Good morning and welcome to Gulf Keystone 's 2025 Half Year Results. I'm Jon Harris, CEO, and I'm joined by our CFO, Gabriel Papineau-Legris. Over the next few slides, we'll run through our operational and financial performance in the first half of 2025 and the outlook for the remainder of the year. Following that, we will open up the line for questions. Next slide, please. This is our regular legal disclaimer, and I'll leave you to review at your leisure. I'd like to remind those listening that the presentation slides are available on our website. Next slide, please. We delivered a strong operational and financial performance in the first half of 2025. Consistent demand from the local sales market in Kurdistan and good reservoir performance enabled an increase in production relative to the same period last year. Capital and cost discipline continued to underpin free cash flow generation, funding the payment of a BMD 25 million interim dividend in April. We remain focused on safe operations, extending our track record of zero lost time incidents to over 950 days. We are pleased to have recently ramped up production and back towards full well capacity following the temporary shutdown of the field in July after the drone attacks on neighboring oil fields. With the return to stable sales and our robust cash balance, we are pleased to declare another BMD 25 million interim dividend to be paid on September 30, increasing dividends paid and declared in the year to date to BMD 50 million. We have also taken the investment decision of installing water-handling facilities at our Production Facility 2, which is an important milestone for the company. As we focus on maximizing shareholder value from local sales, we also continue to engage with government stakeholders regarding the restart of exports, turning now to our production and local sales performance and outlook. Next slide. Gross average production increased 12% in the first half of 2025 to 44,100 bbl of oil per day, over that of the first half of 2024. The improvement was driven by consistently strong local market demand between January and May 2025, enabling monthly gross average production above 45,000 bbl of oil per day. High volumes were also supported by good reservoir performance, with our production optimization program enabling us to offset declines and well maintenance. We saw a reduction in sales in June due to trucking shortages around Eid al-Adha, a religious holiday, and conflict between Israel and Iran. In mid-July, we shut the Shaikan Field as a safety precaution following drone attacks on neighboring oil fields, reacting quickly to move all staff and contractors to safe locations. At the beginning of August, following a security assessment and consultation with the Kurdistan Regional Government, we restarted production and progressively ramped up through the month towards full oil capacity. We continue to closely monitor the security environment as we operate the plant, and we have also introduced increased security protocols. Average realized prices for local sales in the first half of the year are BMD 27.80 a barrel, a slight increase relative to last year. We have continued to sell at prices around BMD 27-B MD 28 a barrel since June. Looking ahead, we have timed out 2025 with gross average production guidance between 40,000 bbl and 42,000 bbl of oil per day. Through regulatory press, the production losses from June through August disrupted, which amounted to around 1.3 million bbl, or around 2,500 bbl of oil per day annualized. We have additional well optimizations planned in the remainder of the year as we continue to manage natural field decline and certain wells constrained by water and gas. The guidance remains subject to local sales demand and a stable security environment. Moving on now to field activity. We spent around BMD 13 million of cash in headcount base in the first half of the year, in line with our disciplined guidance for 2025. Work to date has included implementing the program of safety upgrades at our Production Facility 2, with installed equipment expected to be tied in next year during the rescheduled shutdown. We have also been executing a variety of production optimization initiatives on certain wells. We are really pleased this week to sanction the installation of water handling at Production Facility 2. This is an important milestone for the company, which we have long envisaged as part of the development of the field and its natural lifecycle. Engineering design work has begun and commissioning is currently expected at the beginning of 2027. The facilities will add an additional wet oil processing capacity of around 17,000 bbl of oil per day to the Shaikan Field's existing dry oil processing capacity of 60,000 bbl of oil a day. Once operational, the new facilities are expected to unlock an estimated 4,000 bbl- 8,000 bbl of oil per day of incremental gross production above the anticipated field baseline from existing constrained wells. The ability to produce wet oil will also reduce the downside risk to reservoir recovery. To reduce costs, we are bringing second-hand facilities to Production Facility 2 and combining them with an existing but unused oil track from the previous expansion program, which was suspended in 2023 with the closure of the pipeline. To minimize upfront capital expenditure and provide flexibility, the facilities will be leased over multiple years following commissioning. Limited incremental net CapEx is expected in 2025, and the total costs ahead of commissioning are estimated at around BMD 12 million net to GKP. Facilities are expected to generate positive cash flow even in a local sales environment and at the low end of the incremental production forecast I just mentioned. Looking ahead to the remainder of the year, we are now expecting cash net CapEx of BMD 30 million- BMD 35 million in 2025, a slight increase versus previous guidance of BMD 25 million- BMD 30 million, primarily reflecting the incremental net CapEx associated with the water handling project we have just sanctioned. We continue to expect around BMD20 million of net capital expenditure on the Production Facility 2 safety upgrades and the BMD 5 million- BMD 10 million related to the production optimization program. Next slide, please. Update on Kurdistan exports. We are continuing to engage with the government stakeholders regarding a solution to restart Kurdistan exports through the Iraq-Turkey Pipeline. We have seen increased momentum towards the solution in recent weeks as we remain focused on securing written agreements on paying maturity for past and future oil sales and the preservation of our contractual rights. We are ready to restart exports quickly provided we have the right agreements in place. We continue to see a number of sources of potential value to Gulf Keystone on the restart, including operational leverage to higher realized prices, the full repayment of outstanding receivables, a stable commercial environment enabling us to develop the Shaikan Field's significant estimated 2P reserve space of around 440 million bbl of oil and recognition by Iraq for Kurdistan's oil and gas industry, potentially reducing our cost of capital. The restart of exports would also be a significant positive for Kurdistan and Iraq by unlocking additional revenue from a vital source of global oil supply. With that, I'll now hand over to Gabriel for the financial review. Great. Thank you, Jon. In the first half of 2025, we delivered a resilient financial performance. Increased EBITDA from stronger production combined with capital and cost discipline enabled continued free cash flow generation, in turn funding a BMD 25 million dividend and reinforcing our robust balance sheet. Next slide, please. Adjusted EBITDA increased 13% to BMD 41 million in the first half of 2025. The improvement was primarily driven by the 12% increase in gross average production to over 44,000 bbl a day and a higher average realized price of BMD 27.8 per barrel. Stronger volumes and prices, combined with lower G&A expenses, more than offset the increase in operating costs and share option expense. Turning now to operating costs and G&A. We continue to exercise tight control of our cost base while safely maintaining the production capacity of the Shaikan Field. Gross OpEx per barrel was flat at BMD 4.2 per barrel versus last year's first half as we maintain our leading industry cost position. The 13% increase in operating costs, BMD 27 million, reflected higher production and increased well service costs spent on bringing two wells back onto production. Other G&A expenses decreased 15% to BMD 4.6 million in the first half. The performance so far this year means that we are pleased to report today that we are on track to meet our 2025 guidance for operating costs between BMD 50 million and BMD 55 million and for other G&A expenses under BMD 10 million. Next slide, please. On cash flow, we generated BMD 25 million of free cash flow in the first half of the year relative to BMD 27 million a year ago. Stronger adjusted EBITDA more than offset the increase in net capital expenditures, working capital, and other cash outflows. Net CapEx in the first half of the year was BMD 18 million, or BMD 13 million on a cash basis after excluding a BMD 5 million non-cash charge associated with reclassification of drilling inventory purchased and paid in 2022 and 2023. Free cash flow funded the payment of the BMD 25 million interim dividend paid in April, while BMD 4 million were also used to fund share purchases by the Employee Benefit Trust to satisfy the 2022 ELP vesting. Our cash balance was broadly flat at BMD 99 million at the end of June, and since then, liquidity has improved to BMD 106 million as at yesterday. Moving on to capital allocation and shareholder distributions. We have a consistent track record of balancing investment with shareholder returns while maintaining a robust balance sheet. We've delivered against this strategy for many years now, and it is the cornerstone of our investment case. In the current local sales environment, we are taking a specific approach to capital allocation. In terms of field development, our focus is on safely maintaining our existing production capacity and reliability, as evidenced by the recent sectioning of the water handling project. Looking at our balance sheets, we are focused on preserving a certain level of minimum cash to fund this essential investment while managing the operating environment. We are committed to returning excess cash to shareholders in line with our clear shareholder distribution framework, which includes semi-annual dividend reviews and the opportunistic consideration of share buybacks. Given the recent return to stable sales and the current liquidity position, the board has approved the declaration of an additional BMD 25 million interim dividend to be paid on the 30th of September, bringing total dividends this year to BMD 50 million. The dividend decision has been taken, recognizing the potential liquidity required to transition from prepaid local sales to exports. In an export restart scenario, we plan to review our approach to investment and broader field development. Higher realized prices from exports would make growth investment more attractive, in particular as the recovery of the cost pool is accelerated. We would also expect to review the current distribution policy with the objective of providing investors with additional predictability on future returns. With that, I will now hand back to Jon to wrap up. Thanks, Gabriel. To summarize, we've delivered a good performance in the first half of the year with higher production, prices, and capital discipline and cost control generating free cash flow. We've continued to execute our disciplined work program to safely maintain the well capacity and the reliability of the Shaikan Field, and have taken an important step towards unlocking incremental production and reducing reservoir risk through the sanction of water handling facilities at Production Facility 2. Looking ahead to the remainder of the year, we are now focused on delivering a tightened gross average production guidance range for 2025 of between 40,000 bbl- 42,000 bbl of oil per day, subject, of course, to stable local sales demand and the security environment. We have increased annual net CapEx guidance slightly to BMD 30 million- BMD 35 million, reflecting the incremental investment in the water handling. OpEx and G&A guidance remains unchanged. Following the return to stable sales and further improvement in our cash position since the end of June, we are pleased to declare an additional BMD 25 million interim dividend to be paid on the 30th of September, increasing total dividends paid and declared in 2025 to BMD 50 million. Finally, we are continuing to make progress towards unlocking the restart of exports. We continue to push hard, and we are hopeful of nearing a solution. With that, I will now hand you back to the operator for Q&A. Thank you. Thank you very much, sir. Ladies and gentlemen, as a reminder, for any audio questions, please press star one on your tablet or keypad. Just make sure that your line is not muted in order to let your signal reach your equipment. Our very first question is coming from Werner Riding of Peel Hunt. Please go ahead. Your line is open. Thank you. Morning, everyone. Just a question to sort of understand a bit more about CapEx and what the total gross water handling CapEx is between now and commissioning in 2027. That's the first part. All right. Okay. Thanks, Werner. Sorry, I thought I'd give you a pause rather than just ask them all in one go. Right. Okay. Fair enough. That's fine. Yeah. The total CapEx between now and the start of commissioning in 2027 is BMD 12 million. Perfect. Thank you. Just following on from that, can you perhaps give a feel for what you'd expect your, I guess, CapEx at the moment? It's relatively modest. What that would increase to above and beyond the water handling when the pipeline restarts and you accelerate investment in drilling and other related spend again? I'm sure, yeah. I mean, I think obviously we would look to restart our drilling campaign. That will take some time following opening of the pipeline and surety of payments. We would look to restart drilling. That will take a little bit of time. Depending on when that speed or when that occurs will depend on kind of if you're looking at annual spend budget next year, a bit difficult to predict. Other than, say, we were to drill two wells, two wells would be notionally BMD 40 million net to GKP on top of this existing budget. There may be a few other bits and pieces that we would look to do improvements around that we've been kind of, we've been delaying as a result of our cash position currently. All right. Thank you. Thank you so much, sir. Our next question will be coming from Charlie Sharp of Canaccord. Please go ahead. Yes. Good morning, and thank you very much for taking my call. Can I ask you, if I may, a sort of three-part question? I know it's a bit of a naughty thing, but analysts always do that. The first thing is just a reminder of what the current throughput is at PF1 and PF2. Secondly, do you see the water handling project at PF 2 kind of being rolled over, if you like, onto PF1 additionally next year? In other words, maybe PF1 might be sanctioned, yes, next year and lag 12 months for P F 2 water handling. Following your comments about drilling, perhaps next year if there are exports, do you think that there may be drilling even if there are continued local sales? Okay. First question was throughput PF1 and PF2. I think we already said the capacity of PF1 and PF2 are about 30,000 bbl, 31,000 bbl a day of dry oil each. Current throughput is 26,000 bbl a day through PF1, 19,000 bbl through PF2. Will we put water handling next year at PF1 following PF2's installation next year? The answer is the wells that feed PF2 are lower in structure and therefore, the whole structure is slightly tilted to the east. The wells are slightly lower and therefore closer to the aquifer. What we've seen is a number of wells are constrained at PF2 and we don't have similar issues at PF1 at the moment. In the lifecycle of the field, we would expect the water to encroach on PF1, but it isn't a next-year problem. It's later in the development cycle. I'm not going to hazard a guess at what that will be, but there are plans to put it in, but it's not soon, hopefully. Would we consider drilling in local sales? I think if there was a stability around that, around a kind of geopolitical solution, and we thought that that was going to be the remaining intent going forward, but that isn't the intent. Of course, the intent is to export. If that were, we may well consider drilling, but it's not something we are contemplating at this moment in time. That's perfect. Thank you. Thank you very much, sir. Next question will be coming from David Round calling from Stifel. Please go ahead. Your line is open, sir. Great. Thanks, George. Can I start with just a follow-up on Charlie's question there on the water handling, please? On the P F 2, I remember we talked about it years ago, but would you mind just reminding us how many wells are constrained by water, what the handling is there at the moment, and where you hope to get to? I don't have those numbers to hand. I'd appreciate just a bit of color around what you're producing at the moment. Second question, just on the export pipeline, and I guess it's probably another way to ask about the drilling, but if it was to reopen tomorrow, to what extent could you ramp up production? I suppose I'm taking a baseline from maybe your 47,000 bbl, 48,000 bbl you were doing at the start of this year. Could you go much higher than that? Finally, I'll call it a third part. On the pipeline again, you've talked about there's progress, terms are being discussed. What compromises around terms are you prepared to accept, if any, to access better prices? Thank you. Okay, David. Thank you for your questions. I think your first question was around, all right, what's our current capacity at PF 2? The current production, I think I just said to Charlie, was 19,000 bbl a day today we're currently producing. I think a handful of wells are constrained. They're not shut in, but we have a number of wells which, how water production manifests itself is we see the salt content increase at the wellhead. What we have to do is we kind of choke the well back slightly to limit production on that well. The salt stops and we can produce what we say is water-free oil. That's the kind of mechanism. The third drain that we're installing at PF 2 will allow us to take the water out and the salt out because there's a salt limit, quite a low salt limit on the export pipeline. That's why we need it. In fact, local sales are the same as well, to be honest. I think the other thing was about once we start exporting, how, what can we ramp production up to? To be clear, we are at our maximum deliverability from our existing wells. Opening an export pipeline doesn't give us any additional well deliverability because that's the joke. It's wells. It's not export. It's not local sales. It's the well deliverability. By installing PF 2, we would hope to see somewhere between 4,000 bbl and 8,000 bbl a day of additional dry oil production. That's what we're expecting to get at the end of 2026 when we commission it early 2027. I hope that answers that question. On the pipeline terms and compromises, I think you'll understand now. I think we've been clear about what we expect to get in order to put oil in the export pipeline. We've been very clear, actually, in terms of public statements. What I will say is that we are having discussions and negotiations, but really, I'm not prepared to discuss that until we've kind of landed those. I'm not going to give you any details, I'm afraid. Okay, that's fair enough. Thank you for that. Thank you for your questions, sir. Our next question will be coming from Teodor Nilsen calling from SB1 Markets. Please go ahead. Good morning, Jon and Gabriel. Thanks for taking my questions. First of all, I'm just following up on the export pipeline. Of course, I understand it's extremely hard to have any good visibility here, but still, do you have any sense of timing here? What do you plan for in terms of timing for the reopening? Second question that is on dividends. Let's assume that the export pipeline reopens before year-end and that you're able to export oil in 2024, except global oil prices. How should we think around dividend in that scenario? I would assume that that would maybe increase. Final question that is on the M&A landscape in Kurdistan. Of course, hard to do deals in Kurdistan now, but pure conceptually, would you look for more assets in Kurdistan or just still your main strategy to produce as much as possible from Shaikan and then distribute any excess cash to shareholders? Thanks. Okay. Thank you. I don't want to hazard a guess on export timing, when they will restart, other than obviously I've become more optimistic recently as we're starting to have negotiations. I don't want to hazard a guess of when they might resolve satisfactorily. Sorry about that. Gabriel? Yeah. On your question on the dividends, when the pipeline comes in and the realized price is coming to international levels, as I mentioned earlier, once we go back to the export pipeline, we're also going to revisit our investment and the timing of those. As Jon mentioned around, for example, returning to drilling, other facilities increase, obviously there's going to be a timeline as to when that actually turns into cash going out the door. Absolutely, the dividend side and capital distribution as a whole remains a very important part of our strategy. We're not at a moment to think that we're just going to stop distribution to focus solely on CapEx. The other bit to just be very, very minded, and I'm very cautious on this, is whenever we get into the pipeline going, is actually the cycle of the payments. Now it's very straightforward because local sales will get paid upfront. Payment surety is probably on all the IOCs' mind on when we put the oil back in, what's going to be the cycle of the money coming back to us. That's also going to be an important factor as we deal with capital allocation, whether it's CapEx or distribution. I would just perhaps bear that in mind in terms of the cycle of the future oil sales and the export. On the M&A landscape, as we've said in the past, we don't have any rush or requirements to deal with M&A. We have fantastic assets with a lot of upside, and we could definitely grow production from here. Absolutely, if we see some opportunities to increase value for our shareholders with opportunities in Kurdistan and reduce costs, improve cash flows, and overall distribution capacity, absolutely we'll look at this, but this is not one of our priorities at the moment. Understood. Just to laminate, has it been on the agenda to expand outside Kurdistan, or will it still remain at the Kurdistan company? Yeah, at the moment, our focus is Kurdistan. Okay, understood. Thanks. That's all for me. Thank you, Mr. Nilsen. We'll now go to Christoffer Bachke calling from Clarksons Securities. Please go ahead. Hi guys, congrats on the first half of the year, strong first half, and thanks for taking my question. Most of my questions have already been answered, but I have one last question on shareholder distributions. How do you think about the balance between buybacks and dividends going forward? Also, looking ahead, do you have any minimum cash buffer above which you would target to return excess cash to shareholders? I know you had touched upon this already, but a bit more color would be appreciated. Yeah, yeah, no problems, Christoffer. I'll just take this in turn. In terms of the minimum cash, we've always been focused on ensuring that we have enough liquidity for about more or less a year of spend, just getting us sufficient headroom to navigate the transition back into the pipeline, any payment side of it. This is obviously going to evolve over time, as I mentioned, with the pipeline or not. At the moment, we've got around BMD 105 million or BMD 106 million, BMD 25 million. We think that BMD 80 million is still a level that we're comfortable at, kind of minimum cash to get us going in local sales. We're going to revisit this in due course. For the time being, we feel that it's the right level for the company. In terms of shareholder distribution between buyback and dividend, on this one, we take an approach and get the feedback from shareholders. Some shareholders have clear preference on dividends, but also to a point that comes at the level of the share price. We've seen the share price very strong over the last few months. For the time being, we're focusing on ensuring that twice a year we're delivering some distribution on the dividend side of it. If we see opportunistically the value for shareholders throughout the year, we want to remain agile and be able to act quickly on this if we see an opportunity. Great caller, thank you very much. Thank you for your questions, Christoffer. As we have no further audio questions at this time, I'd like to turn the call over to Rosie, who will take questions submitted by webcast. Thank you. Thanks, George. We have a number of questions that have been submitted on the webcast. Our first is, "Hi Jon, please can you tell us the difference in production volumes from investing in water handling at PF 2 versus drilling two new wells? A great set of results today. Well done. Thank you. Thank you very much. Yes, certainly. I think the question was asked already, but the CapEx to install this water handling is BMD 12 million, and the cost to drill two new wells is between BMD 35 million and BMD 40 million. The production from two wells would be somewhere between 6,000 bbl and 8,000 bbl, and we're expecting somewhere between 4,000 bbl and 8,000 bbl from already constrained wells that we've already drilled. Looking at that, you will understand that the kind of return is much better on the water handling. It's not really a subtlety. With the production of oil fields, oil from oil fields which are underlain by water, over time, as you take the oil out, the water encroaches on your wells, and therefore you get to a point where you have to deal with the water or you have to shut your wells in if you can't deal with the water. This is a situation where at the moment we have a number of wells that are constrained but not shut in. It might become to the point where if the water production increases, we can't deal with it by choking the wells back. We'll have to shut them in. This is a kind of downside risk mitigation that we're also installing. It's not just a straight investment decision of one versus the other between wells or water handling, although in this case, water handling is actually better, but it is also a downside risk mitigation as well. Thank you. Our next question is, "Is it the intention of the company to increase the number of wells/bbl per day when exports recommence and the cash flow situation improves? The simple answer is yes. We would look to increase the number of wells. That's underlain by our 2P oil reserves. Our estimate is in the region of 440 million bbl. If you look, I think in the presentation, I stated this, that using last year's production as the target as a production level, if you divide one by the other, you get something approaching 30 years, which kind of actually says that the field isn't reducing its kind of classic optimum rate. We would absolutely seek to increase drilling once we continue to export and look to raise the daily production rate. Thanks. Thank you. Our next question, they say, "Congratulations on a resilient half-year performance and your continued prudence in managing the business. Could management provide greater specificity on the settlement mechanics discussed to date and timing for overdue receivables? I think, as I've said, we've been clear about what we seek in order to restart exports and the fact that we are in negotiations. I think people will understand that I'm not going to disclose anything that we're talking about until it's finalized. Once it's finalized, we will obviously share it with the market. The mechanics of that, I'm afraid I can't do that now. I think also, I would say that the arrears we would expect to recover over a period of time. Again, that's part of the negotiation that's going to take place. I'm not going to say anything more than that, I'm afraid. Thanks. Thank you. Next question, "Why was the BMD 10 million share buyback never utilized? Yeah, I'll take that one. We only had very limited purchases that were made primarily because of the steady increase in share price following the launch in October 2024. The buybacks make sense as a way to return capital to shareholders, as mentioned earlier, if we are increasing value. We'll continue to review opportunistically throughout the year. As mentioned earlier, we try to take as broad feedback from shareholders, some of a clearer view and preference on dividend as we make our decision. We're monitoring this throughout the year. Thanks. Thank you. Our next question is on whether GKP and/or other IOCs in Kurdistan have signed in recent weeks lifting agreements to facilitate oil handover after ITP resumption that have included the Federal Government of Iraq, or were those signed with the KRG If no such agreements were signed, was there a template circulated with the firms/KRG? Thank you. Yes, sir. Thanks for that question. I think as I've answered two similar questions already, you'll understand that we've made it clear what we seek in order to put oil back in the pipeline. We are having discussions and negotiations with the KRG and the Ministry of Oil. I'm not really at liberty to disclose those negotiations at this point in time, other than we are having them. We'll give full disclosure once we've signed the agreement. Thank you. Thank you. Next question, "What is the cost of water handling solution, namely higher CapEx through 2027 and increased OpEx thereafter via leasing? Okay, because we're utilizing existing equipment, we're going to install this and have it operational by the start of 2027. The increased CapEx will be between now and the start of 2027. It'll be through 2026 and a little bit in 2025. That amount is BMD 12 million. I think also from our presentation, we said that the leasing costs will be covered by the low-end production increase that we're expecting, which is BMD 4,000 gross at the low local sales price, which we said is, again, it's BMD 27 to BMD 28. You can work out that the absolute maximum of operating activity is slightly lower than that. Okay. Thank you. What are the expected lease costs of the PF 2 water handling facilities? No, sorry, I think I've just answered that with the previous question. Apologies. In an export restart scenario, would GKP intend to export 100% of Shaikan output, or is there a specific benefit to retaining the local market offtake route? We're currently expected to export all of our oil under the agreement. 50,000 bbl might be retained in the local market, but I don't expect it to be our oil. That's a government thing rather than an IOC thing. Thanks. Thank you. Our next question, "It will take considerable capital to fully develop a resource the size of Shaikan. Are you open to third-party farming to accelerate development, or are you still committed to a self-funding but slower path? Good question. At this time, we're not considering in the near term or long term any farming. As we revisit the development plan following the export, we'll assess the capital phasing and requirements at the time, and we'll seek to get the best use of capital to fund this. I think it's fair to say that there's definitely a lot of growth here, and our intention is not to keep capital out of the CapEx. If it's a good project, we'll find capital to make sure that we can deliver a good production growth outlook of this. Thank you. Finally, "What is the ultimate production plan? Okay, basically, previously we had a field development plan, which basically took our production to 80,000 bbl, 85,000 bbl a day from the Jurassic and somewhere between 10,000 bbl and 20,000 bbl a day from the Triassic, depending on the appraisal of that reservoir. That's kind of the levels that we would expect to get back to if we resumed our drilling plans, basically. Thank you very much. There are no further questions from the webcast. I'd like to hand back to Jon for any additional or closing remarks. Thank you. Thank you for everyone's questions and your time today, Thomas and Warren, for listening to our presentation. I hope it gave you an insightful view as to how we've done this year and how we're going to do for the rest of the year, and also an insight into maybe what's going to happen in future years if we get to restart exports in the near future. I would say thank you very much for your time today. Thanks to George and Rosie for managing this, and thank the team also for a great job. Thanks, guys and girls, and thanks for your continued support as investors. Thank you.