Jadestone Energy plc (JSE) Earnings Call Transcript & Summary

Ladies and gentlemen, good morning or good afternoon, and thank you for joining this conference call to discuss the CWLH acquisition that we announced earlier today. I know it's short notice and so I do appreciate your time and in turn, we'll endeavor to keep this brief. I'm Paul Blakeley, Jadestone's CEO, and I am joined on the call today by CFO, Bert-Jaap Dijkstra, who is in Jakarta today; by Michael Horn, EVP for Business Development; and by Phil Corbett, Investor Relations Manager. On this webcast, we'll take you through a presentation, which was recently uploaded to the Investor Relations section of our website or you can view it via the link on the webcast. And after that, let's take some questions. Moving to Slide 2, which just outlines our standard disclaimer and then on to Slide 3, which I'll use to summarize the acquisition that we announced today. We're really pleased to be doubling down on our interest in the CWLH fields offshore Australia through the acquisition of this 16.67% interest from MIMI. Not only is the acquisition accretive on all measures, providing additional immediate production with significant follow-on potential to add further value, but it also increases our exposure to an asset that is exceeding our expectations from the original entry into the asset in 2022 as well as delivering on one of our strategic objectives to diversify the producing portfolio. So let me walk you through the high-level details. We're acquiring from MIMI, which is a joint venture between Mitsubishi and Mitsui, a further non-operated 16.67% interest in the Cossack, Wanaea, Lambert and Hermes fields and associated infrastructure offshore Western Australia. This will double our existing interest in the fields after we bought BP stake in November 2022 -- sorry, 2022. As a reminder, these are mid-life assets having been producing since the late 1990s with the potential for life extension well into the future for potentially up to another 20 years. Combined, the 4 fields have a very large oil in place of around 900 million barrels and have produced approaching 500 million barrels to date. Jadestone is acquiring 11.8 million barrels of production, reserves and resource based on an effective date of the first of July 2022, for which we will pay a headline consideration of $9 million. The terms of the acquisition are essentially in line with the original BP deal, which in turn was negotiated in a lower oil price environment than we see today. That results in a very attractive acquisition metric of USD 1.70 per barrel or -- of 2P reserves and $0.80 per barrel on 2P + 2C. Due to the free cash flow from the asset since the effective date, we expect there will be a positive completion adjustment resulting in something like $3 million to $6 million net receipt to Jadestone. However, since we will enjoy the benefits of the next lifting at around the same time as the transaction closes, we are really benefiting by a further $50 million to $60 million of interim revenues. The CWLH asset has really impressed us since acquiring our initial stake, particularly the reservoir performance. The fields have, in recent years, exhibited a very low rate of decline at around 4% per annum, which it's significantly less than the 6.5% per annum that we assumed at the time of the BP stake purchase. This is eye-catching in the context of offshore developments of this nature and a testament to the quality of the subsurface setting, but also to the very low production offtake with only 5 active wells. We continue to see significant upside in the CWLH fields, both from infill drilling as well as life extension of the Okha FPSO beyond 2031. We'll continue to make the case for investment targeting this upside to the other JV partners. Like the BP deal, we'll also be prefunding Jadestone's share of the decommissioning costs for the acquired interests. This is in large part a reflection of the heightened focus on decommissioning security in Australia following the collapse of Noga and the government's assumption of decommissioning responsibility for the Laminaria and Corallina fields and the Northern Endeavour FPSO, but it also represents a safe and responsible approach to this key issue and give certainty to all stakeholders on this longer-term obligation. But there are a number of key points to make around this. The purchase consideration reflects this approach to abandon security and is highly competitive and accretive as a result. The projected cash flows associated with the MIMI interest effectively self-fund the abandonment trust payments over 2024 and 2025. And then after this point, forward-looking cash flows from the acquired interests are therefore unencumbered by future decommissioning liabilities, providing a much longer free cash tail. And as a result, also increases the potential borrowing base of the assets in the future. And finally, from a sustainability perspective, it's worth noting that the emissions profile of the asset is comparatively low, benefiting from the principle that all excess associated gas from the field after use for fuel is dispatched as feedstock into the Northwest Shelf LNG plant, and so flaring from the FPSO is minimized. We also continue to believe that core to our climate strategy is the principle that demand for hydrocarbons should be met as far as possible by maximizing the recovery of assets currently in production ahead of any new development. This acquisition is a perfect example of that. So overall, I believe that increasing our exposure and influence in this transformational asset is really a great result for our shareholders. And now as you move to Slide 4. Here, we set out the transaction in more detail. Much of this I've just covered in the introduction, but it is important to note several reasons why these are high-margin barrels. Unit OpEx is approximately $25 a barrel, relatively low for an offshore development of this kind and at this stage in its producing life. We're also acquiring somewhere in the region of $0.5 billion of PRRT credits which we project will ensure that we will never pay any PRRT on this interest in the future. And finally, there's no additional headcount needed to manage this acquired interest. And so now to Slide 5. The CWLH fields are located offshore Western Australia in water depths of between 75 and 135 meters. They are very large oil-in-place fields, with high-quality upper jurassic sandstone reservoirs, setting low relief anticlinal structures. All the fields benefit from strong aquifer support, which really contributes to a very high recovery factor. And as highlighted already, with oil in place of around 900 million barrels and 500 million barrels produced to date, even small increases in recovery factor will have material reserves impact. And we believe from the evidence so far that recovery factors in the high 60s is possible, and that's material. So turning to Slide 6, which provides an overview of the Okha FPSO and the CWLH subsea facilities. The Okha FPSO replaced the original CWH FPSO at the field in 2011. And though it has a nominal 20-year design life, this can be extended through modest investment, which the operator is working through right now. The Okha FPSO is double hold and was designed for mid-life operation. And as a result, it has significant water and gas handling capacity, which is not usual with new greenfield development at FPSO concept. The vessel undergoes a 5-year survey to establish the technical condition of the hole with the most recent major survey occurring in 2021. It has approximately 900,000 barrels of storage capacity with offtakes usually in the 650,000 barrel parcel range. The barrels are lifted on an equity basis with the next lifting attributable to this interest that we're acquiring to be sold in February next year. On the right of this slide, you can see a schematic of the field facilities noting that the subsea infrastructure already has capacity for the tie-in of future infill wells. In addition, there is the option to reuse current idle wells on both the Wanaea and Lambert-Hermes fields, which is a very low-cost option for additional reservoir offtake points in the future. The production data on Slide 7 illustrates how the asset has exceeded our expectations and why the deal is a great outcome for our shareholders. The solid black line on the chart is the 2P production profile that was determined by ERCE as part of the acquisition analysis of the original stake acquired in 2022. The actual performance is a combination of the green spots representing daily production, clearly illustrating the outperformance of the reservoirs versus original expectations with low decline rate and higher uptime at the facilities, all ahead of our initial expectations. There were 2 isolated incidents of facility downtime earlier in 2023. One was process-related and actions to fix that have already been put in place and the other was as a result of Cyclone Aila. And with that introduction, I'm going to hand you over now to Bert-Jaap. Over to you, Bert-Jaap.

Thank you, Paul, and good morning or afternoon to all of you. Let's now turn to Slide 8. This slide shows the expected phasing of these things and cash flows from the acquired interest supporting Paul's earlier comments that the asset is expected to essentially self-fund the abandonment payments over the next 24 months, after which Jadestone receives an unencumbered cash flow stream, attractive to shareholders and our lending banks. The upper chart sets out the projected lifting schedule for the acquired interest in 2024 and 2025. Parcel sizes for CWLH liftings are typically around 650,000 barrels with receipt of proceeds typically 1 month after listing. On the left of the lower chart, you can see the expected closing payment which is a net cash received for Jadestone of $3 million to $6 million with the final amount depending on the actual timing of the transaction closing in Q1 2024. This payment will be made directly into the CWLH abandonment fund by the seller with Jadestone making up the balance of the initial $42 million abandonment installment. This payment as well as the second abandonment installment, which is due after receiving NOPA approval, broadly coincide with the proceeds of the next lifting attributable to our newly acquired interest currently estimated at 650,000 barrels in March 2024 based on the upper chart. This February 2024 lifting is expected to remain unhedged. The next lifting is currently scheduled for late 2024 with proceeds received in early 2025, shortly after we state the third and final installment of the abandonment funding. This third installment will be up to $37 million. The amount could end up being less than that depending on the CWLH operators ongoing work to update the decommissioning estimates for the asset. We expect that the figure will be finalized before the end of the year. Phasing of the revenue from the lift relative to the abandonment payments is a key positive aspect of the deal. These are, of course, projections and therefore, subject to change. But as Paul has shown, the asset operating performance has been stable, and as such, is expected to continue to generate steady cash flow. As such, Jadestone has reasonable confidence in the lifting schedule presented. The experience of gaining similar approvals for the first CWLH acquisition is expected to assist the company in expediting the approvals required for this transaction. Now turning to Slide 9. This slide contains a chart that should hopefully be familiar to many of you now, the borrowing base availability under our reserves-based loan. Last month, we announced the results of the biannual redetermination of the RBL, which updates the banking model and resulting loan availability. Prior to the September redetermination, we had an availability dip in the second quarter of 2024, a challenge with one which we consistently maintained, we could manage through working with our RBL banks. We were as such, very pleased that the September redetermination significantly increased the borrowing capacity in this dip period in Q2 and Q3 2024 from previously $90 million to $149 million now. We are very pleased with the constructive working relationship we have with our banks and are looking forward to continue to work towards integrating this tranche of CWLH, the completion of Akatara and, of course, supporting the business strategy thereafter. We hosted our RBL banks with our Kuala Lumpur office last week, and I don't think they will mind me saying that the visit was very well received and that the banks were impressed with the caliber of our team there and the positive outlook they presented for Jadestone's business and specifically for the Akatara project and the Malaysian business case. We have received unanimous lender approval for the CWLH acquisition required under the RBL facility agreement, and we intend with a separate lender consent process to integrate the acquired interest into our borrowing base, likely through an interim redetermination once the transaction closes. As Jadestone already is on title for CWLH and at the first CWLH tranche is already part of the existing borrowing base, the process to integrate the second tranche is expected to be relatively straightforward. Also, due to the attractive characteristics of the CWLH assets, we expect this to have a positive impact on the borrowing base availability. Finally and importantly, we do not see our liquidity being compromised in this transaction. As you would expect, we regularly stress test our liquidity projections. And with CWLH, we expect to maintain our liquidity buffer, in a combined downside oil price and operating performance scenario. With that, I will hand back to Paul.

That's great. Thanks, Bert-Jaap. And so now moving on to Slide 10, which sets out the ownership structure of the CWLH fields prior to completion of Jadestone's acquisition of MIMI's Interest. Woodside is the operator with a 60% interest in Chevron, owns the remaining 16.67% stake. With today's acquisition, following closely after the BP CWLH transaction, I imagine you might speculate about the possibility of increasing our exposure to this asset further. All I can say is that we believe the asset would benefit from investment, which the current owners are not so inclined to make, and that might create opportunity to further increase our exposure in the future. Now moving to Slide 11, which sets out the timetable of the transaction towards completion. We signed the sale and purchase agreement earlier today and paid a $1 million deposit. The near-term focus will be on obtaining the required approvals from regulatory authorities, principally NOPTA and FIRB as well as consent from the other Northwest Shelf partners under the coordination agreements governing the supply of associated gas from the CWLH fields. On closing, which is targeted for the first quarter next year, the completion adjustment is expected to result in a net receipt to Jadestone, which will be paid into the abandonment trust fund on our behalf by MIMI and then the balance of the $42 million to be paid by Jadestone, reminding you that the next lifting occurs in the same time frame and will largely cover the eCom security installment. The second and third installments will follow later in 2024 with the third installment to be determined once the updated decommissioning cost of the field is finalized by the operator. And again, will occur in the same time frame as the next crude oil lifting. And so now really finishing on Slide 12 with a recap on this high-quality and high-value acquisition, which continues to broaden the production in our business and add considerable value to Jadestone. CWLH is accretive on all measures and the purchase was secured on exceptional terms for us. We were also able to deliver a creative solution to manage the decommissioning security, largely through asset cash flows, and we will enjoy many years of unencumbered cash flow as a result. It's a high-performing asset and will help further bolster our position to influence the partnership towards the upside. Overall, the Jadestone business is performing well. Production stabilized growth through Malaysia infill drilling now and Akatara moving ahead on track for more growth early next year. We have 1.6 million barrels of crude sales planned to be sold in the next 6 weeks, which helps the turnaround towards a strengthened balance sheet. In turn, this underpins the potential to return to growth, including by M&A. And we are in a number of processes, which will hopefully deliver further upside for shareholders. I can promise discipline in what we look at, both in terms of quality, in terms of being consistent with strategy and importantly, to be firmly within the boundary of what we can afford through available cash and debt. In the end, the strategy is as relevant today as ever. The business is in good shape and opportunities are growing in parallel with improving liquidity and an inflection point right in front of us. We will be prudent, diligent and look towards the next steps in building a highly resilient and expansive production business in Asia Pacific. And with that, thank you. And operator, I can hand back to you now to open for Q&A.

[Operator Instructions] Our first question today comes from the line of David Round from Stifel.

A couple of topics, I just want 1 covering, please. The first, Paul, you mentioned $50 million to $60 million due shortly after completion. So that's sort of lifting that's due in Q1. Just to confirm, that is separate and on top of the completion adjustment? And then just be interested, are there any costs that need to be netted off that amount? Or will we just see $50 million to $60 million in your bank account? The second one was maybe 1 for Bert-Jaap, would appreciate any sort of elaboration on the RBL. Are you able to say how much you think this deal will add to the borrowing base and also when you'll have that in place, please?

Great. Thank you, David. That's good. And yes, let me answer those questions in order. The first one, I mean, I think you have to do the math yourself, what are the points -- the data points, 650,000 barrels to be sold at Brent and a slight discount, not sure what the price is going to be early next year, but one might speculate if it were in the mid-$80 range that's what you might think about as proceeds. And it's as simple as that. As Bert-Jaap suggested, payment 30 days later. And so we'll see the money a month after the lifting.

Okay. And you won't have to net off any OpEx or royalties from that number?

I mean we pay operating costs on a monthly basis. As you can just judge from the chart that Bert-Jaap showed. In round terms, it's a little under $2 million a month. That's how you should think about operating costs, $18 million to $20 million a month net for this share of interest, okay? Great. And Bert-Jaap, a little bit of color on RBL. I'll hand that to you.

Yes, sure. Thanks, Paul, and thanks, David for the question. So as you know, the relevant part of your question is what we call the dip Q2, Q3 2024. In our chart on Page 9, we're assuming Akatara being on stream and passing the completion test well early Q3, if you will, which is just an assumption. So you're really talking about Q2 2024 because before and after this period, we're projecting to have basically $200 million, which is the facility limit today. If the banks approve this acquisition into the borrowing base, which is both clearly our base case and what we're expecting that will happen, that dip will effectively be gone. But it completely depends, of course, on what the banks consider in the next banking model because there's a lot [Technical Difficulty] that will be taken through the banking model in March 2024, whether the determination takes place. But this has a very significant potential, I would say, without going into the numbers. But it would take us -- I mean, let's call it will take us to the $200 million if the banks would agree with just taking the banking model as we know it today, plus [indiscernible], but that's subject to change because all of the forward-looking that is sitting in the model, will get an update on the [indiscernible] and we need to see how this all comes out. But that's -- the short version is very significant. I think it will answer the second part, David, [Technical Difficulty] when that's in place, which would be clearly before Q2, if we're trying to -- and what we will do, which is the base case as well. We're trying to integrate this asset into the borrowing base basically at closing, and we're working with the banks as we speak in the background to trying to make that work.

Okay. So just to clarify then. So I mean, if I look back at Slide 8, and I think you mentioned upfront, there might be a short period where you have to fund a small amount of consideration before you get the lifting in February, but what you're saying is actually that isn't the pinch point for the borrowing base anyway. And by the pinch point in Q2, that will hopefully be up and you won't have that dip anyway. So actually, in terms of liquidity and borrowing base and capacity, it looks pretty comfortable.

Yes, that's exactly right. And then, of course, this is all, again, subject to change, but on the base case that you're looking at, we would be looking at $36 million on today's assumption, if you assume $6 million net cash in, just for the -- just to take a number, you would need to fund $36 million. If at that stage, it enters into the RBL under today's terms and the model that we're using today, we would just need to have capacity in the RBL, which is having a capacity of up to $200 million at that stage. And we're currently projecting to have liquidity in the RBL, and it may be close, but it looks like we're getting there, yes.

The next question today comes from the line of Ashley Kelty from Panmure Gordon.

Well done on the acquisition. Just on sort of a couple of operational ones questions. You're talking about the sort of high recovery factor that you could get for the [indiscernible]. What is the current recovery factor and what activity would be needed to get it up to the high 60s that Paul mentioned? And I was also wondering what activity is needed to extend beyond 2031 and what's the sort of time line for any news on expansion?

Great. Thanks, Ashley. Good morning. So let's talk about recovery factors first. All of the fields are of similar quality, Darcy sandstones, and as we said, very strong aquifer support. And so that lends itself to high recovery. The Wanaea field so far is the highest recovery factor and still going strong. It's at 63%, and we project that it will continue to 66%, 67%. And so already with Wanaea, you're starting to see the evidence, the real evidence of what these fields can achieve. And we do see infill opportunities that could take recovery even higher than that. Cossack, the next largest field sits right now at only 53% recovery. And again, we project on our modeling at least going to 67%. So there's a significant margin there. And Lambert-Hermes, slightly smaller fields, but the same story applies. And so I think the evidence is strongly in favor that those are recovery factors that we can expect. And there are pockets, which -- there are pockets and small highs that -- within the structures that simply will not be drained and would require infill wells and that would further improve recovery and accelerate production as well. And that's what we target, if you like, to take the field beyond '31 to 2040 and even beyond that in our thinking. And so there is a -- as we talk about, 2C resource let's say, right now around 6.5 million barrels. Half of that is associated with infill drilling. And the other half is associated with life extension. In other words, no infill wells, but taking the existing production beyond the 2031, which is the work that operator -- the operator has already started. And what would that look like? It's mostly subsea infrastructure. I think what they're identifying is lifespan of some flexible -- subsea flexible lines, maintenance on subsea trees anchor chains, relatively modest costs, but those are the sorts of activities to take the life extension project into the 2040s. And so think about that 2C resource in 2 parts. One, is something that we can deliver without new wells and the other half we'll need new drilling. I hope that gets to your question.

The next question today comes from the line of Matt Cooper from Peel Hunt.

Well, yes, congratulations on the deal. Good to see the positive move in the shares this morning. First question is, can you give some more detail on why the CWLH decline rate has been lower than the initial forecast? How long do you expect this to continue? And could we see a reserve upgrade on the back of this?

Yes. Matt, good question. I'm not sure how to answer that. But in part, let's say, I mean the main reason the recovery factor is lower than expectations, I believe, is because of the very limited offtake. There are only 5 wells in production. I mean 12 to 13 available, but only 5 wells are in production. And so if you think about the Cossack field, for example, only 1 well producing from Cossack, 3 from Wanaea. And so that's really the constraint in production terms. And so one of the things that we would like to consider is how can you change that? Well, can you bring some of the dormant wells back into use relatively modest exercise to do that. That work we'd like to sit with Woodside and see what can be done there. And then, of course, the other thing that would change the recovery factor and ultimately, therefore, a decline rate would be an acceleration that would come from infill drilling. So those are the activities that would change that decline rate, accelerate the production of oil basically is what it would all be about. Okay?

Yes. Okay. That makes sense.

It's that simple.

Yes, I just want to talk around the DCOM payment. So if you make the $402 million payment, I believe that's higher than the $82 million payment relating to the BP, some CWLH stake. So I just wondered if you could talk about why that is?

Yes. Yes. We acquired the BP interest with the DCOM assumptions held by the operator at the time. In a world of high inflation over the last 12 to 18 months, the operator has begun a study to assess whether or not their previous decommissioning estimates are still valid. And that's a piece of work that's ongoing, and we don't know the answer. And of course, as an existing participating partner we will have the right to challenge and ultimately seek to get to the right answer with the operator. In order to conclude this transaction with the support of the partnership who remain on the license, recognizing this work was ongoing. They have asked us to secure or to agree to the principle of the upper end of the range of that decommissioning estimate work. And what we will do is, over the course of the next 12 months, working with the operator, find the right answer and ultimately adjust that final payment, that $37 million to be set at whatever is the final DCOM estimate that Woodside and the partnership agree. And hence, that's a flexible number but with enough a boundary of $37 million. I expect we'll pay a number less than that. We just don't know. But that's the process by which the decommissioning estimate is likely to increase. We just don't know how much. With respect to the BP interest, as a partner before you ask the question, in the Northwest Shelf partnership agreement, there is a methodology during what we call a rundown period in the future, where if this number is adjusted, that would be reflected over the course of a number of years through the rundown period with installment payments being made. So it is quite likely that we would see that come through, but it would be in the future, and it would be over a number of years, and that's how it works.

Got you. Yes, you did preempt my next question. I might just have 1 final one in there, which is just around how much influence you think you'll have at 33% non-operated? And how receptive has the operator been to date in terms of your views around extending the asset and in potential work, et cetera?

Yes. Time will tell. I mean I don't like to talk in negative terms. But the reality is, as now a 33% interest owner, we actually do have a blocking vote on all activity. which we did not have before. So that does allow us, I think, a little more leverage. But I'd rather look at this from the positive perspective that we are really engaged with a high-quality operator and working with them to try to influence activities that will enhance value. The operator is active in looking at the life extension project and model. And we really support that, and we'll work with them to see that being successful. As I said to -- in response to the question from Ashley, I mean that gets at half of the 2C resource already. So that would be a major step forward. I'm not sure how well we'll influence the operator on infill drilling, but separate time.

[Operator Instructions] The next question today comes from the line of Mark Wilson from Jefferies.

Okay. First question, obviously, Slide 8 is very important. Thanks for the clarity on that. So just to summarize. So basically, there's 1 lifting or cash inflow per year for a 16% stake. And last year's BP deal, you said $40 million EBITDA at $100 million. So I imagine that equates to do what, about mid-30s at the current price? Is that correct? And the second point related to that slide is where in the slide are the listings expected time-wise for your current interest, please?

Mark, I'm not sure I got all the question, but we'll give it a go. And if I've missed something, you can remind me. The first point I'd make is it's lifting every -- at current production, 10.5 months, so better than a year, which isn't quite important because, as Bert-Jaap described in his presentation, next year, it just so happens that we'll have 2 liftings for this interest in the year, 1 in January and 1 in December. So that makes quite a difference for the year. So that's the principle, and they are 600 -- plus or minus 650,000 barrel parcels. I missed your next question around that.

Yes, I was wondering where it got -- where in the time line, Paul, the existing liftings are kind, if I imagine...

Yes. The next ex BP equity piece lifting is actually coming up in the next couple of weeks. And so we will see that. And given that each participating owner has their own lifting schedule. I believe the one after that is a Woodside lifting and then the one after that is the MIMI lifting. So that's the way that they're currently scheduled. So we will get a BP lifting, ex-BP lifting this year. And then, of course, the next one after that from our existing equity will be 10 to 11 months, hence in October of next year, okay?

That's great. And then question regarding the partnership just to understand that better. You mentioned that the current owners, and I think you meant this particular stake and not inclined to look at further investment. Just want to confirm that the partnership as it stands now is inclined to look at the further investment that you're talking about? Or is there another potential stake that requires to be done to get a truly aligned partnership. That's the first question. Second one is, does the selling party get their abandonment funds back? Do they get to take them home with them, if you like, from the government? And then just out of interest, who gets the interest on all this abandonment money that is in a pot somewhere?

Let's see how we can get through this. So I mean, in response to earlier questions, what we're doing here is we're trying to work with the group, with the partnership and to promote the right sort of activity for value for the group, for the whole participating group. As I've said, Woodside is a high-quality operator. They see the rationale for life extension investment. And I think we're pretty confident that, that will go ahead in a way that will be really beneficial to all the interest owners. The question in your mind, and I can't answer it and is simply in the alternative investment options open to a Woodside or a Chevron doesn't infill well at Cossack, Wanaea, Lambert-Hermes make it onto the exec com approval's table. And I can't answer that. But you can form your own judgment. And so we just have to see how we can further leverage our current interest and potentially seek to increase it, which we'd love to do. And that's really all I can honestly say about it at this point in time. And then with respect to decommissioning, there is interest rate attributable to the fund that's currently in place. We are the only participating interest owner today who is putting money into the fund. The remaining participants have the credit rating that does not require them to physically fund decommissioning. And yes, I think today, we're getting 4.5% and it accrues in the fund. That's how it works.

This concludes today's question-and-answer session. So I'd like to pass the call back over to Paul Blakeley, for any closing remarks.

That's great. Thanks, Bailey. Sorry. Just had to unmute. Thank you very much, and thank you, everyone, for your time today. And I do appreciate the questions, too. It's really helpful. We hope that the acquisition announced today and the positive operational momentum in the business. gives you the confidence and is evidence that we are turning a corner after some challenging times over the last few months. We feel really confident about the business today. There are some very significant short-term milestones ahead of us finishing off the drilling in Malaysia. Obviously, the Akatara project, which is forging ahead on schedule. And now with this acquisition as well it sort of brings all of the elements of our growth strategy into clear focus today. And we feel good about that. We feel good that we're able to do that. And the team work really creatively to find solutions and add very significant value through everything we do. And so with that, thank you. Please don't hesitate to contact us if you have further questions. And as we look forward to our next trip to the U.K., I hope we'll see many of you in London in early December. Thank you very much indeed.