for many years to come. That's it. Sorry. It's okay. Thanks. Nathan, anything else? Yeah, just one final one. Not to be a party pooper, but I assume this time around the approval process is a bit more like clockwork, I guess, given that you're talking to PETRONAS directly, and they're familiar with you in the first place. Yeah. Of course, one can't take anything for granted, but PETRONAS run a very rigorous process, the first principle of which is who is allowed to even access the data. In providing that approval, that's a pretty strong signal around having satisfied PETRONAS on capabilities, technical, financial, and so on. Let's see how it goes. There's an automatic preemption potential from the upstream operator, Carigali. There's the formal MPM regulatory approval process. We hope it'll be a lot quicker and a lot smoother than we've experienced recently. Okay. Thank you very much for all the detail. Thanks. Your next question comes from Mark Wilson, from Jefferies. Mark, please go ahead. Thank you. Good morning, gents. On the face of it, an amazing deal, as you say, by the completion date, they're likely paying you to take these off your hands. Could I just check here? On the preemption rights, are they on the whole package as one or on a per license basis? If there is any particular license that if that happened, might preclude you from taking the whole deal? That's the first question. The second one is, a lot of questions about the decom and production. I'm just wondering how many wells there are across these four assets and also how many are under production today. Thank you. Okay. Thanks, Mark. Just a heads up to the team. Henning, I'm going to ask you to talk to the numbers of active wells and total well count. Michael, as head of business development and the architect behind the work to get this deal to where it is today, perhaps you could talk to the principles around preemption. This is a corporate acquisition, Mark, but I'll let Michael fill in the detail. Mark, good morning to you. Michael Horn speaking. With all due respect, I don't feel comfortable answering your question. The terms of the SPA are strictly confidential. You are asking for a level of detail that I simply don't feel that it would be appropriate to discuss. If we could just simply take a step back, Carigali enjoys a preemption across all the licenses, each discrete, separate individual license. If I might leave it there, please forgive me for not being able to provide any greater detail at this stage. Okay. No, I understand that and appreciate it's a corporate transaction. Yeah, okay. Let's move to well. Thanks. Sorry about that, Mark. Thanks, Michael. Good. Henning. Yeah. I'm just counting really fast in my head here now. If we look at PM323, where we have a majority of the wells on the operated side, we're sitting with close to 30 wells at the moment, probably a little bit above that. In terms of idle wells, we probably have eight idle wells at the moment for various reasons. Some of them need interventions. Others are shut in for facilities limitations on the gas side, which we're working on, which we can debottleneck and bring back. There's not a large idle well stock here. There are quite a few assets in Malaysia which have a lot of idle wells, and we've looked at a lot of those. There aren't that many idle wells here. East Piatu. We have 12 wells, or 13 wells, 12 oil producers and one gas producer, where we have seven of the oil producers active, five idle, and the gas injector is also active. These are idle due to capacities a bit, mostly, but also some wells are being cycled at times. On the Puteri-Padang, which is 318, we have probably four active and two idle wells, it's a relatively low well count. If you look at AAKBNLP, we're probably also looking at eight active and maybe four idle. The majority of the wells are active. There are active well interventions campaigns on the idle wells. If you look at East Belumut, which probably has more idle wells, actually, these are slots we'll use for future sidetracks. There's not wells that we would abandon for abandonment sake. These are wells that we will actually abandon as we go along and then drill more new wells. If you want a number, so far they've actually already P&A'd 14 wells in East Belumut due to ongoing drilling campaigns. That's what we see going forward, meaning that we'll keep on sidetracking wells, very similar to Stag, and then do the abandonment on these wells at the end of the economic life. Okay. Yeah, obviously very much an ongoing work program on these fields. You mentioned also, Henning, that the production in the second half of last year had actually seen a step up from activity last year. Any more details you can give on that? The non-operated assets had quite a lot of activities on production enhancement through well interventions, the PM318 and AAKBNLP. They have issues with both scale and wax. They've done some stimulation jobs and some cleanout jobs, which gave much better than expected results. I don't think I can share too many numbers here, but it was a significant bump in production for those two assets. That might not last that long, but it shows the potential for us to go after more rounds on that. That was the big bump there. The other one is East Piatu is still performing really strongly with the reservoir, and East Belumut is probably more in line with forecasts. Okay. Thank you very much for your time. Thanks. I'll hand it over. Thanks, Mark. Your next question comes from Matt Cooper from Peel Hunt. Matt, please go ahead. That's great. Thank you. Well, congratulations on the acquisition. I wondered if you could talk about the shape of the 2P production profile going forward, and also maybe just give a little bit of color on quantifying the size of the upside that you're looking at in terms of potential reserves or production adds. Final question, I just wanted to double-check when you say you're only required to pay for the abandonment of wells, is that just new wells that you drill? Thank you. Okay. Thanks, Matt. With respect to production and so on, I think we'll keep the answer relatively simple. The first point is, on the two key operated PSCs, there's a PSC expiry on each of them at different dates. One's 2028, the other's 2031. We still have a significant amount of time left, and let's say up to 10 years. At that point, of course, to any point, you can look to renew the PSC. In recent years, PETRONAS h as shown themselves very willing to do that on the principle of agreed future and additional investment. I think what Henning will be trying to do is maintain plateau, or I should say, the current production level for as long as possible with infill programs. That would be a great outcome if we could hold that for several years. I think it's too early to talk very specifically. That's something that perhaps once we're operator and once we've had some time hands-on, we'll be able to talk to that, Matt. In terms of the wells abandonment, perhaps, Michael, under the terms of the PSC, you could give Matt some reference to the principles around which wells would qualify to be abandoned by Jadestone in the future. Matt, good morning. It's all wells. To answer your question, it's not just the wells that you are responsible for drilling. You inherit a responsibility for all prior wells in terms of the abandonment obligation. I think Dan has already touched on, and Paul has, as and when you come to abandon, you'll want to do it in the most efficient manner possible, and that will be something that we'll be very focused on. I think that's the short answer to your question. Okay. Thanks, Michael. Okay. Sorry, go ahead. Oh, sorry. Yeah, I just wanted to clarify on that final point. The existing fund doesn't necessarily cover abandonment of all existing wells. Is that correct? That's correct. That's correct. That's correct. Okay. Understood. Yeah. That's great. Thank you very much. Yeah. Just to remind you, as you heard from Henning, if you see multi-well drilling campaigns over the next several years, many of the wells will be naturally recycled. The slots recovered to be reused through sidetracks. The well count may not change very much, but there'll be a lot of recycling. Your next question comes from Ashley Kelty from Panmure Gordon. Ashley, please go ahead. Good morning, gents. Well done on the acquisition. Actually, I don't actually have any questions now. You have extensive answers to the other questions have covered off the points that I was wanting to ask about. Nothing from me. Thanks. Great. Thanks, Ashley. Next question comes from Ian Crossdale, a private investor. Ian, please go ahead. Hi, guys, and congratulations on what looks to be a fantastic acquisition. Couple of questions. What's the actual sulfur content of the oil, and what sort of premium? You've indicated the small premiums of Brent. Can you give an indication for that? Lastly, what's the split between the operated and non-operated barrels of oil per day? Hi, Ian. Thanks for the question. Dan, when we talk about barrel value, do you want to pick that up? The production split is very roughly two-thirds operated, one-third non-operated. The margin on the oil is basically sold with reference to Tapis or another benchmark that trades very close to Tapis. Historically, the Tapis differential before COVID was pretty attractive for $4, $5, $6. At the moment, the Tapis differential to Brent is compressed, and it's most linked to naphtha and to jet fuel demand. As we see petrochemical demand grow over time with global economic growth and people flying again, flying more frequently, we should see that differential start to improve. The answer is it's basically priced with reference to Tapis or another crude, which price is close to Tapis. The sulfur content? I don't believe we can tell you that at this time. Okay. Thank you very much. Ladies and gentlemen, should you have a question, as a final reminder, please press star followed by one. Okay, it appears there are no further questions at this time. Please proceed. It appears there are no further questions at this time. Thank you, operator. Searching for the unmute button. Ladies and gentlemen, it just remains to thank you for your interest in Jadestone and for participating in the call and for your questions. We appreciate it. As I've already said, we're excited by progress and of course, particularly to be able to announce this next step with the SapuraOMV asset acquisition. We really like the opportunity. We'll be working very closely and cooperatively with the seller all the way through to closing, which we anticipate to be in the second half of this year. And of course, as we've said already, re-engaging with PETRONAS and other key stakeholders in Malaysia. As and when we can, we look forward to providing updates, more details in due course. In the meantime, once again, thank you very much indeed. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.