I would now like to hand the conference over to Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead. Thank you, and good morning, and welcome to the presentation of Santos' 2026 half year results. I am speaking today from the traditional lands of the Kaurna people of the Adelaide Plains, and I pay my respects to Elders, past and present. I also acknowledge and recognize the support of traditional owners, indigenous people, and nationals everywhere Santos operates around the world. 2026 is a year of transition for Santos. In the first half, we safely commenced Pikka production and continued commissioning and ramp-up at Barossa, and that is the story of this result, new production coming online while the base business keeps delivering. I will begin with an overview of our performance before handing to our Chief Financial Officer, Lachlan Harris, to take you through the financial results. Our Chief Operating Officer, Brett Darley, will then cover the operational performance of the base business. I will return at the end to discuss our outlook and strategic priorities before we open the call to questions. Before we start, I draw your attention to the usual disclaimer on slide two. Safety performance in the first half was strong. We recorded no lost time injuries and no Tier 1 process safety incidents. That discipline underpins everything that we do. Our lost time injury rate has been better than the IOGP global average every year since 2022, including the first half of this year. In 2025, IOGP recorded its highest number of fatalities since 2015. We see that as a reason to work harder and drive continuous improvement, not to take comfort in our own numbers. Safety remains a core focus at Santos. As Barossa and Pikka transition to stable operations, maintaining the discipline around safety will be critical. Safe, reliable operations underpin our production and cost performance. Slide 5 summarizes our financial results. In a year of transition, the base business kept generating cash, and we declared an interim dividend of $0.116 per share for shareholders. Sales revenue of $2.6 billion generating EBITDAX of $1.6 billion and free cash flow from operations of $378 million, offset by commissioning and timing effects, which we expect to unwind in the second half. Lachlan will step through that shortly. 2026 is shaping up to be a tale of two halves. The first half has set us up for materially stronger cash generation as production from Barossa and Pikka build toward. In line with our expectations, July has started the second half with a much stronger performance. It is early, but the direction is consistent with a stronger second half as described. I am pleased that the board has resolved to pay an interim dividend of $0.116 per share, a dividend consistent with our capital allocation framework and reflecting its view of the full-year performance outlook. I said at the outset that 2026 is a year of transition for Santos. In the first half, we brought Pikka online safely, and Barossa continued to progress through commissioning towards steady state. Each of the six Barossa wells has confirmed capacity of 300 million standard cubic feet a day, with the wells operating in line with expectations. Pleasingly, Darwin LNG delivered 100% plant reliability in the first half. At Pikka, initial production reached around 23,000 bbl a day gross, and with water injection due to start up shortly, production is expected to ramp towards the 80,000 bbl a day gross plateau by the end of the quarter. Pleasingly, we lifted our first crude oil cargo just last week. At the same time, the major development build is behind us, and peak CapEx is also behind us. As Barossa and Pikka ramp towards plateau, we expect second half production to be around 20%-30% higher than the first half. That combination of higher production and lower CapEx is expected to drive stronger free cash flows. That is the inflection point we have been working towards. From major projects investment into production, cash generation, and long-term value for shareholders. Moving to slide seven. First half production was 45.6 million bbl, up 3% compared to the same period last year. The base business continued to perform reliably across the portfolio, and Barossa is now part of that base, adding meaningful new production. In Australia, we strengthened our domestic gas position through two linked decisions. We executed a gas sales agreement with the South Australian Strategic Gas Reserve to supply 200 petajoules of domestic gas from 2030 to 2040, with a prepayment supporting our investment in the Moomba Central Optimisation Project. Together, these support the long-term future of the Cooper Basin Central Fields, while targeting more than $600 million of capital and operating cost savings over the life of the Central Fields and up to $3 a barrel reduction in unit production costs. GLNG recently shipped its 1,000th LNG cargo from Gladstone, an important milestone that is testament to the quality of the asset and the strength of our joint venture partnerships, and reflects more than a decade of reliable supply to our customers. Our operations at Varanus Island in Western Australia ran at 97% reliability through the half. All facilities are back online following Cyclone Nigel, and Halyard-2 continues to exceed expectations at around 85 terajoules a day, with minimal decline and no water breakthrough. We expect this strong performance may result in a significant upward reserves revision at the year-end. At PNG, we took a final investment decision on the Agogo production facility tie-in, targeting an IRR above 50% and a payback of less than four years. We also took FID on the PNG LNG oil infill drilling campaign. Papua LNG continues to progress towards a financial investment decision in the second half, and the development forum in PNG has now commenced. In Alaska, Pikka continued to ramp up, and the drilling program progressed strongly. We have now drilled 31 development wells and 28 stimulated and 25 flowed back, in line with pre-drill expectations. Across all three regions, the approach is consistent. Disciplined capital allocation focused on high-return opportunities in and around infrastructure we already own and operate. That is the strategy we set out at Investor Day, and this half shows us delivering on that strategy. Moving to Pikka on slide eight. Pikka coming online is an important milestone for us in Alaska. We achieved first oil in May, moved to continuous production in June, and lifted our first crude oil cargo last week when we sold 450,000 bbl. Production was around 23,000 bbl a day gross at the end of the half. From here, the path to plateau runs through startup of the seawater treatment plant, water injection, and continued buildup of well inventory. The seawater treatment plant is in the final stages of commissioning. The drilling program continues to perform strongly with a third combination well now complete. We are consistently beating technical limit across the drilling program, taking time and cost out, and we expect to keep improving. We are also progressing well tie-ins, building the inventory needed to support the production ramp. Pikka is a Tier 1 oil asset entering production in a premium market. Our focus now shifts from project execution to running it within our disciplined low-cost operating model to maximize long-term value for shareholders. Papua LNG is a high-quality opportunity for Santos to sustain and increase our equity LNG production in PNG. The project continues to target FID in the second half of 2026. With environmental permits issued, the development forum underway, and project financing also progressing well. At plateau, the project is expected to contribute around 1 million tons per annum of equity LNG and around 11 million bbl of oil equivalent a year to our production. The economics also benefit from integration with PNG LNG. Our 39.9% interest in PNG LNG creates additional value through access fees, processing tolls, and cost sharing. Project financing is also expected to fund a significant portion of development capital, reducing the upfront equity requirements. Together, these elements make Papua LNG an increasingly capital-efficient opportunity with multiple and diverse sources of value for Santos. Our disciplined low-cost operating model continues to underpin the business, supporting consistent operations, strong safety performance, and reliable shareholder returns. We've maintained that focus through the first half, with Barossa and Pikka moving through commissioning and ramp-up alongside solid performance from the base business. As Barossa and Pikka move to plateau, we expect production volumes to rise and unit production cost to trend lower over time as we continue to target less than $7 per barrel of oil equivalent. The timing of cash flow is also different this year. In recent years, shareholder returns have been more weighted to the first half. This year, with production and realized LNG pricing expected to strengthen through the second half, we expect cash flow to be more heavily weighted to the second half as well. The model remains the same: generate cash, reward shareholders, reinvest to backfill and sustain our infrastructure, and to build and grow our production while continuing to operate safely and reliably. I'll now hand over to Lachlan to provide an overview of our financial results. Thanks, Kevin, and thank you everyone for joining us today. In the first half of 2026, we generated sales revenue of $2.6 billion and EBITDAX of $1.6 billion. Free cash flow from operations was $378 million. Unit production cost was $7.53 a barrel, and gearing was 28.1% including leases, or 23.2% excluding. As Kevin has mentioned, we are declaring an interim dividend of $0.116 per share. The first half began with JCC link pricing at a multi-year low in the first quarter, before global energy markets tightened following supply disruption around the Strait of Hormuz. Against that backdrop, LNG realized $10.95 per MMBtu, and crude oil realized $92 a barrel across our portfolio, remaining strong compared to peers. This reflects the quality and structure of our portfolio, including premium oil-linked pricing, high heating value LNG, proximity to Asian markets, and flexible contract positions. The Japanese Crude Cocktail price, or JCC, is now trading above $100 a barrel. Of our contracted position, approximately 80% is linked to JCC and oil indexation. Most of our LNG contracts have around a three-month pricing lag, so the benefit of that stronger pricing will flow into realized pricing in the second half. The base business continued to deliver strong EBITDAX margin of 59%. Kevin has already touched on the key drivers of first-half earnings and free cash flow. However, let me take you through those in some more detail. Free cash flow from operations was $378 million, with the first-half result reflecting three main factors, commissioning costs of Barossa and Pikka, the timing of cargo movements around 30th June, and the PNG underlift position at the end of the half. The first item is commissioning. As Barossa and Pikka move to steady state production, commissioning-related costs fall away, as do the third-party cargo purchases that we have made during Barossa's commissioning period. The second item is cargo timing. Four of the seven Barossa cargoes and three PNG equity cargoes were lifted before 30th June, with around $300 million of proceeds received shortly after period end. So whilst those cargoes were recognized in sales revenue in the first half, cash was receipted in July. Finally, we ended the half with a PNG LNG underlift position of around 1.3 million bbl of oil equivalent. An underlift arises when a joint venture participant has lifted less LNG than its proportional share of production over a given period. The production occurred as planned, and this is purely a timing effect. The underlift position is expected to reverse in the second half as the PNG LNG cargo program delivers the corresponding cash receipts. The first-half free cash flow results include a number of commissioning and timing effects that we expect to unwind through the second half and balance out over the course of the year. Our approach to capital management and capital allocation framework remains unchanged. We continue to hold a high level of liquidity with $3.8 billion at the end of June in a combination of cash facilities and undrawn committed finance facilities, with no debt maturities before September 2027. Net debt was approximately $6 billion at the end of the half, with gearing of 28.1% including leases or 23.2% excluding. That is above our 15%-25% target range, reflecting the Barossa FPSO liability now on the balance sheet and the tail of our peak CapEx spend. We continue to target a $2.5 billion reduction in net debt by 2030 and expect to see gearing back in towards the target range as Barossa and Pikka move to plateau and free cash flow builds. All three rating agencies have reaffirmed our investment-grade ratings, Moody's at Baa3, Fitch at BBB, S&P at BBB-, and Moody's has moved us to a positive outlook. We have hedged 11.5 million bbl of oil for the second half through zero-cost collars with a floor of $67.10 and an average cap of $98.59. In the first half, oil hedging realized a loss of $37 million. On foreign exchange hedging, we hold hedges for AUD 975 million for the second half at an average rate of AUD 0.643 and just over AUD 1.5 billion for 2027 at AUD 0.658. In the first half of 2026, FX gains were $75 million. It is a balance sheet that supports the base business, funds growth, and rewards shareholders. Moving to slide 16. Our free cash flow breakeven has come down year after year, and it's targeted in a $45 - $50 a barrel band through to 2030. That improvement is driven by cost and capital discipline, not a higher oil price assumption. At this level, we will drive shareholder returns through the base business whilst investing in sustainable growth. In addition, we continue to target a free cash flow breakeven from operations of below $35 per barrel. Santos' sensitivity to oil is improving, too. For every $10 Brent trades above our breakeven, free cash flow increases from around $400 million today to between $550 million to $600 million once Barossa and Pikka reach plateau, an increase of around 50%. A lower breakeven and a higher sensitivity to oil means that at the same oil price, it does more for shareholders than it used to. That's the model getting stronger as the portfolio is upgraded and diversified as new production comes online. The portfolio isn't just generating more cash, it's generating high-quality returns. EBITDAX margin has expanded as unit production cost has fallen over time. Margin is up around 30% since 2016, while unit production cost has come down over the same period. That margin has remained strong over the period despite first-half timing impacts, a function of high-margin barrels working through the portfolio. It's underpinned by structural cost savings. We remain on track to deliver annual recurrent savings of $150 million by the end of 2026. A lower cost base and higher margin barrel business mean the same production does more for shareholders than it used to. Thank you, and I'll now hand over to Brett. Thanks, Lachy. I want to turn the focus now on our operational performance starting on slide 19. 111 cargoes were shipped across Australia and PNG in the first half. The ramp-up in Barossa production lifted upstream LNG production by 12%, at an LNG upstream unit cost of $6.80 a barrel. Barossa is currently producing around 550 million SCUFS per day, and increasing to around 600 million SCUFS per day by the end of the quarter, with cargo cadence of approximately every eight days. Each of these six Barossa wells are operating in line with expectations, and the facility achieved reliability above 85% through July. We reported through the first half some challenges during Barossa commissioning and ramp to full rates. We have moved beyond these challenges and have moved into operating mode. Through the second half, there will be planned statutory maintenance and routine testing of the FPSO safety systems, and we will provide further detail as the timing firms up. Santos-operated fields supplied 15% of PNG LNG's plant. Reliability there was above 99%, and the plant is sustaining an annualized run rate of 8.7 million tonnes. GLNG and GLNG plant reliability ran at 100%. Roma set a record of 230 terajoules a day, and 98 additional wells were drilled across the GLNG acreage. Our drilling program keeps finding ways to improve costs. Extended reach CSG wells delivered around $100 per meter in cost reduction gross, letting us reach geographically where we couldn't get to efficiently before and achieve additional production volumes. That's our self-execution capability at work, the same in-house drilling expertise showing up as lower cost per meter well after well. Put simply, the base business is performing well. On slide 20, looking at our performance in Australia and PNG, continuing looking at our performance in Australia and PNG LNG, our upstream production stepped up to 30.2 million bbl of oil equivalent. LNG sales volumes reached 7.7 million tonnes gross, with Barossa LNG now a distinct contributor to both production and sales volumes. Unit production costs remained steady at $6.80 a barrel, and plant reliability sat at over 99% across PNG LNG, GLNG, and Darwin LNG. That consistency is what the operating model is built to deliver. Domestic oil and gas operations generated $85 million of free cash flow from our disciplined low-cost operating model. Sales gas was 76.4 petajoules for the half. As Kevin said earlier, Halyard-2 in Western Australia continues to perform well ahead of expectations, producing around 85 terajoules a day. Western Australia produced below $7 a barrel, excluding cyclone impacts. The Harriet Alpha platform was safely removed ahead of schedule, and approvals are progressing for the John Brooks backfill program for Varanus Island. The Cooper Basin experienced record rainfall this half, more than double our annual average. We put over 25,000 contractor hours into road recovery and held production costs on target through this period. The basin is back to pre-2025 flood production, with around 80% of the flood-affected wells restored and 30 drilled but unconnected wells ready to connect as access comes back. We took FID on the Moomba Central Optimisation project, targeting more than $600 million in CapEx and OpEx savings and up to $3 a barrel of Cooper Basin unit production costs. This year's well program is a 75-well campaign prioritizing activities in the lowest cost part of the basin near central fields. Upstream production was 15.4 million bbl this half, down from 16.8 million bbl a year ago. That is consistent with our strategic review of our Australian domestic gas business, a shift towards a lower capital intensity, higher margin footprint that delivers cash while meeting our contracted and decommissioning commitments. Reliability stayed strong through the half. Varanus Island ran around 97% for the half, Moomba plant at close to 100%, Port Bonython at 100%, and Moomba CCS above 95%. Cumulative storage at Moomba CCS has now reached around 2.3 million tonnes of CO2 equivalent, safely and permanently stored since start-up. I will now hand back to Kevin. Thanks, Brett. Moving to slide 24, the broader market backdrop continues to reinforce the importance of reliable energy supply. We have seen again this year how quickly geopolitical events can disrupt global oil and LNG markets. Events around the Strait of Hormuz have highlighted how exposed global energy markets remain when supply is concentrated in a relatively small number of regions and trade routes. At the same time, underlying demand remains strong, particularly across Asia, while years of underinvestment mean new supply is becoming increasingly important. For Santos, that reinforces the strategy we have been pursuing for some time, maintaining a disciplined low-cost business and investing in reliable oil and LNG supply close to the markets that need it. This approach has and will continue to ensure the portfolio is well-positioned for the longer term. Australia has plenty of gas. Last year, gas production for both exports and the domestic market was just over 6,000 petajoules. Based on Geoscience Australia's estimates, Australia has enough total demonstrated resources, that is 2P and 2C, to keep producing at that rate for the next 40 years. The challenge is getting those gas resources developed and into the market when they are needed. Santos is already Australia's second-largest domestic gas supplier, and we have a long history of supplying Australian customers alongside our LNG business. Importantly, the government's own data shows there is no gas supply crisis. AEMO's latest outlook shows near-term gas adequacy has improved through to 2029. But from around 2030, new supply will be required as existing fields decline. That does not mean there will be a gas shortage. It just means we have to invest in developing new gas supply sources now. That is why the investment signals being set today matter. Projects that will supply the market in the early 2030s need investment decisions well before then. Policy settings need to support that investment, not discourage it. LNG is a good example of how that can work. LNG contracts have underwritten the development of Senex and Meridian's gas projects, and those projects also supply gas into the domestic market. Australia does not have a gas shortage. We have plenty of gas. What we need is confidence to invest and bring that resource to market reliably and competitively when Australia needs it. Across Australia, PNG, and Alaska, we have around 4.7 billion bbl of oil equivalent of 2P reserves and 2C contingent resources. Our 1P reserve life is 10 years at the top end of our global peer group, and our 2P reserve life is 17 years. Importantly, much of this resource is in and around areas we already have operations and can be developed through infrastructure already in place, supporting capital-efficient growth and creating opportunities to extend the value of our existing assets and infrastructure positions. The other important point is the production mix. LNG represented 57% of production in the first half, with domestic gas at 33% and liquids at 10%. That LNG weighting matters because much of our LNG is priced off oil with around a three-month lag to JCC, meaning the stronger JCC pricing through the second quarter is expected to flow through to stronger realized LNG pricing in the second half. Moving to slide 27. You will recognize this framework from Investor Day in May, so I will not take you through it again in detail. The key point is that our growth is concentrated in three advantaged regions, Alaska, PNG, and Australia, where we have scale, margin, and infrastructure advantage. In Alaska, Pikka has now started up and opens a runway of oil growth. In PNG, we have conventional gas, significant backfill opportunities, and material oil upside. In Australia, Barossa is now online alongside longer-dated opportunities in the Beetaloo and Bedout basins. Importantly, that growth is supported by a strong base business, including midstream and energy solutions, Australian domestic gas operations, and marketing and trading, which helps lower costs, improve reliability, and capture additional value across the portfolio. As we move into the second half, our strategic priorities remain clear, and we are on track and delivering against them. Barossa is now producing at close to planned rates, and Pikka is now producing and ramping up. In PNG, we are progressing backfill opportunities, and the Papua LNG project is targeting FID in the fourth quarter of this year. We are also moving our next wave of opportunities forward. Beetaloo appraisal wells spud at the end of this month. The Bedout appraisal program is progressing, and we continue to engage with the government of Timor-Leste to progress the Bayu-Undan CCS project. Importantly, as announced at our Investor Day, we have completed the strategic review of our Australian integrated oil and gas portfolio, creating a lower capital intensity, higher margin domestic gas business. Our focus for the remainder of 2026 is straightforward: execute these priorities safely and with discipline, continue to strengthen free cash flow, and deliver sustainable shareholder returns. That execution brings us back to the Santos value proposition. We have a high-quality, geographically diverse asset base with large-scale growth opportunities built around advantaged infrastructure and an all-in breakeven oil price target of $45-$50 a barrel. Barossa and Pikka are now adding new production and driving the next step up in free cash flow. From 2027, every $10 of realized oil price above our breakeven is expected to generate an additional $550 million-$600 million of free cash flow. Through our disciplined capital allocation framework, we will return at least 60% of free cash flow to shareholders while reducing net debt by $2.5 billion by 2030. High quality assets, growing free cash flow, disciplined shareholder returns. That is the Santos value proposition. Thank you. I will now open the call to 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 then two. If you are using a speakerphone, please pick up the handset to ask your question. We ask that questions be limited to one per person. Please rejoin the question queue for any follow-up questions. The first question today comes from Ewan Minogue from Barrenjoey. Please go ahead. Yeah, good morning, guys. On Papua, is there any update you can give us on how the development forum is proceeding? Well, good morning, Ewan, and thanks for the question. Our understanding is it is progressing well. There was a stall after a few weeks when it first got up and going when there were some challenges, and those issues were resolved, and the forum went back operational two or three weeks back. Our understanding is it is going to plan. All the feedback has been very positive. We would expect that to go through probably to the end of September or something like that before that concludes. That is the last major government process step in the approvals process for the project. Thanks, guys. I will give it back and join back in the queue. Yes, thanks, Ewan. Thank you. The next question comes from Tom Allen from UBS. Please go ahead. Good morning, Kevin, Lachlan, Brett, and the board team. The board opting to pay out what looks to be 100% of free cash flow from operations over the half, just with gearing still a little elevated, certainly implies the board's very comfortable with the outlook. On the second half, getting Pikka at 80,000 bbl a day is no doubt the focus. You've just confirmed today that production is still at 23,000 bbl a day. Commissioning the seawater treatment plant, is that the single largest operational risk for Santos to manage over the second half and meeting that delivery rate at 80,000 bbl a day over the next 40 days? Thanks, Tom. Thanks for the question. You're right. The board's consideration for the dividend was very much focused on the full-year performance. Of course, they've got the benefit of seeing what was a very strong month in July as further evidence supporting that. That's driven at this point mainly by the JCC pricing coming through in July that obviously we didn't have in that second quarter, and the increased production from Barossa that we're now seeing. As far as Pikka is concerned, as much as we've only been producing around 23,000 bbl-25,000 bbl a day over the last couple of months, we've constrained that production. The wells could produce a lot more than that. We've constrained that production because we need water injection support, pressure support for the reservoir, so that we don't produce too fast, if you like, and then end up depleting pressure in the reservoir before we've got the pressure support, leaving barrels behind in longer term. That's just purely reservoir management. What we've been doing in the meantime is cycling wells around and cleaning them up fully so that we can get an accelerated ramp-up once we get the water injection running. We're close to the very end of the commissioning on the seawater treatment plant. I can tell you that the plant is operational at this point in time, and water is going into the pipeline. We're very advanced in the commissioning, and we expect to complete that very shortly, at which point we then start the injection into the wells. Once we start injecting in the wells, we can start that ramp-up. Our schedule still has us forecasting that that would get to the plateau before the end of the quarter. I think we've said late in the quarter. If you think towards the end of September, that ramp-up, think of it more or less as a straight line between once we start water injection quite soon through the end of September. Okay, thanks. The production plant is all operational, just waiting for that injection to start up. Okay, that's encouraging. Thanks, Kevin. Just quickly, there's press reports in the recent weeks of a potential change in operator, possibly equity interest in the Papua LNG joint venture. I think Santos equity is at 17.7% post the government back in rights. You confirmed at the IBD that if there were opportunities to increase Santos equity, that might be of interest. Should we anticipate these opportunities for Santos in the near term? Could you confirm that Santos still supports its broader growth and higher cash payouts if it were to seek more equity in that particular project? Look, what I would say, Tom, thank you for that question and putting me on the spot with that one. What I would say is that, first of all, the joint venture partners are all talking in detailed discussions as we approach FID on how to best execute the project, and any changes or updates on how we're going to do that, of course, I'd expect the operator to announce at the appropriate time. In terms of equity, you're right. We did comment at the Investor Day that we'd always be open to any opportunity if that was to come our way. We obviously don't comment on M&A activities before we've got something to talk about. If anything changes there in the future, of course, we'll announce it and we'll communicate it to you then. But look, we believe that Papua is a great project. It doesn't matter what projects we do in our portfolio. Whether it's Papua, any projects in Alaska or elsewhere in the future, they'll all be within our capital allocation framework. There'll be no change to the capital allocation framework, and therefore, the returns to shareholders, the free cash flow breakeven target we'll set between $45 and $50 through to 2030, for the next five years or so, none of that changes. That is that everything will work within that operating model, and therefore, we will continue to provide sustainable strong shareholder returns. That's clear. Thanks, Kevin. Thanks, Tom. Thank you. The next question comes from Rob Koh from Morgan Stanley. Please go ahead. Good morning. Maybe can I ask a question about the Bedout Basin, which you haven't spoken a lot about here, and I guess it's still early days. I guess part one of the question is, with Australia potentially looking at extra refining capacity, could that form part of your concept select? Secondly, and probably more seriously, have you evolved your thinking on the floater on the FPSO for this? I understand the BW Offshore option has lapsed. If there's any further color you could provide, please. Well, thank you, Rob. Let me just say that, first of all, we think the Bedout Basin has got incredible prospectivity, and that the Dorado project, which is part of that, is a very exciting opportunity. We've always thought that. We've never changed our thinking on that. We have a capital allocation framework which dictates how much we can spend in terms of CapEx and things going forward, in order to be able to provide a measured growth trajectory into the future while still being able to provide strong shareholder returns through the cycle. We'll continue to work with that discipline going forward. The Bedout Basin will compete with Alaska, will compete with Beetaloo, will compete with any other projects in the portfolio if they fit within that framework, and the best projects will win. In terms of our update on it, though, what I can tell you is that we still plan to drill three appraisal wells in the Bedout Basin in 2027, and we have awarded a drilling rig contract to support those activities. That is a firm commitment to the work we are doing there. We see it as a very attractive opportunity, not only because Australia might build more refining capacity, but also just to increase the energy security, the potential benefits that gives to Australia in the longer term. I think this year has highlighted the need for more oil in this part of the world as part of an energy security strategy for Australia. We see that it got added value from that perspective. In terms of, I think what you are referring to in the FPSO is the old Woodside FPSO that I believe BW bought, and any options that people have on that, I am not aware of. If we were going forward on that project, we would only make financial commitments for the project at the point we are ready to take FID. Okay. Yeah, that is the FPSO I was referring to, so that makes sense. Yeah. What you said. Thank you so much. Maybe just Thanks, Rob. Can I ask a question about the carbon disclosures? Is it right for me to take your CCS tolling income and your other carbon income and divide that by injection volumes to get a kind of proxy average realized price, or is it? It's probably more complicated than that, I am sure. Hi, Rob. There is a little bit more complication to that. There is a line item for revenue that is received from the ACCUs that are generated at Moomba CCS. There is also obviously some carbon costs that come through that as well, and there is also a lag in terms of when ACCUs are actually issued by the regulator, which comes into play as well. It is slightly more complicated than what you would start to divide it on a headline level. Yeah. Okay. Perhaps suggest you work with an IR group, and they can help you tighten up how to model that. Yeah. Lovely. Will do. Thank you so much. Cheers, Rob. Thanks. Thank you. The next question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead. Thank you for the presentation today, and congratulations on starting up Pikka and Barossa, key growth projects for the company. My question relates to your legacy assets, in particular the Cooper Basin and GLNG. You haven't commented on the production outlook for those assets, and I understand the importance of the Moomba Central Optimization project for the Cooper Basin in terms of cost savings, but what does that mean for the production outlook from that asset? Also with GLNG, with decontracting gas supply volumes, what does it mean for the near-term production outlook there? Can you please comment? Well, let me try and break that down, Gordon, and of course, if I miss anything, please just pick me up on that. But look, we give our guidance at a portfolio level because from year to year, things move around on assets. There's shutdowns and things like that. So we typically give our guidance at a portfolio level. What I can tell you for the Cooper is we'd expect the Cooper Basin to be relatively steady for the next few years around the levels it's been. Now, of course, there's been some temporary impacts in the last couple of years because of floods. I had to smile when Brett said record flooding this year because I think he's told me that three years in a row as he talks about the Cooper Basin. But it has been. The records are getting beaten year- on- year. But the focus in the Cooper Basin, as much as some gas production will drop off another region, again, less of a focus going forward, and the reality is, for those regions, we'd be very open to anyone else owning them going forward if that's what they wanted to do. We are focusing our investment in the central areas and probably the northern areas, but predominantly the central areas of the Cooper Basin, where over 90% of our future resource requiring development sits. We believe we can make that a much lower cost, a higher margin asset by doing that and getting the infrastructure investment right there to electrify and simplify the operations in the upstream fields around the central area. So that's really what we're doing there. We'd expect production in that area to grow once we've finished that project, to balance some of the losses elsewhere that come off the other areas of the Cooper Basin. But ultimately, we're not looking to shrink our production there. We're just looking to maintain it but get higher margin barrels. I can't remember the last part. Oh, GLNG. GLNG. Yeah. GLNG, we have given guidance in terms of some contracts rolling off. The AGL contract will roll off in 2027, and that gas will be available for the domestic market, I guess. Our production will come down by those volumes. However, we are continuing to invest and grow our indigenous production there. The longer term, we will reset guidance on that once we get more clarity, probably going into 2027. Okay. Thank you very much. Thanks, Gordon. Thank you. The next question comes from Nik Burns from Jarden Australia. Please go ahead. Hi, Kevin, Brett, and Lachy. I was just after some clarity on exactly where Barossa LNG is at. I think you've mentioned in the presentation that you're currently producing around 550 million standard cubic feet of gas a day and targeting 600 by the end of the quarter. Just so it's clear, we're all clear, what rate equates to Darwin LNG hitting its 3.7 million ton annum nameplate capacity, and when do you expect to achieve that target rate? Thank you. Thanks, Nik. Well, look, actually, that is a really good question and a complicated one because Darwin's capacity changes depending on what time of year it is because of the seasonal weather impacts. In the middle of winter, when it's cooler, Darwin can produce LNG at a higher rate, probably around the 600 million standard cubic feet per day, although we hope to push it a little bit higher than that because Barossa can go higher than that. In the height of summer, it's probably more like 560-ish, is what the historical performance levels have been at. We want to see if we can push that even higher. We're effectively at winter capacity levels right now. Sorry, summer capacity levels right now, although we're not in the summer, right? That's why we've got a couple of systems just offline and getting some repairs and maintenance work done to them, and they'll be back online next month sometime. That should, I think I've said in my speech earlier on, by the end of September, we're hoping to push that then up to the sort of 600 + rates. Barossa's currently got more capacity available than, or when it's all online, will have more capacity available to it than Darwin can take historically. Darwin used to get about 550 a day from Bayu-Undan coming into the facility. But through debottlenecking and running it with high reliability levels, we'd hope to try and get that up a wee bit. Hopefully, that helps you paint the picture, but it's seasonal, and it just changes at different times of the year. No, that is clear. Thanks for that, Kevin. Basically, by the end of this quarter, you hope to have enough gas available consistently to meet whatever nameplate is available. Yeah, whatever the seasonal nameplate capacity at Darwin is. That is correct. Got it. In the interim, has there been any further need to purchase additional third-party cargoes just to meet any contractual obligations? No, there has not. When everything is running smoothly, we are about eight days between cargoes just now. We are just getting into that cadence now. I think if I average it from the 1st of July, it is probably 9.3 days or something like that because we have had a couple of times where we have taken rates down a bit for maintenance or checking and stuff as you tend to do from time to time. But no purchases in the second half. That is great. Thanks, Kevin. Cheers, Nik. Thank you. Thank you. The next question comes from Baden Moore from CLSA. Please go ahead. Thank you. Thanks for the slide nine with the value drivers on Papua. I was just wondering at this point, just given the location advantage for the plant, is there any indications you can see that you might also be able to achieve some pricing premiums for the gas out of the new project? Just given its differentiated location, it is non-Middle Eastern. Anything you can share on that would be helpful. Then just a second question just for the balance sheet. I noticed there is a slide just highlighting that the target debt number has a timeframe as well to 2030. Maybe I am reading too much into that. Is it more just a guide on absolute gearing target or is timing relevant there as well? Well, let me start with the pricing. First of all, our PNG and Barossa LNG tends to get a premium to market because of the high heating value benefits that the gas from those two projects provides. That's particularly attractive to our northern Asian and Japan customers in particular. We would expect to see that continue as we go forward with Papua when it comes online. In terms of the expectation of Sean and the market team, we've made that very clear to them, right? We've got a great marketing team. They've got a great track record, and you can see in the pricing charts in the pack that we've achieved that consistently over a number of time. On that same chart, you can see how that pricing is driving through against our peers. That's a fortunate position we're in. Mother Nature's been kind to us there, that we've got a high heating value. That's not me taking any away from Sean and the group. They do a great job as well. The two things combined have led to a nice premium advantage there. However, when you talk about the net debt reduction target, what we've set as a timeline on that target that we thought was appropriate, achievable at a reasonable oil price forecast, and we gave ourselves to 2030 to achieve that. It's not tied to any project outcomes or any business outcomes. It's really just a timeline by which we want to get the net debt down. That would take us to the lower end of the gearing range target, 15%. That would be inclusive of leases. When you put those two things together, exclusive of leases, that's probably nearer the 10% mark. That'd be a very low geared balance sheet at that point in time. We believe that is where we want to sit as an operating company. It gives us the flexibility to have a balance sheet that we can use if we have to grow the company beyond that point in time, while still being able to deliver very strong cash flows. Our interest payments would be reduced from what they are today by around AUD 150 million a year. That's freeing up even more free cash flow. That just helps us focus on giving strong returns, investing for growth, but at a low geared level. Thank you. Cheers. Thanks, Baden. Thank you. The next question comes from Adam Martin from E&P. Please go ahead. Yeah, morning, Kevin, Lachy, the Brett team. I was just thinking about the free cash flow breakeven into 2027. You've also got Alaska and Barossa CapEx. Some of the bigger stuff rolling off. You've got some of this exploration appraisal spend that you've called out in the Bedout and the Beetaloo. Do you think that the quantum of that's going to be less than some of those bigger growth projects? I'm wondering whether that free cash flow breakeven into 2027 might actually be lower. Well- It depends. Yeah, no, look, thanks, Adam. It might be. I think what I would say is that we see a little bit of CapEx being spent on appraisal, both in the Bedout and the Beetaloo over the next couple of years. We're going to spend a little bit, but nowhere near the levels we've spent in recent years on growth projects. When you consider the bulk of the CapEx on Papua will be covered by the project financing vehicle, then for the first few years of Papua, then you're right. There's no other major FIDs that we can see in the immediate future that's going to suck up a lot of CapEx. Yeah, it could well be lower than that range. We're not giving any guidance on that. I'm not going to give any pseudo-guidance here today. But you're right, it could be. We'll give that guidance towards the end of the year. I don't foresee any major FIDs anywhere being possible for Santos the next two to three years, except for Papua, which we've given guidance on later this year. As I say, that'll be supported by the financing vehicle, which takes a lot of the heavy lifting on CapEx in the first few years. Okay, good to hear. The second question, just on the whole reservation policy. If you do get the right settings from the government in the next 12 months or so, is there anything in your portfolio you'd look to accelerate? Maybe just talk through that, if you actually got the right settings, what you would do there. Well, look, I think we've got to wait and see what the draft legislation looks like when it comes out shortly for consultation. We believe that the government is listening and trying to get the settings right. But undoubtedly, it won't be perfect because it's very complicated. We'll provide our feedback on that once it comes out. At Santos, we're keen to work with all the stakeholders to get something that works for the industry, for the government, for the manufacturers and users of gas here in Australia. Ultimately, it has to be focused, in my view, on freeing up more supply. Until then, I don't want to start commenting and speculating on what projects might go forward or not go forward because it's too wide-ranging. Obviously, the interest on people buying into or supporting some of those projects will also depend on what those settings look like. It's too speculative to do anything else. We'll just keep working with all the stakeholders until we get something that gives us that certainty, and then we can all buckle down and get on with life. What I will say is that, I'll reiterate, Santos is the second largest supplier of domestic gas in Australia. We've got a strong track record. One of the things that you may not be aware of, Adam, is that you and others on the call, is that since GLNG started up in late 2015 to the end of 2025, Santos has contributed gas to the East Coast market alone, ignoring the very large supply in West Coast. We've supplied gas to the East Coast market alone to the equivalent of 26% of our exports through GLNG over the same period. That's over the period to the end of 2025. We're not overly panicky about anything that's being proposed here. We've been a strong contributor forever. We'll continue to be a strong contributor to the market. We think it's a very important market, and we'll wait and see what we get next month. Okay. No, thank you, Kevin. Thanks, Adam. Thank you. The next question comes from Tom Wallington from Citigroup. Please go ahead. Hi, team. Thanks for the update this morning. Good to see Pikka progressing nicely and the seawater treatment plant reaching the final stages of commissioning there. Just thought it would be a good opportunity to get an update as to what you would need to see technically before progressing any brownfield expansion. I think, Kevin, in the past you've talked about wanting to see around 12 months of production data to get more confidence there. I just wanted to gauge as to how you're seeing this opportunity progress, conscious that it has to compete with capital with other parts of the business. I guess, finally, just in terms of the success you've had there in developing and commissioning key pieces of infrastructure there, just trying to get a sense as to what you're looking at for capital intensity savings for future phases of development. Thanks. Thank you, Tom. Look, I think first of all, I want to start by saying it's no mean feat for a company like Santos to build its first project in the North Slope of Alaska and bring it online. There would've been a lot of people out there that would've said that was a recipe for disaster, going into a very harsh, remote environment, very different operating conditions from anything we've ever faced before. It's been bumpy. We're not going to dispute that. There's been a few bumps along the road, and there'll be a few lessons learned from that. But I'm very confident that given the team that we have on the ground, given the lessons that we have learned, that Pikka will be a fantastic project for Santos. We believe that Pikka has the potential to develop up to 1 billion bbl of oil over time, and we will be very focused on trying to do that and tie it back into the infrastructure. Before we go and think about a phase II or an expansion project or anything like that, we have to get Pikka phase I up and running. We have to see that everything delivers what it was promised to deliver and gather all the lessons from phase I so that whether it be contracting strategies, project management, philosophies, whatever, when we go into the next project in Alaska, that we've captured those lessons, learned them, and that we can improve our performance now that we're an established operator on the North Slope of Alaska. You're right that those projects will also have to compete in the stratum of projects that we have here at Santos. I'm very confident it will be very competitive because I think it's a great world-class Tier 1 asset. But we need to see, as I've said before, a period of time with continuous production, with the water injection system up and running and seeing that it's all doing what it's planned to do to give us the confidence to go again. So it's just being disciplined, being patient. There's a lot of resource there, and we're not rushing. Like I say, I can't see any major FIDs in the next couple of years here at Santos across the portfolio because we'll be in watching and learning mode in Alaska. Now, we might have to do some long lead activities to prepare us for that, but there'll be no major FID decisions. Likewise, in Bedout, likewise in Beetaloo and outside of Papua. I just don't see us FID-ing anything for the next two years or so. Thank you very much. Any major projects. Thank you. Thank you. The next question comes from Cameron Needham from Bank of America. Please go ahead. Yeah. Afternoon, all. Thanks very much for the presentation. Just from 2027, appreciate you've given us the free cash flow sensitivity, and you've outlined your capital allocation framework. In a stronger commodity price environment, how do you guys as a management team think about the optimal use of windfall cash flows? Is it a bit countercyclical thing to do, actually, just retain more of that windfall and get to the bottom end of the gearing range faster than you'd previously anticipated? Thanks. Thank you, Cameron. Look, it's actually really quite simple. It's the same framework applies no matter what the level of cash flow generation is. We're just focused on strong returns, so a minimum of 60% of that free cash flow would be returned to shareholders. In the scenario you're trying to create there, that 40% would be a higher absolute number, so that would help us accelerate reducing debt anyway over our plan. Of course, within all of that, sticking within that framework in terms of how we allocate capital for future growth. I think at the Investor Day, we gave guidance of wanting to grow production somewhere around the 4% CAGR level between now and 2035, and we're not looking to go any steeper or any faster than that. We think that's a very measured and disciplined way to grow the company, and we can do that within our disciplined capital allocation framework, providing good returns to shareholders on the way through after we've been able to invest at a modest level to support that growth rate, and reduce our debt to strengthen the balance sheet at the same time, positioning us to be opportunistic in the future should good opportunities arise to use to leverage off the balance sheet. It's a very balanced approach to it. Stronger commodity prices just means stronger returns, quicker debt reduction, but not looking to grow the company at any higher a growth rate. Great. Thanks. Then, a quick second one if I may. If we don't get a Papua LNG FID or it's not sanctioned, how do we think about backfill optionality in terms of PNG LNG now, and the need to look at other options and timing around that? Thanks. Well, look, we've got a lot of prospectivity and a lot of discovered resource in PNG. We've got projects like Muruk that we could throw in there that would be a filler. Of course, the big one is P'nyang. The big one is P'nyang. If I look at it purely as a barrel of oil equivalent or barrels, backfill, Santos also has, in our PD-L2 production license area, a oil project called Usano that we're going to drill a well probably at the beginning of 2028 to test. That is one we're very excited about, where I think we estimate the structure could have up to 85 million bbl of oil in place. That is something we'd be very excited about. So, we also have the potential to fast-track oil production there as well. So look, we've got options. But I would have to say the organization and our joint venture partners and the government and the land holders at PNG are all working and are very focused on getting to FID this year for Papua. Everybody's very motivated to achieve that, and I've no reason to doubt that we're not going to do that. Great. Appreciate the call. Thanks all. Thank you. Thank you. That does conclude the question and answer session. I will hand the conference back to Kevin for closing remarks. Okay. Well, thank you very much for joining us on our half year results call this morning. If you did not get the opportunity to ask a question, please feel free to reach out to us directly. I will look forward to meeting many of you over the next week or so as we do the rounds. Thank you very much.