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Kevin Gallagher: Good morning, and welcome to the presentation of Santos' 2025 full year results. I'm speaking today from the traditional lands of the Kaurna people of the Adelaide Plains and pay my respects to Elders past and present. I also acknowledge and recognize 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 2. 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, Lachie 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 Santos ranking in 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 Santos' 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 summarizes 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% including 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 $0.0103 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 ACCUs for Moomba CCS Phase 1. PNG LNG plant was at capacity throughout 2025. In GLNG, we saw plant reliability of more than 99.5%, and our marketing and trading team signed 3 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 the disciplined application of our capital allocation framework. For 2025, the $0.0103 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 $0.0237 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 7 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 6 months of the original planned start date and without drawing on additional budget contingency. On 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 full production is achieved. The project has a high level of 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 field change-outs, and we are targeting ramping up to full production rates in the next few weeks. Mechanical completion of Pikka 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, Nanushuk Drillsite B and the Nanushuk processing facility. The Nanushuk Drillsite 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 2 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 the flow rates, Barossa and Pikka Phase 1 together are expected to lift Santos' production by around 25% by 2027 compared to 2025 levels. In 2026, as these 2 major development projects are integrated into the base business and we rightsize 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 reserves 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 Bedout 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 million 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 2 major developments, Moomba CCS and Barossa and are closing in on the start-up of Pikka 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 Moomba 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 Lachie to provide an overview of our financial results.
Lachlan Harris: Thanks, Kevin, and good morning, everyone. I'll step through the financial performance for 2025, which reflects a resilient base 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-FEED opportunities. Unit production costs was $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 Pikka 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 Pikka 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 reflect Santos' disciplined capital management and low-cost operating model that has been in place since 2016. Our long-dated debt maturity profile supports financial stability with an average weighted term to maturity of 5 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 U.S. 144A/RegS 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 provided strong returns to shareholders. Our underlying earnings show that product sales revenue remained 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 domestic gas contracts and continued 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 Pikka Phase 1 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 million to $600 million for every $10 movement. As outlined earlier, we achieved record low unit production cost of $6.78 per barrel in 2025, supported by FX tailwinds and disciplined cost control. Our track 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 Pikka 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 costs and investment in growth at an all-in free cash flow breakeven of $45 to $50 per barrel. Our portfolio will keep production between 100 million 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, Beetaloo and the Bedout Basin. Cash flow in excess of our all-in free cash flow breakeven will be returned to shareholders at a minimum of 60%, with the remaining 40% available for degearing 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.
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 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 Santos is our ability to self-execute projects. In 2025, 296 wells were drilled globally. We reduced drill duration in the Cooper by 2.5 days per well, drilled a record 8,200-meter horizontal well in Alaska and completed the first triple lateral CSG well in Queensland. In 2025, PNG LNG sustained an annualized run rate of 8.6 million tonnes per annum, supported by plant reliability of more than 98% and the first full year production from Angore. PNG LNG effectively ran full for the year with upstream capacity exceeding planned capacity. We intentionally choke back some of our operated wells, a strong position that highlights the depth and flexibility of our resource base. Our Santos operated fields provided 17% of PNG LNG gas supply with upstream operated gas reliability of 98%. The Hides F2 well was completed with a safe and accelerated start-up in the first quarter -- 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 $0.34 per BOE 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 optimization of maintenance programs, 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. 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 shutdown safely and on schedule. GLNG continued 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 remained 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 AUD 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 in-seam lateral length at 3.2 kilometers, increasing reservoir access and improving recovery. In Western Australia, our focus on reliability and disciplined execution and infrastructure-led value continues to deliver strong results. Varanus Island averaged 99% reliability in 2025. Production costs improved by around $66 million 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 tieback model underpins approval of the John Brookes 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 kilometers 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 flood water is received 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 Pachawarra tight gas plays. 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 Optimization 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 are thinking about the Cooper Basin more broadly. In 2025, we also implemented our integrated remote drilling ops center, 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.
Kevin Gallagher: Thanks, Brett, and thanks, Lachie. 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 center of LNG demand growth, with consumption forecast to expand strongly through to 2050. Santos is well positioned with advantaged 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 prioritizing dependable partners. At the same time, oil demand remains resilient. Projects, such as Pikka, add competitive low breakeven 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 5 years, with portfolio pricing realized 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 centers 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 PNG 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 8 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 Pikka 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 PNG LNG backfill projects. PNG 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 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 of our -- for our PNG platform and is underpinned by a net 2C resource of 1.6 Tcf. Just the other day, I was pleased to hear encouraging comments from the operator 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 Beetaloo 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 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 program is focused on proving commercial flow at scale and demonstrating the basin's development potential. Importantly, Beetaloo sits within a supportive jurisdiction that has established a clear pathway for responsible development. Alongside Beetaloo, the sixth priority is progressing the Bedout Basin appraisal program. This work expands future supply options. We've already discovered 5 fields in the basin supporting a net 2C contingent resource of 230 million barrels of oil equivalent. The integrated gas and liquids concept is about building scalable value from that emerging position. We're planning to drill up to 3 gas exploration wells in 2027 to further define that potential and optimize development concept. A future gas development could be brought back to Devil Creek gas plant to access the domestic gas market 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 center, supported by significant geological storage capacity and proximity to regional emitters. We have completed critical technical work underpinning a development for Bayu-Undan, which has the potential to be one of the world's largest CCS projects. With 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 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, West 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 disciplined delivery and continued value creation for shareholders. Thank you. It's now time for questions.
Operator: [Operator Instructions] The first question today comes from Rob Koh from Morgan Stanley.
Robert Koh: Congrats on the high quality of your results and 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 Bayu-Undan CCS FID readiness in about 2027. And just wondering if you could outline some of the critical path towards that, if that's correct.
Kevin Gallagher: Yes. Thank you, Rob. I'm not quite sure about the first question. I'll try and answer that as I understand it. But I think you mean during the commissioning phase. So yes, 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 1. 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 1. In terms of the second part on Bayu-Undan, yes, we're FID-ready now. We've completed the FEED work, 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 where we require to do basically the finalized 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. Yes, 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 2 governments -- the 2 national governments in terms of getting the various approvals, cross-border approvals for the transport of CO2 and the development approvals in Timor-Leste.
Robert Koh: Okay. Great. That's super helpful. My second question is on the topic of decommissioning. And 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 [ Newton near Exeter ], except for the cyclone impact. So I'm just wondering if you can share any kind of learnings for future efficiency of decommissioning.
Kevin Gallagher: 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 2 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 a cost -- every dollar you spend on decommissioning comes with no return on it, yes? 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 USD 600 million to USD 700 million 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 Pikka, 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 2 or 3 years. I think anywhere from the sort of $200 million 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 our scope of work last year. There are lots of learnings, and we're continually recycling some of that stuff back through the organization 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 looking at good commercial solutions. For example, we're 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 FPSO, the time it took from shutting the field down to that vessel exiting the country was a best-in-class. So the guys are pushing every boundary, and we're really proud of the effort of 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 can go wrong. So 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 exposure.
Operator: The next question comes from Tom Allen from UBS.
Tom Allen: On Santos' free cash flow sensitivity to changes in oil, when Barossa and Pikka Phase 1 are at full run rate, Santos 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?
Kevin Gallagher: Yes, Tom, all of those things matter, right? And as does FX, there's a lot of variables go into 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, 20% 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 from '27, I'd 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 1 asset. And at the time, we're running a sale process for that because we have balance sheet challenges at the time as an organization. If you look at us today or certainly from '27, we'll have 3 Tier 1 assets, we'll be 51% in Alaska equity, 50% equity in Barossa and we're 39.5% equity in PNG. That dominates our portfolio, and that is giving us a much higher percentage of higher-margin barrels, which is increasing that cash flow sensitivity.
Tom Allen: 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 Mahalo and up in the Bonaparte Basin. Can you comment on broader initiatives that Santos has to accelerate deleveraging, perhaps tidy up the portfolio further? I think on the call just now, you've called out on your eighth strategic priority in regard to the strategic review, you made a mentioned at the Cooper Basin, Narrabri and WA. Anything you can share further?
Kevin Gallagher: 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 Barossa and Pikka 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 3 Tier 1 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 for the organization. And within that, we still want to grow the business, right? So it's the best margin, and 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 -- 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 into our future growth ambitions as an organization. And 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.
Tom Allen: And 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 prioritize them? Will projects simply compete for capital based on their forecast returns? Or are there other drivers? Perhaps you've commented now on your future portfolio product mix, but there are other strategic drivers that will bring some projects ahead of others?
Kevin Gallagher: 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 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, allow 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, 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.
Operator: The next question comes from Adam Martin from E&P.
Adam Martin: I suppose first question, Kevin, just on the gas market review, just any sort of thoughts, any implications for the business going forward, just on the federal gas market review there, please?
Kevin Gallagher: Look, thanks, Mark -- Adam, sorry. That's a very good question and 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. But from 2027, GLNG feed gas will come predominantly from equity gas plus those strategic partner fields that we 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 reshaping or whatever to limit any liability type impact. 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 that -- 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. And what does that mean now? That 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 will come back. But in terms of margin or our 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. 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 relieve pressure on the domestic market and in my view, should alleviate any shortfall concerns for 2027.
Adam Martin: And second question, just on the Beetaloo. We've obviously seen some encouraging well performance, well cost data come out from other operators in the basin. What are you looking to do differently this time around? I think your well costs are pretty high. It was a few years ago. And 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 of the year, please?
Kevin Gallagher: Yes. Look, I mean, I think when we drilled it, I mean, it was early days of drilling in the basin. And I have to say, it looked like a well that I drilled. 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 5 years or so in the basin. So we've got -- we're in the process of contracting rigs and get everything set up for that operation. But Brett, why don't you just give an indication of how you see the drilling plans for 2026, '27 and what the plant's appraisal plan is?
Brett Darley: Yes. Thanks, Kevin. So yes, there's been a lot of drilling up there. So 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 is a partner in that block with us, and they have obviously been getting some good performance, and we'll be definitely leveraging everything we can from the other operators, including Tamboran. And we are making sure we're learning from what's happening in the U.S. as well. So we're going to embed all the learnings we can, and we've got a team focused on delivering this. It's a very focused plan. Our plan is to drill these 3 wells, fracture 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 a very, very targeted, and we've got the best people on the job. We will have people from the U.S. involved, whether they work directly for us or through our contractors, to make sure that not only have we learned from what's happened in the Beetaloo Basin over the last couple of years, but the latest technologies from the U.S. 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 a total booking from the wells we drilled previously and this appraisal campaign of just under 5 Tcf of 2C resource. So it's a very significant and important appraisal program, which hopefully will result in a significant booking of 2C resource.
Operator: The next question comes from Dale Koenders from Barrenjoey.
Dale Koenders: Just 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 color around those numbers?
Kevin Gallagher: Yes. 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 projects' phase, if you like, the 2 big projects we've had ongoing, 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 organization, you move more into the operations phase. And some of it's more from efficiencies and technology improvements 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 yes, it's pretty short to medium term. It is included in the $150 million number. It's not in addition to. I mean that's important to clarify. But yes, 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.
Dale Koenders: So does that mean it's part of the $45 to $50 per barrel breakeven number and the $7 per BOE OpEx guidance? It's already included in those numbers? Or is it incremental to them?
Kevin Gallagher: No, no, it's already included in those numbers.
Dale Koenders: Okay. Second question, just on the strategic review. The concept of, I guess, exiting the mature high-cost assets with higher sustaining CapEx requirements to leave a higher-quality LNG core, the idea has been around for a while. Are there any other questions or outcomes or considerations you're thinking of that you can provide a bit more color and a bit more meat around the volumes of the strategic review?
Kevin Gallagher: Yes. 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 upfront. 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 in near-field opportunities, including oil field drilling and PNG, how are they going to -- what are we going to do with them? What is the plan for those assets? And so everything is on the table in that review, and I look forward to sharing the detail of that at our Investor Day in May, and that 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 Day in May.
Operator: The next question comes from Tom Wallington from Citi.
Tom Wallington: Just on Pikka, with development now largely derisked and now having line of sight to first oil and also noting that execution to date has been a standout, could 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 talk about running the business for value and the other growth opportunities that are also competing with this particular opportunity?
Kevin Gallagher: Yes. Look, thank you, Tom. Look, I mean, it's not been without our challenges, right? I mean on the execution front, it's been excellent. The drilling has been superb. Costs could have been better, right? We've got to be frank about that. I mean 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, 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. But I have to say the execution of the projects, they're very high quality. I always get nervous talking about like the -- 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 FPSOs that have come to Australia have departed pretty soon afterwards to go back to the shipyards for one reason or another. And fortunately, touchwood, I've not seen anything like that through the hookup, and commissioning at Barossa has been pretty good, but we've had a few bumps. And no doubt, there'll be a few little things, and we've got the iron out with Alaska as well. But the team is 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, when you're developing anything in a new basin for the first time, that's one of the key deliverables. You can fix little things on the plant. What you can't fix is 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 or 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 get the injection up and running and we get a few more wells drilled in that time frame, there's the opportunity that, that could be quicker, yes.
Operator: The next question comes from Nik Burns from Jarden Australia.
Nik Burns: First one, just a clarification on your $45 to $50 all-in free cash flow breakeven target. Just wondering how prescriptive that number is? Like does that set a hard upper limit on investment every year? Or is it an average over, say, 3 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?
Kevin Gallagher: I'm going to throw that one to Lachie. That's a good one for Lachie to handle.
Lachlan Harris: Thanks, Kevin. Thanks, Nik. Yes, look, we'll guide each year to the -- where we think that, that will range -- 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 said, we do have a lot of investments that we can look to optimize. So we'll give guidance every year, $45 to $50, I think, will be where we'll be targeting across the range.
Kevin Gallagher: Yes. And 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 Lachie 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 degearing is actually an important part of the strategy.
Nik Burns: So that should mean we should be thinking that over the next 2 or 3 years, you could be well below that number as you look to target lower gearing ahead of a pickup in investment towards the end of this decade?
Kevin Gallagher: Well, it could be either/or, right? I mean, it depends. I mean, we're looking -- we talked about some of the development opportunities that we're 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 whether that was something in the Beetaloo or the Bedout, who knows? We'll wait and see what the results of those programs are, and we'll make those decisions as we go. But it could be either/or, quite frankly.
Nik Burns: 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 USD 18 billion to around USD 14 billion. Are you able to sort of quantify whether those costs are coming at around that level?
Kevin Gallagher: Well, I saw a transcript the other day from Patrick, it's Tal, and he was talking in the $14 billion to $15 billion range. I think that was public. And well, it's probably now, I guess. But he did actually say that. And the financing progressing, the project financing progressing. Everything is 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 Papua is in that. We have assumed that Papua is in. That's very important.
Operator: The next question comes from Gordon Ramsay from RBC Capital Markets.
Gordon Ramsay: Kevin, I just picked up on this and maybe it's nothing. You previously have stated that the combined production increase from Barossa and Pikka 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?
Kevin Gallagher: No. Look, I mean, I'd still say it's in that range, Gordon. I've been a bit conservative with the number because you guys always pick me up in that stuff, right? So as you just have done. But look, I'd say we've been a bit conservative there. But it's in that range, right? 25% to 30%. But it kind of -- am I being conservative? Yes, a little. But it's also about phasing and timing and when things come on. And we don't know. I still -- 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 a plateau rate. I'm sure we'll get there. The team are confident we'll get there based on the well test. But until it's flowing, I don't want to bank it, yes.
Gordon Ramsay: Okay. And just second question, I'll just follow up on Alaska. I mean, congratulations on good IPs and the dual completions that you delivering on these new wells. Can you comment on what annual decline curve you might be expecting from the Pikka wells? I know they're starting up really well, but do you have a feel for what Santos' target would be, let's say, 12 months out or 2 years out on some of these wells?
Kevin Gallagher: Look, I actually can't give you that number off top of my head, Gordon. What I can tell you is that we're looking at a 5- to 6-year plateau with about -- I think it's about 2.5 -- let's say, 2 to 3 years of sustaining drilling going forward, just keeping that performing at those levels before it starts to come off plateau. So 5 to 6 years on plateau, and you're probably looking at 8 wells, 9 wells a year or whatever during that period.
Operator: The next question comes from Henry Meyer from Goldman Sachs.
Henry Meyer: Jumping back to Barossa. Could you share any detail on the challenges that were observed during that early commissioning and what the current state of the FPSO performance is as you ramp over the next few weeks, Kevin, you mentioned?
Kevin Gallagher: Yes. Look, I mean, I think the very first thing I would say is that the processing kit is performing really well. So from a process-integrity point of view, which is often one of the biggest issues you have with a new gas plant or oil facility, we've not had leaks and things like that, which has been very, very encouraging. And so my hat goes -- I take my hat off to BWO for the quality of the process that have 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 2 or 3 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, 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 safety -- or utility water systems, I should say, had some connection failures. That we looked at systemically, and we had to go through a program of strengthening all of those connections across the facility because we figured -- I'm 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 on that. And that cost us 2 or 3 weeks around Christmas time. Following that, everything has 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 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. So it's a bit like when the airlines give you a product-upgrade type alert that you ground the planes and fix them, right? So what we're kind of 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 them coming on over the next 2 weeks. And then as I say, 2 or 3 weeks from now, I fully expect we'll have the potential to be pretty close to, if not at full rates, yes.
Henry Meyer: Excellent. And covering a lot of ground with all the assets, maybe jumping into Cooper Basin.
Kevin Gallagher: And what I should have said, 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 cargoes out just at a slower rate until we get the full rates in a few weeks' time.
Henry Meyer: Sounds good. Cooper Basin, just any details on the Moomba Central Optimization program, the CapEx you're expecting there and improvements to cost and production going forward?
Kevin Gallagher: 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 1-minute summary of the scope and why the cost will be coming down so much with that investment.
Brett Darley: Yes, thanks, Kevin. Yes. 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 maximize the value of the Cooper Basin. Part of that is getting a resource and proving up that we can develop our -- the resources in the future, and we've made some great progress with Granite Wash and our tight Patchawarra formations around -- pretty much around our central facilities. So we've got a basin that's got hundreds and hundreds of oil and gas fields in an area the size of Wales. And 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. So targeting starts with 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 are least reliable, the ones that require the most manning. So that step with Moomba Central Optimization will be completely modernize the Cooper in that area -- in 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 debottlenecking and producing further capacity to bring that gas back to Moomba, and it will completely transform the cost base in the Cooper Basin.
Kevin Gallagher: Thanks, Brett.
Operator: The next question comes from Mark Wiseman from Macquarie Group.
Mark Wiseman: I've just got 2 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 Beetaloo gas through Train 2. It has been one of the more challenging JVs in your portfolio. Is there a risk that you appraise the Beetaloo but face delays on the commercial structuring? Any insight on that would be great.
Kevin Gallagher: Well, look, I mean, that's a great question, Mark. There's a lot of parts to it. In terms of timing, as Brett said, we're looking to drill the 2 to 3 appraisal wells starting second half this year through first half of next year and then put them on production for 9 to 12 months, producing them to get the information we need to fully appraise to take us to the point where we would be confident to go forward and develop. That's -- hopefully, that will get us pretty close to 5 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. We've looked at that cost of supply both to GLNG and also to Darwin. We've started to work with both governments on pipeline approval processes to get the various licenses. And 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. So we're very confident in the time line. 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 based on the time you'd be producing the wells, more like probably early '29. And if you just think of that as being a 3- to 5-year development -- probably 3, 4 years because pipeline is probably the critical path there because the rest of it is just an upstream drilling project. That's the earliest you're looking then at any sort of backfill or feedstock opportunities for, say, GLNG. Look, I'm pretty confident when it comes to GLNG that when that becomes available, the partners would obviously be very keen for any material resource to come through. It's a value -- 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 field. 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 has an approval for its second train 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 Beetaloo development offers backfill opportunities, relatively low-cost backfill opportunities for Barossa in the future as well. So what excites us about the Beetaloo Basin is that it's got the potential to fill all of our LNG operations or assets in Australia for decades to come if, it's a big if at this stage, the appraisal program goes well, and we're able to develop that basin economically.
Mark Wiseman: That's fantastic, Kevin. And perhaps my second question on the marketing book. You mentioned 83% contracted over the next 4 or 5 years. 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 spot exposure even further?
Kevin Gallagher: Well, look, Mark, I mean, our plan is to try and maintain the portfolio around about the 80% to 85% contracted, leaving a bit of spot exposure in there as well. And that also allows us to do some of that portfolio optimization 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 realized prices in terms of slope to Brent, well above benchmark. And you can see on the WoodMac chart that our relative prices to our competition are significantly higher. And the guys, look, we've 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 5-year horizon. And as we keep rolling 1 year to the next, we'll continue to do short and midterm 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. Now I'm getting the hook. I believe I'm 50 minutes -- 60 minutes over to you. So I think there's 2 or 3 people left in the line that I'm not going to be able to go to. So I apologize for that, and I look forward to catching up with some of you on a road show over the next week or so. So thank you very much.