I would now like to hand the CEO and Managing Director. Please go ahead. Good morning, and welcome to the presentation of Santos [inaudible] 2024. I'm speaking today from the traditional lands of the Kaurna people. Pay respects to elders, past and present. I also acknowledge the owners and indigenous people everywhere Santos operates around. Before we start, I draw your attention to the usual disclaimer on Slide two. Santos delivered a strong result despite lower commodity prices, with the base business continuing to demonstrate the resilience operating model. I'll begin with an overview of our results before handing over to our Chief Financial Officer, Lachlan Harris, to present. Chief Operating Officer, Brett Darley, will then discuss the operational performance of our base business. Following Brett's presentation, I'll take you through our outlook and strategic priorities for 2024, open the call up to questions. In 2025, personal and process safety performance were outstanding. Top quartile of our sector globally for personal safety and outperforming the global benchmark. Our lost time injury rate and total recordable injury rate were Santos best on record. Process safety performance, measured by the loss of containment incident rate, was the best. While we are proud of these outcomes, we remain focused on continuous improvement, and I'd like to thank all of our employees across our global operations for their hard work and commitment to continuous improvement. Slide five summarizes our 2025. The business generated strong revenues and delivered free cash flow from operations of $1.8 billion-$2.4 billion, and underlying profit after tax of almost $900 million. 26.9% includes, including leases and 21.5% excluding leases, notwithstanding a capital-intensive period. This performance discipline focus on costs, reliability, and margin. Accordingly, the dividend of $0.103 per share, 48% of free cash flow from operations in the second half. Our operating model, the base business continues to improve reliability. Total production for the year was 87.7 million barrels of oil equivalent, an increase on 2024, and unit production cost was the lowest in a decade, $0.78. Pleasingly, we received more than 900,000 ACCUs for Moomba CCS phase I. PNG LNG plant was at capacity throughout 2022. We saw plant reliability of more than 99.5% and our marketing and trading team purchase agreements in the year. Compounding growth in shareholder return extraction from the underlying portfolio and a disciplined application of our capital allocation framework. The $0.103 per share will be returned to shareholders in the final dividend, equivalent to 48% of free cash flow from operations and our commitment under the capital allocation framework. The total amount returned to shareholders for the year is $0.237 per share, which is 43%. The board's decision to increase returns to shareholders, plus is now producing and gearing has passed its peak at a lower level than previously anticipated. Over the last seven years, compound annual dividend growth of more than 13% has been achieved despite a period of major capital global inflation. Santos delivered Barossa, a Tier 1 long-life asset, within around six months of the original plan start date and without drawing on additional budget contingency. For a project, a significant achievement, it demonstrates outstanding project self-execution and discipline, the challenges of COVID, global supply chain disruption, uncertain regulatory approvals, and un... Just as importantly, it demonstrates our capability to execute major development projects while continuing to run the base business efficiently. We've taken a very considered approach to the final stages of commissioning to ensure offshore operations achieve as quickly as possible once full production is achieved. The project is a high level of technical complexity, improve operational efficiency and emissions, and we're currently producing at just under half rates while we go through a sequence of compressor dry gas seal change out full production rates in the next few weeks. Phase I was achieved in January, with ramp up to plateau production rates expected around the middle of the year. Is underway at the Seawater Treatment Plant, Nanushuk Drill Site B, and the Nanushuk Processing Facility. The number two operations, another key milestone towards first oil. Drilling performance remained 26 well and continue to push technical limits. Two combination wells have been completed, including a record 10,000-foot horizontal section with a single well. Combination wells deliver savings on cost as well as rig time, accelerating the drilling schedule and getting more reservoirs. 20 development wells have been flowed back, including prospective start-up flow rates of approximately 7,000 barrels per day per well, in line with pre-drill expectations. Productivity to date, with expectations of flow rates of approximately 8,000 barrels per day. Once a phase I together, are expected to lift Santos production by around 25% to 2025 levels. In 2026, integrated into the base business and we rightsize the business, we expect a reduction in headcount of around 10% across the business. Moving to slide 10. Santos holds a unique and diversified 1P reserves life and a 10-year 1P life, supports 1 billion barrels of oil equivalent in reserves and contingent resources. Depth of our inventory underpins our strategy to continue to backfill existing infrastructure and grow production. Significant resource additions following the appraisal campaigns in the Beetaloo 18 months or so. Across support for opportunities embedded in the base business, these have the potential to leverage existing infrastructure to lift production and deliver strong returns. Our ambition to maintain production between 100 and 120 in the near term, with clear pathways to sustain growth beyond that. Shows the disciplined, low-cost operating model in action. With a relatively, we have still managed to reduce unit production cost during this period, despite falling commodity prices, resulting in our ability to increase shareholder returns over this. Additionally, we have delivered two major developments, Moomba CCS and Barossa, and are closing in on the startup of Pikka phase I. All of this has been achieved while improving our personnel and process safety performance and lowering our emissions. Santos has already achieved its. Supported by the world-class Moomba CCS, the role lower carbon gas can play in delivering energy security while reducing emissions. Strategy remains clear: generate strong cash flow, reward shareholders, reinvest to build new capacity and grow production, and continue to operate safely. I'll now hand over to Lachlan to provide an overview of our financial results. Thanks. I'll step through the financial performance for 2025, which reflects a resilient base business and disciplined execution. In terms of our 2025 financial highlights, free cash flow breakeven $43 per barrel, demonstrating the ongoing cost discipline from our base business. All-in free cash flow breakeven was $58. Going forward, we will target an all-in free cash flow breakeven of $45-$50 per barrel to invest in projects that add high-quality production volumes, reserves and resources, and continued feed opportunities. Unit production cost was $6.78 per barrel, the best result in a decade, achieved with FX tailwinds. Total 2025 dividends of $770 million includes a $35 million dollars. Slide 14, pleasingly, gearing finished the year at 26.9%, including leases, which is a real positive, noting we're at the conclusion of our peak capital investment phase, Barossa is in production and Pikka phase I nearing. Committed to a resilient balance sheet and maintaining an investment-grade credit rating, following the delivery of Barossa and Pikka phase I. This financial growth delivers shareholder returns and actively manage gearing. Our continued investment-grade credit ratings from Fitch, Moody's, and S&P reflect Santos discipline, capital management, and since 2016. Our long dated debt maturity profile supports financial stability with an average weighted term to maturity- 2025, we accelerated the final repayment of the PNG LNG project, repaying the debt. The early repayment reduces interest costs and removes restricted cash requirements, which helps strengthen our liquidity position. Approximately $4.3 billion of liquidity across cash and undrawn facilities. There are no scheduled debt maturities in 2020, December 2027. During 2025, we also see a senior unsecured 10-year bond offering in the U.S. 144A/Reg S market. Capital further strengthens our funding base and supports disciplined growth from our high-quality, diversified portfolio. Consistent with our capital management framework, we continue to protect and strengthen the balance position through hedging strategies for both commodity and FX exposure. Hedging has been undertaken at rates well below the long-term Australian dollar FX average, providing strong balance protection for the balance sheet. Sheet is what has funded the development projects while provided strong returns to shareholders. Our underlying earnings strong at over $4.9 billion, generating EBITDA of $3.4 billion, an underlying profit of $898 million. Underlying profit is lower than the prior year, reflecting lower commodity prices and a higher effect. Our 2025 free cash flow from operations highlights the strength of Santos diversified portfolio, higher LNG contracts, inflation-linked domestic gas contracts, and continued cost discipline. To maintain high gross profit margins across the portfolio with a gross profit margin of 33.7%, delivered savings of around $50 million and continue to target an annual savings run rate of $150 million. Previously advised, once Barossa and Pikka phase I are online, we expect our free cash flow sensitivity to increase every $10 movement in Brent Oil, up to $550 movement. As outlined earlier, unit cost of $6.78 per barrel in 2025, supported by FX tailwinds and... Track record shows we continue to outperform our peers in this space with an un- In addition, we remain focused on our target of less than $7. Santos is Australia's low-cost operator, and that is not a slogan, it is a competitive advantage. With the production from Barossa and Pikka, is positioned to fully fund the base business and growth capital requirements. And appraisal, decommissioning, corporate and funding cost, and investment in growth at an all-in $5-$50 per barrel. Our portfolio will keep production in barrels of oil equivalent over the next few years, but the $45-$50 framework allows us to pre-invest, including exploration and appraisal projects such as Papua LNG, Beetaloo, and the Bedout Basin. Cash flow in breakeven will be returned to shareholders at a minimum of 60%, de-gearing the balance sheet or increase shareholder returns. ... With a strong balance sheet, Santos has the ability to take advantages of opportunity. Thank you, and I'll now hand over to our Chief Operating Officer, Brett Darley. Thanks, Lachlan. Let me turn now to the operational performance. Our base business. Safety remains a leading indicator of operating capability, and we achieved our lowest lost time injury. We are getting more from our infrastructure, with reliability above 98% across PNG gas, PNG stream facilities. The GLNG plant at Curtis Island achieved 99.5% reliability. Advantage for Santos is our ability to self-execute projects. In 2025, 296 wells were drilled globally. In the Cooper, by two and a half days per well, drilled a record 8,200 m horizontal well in Alaska, lateral CSG well in Queensland. In 2025, PNG LNG sustained an annualized 1 million tons per annum, supported by plant reliability of more than 98% and the first full year production from Angore. We effectively ran full for the year, with upstream capacity. We intentionally choked back some of our operated wells, a strong position that highlights the depth and flexibility of our resource base. Our PNG LNG gas supply, with upstream operated gas reliability of 98%. Pleased with a safe and accelerated start-up in the first quarter. In the fourth quarter, averaging around 60 TJs a day, further adding volume and resilience to our supply base. Alongside strong operating cost performance. Upstream PNG production cost decreased $0.34 per BOE, and overall, we delivered a 5% reduction in unit production costs. Initiatives, including the reorg of our supply chain and logistics services, delivering around $1.3 million in sustainable annual savings grams, contributing more than $5 million in savings in 2025. Put simply, PNG LNG is performing. Costs are improving, and we've got a deep runway ahead of us. It's a high-quality, long-life asset in a very strong position. LNG and our Queensland CSG operations delivered another year of strong performance. GLNG produced 6 million tonnes of LNG, shipping 199.5% plant reliability. We also plan on schedule. GLNG continued to support the East Coast domestic gas market, supplying 11 PJ and working with our joint venture partners to exercise contractual flexibility so we can continue supporting the domestic gas market in 2026. Upstream supply remains stable, with record production rates from Roma of 23,223 TJ/day and record average production from Scotia of 105 TJ/day, underpinned, and we continue to focus on disciplined cost performance. In 2025, we completed several... enabling the shutdown of a legacy facility. These initiatives delivered cost savings and unlocked an additional 1 5 TJ a day of incremental production. At the well level, we continue to push technical boundaries. Pump life has improved through solids handling initiatives and the rollout, which reduces failure rates and improves uptime. We also extended our well to the lateral CSG well and achieving our longest in-seam lateral length at 3-point reservoir access and improving recovery. In Western Australia, our focus on reliability, infrastructure-led value continues to deliver strong results. Barossa facility in 2025. Production costs improved by around $66 million compared to 2024, with unit production costs at $0.15 per BOE, benefiting from strong contribution from the Halyard 2 well and FX tailwinds. The Halyard 2 infill well is a strong example of our successful self-execute capability. It came online in the first quarter and has exceeded pre-drill deliverability expectations, reinforcing the value of developing reserves close to existing infrastructure. The same tieback model underpins approval of the John Brookes 7 infill well as the next Varanus Island. Varanus Island Compression Project phase II has developed around 24 of 2P reserves. The Cooper Basin was impacted by a record-breaking flood event on a scale not seen since, affecting more than 200 wells and several upstream compressor facilities. Our focus throughout has been the safe recovery of these facilities. They have now returned to pre-flood levels. We have safely reinstalled facilities and restored more than 2,500 km of road access. Importantly, drilling activity continues. We drilled and 80 wells connected during the year. As a connection in early 2026, once residual flood waters recede and full access to flow line routes is restored. Beyond recovery, we continue to advance the long-term potential of the Cooper Basin. While the Cooper has its challenges, opportunities, including the Granite Wash and the Patchawarra Tight Gas Plays. Our future investments will focus on these areas that provide higher margins and contain the majority of our future resources. Also progressed in the planning of a new way of operating these areas, with the development of the Moomba Central Optimization, transform the cost structure in the central area of the basin, and we have plans in place to change the way we are thinking about the Cooper Basin more broadly. In 2025, we also implemented our integrated remote drilling ops center, safety and cost by taking people out of the field and reducing evaluation costs, and is expected to deliver annual recurring savings. It will also improve our stimulation and completion activities. I'll now hand back to Kevin. Thanks, Brett, and thanks, Lachlan. If you step back and look at the global energy system, energy demand continues to rise. The transition, however, it's adding new supply to meet structural growth. Gas is the only scalable, dispatchable fuel capable of supporting stability. That makes it a foundation fuel for economies. Asia remains at the center of LNG demand growth, with consumption forecast to expand strongly through to 2050. Santos is well-positioned with advanced Tier 1 customers and a track record of reliability. In a world of geopolitical uncertainty and shifting trade dynamics, that customers are prioritizing dependable partners. At the same time, oil demand remains resilient, competitive, low break-even supply that strengthens our portfolio. That structural demand growth is not theoretical for Santos, it's a recent performance of our LNG portfolio. Our LNG capture value through disciplined end-use, use customer-focused contracting. 83% contracted over the next five years, with portfolio pricing realized since slope to Brent in 2025. Our average contract price remains above peer cash margins. Our proximity to Asian demand centers provides a structural advantage, with lower shipping costs, faster responsiveness compared to more distant suppliers. That is flexibility. With multiple LNG sources, we can direct volumes into highest value markets and respond to demands. Our LNG portfolio is also weighted toward higher heating value gas, premium Barossa, which together account for over 75% of our equity LNG volumes. Customers place that is reflected directly in our realized prices relative to our peers. That demand and portfolio form for execution, which brings me to our 2026 strategic priorities. There are eight priorities that will guide our focus in 2026, form a single operating framework, cost discipline, and long-term value creation. I'll step through each of them. The first priority is delivering, establishing it as a reliable, Tier 1, long-life capacity. Barossa is expected to achieve full rates in just a few weeks' time, and throughout the next few months, we'll work to overcome the usual early issues on any new project to achieve the sort of reliability we see across the rest of our operating assets. The second plateau production rate, with a focus on a safe, controlled ramp-up to steady performance. We expect to achieve in quarter, and then that focus will turn to achieving the expected levels of reliability of any other. The third priority is delivering on PNG LNG, buying a core asset in our long-term portfolio, supported by a prolific resource base. Our focus is on sustaining practical opportunities, including an oil infill drilling program. These are practical, very high return projects designed to extend asset life and preserve cash generation. The fourth priority is progressing Papua LNG to final investment decision. Papua represents the next phase of development and is underpinned by a net 2C resource of 1.6 TCF. Just the other day, I was pleased to hear the CEO clarifying the improved cost position that we are aiming to get an FID decision around the middle of the year. The two appraisal activities. Beetaloo is a transformational opportunity for Australia and Santos. The scale of the resource is globally significant and has the potential to reshape our... This is not a marginal resource addition. It is a new basin with the potential to supply both domestic and LNG markets, subject to- Our 2026 program is focused on improving commercial flow at scale and demonstrating the basin's development potential. Importantly, Beetaloo Basin that has established a clear pathway for responsible development. Alongside being the Bedout Basin appraisal program, this work expands future supply options. We've already discovered five fields in the basin, a contingent resource of 230 million barrels of oil equivalent. Gas and liquids concept is about building scalable value from that emerging position. We're planning to drill up to 3-3-GS-A to further define that potential and optimize the development concept. A future gas development could be brought back to Devil Creek gas plant to access the domestic gas market or LNG processing infrastructure to provide access to the export markets. It's early stage, but the ingredients for a material, high rate of return future, and now that we are nearing the end of the current capital-intensive investment phase, we're keen to get back to focusing on moving this opportunity forward. Moomba CCS for large-scale carbon storage. The seventh priority is extending that capability through development of a Northern Australia CCS hub. Northern Australia is well-positioned to become a CCS center, supported by capacity and proximity to regional emitters. Underpinning a development for Bayu-Undan, which has the potential to be one of the world's largest. Existing wells and facilities already in place, Bayu-Undan could provide low cost, large-scale commercial storage for regional CO2 volumes. In parallel, we are progressing feasibility work on additional storage options in the Bonaparte Basin, including G-11. That upcoming work program is focused on expanding Australian storage capacity hub framework. The eighth priority is to conduct a strategic review of Australian integrated, including the Cooper Basin, Western Australia, and Narrabri. This review is underway, and we will share further details at our Investor Day. In closing-... The momentum we built in 2025, driven by strong base business performance, carries directly into 2026, with first LNG from Barossa and our execution agenda focused on disciplined delivery and continued value creation for shareholders. Thank you. 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 press star, then two. If you're using a speakerphone, please pick up the-- We ask that questions be limited to two per person. The first question today comes from Rob Koh from Morgan Stanley. Good morning. Thank you very much, and congrats on Santos team. My first question just relates to Barossa entry on the CO2 that's coming out of the field in the early days. Looking at your climate strategy document, you're kind of looking like Bayu-Undan CCS FID readiness in about could outline some of the critical path towards that, if that's correct. Thank you. I'm not quite sure of the first question. I'll try and answer that, but as I understand it, I think you mean during the commissioning phase for CO2 emissions, as you do some flaring as you're commissioning activities, but obviously, once we get into full production, it'll be in line with our environmental base. As you probably are aware, under the Safeguard Mechanism rules, Barossa, our emissions from day one, and so that will be our plan until we are able to develop a CCS solution for those emissions from day one. In terms of the second part on Bayu-Undan, yeah, we're FID completed the FEED work. We have a little bit of work to do before we take FID. So we're, I'd say we're FEED complete, and there's a little required to do, basically, the finalized costs and cost estimates, but the engineering design work is fundamental. That would be an excellent project, and we're in discussions with the regulators about moving forward and trying to progress. Really, those activities that are required before we can go to the next step and take FID. Well, that would take, yeah, I think 2027, second half is probably realistic, in terms of it's quick, but really it depends on how we get on with the two governments, the two national governments cross-border approvals for the transport of CO2 and with in Timor-Leste. Okay, great. Thank you. That's super helpful. My second question is, and I'm just wondering, you've given us guidance for this year. Just wondering if you can maybe give us a steer on the longer-term outlook. And then also, I guess, during 2025, I think you came in a little bit under budget except for the cyclone impacts. So I'm just wondering if you can share any kind of learnings for future efficiency of decommissioning. Look, first of all, I'd like to say the majority of our decommissioning activities are in Western Australia, under Jason Young, have performed fantastically over the last two years, expediting decommissioning in a extremely cost-efficient, industry-leading way, and they've come through with lots of innovations in order to. It's the cost. Every dollar you spend on decommissioning comes with no return on it. Yeah, so I can't think of it as a spend, but it's not investment spend. The guys have done a fantastic job. Over the last couple of, like, $600 million-$700 million of liability off of the balance sheet, and as much as the liabilities have only come, we build new projects like Barossa and Pikka, they go back on our books, but of course, they're, they're 20+ years out, and so we're liquidating a lot of that near-term stuff. And we'll continue, I think, anywhere from the sort of $200 million-$300 million per year is probably a good way to think about the level of activity over the next few years. You point to some of the cost underspend, and some of that the team have been able to deliver under budget. The WA job you're referring to is about $22 million overall last year. There are lots of learnings, and we're continually recycling some of that stuff back through the organization. Cost required to decommissioning our activities down, but operations team, it's the commercial teams, looking at good commercial solutions. For example, we're able to sell a vessel for someone else to use it last year, and that was a bit of a win for us. And you can see, if you saw, the time it took to from shutting the field down to that vessel exiting the country was a best-in-class. Pushing every boundary, and we're really proud of the effort they're turning in there to go, and over the next few years, we'll continue to drive those costs down, continue to learn. But as you know, in decomm, so, you know, building that capability in-house is something we've put a lot of effort into the last few years to minimize that risk and minimize that cost. Great. Thank you so much. Thank you. The next, [inaudible]PS, please go ahead. Good morning, Kevin. On Santos free cash flow sensitivity to changes in oil, when Barossa and Pikka phase I are at full run rate, 50% stronger free cash flow sensitivity per a $10/barrel change in volumes and lower headcount are clearly a key driver, but what else? The changes to baseline CapEx are implied there, too, or broader cost reduction initiatives? Yeah, Tom, all of those things matter, right? Variables go into that. But one of the biggest contributors is, of course, the fact that 60% of our production is LNG, and 20% from our Australian integrated oil and gas assets. Those higher margin crude coming in from Alaska are driving that free cash flow sensitivity in the right direction. And to think Santos is now a company that you go back a decade, we had a 13.5% investment in a Tier 1 asset for that, because we had balance sheet challenges at the time as an organization. If you look at us, or certainly from 2027, we'll have three Tier 1 assets. We'll be 51%, 50% equity in Barossa, and we're 39.5% equity in PNG. That is giving us a much higher percentage of high back cash flow sensitivity. Thanks, Kevin. Just on your broader options to accelerate de-leveraging. So we've seen a couple of capital recycling initiatives last quarter, and then up in the Bonaparte Basin. Can you comment on broader initiatives and perhaps tidy up the portfolio further? I think on the call, the big priority in regard to the strategic review, you made a mention at the Cooper Basin, Narrabri, and WA. Oh, I admire, I admire your effort, to get me to tell you what the answer is. I'll give you credit for that. But look, I mean, we've talked about the strategic review, but I go back to the fact that really what's driving Pikka come online, Santos portfolio changes. Because, as much as sixty coming from our LNG assets and 20% from the oil project, from an Australian integrated oil and gas assets. Now, those three Tier 1, high-value growth opportunities around those as well. And so what changes now is, of course, you know, we've put in place the $45-$50 forward for the organization, and within that, we still want to grow the business, right? Its margin and the, the highest value opportunities will win. That's where we will invest. And so it changes the way we think about what and where we invest. The review and the opportunities around those assets fit in to our future growth and organization. I'm not gonna comment on what will likely come out of that review, but we'll share that with you when we get to our I nvestor Day. Of course, we'll continue where it makes sense to clean up the portfolio to do that. We're not gonna for asset sell downs or anything like that because we know how tricky, right? But we'll continue if those opportunities come up to clean up the portfolio. We'll continue to look at that and execute it where it makes sense. Right. Your capital framework that you still need to support growth, and you've got quite a broad set of growth options. So can you clarify how you prioritize them? Well, projects simply compete for capital. There are other drivers, perhaps you're, you've commented now on your strategic drivers that will bring some projects ahead of others. We're going to run the business for value. We'll be looking at those rate returns, the best will win every time. And you know, adoption position, our high heating value LNG has a for us, because not only does that allow us to get better prices for LNG, it allows a lot of portfolio optimization, or quite seasonal, to create more value. We've done a bit of that over the last years as well. So really, I think the best way to kinda describe what Tom is that we'll be running it for value. And so, it's really the best value outcomes and the best value. That's clear. Thanks, Kevin. Cheers, Tom. Thank you. From [inaudible]ENP. Please go ahead. Yep. Morning, Kevin, Lachlan, Brett, and team. I suppose first question, Kevin, just on the gas, you know, any implications for the business going forward, just on the federal gas market view there, please? Look, thanks, Mark. I'm sorry. That's a very good question, and good opportunity to communicate a few things we've done. Look, I think the plan with this is that we see no material value impact to reducing into GLNG. There's a couple of fields we'll continue to take gas from, that were developed specifically for GLNG. But from 2020, gas will come predominantly from equity gas, plus those developed for GLNG. And we're working with our partners, and we've already made agreements with partners for certain mitigations in terms of contract, we any liability type impact. But the bottom line is that it doesn't make sense of domestic market to sell into the LNG markets. The free market is working and value barrels. GLNG is actually a better asset without doing that. And so, as I say, we see this, we're gonna continue drilling and developing our indigenous resource over the next few years. So you'll see them now in sort of 2029, 2030, and doing the third-party contracts that still exist as they come up for renewal in a couple of years. What does that mean? That will mean that they will drop back a bit. The production will not be impacted at all. In fact, our production will increase over the next few years. LNG sales will come back, but in terms of margin or materially impacted at all, because as I say, gas really is zero margin barrels or very low margin barrels. Okay. What does that mean for the domestic? Gas we won't be contracting can be turned back into the domestic market. Domestic market and my view should alleviate any 2027. Thank you. You know, I've also seen some encouraging well performance, well cost data. So what, what are you, what are you looking to differently this time around? You know, I think your well costs are pretty high. It was a few low, but any changes around well design that you need to do well, I think it's the second half of the year, please. Yeah, look, I mean, I think when we drill in the basin, and I have to say, you know, it looked like a well that I drilled. You know, that we've got better drillers there now. We got a very experienced team, a lot of shale experience in the team. We've also performance of other people as that experience has been built over the last five. So, you know, we've got. We're in the process of contracting rigs and getting everything set up for- Give an indication or how you see the 2026, 2027. Yeah. What the plan, the appraisal plan, is. Yeah, thanks, Kevin. So yeah, there's been a lot of drilling up there. So there's been 12 wells drilled since we've drilled, we wanna make sure we learn from that. Tamboran is a partner in that block with us. ... and they have obviously been getting some good everything we can from the other operators, including Tamboran. And, you know, we are making sure we're learning from what's happening in the - And all the learnings we can. We've got a team focused on delivering this. It's a very plan. Our plan is to drill these, emulate them as if they were production wells, and produce them for 12 that ultimately will allow us to make an FID decision out of this program. So a lot, very, very targeted, and, you know, we've got people from the U.S. involved, whether they work directly for us or through our contractors, to make what's happened in the Beetaloo Basin over the last couple of years but the last- Based on the work that we've done, we're actually very optimistic. Cost of supply target that we need to achieve here, opportunity, and we're targeting a total booking and this appraisal campaign of just under five TCF of 2C resources. It's a very significant and important appraisal program, and which hopefully 2C resource. Okay. Great. Looks like- Thanks, Adam. Thank you. The next question comes from Dale Koenders, from Barrenjoey. Morning, Kevin, Lachlan, and, and Brett. Just firstly, on the cost out, the 10% reduction in headcount, is this savings targeted? Is it net of inflation and other income color around those numbers? Yeah, look, I mean, we see that as quite a natural trend. Well, a big part of it, Dale, as you transition from the projects we've had ongoing, and it's pretty natural that, you know, your headcount goes up as you build these projects, and as they come off, your organization moves more into the operations phase. And some of it's more than technology improvements are allowing us to see some headcount or FTE reduction. I'd see most of that occurring over this year. And so yeah, it's pretty short to meet the 50 number. It's not in addition to it. I mean, that's important to clarify. But yeah, we see it this year, and it's mainly a combination and some efficiency gains and improvements just through technology and different ways of working. ... $5-$50 per barrel breakeven number and the $7 per BOE OpEx, or is it incremental to them? No, no, it's already included in those numbers. Okay. Review. The concept of, I guess, exiting the mature high-cost diamonds to leave a higher quality LNG core, the idea has been around for a while. Are there any more considerations that you're thinking of, that you can provide a bit more color and a bit more meat on the bones of the strategic review? I'm not saying is that we're selling anything or buying anything. I think that's very important to clarify up front. Those come from the strategic review, but we are, we're looking differently at those assets, how they compete in the portfolio going forward. If they're not gonna get capital, what does that mean? If they're not gonna compete against Alaska expansion and growth opportunities, or they're not gonna compete at near drilling and PNG, how are they gonna No, what are we gonna do with them? What is it, please, on the table in that review, and I'll look forward to sharing the details today in May. Our target is to complete the work. We're well advanced in that work. We've been doing it for a little while. We'll complete that work, and then we'll share it with our investors, the Investor DNA. Okay. Thank you. Cheers, Dale. Thanks. Tom Wallington from Citi. Please go ahead. Morning, team. Thanks for the update. Just development now, largely de-risked, and now having line of sight to first execution to date has been a standout. Can you please refresh us specifically on what milestones or operating performances you might look to addressing a brownfield expansion, and just how we should think about the potential timing, noting that, you know, you talk about, running the business for growth opportunities that are also competing with this particular, opportunity? Thank you. Yeah. So thank you, Tom. There are challenges, right? I mean, on the execution front, it's been excellent. The drilling's been superb. You know, costs could have been better, right? We've got to be frank about that, and we're not pleased. The team are not pleased themselves. Spent more than we intended to spend along the way, and inflation and the high activity levels in the region have driven inflation there above what we were expecting. So that's not been a great outcome on the cost side of the projects. They're very high quality. I always get nervous talking about it, like the actually won the game, and so I'm not gonna get carried away. We've got that last 5% or so to close out. We're commissioning, and we're getting close to that. You know, we've had a few bumps after we started up in Barossa, which is not unusual. You know, I think something like 20 years old that have come to Australia have departed pretty soon afterwards to go back. And fortunately, touch wood, we have not seen anything like that. It's been pretty good, but we've had a few bumps and, you know, no doubt there'll be a few little things. But the team is very focused. We're running a very strong commissioning quality assurance process. We want a strong ramp up and really starting up and getting the water injection plant up and running so that we have our pressure. So if, if we can start up early, that's easy, but, but if we are producing too fast without the water injection support, we'll end up leaving the water injection plant up and running, get the pressure support in place, and then ramp up to full production to plateau rates. But what I'm very pleased about is the subsurface indications are in line, when, of course, you know, when you're developing anything in a new basin for the first time, that's one of the key deliverables. You know, you can fix little things on the plant, but you can't fix it if you get a bad-... That's looking very, very promising, and as I said in my notes, just tested was significantly higher in terms of its productivity or the average for the wells to date. So that's very encouraging. Back for first oil late Q1, but really it's not about the first oil date, it's really about the ramp up from that, 'cause that ramp up is determined injection system up and running and the pressure support for the reservoir. And so the plan is to reaching plateau at the end of Q2. But of course, if we can get the injection up and running, and we, there's the opportunity that that could be quicker. Yeah. Thanks, Tom. Thank you. The next question comes from Nik Burns, from Jarden Australia. Please go ahead. Yes, taking my questions. First one, just a clarification on your $45-$50 all-in free cash flow breakeven, that number is... Like, does that set a hard upper limit on investment every year, or is it an average over, say, three years? 2026, it looks like you're gonna come in below that number. So whether that breakeven may be lifted above that range. Thanks. That's a good one for Lachlan to handle. Thanks, Kevin. Thanks, Nick. Yeah, look, we'll guide each year to the, where we think that that will range. We'll hit on an annual basis in our well-defined parameters, but we'll guide each year, so the $45-$50. Obviously, it, it aligns with $5, and as we said, we do have a, a lot of investments that we, we can look to. Yeah, $45-$50, I think, will be where we'll be targeting across, across the range. That's what our sort of forecast at this point in time would be. I think point there, 15%-25% is our target gearing range. At the lower end of that, our interest payments are significantly able to reinvest in the business within that framework as well. So de-gearing is actually an important part of the strategy. Thinking that, over the next two or three years, you could be well below that number as you lower gearing ahead of a pickup in investment towards the end of this decade. You know, it could be either or, right? I mean, it depends. I mean, you know, we're looking, you know, we talked about some of the development opportunities that we're progressing. So there's no major development spend on the balance sheet in the next couple of years, but depending on the results of those, we may, right? And then there's nothing scheduled there right now, but, you know, whether the... Who knows? We'll wait and see what the results of those programs are, and we'll make those decisions as we go. But thank you. Got it. My second question is just on Papua about the improved cost estimates coming through from the operator. There's been some speculation. I think the JV was targeting a reduction in costs from around the $18 billion-$14 billion. Are you able to sort of quantify where, whether those costs are coming out around that level? Patrick, it's Al, and he was talking in the $14 billion-$15 billion range. I think it was public. He did actually say that. And progressing, the project financing progressing, everything's heading in. Things we still have to get ironed out, but ultimately ourselves, Exxon, Total are working to... And we we'd like that to be around the middle of the year. So we're hoping that's around the middle of the year. And in that $45-$50 guidance we've given you, we've assumed that Papua's on, that's very important. That's very clear. Thanks, Kevin. Thanks, Nick. The next question comes from Gordon Ramsay, from RBC Capital Markets. Please go ahead. Well, thank you very much. Kevin, I just picked up on this, and maybe it's nothing. Stated that the combined production in Pikka is gonna be 25%-30% by 2027. You're now saying 25%. Is that just being conservative? There's no change there. Is there any kind of risk that you're taking into account that you might not have seen? I'd still say it's in that range, Gordon. I'm being a bit conservative with the number because you guys always pick me up, and you just have done. But look, I'd say we've been a wee bit. It's in that range, right? It'll be 25%-30%. But yeah, it kinda... Am I being conservative? Yes, a little, but it's also about phasing and timing and when things come on. And you know, we are still, you know, I'll always say, we still don't know how Alaska will perform until it comes on. We were assuming 80,000 rate. I'm sure we'll get there. The team are confident we'll get there, based on the well test and bank it. Yeah. Okay. And just a second question. I mean, congratulations on good IPs and the dual completions that you... new wells. Can you comment on what annual decline from the Pikka wells? I know they're starting up really well, but do you have a feel for what sounds out or two years out on some of these wells? Look, I actually can't give you that number, Gordon. What I can tell you is that we're looking at a 5 to 6 year plateau, with up to, say, two to three years of sustaining drilling, keeping that performing at those levels before it starts years on plateau, and you're probably looking at a nine wells a year or whatever, during that period. Excellent. Thank you very much. Thanks, Gordon. Thank you. The next question comes from Henry Meyer, from Goldman Sachs. Please go ahead. Morning, team. Jumping back to Barossa, could you share any detail on the challenges that were observed doing that? What the current state of the FPSO performance is as you ramp over the next few weeks, giving- The very first thing I would say is that, the process. Well, so from a processing integrity point of view, which is often one of the biggest issues you have with a new gas plant or oil facility, you know, we're very, very encouraging. And so, you know, my hat goes off, I take my hat off to BW Offshore for the quality of the process. In terms of the issues we've had, once I think I communicated last year that we had a heat sensor that caused us two or three weeks to reset the settings on each one of those 300 Barossa facilities. And that was more of a software issue, and risks you take with all the high-tech stuff we have in our facilities. Our GRE and safety utility water system some connection failures that we looked at systemically, and we had to go through a program of these connections across the facility. Because design error or not, but we figured it was a systemic issue that we want to address for the longer term and not take any risks on that. And that cost us two or three weeks. Following that, everything's been working well. I mean, we've had the usual little kind of tuning type issues you get in any new facility, but a issue with seals of our main equipment issued to BWO. And we've taken the decision to run through, to run it at half rates just now, while we take compressors offline and change those seals now, rather than take the risk of any failures occurring further down the line. Yeah, a product upgrade type alert that you ground the planes and fix them, right? So what we're kinda doing is we're taking it half rates while we replace them, and we've got them coming on over the next two weeks, and then two or three weeks from now, I fully expect we'll have the potential to be pretty close to, if not at full rates. Yeah. Covering a lot of ground with all the assets, maybe jumping into- So Henry, just to close on that, obviously, we've had a couple of cargoes already shipped and another one in the next few, and still getting cargoes out, just at a slower rate until we get the... Yep. Sounds good. Thanks, Kevin. The Cooper Basin, just any details on the CapEx you're expecting there and improvements to costs and production going forward? That's a really exciting project for the Cooper Basin because, you know, that is a project that certainly makes one part of the Cooper Basin become very competitive in our portfolio. Without going into— Do you just want to give a sort of one-minute summary of the scope and why the costs will be coming down so much with that investment. Thanks, Kevin. Yeah, look, we've been working years along with our joint venture Beach, and it's really about the Cooper Basin. Part of that is getting a resource, you know, the resources in the future, and we've made some great progress with the formations around, pretty much around our central facilities. So we've got a basin that's got hundreds of them in an area the size of Wales, and what we've been trying to do is get focused on the areas that are gonna provide and actually do it at a lower cost. So spending a lot of time there, and we've been proving up the economics of those rocks, and then ultimately, that area, which is closer to Moomba, around our area, holds the most of our future production. But it is also our oldest facilities, our least reliable, the ones that require the most manning. So that a step with Moomba Central optimization will be to completely modernize the Cooper in that area and a very reliability, reducing costs incredibly, significantly, data flow from those areas which we're currently constrained on producing. So further capacity to bring that gas back to Moomba. And it will completely transform. Thanks, Brett. Excellent. Thanks. Thank you. The next question comes from Mark Wiseman from Macquarie Group. Please go ahead. Good day, Kevin, Brett, Lachlan. Two questions, one on the Beetaloo and one on the LNG marketing book. Firstly, on the Beetaloo, with an improved well costs over time, we feel pretty optimistic that outcome there. But could you provide some perspective just on pipeline and the GL, and the willingness of that JV to, to process Beetaloo gas through train two? It has been one of the more challenging JVs. Is there a risk that you appraise the Beetaloo but face delays on the commercial structuring? Well, look, I mean, that's a great question, Mark. There's a lot of parts to it. You know, as Brett said, we're looking to drill the 2-3 appraisal wells, start half of next year and then put them on production for 9-12 months. Producing them to get the information we need to fully appraise, we would be confident to go forward and develop. That hopefully will get us pretty close to 5 TCF of resource, confident about going and developing. We've already done a lot of work in what that sort of development would look like. We've had looking at Permian developments and stuff like that, to identify how to do this very efficiently, and what the cost of supply would be. We've looked at that cost of supply both to GLNG and also to work with both governments on pipeline approval processes. So we're not in that sorta loop that we have been in for a long time, say, with firms and different processes doing those approvals for long, or, you know, over the longer term. So we're very confident in the timeline in terms of when would you be ready? Earliest, sometime late 2028 or something like that. Probably, anytime you'd be producing the wells, more like probably early 2029. And if you just think of that as being development, probably three, four years, because pipeline is probably the critical path there. But that's the earliest you're looking then at any sort of feedstock opportunities for, say, GLNG. Oh, look, I'm pretty confident when it comes to when that becomes available. I mean, the part for any material resource to come through is the value I would expect. But if you start to look at GLNG through GLNG, it's still pretty strong in the early 2030s per annum in the 2030s. I think it's still around about a full train just based on a natural decline curve for the CSG fields. So it's a very strong production profile, but there is one mid-2030s. And that, but you shouldn't discount the opportunity to go north to Darwin as well. Economic and lower cost of supply option, and of course, Santos does have EIS approval for a second train at Darwin, approval for a second train already. We have that. And so with the right partners, the right opportunity to expand Darwin, GLNG would be a more expensive pipeline operation, but of course, you already have a train in place, so that's an advantage for GLNG. But Darwin has the opportunity to expand further out to Barossa, backfill, a success, backfill opportunities, relatively low cost backfill opportunities for Barossa in the future as well. Beetaloo Basin is that it's got the potential to fill all of our LNG operations or assets in Australia. If, and it's a big if at this stage, the appraisal program goes well, and we're able to develop. That's fantastic, Kevin. Thanks for... And perhaps to my second question on, you mentioned 83% contracted. Is there more work to do on the LNG book? Are you, as you gain confidence in Barossa and you start to hit nameplate there, do you layer in more contracts and reduce your spots? Well, look, Mark, I mean, our, our plan is to try and maintain the portfolio around about the 80%-85% contract, leaving about as well. And, and that also allows us to, to do some of that portfolio optimization if we don't have it. So our guys have done a great great job. If you look at that chart, I think on slide 26, you can see this is in terms of slope to Brent, well above benchmark. And you can see on the WoodMac chart that our, our relative price higher. And the guys, have we got a great M&T team, led by Sean Pitt, for delivering a lot of value, and, you can see the results in that chart. And that's a chart that's done independently of us. But we'll continue to... But, you know, we've got all some of our portfolio contracted much longer than that, 10, 10 years + out into the future over a five-year horizon. And as we keep rolling one year to the next, we'll continue to do short and midterm contracts. It makes sense for us. We'll continue to try and see more new partnerships with end users, very strong relationships, long-term relationships with great partners, great, great customers, and continue to do that going forward. Now, I'm getting the hook now. I believe I'm 15 minutes, 16 minutes overdue, so I think there's two or three people to go to, so I apologize for that, and I'll look forward to catching up with some of you in a week or so. So thank you very much. Thank you. That does conclude our conference. You may now disconnect.