Thank you for standing by, and welcome to the Santos 2023 half year results webcast. All participants are in a listen-only mode. There will be a presentation followed by a question-and-answer session. If you wish to ask a question, you will need to press the star key followed by the number 1 on your telephone keypad. I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead. Thank you, and good morning, and welcome to Santos' 2023 half year results question-and-answer investor call. Joining me today is Chief Financial Officer, Anthea McKinnell. Anthea and I recorded a video presentations on today's results, which you can find on our website, along with the presentation. We're not going to repeat the video presentation on this call. We will, however, be happy to take your questions. Before we do that, I'd like to start by acknowledging the traditional owners of the Kaurna people of the Adelaide Plains, from where I am speaking today. I pay my respect to their elders, past, present, and emerging, and I also acknowledge and recognize the support of traditional owners and indigenous people everywhere Santos operates, including in Papua New Guinea, Timor-Leste, and Alaska. I'm pleased to present yet another solid set of financial results that demonstrate the success of our disciplined operating model. Santos continues to generate strong cash flow despite the challenging operating environment. I'd also like to touch on some of the highlights from this result. In the first half of 2023, Santos generated sales revenue of AUD 3 billion, EBITDA of AUD 2.1 billion, free cash flow from operations of AUD 1.1 billion, and underlying profit of AUD 800 million. The board has determined to pay a dividend for the half of AUD 283 million or AUD 0.087 per share unfranked. The buybacks announced last year have now been completed. The board decided not to announce a buyback in conjunction with the interim dividend at this time and will consider the most effective way to return cash to shareholders in the context of the full-year results. We are pleased to continue to deliver strong cash returns to our shareholders, while also balancing the need to invest in our business. Always safe is a core value at Santos. Personal safety performance improved in the first half, and pleasingly, loss of containment incidents continue to reduce. In the second half of 2023, we are focused on implementing programs to improve contractor safety performance. Our performance on reducing spills has continued to improve, and we are world-class relative to international benchmarks. However, we recognize that some incidents are still occurring, and we continue to work on driving the number of incidents down. Across our business, it's been a very busy first half. At GLNG, we have increased drilling productivity through horizontal drilling. In the Cooper, we're on track to drill more than 100 wells, and in Northern Australia, we're expecting at least one more LNG cargo from Bayu-Undan. These are just a few of the operational highlights from across our business. Across our major projects, Barossa was 60% complete, including the Darwin Pipeline Duplication project at the end of June, and we successfully submitted our drilling EP to NOPSEMA in July. We continue to consult with the First Nations and other relevant people regarding how the environmental impacts of the project will be managed, and we are making excellent progress on the FPSO, with the hull successfully floated in the shipyard. At our Pikka project, we were pleased to complete drilling on the... Of the first, well this year, and we remain on track for first production in 2026. Pikka is a tier one project with a highly capable team in place, supportive stakeholders and partners, including our indigenous communities, and we are operating in a supportive and low sovereign risk jurisdiction with world-class environmental regulations, including for carbon emissions. In summary, it was a solid first half. The business is strong and benefiting from a diverse portfolio of high-quality assets. We are committed to achieving our net zero Scope 1 and 2 emissions target by 2040, and we are confident our disciplined approach to operating our business and allocating capital will deliver strong returns to shareholders over the long term. Our unrelenting focus on sticking to our strategy and implementing our disciplined operating model has delivered consistent results and kept the business resilient and performing strongly. We continue to generate strong free cash flows to maintain the strength of our balance sheet and to provide returns to shareholders. Thank you. We're now happy to open for questions. Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from James Redfern from Bank of America. Please go ahead. Oh, hi, Kevin. Morning, James. I hope you're well. Yeah, hi. Yeah. Thank you. Morning, James. Okay, through... Just a few questions, please. First one, can you please provide an update on the 5% sell down in PNG LNG to- Sorry, you got cut off at the end there, James. Please, I just want to get an update on that, please. All right, on PNG. Look, on the PNG sell down, we're continuing our discussions with Kumul for the sale of up to 5% of the PNG LNG project. We've got a commitment to update the market by the 31st of August. I was encouraged by the public comments last week by the CEO of KOGAS, Baek Jong-hoon, in the media. Really we don't want to say anything really, until we have something to announce before or at the 31st of August. We'll update the market then. Okay, thanks, Kevin. Next question is, how confident are you that Santos will obtain the environmental approvals to resume drilling at Barossa later? Well, we're working, we're working towards that. I mean, the comprehensive body of work has been done to this point, and we're very confident in what we've submitted. As you would know, I think, James, I think there's 40 odd EPs in with the regulator just now, the regulator is working flat out on those, because ours is a live operation, is giving that focus. We're very confident that they're giving that the appropriate focus. Consultation is continuing. It's not just the drilling EP, all of the secondary EP approvals require that consultation, so we're consulting with many stakeholders. You know, submitting the EP does not actually indicate a line in the sand in that respect. We're continuing with that engagement. We've been doing that now for several months, and it's going well. A lot of work. We're confident in the quality of our work. It's a quality product. If the regulator has any questions, we expect them to come back to us soon on that. Then we would work to resolve those. We are still working towards getting drilling this year before the end of this calendar year. Great. Thanks, Kevin. If I can squeeze you one more, please? Just interested in, in, any comments around the Dorado sell down, just wanting... Well, look, I saw the article in, in, in the press this morning. Look, we don't really have any comment on any specific sell downs. I mean, the, the, the approach I want to take there, James, is if we've something to announce, we'll announce it then. As I've, I've previously said, we are, we are always looking to optimize our portfolio, selling down interests in development assets for value to appropriate partners is part of that strategy. Okay, great. Thanks, Kevin. Thanks. Thank you. The next question is from Gordon Ramsay, from RBC Capital Markets. Please go ahead. Well, thank you very much. Kevin, I've just got another question about Barossa. I'm just wondering how you really avoid a CapEx increase with this project, and want to get a feel for what your costs to date have been, and are they still expected to be absorbed by the contingency in the project? Because apparently you've got a rig on standby, there are costs obviously involved. Yeah. Look, I mean, we've, we've, we've stripped the costs of the standby for the rig down to the bare minimum that we can. We've, we've, we've sublet vessels and stuff like that to, to help reduce those costs, but we are incurring costs. The reality was that we had not actually incurred or used any of our contingency before this event occurred on the project, and we had a significant contingency available to us in this project within the confines or within the number that we had previously communicated to market. We're obviously using some of that contingency now, and the longer it goes, the more of that contingency we would continue to use. At this point in time, if, if we get back drilling before the end of this calendar year, and we are successful in executing our pipeline laying activities, we still believe we can do that within the original cost estimate, albeit we'll be going forward with a much lower contingency element to, to that cost estimate for any other interruptions. We're still confident first half 2023, 2025, sorry, coming, coming online. At this point in time, that's what we're aiming for, Gordon. We will be doing, as we always do on these projects, 25, 50%, 75% detailed cost reviews on these projects, deep dive cost reviews, risk assessments, and if there's ever any updates following those, we would bring those updates to the market at that time. Is it fair to assume the contingency is roughly 15%? Well, we, we don't disclose the contingency on individual projects, but it's fair to assume that 15% is a normal level of contingency for these types of projects. Okay. Thanks, Kevin. Appreciate it. Thanks, Gordon. Thank you. The next question is from Adam Martin, from E&P Financial Group. Please go ahead. Good morning, Kevin. Adam here. Just, just buybacks. I think you said there that the buyback's off for the next 6 months. Just, just perhaps a bit insight there, what the board's thinking. Clearly, balance sheet's continuing to delever. Yeah, what's the strategy there, please? Yeah, look, thanks for that, Adam. look, the board, well, we look at shareholder returns on a full year basis, and our, our, our aim, as per our policy, is to return 40% of free cash flow from operations, from free cash flow from operations, should I say, to, to our shareholders. The board decided, in this instance, not to announce a buyback in conjunction with the interim dividend at this time, as they want to consider the most effective way to return cash to shareholder holders in the context of full year results. You know, and, and based on those first half results, the board attempted to pay an interim cash dividend, which is 14% higher than the cash dividend that we returned to shareholders, you know, for the same period last year. Really, it's taking the approach that buybacks, we'll decide on, on a 12-monthly basis rather than a 6-monthly basis, and manage that buyback program over longer periods of time rather than shorter windows. Okay. Okay, makes sense. just there was a comment there about potential for domestic gas supply once Darwin LNG ceases. Perhaps you can elaborate a little bit more what you're thinking there, please? Yeah, well, look, I mean, we've been working pretty hard with Bayu-Undan and Reindeer, actually, in Western Australia as well, to extend the lives of those fields as they begin to cut water. As you, you would know, I think we, we, we originally predicted Bayu-Undan would come to end of field life last year. When we actually acquired that asset, it was due to come end of field life in 2021. We drilled some infill wells to get an extension to that. Of course, we're now continuing to produce round about 9,300 million standard cubic feet per day from that field. Now, we think we can get 1 more LNG cargo, at least 1 more cargo out, out at this point in time. Ultimately, when it gets down to around the 80 sort of million standard cubic feet per day level, that's getting close to turndown levels for the plant. We've been working with the joint venture partners, with Northern Territory stakeholders, with our Timor-Leste government stakeholders and partners, to get an agreement that we can... You know, 80 terajoules per day is still a good amount of gas, right? Rather than shutting the field and losing that value, even though we shut the LNG plant down, we can continue producing that straight through into the domestic market here in Australia. We're working on plans to do that. That, that, that could keep Darwin producing for a significant period longer as a domestic gas supply into the Australian market Okay. Thanks for that. That's all from me. Thank you. Thanks, Aaron. Thank you. The next question comes from Saul Kavonic, from Credit Suisse. Please go ahead. Hi, Kevin and Anthea. Hey, Saul. Few quick questions for me. Sure. If I could just circle back on the buyback. Could you just elaborate a little bit as to, I guess, why we've moved to this annual basis, and we now have to go through a six-month period without buybacks, given buybacks have been supporting the share price over the last year? Can you address any concerns that maybe, you know, it's because of the delay to the PNG sell down and the capital management policy might not be sustainable without asset sell downs? Well, look, I mean, I, I think that there's, there's a lot packed into that question, Saul. I think the, the board feels comfortable with buyback programs on the basis that, that, that you, you, you're not confining that to too short a period to do the buyback, and given that, you know, we can't actually control what the share price is in, in, in that period or not, and of course, what other activities are going. We're looking at this on an annualized basis. We, we, we, we had very strong cash flow production in, in 2022, you know, as a consequence of very high commodity prices, and so it's very significant volumes we're able to... Or, or sorry, cash, cash flow we're able to dedicate to buybacks during those six-month periods. We just felt in this instance that the, the, the impact of the buyback or the, the, the quantity of the buyback was not significant enough to really have to make that decision right now, and instead to look at delivering that over the longer period. In giving us a longer period to deliver on that buyback, we think gives us more opportunities to optimize the buyback if the board resolves to do a buyback. It's not a given. I mean, ultimately, they might decide to return as a cash dividend at the full year. You know, it's really just moving from a 6-month sort of deciding or decision-making process on buybacks to think of that as a 12-month annual decision. Okay, got it. The extra AUD 200 million odd, which would be required to get to the 40% payout, we should just expect that to be added in at the end of the year? Well, look, I can't say that, Saul, because ultimately, that's a decision for the board, right? I mean, the, the, the, the policy states that dividends will be a decision for the board. As I said earlier on, our policy aims to return 40% of free cash flow from operations to shareholders, that, excuse me, that is the policy. Thanks. Quick one on just PNG. Sure. I just, I think there's just something in the press from Australian overnight, talking about conflict with quite a number of deaths up in Enga Province, which I think is where Hides is. Any sign that that might be presenting any risk to PNG LNG production? Thanks for that. Look, security in PNG is something that we always work closely with the PNG government and authorities on. You know, as, as you would know, through Oil Search and even in our early, early period of being not the operator in our, sorry, non-PNG LNG operations in PNG, we, we, we have security issues that we have to deal with. These particular incidents haven't caused us any concerns in our operating areas. We've got no impact on us, and, and, and, and our communities are actually pretty stable at this point in time. We work very hard in those communities through both the Santos Foundation as well as our operations teams, to maintain our presence in those communities and strong working relationships with those communities, including recruiting and providing jobs for lot of the local people in those communities. We're very proud of our investments here and the work that our community teams, community teams do in PNG. Interestingly, the reliability of our PNG operations since we've merged with Oil Search, has increased from 83% up to 96% on those assets. We're seeing that in higher production from those assets as a consequence of that higher operating reliability. That's because we're able to get to these locations without interruption from any of the sort of events that you're referring to. But, you know, our security is always front of mind for us as an organization, and we get regular briefings, and we stay in contact with the authorities to make sure that it's safe for all of our people to operate. Thanks. Last question from me is just staying on PNG. Sure. If we could just get an update on execution of Angore. I think in the last public Q&A we had earlier in the year, you said you needed to just see, I guess, you know, not to judge by the early kind of activity and let some more time pan out. Is there any update there, and does execution at Angore potentially present any risk to the production outlook in 2025 that Santos previously put out about 6 or 7 months ago? Yeah. Look, I mean, delays in any of these programs always presents risk to future production. There has been delays in the three wells, in the top hole sections of these wells. Our recent briefings are that, that the Exxon are on top of that now. They're recovering from that, and they've been able to make up as much as the drilling's blown out a little bit on terms of schedule. They've been able to make up for that with some of the facilities parts of the project. We're still expecting it to come in on, on budget, and probably still looking around the middle of 2024 for production to be on stream. All right. Thank you. I'll jump back in the queue. Cheers. Thanks, Saul. Thank you. The next question is from Dale Koenders, from Barrenjoey. Please go ahead. Morning, Kevin. Maybe just firstly on Dorado, there's a comment that explorations are phase two gas development. Does, does that now confirm the JV aligned with phase one gas and oil development? You broke up a little bit there, Dale, but I think what you said at the, what you asked at the end there was, are they aligned on the oil and gas integrated development? Was that, is that correct? Just oil, phase one. Oh, just oil, phase one. Look, phase one is always the liquid stripping part of this project. Phase, phase one has got its OPP approved by the regulator. That, that, that effectively would be the liquid stripping phase of the project. What Santos wanted to do last year when we recycled this project, was to then make sure we're designing that for the gas project to be compatible with an integrated gas development for phase two. We probably need a little bit more gas to make that economic coming back to Barrenjoey Island, and, and, and that's what we're working through just now. The prospectivity, as you would know, is very high for both oil and gas. Yeah, phase one would be liquid stripping with all gas reinjected, to maximize liquid recovery and of course, to store the gas for future gas production. And then you'd previously also mentioned you needed certainty on the contracting market, both in terms of cost and risk. Are we there yet? Yeah. Well, we're working through that right now, but it, it's fair to say we, we haven't recontracted anything for, for that. We're working towards an FID readiness for the second half of 2024. Okay. So what else are we waiting for for that project sanction? Is it down? Is it Santos balance sheet? Is it NOPSEMA? Well, look, I mean, it's, it's all of those things, quite frankly. I mean, it's getting to the right JV equity levels. It's getting the maturity of the subsurface work done, and the contracting strategies in place and the cost estimates where we want them to be. Of course, it's, it's about approvals as well, right? It's working through the regulatory approvals processes. As I've always said, I'd need to see that we are well progressed on Barossa before we want to take another offshore project through FID in Australia. I'm confident we'll get there. It's just that, you know, you wouldn't want to be taking that on prematurely, that risk. Maybe a finally, a boring question for your CFO. The power gain in the accounts through the period, can you explain that, and is this likely to be an ongoing benefit? Yep. Dale, I can explain that. That's largely related to our WA assets and its augmentation on carry forward balances. To the extent for projects, particularly like Barossa, when you haven't yet got production utilizing those credits, the credits get carried forward and augmented, and that goes as a credit to the P&L and a debit to the deferred tax asset. It's non-cash. Okay. We'll continue. Thank you. We'll continue. Yep. Thank you. The next question comes from James Byrne from Citi. Please go ahead. Good morning, team. My understanding is that once the environmental plans are submitted, NOPSEMA reviews them for, call it, one month. They'll come back to you with questions or concerns. Just wondering if you could confirm whether, you know, you're having to rework anything or are there any major concerns at that? No. We'll have no response from NOPSEMA on the plan officially at this point in time, other than they ask for an extra few days, an extra 10 days or so, to review that. You can add 10 days onto that approximate month that you stated, it's not unusual then for the regulator who've reviewed. These are very large documents, I'm sure you're well aware, it's not unusual for them to then come back with a number of questions or clarifications that they require. At that point, we would work through those bits. You know, until we see what that is, it's difficult to speculate. The one thing that I would say is we're very confident in what we've submitted, and remember, it's based on an EP that technically was approved previously, right? So, so, it, you know, a lot of it, the, the, the supplementary work that's done here is around the body of work we've done in consultation. And with all of our- Got it. Okay. Thank you, Kevin. Can we just have a quick conversation on carbon and any potential liability? So I look since six months ago, Safeguard Mechanism, you know, a bit, bit more known and certain, the London Protocol being introduced to Parliament, that bill. You know, in the scenario that Bayu-Undan doesn't get up or is significantly late relative to start up for Barossa, how, how's your understanding there on your, your liability for CO2? Well, look, I mean, the Safeguard Mechanism, in, in one regards, makes it quite simple for all of us to, to estimate and to think about what we have to do going forward. If you think about the Barossa project, Barossa has been impacted quite significantly from the point of view that from day one, it has to be net zero reservoir emissions, right? What that means for us is if the Bayu-Undan project is not up and running, Bayu-Undan CCS project is not up and running at the start of the Barossa production, we would need to have credits available to offset those reservoir emissions until such times as Bayu-Undan CCS is up and running. I'm only focused on Bayu-Undan CCS being up and running and being approved, and we've got very constructive conversations going on with the regulators and, and, and Timor-Leste. I was very pleased to see the Australian government push through on the London Protocol. That needs to be in place to allow this project to, to, to occur. You know, thankfully, we've got that through the parliament now. We look forward to the two governments progressing on the conversations to put in place the regulatory frameworks below that, that allow, allow us to get this project approved. Bayu-Undan CCS is the most logical option, given the need for, for carbon capture and storage. It's a, it's a reservoir that for many years, in fact, in the early years, we injected more than 1 billion cubic feet of gas per day in, when... Similar to the, the, the question, I think that Adam asked about Dorado or, or maybe it was Dale, that, you know, we were injecting and liquid stripping for the first few years of Bayu-Undan. We were injecting 1 billion cubic feet of gas into the Bayu-Undan reservoir every single day back at that time. You know, it's a very, very good reservoir for storage, and we're very confident we'll get that up. You can see with some of the, the legislative and regulatory framework, progressions such as the London Protocol, we're moving in that direction. Got it. Okay, my third and final question is just on Alaska. You've drilled that first well already, and my recollection is you described that as having gotten off to a flying start. What are your lessons learned so far? Are you still confident in your, in your capabilities as an operator there? Look, as an ex-driller myself, James, I don't think I have ever described any drilling operation as getting off to a flying start, 'cause I always think they can fly much faster than the flying. Look, I think they've got off to a solid start and in actual fact, well, you know, that comment about 1 well was at the end of the quarter or the end of the half. They've drilled another, they've drilled 2 wells since then, in fact. We're progressing. The drilling is progressing very well. We're on the third. Actually, we're on the third well right now. Apologies. It's progressing well. We're learning some things as we go, but they're all positive. We've got 42 wells to drill, so all up. A bit, bit of time to go, but the, the safety performance has been very solid. The environmental performance has been solid. As I say, we've got a quality team. I was up there in July visiting them, and it's, it's going very well at this stage. Long may that continue, but I do, I do look forward to our drillers continuing to move along that learning curve and, and improve the performance, and, and I know that they're very keen to do that. In these projects, just like in Queensland, on our onshore operations in Queensland, when they're very heavy, drilling-dominated projects, which, you know, a lot of the costs in these projects are, the risks around cost escalation and/or cost-saving opportunities really, are driven by how the drilling part of the projects go. It's been a very solid start, and I look forward to them continue to improve. Great. Look, just considering you got through your, your slides in six minutes, I might actually sneak in another question. Just thinking about, you know, following on from what Saul was asking around PNG, LNG production levels of Angore. We maybe just look out another couple of years. You've got Papua LNG production that potentially comes online, uses some of the liquefaction capacity at Trains One and Two. So you're able to. Yep ... push out some of that CapEx you might have otherwise spent, such as, you know, PNG and Juha. In the event that, you know, Papua LNG was late, do you feel like you've got enough gas there in the upstream to be able to continue to operate PNG LNG at a higher rate? My understanding was there was a JV meeting a few months ago to figure out if you wanted to drill some extra wells or not on that risk, Papua LNG schedule. Yeah, look, I mean, we're always looking at having a better you, you like to always have a little bit of kinda buffer in your supply plans, but not too much buffer, 'cause that means you spend a lot of capital, of course, and, and, overdevelop. I think the key thing to know here is, if, if that were to happen, then you have options to bring other things forward, including our, our own operated opportunities, production opportunities, from, you know, the APF project, which has also been deferred, which is what you're referring to in terms of our CapEx being pushed out by two or three years. We're pretty confident in the plan. I mean, Papua is progressing well. we're you know, the latest update I got is it's still online to take a FID decision next year. As long as we do that, we'd be pretty confident that we'll be able to get this on time. Fantastic. Thank you, Kevin. Thank you. Thank you. The next question is from Sarah Kerr, from Morgan Stanley. Please go ahead. Thanks so much. Congratulations, Kevin and Anthea, on the results. I just had a question around Narrabri, and what are the critical path items left for that project to reach, FEED and FID? Sarah, good morning. Look, thank you for that question. I've just got to change direction here a little bit, 'cause I, I don't get too many questions on Narrabri these days. Look, the project has got its approvals. It's still had its Native Title award, which is being challenged in court. The, the, the, the decision from the arbitration has been challenged, and so we will, we will respect any decisions from that. We'd expect something in the next three or four months on that front. The main critical path item really for Narrabri now is the Hunter Valley pipeline approvals and getting the pipeline licensed. We've been working constructively along that pipeline route, consulting with many of the landholders and community stakeholders along that route, optimizing pipeline route as we go, and signing people up for the survey work that we have to do to progress that licensing approval. That's going very well. We've been consulting with thousands of people over the last few months or last several months. My expectation is that that's probably a sort of 12-month cycle or so to get to the point where we'd be able to hopefully get our pipeline license in place. That's the last big formal approval required before you could go forward on the Narrabri Gas Project. What I will say about Narrabri, though, it's a project in demand. I mean, we have had more demand-led conversations from people who are looking for gas, needing gas, in the future, particularly in New South Wales. And we are oversubscribed in terms of interest for that project. Great. Thanks so much. Maybe just one more question, if I may. Pikka is obviously going really well. Are you considering maybe having a larger footprint in North America? Oh, look, I, I, I think at this point in time, the, the hopper for Santos is pretty full. I mean, we want to stay very disciplined. I'm very focused on, on disciplined, very focused on delivering what we have on our plate right now, continuing to operate well. We can always operate better. You know, around our, our, our, our sort of core assets across the business today, Queensland is performing very well. Cooper's getting back to a very strong, steady state operation. Darwin, of course, is coming to end of the Bayu-Undan field life, and we've got a lot of work associated with that and getting that ready for the start of Barossa. Of course, we have to then get on with delivering the Barossa project. Of course, in Western Australia, we've had some challenges over the last 12 months or so there, with Reindeer coming to end of field life, albeit it's showing a surprisingly strong signs of life at this point in time. Hopefully that'll go for a bit, bit yet. You know, some reliability issues over there as well, which we're really, really focused on, on, on, on, on improving. We expect a stronger second half in WA as a consequence of some of the planned maintenance work we've been doing over the last few months. Yeah, I mean, the hopper is pretty full. I'm not really looking at expanding or developing any other projects at this point in time. We'd like to get some of these things off our plate before we move forward. Great. Thanks so much. Thank you. Thank you. The next question is from Nik Burns from Jarden, Australia. Please go ahead. Oh, thanks, Kevin and Anthea. Maybe just starting off with a follow-up to your comments around Bayu-Undan CCS. I think the last update was targeting FID in 2025. Appreciate that sounds like it's, you know, a fair way away, but there's obviously a lot to be done between now and then. Can you just help us maybe walk through the key milestones that you're looking to achieve between now and then, and what we should be looking out for? Also, once you achieve FID, how long do you think it will take to actually bring the CCS project online, understanding that there is going to be a gap between Barossa LNG start and the start-up of this CCS project? Cheers. Look, thanks, Nik. Very good questions. Look, the, the technical work for the project's almost done. I mean, we're pretty much finished or at the latter stages of our, of our FEED, FEED process, and then it's really a case of waiting for approvals. You know, if you think about the traditional approach to these projects, we do some pre-FEED concept, pre-FEED work, then you FEED, then you FID and go straight into execution. These projects really have developed a new phase now between FEED and FID, which is that approvals, phase, and, and getting those secondary approvals in, in place, to de-risk that approval, process. No longer can, I, I think, can you simply take FID and get going and get your approvals in parallel. The regulatory and legislative structure in Australia right now for our industry does not really warrant taking those risks, I think. For us, it's about getting all the approvals in place. That's really what comes next. The London Protocol is a great first step, but we've got to then get the rest of the approvals, the regulatory approvals that we need on both sides, you know, Timor-Leste, as well as in Australia, and that has allowed us to take FID and move that project forward. In terms of the timeline to deliver on the project, it's not huge, but the biggest risk to that schedule is actually supply chain. It, it as the world is heating up and projects are getting developed all over the world, whether they be oil and gas projects or other, other industry projects, rotating equipment, compressions, all that sort of stuff is becoming more in demand, and lead times for the delivery of equipment is going out and taking longer. We're keeping our eyes on that. I, I would think that you're really looking at something like a two-year sort of period from FID to delivery. Remember, a lot of the kit's already in place, the pipeline's there. Some of the CO2 separation equipment is already there, you know, in, in terms of Darwin and at Barossa. It's really about compression, and it's really about facilities offshore. Got it. Thanks for that, Kevin. My other question is on another asset that maybe doesn't get as much attention these days, GLNG. It's good to see the field performance in recent times and understand you've got Arcadia expansion underway. You're flagging sort of up to what, 350 to, I think, 450 wells this year. As we sort of look further ahead, you know, conscious that there are some third-party gas supply contracts that do roll off aggressively over the next few years. Just thinking about how we should think about GLNG, LNG output over the, say, the next five years. You know, you've been targeting more than 6 million tons per annum over the last couple of years, which has been great. Is that level of investment in new wells and processing capacity, will that be sufficient to offset the decline from the third-party supplies, or should we be thinking about a step down in LNG supply from GLNG over the medium term? Thanks. Yes, thank you for that, Nik. Look, in the short term, no, I don't see that production dropping down. I mean, we are very focused on maintaining that production. What that has steadily been doing over the last few years is, as you rightly point out, they're replacing third-party gas with, with project gas as, as we keep building those, those profiles, the, the, the, the, the indigenous gas production higher and higher. Look, there's a lot of good things going on at GLNG, you know, it's one of the things I'm, I'm proudest of across the organization, is the way that those guys continually innovate to get better reliability. You can see in our pack, we, we show you the slide on mean time between failures, that is world-class performance. Everywhere we benchmark that, it really is world-class performance. You can see the sales gas now, a much higher percentage of that is either Santos or GLNG gas and not third-party contracted volumes. So we expect to fully replace that over time and continue to replace that over time. In order to go beyond, beyond six, so I think we need new developments. We need new fields to come into the mix. We are seeing some higher productivity rates from wells, and I mentioned in the pack about the horizontal wells, the lateral horizontal wells that we're drilling at Arcadia, where we're seeing well productivity more than 15 times what we would get from traditional vertical wells in that, in those same coals. That's, that's an amazing outcome. What that will do, though, rather than simply give us higher production, it will give us much stronger base production and stronger tail production. The other thing I would draw your attention to there, Nik, is over the last few years, you will have seen a steadily increase in our reserves position. What we've been building year on year at GLNG is our reserves position to allow us to be in a strong position when we get to some of those options, in a few years' time. Right now, I think 6 million tons per annum is still the guidance I would want to give year on year. We're, we're working hard at maintaining that and working with our joint venture partners to look at opportunities, to develop, new opportunities, to bring into GLNG and take it higher. That's great. Thanks, Kevin. Thank you. Thank you. The next question is a follow-up from Saul Kavonic from Credit Suisse. Please go ahead. Saul, welcome back. All right. Thank you. There's a few quick ones just to run through some projects. First up, just Moomba CCS, where the CapEx has gone up to, I think, $220 million, when like, I think if I use more, AUD 220 million. Just get some color on the drivers of that and if there's any-- if that's a sign of broader risk execution or it's very specific to Moomba CCS? ... Yeah, look, I mean, it, it's gone up just over 30% on, on a gross level. The, the reality of this project has really been driven by contractor. I would call it capability and capacity is the main driver of, of this. As, as we've seen very high turnover in contractor personnel in Australia, I think that is a broader risk for the industry. I think that is a risk we, we are seeing right across our industry. What that's leading to is lower productivity, which then leads to activity delays. The project itself is very well progressed on all the big material items. All the kits out there, now the pipelines are done and in place and commissioned. The, the wells are all in place, just waiting for the CO2 to come. A lot of the tie-ins have been done, so three of the four tie-ins to the trains at Moomba are now completed, and we've been doing that as we've been doing planned maintenance shutdowns at Moomba throughout the year. We've been able to execute that. You know, if I was thinking about what was driving the cost escalation, it's really contractor capability and capacity. There was some engineering issues in terms of scope creep, in terms of volumes, quantities early on in the project, which is coming through, and some supply chain impacts. I would think they would be more local to this project. One of the AFE cost estimate were out with $165 million, which I think you said at the time was AUD 220 million, but $165 million. That's a $55 million gross increase in CapEx. One of the problems you have with small CapEx projects, relatively small CapEx projects, of course, the increase is always going to be in the tens, and the percentages are much higher on the smaller projects, right? It's, and it's unfortunate when that happens. We're pretty confident that we've, we've, we've got a very good, very, very comprehensive startup strategy for this project. We're still confident it'll be in the first half of 2024 that it will come online. Unfortunately, it's going to cost a little bit more to get us over the line, which is not inconsistent with what we're seeing elsewhere. From an integrity point of view and from a progress point of view, it's going well. Unfortunately, on the cost side, it's blown out a little bit. Thank you. Also a question on Varanus. When I just look at some of the gas flows recently, it seems to be quite a bit down versus last month. Any issues in kind of Spartan coming online there? Yep. Yeah, no, Spartan came online as so, that was producing well. We've got a train shut down just now. It's quite a long shutdown for the one of the amine trains at Varanus Island, that's a big bit of planned maintenance work we're doing, which was always in the plan. From memory, I think it's like a four-to-five day shutdown. That's why we've had a lot of... You know, with the unplanned outage at the start of the year, Spartan came on, then we've gone into this planned outage. Unfortunately, what that's meant is a lot of interruption, if you like, in the first half. We expect that to pick up and be a steadier second half. I think that should all be coming on early next month. We get back to significantly higher rates. In fact, I think Reindeer, which was also shut down for some maintenance activities, is due to come on today, I think. We get that back on, and we'll see where we are with that. That was producing between 40 and 50 TJ a day, just when that was shut in a few weeks back as well. A lot of maintenance, a lot of activity, it's been impacting and interrupting our Western Australian operations in the first half. Hopefully, we'll have a much smoother second half, and we'll get the benefits of that maintenance activity. Great. My proper last question, just on Barossa, the $3.6 billion budget, I just want to just clarify, I guess. Is there a little footnote there saying that that's up until it reaches nameplate capacity? Is there any activity that was in the original FID budget, which I guess has been pushed beyond when the project will reach nameplate, which is now kind of out of that $3.6 billion, or the $3.6 billion is for all the activity that was assumed at FID to include within that same number? Yeah, I mean, the AFE has not been changed. There's been no change to the scope for the Barossa, phase one. All the same, you know, all the same activities still included in that cost estimate. I mean, I think what may well happen is that we may start up before we're finished that scope, but that doesn't change the cost estimate we have out there for the scope. Of course, Barossa always had phase two activity, which will be approved subsequently well down the line for the, you know, for the additional wells, I think, after about seven years or something of production. No, the phase one is always the same scope as it is right now, that represents AUD 3.6 billion. Right. With the DPD, that was increased to AUD 4.3 billion, I believe. Yeah. Yeah. Great. Just wanted to clarify that. Thanks. That's all. All right. Thanks, so I think, we have what? Time for one more question, I think. Thank you. The final question comes from Henry Meyer from Goldman Sachs. Please go ahead. Well, morning, Kevin and Anthea. I have to keep it to one. I think we've covered most ground, so I might throw something pretty left field in, and I'm sure you get even less questions around Poseidon than, than Narrabri. Just in the context that, it seems some of the Exxon partners are picking up some of the leases nearby. Has there been any movement in how you're thinking about commercializing those discoveries around Exxon? Well, again, Henry, you know, any, any thing we do in terms of portfolio optimization. We'll be happy to talk about when we make any announcements on that. We are constantly looking at the best ways to monetize all, all of our assets, whether they be exploration or, or, or development assets. Anything we can do to optimize portfolio, we, we, we, we, we continually review. We'll only talk about that really if there's anything to announce. Got it. Fair enough. Thanks, Kevin. Do we have time for a few more, if that's okay? Well, I'll give you one more, Henry. Sure. Unfortunately, you know, you've got the last slot, but I know we're under time pressure here, so we'll give you 1. How's that? Thank you. No, I appreciate it. Okay, last one, hopefully this is pretty quick. Just wanna test my understanding on the Barossa Mitsubishi contract, the gas contract. Am I right in understanding that there's flexibility there to sell the gas at oil linked rather than JKM as well? How are you thinking about perhaps adjusting the contract or targeting your spot gas exposure into 2025 and 2026? You, you, you're right to think that we have flexibility to recontract part over all of those volumes. I think I'd leave it at that, Henry, because, oh, you know, I wouldn't want to say what we're going to do or not going to do, but we're always looking at opportunities. You know, the good thing about the contract is we've got the flexibility to do that when the time is right and the best opportunities arise. Got it. Thanks again, Kevin, and then maybe just a bit cheeky at the end to see if I can draw some more on that. Is there like a timeline constraint or anything you need to make a decision by, on choosing what index to sell it at? Nope. Got it. That's clear. Thank you. That was efficient, wasn't it? That was very efficient. All right, Henry, thanks very much. Look, I think we're going to have to wrap it up there. I'd just like to say thank you to everybody for, for dialing in. I look forward to catching up with all of you, over the next week or so on, on our road shows. Thanks again for, for your support. Thank you. Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.