Santos Limited

Good morning and welcome to the presentation of Santos' 2025 full year results. I'm speaking today from the traditional lands of the Gardiner people of the Adelaide Plains and pay my respects to elders past and present. I also acknowledge and recognise the support of traditional owners and indigenous people everywhere Santos operates around the world. 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 of our disciplined, low-cost operating model. I'll begin with an overview of our results before handing over to our Chief Financial Officer, Lockie Harris, to present the financial details. Our 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 2026. Then we'll open the call up to questions. In 2025, personal and process safety performance were outstanding, with Santorff ranking the top quartile of our sector globally for personal safety and outperforming the global benchmark for process safety. Our lost time injury rate and total recordable injury rate were Santorff's best on record. Process safety performance, measured by the loss of containment incident rate was the best in more than a decade. While we are proud of these outcomes, we remain focused on continuous improvement, and I'd like to take this opportunity to thank all of our employees across our global operations for their hard work and commitment to continual improvement. Slide 5 summarises our 2025 financial results. The business generated strong revenues and delivered free cash flow from operations of $1.8 billion, EBITDAX of $3.4 billion, and underlying profit after tax of almost $900 million. Our gearing was 26.9% excluding leases and 21.5% excluding leases, notwithstanding a capital-intensive period. This performance demonstrates the value of our disciplined focus on costs, reliability and margin. Accordingly, the Board has resolved to pay a final dividend of 10.3 US cents per share, 48% of free cash flow from operations in the second half. Underpinned by our disciplined low-cost operating model, the base business continues to improve reliability and reduce costs. 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 at $6.78. Pleasingly, we received more than 900,000 ACUs for Moomba CCS Phase 1. B&G L&G plant was at capacity throughout 2025. In GL&G, we saw plant reliability of more than 99.5%, and our marketing and trading teams signed three new LNG sales and purchase agreements in the year. Compounding growth in shareholder returns is driven by consistent value extraction from the underlying portfolio and a disciplined application of our capital allocation framework. For 2025, the 10.3 cents per share will be returned to shareholders in the final dividend, equivalent to 48% of free cash flow from operations in the second half, exceeding our commitment under the capital allocation framework. The total amount returned to shareholders for the year is 23.7 cents per share, which is 43% of free cash flow from operations. The Board's decision to increase returns to shareholders reflects the fact that Barossa 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 investment and significant global inflation. Santos delivered Barossa, a Tier 1 long-life asset, within around six months of the original planned start date and without drawing on additional budget contingency. For a project of this scale and complexity, that is a significant achievement. It demonstrates outstanding project self-execution and disciplined contractor management, despite the challenges of COVID, global supply chain disruption, uncertain regulatory approvals and unprecedented litigation. Just as importantly, it demonstrates our capability to execute major development projects while continuing to run the base business efficiently, reliably and safely. We've taken a very considered approach to the final stages of commissioning to ensure offshore operations achieve a high level of reliability as quickly as possible once fuel production is achieved. The project has a high technical complexity with technology deployed to 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-outs and we are targeting ramping up the fuel production rates in the next few weeks. Mechanical completion of PICA Phase 1 was achieved in January, with ramp-up to plateau production rates expected around the middle of the year. Dynamic commissioning is underway at the Seawater Treatment Plant, Nanoshoot Drill Site B and the Nanoshoot Processing Facility. The Nanoshoot Drill Site B has been handed over to operations, another key milestone towards first oil. Drilling performance remains exceptional. We're now drilling the 26th well and continue to push technical limits. Two combination wells have been completed, including a record 10,000 foot horizontal section that delivers two bottom hole locations with a single well. Combination wells deliver savings on cost as well as rig time, accelerating the drilling schedule and getting more reservoir sections online earlier. 20 development wells have been flowed back, including 10 producers, with average expected start-up flow rates of approximately 7,000 barrels per day per well, in line with pre-drill expectations. The 23rd well delivered the highest productivity to date, with expectations of flow rates of approximately 8,000 barrels per day. Once at full rates, Barossa and Beaker Phase 1 together are expected to lift Santos' production by around 25% by 2027 compared to 2025 levels. In 2026, as these two major development projects are integrated into the base business and we right-size the business, we expect a reduction in headcount of around 10% across the business from 2024 levels. Moving to slide 10, Santos holds a unique and diversified resource base with a 17-year 2P reserve life and a 10-year 1P life. supported by almost 4.7 billion barrels of oil equivalent and reserves and contingent resources. The quality and depth of our inventory underpins our strategy to continue to backfill existing infrastructure and grow production. We are optimistic of making significant resource additions following the appraisal campaigns in the Beetaloo and Berri basins over the next 18 months or so. Across the portfolio, We have a deep inventory of opportunities embedded in the base business. These have the potential to leverage existing infrastructure to lift production and deliver strong returns, supporting our ambition to maintain production between 100 and 120 million barrels of oil equivalent in the near term with clear pathways to sustain growth beyond that. Slide 11 demonstrates the disciplined low-cost operating model in action. With a relatively steady production over the last few years, we have still managed to reduce unit production costs during this period, generating strong cash flows despite falling commodity prices, resulting in our ability to increase shareholder returns over the same period. Additionally, we have delivered two major developments, Numba CCS and Barossa, and are closing in on the start-up of PICA Phase 1. All of this has been achieved while maintaining balance sheet strength improving our personal and process safety performance, and lowering our emissions. Santos has already achieved its 2030 emissions target, supported by the world-class Moonbus CCS project, reinforcing the role lower carbon gas can play in delivering energy security while reducing emissions. Our strategy remains clear. Generate strong cash flow, reward shareholders, reinvest to backfill our infrastructure, and to build new capacity and grow production and continue to operate safely and reliably. I'll now hand over to Lockie to provide an overview of our financial results.

Thanks, Kevin, and good morning, everyone. I'll step through the financial performance for 2025, which reflects a resilient-based business and disciplined execution across the portfolio. In terms of our 2025 financial highlights, free cash flow breakeven from operations was $27.43 per barrel, demonstrating the ongoing cost discipline from our base business. All-in free cash flow breakeven was $58.90 per barrel. Going forward, we will target an all-in free cash flow breakeven of $45 to $50 per barrel. At this range, we will have capacity to invest in projects that add high-quality production volumes, reserves and resources, and continue progressing our organic pre-fit opportunities. Unit production costs were $6.78 per barrel, the best result in a decade, achieved with FX tailwinds and cost discipline. Total 2025 dividends of $770 million include the final dividend declared of $335 million. Slide 14 details our balance sheet strength. 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 Picker Phase 1 nearing production. We remain committed to a resilient balance sheet and maintaining an investment grade credit rating as production and cash flow increase following the delivery of Barossa and Picker Phase 1. This financial strength provides flexibility to fund growth, deliver shareholder returns and actively manage gearing. Our continued investment grade credit ratings from Fitch, Moody's and S&P reflects Santos' in place since 2016. Our long-dated debt maturity profile supports financial stability with an average weighted term to maturity of five years. In 2025, we accelerated the final repayment of the PNG LNG project financing facility, fully repaying the debt. The early repayment reduces interest costs and removes restricted cash requirements, which helps strengthen our liquidity position. Santos now has approximately $4.3 billion of liquidity across cash and undrawn facilities. There are no scheduled debt maturities in 2026, with the next due in September 2027. During 2025, we also successfully completed a $1 billion senior unsecured 10-year bond offering in the US 144A Reg S market. This attractively priced long-term 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 sheet to safeguard our financial 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 protection for the balance sheet. The strength of this balance sheet is what has funded the development projects whilst providing strong returns to shareholders. Our underlying earnings show that product sales revenue remains strong at over $4.9 billion, generating EBITDAX of $3.4 billion and underlying profit of $898 million. Underlying profit is lower than the prior year, reflecting lower commodity prices and a higher effective income tax rate. Our 2025 free cash flow from operations highlights the strength of Santos' diversified portfolio, high-performing core assets, secure LNG contracts, inflation-linked cost discipline. Pleasingly, we continue to maintain high gross profit margins across the portfolio with a gross profit margin of 33.7% this year. We have delivered savings of around $50 million and continue to target an annual savings run rate of $150 million. As we have previously advised, once Barossa and Picker Fudge One are online, we expect our free cash flow sensitivity to increase from around $400 million for every $10 movement in Brent oil up to $550 to $600 million for every $10 movement. As outlined earlier, we achieved record low unit production costs of $6.78 per barrel in 2025, supported by FX tailwinds and discipline cost control. Our TREC record shows we continue to outperform our peers in this space with an unwavering commitment to cost discipline. In addition, we remain focused on our target of less than $7 per BOE unit production cost. Santos is Australia's low cost operator and that is not a slogan, it is a competitive advantage. With the production from Barossa and Picker Phase 1 coming online, Santos is positioned to fully fund the base business and growth capital requirements. This includes exploration and appraisal, decommissioning, corporate and funding cost and investment in growth at an all in free cash flow break even of $45 to $50 per barrel. Our portfolio will keep production between 100 to 120 million barrels of oil equivalent over the next few years, but the $45 to $50 framework allows us to pre-invest in our next stage of growth, including exploration and appraisal projects such as Papua LNG, Betaloo and the Bedouin Basin. Cash flow in excess of our all-in free cash flow break-even will be returned to shareholders at a minimum of 60%. with the remaining 40% available for de-gearing the balance sheet or increased shareholder returns. With a strong balance sheet, Santos has the ability to take advantages of opportunities for value accretive growth. Thank you, and I'll now hand over to our Chief Operating Officer, Brett Darley. Thanks, Lachie, and good morning, everyone.

Let me turn now to the operational performance. Our base business has delivered another strong year. Safety remains a leading indicator of operating capability. and we achieved our lowest lost time injury rep rate on record. We are getting more from our infrastructure with reliability above 98% across PNG gas, PNG LNG plant and GLNG upstream facilities. The GLNG plant at Curtis Island achieved 99.5% reliability. A key competitive advantage for Sanos is our ability to self-execute projects. In 2025, 296 wells were drilled globally. We produced drill duration in the Cooper by two and a half days per well, drilled a record 8,200 metre horizontal well in Alaska and completed the first triple lateral CSG well in Queensland. In 2025, P&G LNG sustained an annualised run rate of 8.6 million tonnes per annum, supported by plant reliability of more than 98% and the first full year production from Angorae. PMG LNG effectively ran full for the year with upstream capacity exceeding planned capacity. We intentionally choked back some of our operated wells, a strong position that highlights the depth and flexibility of our resource base. Our Stannos operated fields provided 17% of PMG LNG gas supply with upstream operated gas reliability of 98%. The Heights 2F2 well was completed with a safe and accelerated start-up in the fourth quarter. Initial production is averaging around 60 TJs a day, further adding volume and resilience to our supply base. Alongside strong operational delivery, we maintained our disciplined cost performance. Upstream PNG production costs decreased 34 cents per BFOE compared to 2024, and overall we delivered a 5% reduction in unit production costs. This improvement was driven by targeted initiatives, including the reorg of our supply chain and logistics services, delivering around 1.3 million in sustainable annual savings, and optimisation of maintenance programs, contributing more than $5 million in savings in 2025. Put simply, P&G 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. GLNG and our Queensland CSG operations delivered another year of strong performance. GLNG produced 6 million tonnes of LNG, shipping 101 cargoes, with more than 99.5% plant reliability. We also completed Train 2 shutdowns safely and on schedule. GLNG continue to support the East Coast domestic gas market, supplying 11 petajoules through seasonal shaping and working with our joint venture partners to exercise contractual flexibility so we can continue supporting the domestic gas market in 26. Upstream supply remains stable with record production rates from Roma of 223 terajoules per day and record average production from Scotia of 105 terajoules per day, underpinned by high facility reliability. And we continue to focus on disciplined cost performance. In 2025, we completed several compressor facility upgrades, enabling the shutdown of a legacy facility. These initiatives delivered around $5 million per annum in production cost savings and unlocked an additional 15 terajoules 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 of our Smart PCP digital program, which reduces failure rates and improves uptime. We also extended our well design capability, drilling our first triple lateral CSG well and achieving our longest inseam lateral length at 3.2 kilometres, increasing reservoir access and improving recovery. In Western Australia, our focus on reliability and discipline execution and infrastructure-led value continues to deliver strong results. Uranus Island averaged 99% reliability in 2025. Production costs improved compared to 24, with unit production costs now approximately $6.15 per BOE, benefiting from strong contribution from the Halyard 2 well and FX tailwinds. The Halyard 2 infill wells is a strong example of our self-execute capability. It came online in the first quarter and has exceeded pre-drill deliverability expectations by 38%, reinforcing the value of developing reserves close to existing infrastructure. The same self-execute, low-cost tie-back model underpins approval of the John Brooks 7 infill well as the next Varanus Island backfill opportunity, while the Varanus Island Compression Project Phase 2 has developed around 24 million barrels of oil equivalent of 2P reserves. The Cooper Basin was impacted by a record-breaking flood event on a scale not seen since 1974, affecting more than 200 wells and several upstream compressor facilities. Our focus throughout has been the safe recovery of these facilities, and I'm pleased to say production rates have now returned to pre-flood levels. We have safely reinstated about 70% of impacted wells and facilities and restored more than 2,500 kilometres of road access. Importantly, drilling activity continued uninterrupted with 104 wells drilled and 80 wells connected during the year. As a result, 30 wells are now ready for connection in early 26 once residual floodwaters recede and full access to flowline routes is restored. Beyond recovery, we continue to advance the long-term potential of the Cooper Basin. Whilst the Cooper has its challenges, we've been progressing our resource opportunities including the granite wash and the patch of watertight gas place. Our future investments will focus on these areas that provide higher margins and contain the majority of our future resource base. We've also progressed in the planning of a new way of operating these areas with the development of the Moomba Central Optimisation Project. This project will transform the cost structure in the central area of the basin and we have plans in place to change the way we're thinking about the Cooper Basin more broadly. In 2025, we also implemented our integrated remote drilling ops centre, the IROC, which will improve safety and cost by taking people out of the field and reducing evaluation costs, and is expected to deliver around $5.5 million in annual recurring savings. It will also improve our stimulation and completion activities, improving overall well productivity. I'll now hand back to Kevin.

Thanks, Brett, and thanks, Lockie. If you step back and look at the global energy system, the starting point is simple. Energy demand continues to rise. The transition isn't replacing one source with another. It's adding new supply to meet structural growth. Gas plays a unique role in that system. It is the only scalable, dispatchable fuel capable of supporting renewables while maintaining grid stability. That makes it a foundation fuel for economies that are growing. Asia remains at the centre of LNG demand growth, with consumption forecast to expand strongly through to 2050. Santos is well positioned with advantage supply into the region, Tier 1 customers and a track record of reliability. In a world of geopolitical uncertainty and shifting trade dynamics, that reliability carries a premium. Customers are prioritising dependable partners. At the same time, Oil demand remains resilient. Projects such as PICA add competitive, low-break-even supply that strengthens our portfolio and long-term cash generation. That structural demand growth is not theoretical for Santos. It's already embedded in the quality and performance of our LNG portfolio. Our LNG marketing business continues to capture value through disciplined, end-use customer-focused contracting. The LNG portfolio is 83% contracted over the next five years, with portfolio pricing realised at 14.6% slope to Brent in 2025. Our average contract price remains above peers and supports strong cash margins. Our proximity to Asian demand centres provides a structural advantage, with lower shipping costs, lower emissions and faster responsiveness compared to more distant suppliers. That advantage is matched by portfolio flexibility. With multiple LNG sources, we can direct volumes into highest value markets and respond to seasonal and market disruptions. Our LNG portfolio is also weighted toward higher heating value gas, primarily from P&G LNG and Barossa, which together account for over 75% of our equity LNG volumes. Customers place a premium on richer LNG, and that is reflected directly in our realized prices relative to our peers. That demand and portfolio strength gives us a clear platform for execution, which brings me to our 2026 strategic priorities. There are eight priorities that will guide our focus in 2026. Together, they form a single operating framework focused on safety, cost discipline, and long-term value creation. I'll step through each of them. The first priority is delivering steady-state production for Barossa, establishing it as a reliable Tier 1, long-life cash engine for the portfolio. 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 priority is bringing PICA Phase 1 to plateau production rate, with a focus on a safe, controlled ramp-up to steady performance. We expect to achieve this very important milestone in the second quarter, and then that focus will turn to achieving the expected levels of reliability of any other Santos asset. The third priority is delivering on P&G LNG backfill projects, P&G remains a core asset in our long-term portfolio, supported by a prolific resource base. Our focus is on sustaining plateau production through near-term backfill opportunities, including the APF pipeline tie-in and an oil infill drilling programme. These are practical, very high-return projects designed to extend asset life and preserve cash generation. The fourth priority is progressing pathway LNG to final investment decisions. PAPWA represents the next phase of development for our P&G platform and is underpinned by a net 2C resource of 1.6 PCF. Just the other day, I was pleased to hear encouraging comments from the operator's CEO clarifying the improved cost position that we are aiming to get an FID decision around the middle of the year. The fifth priority is commencing B2W appraisal activities. BTLU is a transformational opportunity for Australia and Santos. The scale of the resource is globally significant and has the potential to reshape our long-term production profile. This is not a marginal resource addition. It is a new basin with the potential to supply both domestic and LNG markets, subject to successful appraisal. Our 2026 programme is focused on proving commercial flow at scale and demonstrating the basin's development potential. Importantly, Beechaloo sits within a supportive jurisdiction that has established a clear pathway for responsible development. Alongside Beechaloo, the sixth priority is progressing the Bedouin Basin Appraisal Programme. This work expands future supply auctions. We've already discovered five fields in the basin supporting a net 2C contingent resource of 230 million barrels of oil equivalent. The integrated gas and liquid concept is about building scalable value from that emerging position. We're planning to drill up to three gas exploration wells in 2027 to further define that potential and optimise the development concept. A future gas development could be brought back to Devil Creek gas plant to access the domestic gas market or and or toll through adjacent 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 production hub are there, 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 has established a proven operating model 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 centre, supported by significant geological storage capacity and proximity to regional emitters. We have completed critical technical work underpinning a development for bioengineering, which has the potential to be one of the world's largest CCS projects. With existing wells and facilities already in place, by London to 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 G11. That upcoming work programme is focused on expanding Australian storage capacity and building a scalable hub framework. The eighth priority is to conduct a strategic review of our Australian integrated oil and gas portfolio, including the Cooper Basin, Western Australia and Narrabri. This review is underway and we will share further details at our investor day in May. In closing, the momentum we built in 2025, driven by strong base business performance and first production from Barossa, carries directly into 2026. With first LNG from Barossa and our execution agenda already underway, we are focused on discipline delivery and continued value creation for shareholders. Thank you. It's now time for questions.

Thank you. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star then 2. If you're using a speakerphone, please pick up the handset to ask your question. We ask that questions be limited to two per person. The first question today comes from Rob Coe from Morgan Stanley. Please go ahead.

Good morning. Thank you very much and congrats on the high quality of your result, Santos team. My first question just relates to Barossa. I wonder if you can give us any commentary on the CO2 that's coming out of the field in the early days. And then I guess related to that, looking at your climate strategy document, you're kind of looking like CCS FID readiness in about 2027. And just wondering if you could outline some of the critical path towards that, if that's correct. Thank you.

Yeah, thank you, Rob. I'm not quite sure of the first question. I'll try and answer that as I understand it. But I think you mean during the commissioning phase? So, yeah, there is always a little bit more CO2 emissions as you do some flaring as you're commissioning activities. But obviously, once we go into full production, it will be in line with our environmental plan commitments for the production phase. And as you probably are aware, under the safeguard mechanism rules, Barossa has to offset all of its reservoir emissions from day one. And so that will be our plan until we – are able to develop a CCS solution for that project. So we will be offsetting those emissions from day one. In terms of the second part of Bioenden, yeah, we're FID ready now. We've completed the feed work. We've got a little bit of work to do before we take FID. So I'd say we're feed complete, and there's a little pre-FID phase we require to do basically the finalised costs and cost estimates from contractors. But the engineering design work is fundamentally done for that project. That would be an excellent project. And we're in discussions with the regulators about moving forward and trying to progress the approvals to support that project. And it's really those activities that are required before we can go to the next step and take FID. Our estimate of how long that would take, yeah, I think 2027 second half is probably realistic in terms of as quickly as we could get there. But really, it depends on how we get on with the two governments, the two national governments in terms of getting the various approvals, the cross-border approvals for the transport of CO2 and the development approvals in Timor-Leste.

Okay, great. Thank you. That's super helpful. My second question is on the topic of decommissioning. 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 at Mutineer Exeter, 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. And the team there under Jason Young have performed fantastically over the last two years. We've given them the challenge of expediting decommissioning in an extremely cost-efficient, industry-leading way, and they've come through with lots of innovations in order to take cost out of that, because as we all know, it's the cost. Every dollar you spend on decommissioning comes with no return on it. So I can't think of it as investment spend. It's necessary spend, but it's not investment spend. And the guys have done a fantastic job Over the last couple of years, I think we've liquidated something like 600 to 700 million US dollars of liability off of the balance sheet. And as much as the liabilities have only come down a little bit in that time, that's because as we build new projects like Barossa and PICA, they go back on to the decommissioning liabilities on our books. But, of course, they're 20-plus years out. And so we're liquidating a lot of that near-term stuff. And we'll continue to do that for the next two or three years, I think. anywhere from the sort of $200 to $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 on some of these projects. There's been many scopes that the team have been able to deliver under budget. And I think the WA job you're referring to is about $22 million overall under budget for a scope of work last year. There are lots of learnings, and we're continually recycling some of that stuff back through the organisation so that we can continue to drive the costs required to decommissioning our activities down. But the entire team, and it's not only the operations team, it's the commercial teams, we're getting good commercial solutions. For example, we were able to sell a vessel rather than have to decommission it for someone else to use it last year, and that was a bit of a win for us. And you can see in the Van Gogh So the time it took from shutting the field down to that vessel exiting the country was the best in class. So the guys are pushing every boundary, and we're really proud of the effort they're turning in there. But there's a lot of work to go over the next few years. We'll continue to drive those costs down, continue to learn. But as you know, in decommissioning, there's a lot that can go wrong. So building that capability in-house is something we've put a lot of effort into the last few years. to minimise that risk, to minimise that cost exposure. Thank you.

Great. Thank you so much. Thank you. The next question comes from Tom Allen from UBS. Please go ahead.

Morning, Kevin, Lachlan, Brett, and the broader team. On Sandus' free cash flow sensitivity to changes in oil, when Barasa and PICA Phase 1 are at full run rate, Sandus is guiding 40% to 50% stronger free cash flow sensitivity per $10 barrel change in oil price. So the higher production 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? And, you know, as does FX, there's a lot of variables going to that. But one of the biggest contributors is, of course, the fact that if you think from 2027 onwards, 60% of our production is LNG, 10%. will be from Alaska and 20% from our Australian integrated oil and gas assets. Those higher margin barrels that are coming in from Barossa and coming in from Alaska are driving that free cash flow sensitivity in the right direction. And so it's, you know, from 27, I like to think Santos is now a company that, if you go back a decade or so ago, we had a 13.5% investment in a tier one asset. And at the time, we're running a sale process for that because we had balance sheet challenges at the time as an organization. If you look at us today, or certainly from 27, we'll have three tier one assets. We'll be 51% in Alaska equity, 50% equity in Barossa, and we're 39.5% equity in P&G. That dominates our portfolio. and that is giving us a much higher percentage of higher margin barrels, which is increasing that cash flow sensitivity.

Thanks, Kevin. Just on your broader options to accelerate deleveraging, so we've seen a couple of capital recycling initiatives last quarter. You sold the stakes in the Harlow and up in the Bonaparte Basin. Can you comment on broader initiatives that Santa Rosa has to accelerate deleveraging, perhaps tidy up the portfolio further? I think on the call just now, you've called out your eighth strategic priority in regard to the strategic review. You might have mentioned that the Cooper Basin, Narrabri and WA. Anything you can share further?

Tom, 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 that, and we've said all along, is once Perosa and PICA come online, Santos' portfolio changes. Because As much as 60% of our production will be coming from our LNG assets and 20% from the oil project in Alaska, the other 20% is from our Australian integrated oil and gas assets. And those three tier one assets all have high value growth opportunities around those as well. And so what changes now is, of course, we've put in place the $45 to $50 all-in free cash flow target going forward. the organization and within that we still want to grow the business right so um it's the the best margin and the highest value opportunities will win that's where we will invest so it changes the way we think about what and where we invest what we invest in and where we invest and so the review then is really looking at how those assets and the opportunities around those assets fit in to our future growth uh ambitions as an organization and uh I'm not going to comment on what will likely come out of that review, but we'll share that with you when we get to our investor day in a couple of months' time. And what I would say, of course, is we'll continue where it makes sense to clean up the portfolio to do that. We're not going to put targets out there for asset sell-downs or anything like that because we know how precarious that can be from past experience, 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.

Thanks, Kevin. Maybe a follow-up. Your capital framework, clearly calls out that you still need to support growth and you've got quite a broad set of growth options. So can you clarify how you're prioritising? Will projects simply compete for capital based on their forecast returns or their other drivers? Perhaps you've commented now on your future portfolio product mix, but are there other strategic drivers that will bring some projects ahead of others?

We're going to run the business for value. I mean, it's really as simple as that. And so we'll be looking at Those rate of returns, the best returns projects will win every time. And, you know, obviously we've got a very strong LNG production position. Our high heating value LNG has a very high priority and high value for us because not only does that allow us to get better prices for LNG, it allows a lot of portfolio optimization opportunities that are quite seasonal. to create more value. We've done a bit of that over the last year or so, and there'll be a bit of that in 2026 as well. So really, I think the best way to kind of describe what our priority or our focus is there, Tom, is that we'll be running it for value. And so it's really the best value outcomes and the best value projects that we're going to win.

That's clear. Thanks, Kevin. Cheers, Tom. Thank you. The next question comes from Adam Martin from E&P. Please go ahead.

Good morning, Kevin, Lockie, Brett and team. I suppose first question, Kevin, just on the gas market review, just any sort of thoughts, you know, any implications for the business going forward? Just on the federal gas market review there, please.

Well, thanks, Adam. Sorry, that's a very good question and a good opportunity to communicate a few things we've done. Look, I think the main thing to understand with this is that We see no material value impact to reducing third-party gas intake into GLNG. There's a couple of fields we'll continue to take gas from that were developed specifically for GLNG. From 2027, GLNG feed gas will come predominantly from equity gas plus those strategic partner fields that we developed for GLNG. We're working with our partners, and we've already made agreements with partners for certain mitigations in terms of contract reshaping or whatever to limit any liability type impacts. But the bottom line is that it doesn't make sense to buy third-party gas off the domestic market to sell into the LNG markets. The free market is working, and those barrels would be zero-value barrels. GLNG is actually a better asset without doing that. And so, as I say, we see no material impact to Santos. We're going to continue drilling and developing our indigenous resource over the next few years. So you'll see that grow. We should expect that to grow between now and sort of 2029, 2030. And we will not be renewing 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 the LNG sales 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 have come back. But in terms of margin or earnings from that project, we don't see them materially impacted at all because, as I say, the third-party gas really is zero margin barrels or very low margin barrels. And what does that mean for the domestic market? Well, that means that some of that gas we won't be contracting can be turned back into the domestic market, and that will leave pressure on the domestic market and, in my view, should alleviate any shortfall concerns for 2027. Thank you.

And second question, just on the Betaloo, you know, I've obviously seen some encouraging well-performance, well-cost data come out from other operators in the basin. What are you... What are you looking to do differently this time around? I think your well costs are pretty high. It was a few years ago. Obviously, flow rates are pretty low. But any changes around well design that you need to do differently just for these upcoming wells? I think it's the second half for you, please.

Yeah, look, I mean, I think when we drilled it, I mean, it was the early days of drilling in the basin. And I have to say, you know, it looked like a well that I drilled. You know, it wasn't particularly impressive. But we've got better drillers there now. We've got a very experienced team, a lot of shale experience in the team. We've also seen, of course, the drilling performance of other people as that experience has been built over the last five years or so in the basin. So, you know, we're in the process of contracting rigs and getting everything set up for that operation. But Brett, why don't you just give an indication or how you see the drilling plans for 2026, 2027? Yeah, thanks, Stephen.

So, yeah, there's been a lot of drilling up there. There's been 12 wells drilled since we've drilled there last time, and ultimately we want to make sure we learn from that. Tamboran's a partner in that block with us, and they obviously have been getting some good performance, and we'll be definitely leveraging 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 U.S. as well. So we're going to invent all the learnings we can We've got a team focused on delivering this. It's a very focused plan. Our plan is to drill these three wells, ratchet stimulate them as if they were production wells and produce them for 12 months plus to get appraisal results that ultimately will allow us to make an FID decision out of this program. So very, very targeted and we've got the best people on the job. sure that not only have we learned from what's happened in the Beedaloo Basin over the last couple of years, but the latest technologies from the US.

And based on the work that we've done, we're actually very optimistic in terms of the cost of supply target that we need to achieve here for the future development opportunity. And we're targeting the total booking from the Wellsville drill previously and this appraisal campaign of just under five TCF of 2C resources, a very significant and important appraisal program, which hopefully will result in a significant booking of 2C resource.

Okay. Looks like a good opportunity. Thank you. Thanks, Adam. Thank you. The next question comes from Dale Coenders from Baron Joey. Please go ahead.

Good morning, Kevin, Lachlan, and Brett. Firstly, on the cost out, the 10% reduction in headcount, is this in the $150 million savings targeted? Is it net of inflation and other increases? Can you provide a bit more colour around those numbers?

Yeah, look, I mean, we see that as quite a natural – well, a big part of it, anyway, is a natural transition, Dale, as you transition from the project space, if you like, you know, of the two big projects we've had ongoing. And it's pretty natural that your headcount goes up as you build these projects. And as they come off, a lot of those people roll off the organisation. You move more into the operations phase. And some of it's more from efficiencies and technology improvements that are allowing us to see some headcount or FTE reductions as a consequence of that. I'd see most of that occurring over this year as these projects come online. And so, yeah, it's pretty short to medium term. It is included in the 150 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 of rolling off from projects and some efficiency gains and improvements just through technology and different ways of working.

So does that mean it's part of the $45 to $50 per barrel break-even number and the $7 per BOLI OPEX guidance? It's already included in those numbers or is it incremental to them?

No, no, it's already included in those numbers.

Okay. Second question, just on the strategic review, the concept of, I guess, exiting the mature high-cost assets with high-sustaining CapEx requirements to leave a high-quality LNG core, the idea has been around for a while. Are there any other questions or outcomes or considerations that you're thinking of that you can provide a bit more colour and a bit more meat around the bones of the strategic review?

Yeah, look, I mean, what we're not saying is that we're selling anything or buying anything. I think that's very important to clarify up front. Those may end up being outcomes that come from the strategic review, but we're looking differently at the way we think about those assets. how they compete in the portfolio going forward. If they're not going to get capital, what does that mean? If they're not going to compete against Alaska expansion and growth opportunities, or they're not going to compete at near-field opportunity, including oil drilling and P&G, what are we going to do with them? What is the plan for those assets? So everything's on the table in that review, and I'll move forward to sharing the detail of that at our investor day in May. And 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, as I say, at the investor D&D. Okay. Thank you. Cheers, Neil. Thanks.

Thank you. The next question comes from Tom Wallington from Sydney. Please go ahead.

Morning team, thanks for the update. Just on PICA, with development now largely de-risked and now having line of sight to first oil and also noting that execution to date has been a standout, can you please refresh us specifically on what milestones or operating performances you might look to be seeing in terms of progressing a brownfield expansion and just how we should think about the potential timing, noting that You know, you talk about running the business for value and the other growth opportunities that are also competing with this particular opportunity. Thank you.

Thank you, Tom. Look, I mean, it's not been without 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. We're not pleased. The team are not pleased themselves that we've spent more than we intended to spend along the way in inflation in the region. You know, the high activity levels in the region have done inflation there above what we were expecting. So that's not been a great outcome on the cost side. But I have to say, the execution of the project is very high quality. I always get nervous talking about, like, taking the victory lap before you've actually won the game. And so I'm not going to get carried away. We've got that last 5% or so, or last few percent of the project to close out and we're commissioning and we're getting close to that we all know that with projects we've had a few bumps after we started up in Barossa which is not unusual I think something like 20% of FBSOs that have come to Australia have departed pretty soon afterwards to go back to the shipyards for one reason or another and fortunately touch wood we've not seen anything like that through the hook up and commissioning at Barossa it's been pretty good but we've had a few bumps And, you know, no doubt there'll be a few little things we're going to iron out with Alaska as well. But the team's very focused. We're running a very strong commissioning quality assurance process through this process because we want a strong ramp up. And the key to this project is really starting up and getting the water injection plant up and running so that we have a pressure support for the reservoir. Because if we can start up early, that's easy. But if we can't go to full rates, if we start producing too fast without the water injection support, we'll end up leaving barrels behind. So it's really getting the water injection plant up and running, get the pressure support in place, and then it's all about how quickly we can ramp up to full production to plateau rates. But what I'm very pleased about is the subsurface indications are in line with all the pre-drill expectations and, 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 reservoir outcome. So, so far, that's looking very, very promising. And as I said in my notes earlier on, the last well that we just tested was significantly higher in terms of its productivity and deliverability than the previous, or the average for the wells to date. So that's very encouraging. In terms of timing, We're still on track for first oil late Q1, but really it's not about the first oil date. It's really about the ramp-up from that, because that ramp-up is determined by how quickly we get the injection system up and running and the pressure support for the reservoir. And so the plan is to ramp up across Q2, reaching plateau at the end of Q2. But, of course, if we can get the injection up and running and we get a few more wells drilled in that timeframe, there's the opportunity that that could be quicker, yeah.

Thank you.

Thanks, Tom.

Thank you. The next question comes from Nick Burns from Jarden, Australia. Please go ahead.

Yes, hi, Kevin, Lockie and Brett. Thanks for taking my questions. First, just a clarification on your $45 to $50 all-in-a-free cash flow break-even target. Just wondering how prescriptive that number is. Does that set a hard upper limit on investment every year or is it an average over say three years? Just noting the fact that in 2026 it looks like you're going to come in below that number. So whether that provides some flexibility over the next couple of years to maybe lift it above that range. Thanks.

I'm going to throw that one to Lachie. That's a good one for Lachie to handle.

Thanks, Kevin. Thanks, Nick. Yeah, look, we'll guide each year to where we think that that full rain will hit on an annual basis. We're going to take a conservative approach within our well-defined parameters, but we'll guide each year to the 45 to 50. Obviously, it aligns with our gearing target of 15 to 25. And as we've said, we do have a lot of investments that we can look to optimise. So we'll give guidance every year. 45 to 50, I think, will be where we'll be targeting across the range.

Yeah, I think we've set out to 2030. That's what our sort of forecast at this point in time would be. And I think what I would add to that is Lockie made a very good point there. 15% to 25% is our target gearing range. At the lower end of that, our interest payments are significantly lower, and that frees up more capital to reinvest in the business within that framework as well. So de-gearing is actually an important part of the strategy.

So that should mean we should be thinking that of the next two or three years, you could be well below that number if you look to target lower gearing ahead of a pickup in investment towards the end of this decade?

Well, you know, it could be either or, right? I mean, it depends. I mean, you know, we talked about some of the development opportunities that were progressing through appraisal over the next couple of years. 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 might have one in, say, 28, for example, right? And there's nothing scheduled there right now. But, you know, whether that was something in the BTLU or the BEDU, who knows? We'll wait and see what the results of those programs are, and we'll make those decisions as we go. But, you know, it could be either or, quite frankly.

Got it. My second question is just on Papua LNG. You talked, Kevin, 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 US to around $14 billion. Are you able to sort of quantify whether those costs are coming out around that level?

Well, I saw a transcript the other day from Patrick. It's Tal, and he was talking in the $14 to $15 range. I think that was public. Well, it's public now, I guess, but he did actually say that. And, you know, the financing is progressing, the project financing is progressing. Everything's heading in the right direction. There's a few things we still have to get ironed out, but ultimately ourselves, Exxon, Total, are working towards a 2026 fit, and 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 to 50 guidance we've given you, We have assumed that's very important.

That's very clear. Thanks, Kevin. Thanks, Nick. Thank you. The next question comes from Gordon Ramsey from RBC Capital Markets. Please go ahead.

Oh, thank you very much. Kevin, I just picked up on this and maybe it's nothing. You previously have stated that the combined production increase from Barossa and Pika is going to be 25% to 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 before?

No, look, I mean, 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 on that stuff, right? So, as you just have done. But, look, I'd say we're being a wee bit conservative there. But, you know, it's... It's in that range, right? 25% to 30%. Am I being conservative? Yes, a little. But there's also a bit of phasing and timing when things come on. And, you know, we don't know. I'll always say we still don't know how Alaska will perform until it comes on. We were assuming 80,000 barrels a day. That's what we're aiming for as plateau rate. I'm sure we'll get there. The team are confident we'll get there based on the wealth test. But until it's flowing, I don't want to bank it, you know.

And just a second question. I'll just follow up on Alaska. I mean, congratulations on good IPs and the dual completions that you're delivering on these new wells. Can you comment on what annual decline curve you might be expecting from the PICA wells? I know they're starting up really well, but do you have a feel for what Sandals' target would be, let's say, 12 months out or two years out on some of these wells?

Look, I actually can't give you that number off the top of my head, Gordon, but what I can tell you is that we're looking at a five to six year plateau with about, I think it's about two and a half, I'd say two to three years of sustaining drilling going forward, just keeping that performing at those levels before it starts to come off plateau. So five to six years on plateau and you're probably looking at a eight wells, nine wells a year or whatever during that period.

Excellent. Thank you very much.

Thanks, Gordon.

Thank you. The next question comes from Henry Mayer 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 early commissioning and what the current state of the SPSO performance is as you ramp over the next few weeks? Can you imagine?

Yeah, look, I mean, I think the very first thing I would say is that the processing kit is performing really well. So from a processing technical point of view, which is often one of the biggest issues you have with a new gas plant or oil facility, you know, we've not had leaks and things like that, which has been very, very encouraging. And so, you know, I take my hat off to BWO for the quality of the process kit that they've installed. In terms of the issues we've had... A couple of unusual ones. I think I communicated last year that we had a heat sensor software issue that caused us two or three weeks to reset the settings on each one of those, 356 of them, I think, across our facilities. And that was more of a software issue. And it's, you know, I guess part and parcel with the risks you take with all the high-tech stuff we have in our facilities these days. And then following that, our GRE fire water and utility water systems, I should say, had some connection failures that we looked at systemically, and we had to go through a programme of strengthening all of those connections across the facility, because we figured... Not sure if that was a design error or not, but we figured it's a systemic issue that we want to address for the longer term and not take any risks in that. And that cost us two or three weeks around Christmas time. 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 there was a product issue with seals on compressors that our main equipment manufacturer issued to BWO and we've taken the decision 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. So it's a bit like when the airlines give you a product upgrade type alert that you round the planes and fix them. So what we're doing is we're taking some of the compressors offline right now so running at half rates while we replace them and we've got We've got them coming on over the next two weeks. And then, as I say, two or three weeks from now, I fully expect we'll have the potential to be pretty close to, if not at full rates.

Excellent. Thanks, Kevin. And covering a lot of ground with all the assets, maybe jumping into Cupid Basin.

And what I should have said to Henry, just to close on that, obviously we've had a couple of cargoes already shipped and another one in the next few days. So we're still producing and still getting cargos out just at a slower rate until we get the full rates in a few weeks' time.

Sounds good. Thanks, Kevin. Cooper Basin, just any details on the Moomba Central Optimisation Programme, the CAPEX, you're expecting there and improvements to costs and production going forward?

Look, that's a really exciting project for the Cooper Basin because that is a project that certainly makes one part of the Cooper Basin become very competitive. in our portfolio. And without going into great details about it, Brett, maybe 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. Yeah, yeah, thanks.

Thanks, Kevin. Yeah, look, we've been working on a couple of things over the last couple of years along with our joint venture, Beach, and it's really about trying to maximise the value of the Crescent Basin. Part of that is getting a resource and proving up that we can develop the resources in the future. We've made some great progress with granite washing our tight patch of water formations pretty much around our central facilities. We've got a basin that's got hundreds and hundreds of oil and gas fields in an area the size of Wales. What we've been trying to do is get focus on the areas that are going to provide our resources into the future and actually do it at a lower cost. targeting starts of the rocks and we've been 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 central and northern fields, that 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 optimisation will be to completely modernise the Cooper in that area and a very targeted area increasing reliability, reducing costs incredibly significantly and also allowing greater flow from those areas which we're currently constrained on producing, so de-bottlenecking and producing further capacity to bring that gas back to Mirba. And it will completely transform the cost base in the Cooper base.

Thanks Brett.

Excellent. Thanks Dan. Thanks Henry. Thank you. The next question comes from Mark Wiseman from Macquarie Group. Please go ahead.

Good day, Kevin, Brett, Lockie. Thanks for the update here. I've just got two questions, one on the Beetaloo and one on the LNG marketing book. Firstly, on the Beetaloo, with an improved well design and lower well costs over time, we feel pretty optimistic that you should be able to achieve an economic outcome there. But could you provide some perspective just on pipeline and the GLNG joint venture and the willingness of that JV to process Beteloo gas through Train 2? It has been one of the more challenging JVs in your portfolio. Is there a risk that you appraise the Beteloo but face delays on the commercial structuring? Any insight on that would be great. Thanks.

Well, look, I mean, that's a great question, Mark. There's a lot of parts to it. In terms of timing, you know, as Brett said, we're looking to drill the two to three appraisal wells starting second half this year through first half of next year and then put them on production for nine to 12 months, producing them to get the information we need to fully appraise to take us to the point where we'd be confident to go forward and develop. Hopefully that will get us pretty close to five TCF of resource booked that we then get 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 teams going over looking at Permian developments and stuff like that to identify how to do this very efficiently in the Northern Territory and what the cost of supply would be. And we've looked at that cost of supply both to GLNG and also to Darwin. We've started work with both governments on pipeline approval processes to get the various licences, so we're not in that sort of loop that we have been in for a long time, say with Narrabri, for example. Different regimes and different processes, but making sure we're not going to be held up doing those approvals over the longer term. we're very confident in the timeline in terms of when would you be ready to take an FID you're probably looking at earliest sometime late 28 or something like that probably earliest but based on the time you'd be producing the wells more like probably early 29th and if you just think of that as being a three to five year development probably three four years because pipeline is probably the critical part there because the rest of it's just an upstream drilling project um That's the earliest you're looking at any sort of backfill or feedstock opportunities for, say, GLNG. I'm pretty confident when it comes to all of GLNG that when that becomes available, the partners would obviously be very keen for any material resource to come through. It's a value-based decision-making process. I would expect. But if you start to look at GLNG's production profile through GLNG, it's still pretty strong in the early 2030s, still over 5 million tonnes per annum in the 2030s. I think it's still around about a full train in 2040s, 2045, just based on a natural decline curve for the CSG fields. So it's a very strong production profile. But there is one train that starts to open up, I'd say, mid-2030s. And that would be a good opportunity for it. But you shouldn't discount the opportunity to go north to Darwin as well, because that's probably a more economic and lower cost of supply option. And, of course, Santos does have EIS approval for a second train at Darwin. We're the only project that's in approval for a second train there. Already we have that. And so with the right partners, the right opportunities, there's also the 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. And of course, if you start thinking further out to Barossa backfill, a successful BTLU development offers backfill opportunities future as well. So what excites us about the Betaloo Basin is that it's got the potential to fill all of our LNG operations or assets in Australia for decades to come if, and it's a big if at this stage, the appraisal programme goes well and we're able to develop that basin economically.

That's fantastic, Kevin. Thanks for the insight there. And that's my second question on the marketing book. You mentioned 83% contracted over the next four or five years. Is there more work to do on the LNG book as you gain confidence in Barossa and you start to hit nameplate there? Do you layer in more contracts and reduce your spot exposure even further?

Well, look, Mark, our plan is to try and maintain the portfolio round about the 80% to 85% contract, leaving a bit of spot exposure in there as well. And that also allows us to do some of that portfolio optimisation if we don't have it all contracted as well. So our guys have done a great job. If you look at that chart, I think on slide 26, you can see the actual realised prices in terms of slope to Brent, well above benchmark. And you can see on the Wood Mac chart that our relative prices to our competition are significantly higher. And the guys have got a great M&T team led by Sean Pitt, a fantastic team, doing a great job, 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 – I mean, I guess what Sean and the team are doing, we've got some of our portfolio contracted much longer than that, 10 years plus. into the future. What we're saying is it's about 83% over a five-year horizon. And as we keep rolling one year to the next, we'll continue to do short and mid-term contracting opportunistically that makes sense for us. We'll continue to try and form more new partnerships with end users in our key markets. And we're building very strong relationships, long-term relationships with great partners, great customers, in Japan and Korea, and we'll continue to do that going forward.

Thanks very much.

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 left in the line that I'm not going to be able to go to, so I apologise for that, and I'll look forward to catching up with some of you on a roadshow over the next week or so. So thank you very much.