Santos Aktie

Thank you for standing by, and welcome to the Santos Limited 2026 Half Year Results Briefing. [Operator Instructions] I would now like to hand the conference over to Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead.

Thank you, and good morning, and welcome to the presentation of Santos' 2026 Half Year Results. I'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, indigenous people and nationals everywhere Santos operates around the world. 2026 is a year of transition for Santos. In the first half, we safely commenced Pikka production and continued commissioning and ramp-up at Barossa.

And that is the story of this result, new production coming online while the base business keeps delivering. I'll begin with an overview of our performance before handing to our Chief Financial Officer, Lachlan Harris, to take you through the financial results. Our Chief Operating Officer, Brett Darley, will then cover the operational performance of the base business. And I'll return at the end to discuss our outlook and strategic priorities before we open the call to questions. Before we start, I draw your attention to the usual disclaimer on Slide 2. Safety performance in the first half was strong. We recorded no lost time injuries and no Tier 1 process safety incidents. That discipline underpins everything that we do. Our lost time injury rate has been better than the IOGP global average every year since 2022, including the first half of this year.

In 2025, IOGP recorded its highest number of fatalities since 2015. We see that as a reason to work harder and drive continuous improvement, not to take comfort in our own numbers. Safety remains a core focus at Santos. As Barossa and Pikka transition to stable operations, maintaining the discipline around safety will be critical. Safe, reliable operations underpin our production and cost performance. Slide 5 summarizes our financial results. In a year of transition, the base business kept generating cash, and we declared an interim dividend of USD 0.116 per share for shareholders. Sales revenue of $2.6 billion generated EBITDAX of $1.6 billion and free cash flow from operations of $378 million, offset by commissioning and timing effects, which we expect to unwind in the second half.

Lachlan will step through that shortly. 2026 is shaping up to be a tale of 2 halves. The first half has set us up for materially stronger cash generation as production from Barossa and Pikka build towards plateau. In line with our expectations, July has started the second half with a much stronger performance. It's early, but the direction is consistent with a stronger second half as described. I am pleased that the Board has resolved to pay an interim dividend of USD 0.116 per share, a dividend consistent with our capital allocation framework and reflecting its view of the full year performance outlook. I said at the outset that 2026 is a year of transition for Santos. In the first half, we brought Pikka online safely and Barossa continued to progress through commissioning towards steady state. Each of the 6 Barossa wells has confirmed capacity of 300 million standard cubic feet a day with the wells operating in line with expectations.

Pleasingly, Darwin LNG delivered 100% plant reliability in the first half. At Pikka, initial production reached around 23,000 barrels a day gross and with water injection due to startup shortly, production is expected to ramp towards the 80,000 barrels a day gross plateau by the end of the quarter. Pleasingly, we lifted our first crude oil cargo just last week. At the same time, the major development build is behind us and peak CapEx is also behind us. As Barossa and Pikka ramp towards plateau, we expect second half production to be around 20% to 30% higher than the first half. That combination of higher production and lower CapEx is expected to drive stronger free cash flows. That is the inflection point we have been working towards from major projects investment into production, cash generation and long-term value for shareholders. Moving to Slide 7. First half production was 45.6 million barrels of oil equivalent, up 3% compared to the same period last year. The base business continued to perform reliably across the portfolio, and Barossa is now part of that base, adding meaningful new production.

In Australia, we strengthened our domestic gas position through 2 linked decisions. We executed a gas sales agreement with the South Australian Strategic Gas Reserve to supply 200 petajoules of domestic gas from 2030 to 2040 with a prepayment supporting our investment in the Moomba Central Optimization project. Together, these support the long-term future of the Cooper Basin central fields while targeting more than $600 million of capital and operating cost savings over the life of the central field and up to $3 a barrel reduction in unit production costs. GLNG recently shipped its 1,000th LNG cargo from Gladstone, an important milestone that is testament to the quality of the asset and the strength of our joint venture partnerships and reflects more than a decade of reliable supply to our customers.

Our operations at Varanus Island in Western Australia ran at 97% reliability through the half. All facilities are back online following Cyclone Narelle, and Halyard-2 continues to exceed expectations at around 85 terajoules a day with minimal decline and no water breakthrough. We expect this strong performance may result in a significant upward reserves revision at the year-end. In PNG, we took a final investment decision on the Agogo Production Facility tie-in, targeting an IRR above 50% and a payback of less than 4 years. We also took FID on the PNG LNG oil infill drilling campaign. Papua LNG continues to progress towards a financial investment decision in the second half and the development forum in PNG has now commenced.

In Alaska, Pikka continued to ramp up and the drilling program progressed strongly. We have now drilled 31 development wells and 28 stimulated and 25 flowed back in line with pre-drill expectations. Across all 3 regions, the approach is consistent: disciplined capital allocation focused on high-return opportunities in and around infrastructure we already own and operate. That is the strategy we set out at Investor Day, and this half shows us delivering on that strategy. Moving to Pikka on Slide 8. Pikka coming online is an important milestone for us in Alaska. We achieved first oil in May, moved to continuous production in June and lifted our first crude oil cargo last week when we sold 450,000 barrels. Production was around 23,000 barrels a day gross at the end of the half. And from here, the path to plateau runs through start-up of the seawater treatment plant, water injection and continued buildup of well inventory. The seawater treatment plant is in the final stages of commissioning. The drilling program continues to perform strongly with a third combination well now complete.

We are consistently beating technical limit across the drilling program, taking time and cost out, and we expect to keep improving. We are also progressing well tie-ins, building the inventory needed to support the production ramp. Pikka is a Tier 1 oil asset entering production in a premium market. Our focus now shifts from project execution to running it within our disciplined low-cost operating model to maximize long-term value for shareholders. Papua LNG is a high-quality opportunity for Santos to sustain and increase our equity LNG production in PNG. The project continues to target FID in the second half of 2026 with environmental permits issued, the development forum underway and project financing also progressing well. At plateau, the project is expected to contribute around 1 million tons per annum of equity LNG and around 11 million barrels of oil equivalent a year to our production.

The economics also benefit from integration with PNG LNG. Our 39.9% interest in PNG LNG creates additional value through access fees, processing tolls and cost sharing. Project financing is also expected to fund a significant portion of development capital, reducing the upfront equity requirements. Together, these elements make Papua LNG an increasingly capital-efficient opportunity with multiple and diverse sources of value for Santos. Our disciplined low-cost operating model continues to underpin the business, supporting consistent operations, strong safety performance and reliable shareholder returns. We've maintained that focus through the first half with Barossa and Pikka moving through commissioning and ramp-up alongside solid performance from the base business. And Barossa and Pikka move to plateau, we expect production volumes to rise and unit production cost to trend lower over time as we continue to target less than $7 per barrel of oil equivalent.

The timing of cash flow is also different this year. In recent years, shareholder returns have been more weighted to the first half. This year, with production and realized LNG pricing expected to strengthen through the second half, we expect cash flow to be more heavily weighted to the second half as well. The model remains the same: generate cash, reward shareholders, reinvest to backfill and sustain our infrastructure and to build and grow our production while continuing to operate safely and reliably.

I'll now hand over to Lachlan to provide an overview of our financial results.

Thanks, Kevin, and thank you to everyone for joining us today. In the first half of 2026, we generated sales revenue of $2.6 billion and EBITDAX of $1.6 billion. Free cash flow from operations was $378 million. Unit production cost was $7.53 a barrel and gearing was 28.1%, including leases or 23.2%, excluding. As Kevin has mentioned, we are declaring an interim dividend of USD 0.116 per share. The first half began with JCC-linked pricing at a multiyear low in the first quarter before global energy markets tightened following supply disruption around the Strait of Hormuz. Against that backdrop, LNG realized $10.95 per mmBtu and crude oil realized $92 a barrel across our portfolio, remaining strong compared to peers. This reflects the quality and structure of our portfolio, including premium oil-linked pricing, high heating value LNG, proximity to Asian markets and flexible contract positions.

The Japanese crude cocktail price, or JCC, is now trading above $100 a barrel. Of our contracted position, approximately 80% is linked to JCC and oil indexation. Most of our LNG contracts have around a 3-month pricing lag, so the benefit of that stronger pricing will flow into realized pricing in the second half. The base business continued to deliver strong EBITDAX margin of 59%. Kevin has already touched on the key drivers of first half earnings and free cash flow. However, let me take you through those in some more detail. Free cash flow from operations was $378 million, with the first half result reflecting 3 main factors: commissioning costs at Barossa and Pikka, the timing of cargo movements around 30 June and the PNG underlift position at the end of the half. The first item is commissioning. As Barossa and Pikka move to steady-state production, commissioning-related costs fall away as do the third-party cargo purchases that we have made during Barossa's commissioning period.

The second item is cargo timing. 4 of the 7 Barossa cargoes and 3 PNG equity cargoes were lifted before 30 June with around $300 million of proceeds received shortly after period end. So whilst those cargoes were recognized in sales revenue in the first half, cash was received in July. And finally, we ended the half with a PNG LNG underlift position of around 1.3 million barrels of oil equivalent. An underlift arises when a joint venture participant has lifted less LNG than its proportional share of production over a given period. The production occurred as planned, and this is purely a timing effect. The underlift position is expected to reverse in the second half as the PNG LNG cargo program delivers the corresponding cash receipts.

So the first half free cash flow results include a number of commissioning and timing effects that we expect to unwind through the second half and balance out over the course of the year. Our approach to capital management and capital allocation framework remains unchanged. We continue to hold a high level of liquidity with $3.8 billion at the end of June in a combination of cash facilities and undrawn committed finance facilities with no debt maturities before September 2027. Net debt was approximately $6 billion at the end of the half with gearing of 28.1%, including leases or 23.2%, excluding -- that's above our 15% to 25% target range, reflecting the Barossa FPSO liability now on the balance sheet and the tail of our peak CapEx spend. We continue to target a $2.5 billion reduction in net debt by 2030 and expect to see gearing back in towards the target range as Barossa and Pikka moved to plateau and free cash flow builds.

All 3 rating agencies have reaffirmed our investment-grade ratings, Moody's at Baa3, Fitch BBB, S&P BBB- and Moody's has moved us to a positive outlook. We have hedged 11.5 million barrels of oil for the second half through zero-cost collars with a floor of $67.10 and an average cap of $98.59. In the first half, oil hedging realized a loss of $37 million. On foreign exchange hedging, we hold hedges for AUD 975 million for the second half at an average rate of $0.643 and just over $1.5 billion for 2027 at $0.658. In the first half of 2026, FX gains were $75 million. It is a balance sheet that supports the base business, funds growth and rewards shareholders. Moving to Slide 16. Our free cash flow breakeven has come down year after year, and it's targeted in a $45 to $50 a barrel band through to 2030. That improvement is driven by cost and capital discipline, not a higher oil price assumption.

At this level, we will drive shareholder returns through the base business whilst investing in sustainable growth. In addition, we continue to target a free cash flow breakeven from operations of below $35 per barrel. Santos' sensitivity to oil is improving, too. For every $10 Brent trades above our breakeven, free cash flow increases from around $400 million today to between $550 million to $600 million once Barossa and Pikka reach plateau, an increase of around 50%. A lower breakeven and a higher sensitivity to oil means that at the same oil price, it does more for shareholders than it used to. That's the model getting stronger as the portfolio is upgraded and diversified as new production comes online. The portfolio isn't just generating more cash.

It's generating higher-quality returns. EBITDAX margin has expanded as unit production cost has fallen over time. Margin is up around 30% since 2016, while unit production cost has come down over the same period. That margin has remained strong over the period despite first half timing impacts, a function of higher-margin barrels working through the portfolio. And it's underpinned by structural cost savings. We remain on track to deliver annual recurrent savings of $150 million by the end of 2026. A lower cost base and higher-margin barrel business mean the same production does more for shareholders than it used to. Thank you, and I'll now hand over to Brett.

Thanks, Lachie. I want to turn the focus now on our operational performance starting on Slide 19. 111 cargoes were shipped across Australia and PNG in the first half. The ramp-up in Barossa production lifted upstream LNG production by 12% and an LNG upstream unit cost of $6.80 a barrel. Barossa is currently producing around 550 million scuffs per day and increasing to around 600 million scuffs per day by the end of the quarter with cargo cadence of approximately every 8 days. Each of these 6 Barossa wells are operating in line with expectations, and the facility achieved reliability above 85% through July. We reported through the first half some challenges during Barossa commissioning and ramp to full rates.

We have moved beyond these challenges and have moved into operating mode. Through the second half, there will be planned statutory maintenance and routine testing of the FPSO safety systems, and we will provide further detail as the timing firms up. Santos-operated fields supplied 15% of PNG LNG's plant. Reliability there was above 99%, and the plant is sustaining an annualized run rate of 8.7 million tons. DLNG and GLNG plant reliability ran at 100%. Roma set a record of 230 terajoules a day and 98 additional wells were drilled across the GLNG acreage. Our drilling program keeps finding ways to improve costs. Extended reach GLNG wells delivered around $100 per meter in cost reduction gross, letting us reach geographically where we couldn't get to efficiently before and achieve additional production volumes. That's our self-execution capability at work, the same in-house drilling expertise showing up as lower cost per meter well after well.

Put simply, the base business is performing well. On Slide 20, looking at our performance in Australia and PNG -- continuing looking at our performance in Australia and PNG LNG, our upstream production stepped up to 30.2 million barrels of oil equivalent. LNG sales volumes reached 7.7 million tons gross with Barossa LNG now a distinct contributor to both production and sales volumes. Unit production costs remained steady at $6.80 a barrel and plant reliability at over 99% across PNG LNG, GLNG and Darwin LNG. That consistency is what the operating model is built to deliver. Domestic oil and gas operations generated $85 million of free cash flow from our disciplined low-cost operating model. Sales gas was 76.4 petajoules for the half. As Kevin said earlier, Halyard-2 in Western Australia continues to perform well ahead of expectations, producing around 85 terajoules a day. Western Australia produced below $7 a barrel, excluding cyclone impacts.

The Harriet Alpha platform was safely removed ahead of schedule and approvals are progressing for the John Brookes backfill program for Varanus. The Cooper Basin experienced record rainfall this half, more than double our annual average. We put over 25,000 contractor hours into road recovery and held production costs on target through this period. The basin is back to pre-2025 flood production with around 80% of the flood-affected wells restored and 30 drilled but unconnected wells ready to connect as access comes back. We took FID on the Moomba Central Optimization project, targeting more than $600 million in CapEx and OpEx savings and up to $3 a barrel of Cooper Basin unit production costs.

This year's well program is a 75-well campaign prioritizing activities in the lowest cost part of the basin near central field. Upstream production was 15.4 million barrels of oil equivalent this half, down from 16.8 million a year ago. That's consistent with our strategic review of our Australian domestic gas business, a shift towards a lower capital intensity, higher-margin footprint that delivers cash while meeting our contracted and decommissioning commitments. Reliability stayed strong through the half. Varanus Island ran around 97% for the half, Moomba plant at close to 100%, Port Bonython at 100% and Moomba CCS above 95%. Cumulative storage at Moomba CCS has now reached around 2.3 million tons of CO2 equivalent, safely and permanently stored since start-up.

I'll now hand back to Kevin.

Thanks, Brett. Moving to Slide 24. The broader market backdrop continues to reinforce the importance of reliable energy supply. We've seen again this year how quickly geopolitical events can disrupt global LNG markets. Events around the Strait of Hormuz have highlighted how exposed global energy markets remain when supply is concentrated in a relatively small number of regions and trade routes. At the same time, underlying demand remains strong, particularly across Asia, while years of underinvestment in new supply is becoming increasingly important.

For Santos, that reinforces the strategy we have been pursuing for some time, maintaining a disciplined, low-cost business and investing in reliable oil and LNG supply close to the markets that need it. This approach has and will continue to ensure the portfolio is well positioned for the longer term. Australia has plenty of gas. Last year, gas production for both exports and the domestic market was just over 6,000 petajoules. Based on Geoscience Australia's estimates, Australia has enough total demonstrated resources, that's 2P and 2C to keep producing at that rate for the next 40 years. The challenge is getting those gas resources developed and into the market when they are needed. Santos is already Australia's second largest domestic gas supplier, and we have a long history of supplying Australian customers alongside our LNG business.

Importantly, the government's own data shows there is no gas supply crisis. AEMO's latest outlook shows near-term gas adequacy has improved through to 2029. But from around 2030, new supply will be required as existing fuels decline. That does not mean there will be a gas shortage. It just means we have to invest in developing new gas supply sources now. That is why the investment signals being set today matter. Projects that will supply the market in the early 2030s need investment decisions well before then. Policy settings need to support that investment, not to discourage it. GLNG is a good example of how that can work. GLNG contracts have underwritten the development of Senex and Meridian's gas projects, and those projects also supply gas into the domestic market. Australia does not have a gas shortage. We have plenty of gas. What we need is confidence to invest and bring that resource to market reliably and competitively when Australia needs it.

Across Australia, PNG and Alaska, we have around 4.7 billion barrels of oil equivalent of 2P reserves and 2C contingent resources. Our 1P reserve life is 10 years at the top end of our global peer group and our 2P reserve life is 17 years. Importantly, much of this resource is in and around areas we already have operations and can be developed through infrastructure already in place, supporting capital-efficient growth and creating opportunities to extend the value of our existing assets and infrastructure positions. The other important point is the production mix. LNG representing 50% -- 57% of production in the first half with domestic gas at 33% and liquids at 10%. That LNG weighting matters because much of our LNG is priced off oil with around a 3-month lag to JCC, meaning the stronger JCC pricing through the second quarter is expected to flow through to stronger realized LNG pricing in the second half.

Moving to Slide 27. You'll recognize this framework from Investor Day in May, so I won't take you through it again in detail. The key point is that our growth is concentrated in 3 advantaged regions: Alaska, PNG and Australia, where we have scale, margin and infrastructure advantage. In Alaska, Pikka has now started up and opens a runway of oil growth. In PNG, we have conventional gas, significant backfill opportunities and material oil upside. And in Australia, Barossa is now online alongside longer-dated opportunities in the Beetaloo and Bedout Basins. Importantly, that growth is supported by a strong base business, including Midstream and Energy Solutions, Australian domestic gas operations and marketing and trading, which helps lower costs, improve reliability and capture additional value across the portfolio.

As we move into the second half, our strategic priorities remain clear, and we are on track and delivering against them. Barossa is now producing at close to planned rates and Pikka is now producing and ramping up. In PNG, we are progressing backfill opportunities and the Papua LNG project is targeting FID in the fourth quarter of this year. We are also moving our next wave of opportunities forward. Beetaloo appraisal wells spud at the end of this month. The Bedout appraisal program is progressing, and we continue to engage with the government of Timor-Leste to progress the Bayu-Undan CCS project. And importantly, as announced at our Investor Day, we have completed the strategic review of our Australian integrated oil and gas portfolio, creating a lower capital intensity, higher-margin domestic gas business.

Our focus for the remainder of 2026 is straightforward, execute these priorities safely and with discipline, continue to strengthen free cash flow and deliver sustainable shareholder returns. And that execution brings us back to the Santos value proposition. We have a high-quality, geographically diverse asset base with large-scale growth opportunities built around advantaged infrastructure and an all-in breakeven oil price target of $45 to $50 a barrel. Barossa and Pikka are now adding new production and driving the next step-up in free cash flow. From 2027, every $10 of realized oil price above our breakeven is expected to generate an additional $550 million to $600 million of free cash flow. And through our disciplined capital allocation framework, we will return at least 60% of free cash flow to shareholders while reducing net debt by $2.5 billion by 2030. High-quality assets, growing free cash flow, disciplined shareholder returns. That is the Santos value proposition. Thank you.

I'll now open the call to questions.

[Operator Instructions] The first question today comes from Uwan Minogue from Barrenjoey.

On Papua, is there any update you can give us on how the development forum is proceeding?

Thanks for the question. Look, our understanding is progressing well. I mean there was a stall after a few weeks when it first got up and going when there were some challenges, and those issues were resolved and the forum went back operational 2 or 3 weeks back. And our understanding is it's going to plan. All the feedback has been very positive. And we'd expect that to go through probably to the end of September or something like that before that concludes. And that's the last sort of major government process step in the approvals process for the project.

The next question comes from Tom Allen from UBS.

So the Board opting to pay out looks to be 100% of free cash flow from operations over the half, just with gearing still a little elevated, certainly implies that the Board is very comfortable with the outlook. So on the second half, so getting Pikka at 80,000 barrels a day is no doubt the focus. You've just confirmed today that production is still at 23,000 barrels a day. So commissioning the seawater treatment plant, is that the single largest operational risk for Santos to manage over the second half and meeting that delivery rate at 80,000 barrels a day over the next 40 days?

Thanks, Tom. Thanks for the question. And you're right. I mean the Board's consideration for the dividend was very much focused on the full year performance. And of course, they've got the benefit of seeing what was a very strong month in July as further evidence supporting that. And so -- and that's driven at this point, mainly by the JCC pricing coming through in July, but obviously, we didn't have in that second quarter and the increased production from Barossa that we're now seeing. As far as Pikka is concerned, as much as we've only been producing around 23,000 to 25,000 barrels a day over the last couple of months, we've constrained that production. The wells could produce a lot more than that.

And we've constrained that production because we need water injection support, pressure support for the reservoir so that we don't produce too fast, if you like, and then end up depleting pressure in the reservoir before we've got the pressure support, leaving barrels behind in longer term. So that's just purely reservoir management. And what we've been doing in the meantime is cycling wells around and cleaning them up fully so that we can get an accelerated ramp-up once we get the water injection running. We're close to the very end of the commissioning on the seawater treatment plant.

In fact, I can tell you that the plant is operational at this point in time and water is going into the pipeline. And so we're very advanced in the commissioning, and we expect to complete that very, very shortly, at which point we then start the injection into the wells. And once we start injecting in the wells, we can start that ramp up. And our schedule still has us forecasting that, that would get to the plateau before the end of the quarter. So I think we've said late in the quarter. So if you think towards the end of September, that ramp-up, think of it more or less as a straight line between once we start water injection quite soon through the end of September. The production plant is all operational and just waiting for that injection to start up.

Okay. That's encouraging. And just quickly, there's press reports in the recent weeks of a potential change in operator, possibly equity interest in the Papua LNG joint venture. I think Santos equity is at 17.7% post the government backing rights. You confirmed at the IBD that if there were opportunities to increase Santos equity, that might be of interest. Should we anticipate these opportunities for Santos in the near term? And could you confirm that Santos still supports its broader growth and higher cash payout if it were to seek more equity in that particular project?

Look, what I would say to Tom, thank you for that question and put me on the spot with that. What I would say is that, first of all, the joint venture partners are all talking in detailed discussions as we approach FID on how to best execute the project. And any changes or updates on how we're going to do that, of course, I'd expect the operator to announce at the appropriate time. In terms of equity, you're right. We did comment at the Investor Day that we'd always be open to any opportunity if that was to come our way. We obviously don't comment on M&A activities before we've got something to talk about. And so if anything changes there in the future, of course, we'll announce it and we'll communicate it to you then.

But look, we believe that Papua is a great project. But it doesn't matter what projects we do in our portfolio, whether it's Papua, any projects in Alaska or elsewhere in the future, they'll all be within our capital allocation framework. There will be no change to the capital allocation framework. And therefore, the returns to shareholders, the free cash flow breakeven target will set between 45 and 50 through 2030 for the next 5 years or so. None of that changes. That is everything will work within that operating model. And therefore, we will continue to provide sustainable strong shareholder returns.

The next question comes from Rob Koh from Morgan Stanley.

Maybe can I ask a question about the Bedout Basin, which you haven't spoken a lot about here, and I guess it's still early days. I guess part one of the question is with Australia potentially looking at extra refining capacity, could that form part of your concept select? And then secondly, and probably more seriously, have you evolved your thinking on the floater on the FPSO for this? I understand the BW Offshore option has lapsed. If there's any further color you could provide, please?

Well, thank you, Rob. So let me just say that, first of all, we think the Bedout Basin has got incredible prospectivity and the Dorado project, which is part of that is a very exciting opportunity. We've always thought that. We've never changed our thinking on that. We have a capital allocation framework, which dictates how much we can spend in terms of CapEx and things going forward in order to be able to provide a measured growth trajectory in the future while still being able to provide strong shareholder returns through the cycle. And we'll continue to work with that discipline going forward.

So the Bedout Basin will compete with Alaska will compete with Beetaloo compete with any other projects in the portfolio that fit within that framework and the best projects will win. In terms of our update on it, though, what I can tell you is that we still plan to drill 3 appraisal wells in the Bedout Basin in 2027, and we've awarded a drilling rig contract to support those activities. And so that's a firm commitment to the work we're doing there. And we see it as a very attractive opportunity, not only because Australia might build more refining capacity, but also just to increase the energy security, the potential benefits that gives to Australia in the longer term. I think this year has highlighted the need for more oil in this part of the world as part of an energy security strategy for Australia.

And so we see that got added value from that perspective. In terms of -- I think what you're referring to in the FPSO is the old Woodside FPSO that I believe BWO got and any options that people have on that, I'm not aware of. If we were going forward on that project, we'd only make financial commitments for the project at the point we're ready to take FID.

Okay. Yes, that's the I was referring to. So that makes sense what you said -- maybe can I ask a question about the carbon disclosures. Is it right for me to take your CCS tolling income and your other carbon income and divide that by injection volumes to get a kind of proxy average realized price? Or is it -- it's probably more complicated than that, I'm sure.

Rob, yes, there is a little bit more complication to that. So there is a line item for revenue that is received from the -- ACCUs generated that move to CCS. There is also obviously some carbon costs that come through that as well. And there's also a lag in terms of when -- ACCUs are actually issued by the regulator, which comes into play as well. So it is slightly more complicated than what you start to divide it on a headline level.

Perhaps suggest you work with our IR group, it can help you tighten up how to model that.

The next question comes from Gordon Ramsay from RBC Capital Markets.

Congratulations on starting up Pikka and Barossa key growth projects for the company. My question relates to your legacy assets, in particular, the Cooper Basin and GLNG. You haven't commented on the production outlook for those assets. And I understand the importance of the Moomba Central Optimization project for the Cooper Basin in terms of cost savings. But what does that mean for the production outlook from that asset? And then also with GLNG, with de-contracting gas supply volumes, what does it mean for the near-term production outlook there? -- please?

All right. Well, let me try and break that down, Gordon. And of course, if I miss anything, please just pick me up on that. But look, we give our guidance at a portfolio level because from year-to-year, things move around on assets or shutdowns or things like that. So we typically give our guidance at a portfolio level. What I can tell you for the Cooper is we'd expect the Cooper Basin to be relatively steady for the next few years around the levels it's been. Now of course, there have been some temporary impacts in the last couple of years because of floods. And I had to smile when Brett said record flooding this year because I think he told me that 3 years in a row as he talks about the Cooper Basin.

But it has been -- the records are getting beating year-on-year. But the focus in the Cooper Basin as much as some gas production will drop up in other reasons that get less of a focus going forward, -- and the reality is for those regions, we'd be very open to anyone else owning them going forward if that's what they wanted to do. We are focusing our investment in the central areas and probably the northern areas, but predominantly the central areas of the Cooper Basin, where over 90% of our future resource requiring development sits. And we believe we can make that a much lower cost, higher-margin asset by doing that and getting the infrastructure investment right there to electrify and simplify the operations in the upstream fields around the central area.

So that's really what we're doing there. We expect production in that area to grow once we'll finish that project to balance some of the losses elsewhere to come off the other areas of the Cooper Basin. But ultimately, we're not looking to shrink our production there. We're just looking to maintain it but get higher-margin barrels. Now I can't remember the last part GLNG. So GLNG, we've given guidance in terms of some contracts rolling off. The AGL contract will roll off in 2027, and that gas will be available to the domestic market, I guess. And so our production will come down by those volumes. However, we're continuing to invest and grow our indigenous production there. But the longer term, we'll reset guidance on that once we get more clarity, probably going into '27.

The next question comes from Nik Burns from Jarden Australia.

I just have some clarity on exactly where Barossa LNG is at. I think you mentioned in the presentation that you're currently producing around 550 million standard cubic feet of gas a day and targeting 600 million by the end of the quarter. Just so we're all clear, what rate equates to Darwin LNG hitting its 3.7 million ton per annum nameplate capacity? And when do you expect to achieve that target rate?

Thanks, Nik. Well, look, actually, that is a really good question and a complicated one because Darwin's capacity changes depending on what time of year it is because of the seasonal weather impacts. So in the middle of winter, when it's cooler, Darwin can produce LNG at a higher rate, probably around the 600 million standard cubic feet per day, although we hope to push it a little bit higher than that because Barossa can go higher than that. And in the height of summer, it's probably more like 560-ish is what the historical performance levels have been at. And so again, we want to see if we can push that even higher. So we're effectively at winter capacity levels right now -- sorry, summer capacity levels right now, although we're not in the summer, right?

And that's why we've got a couple of systems just offline and getting some repairs and maintenance work done to them. They'll be back online next month sometime. And that should -- I think I've said in my speech earlier on, by the end of September, we're hoping to push that then up to the sort of 600, 600-plus rates. But Barossa has currently got more capacity available than -- or when it's all online, we'll have more capacity available to it than Darwin can take historically.

Darwin used to get about 550 a day from Bayu-Undan coming into the facility. But through de-bottlenecking and running it with high reliability levels, we hope to try and get that up a little bit. Hopefully, that helps you paint the picture, but it's seasonal, and it just changes at different times of the year.

No, that's clear. So basically, by the end of this quarter, you hope to have enough gas available consistently to meet whatever nameplate.

Whatever. Yes, whatever the seasonal nameplate capacity at Darwin is, that's correct.

Got it. And in the interim, has there been any further need to purchase additional third-party cargoes just to meet any contractual obligations?

No, there has not. I mean, when everything is running smoothly, we're about 8 days between cargoes just now. We're just getting into that cadence now. I think if I average it from the 1st of July, it's probably 9.3 days or something like that because we've had a couple of times where we've taken rates down a bit for maintenance or checking the stuff as you tend to do from time to time. But no purchases in the second half.

The next question comes from Baden Moore from CLSA.

Thanks for the Slide 9 with the value drivers on Papua. I was just wondering, at this point, just given the location advantage for the plant, is there any indications you can see that you might also be able to achieve some pricing premiums for the gas out of the new project, just given its differentiated location, it's non-Middle East and anything you can share on that would be helpful. And then just a second question just for the balance sheet. I noticed there's a slide just highlighting that the target debt number has a time frame as well to 2030. Maybe I'm reading too much into that. Is it more just a guide on absolute gearing target? Or is timing relevant there as well?

Well, let me start with the pricing. First of all, our PNG and Barossa LNG tends to get a premium to market because of the high heating value benefits that the gas from those 2 projects provides. And that's particularly attractive to our Northern Asian and Japan customers in particular. So we would expect to see that continue as we go forward with Papua when it comes online. And in terms of the expectation of Sean and the market team, we've made that very clear to them, right? So we've got a great marketing team. They've got a great track record. And you can see in the pricing charts in the pack that we've achieved that consistently over a number of time on that same chart, you can see that pricing is driving through against our peers.

And that's a fortunate position we're in. Mother nature has been kind to us there that we've got high heating value. And that's not taking anyway from Sean and the group. They do a great job as well. The 2 things combined have led to a nice premium advantage there. However, when you talk about the net debt reduction target, what we've set is a time line on that target that we thought was appropriate, achievable at a reasonable oil price forecast and we gave ourselves to 2030 to achieve that. And so it's really just -- it's not tied to any project outcomes or any business outcomes. It's really just a time line by which we want to get the net debt down to the -- that would take us to the lower end of the gearing range target, 15%, and that would be inclusive of leases. So when you put those 2 things together, exclusive of leases, that's probably near the 10% mark.

So that will be a very low geared balance sheet at that point in time. And we believe that, that is where we want to sit as an operating company. It gives us the flexibility to have a balance sheet that we can use if we have to grow the company beyond that point in time, while still being able to develop -- deliver, sorry, very, very strong cash flows. Our interest payments will be reduced from what they are today by around about $150 million a year. So that's freeing up even more free cash flow. That just helps us focus on giving strong returns, investing for growth, but at a low geared level.

The next question comes from Adam Martin from E&P.

I was just thinking about the sort of free cash flow breakeven in '27. You've obviously got Alaska and Barossa CapEx, some of the bigger stuff rolling off and you've got some of this exploration and appraisal spend that you've called out in the Bedout and the Beetaloo. Do you think that the quantum of that is going to be less than some of those bigger growth projects? I'm sort of wondering where that free cash flow breakeven even into '27 might actually be lower, but it depends.

Yes. Thanks, Adam. It may be. I think what I would say is that we see a little bit of CapEx being spent on appraisal, both in the Bedout and the Beetaloo over the next couple of years, right? So we're going to spend a little bit, but nowhere near the levels we spent in recent years on growth projects. And when you consider that the bulk of the CapEx on Papua will be covered by the project financing vehicle for the first few years of Papua, then you're right, there's no other major FIDs that we can see in the immediate future that's going to suck up a lot of CapEx. So yes, it could well be lower than that range. We've not given any guidance on that. I'm not going to kind of give any pseudo guidance here today.

But you're right, it could be. We'll give that guidance towards the end of the year. But I don't foresee any major FIDs anywhere being possible for Santos in the next 2 to 3 years, except for Papua, which we've given guidance on later this year. As I say, that will be -- that will be supported by the financing vehicle, which has a lot of -- a lot of the heavy lifting on CapEx for the first few years.

Okay. Good to hear. And then the second question, just on the sort of whole reservation policy. If you do get the right settings from the government in the next 12 months or so, I mean is there anything in your portfolio you'd look to accelerate? Or maybe just talk through that if you actually got the right settings, what you would do there?

Well, look, I mean, I think we've got to wait and see what the draft legislation looks like when it comes out shortly for consultation. We believe that the government is listening and trying to get the settings right. But undoubtedly, it won't be perfect because it's very complicated. We'll provide our feedback on that once it comes out. We are keen at Santos, we're keen to work with all the stakeholders to get something that works for the industry, for the government, for the manufacturers and users of gas here in Australia. And ultimately, it has to be focused, in my view, on freeing up more supply. Until then, I don't want to sort of comment and speculate on what projects might go forward or not go forward because it's too wide ranging.

And obviously, the interest on people buying into or supporting some of those projects will also depend on what those settings look like. So it's too speculative to do anything else. We'll just keep working with all the stakeholders until we get something that gives us that certainty and then we can all buckle down and get on with life. I mean what I will say is that I'll reiterate Santos is the second largest supplier of domestic gas in Australia. We've got a strong track record. I mean one of the things that you may not be aware of, Adam, is that you and others on the call is that since GLNG started up in late 2015 to the end of 2025, Santos has contributed gas to the East Coast market alone, ignoring the very large supply in West Coast, we've supplied gas to the East Coast market alone to the equivalent of 26% of our exports through GLNG over the same period.

That's over the period to the end of 2025. So we're not overly panicky about anything that's being proposed here. We've been a strong contributor forever. We'll continue to be a strong contributor to the market. We think it's a very important market. And we'll wait and see what we get next month.

The next question comes from Tom Wallington from Citigroup.

Good to see Pikka progressing nicely and the seawater treatment plant reaching the final stages of commissioning there. Just thought it would be a good opportunity to get an update as to what you would need to see technically before progressing any brownfield expansion. I think, Kevin, in the past, you've talked about wanting to see around 12 months of production data to get more confidence there. But I mean, I just wanted to kind of gauge as to how you're seeing this opportunity progress conscious that it has to compete with capital with other parts of the business? And I guess, finally, just in terms of the success you've had there in developing and commissioning key pieces of infrastructure there. Just trying to get a sense as to what you're looking at for capital intensity savings for future phases of development.

Thank you, Tom. Look, I think, first of all, I want to start by saying it's no mean feat for a company like Santos to build its first project in the North Slope of Alaska and bring it online. I mean there would have been a lot of people out there that would have said that, that was a recipe for disaster going to a very harsh remote environment, very different operating conditions from anything we've ever faced before. And it's been bumpy. We're not going to dispute that. There's been a few bumps along the road. And there'll be a few lessons learned from that. But I'm very confident that given the team that we have on the ground, given the lessons that we have learned that Pikka will be a fantastic project for Santos.

We believe that Pikka has the potential to develop up to 1 billion barrels of oil over time, and we will be very focused on trying to do that and tie back into the infrastructure. Before we go and think about a Phase 2 or an expansion project or anything like that, we have to get Pikka Phase 1 up and running. We have to see that everything delivers what it was promised to deliver and gather all the lessons from Phase 1 so that whether it be contracting strategies, project management philosophies, whatever, when we go into the next project in Alaska that we've captured those lessons, learned them and that we can improve our performance now that we're an established operator on the North Slope of Alaska. You're right that those projects will also have to compete in the [saratum of projects] that we have here at Santos. And I'm very confident it will be very competitive because I think it's a great world-class Tier 1 asset.

But we need to see, as I've said before, a period of time with continuous production with the water injection system up and running and seeing that it's all doing what it's planned to do to give us the confidence to go again. And so it's just being disciplined, being patient. A lot of resource there, and we're not rushing. And like I say, I can't see any major FIDs in the next couple of years here at Santos across the portfolio because we'll be in watching and learning mode in Alaska. Now we might have to do some long lead activities to prepare us for that, but there'll be no major FID decisions. Likewise, in Bedout, likewise in Beetaloo and outside of Papua, I just don't see us FIDing anything for the next 2 years or so.

The next question comes from Cameron Needham from Bank of America.

Just from 2027, I appreciate you've given us the free cash flow sensitivity and you've outlined your capital allocation framework. But just in a stronger commodity price environment, how do you guys as a management team think about the optimal use of windfall cash flows? And is the countercyclical thing to do actually just retain more of that windfall and get to the bottom end of the gearing range faster than you previously anticipated?

Thank you, Cameron. Look, it's actually really quite simple. It's the same framework applies no matter what the level of cash flow generation is. We're just focused on strong returns. So a minimum of 60% of that free cash flow would be returned to shareholders. In the scenario you're trying to create there, that would give us that 40% would be a higher absolute number. So that would help us accelerate reducing debt anyway over our plan. And of course, within all of that, sticking within that framework in terms of how we allocate capital for future growth. I think at the Investor Day, we gave guidance of wanting growth production somewhere around the 4% CAGR level between now and 2035.

And we're not looking to go any steeper or any faster than that. We think that's a very measured and disciplined way to grow the company. And we can do that within our disciplined capital allocation framework. providing good returns to shareholders on the way through after we've been able to invest at a modest level to support that growth rate and reduce our debt to strengthen the balance sheet at the same time, positioning us to be opportunistic in the future should good opportunities arise to use to leverage off the balance sheet. So it's a very balanced approach to it and stronger commodity prices just means stronger returns, quicker debt reduction, but not looking to grow the company at any higher growth rate.

Great. And then a quick second one, if I may. Just if we don't get a Papua LNG FID or it's not sanctioned, how do we think about backfill optionality in terms of PNG, LNG now and the need to look at other options and timing around that?

Well, look, I mean, we've got a lot of prospectivity and a lot of discovered resource in PNG. And so we've got projects like Muruk that we could throw in there that would be a filler. And of course, the big one is P'nyang. The big one is P'nyang. If I look at it purely as a barrel of oil equivalent or barrels Santos also has in our PDL2 production license area, an oil project called Mosa that we're going to drill a well probably at the beginning of 2028 to test. And that is one we're very excited about where I think we estimate the structure could have up to 85 million barrels of oil in place, and that is something we'd be very excited about.

So we also have the potential to fast track oil production there as well. So look, we've got options. We -- but I would have to say the organization and our joint venture partners and the government and the landholders of PNG are all working and very focused on getting to FID this year for Papua. -- everybody is very motivated to achieve that. And I have no reason to doubt that we're not going to do that.

That does conclude the question-and-answer session. I'll hand the conference back to Kevin for closing remarks.

Okay. Well, thank you very much for joining us on our half year results call this morning. If you didn't get the opportunity to ask a question, please feel free to reach out to us directly. And I look forward to meeting many of you over the next week or so as we do the rounds. So thank you very much.

Good morning, and welcome to Santos' 2026 Investor Day. Our theme for today is focusing on Tier 1 basins, growing free cash flow and delivering shareholder returns.

Today, you're going to hear from a lot of the members of the management team. It's a busy day, a lot to get through, and I'll get straight into in a second, where we're going to cover the financials, the market outlook, look at our marketing trading activities and particularly focused there on the premiums that we get from many of our products. We want to stop and take stock of our reserves and resources position and share with you the very strong fundamentals that we have at Santos for going forward. And then the big focus of the day really, where we'll get Brett and Bruce to take you through the oil and LNG growth hubs and the growth focus for our organization going forward. Then Alan will share with you how we're creating value out of our Midstream and Energy Solutions Group. And of course, Steve [indiscernible] touching on the technologies we're playing across our business and how we're driving technologies through our business to reduce costs to create value and improve our business performance. And then I'll wrap up at the end, and then we'll be some time for Q&A at the end.

So let me get straight into it. I won't ask you to read every line of this, but be aware of disclaimer, and I'll move on to start with this. If we think about the macro, there's no doubt at the start of this year, none of us saw coming, what has occurred in the first quarter in the Strait of Hormuz with the conflict in the Middle East. And the impact of that is having on markets. And I think our view on that is we don't run our business in anticipation of major global conflict driving commodity prices up. But we run our business on a cost basis understanding that when interruptions to the market occur that our business will benefit from being a reliable supplier and will benefit from those higher commodity prices.

You can see, you've all seen it and you're all very aware of the impact on oil and LNG markets. And our view when we look at this is that this is not something that will go back to normal anytime soon. We believe this is quite structural, the impact on the markets and particularly the focus on energy security and specifically in our region, where many countries it's fair to say maybe drop the ball -- a bit overly secure and forgot about the need to build strong strategic reserves, and a few countries have been caught short by that.

Our suspicion is that when things do eventually normalize and the conflict is behind us, the time to take to get back to steady state will be much longer than most people are anticipating. Number one, this is the single biggest oil shock the world has ever seen. The amount of wells that are closed and shut in, in the Middle East, far exceeds the interruptions from any interruption the market has seen in the past. And the last time -- anything close to this. It took 2 years for those Eastern companies to get the production back to the levels they were prior to shutting their wells in. Many of these wells will require workovers. They'll require redrills to get the production back, and that will take time.

We know this very significant infrastructure damage, particularly in LNG were 2 trains in Qatar have been impacted, and that's taken 12.8 million tons of capacity out of the market. Our view on that is that, that structural slight oversupply people were predicting in the second half of this decade through to 2030 probably will not occur. We think there's going to be a shortage or at least a tighter market as a consequence of that. And that's probably 2 to 5 years to get those trains back online and functioning.

And there's no doubt there's now a risk premium -- or risk discount, I should say, for supply out of the Middle East going forward. That maybe was not top of mind for many of the buying nations and buying companies prior to this conflict. It's a reminder, of the risks of traveling through the Strait of Hormuz. And I would also add to that, there's a very strong likelihood that you'll be paying another $1 per barrel or $1 per barrel equivalent as a toll to go through the Strait of Hormuz once this conflict is over. So we see significant impact on the oil markets, significant impact on the LNG markets, but not not impact it will rectify themselves very quickly once the conflicts over. So we think you're going to see stronger prices for longer than most people are or suspecting.

Going back to Santos' strategy, nothing's changed. The strategy is enduring. We believe it's the right strategy for this company. We believe it has delivered a much stronger company year-on-year over the last 10, 11 years, and we'll touch on that in a second. But our focus is very much on 3 horizons, that backfill is sustained and decarbonizing our base business with our energy solutions and decarbonization, not just part of our base businesses, the way that Santos operates. You have seen how the CCS project has been integrated into Moomba operations, and that is driving our emissions down, driving emissions intensity down, but very importantly, doing it economically. We have now stored around 2 million tons or over 2 million tons of CO2 since the project started up. The reservoirs are overperforming versus our predrill expectations. So really good injectivity, no signs of any problems at the reservoir level, and that's very encouraging for the future.

And I can't remember exactly how many ACUs we've got, I think it's about 1.1 million tons we've received, which means we've got about 900,000 that are still in the pipeline on their way to be received. So it's a very successful project on all fronts, but that is now base business, and Alan will talk about that later on this morning.

Our build and grow is very important that you want the share price to go up, you've got to grow your business. You can't stand still. And we're going to do that in a way that can be balanced with strong returns to shareholders all the way through at the same time. And we believe that, that build and grow focus, we've built a portfolio through strategic acquisitions over the years, and the merger with Oil Search and tactical sell downs along the way as well, just strengthening the portfolio, reducing that unit production cost and building a much more resilient lower-cost portfolio has now started paying dividends, where it's given Santos now the scale, the scale of a business that can do both that can grow, and it can provide strong returns continually through the cycle. You'll see more about that and the focus on that this morning.

When it comes to low carbon fuels, we're not giving up on that, but it's fair to say the world has slowed down its anticipation and its appetite for spending money on things like hydrogen and things like that. But we're still keeping a keen eye on opportunities there. We're still looking at things like geothermal to help us reduce our emissions out in the Cooper Basin. Again, Alan will touch on that later on this morning. But I think it's fair to say when it comes to clean fuels probably moving to the right a little bit. It's a bit more long dated. And we're not giving up on it. We're just acknowledging it's going to take longer because of the economic challenges to make those things work.

In terms of operations update, I'm not going to spend a lot of time on this slide because Brett and Bruce will cover a lot of the operations or Brett predominantly later on this morning. But what I will say is that I'm pleased to say that Barossa's online is producing around 70% to 75% of maximum rates with a cargo leave, I think it was Sunday morning, and operations are going well there. The problems that we had faced are now behind us, and Brett will take you through some of that later on this morning. But that's in a great position, the project. The wells are performing and the facility is performing reliably, been producing now for a couple of weeks as I say, 70% to 75% of planned rates.

And in terms of Pikka, I'll let Bruce get you excited about Pika and I'll ask more generally later on this morning. But we are -- we got first oil into the system last week, I think it was. And we're producing intermittently at this point in time where we finalized the late commissioning activities. But days, Bruce, from continuous production. We're not far away, but very excited and waiting for that to happen. Like I said, I wasn't going to steal his thunder, but I thought I that -- sorry, Bruce, but I'll let you talk more about that. But that's really the big news. Base operations are across the rest of the company are going really well. And I'll let Brett particularly take you through the operations in Australia and PG later on this morning. But you can read this slide, the information is there for you.

Our operating model. It's never changed. And I know sometimes when I meet you in one-on-ones, particularly, and I talk about the low-cost disciplined operating model at Santos, I see you rolling your eyes. [indiscernible] here he goes again talking about low-cost disciplined operating model. But it's a cultural thing we've implemented at Santos over a long period of time. Why did we do that? Well, we did that because back in 2016 with a company that wasn't free cash flow positive even at an operating level, we needed $50, $55 oil back then from our operations to breakeven, right? And we set initially a $40 operating cash flow breakeven ceiling back in 2016. We refined that to $35, held that ever since.

And I remember the outcries in 2016 at our AGM, the amount of questions about you're going to start the business of capital by doing that because there was this notion we have to spend all this capital every year, particularly in the Cooper Basin to maintain. I think they called it in those days, stay on track, CapEx or something like that, right? And we said, no, no, we've got to be able to do this at a lower level or the assets not viable, and we corrected $35. And the 10 years since we've never exceeded that for our operations.

So in 10 years, we've not only set a ceiling in 2016 at $35. We have not once succeeded at, and we haven't seen any material reduction in production in that time. And more importantly, we have outperformed every safety, process safety and integrity, metric environmental metric that we measure at the same time as well as bringing down our emissions quite considerably on that asset.

Now that's applied to the whole business. And you can look at the comparisons here between 2016 and 2026. And the bottom line is that, that model has driven a base business that allows us to continually build the business stronger year-on-year. And we are operating the same way today as we did that same discipline, the same model across every asset in the portfolio. And it's designed to combat inflation. Now we won't always combat inflation. There are certain aspects of inflation, you cannot. But we have done that over the years. And you see that in our unit production costs, which have come down considerably, over the years, which if you think about it from a value perspective, if you just take production costs in 2016 and imply inflation from 2016, that's billions of dollars of value we create by combating inflation.

Now we weren't always the same, but that's about applying technology, different ways of working, real discipline across our organization. And you can see we've done that whilst we've materially increased our production. And I've got to give credit to all of the management team for doing that, whether that be through the M&A transactions, delivering our projects, squeezing extra barrels out of our assets, very importantly, driving reliability up across our assets. And PNG, we took over in -- at the end of '21, early '22, the PNG operations. And where these assets have historically been around 78% reliability, we got to over 95%. That's 1.5 million barrels a year of extra production just because we have the facilities working more. So it's not just to be reliable, it's to create value for shareholders.

You look at those unit production costs, they're down from over $10, almost $11 in 2016 down to just around the $7 mark today. And then what that's allowed us to, in 2016, you may recall we had to suspend the dividend for 2 years to repair the balance sheet. Now we've got a company you can rely on to provide strong dividends year-on-year reliably into future whilst investing and growing our business, something we couldn't have even contemplated back at that point in time because of the asset base that we had. And we've done all of that while improving our safety performance and reducing our energy -- or sorry, our emissions intensity.

And very importantly, back then, even though we didn't have a lot of growth with 1 big growth project at the time coming in, which was GLNG and it was at the end of that, we were negative cash flow around USD 700 million, negative. And today, last year -- end of last year, $1.8 billion. That is a phenomenal transformation, and that is because we have been controlling those costs. And now we're at that inflection point today is about what's next. Today is about what's next. We're at that inflection point we've talked about now for a few years. It's now, it's here, and the cash flows will start to really be generated from the additions of Barossa and Pikka into the portfolio.

When we look at that portfolio now, it's a very different company. Gone are all those little assets we had in Victoria. The smattering or scattering, I should say, of assets we had around Asia, in Indonesia and Bangladesh. I mean, really exotic places to go and run operations. But these are small operations, taking a lot of management time contributing very little to the portfolio. They're all gone, and we've replaced them instead with Tier 1 assets, Tier 1 opportunities in Alaska, the Barossa project offshore. PNG, we're now a material stake. I think back then were 13.5% in PNG, we were 11.5% in [indiscernible] Darwin back at that time. So we've changed -- materially changed the make of our portfolio for much stronger, lower cost and high potential assets from a growth perspective.

And very importantly, I move to this slide, 4.7 billion barrels of resource across the portfolio that's made up with around 1.5 million barrels of 2P and 2C of around 3.2 billion. So whilst we have produced around 750 million barrels over that decade. At the same time, we've grown our 2P, you can see here, to 926 million BOEs. And our 2C we've grown considerably to around 3.2 billion. That's the 2P developed and undeveloped number, but 3.2 billion of 2C across the portfolio. That's incredible. And around 83% of those are in what we would consider our high potential growth assets, the regions that we're going to focus on going forward to develop Tier 1 basins, large-scale basins that give us much lower cost growth development costs and lower unit production costs in the longer term. So our resource base is really strong. Our 1P, our 1P reserves life, I think, is around 10 years -- 10 years at this point in time. So a really strong indicator. You'll see Mark Morgan will take you through that later this morning to show you how we benchmark against competition. It's very favorably.

So when it comes to growth, our growth going forward is going to be focused on 3 regions and with a myopic focus on prioritizing our CapEx into the Tier 1 basins in Alaska and in PNG and fully appraising the [indiscernible] here in Australia to identify whether they have the scale and the potential to be Tier 1 basins here as well, supporting our LNG business here in Australia, our LNG business in Papua New Guinea and, of course, our oil business in Alaska. And that will be the prioritization of capital going forward, give us a much higher rate of return than traditionally we have from some other sources that we've been investing in, in years gone by.

And what does that mean for the other parts of the business, when it comes to Midstream and Energy Solutions, that's really about being a low-cost business, driving improved efficiency and taking those processing costs down across that portfolio of assets to help create more value in the upstream business whilst reducing emissions. And also, very importantly, identifying opportunities to create new value streams, new revenue streams from those infrastructure positions we have across our business. And when it comes to the Australian domestic oil and gas portfolio, and I'll have a little bit to say in a minute, on the strategic review that was conducted across that portfolio, really it's about repositioning that business now as a lower capital intensity, higher margin business focused on meeting our domestic gas and our decommissioning commitments going forward and doing that in the most capital-efficient way, paid for that, so that, that business never becomes a drag on the growth hubs that we have and the big Tier 1 basins that we're developing around the growth hubs.

And so it's making that a very efficient business. And you could add -- given the government's announcement. I don't know if anybody in the room is aware, but the government announced something yesterday on the domestic gas market reservation policy, which I'm sure we'll talk about later on this morning. I look forward to that. But when it comes to that, you could argue this is part of the social license to allow us to maximize our exports through those facilities in the years ahead.

Now as talked a lot about the operating model driving cost out and keeping a lid on the costs in our business to help increase margins. I think it's very important that we also focus on the revenue side of the business to increase the margins by getting premiums and the best prices we can products. And Sean will share with you the excellent work our [indiscernible] team have been doing over the years. And those of you that look at quarterly reports and annual reports, you will know that we enjoy very strong premiums compared to competition for many of our products. Now some of that is a [indiscernible] nature and just having the right products in the right places at the right time. But Sean assures me most of it is down to having his market team and their expertise, and he'll share his views on that with me, I'm sure later on this morning.

So what does that mean? Well, I've talked about a disciplined operating model. We're going to maintain that $35 breakeven for the operations of our business. But very importantly, we introduced you earlier this year, the all-in free cash flow breakeven target range now for the company of $45 to $50. And what does that mean? That means after everything, sustaining CapEx, OpEx, growth CapEx, decommissioning CapEx, all of it, all of it, at least for the next 5 years, we are targeting to deliver whatever we say we're going to deliver for a target range all-in breakeven $45 to $50.

Now why is that important? Because we're trying to make it really easy for people to calculate what returns might look like, right? So you use that, and Lachie will take you through the math to this later on. And then you will know that for every $10 that the oil price is above that breakeven, Santos's portfolio will generate $550 million to $600 million, another range, just to confuse it, $550 million to $600 million in free cash flow. And very importantly, our capital allocation framework that works alongside our operating model, which is a Board-approved capital allocation framework, guarantees a minimum of 60% of that free cash flow, a minimum of 60% of that free cash flow returned to shareholders each year.

Another 40% we'll retain a little flexibility for debt reduction, for balance sheet management, all of that sort of stuff. But of course, when everything is healthy and everything in the right place, that's available to be returned to shareholders as well, if necessary. And of course, we do that with a gearing range of 15% to 25%. Nothing's changed on that front.

Now to the Australian domestic oil and gas portfolio strategic review. There's really 4 sets of assets we've been looking at. And I want to take you quickly through what the outcome has been in each of those cases. And I'll start with the Cooper Basin, very important, Cooper Basin I think we've already flagged this to most of you in the market anyway back in February. But our priority here really is to focus investment going forward on the central areas of the Cooper Basin, something like 85% or 80% of the resource to be developed in the Cooper -- is in this part of the Cooper Basin. And that's the NCO project we FID-ed earlier this year. And the contract we're staying with the South Australian government, which Brett will touch on later on is basically as a consequence of that MCO project. And that will supply secure gas in South Australia for 10 years, 20 [indiscernible] gas was a very significant number. You can do the math. It's a very significant number for Santos, 20 [indiscernible] gas per year for 10 years to the [indiscernible] government.

And importantly, through this work, with this reprioritization of capital, that will result in a reduction in capital spend in the Cooper Basin between now and 2030 of around USD 300 million during that period. And then $150 million less CapEx spend in the Cooper Basin year-on-year thereafter. And that's a consequence of really just focusing our capital around that central area of the Cooper going forward. And the way they think about the rest of it is basically we'll run that to meet our current contractual commitments and then run it for value thereafter.

When it comes to the collection of assets that we have, some of which have been stranded for some time in [indiscernible] Eastern Queensland, Narrabri, the [indiscernible] Basin, a spattering of assets all over the place in very quick order, Eastern Queensland, Crown [indiscernible] de-prioritized, not going to spend any effort or money on those assets. [indiscernible] is being appraised by others. I don't know if you're all aware, we've actually got a fairly significant position in [indiscernible] we've not made any comments on the quality of the [indiscernible] we don't let people run that commentary for the time being, but we're pleased that we've got a few farm in arrangements where other people are drilling and testing that for us. So we'll let that play out, and we'll see where we get to as a result of that.

And with [indiscernible] just focusing on approvals and getting -- continuing with that. But again, not spending any capital or overly exerting any effort on that. And some of these assets will be reevaluated once we've appraised the [indiscernible]. And for obvious reasons, if the [indiscernible] works, then it changes what we might want to do with some of those assets. There'll be less of a requirement in some cases to do anything with any of them, and -- because the [indiscernible] has a scale. And in fact, I should have said that in the previous side, when we talk about being excited about the Beetaloo Basin, our acreage alone in the Beetaloo Basin has enough gas in it. we believe there's enough gas in it to supply 10 million tons of LNG and supply the East Coast market for more than 50 years. It's a phenomenal resource and Brett will take you through that later on this morning. And it's all about the cost we can get it to the wellhead.

Carnarvon Basin, possibly a more strategic asset in light of what we heard yesterday. But really, the focus here is just pursuing low-cost tiebacks, the Halyard 2 well, Halyard 2 well, which was supposed to be coming off production shortly. It's performing like it was day 1 see no decline. It's 85 million standard cubic feet per day of gas, no decline and indicating significantly more reserves than we ever thought it was going to be. That's a really low cost. I think with production costs in WA this year around the $5 mark, $5 per BOE because -- and it shows the value of bringing regular low-cost tiebacks, another 1 we're going to drill there, I think, next year or the year after call [indiscernible], a $42 million CapEx project, almost instant payback. So we'll pursue those low-cost near-field tieback opportunities.

And again, that's part of that business that's repurposed now to be a higher capital efficiency, low cost, higher-margin business, essentially, meaning our domestic gas obligations, whatever they end up being and funding our decommissioning activities so that we're not dragging cash away from our 3 core growth hubs.

And when it comes to [indiscernible] in the below sub basin, I think the key messages here is through this review, what we've identified is the really strong economics of [indiscernible]. The [indiscernible] got strong economics. Theras also a project that has -- potentially has significant energy security advantages for Australia and for this region. But more importantly for you, it's a very high IRR project. So it competes very successfully against our growth hubs. And so effectively, what we've done is we've lifted the Betaloo basin, and we put that into the 3 growth hubs. That's in the star growth hub, and we'll evaluate that basin and see if that's got a scale to warrant being part of that growth story going forward. We know what [indiscernible] looks like, but Brett will show you the opportunity set across that basin. It's really about thinking about how has that basin got the scale to compete with those other basins we want to invest in over the longer term or not.

When it comes to those 3 regions, those 3 growth hubs that we're focused on going forward. in Australia. This is just a good indication of the sort of things we're going to be doing over the next few years on that development pipeline. You can see in Australia, the Betaloo appraisal is a priority. We're going to drill 3 wells, hopefully, over the course of the next year and test them for 9 to 12 months to establish our type curves and determine the economics and the potential around that basin and whether it can work going east and going north, very, very confident on the economics going north. But it's all about cost of supply, whether it can stack up to go East because, obviously, it's a longer pipeline, and the pipeline costs would be higher.

And as I say, enough gas there to supply 10 million tons and our acreage alone, not the basin, our acreage alone, 10 million tons and the East Coast market fully supplied for more than 50 years. It's a phenomenal potential resource. We'll do that capping of course, in Dorado and I should say, the Betaloo Basin, it's more the value base than [indiscernible] feed ready. It's ready to go back into a shorter if we decide to do that. We'll appraise the [indiscernible] Basin in 2027 with 3 wells. We're planning to drill 3 wells offshore in the [indiscernible] Basin. And all those costs for all that activity and all the activity on this page are in that $45 to $50 free cash flow breakeven number that I talked about earlier on. In PNG, we've already announced the FID of the APF time -- project, which will provide additional gas to help combat any decline in production towards the end of this decade before the Papua project comes on. [indiscernible] CPF expansion is another 1 of those projects that Brett will talk about this morning. have I did that yet, but you can expect that shortly.

And with Papua LNG, I don't know if you saw Prime Minister [indiscernible] statement yesterday confirming that Total had promised it or guaranteed them or whatever the words was in that announcement, very positive statement saying that they're going FID the project this year. And that's our understanding. We are aiming to do that in the second half of this year with the development forum that I know many of you are tracking scheduled, I think, for July, August to support that timing.

And then, of course, 1 that you will not have heard of is [indiscernible] as an oil project in PG -- and while Brett will show you that we continue to do those little infill programs, which give us those little infill oil wells, high IRR, but not really big material as just keeping the oil business going. This is different. This is something that's 3 kilometers away from our existing infrastructure within our production development license, so no new licenses required -- it's a very significant oil play that's appeared after our most recent mapping exercises right next to those really high term, high-volume oil fields we had many, many years ago. And if this comes in, this would be the largest oil play to be discovered in PNG and something like whereas Brett years or so. So a really exciting project right next to our existing infrastructure at a time when the world is starting to appreciate oil again.

So it's a really exciting play that we didn't have on our books 12 months ago. This is really exciting, and it's coming from the great work the team in PNG have been doing. And in Alaska, Peaks about to come online and start wrapping up to its 80,000 barrels a day.

Previously, we talked about Pikka. I want you to rethink about that now is really just Pikka expansion. And I'll be expanding that. The next phase of Pikka expanding to 120,000 barrels per day. And then we got Quaker. And we just recently announced a very exciting appraisal well in [indiscernible] and Bruce will take you through that. And what's exciting about that our peak oil is currently getting a very strong premium to Brent. And I've not my specs on, but this is the peak on this is a peak of one. So if this goes missing today, it's $110 a barrel, right? And we've worked out the volume in here, we can tell exactly what it costs, right? So we'll be hunting you down for the money if this goes missing.

But when I pass this around the room because what's exciting about [indiscernible] is when you turn it upside down, you see dark the borrow goes, and that's an indication of the viscosity of the oil, right? And we know the flow rates we get from these wells. For similar reservoir conditions, -- this is lighter. I think it's 36-degree API oil versus 30 to 32 for Pikka. And you'll see this clears a lot faster. The glass clears a lot faster.

What that tells us is for similar reservoir positions, we can expect much higher flow rates from Quokka going forward than you get from Pico. So I'll pass this around. And I hope to see the 2 of them again at the end of the day. It's a very valuable commodity, right? We don't want those good missing. But please have a look at them, we'll give you a feel for the grade. This is premium oil, commanding very significant premiums to Brent today in Asian markets, and Sean will take you through that later this morning.

So that was a very successful market. We've already got 177 million barrels of 2C booked from our previous drilling activities in Quokka and Bruce will through the potential scale opportunity there. And then we've got Horseshoe, another exciting prospect to the south of Pikka. So incredible running room and Alaska. And I'll go back to our growth, our 3 region growth strategy, looking at large-scale sort of scale of basins that Santos has never had to invest in, in the past. We've got them in Alaska. We got in PNG, and we hope to have them in Australia going forward.

And what does that mean? That means that all your investment in the future, all your focus is developing fewer but much larger basins, driving lower unit cost developments, lower development costs, lower unit cost of production and higher margin barrels over the business.

And so what does that mean? Because many of you are saying, okay, well, Barossa and Pikka coming on like how should we think about growth going forward? And this is really just to tell you, we've got a lot of optionality in that portfolio. Things get tough and a stricter for a while. We've got a lot of growth opportunities in Alaska and in PNG. And that's a great thing and great flexibility for a business our size to have I think we've got a portfolio that would be the envy of most of our peers. In fact, I saw a chart recently by Wood Mac that showed our growth opportunities out to 2035, way above anyone else in the market. And I include the majors in that -- most of them are pretty flat or going down. And what does that say? That says you should expect to see what you're seeing in the market right now, significant consolidation play as people buy growth, we have organic growth. We have very significant organic growth. We obviously [indiscernible] coming on right now and giving you that initial production uplift. But we're still targeting a 4% CAGR growth rate all the way through to [ 25. ] And we believe we can do that with that capital discipline within that framework we've described earlier on with an all-in breakeven of $45 to $50, which allows us then to continue to drive really strong returns for our shareholders at the same time.

So sustainable strong returns, sustainable reinvestment in the business, recycling CapEx out to Cooper Basin into higher return growth hubs going forward will give us a very sustainable business for decades. And it's all about growing free cash flow at the end of the day.

And -- cash flow per barrel. Here's I would say a Wood Mac chart, this is Woodside -- it's a Wood Mac chart. And you can see where it places Santos between '26 and 2040 for margin per barrel, and it puts us #1 globally on a go-forward basis. Now I do not believe -- it might take some premiums in account, but I do not believe that will be taking the premiums for Alaska into account, and I do not believe it will take the full extent of the opportunities in Alaska into account. But you can see through that some of the -- now obviously, we get that stronger free cash flow generation from Pikka and Barossa coming online today. They have -- so I think they used $65 oil for this comparison. -- as they're compared so their view of our premiums is that results in $71 revenue per BOE for Santos.

So when they look at our products, that's how they see that. And then, of course, you can see that we're getting around $20 a barrel at 65%, and that can affect with the $45 to $50 model that we've actually put out here if you think about it. And what I would say is one of the things that's driving that for Santos is you're now beginning to see the benefits of us having all this -- all these organic opportunities adjacent to our advantaged infrastructure position. So we'll be talking about for many years that we can develop fields around existing infrastructure, which should give us a lower cost of development advantage over our competition.

And importantly, another announcement for today is that we are targeting getting our gearing down to the lower end of our gearing range, not overnight, but we're setting a net debt reduction target of USD 2.5 billion by 2030, $2.5 billion. And importantly, like the Cooper Basin, taking CapEx out and recycling that. That will result in approximately a reduction in interest payments by around USD 150 million per year by 2030, freeing up more cash flow from the portfolio for reinvestment and of course, for returning to shareholders. So that's $2.5 billion net debt reduction by 2035, taking us down to the lower end of that gearing range. And I look forward to seeing that debt, if you like, transitioning to equity in our share price. That's what I'm looking for by making a lower gear company.

And so we think that makes the Santos value proposition very, very clear. It's based on investing and growing our business around high-quality asset base, with an all-in free cash flow breakeven of $45 to $50 per barrel that then is focused on growing free cash flow. And every $10 of that free cash flow or every $10, the oil price is above the breakeven price of $45 to $50 will generate between [ 550 and 600 ] from the end of this year. Actually really from the both projects coming online at full rates. And that will drive stronger shareholder returns for years to come. And that's my introduction section.

What I'm going to do now is hand over to Lachie to take you through the financials. Thank you very much.

Thanks, Kevin, and good morning. For those who haven't met in the room, my name is Lachlan Harris, I'm the CFO of Santos. I'm going to take you through the finance and balance sheet section of today's presentation. I've got 3 key messages which are going to build on what Kevin has gone through. The first of all is to bring the capital allocation framework to life and to give you an example as to how you can really see or predict, forecast what our free cash flow generation will be and by default, a level of shareholder returns. The second is to go through the net gearing target that Kevin just spoke to. And the third will be to unlock or show how our EBITDAX margins are generating returns by investing in higher-growth barrels, aligning to what Kevin mentioned in regards to CPI and our ability to absorb the CPI in our cost base.

Kevin showed you this chart just before shareholder returns in growth, 2 key pillars in the disciplined operating model. Free cash flow breakeven from operations at or below $35 a barrel. We've had it for 10 years, it's continuing. We've got a relentless focus on bringing that number down. The lower we can bring that number down, that will generate more shareholder returns and free cash flow, and I'll take you through that in a second.

On top of that, as Kevin mentioned, that $10 to $15 increase from the operating model to the target and free cash flow breakeven is where we've got growth CapEx, development CapEx to come forward. And I'll show you what we can do with that CapEx. And Kevin has shown you the projects we've got to do with that CapEx, what I'll do is I'll share how that works in reality in terms of the model.

Underpinning that, we used to always talk about a $400 million movement or [indiscernible] movement in free cash flow for every dollar of Brent. As Kevin mentioned, now that's getting closer to $550 million to $600 million when the 2 assets, [indiscernible] and Pikka are at plateau rates. So that's just going to be higher production, higher free cash flow generation.

Underpinning the disciplined operating model is the capital allocation framework. Kevin has already mentioned target gearing, 15% to 25%. No change there, but we're driving down sort of what -- we're going to target to drive down the bottom towards the 15%, minimum 60% of the free cash flow we generate above that price is in shareholder returns, and then 40% will now go -- 40% -- maximum of 40% de-gearing the balance sheet.

Now if I bring that to life with a simple example in terms of the capital allocation framework, and Kevin has already mentioned it. If we take a $50 oil price is to break even in any 1 year, if we take the top end of that range, I say, well, how much free cash flow will Santos generate. If I give you a simple example of saying if the oil price was $75 for the year, $75 minus $50 is $25. That's the delta, that $25 sensitivity, say, 600 just for ease of purpose of the calculation. $25 x 600 will be $1.5 billion in free cash flow generated for the year. You can move that up and down. If you've got a higher oil price at another 550 to 600 for every 10 or conversely, if you're going down, take it off. So $75 oil price the assets at [indiscernible] rate, we'd expect around $1.5 billion in free cash flow generated. Of that $75 -- sorry, of that $1.5 billion, we've already said 60% minimum return to shareholders. That's about $900 million. So to give you a level of an understanding as to where we're at, $75 oil price, [indiscernible] it's just the delta between the oil price assumption you have and the $50 breakeven time for sensitivity.

So you can take that away and work it out at whatever oil price you want to run. You can get an understanding to what free cash flow we expect to generate. Now obviously, the competitive advantage that we will have is to drive that $45 to $50 down. And as I mentioned, we can do that 2 ways. In the operating cost base at the $35 level getting that down or lower development CapEx. The reality for the development CapEx will be or the growth CapEx, it will go up and down through the cycle. It's not going to be a linear spend profile. We will continue to guide you through or guide you every year as to where we expect to be in that phase. One thing that Kevin did mention, I want to reiterate is that we're now past peak CapEx from both the Barossa and Pika project as they've come online. -- and to reiterate that $550 million to $600 million once those 2 assets are in plus rates. So it's an exciting part of what the capital allocation framework will do and generate. And we think that the model is quite simplistic in its calculation and, hopefully, easy to understand. And I should have said, and I will reiterate all this is going to be underpinned by our target gearing range and our investment-grade balance sheet.

Moving to the balance sheet. The balance sheet is well positioned for Santos as we move into this '26 to '30 phase of Santos' life. The balance sheet is strong. We've got -- it's well supported. We've got strong liquidity at $4.3 billion. Kevin has already mentioned, the net debt target reduction coming down from where we currently are, -- so it's probably -- it was around 27% at the end of the year, bringing that down and targeting to get down to 15%. In a $75 oil world using the same oil price that I just went through, we expect to get there by 2030, but it will be underpinned by a disciplined operating model. We don't need to do anything else at $75, we'll get there.

Stronger oil prices initially, sure, they'll provide a bit of a tailwind for us in that instance. But the disciplined operating model will be what will get us there. $4.3 billion in liquidity. Just last week, Moody's upgraded us from stable to positive, so a great announcement as we continue to move into the space of cash generation. The drawn debt maturity profile, we're same as where we're at the end of the year, the balance sheet is underpinned by 5 investment bonds in the market. No debt maturities until September 2027. We've taken some -- we've taken an FX hedging position, and we've taken some commodity hedging to protect the cost base through the cycle.

In terms of what we're going to do with the cash and generate the cash, another example of a $75 scenario for the next 5 years. This is how much operating cash flow we expect to generate. Of that operating cash flow, we will then be investing in CapEx. That's going to be a CapEx. That's a mix going to be of growth CapEx and sustaining CapEx. We'll then -- shareholder returns will come in at the minimum 60% and and that degearing wedge, by 2030, as I said, in a $75 oil world, that will be the balance sheet hitting that 15% target gearing range.

Once we hit that, as the model indicates in the previous couple of slides, the shareholder return bucket goes up once the degearing has got down towards the bottom end of that 15%. This slide also demonstrates that we've got strong capacity to fund future growth, and that's important. There's a lot of optionality we have. Kevin has gone through some of the slides, and we're going to go through further with Brett and Bruce and the team in regards to the great optionality that we have for future growth. This model and the balance sheet and the framework is fit to be able to sustain growth and to sequence growth that will allow us to continue to grow in the $45 to $50 model, and that's what's important.

Before I get on to how many projects we think we can do, I just wanted to update you on the Papua project financing. And Brett is going to talk about the project, but just in terms of the Papua of project financing component -- we are continuing to pursue with the partners a project financing solution for Papua, and it is going very well. [indiscernible] Commercial Bank support is very strong. We anticipate that this financing will be in a ring-fenced type incorporated structure, and it will provide potentially up to the first 60% of the capital required for the Papua project. Now that's important because if the project financing is providing the first 60% of CapEx, that will be front loaded, meaning that the equity contribution that the partners will put in will be towards the back end.

So if Papua does move forward, the project financing is going to be there ready to take the first heavy lifting in terms of the cost of the project. Now what that does is important to the bottom point because that will allow us to do at least the Papua project and 1 potentially 2 other development projects at 1 time and fit within the $45 to $50. Now that will be dependent on sequencing, phasing and working interest of where we get to with some of the projects. But the balance sheet is positioned to fund growth in the model at the $45 to $50 level. And that's what the strength of the balance sheet is currently designed to do.

My last slide is to take you through and just to reiterate what Kevin has already spoken about in regards to our growing margins and our ability to absorb inflation. By investing in higher-margin barrels targeting lower unit costs we are driving higher -- driving higher margins throughout the decade, throughout the period, especially against our peer group, and we have flattened out. We are keeping it at a lower level. We are continuing to focus on the cost base and to drive that down. It drives competitive advantage and is what Santos is known for.

As you can see, we had record low unit production costs last year and unit production costs have reduced by 20% since 2016. So we want to continue to be peer-leading in the space. and we're not going to stop at any point. We're going to continue that focus, and you'll hear that throughout the rest of the morning when Brett and Bruce and the team go through the assets.

My last point is just in regards to the structural cost savings, we last year announced a $150 million cost out target. We delivered $50 million to the end of last year. and we are continuing to pursue that project and we'll aim to update you throughout the year as we get to that $150 million annual cost saving initiatives. So that concludes my presentation today.

I just wanted to reiterate my 3 key messages today with the capital allocation framework and how it's going to generate generate free cash flow and shareholder returns. Secondly, the net debt reduction target of $2.5 billion and how we expect to get there by 2030. And lastly, the margins and expanding on what Kevin already mentioned in terms of our unit production costs and our cost discipline.

So thank you very much. I'm now going to hand over to Tracy.

Thank you, Lachie. My name is Tracy Winters, and I'm the Chief Strategy Officer for Santos. Today, I'm going to make the case that this is the best time in more than a decade to be in oil and gas and LNG and oil. We live in an era of global energy addition. By the middle of the century, the world will have 2 billion more people mostly in the developing world, all needing energy. Artificial intelligence is also reshaping global energy markets, accelerating electricity demand growth after years of stagnation in many developed economies and increasing the importance of reliable baseload power.

Demand for energy keeps rising because demand for human progress keeps rising. The challenge is not choosing between energy sources, it is producing more energy with fewer emissions. Despite the world's best efforts and trillions of dollars of investment over the last 35 years or so, hydrocarbon fuels still make up 80% of the global energy mix today, down only around 5% compared to 50 years ago. Oil and gas alone account for around 50%, and we'll continue to do so through 2040 and beyond. And there are limited alternatives for them in many applications. Oil and gas are not just fuels. They are essential to make things like plastics, fertilizers, synthetic fibers, pharmaceuticals, steel and electronics components.

Historically, energy transitions take 40 to 150 years. depending on the system, technology and policy support. And today's energy system is the largest and most complex ever built. This means all energy sources will grow simultaneously. For the oil and gas industry, several factors have aligned in a way that our industry has not seen for a long time. First, demand resilience. Despite years of peak oil expectations, global oil demand is still around record highs above 100 million barrels a day while the LNG demand growth has accelerated, especially in Asia.

Second, under investment from 2014 to 2021. Following the 2014 oil price collapse, COVID-19, ESG pressures and transition uncertainty, global upstream investment was materially constrained for many years, tightening spare capacity and new supply growth. Third, LNG has become geopolitically strategic -- after Russia's invasion of Ukraine, LNG shifted from being viewed as a transition fuel to the energy security commodity. Long-term LNG contracting returned strongly, especially from North Asia, Europe and emerging Asian buyers. Fourth, higher long-run price expectations -- the floor price for both LNG and oil is likely to be higher because upstream decline rates are relentless, replacement volumes are more expensive and geopolitical risk premiums are persistent.

Finally, public policy realism has increased. More and more governments around the world are now acknowledging that renewables alone cannot sustain modern industrial economies. Gas is needed for grid stability and reliability and oil demand in heavy transport, aviation and petrochemicals is proving very hard to displace. All of these factors are benefiting incumbents in the relatively small number of countries that will dominate low cost, low emissions future supply. And those include Santos supply hubs in Australia, Papua New Guinea and Alaska.

These hubs are on the doorstep of Asia, which has over 50% of the world's population and accounts for almost 50% of the world's total energy consumption. And where 55% of global energy demand growth is forecast to occur in the next 15 years. In particular, the center of LNG demand growth is Asia.

The outlook for LNG is arguably strongest since the original Asian LNG expansion cycle of the 2000s with growing demand, renewed European dependence long-term contracts returning and limited new supply, with buyers likely to be more wary of Middle Eastern supply in the future. What we are showing here is sustained demand growth driven by industrialization urbanization, electrification, rising living standards and energy security concerns across both developed and developing Asia.

According to Wood Mackenzie, global LNG demand grows by more than 60% through to 2040, with Asia accounting for around 3/4 of total growth. The left-hand chart highlights an increasingly important issue for the global market, supply adequacy. Existing LNG supply begins to plateau over time as mature assets decline. Even with projects currently under construction, Wood Mackenzie identifies a substantial supply gap emerging through the 2030s. More than 65 million tons per annum of additional LNG supply will need to reach final investment decision to balance the market by 2040. And there remains considerable uncertainty about the future of Qatar supply growth, including the return to service of the 12.8 million tons of capacity damaged at [indiscernible] during the current conflict.

LNG consumption is broadening from traditional North Asian markets across Southeast and South Asia. Countries such as India, Vietnam, Thailand, the Philippines and Bangladesh are increasingly using LNG to support power generation, industrial growth and energy security. South and Southeast Asian LNG imports alone are expected to increase from around 60 million tons today to 200 million tons by 2040. While these markets are price-sensitive today, demand growth will increasingly require supply from higher-cost suppliers distant from market in an environment of rising project costs, tighter engineering and labor markets, geopolitical risk premiums and shipping constraints.

This creates a real opportunity for reliable, low-cost Pacific Basin suppliers like Santos. Australia and Papua New Guinea remain exceptionally well positioned, geographically close to Asian demand centers highly experienced in LNG operations and capable of supplying long-term contracts into the fastest growing energy markets in the world. The broader strategic point is that despite rapid growth in renewables, the world is still going to require very large volumes of gas particularly LNG to support economic development, industrial activity and power system reliability across Asia for decades to come.

Global oil demand is also proving far more resilient than many forecasts anticipated only a few years ago. Despite rapid growth in renewables and electric vehicles, the world still relies on oil for heavy transport, manufacturing, petrochemicals, aviation, agriculture and heavy industry. As a result, most major outlets now see oil demand remaining at or near historically high levels well into the 2040s.

The chart on the left illustrates 2 important trends. First, global demand remains broadly stable over the long term. Demand plateaus rather than collapses supported by petrochemicals, aviation and Emerging Asia. Second, and arguably more important, existing supply declines materially over time. Mature oilfields naturally decline every year, meaning the industry must continually invest simply to maintain current production levels.

What the chart demonstrates is the emergence of a significant supply gap from the mid-2030s onward unless substantial new investment is sanctioned. Wood Mackenzie estimates prices above $70 a barrel are likely to be required to incentivize sufficient new supply to both offset decline rates and meet long-term demand. This dynamic is reinforced by years of global underinvestment that I talked about earlier.

At the same time, the composition of demand is evolving. Petrochemicals and aviation are major growth drivers. The reality is that there are no viable scalable alternatives yet available for jet fuel. The chart on the right reinforces the central role of Asia. While demand in some OECD economy stabilizes or gradually declines growth across India and the broader Asian region offset much of that reduction. The broader conclusion is that the market increasingly appears characterized not by imminent peak demand, but by a long demand plateau combined with tightening supply conditions. For low-cost, reliable producers like Santos that creates an attractive long-term investment environment.

A theme that has become increasingly important in global energy markets over the past several years is that geography and geopolitics now matter as much as geology. Global LNG and oil markets are no longer driven purely by lowest cost supply. Buyers are increasingly prioritizing energy security, reliability, shipping resilience and geopolitical alignment, and reducing emissions is still important. This shift strongly favors Santos supply hubs across Australia, Papua New Guinea and Alaska. The map on the left highlights a key strategic advantage, direct Pacific Basin access into North Asian demand centers.

Unlike Middle Eastern supply, Pacific LNG shipments avoid some of the world's major maritime choke points. The current conflict has reinforced how vulnerable global energy systems are when too much supply is concentrated through narrow trade corridors. And that will have an impact on how buyers look at their LNG and oil security in the future. Santos assets are positioned close to premium North Asian buyers and the growing Southeast Asian market. That proximity delivers several advantages simultaneously.

First, shorter shipping distances, reduced freight costs and improve delivered competitiveness into Asian markets. second, shorter voyages, lower shipping emissions and reduced fuel consumption and increasingly important consideration for customers focused on supply chain emissions intensity. Third, Pacific Basin supply provides enhanced reliability and schedule certainty compared with longer, more exposed trade routes. Energy Security has become particularly important for North Asian buyers following the European gas crisis after Russia's invasion of Ukraine and growing strategic tensions across global shipping lanes. Many customers are now seeking long-term supply relationships with politically stable and trusted jurisdictions. Australia already exports 90% of it's LNG into Asia, while Australia itself imports most of its refined liquid fuels from Asian partners reinforcing the depths of regional energy interdependence. This creates a strategic alignment between supplier and customer that extends beyond simple commodity trade. Relationships matter. The broader message is that Santos is not simply advantaged by resource and asset quality. It is advantaged by location in a world where energy security, geopolitical resilience and reliable supply chains are increasingly valuable. Pacific Basin, LNG and oil have a strong competitive position. That strategic advantage is likely to become more important, not less as global markets tighten through the 2030s and beyond.

I'll now hand over to my colleague, Sean Pitt, to take you through how our marketing, trading and shipping team is leveraging these strategic advantages for Santos.

Good morning. Thank you, [ Tracy ]. Firstly, my name is Sean Pitt. I'm delighted to be here, and I'm the Executive Vice President for Marketing, Trading and shipping for Santos. It's a great company. You've seen some of the opportunities, the assets, and you'll hear more about it from my other colleagues today, but I still think I've got the best job in the company, and I get the ability to bring the products to the globe.

So marketing, trading and shipping. We see it as a direct value driver for Santos. Our purpose is to maximize the realized price and by extension, maximizing margin available for the broader business. Our LNG strategy is deliberate and layered, spanning spot, mid-term and longer-term positions with high-quality end users and its core established relationships with [indiscernible], Shizouka Gas and Nippon Steel exemplify this approach. This layering enables Santos to respond dynamically to market conditions while maintaining a Brent slope equivalent to or greater than 14%. A benchmark that reflects the quality of both our portfolio counterparties and the result is a strong sustainable realized price of $1.50 -- sorry, thank you. Our Sweet Australian crude compete strongly against West African grades such as Bonny Light, it carries a material freight advantage into the regional market and is ideally suited to Asian refiners optimizing production of jet fuel, motor gasoline and naphtha delivering near double-digit premiums over Brent similar to what Tracy just alluded to on the demand for those products. LPG remains a versatile and highly transportable fuel across developing Asian economies. Domestically, demand continues against the backdrop of declining local supply, a structural dynamic that works in our favor, again, factors that support strong to selling indices such as the Saudi contract price or Saudi CP. And finally, Alaska North Slope, a [ medium weight ] sour grade highly sought after as both a replacement grade for its strong middle distillate yield, making it well suited for complex refining configurations across our Asian Pacific region.

Santos operates a formidable and highly valued portfolio. Several attributes combine to make it genuinely differentiated in the eyes of our buyers. First, our regional location. Our post code is one of the most valued in the global economy proximate to the highest demand LNG and crude consuming nations in the world, many participants are looking to grow their Pacific supply and reduce their Atlantic positions. Second, as both operator and an equity lifter, buyers are actively seeking to reduce complexity and counterparty risk and energy supply chain. In some cases and in recent times, I've certainly seen a cargo pass through 44 sets of hands before arriving to its original Lifter. Santos did not participate in this transaction. I can assure you that, Kevin.

However, each one of those touch points is a potential failure. Santos is a direct operated equity participant eliminates that risk avoiding long chains of intermediaries and strategically positioned away from contested chokepoints is increasingly valued by sophisticated end users. We're a preferred supplier because of these key points. As can be seen on the chart on the right, our portfolio is in a strengthening position. Materially new supply tends to be from the Atlantic is the wrong post code with new supply also typically lean while Santos' portfolio LNG is both of a high-quality HHV value or high heating value and MOC specification or market on close, a suitable and sought after trading position. The combination of our local advantage, high-heating value portfolio and direct equity participation has translated into measurable and incremental value through short-, mid- and long-term contracting.

Our contracting strategy is built around deliberate laying, as I mentioned before, spot exposure through short-term markets providing liquidity and market intelligence, midterm positions are structured to capture periods of structural price strengthening. Longer-term contracts with high-quality end users provide stability and underpin our financial planning horizons. The [ middle ] long-term arrangements rest on deep established counterpart relationships leveraging our world-class highly capable shipping, trading and marketing team, which is located in Australia, Japan and Singapore.

We've invested considerable time understanding what our customers value most, optionality and contractually and where we can constructively offer flexibility in return for portfolio optionality that benefits us, Santos. The result is a set of contractual structures that generally bilateral in their very value creation. This approach has translated into sustained strong pricing that you can see through the results today. The Santos portfolio originated as a set of joint venture contracts. As it's evolved toward a greater equity participation model, we have successfully captured incremental value and realized price following that trajectory. And you see that each quarter, as you compare to our peers.

Looking forward, as the equity proportion of the portfolio continues to strengthen and increase, we expect that trajectory of incremental value and superior realized pricing relative to our peers to be sustained, if not grow. This is reflected in our current brent realization of approximately 14.6%, a strong outcome by any measure, an envy for many of our competitors.

We continue to maintain approximately 80% of our volumes contracted with around 20% available as a spot exposure. This balance allows us to respond to market movements whether that means extending into mid- or longer-term positions, capturing secondary market pricing or providing support or supply assurance to valued customers or countries.

Importantly, as the portfolio has matured and contractually flexibility has been embedded, Santos has began to actively monetize that optionality. In 2026, we've already delivered approximately 0.5 million tonnes of [ that ] optimized or traded position. This will continue to grow and generate higher margin value at a low risk without the requirement of any additional capital. Alaska North Slope crude. So we often refer to it as [indiscernible], but it is ANS, which our [indiscernible] will supply by the transatlantic pipe system or TAPS. It is an exceptionally high demand. Headline premiums of $20 per barrel above Brent reflects a market that is actively seeking supply security from outside contested maritime zones and potential choke points. I've spent much time with many, many Japan or Japanese counterparties, and they have all indicated that even despite a cessation of activities in the Middle East, they will pivot away from a supply that would be fully dependent on Middle East and crude. ANS is a middleweight sour grade highly valued in its distillate yield, making it particularly attractive to complex refining systems across North Asia, the grades technical fit with these facilities underpins a structural demand base that stands well beyond any near-term political premiums.

The security supply dimension cannot be overstated. As I mentioned, Japan has great interest. So much, on 26th of April 2026, Japan marked the landmark moment when Suez tanker of 900,000 barrels of U.S. Gulf crude procured by Cosmo Oil, a company that we're very close to entered Tokyo Bay. It was such a monumental effect that it televise the arrival of the ship on national TV. A measure of just how significant energy security has become to the Japanese consciousness.

Even beyond any eventual ceasefire, the stabilization structure drives Pikka crude remains compelling. West Coast refining capacity on the West Coast of the U.S. is contracting 7% year-on-year, reducing domestic competition for the grade. Jones Act shipping constraints makes U.S. distribution expensive and logically complex where Asian buyers are highly motivated and are seeking sources away from the Middle East. It also adds and supports their ambitions to support the Trump administration in its trading activities.

In conclusion, I'd like to leave you with 3 observations. Santos operates a formidable portfolio, one that is geographically advantaged, technically differentiated and commercially sophisticated. Our established and high-quality customer base generates genuine co-benefits for both Santos and our buyers, relationships built on trust, transparency and a shared commercial interest. In our products, command strong sustained premiums relative to their indices, a function of quality, reliability and strategic positioning of everything I've described today.

Well, thank you very much, I'll pass on the mic.

Good morning. My name is Mark [indiscernible]. I described myself as a deeply technical reservoir engineer. I'm also [indiscernible] as Vice President of Santos. Responsible for the disciplines of geophysics, geology, reservoir engineering, production engineering. And that includes us reserves, which is the topic of discussion this morning. I'm going to take you through how much we have, how we manage it and what it cost to replace it.

4.7 billion barrels of 2P plus 2C resource, 1.5 billion barrels of 2P, 3.2 million of 2C resource. Put that in context, the world consumes about 100 million barrels of oil a day. That's spread across 3 assets, Australia, PNG and Alaska. And it's weighted over 80% of premium product, LNG and liquids. Now those 3 geographic hubs give us diversity of geography, they also give us diversity of geology. In Australia, we've got quite diverse, but it spans Jurassic, Prolific, gas reservoirs, big bore, 300 million [indiscernible] per day wells in Barossa. Factory mode development of marine shales and in [ bitumen ]. In PNG, it's a prolific gas [indiscernible]. Many fields of high rate wells have been already developed. Plastics in the highlands, and coming up with Papua with a reef carbonate shortly. And in Alaska, we've got our conventional oil where we're developing with horizontal wells placed through fluvial -- sorry, sandstones in the shelf edge. And we're developing those with a water alternating gas [ flood ] from the get-go to efficiently sweep from the injectors to the producers. This diversity of geology and geography and product gives us optionality. So when the world throws us curveballs rather than just seeing challenges, we see some opportunities as well.

For a portfolio of this size, how do we manage it? Plot here is what we call a reserve life index or RLI. Quite simply, each one of those data points is the reserves at that year divided by the volume produced in that year. This one is a 1P. It's not a measure of how long our reserves will last for. It's a discipline and health check. It guides us as to when we need to replace reserves and how much for a given target offtake rate.

We see a sweet spot there. If you go much below the sweet spot, you run the risk of shortfalling and you get pushed into making hasty decisions. You go too high, you're overinvesting on long-dated production. So we see that sweet swot as between about 8 to 12 years on a 1P basis, and we are well placed compared to our peers in that area. And that position gives us the ability to pick and choose the when and the what we select next. And when we're making that selection, the cost per BOE is one of the key aspects we look at, and those costs are going down. Ten years ago, we had -- first, to set this up. What we're seeing here is the cost to replace a developed 2P barrel of oil equivalent, all in. Ten years ago, that was $20. Over the forward 5 years, we would drop that by 20% to about $16. Now we're proud of that. That reflects capital efficiency, it reflects an operational focus. But it also reflects a choice in the projects that we're executing a pivot to a more Tier 1 focus. And it's that pivot that we've been doing and continue to do that is going to deliver the target of less than 13% going forward, and let me explain why.

First, Advantage portfolio. Some examples, Pikka Phase 1. We've already seen first oil, factory mode development. The world is performing. There's a Pika Phase 2 around the corner. This model of two developments sharing at facilities. We see [indiscernible] and we see a [indiscernible] over into horseshoe and that's not even take into account the exploration upside, which is phenomenal. Second would be Papua. This is a proven high-deliverability gas play. When I say high deliverability, I'm not sure if anyone remembers but back in 2009, the Elk-2 well tested over 700 million [indiscernible] per day on test. Phenomenal rate in fact, if anyone can find me a validated test that's higher than that I'll buy them a beer [ first personally ], but I'll buy them a beer.

Second is the internal competition. We've got Bedout competing with Beetaloo competing with Quokka and Horseshoe. It's an enviable portfolio and it's not enough just to get a certain metric, a certain investment metric to get up. They've got to compete and be the best one in our portfolio. That drives the efficiencies.

Resource depth. I'm not talking depth below the ground. I'm talking materiality size and the poster child there is Beetaloo. We've got a great position, three shales A, B and C. Just the B shale alone has been assessed at having over 200 Tcf in place across the play. A, B and C together, I think you've seen this report at over 400 Tcf. This is foundational gas that has decades of running room. And it's those decades of running room where the costs get ground out. It's being assessed as being analogous to Utica and Marcellus, which deliver about 1.6 Bs per 1,000 foot of recovery. And we compare favorably across the subsurface elements of that, which include frackability or [indiscernible] content, productivity index on a normalized length basis -- shell thickness. And when I say it compares favorable, I'm not talking about just scraping the bottom of the barrel, just squint slightly. This is right in the cluster, right in the cloud, if not at the top end. It's really exciting. We've got two appraisal wells in the B coming up soon, 3,000 meter length, 60 frac stators, 2,200 pounds per foot, a red hot go at this one. We're also testing the A as well with a shorter 1,000-meter well. So I'm super excited to get the results of those and run [indiscernible] over the next year.

And last is leveraging our operated positions with the Tier 1. These larger assets, it really opens more avenues there. Two examples, Pikka Phase 1 already being executed. Pikka Phase 2 is just around the corner, just plug-and-play, factory mode development back into the same facilities.

APF Tie-in PNG. This is gas associated with our oil fields that has just been stranded. We're plugging into the PNG LNG project. 135 million [indiscernible] per day. No additional compression as some of the most attractive barrels -- BOEs you'll ever find. So our track record says we've dropped our costs by 20% already. Our portfolio says there's much more to go. And if I wrap this all up back to the top, materiality, 4.7 billion barrels across the 3 hubs, different products gives us the options, reserve life index. We're in the sweet spot, gives us the luxury of being able to pick and choose what comes next, and our costs are coming down. So that's the reserve picture. I think it looks pretty good. And I think with that, we're off to coffee.

[Break]

Well, welcome back, everybody. I hope you managed to get whatever it was you got during the break and refreshed and ready to go for the next session. That video, actually, I just -- it's worth commenting on that video. And one of the things I think has been a real transformation for Santos over the last 5 to 6 years has been the effectiveness and the contribution that we're having on local communities and the real commitment across our organization to making a difference. We changed our purpose statement in 2021 to reflect that when we said it's not just about shareholder returns, that's very important and largely really important to all of you people in this room as to all the management team and the Board, but it's also about making a difference in the communities where we operate and creating a better world for everyone. And that's a really important part of the Santos ethos. And you saw some great examples there, the foundations work in PNG. That 7,800 cervical cancer screening that we've done has saved almost 800 lives that otherwise would have had cervical cancer with no treatment, no road to treatment because we can identify that through the screening and on that same day, apply treatment courses for those individuals and start treating them for those diseases that would have been undetected. There is no health system that picks that sort of stuff up. You saw the COVID vaccinations, the Typhoid, the other vaccinations that we give that just aren't readily available to people in PNG. And then the foundation has now moved into the Northern Territory. And you saw some of the work we're doing there in those local communities, helping those communities get a better way of life.

Now in the long term, that is good for Santos because we partner with those communities. We're operating in those communities. And a good thing now is we're offering and developing a lot of local jobs, sustainable jobs for the young people in those communities that hopefully will help break the cycle over the longer term.

It's a long-term objective, but the reason I shared it with you and share my thoughts on it. And let me tell you, it takes a lot to bring a tear to a Scotsman's eye. But there's a few things that I have experienced up in the highlands of PNG really to 5-year-olds. And they didn't say that's a funny accent you've got, by the way. They understood every word I said. So I don't know what that tells you about the PNG kids. But when you're going to experience it and see it for yourself, it's something that makes the employees at Santos immensely proud of the work that we do even up in the north slope of Alaska and you see some of the involvement. And what we're seeing now is indigenous employee numbers, if you look at a sustainability report, indigenous employee numbers that are way above the national average, way above the national average at Santos because it's a great company to work for because they know we're genuine with what we're doing in their communities anyway. I just want to share that before we go into the next session.

So now you're going to -- we're going to change pace a little bit and that was a slow session. Now we're going to go and look at the growth hubs themselves. And we're going to hear from Brett and Bruce and actually take you through their portfolio. And you can see I just remind you on this chart of the opportunities. That focus in those 3 regions, those 3 growth hubs, the 3 regions around the world focusing and prioritizing investment on those Tier 1 basins. And we keep saying that as we go forward. That is the focus of Santos' strategy going forward. Tier 1 basin. So you can see the list, I'm not going to go through them again because Brett and Bruce is going to take you through those. And then you're going to hear from Alan on Midstream and Energy Solutions part of the business. And then Steve, and then I'll wrap up at the end, and we'll get some of the guys back on the stage for some Q&A.

So Brett, over to you, mate.

Thanks. Thanks, Kevin. Good morning, everyone. I'm Brett Darley. I'm the Chief Operating Officer for Australian PNG Upstream. And I'd like to just take you through the assets a bit of an update in the first quarter, and then I'm going to dig in on a little bit more detail on some of the areas that Kevin has covered already. I would say that in the last 10 years and in previous presentations, we spent a lot of time talking about honing our operating model, our disciplined low-cost operating model to make good money to hold inflation flat in some of our non-Tier 1 assets. They are good assets to run, and we've had to run them hard. But as we're pivoting to Tier 1 assets here, and we'll talk about some of them in a second, with that ability to operate and keeping that model with Tier 1 assets, look out. There's a lot of assets here as well to go through. competition is going to be fierce. I'm not really sure how we're actually going to allocate it. I think we're going to meet an octagon or something with Bruce and I. He looks like he's got that Farm Boy strength. So I'm going to have to watch out for that. But yes, there's some excellent things we're going to be running through. And I think this is a great problem to have.

So let's just start with the asset update for '26 so far. So on the Cooper, a couple of things to talk about MCO, so that's Moomba Central optimization. So this is going to transform the area where most of our remaining reserves exist for the Cooper Basin. So it's our oldest equipment, our least reliable equipment and ultimately, it's a place that we're going to produce the majority of our reserves going forward. We are going to modernize that area. We're going to target the capital for that area, and we will make it more reliable. We're basically going to fold 7 satellites into 1. That will be out to be remote operated, electrically run, we'll be able to turn these things -- instead of sending people out to them, we'll be able to actually operate these things remotely. So we're going to revolutionize the area we have the most -- most of our remaining reserves in with MCO. On the sales side, Kevin mentioned, we actually did sign -- or we've entered into a 10-year agreement with the South Australian government to supply 20 petajoules a year from 2031. So that really underpins Santos and our commitment to domestic gas market going forward as well. In WA, Kevin spoke about Halyard. So again, it shows the value of these tiebacks to Varanus Island. These are really low-cost operating barrels. Halyard-2 is overperforming. It's already produced more than 85% of what we thought it would produce and we actually haven't seen any water breakthrough or pressure decline. So that's going to continue to provide value there, but again, shows the value of those tie-ins to Varanus Island. Also, Steve will go through in a bit more detail about the [indiscernible] being safe and [ removed ] ahead of schedule. So it's the largest platform that's been removed in Australia to date. And what is that showing below budget and ahead of schedule with no incidents. That actually -- you can start to project that forward with our decommissioning liabilities. We can do these things cheaper than we thought we could do them and that adds value to the business as well.

GLNG, good run rate, 24 cargoes shipped to date. And we are seeing some good performance, particularly in Fairview with some of the longer wells we drilled. We actually just drilled a 5,500-meter well in that field. And we're starting to see some good flow rates, some really good flow rates in an area that we thought was on decline with actually arrested decline in Fairview, and [indiscernible] is actually producing just above what we expected at the moment as well. So some good strong performance from these base assets.

Barossa, I'm going to talk to Barossa in the next slide or two to give you an update on where we are with that. And PNG LNG continues to perform really well. We've got two projects that we FID in the first quarter, the FSO, which is actually a way that we will export the liquids. Currently, we're doing it from marine terminals to reach the end of its life. The FSO gives us a lot more flexibility. And also, we've integrated the FSO. So that's our liquid exporting for PNG LNG into the new scope for the Papua project as well. So Papua liquids and PNG LNG liquids will both be exported from that FSO. The storage will actually be offshore as opposed to being on tanks onshore. And we're actually running very well at PNG LNG. So with the higher oil prices, we've been focusing on more [indiscernible] gas backing [indiscernible] for the operator has, and we've seen some good liquids upside in that. We're actually 0.5 million barrels above plan, [indiscernible] share in the first quarter of 2026.

Now I'll just dig into Barossa a little bit. So as Kevin said, Sunday, we had the Prism Brilliance, completed its load out and it departed on Sunday. The next vessel is on its way for -- and it will be there next week for load out as well. So the issues we had that have been mentioned on the filing of the heat exchanges. So this is to lower the temperature of the gas. We had failing issues that we reported. Those falling issues happened very quickly. We did not expect them to occur. But what I can say right now is we understand what caused them. We've cleaned the heat exchanges back to factory condition and we know how to prevent reoccurrence. And the facility has been running around 70% to 75% of planned [ rates ] for the last 10 to 14 days. So it's going very, very well at the moment. And Kevin also mentioned these are high-quality wells. So each one of the 6 wells that we've drilled out there, 300 million standard cubic feet per day of potential. There is no constraint from the reservoir. So at the moment, we expect to get the plateau rates about midyear as we bring our production up and we'll bring that up in a stable way so that we continue to operate in the meantime. So we're going to just take that slowly up to production rates, mid- but the issues we had with the filing on the FPSO are well and truly behind us.

And just let me remind you, this is a world-class project. So Barossa is world-class. These are sort of charts you want to see. Barossa keeps the LNG full out until 2040. So this project is going to be producing 3.7 million tonnes per annum of gas or LNG into a market or out of a location, as Sean explained, that is actually a really good post code to be producing gas in really low unit production cost and ultimately, CCS opportunities through [indiscernible] that Alan will take you through as well. So Barossa world-class asset, and it's now producing and we'll keep you updated on that.

Look, I'll go through this in a bit more detail, and we talked about this, but the basins that we're looking at, PNG, Tier 1, lots of plans to keep that full in the long term. And before Papua comes in, and I'll show you that in a minute. Beetaloo, fantastic asset. We're hoping that's going to be a Tier 1 province for us in the future. And the same with Bedout. And these are great assets to have on the books. And -- all right.

So Beetaloo. The Beetaloo Basin here, we've got -- Beetaloo's going to need scale. So it is remote. We have the scale. We've got the ability to have export pathways to generate scale to make this development happen. You'll see on the brochures that you've got on there, the Northern Territory government estimate more than 430 Tcf of undiscovered gas in place in this basin. I mean that's not just important for Santos. That's important for Australia. It's important for the region. This is a game changer. And as Kevin said, from our block alone, we don't need anybody else's block. We've got the best block in the basin, and I'll talk about that in a second. We can not only just fill GLNG trains, we can expand and we can provide domestic gas and more. So this is an absolute game changer. We've got the scale right now to be able to define and to be able to make a development happen with the export pathways that we have. We've got a train at GLNG that by the early 2030s, we're required to be backfilled from a resource. And when that time line works for us, we've got the ability through a different number of different pathways, but CCS connection either [indiscernible] CCS or through Bayu-Undan gives us the ability to place the CO2 into the ground. This is very low CO2 gas mind you. It's pipeline spec [ CO gas ] anyway, it's got 3%. But at the scale we're talking about, we still have the option for a CCS solution for that.

We've got some wells coming up, as Kevin said. So we've got 2 wells or 3 wells over the next year that we're planning to drill. Those 3 wells along with a 9-month production test. And these aren't just test wells, we are going to put in basically development wells, so we can test not just the resource size, but the deliverability so we can make a final investment decision after the evaluating these wells. And that would give us 5 Tcf in the basin. If we took FID on a project, which would give us about 500 TJs a day over 20 years enough to fill a train. So from an export route point of view, like I said, it is remote, but there's a number of options for us. I always say, which ways are going to go. It's not which way it's who goes first. And for us right now, our privileged infrastructure here through Moomba and the ability to put gas in to the East Coast market, but also to come down to Valera and be able to put 500 terajoules a day through the current pipelines into Gladstone via Wallumbilla that actually gives us an advantage right now. So that's our quickest way to market, but in saying that we have multiple ways to market.

On the rocks themselves. So Mark went through some of the rocks. I won't go through the technical details, but these are high-quality rocks. The things I wanted to point out is we've got 360,000 acres of resource area. They are comparable to the Utica and to the Marcellus Shale. So high carbon content, high pressures, all the things you need, good thickness. So the other part I wanted to point out here is we've actually got 3 shales. So if you're looking at who's got the best stuff in the basin, this is what you see on the Western side. This is what you see on our block here is not only do we have the B shale, which is what everyone talks about. And you can see the size of that and the depth, but our B shale is deeper. It's got more pressure, but we also have 2 others. We're actually really, really bullish on the A shale and we think there's potential with the C as well. So what that enables you to do is pretty much at least double that acre size from a stack play perspective. From a development perspective, you can actually access is a cheaper overall development cost if you can access 2 shales. And so the program that we've got coming up in the next year is going to be 2 wells in the B and 1 well in the A. And these are development style wells, long horizontals, 60-stage fracs, 9-month flowbacks. And at the end of that, we'll be able to make a decision, and we'll know what we've got but we're very bullish on these ones.

Now Bedout. So just look at the amount of opportunities here. There's nearly 1 billion barrels already of risk prospective resource in the Bedout. This is the next North West shelf And if you have a look at all of these opportunities, we've only just scratched the surface. We've got a development ready oil development in Dorado and parvo, you can see the resource numbers there. But what we're going to be doing in the next year is drilling 3 wells. And those 3 wells are going to inform us on a greater development opportunity. And again, we'll be drilling those 3 wells and very, very eager to see the results of those. But already, we actually have opportunities there that you could monetize.

In PNG, this is a very prolific obviously, resource play right along this reach here. We continue to see success in PNG. And actually, if I just go through the -- to this supply stack here, again, this is a Tier 1 asset, and it is filled way past 2040. Again, this is another place that continues to deliver. So if you look at our current stack here with Hides and APF CPF, so this is the PNG LNG operated production, this is our production that goes into PNG LNG. And then you have Papua and you'll see the expansion at Papua so there will be an additional 4 million tonnes built in the expansion and 2 million tonnes of capacity that it will be told to Papua joint ventures, [indiscernible] as well, and I don't even think we have [indiscernible] on here, but the running room or the ability to provide PNG LNG and its expanded form, well, well into the future. This is a fantastic, fantastic province.

So you would have seen there's a little dip just before you get to Papua, and I'll talk about Papua in a minute. We are trying everything we can with the joint ventures to fill that [indiscernible]. So there's a bunch of things we talked about. APF Time, which was already spoken about, 135 million standard cubic feet a day of additional gas that goes into PNG LNG. CPF expansion. So we have been getting good reliability up there since the Oil Search merger, but adding another compression train there to be able to get some more gas through CPF. Again, huge value if you've got [indiscernible] PNG LNG. APF expansion, we can quickly put some compression if we need to on the APF time and actually add another 50 million a day. Gobe just keeps on keeping on. At the moment, this was meant to -- we had end of field life originally 2 or 3 years ago. We're still doing 50 million standard cubic feet a day from Gobe. So working with the -- just doing the sort of production engineering to try and add little bits, [indiscernible] we've continued to extend Gobe, and where our target is to get that well out past 2030. And these are high heating value gas that is actually really, really not important, but prioritized by PNG LNG as part of the process.

And then ultimately, Steve will talk a little bit about this, not to be [indiscernible]. These are the cheapest barrels you can get going into our wells and actually optimizing , starting to use AI, starting to use every new technique we can to get the most out of our legacy wells. So these are very, very cheap barrels. And we're going to do all of that to try and make sure that we minimize the amount of ullage before Papua comes online.

And then if I talk about Papua, 6 million tonnes, so 4 million expansion. Ultimately, this delivers 1 million tonnes per annum to Santos net 11 million barrels equivalent per year, the Papua project. At the moment, there's a couple of things between milestones between now and FID, and Kevin talked about the Prime Minister's press release yesterday, he's just met with [indiscernible] in Paris. And there's a commitment to make FID happen before year-end. What do we need from the government? We need the development for them, which is where the landholders get together and agree on the benefit sharing. So that is now being committed to by the government to start late June, early July. We need the project financing. [indiscernible] spoke about that. We need the CapEx review. So the rebid, and there was a couple of things that happened in that CapEx review to get the number down from where it was. One was different tenders, tenders went out, a bit more competition, change in the scope. So there's a little bit of scope reduction and then some integration savings. So even the use of Papua using the FSO for PNG LNG, that is $0.5 billion savings right there. So the joint venture is working together to make this work. So we're really confident by year-end, Papua will actually be FIDed.

The other thing on Papua as well is that not only are we part of the gas production, but as a 39.9% owner of PNG LNG, where there is an access fee and ongoing tolling. So there's quite a bit of value in that as well as OpEx sharing on the shared infrastructure at PNG LNG. So it's not only just production, we're actually getting quite a lot of benefits from that.

And look, what I would like to talk about as well as some of the oil and one of the ones that we wanted to talk about today was Mosa. But first off, we've got an infill drilling program coming up. These things are very, very high IRR. Small volumes, but ultimately, 2 of these 4 wells will actually be required for gas production in the future. So we're just advancing, accelerating a bit of CapEx to take advantage of getting the oil out before they converted to gas wells. At the end of that campaign, we're going to look at Mosa. So Mosa is something that has only just been brought up, you might say, why didn't we discover it 30 years ago. What we actually had used in the last year is a technique, LiDAR. I think it's used in Teslas. But it's basically laser beams that you send out and you receive the ability for this advanced laser has been able to get underneath the canopy of the rain forest. And in PNG, the connection between the subsurface and the topographical map is very important for PNG geology. The maps that they've been using, the topographical maps they've been using, basically, were not correct. So what we've found is a very similar reservoir to the foundational reservoirs. In fact, it was the same way Hides was found. The connection between topographical maps and subsurface maps was actually how Hide was originally discovered. So using this advanced LiDAR that, can get underneath the rainforest canopy and integrating that with our subsurface model, Mosa has come up. So 3 kilometers from the existing CPF facility. We have a lot of [indiscernible] here, so this is the KMT out here, but this oil export pipeline in the '90s, this was producing a lot of oil. So there's no additional cost for us to be able to use that capacity there. It's a couple of wells and a pipeline back to CPF. So we're very excited. Large-scale. It's in the same PDL. There's no permitting, there's no fiscal agreements to work out. There's no infrastructure to build, a very quick tieback to the CPF and we're hoping to give you a bit more information on that in the coming months. But for us, we're going to do that well next year, and that's going to be a great addition to our oil business.

And before I get Bruce to come up, I just did want to go back through a couple of things. So reiterating what Kevin said. So from our base business, we are going to be very, very -- we're going to focus on areas where our higher-margin barrels are. So it's about focus. And that's going to allow us to explore and continue to put money into our Tier 1 assets, which is where we're going to get the most value. The number of Tier 1 assets we have is a problem. It's a good problem to have. And I think that's going to be a unique thing for most oil and gas companies to decide where to spend which Tier 1 asset they want to spend their money on. But to be honest, that is a fantastic problem to have.

So without further ado, I welcome Bruce up. He's got some pretty good stuff as well, but we're going to have to fight it out, Bruce.

All right. Thanks for, Brett. Thanks very much. So cage match, huh? I don't know, I started out as a strong young Farm Boy, but I feel like an old man right now. I don't know if I could take you in a cage match. All right. Thanks very much, Brett. I'm Bruce Dingeman, and I lead Alaska business for Santos reporting to our CEO, Kevin. I'm going to jump straight into our Pikka Phase 1 status and ramp up to start with. We're laser-focused on it because as Phase 1 transitions from development to production, it will be the anchor asset that underpins our long-term growth. I'd like to point out this photo up here. This is actually the Nanushuk processing facility or NPF, for short. This is some time ago before all the modules were placed and things were hooked up. On my next slide, I'll show you what the current state looks like. But this is a key piece of kit for the project. That's where the magic happens with the crude oil processing. After I cover the Phase I update, I'll pivot to the long-term growth story, and it's really quite compelling as others have talked about leading up to this point. It really underpins the key set of opportunities that support Alaska is a core growth pillar in Santos portfolio.

So with that, here's the photo that looks a little bit more recent from that same processing facility. You can see we used a modularized and truckable approach, and all these facilities stitch together allow for extensive crude processing ready for oil shipment. So you'll also know that last week, we announced a first intermittent oil through our custody transfer meter having been achieved. It's a huge milestone for the team. And also for me, personally, it's a culmination of 8 years of work for me. In the first week of June, we'll proceed to continuous production instead of intermittent, which is another milestone and then in the remainder of June, we'll bring on our gas compression and produced water subsystems. That will allow us to hold at 20,000 barrels a day as we bring on our seawater treatment plant and water injection at which point, we'll then ramp to 80,000 a day in the third quarter time frame. So the key drivers behind that plateau attainment are both the water injection and the well inventory build that will drive that plateau attainment. So you can see on the text, I think I've covered most of those points there about the ramp-up in plateau.

Moving to the next slide. These are some of the attributes for Phase 1. And really, the key point I'd like to make is that Phase 1 is foundational for the business in Alaska. It's the basis from which our future growth will proceed it establishes a long-life, high-margin production base. And while Phase 1 develops 400 million barrels of 2P gross by itself, there are an additional 600 million barrels of currently booked 2C resource attributed to Pikka. So when that will be developed through subsequent activities, that gives rise to a total resource volume of 1 billion barrels recognized for Pikka. So this 1 billion-barrel gross field potential is on a 2C, 2P basis. There's further prospective resource upside beyond that 1 billion barrels. So that's what I mean when I say it's a foundational part of our business that we can grow from.

Some of the key attributes from Phase 1 are shown here as well. I've already mentioned the 80,000 barrel a day gross plateau rate thinking on a Santos net after royalty basis. Our volumes will be about 12 million barrels per annum, which is roughly about 29 billion barrels gross per annum when we're on plateau. The 2P volume that now will be moving into production phase is that 400 million-barrel gross, which on a net after royalty basis is 164 million barrels. And then Mark talked earlier about resource life, and I think he showed it on a 1P basis when comparing to others on our 2P basis, it's a 14-year reserve life. So that's a long-lived asset.

Also, not on the slide, I would like to point out that there is a point there about under the $8 a barrel production cost that's -- there's a sub point about the tax royalty and fiscal stability. The key point there though is that we have durable margins because our tax royalty structure is fixed and the fiscal regime is compelling. Together, all these things give us a full cycle internal rate of return from FID, the full cycle for the project that's in the high teens, which were a foundational entry where you have to build all this infrastructure is really quite amazing.

The last point speaks to our Scope 1 and Scope 2 net equity share of emissions being net 0. And how did we get there is really through electrified operations, and those are low carbon intensity. And the other part of it is, so that's low by nature, our emissions. The other part is that we realized offsets by partnering with Alaska Native Corporations to offset the remaining emissions share. The first oil and gas project in Alaska to have these kind of attributes being net 0.

So moving to the next slide. There's a lot to look at here, but just to give you a sense, this is a picture of the North Slope of Alaska and it runs about 600 kilometers from west to east. So really a pretty extensive area. This represents the North Slope Basin. The Santos leasehold is highlighted in light blue and I'd like to call your attention to what we call our core area that's Pikka, Quokka and Horseshoe. We'll dig into that in a bit more detail. We also have significant lease holding with Apache out in [indiscernible] where some discoveries have been previously announced and then a large lease holding with Armstrong and MPRA called Nanushuk West.

So there's a couple of key things I'd like to point out. It says here at the heart of the Nanushuk [ play ], but Santos is really a -- enjoys a first-mover advantage in this new generation play. It's now central to North Slope resurgence. So this is a mature basin that has a new generation play that has now come to the fore. And part of that is you might have noticed that there was a large lease sale recently in the National Petroleum Reserve and had significant activity were over $0.25 billion was exposed and acquiring leases. And you can see the company names highlighted on the map here of different owner companies, and I'll make a shout out in terms of Shell and Exxon, both as either reentrance or new entrants to Alaska in that lease round. This is really a validation of the play. So it's evolved from being a, what I'd call a emerging play into a play under development that now is understood and being pursued by multiple companies.

So why is that? If you look at the geology, the coast line here is with the Beaufort sea. And there's a basement uplift that runs parallel to that coastline called that basement really results in a regional culmination. And then there's 3 world-class source rocks that are in this basin, the HRG, the King Act and the Koublik Shale those provided the charge that filled this basin with hydrocarbons. You have the world's -- or the North America's largest conventional field with [indiscernible] Bay sourced from those rocks. Well, there's a [indiscernible] high in our core area that allows a focal point for that. And that's why these Nanushuk sands are so well charged. And that's what all these new entrants are chasing. So it's really a good ZIP code, a postal code with significant industry activity and material derisking through time. The potential rate stack in the upper right-hand corner will go into a bit more as I dig into the other slides, but that bottom blue wedge is Phase 1, and that's our 80,000 barrel a day plateau. You can see the subsequent increments across different resource classes, giving rise up to a 3x multiple of that 80,000 barrel a day gross production.

So with that, I'd like to zoom into the core area here. I talked about how in Pikka Phase 1, establishing cash flow and production with its billion barrel resource potential. If you look at the Quokka field and the Horseshoe field, they each have similar resource potential as Pikka. The core infrastructure is already in place, and that helps lower future development cost. And really, the way we think about it is two separate areas. This northern area that's where our Pikka Phase 1 project is. That's where we have our processing facility. We have fuel gas supply import. We've got existing roads and infrastructure. we see very much a satellite development approach that leverages that infrastructure, yielding high returns at a fairly quick pace. Our southern area is really geologically interesting, where we do have some exploration success, for example, in our Stirrup-1 well as well as a previous Horseshoe well. However, it's farther away, it's outside 3-phase flow limits to tie back and it's a bit less infrastructure here. So this area would require a new hub for development but provide so much significant long-term running room for the company.

Before moving off this slide, I'd also like to highlight a couple of things about our offset operator activity. So in this area, where Pikka is just to our west, Conoco is actively developing the Narwhal project adjacent to Pikka. Over here where Quokka is to the north, Conoco is currently -- got production and continuing to develop the Coyote field north of here. And then over at Horseshoe, there's active activity in what they call the [indiscernible] area that Conoco is pursuing further appraisal work that's a continuation of this trend. So that nearby offset operator activity is further validation of how we've derisk this area.

So we already talked about the base of Pikka, the Phase I activity are planned to get to ramp up in 3Q to 80,000 a day. I want to shift about now to 3 vignettes and then I'll wrap up on for each of those fields. And that Pikka, there's a series of growth wedges. So the graph here on the right are just in the Pikka area what we see as incremental or accretive opportunities. So there's a clear pathway to expansion with the stage development at Pikka Phase 1. The second drill site, NDC is ready for decisioning later this year, and the facility expansion, as Kevin mentioned, would be an FID event for the following year. The important point about Pikka is that all the major key permits are already in place. So these can be moved at pace. Also, the growth is very capital efficient because these incremental development wedges leverage that existing infrastructure. Further, I haven't touched on our drilling program, but we're actively progressing through our learning curve. So our drilling times have gone from 50 days to 40, now down to about 30 days per well. So we're seeing this continuing improvement in efficiency and drilling that not only lowers our unit cost but unlocks additional potential because it can be done so at lower cost. And then our facility expansion and integration with nearby resources are under evaluation, and there's these backfill and extension opportunities we see these growth opportunities as being well over 20% rate of return type projects but sizable as well. So that's an update on the growth opportunities at Pikka.

The next vignette is on Quokka. And you will have noted that we drilled this [indiscernible] well in 2020. That was the discovery well of what we call the Nanushuk Zero [indiscernible]. That's the well to the Northeast here. Just recently, we announced the Quokka-1 well results, and that's the one where Kevin handed out the oil sample on. So that's 10-kilometer distance, and we have directly correlatable sands between the two wells and supported by seismic data. So we feel that this northern area of Quokka separated by this point here is fully appraised and ready for permit advancement. And that's what we're well in progress on advancing the permitting pathway. Moreover, we think that the permit for that will be what's known as an EA rather than a full environmental impact statement, which will allow for a quick permit cycle time.

I think I've already talked about the well results. I guess we did with the oil samples about how good the flow was and why that was the high-quality reservoir, the light oil, all those things conspire to strong well results. The thing that hadn't been mentioned is that these wells will actually be simpler than the wells at Pikka because at Pikka, we're drilling out under the Colville River, and those represent large extended reach drilling targets. We've had wells up to 27,000, 28,000 foot departures. At Quokka, the surface geology is much more forgiving so the well departures will be shorter, which will also lower cost. So overall, we see returns at or above Pikka levels for -- Pikka Phase 1 levels for this set of opportunities. And the Southern Quokka area represents additional upside that could be developed either tied back to the north or potentially tied back to a new processing hub with Horseshoe. So really thrilled about the Quokka discovery.

But before I move off it, I would point out the reference that we had 177 million barrels of net 2C resource booked for this opportunity prior to drilling the appraisal well. The appraisal well obviously confirm that number, it makes us more confident in it. But that equates to $450 million gross, but that's just for that northern area. So we're knocking on 0.5 billion barrels just in the northern area. So again, that supports the notion that this could be a billion barrel field similar to Pikka.

So my last slide is about Horseshoe. And you can see here the map where we had the [ strip one ] well drilled. That well was drilled in 2020 and. It had the highest single-stage flow rate of any of the 20-odd wells -- appraisal wells -- exploration appraisal wells we've drilled in the area. It's like 3,500 barrels a day. So it's an area we're really excited about. We have approval with both internally and with our partner to drill the Stirrup 2 well this coming winter season. It's a significant offset from Stirrup 1, and that will begin the journey of appraisal and delineation for this feature. But you can see based on its aerial extent that we've mapped, it has significant volumetric potential, a bit longer dated, a bit different risk profile, but compelling very much so.

So to wrap up, there's a text box at the bottom of this slide, and there's a lot of words there, but I really kind of simplify it to that we're unlocking Pikka 1 billion barrel scale potential at Kaka and Horseshoe in a very disciplined way. And it's -- the timing can be adjusted to comply with our corporate financial guidelines. So this is a really deep portfolio. It's got significant running room but it has huge optionality in terms of the pace at which we want to execute it. That means we can responsibly deliver not only reinvestment but also cash flow back to the corporation to meet the dividend and debt paydown and other requirements. So it's part of the plan that Kevin outlined earlier.

So with that, I'll turn it over to Alan Stewart Grant, who will talk about our Midstream and Energy Solutions, and he might fight by proxy for me, I guess, in the cage match if needed.

Good morning, everyone. I'm Alan, the EVP for Midstream and Energy Solutions. So our Midstream and Energy Solutions business is an infrastructure platform, and it exists to unlock value for Santos by getting the lowest cost barrels to market. We really have 2 levers, cost and reliability. And as I'll talk to you in a moment, we have a bunch of development opportunities that come from using the low cost and the capital that we're going to develop from that. The accountability that my team has really spans across all of the gas and liquids and LNG plants in Australia from a midstream perspective.

So that's Moomba and Portman Ithan, including the CCS project in the East. On the West Coast, Banus Island and Devil Creek, linking back to our CCS option there as well. We have a large pipeline portfolio, almost 3,000 kilometers that brings deep expertise in running assets like those, which will become valuable in the years to come. And then on the LNG side, we have the Darwin LNG project, which links into Baayundan CCS and our group also provides engineering and maintenance services to the downstream operations of Gladstone LNG.

The way to think about the business is that it's contracted cash flows. So we generate a lot of cash, and that's actually quite predictable. We don't have any oil and gas price exposure, and that's quite an important point as we think about some of the development options we have. There's quite a bit of spare capacity in the portfolio today. So there's a lot of backfill options that we'll need to make decisions on. And the way I talk to the team about how we're going to win is because we think in cents per barrel rather than dollars per barrel. So really trying to get every last cents out of there. We bought these assets under a single umbrella in recent times. And the logic for that was really so that we could deploy the disciplined low-cost operating model and eke out as much cost benefit as we can. And ultimately, we'll be judged on the barrels that we can get to market as a result of that.

The business unit actually has a very good proven track record in delivering across both cost and reliability. And you can see in 2025, we're actually pretty close to 100% in terms of reliability across the gas and liquids and the LNG assets. Moomba CCS is improving. We're not quite at 100% for that yet, but we're up in that mid- to high 90s, which is a good place to be. But we can always squeeze more value out of this. Last year, we brought the unit operating cost down by about 15%. And that, as Kevin has outlined, always wanting to beat inflation, and that's the benchmark against which we are tested. The way we do that is by getting really good at campaign maintenance and shutdown planning, excellence in both the planning and the excellence in shutdowns. And I'll use a couple of examples to try and bring that to life from last year.

We did the longest shutdown in Varanus Island's history last year. That was done at better economics and around 18% shorter duration than was planned. And if you add up all of the benefits of that improvement since 2022, it equates to over 6 million barrels of additional production through the upstream. Similarly, at Darwin, where we just completed the Darwin life extension project and the pipeline duplication project the former of which was done around USD 200 million cheaper than the prior owners concept study showed back in 2020. And now we're processing all of the Barossa gas under a tolling arrangement there. Really exciting that we're able to use that tolling arrangement to put in place a really neat project financing, which will become very valuable as we look to develop more in Darwin and at Bayu-Undan.

So this strong performance, coupled with an increase in diversification of revenue that we're getting from ACCUs being generated from the CCS project means that we can improve our margins and deliver that to the bottom line. What I hope for the next few years or intend for the next few years is actually just much more of the same. We're going to be applying this ethos to the expanded portfolio. And Steve will talk in a minute to some of the technologies that we're partnering on to make sure that these assets hit their full potential. From a portfolio perspective, across Australia and Tmour, there's a lot of exciting optionality within the portfolio.

So we've got across 3 different buckets, upstream development adjacencies, CCS to decarbonize at scale and then ultimately low carbon fuels and power. We've got a lot of options and really heaps of backfill. I mean you've heard from Brett, whether it's across the Cooper Basin through the MCO project or the Beetaloo where there's going to need to be a pipeline or indeed potentially pipelines, plus an additional train at Darwin over time. All of that is going to require development.

And Bruce, I'll challenge you in that case fight, if you wish. What I would say, however, is that this business is subject to the same hurdles and the same capital allocation framework as the rest of the business. So wherever we can use third-party financing or other funding techniques like we've done at Darwin, that's something we'll definitely explore. The way I tend to think about the business is what's good for upstream is good for midstream. That's where the additional flows are going to come.

So this is very much a sort of complementary or support arrangement that we have in place. And over the next few slides, I'll show you some of the CCS opportunities that we're going to be developing again for upstream. So I think everyone is aware of how the energy transition has evolved over the last couple of years. That's something we've watched very closely and being very realistic about what we should invest in and what we should dodge. We are very committed to carbon management services. If we think about the Moomba CCS project in particular, that project is performing to plan. It's been mentioned, we've now sequestered over 2 million tonnes of CO2. And amazingly, that accounted for over 1/3 of the total safeguard mechanism reductions in Australia last year. So a huge contribution. And what that allowed us to do is get issued by the clean energy regulator, 1.2 million tonnes worth of ACCUs. So that's new and additional revenue and diversification that's coming through.

When we think about what's next for Moomba CCS, we'll be super targeted. In the near term, you've heard from Brett, we're going to be getting some CO2 from the Bloop, probably equates up to around 1 million tonnes. So not huge given its low CO2 production. But when -- given the size, it is actually still a reasonable amount that will help with backfill and over time expansion. When we've had these discussions in the past, we've talked quite a lot about third-party CO2 as well. That's something we're still focused on for sure. But the way I'd encourage you to think about Moomba CCS is that it's set up, it's established, it's ready. And over time, as the transportation of CO2, both domestically and internationally proliferates, we are ready to go.

Bayu-Undan is the next cab off the rank from a CCS perspective, and we intend to develop a 10 million tonne per annum hub there in Timor West. And it's one of those assets that is so well placed because it can cater not only to domestic volumes, adjacent offshore volumes, but also Asian volumes in time. To take you a little bit through the time line of what's happened at Bayu-Undan in the middle of 2025, we ceased production at the upstream field, and that precipitated the suspension of operations phase, which we're well progressed on now. What that phase really does is develop the asset and get it ready for transition into a CCS project. But critically, it also allows us to defer the big decom liabilities that we have, which obviously has a value there as well. So this is a large scalable CCS project. And very importantly, it's brownfield.

There are other CCS projects that look can be developed in the region. They're greenfield and almost by definition, they're going to be higher costs. And the first thing that we'll be doing is having Barossa as the anchor CO2 tenant for this project. So we will be able to give that 2.3 million tonnes a year of CO2 that Barossa has a home and give it a low-cost physical hedge against the safeguard mechanism.

We completed all of the FEED engineering studies during the course of last year. And now the sole focus really is on getting the approvals, the fiscal and regulatory arrangements in place with the Timares and also the G2G arrangements that we need with the Australian government. We're getting pleasingly very, very good engagement from the Timores government right up to the Minister of Energy there, and he's personally engaged on this and sometimes it feels like Dilly is my second home. But we are making very good progress there.

My final slide, I'll just talk a little bit about geothermal and what we're doing in the Cooper Basin, which is super exciting. I mean, Kevin alluded to it earlier. For those of you who are not aware, the Cooper Basin is a world-class hot resource. It's a basin that we understand extremely well given the decades of experience that we've had there. And what we're looking to do is develop a pilot close to Moomba so that we can look and try and displace fuel gas, get that sold as sales gas and then have a new lower-cost form of power to run the plant there.

In doing, we're going to use what's called enhanced geothermal systems, EGS. This is a technique that uses fractured stimulation to inject liquids into hot dry rock and then generate steam, which can then be used at surface to generate power. This is being used pretty widely in the United States at the moment. So what we're trying to do is use some of the capability and Brett's team for oil and gas drilling and applying that to decarbonization whilst learning from what's going on in the United States. And if you've read anything about it, the AI data centers are really trying to use geothermal as a low-cost baseload power for their data centers. And there's a couple of companies out there who are using this technique that we're looking to replicate.

So the first thing that we'll be doing, we'll drill a vertical appraisal well in the back end of this year. And what we'll be doing is using that initially to test the temperature. We're targeting about 200 degrees C or more. But we're pretty confident we'll get that because there's already been about 45 wells over the last years that have intersected those sort of temperatures. But what we can do is use the data from that appraisal well to then plan what comes next, which will be a multi-well campaign and ultimately bring down the cost.

So the way I'd sort of encourage you to think about this is if we get the initial pilot plant up and running close to Moomba, it'd probably be 1 or 2-megawatt power station, which is about 5% to 10% of Moomba's load today. But we've got a vision that we can get that over time to more like 20 megawatts of power. And if we can do that, that starts to take out close to 100,000 tonnes of CO2 from Moomba. So that's real change. So if we can use this to demonstrate geothermal as a viable alternative, that goes to what Kevin was saying earlier about how we're thinking just carefully around that third horizon of our strategy. And before I hand over to Steve, just maybe a few comments in closing.

So we've got within Midstream and Energy Solutions, a fantastic irreplaceable set of energy infrastructure across Australia and Tim. We're focused on bringing down costs, increasing and maintaining reliability so we get better margins whilst decarbonizing as well. And then ultimately, this will mean lower cost barrels to market and unlocking value for Santos. Thank you.

Good morning. My name is Steve Trench. I'm the EVP of Operations and Technical Services. You just heard about all the great assets and the high-quality growth opportunities that we have in front of us. I'm here to talk to you a little bit about how we're going to get this done. And not only that, why I have the confidence that we're going to continue to outperform well into the long term. We will build off our proven high-performance, low-cost operating culture. We will transform our infrastructure returns and our personnel efficiency through technology and AI, and we'll connect some of the best capabilities across the company and the globe with world-class technologies in a centralized global operating hub to help us connect these capabilities and perform at scale.

Now we've got a strong track record of delivery, and I'm really proud of the people and the culture that sit behind this. You've seen this track record of delivery through some of the financials that Kevin and Lachie showed a little bit earlier. The team have been able to deliver a world-class safety culture, delivering record personal and process safety results. Now why does that matter? Well, not only is it important for the safety of our people, but this is a demonstration of a disciplined operating culture that focuses on sustainability, compliance and manages risk, which means it's managing your returns.

We've also delivered world-class reliability across our assets. If you take a look since the start of our reliability improvement program several years ago, we've been able to deliver up to around 7 million barrels of oil equivalent additional production from our Varanus Island and our PNG assets through the application of these techniques. And importantly, to our strategy going forward, in particular, the operation of LNG assets and the growth of our LNG business, as you heard from the folks before me, we've sustained 99% production reliability across those assets.

Now we don't focus on these metrics just for the charts. They lower production costs. The increase production, which, therefore, results in improved margins. Both sides of the equation, it all matters. And I share this stuff with you because I want you to leave here today knowing that this sort of a performance culture and this focus on continuously chasing the margins and continuously chasing the barrels is in our DNA. And I'm confident that we'll continue to outperform as we bring these Tier 1 growth assets into the portfolio and wherever the capital gets allocated across the various asset managers.

Technology is going to play an important role in improving return on capital and in lowering production costs, particularly so because our strategy is leveraging the use of existing infrastructure. Now we're not only just talking about technology like many others out there are doing, we are actually implementing it all the way through our integrated value chain. And I wanted to just share a few examples of how we're doing that at the moment but this is only the start of what's to come.

For example, we're seeing the potential of greater than $60 million of annual production benefit through the application of AI-driven oilfield technologies. We've already seen $18 million in annual benefit as we built out these models and as the AI starts to take hold, and we can see the running room to scale out to this magnitude. Classic example of this would be in our Cooper Basin, where we're shifting from a reactive response type operating model through the use of this capability to an autonomous, continuously monitored operating model. And what does that mean? Well, take 400 gas wells, we've seen 3x the production enhancement opportunities through the application of this technology, essentially free barrels, something that it would have taken months, if not years, for the humans to be able to identify those opportunities.

Another example is $70 million worth of CapEx out as a result of machine learning-assisted bottom hole pressure modeling across some of our onshore assets. Through building out this sophisticated model overlaid with machine learning capability and AI response, it's enabled us to have the confidence to no longer need to install physical downhole gauges in hundreds of wells going forward. So what? Well, that reduces CapEx up to this level, but it also reduces operational complexity and improves response time. So another great example of that technology in play.

We're also lowering drilling costs, an example that we've seen recently here in Australia through the application of an auto drill AI-assisted technology that connects the drill string to our integrated remote operating center in Brisbane, which I'll talk to you a little bit more shortly, has enabled the harnessing of thousands and thousands of data points of geological data points, drilling parameters from our years of drilling capability and sending predictable signals to the drill stream to essentially continue to operate in the zone, taking out all of the human variability and human error that comes with our operations. It's a fantastic outcome.

When we go abroad into our U.S. operations through the application of technologies that are being used extensively across the U.S. in the Marcellus, the Eagle Ford, but also in the Montney and here in Australia, we've been able to increase our lateral drilling length by 130% in Alaska. We've had a 50% reduction in the time to drill to 10,000 feet. We've actually drilled an 11,000-foot long lateral. And in fact, we've just drilled our third combo well.

What does that all mean? Well, essentially, the money section is the horizontal section. That's where it's fracked. That's the productivity section. We're now able through these technologies and this capability to essentially be able to combine 2 wells into 1 through the extended reach capability of the team.

Now when you look at the running room that Bruce talked about before in Alaska, avoiding the need to install all of that surface wellbore infrastructure and surface infrastructure across a number of those developments, that's significant capital out. And it's one thing lowering the drilling costs, but you need to improve the quality of the wellbores and the productivity of the wellbores that come with it, and we're doing just that. More recently, we've seen an 80% increase in frac installation productivity in our U.S. operations. What does that mean? Well, we're basically pumping more proppant faster, which essentially for the same unit cost is resulting in greater productivity in our wellbores.

More locally, we're seeing reductions in pumping time in the frac operations that we've got through a world-first application of Halliburton's Optiv technology outside of U.S. shales into conventional reservoirs, allowing us to automatically feed instructions to the frac units out in the field, improving the quality, reducing the chance of screen out and improving our well productivity across a number of our fracked wells. More recently as well, we've seen the use of AI technology to remove people from the field. A great example of this, and sorry to any of the geologists in the room would be the use of this AI lithological capture system, which essentially is using photographs and video technology to scan cuttings, send the information back in through the model, have it verified onshore in our operating center, removing the need for geologists in the field. That's only the start of this sort of technology and how it can be applied across the hundreds of operations that we run across the globe.

So I share these things with you because they are going to be critical enablers in driving the cost down and the performance up across our Tier 1 growth assets. The Beetaloo Basin, we've already got this U.S. shale technology in play. We have U.S. shale capability within the business, and we're going to connect that up and apply it to continuously perform and drive the cost out on these future opportunities.

Now it was mentioned before that I would talk a little bit about decommissioning, and I think it's really important that we do. Decommissioning costs and lowering our decommissioning cost is an absolute priority for us. And our application of technology doesn't just stop at the identification, the extraction and the production of our resources. It's actually being applied right across the value chain. We've just built a highly capable, dedicated decommissioning campaign team that will focus in a progressive manner, working across each of the key assets that are moving into the retirement phase, planning them, executing them, locking back in the learnings and delivering outstanding outcomes. And I'm really proud to be able to share a few examples of that with you today.

In the wealth space, in the Mter Exeter, Fincane and Fletcher project or asset, we set new benchmark performance levels in well decommissioning durations when we compare to global activities of a similar nature. Why is that important? Well, it lowers the cost of executing that work. For our Ningaloo Vision FPSO, we set new benchmarks from the time that the operations were suspended, aka when it stopped delivering returns to the point in time when that asset is off the books. Offshore operations are high-risk, high-cost activities, so shortening that time and pivoting to the next stage is of crucial importance to us.

Finally, and the one that we're most proud of is the Harrod Alpha platform removal. This is a classic example of that campaign team combined with the use of technologies and how it's delivered outstanding outcomes. This is Santos -- well I would say this was Santos' largest fixed platform and decommissioning activity, and it's behind us. In fact, it was Australia's largest fixed platform to be removed offshore. And this was a classic example where through the application of technologies like submarine ROVs, removing divers from the line of fire, 3D models, drones, specialized cutting techniques, installation stage removal process from barges through to smaller vessels and larger vessels, we were able to deliver this activity well below cost and ahead of schedule.

I share these examples with you because I want you to have the confidence that not only are some of the largest decommissioning activities behind us, but that we will continue to liquidate this scope in a capitally efficient manner, and I'm feeling pretty confident that we'll deliver this well ahead of promise.

And finally, connecting up the best capabilities under a global remote operations center, designed to scale the performance and capabilities that you've seen to leverage the economies of scale and apply that across our global operations, whether that be in advisory, surveillance, support or control, the operating model is open as we choose. How are we going to do it? Well, extending off some of the experiences we've had with remote operations in our upstream operations, we'll extend that out across upstream and into our midstream portfolio. We'll also build out our pilot integrated remote operating center that we're applying in the drilling and completions arena. And we'll create a centralized, highly technologically capable hub in Brisbane that will be the brain and the operating center, and it will provide support out to the operating sites across the globe.

And why would we do this? Well, firstly, it lowers cost. Not only is it going to reduce overheads and bring people out of the field and surround them with like-minded capability and technology. But let's take, for example, the opportunities that Alan just talked about, like I talked about with the decommissioning side, our drilling and completions experience, when you bring people together in a campaign fashion like in our maintenance and turnaround capability, you have the opportunity for the best in the business to plan, to scope optimize, to coordinate large-scale contractor workforces to travel around our Australian sites and execute these large-scale turnarounds.

That lowers the cost of those activities, and it improves the productivity and the production from those assets because the duration is continually coming down. That is direct bottom line benefit that we can see coming from these sorts of activities. We'll see the same in the drilling space as we enhance and reduce the overheads, we improve the drilling performance and lower the cost. We expect that it's going to improve reliability. By having a centralized capability that provides surveillance, advisory and support across our operating assets, we expect to avoid trips to improve uptime and throughput, which is ultimately going to improve returns.

We also expect to identify a number of debottlenecking opportunities. And one I'm most excited about when I look at the Barossa to DLNG value chain with my experience in running large-scale integrated LNG assets, I believe that there's quite some potential in that particular asset base. And finally, the magic in all this is that it scales with growth. As we bring in these Tier 1 assets, this centralized operating center can expand in a pod-like manner out and supporting the operations to continue to bring that capability to bear.

So in closing, as you can see, I'm pretty proud of the results and the culture that we have in Santos because our operating performance matters to our strategy and to your returns. And I want you to leave here with the confidence that we will continue to deliver this performance throughout our base business, and we'll extend these capabilities into those Tier 1 growth assets you heard about before. Thank you.

Thank you, Steve. Now look, I realize we've filled the time. We're still going to have some Q&A if you've got the patience to stay with us. So maybe if I could get 4 chairs put up here, we'll just get that doing as I'm wrapping up.

Look, you've heard from the management team. I've said it many, many times. I think I'm often blown away when I look inside the organization at the depth and the depth of talent and capability we have, and I still put this management team up with any management team across our sector in this region as the best in the business. I truly believe that. And you can see some of the great work that they're delivering today.

Today has been about communicating to you our focus on our Tier 1 assets in order to grow our free cash flow and deliver consistent, strong shareholder returns through the cycle and for decades to come. You've heard from a lot of the team today -- and in summary, some of the key takeaways. You heard from Brett and from Bruce about the status on Barossa and Pikka that they're ramping up now or close to ramping up in Pikka. And in Q3, we'll have both those assets. We expect both those assets at plateau production, and that's the start of that cash flow inflection point.

Lachie talked about the capital allocation framework and took you through how the $45 to $50 free cash flow all-in free cash flow breakeven works in controlling and providing discipline into the business and works alongside the disciplined operating model. And that cash flow inflection point, how we talked about every $10, the actual oil price is above that $45 to $50 breakeven will generate between USD 550 million to USD 600 million in free cash flow each year from that portfolio going forward.

We also talked about the net debt reduction target, $2.5 billion between now and 2030, again, driving value, bringing discipline into the business and freeing up around USD 150 million per year in interest payments because of that lower net debt position. We gave you feedback from the strategic review and showed you the 4 chunks of assets and what that means and particularly in the Cooper Basin, we're focusing going forward or prioritizing, I should say, our capital investment in the Cooper Basin into that central area where the majority of our resource across the Cooper, our future resource, undeveloped resource exists, taking out $300 million in CapEx between now and 2030 and $150 million a year thereafter into the future.

And then you heard from Alan and Steve how we're leveraging our midstream position and our application of technology, fast application of fast developing technologies through simplification, infrastructure optimization and the energy solutions capability to drive emissions down to drive value, create new value from those assets. And the day, as I say, has been around or about the focus on those Tier 1 basins across 3 regions to drive the future growth and prosperity for Santos and particularly focused on developing those Tier 1 basins in Alaska and PNG, but also fully appraising the Bet2oo Basin that provides us the ability if we can make it work to backfill and expand our current Australian LNG capacity and very importantly, to test the Bedout Basin to see if we can create a fourth Tier 1 basin for the longer term. And the Bedout Basin stacks up economically, looks great. It's now about testing for scale and it provides energy security advantages for Australia in the region. And that's a wrap-up of the presentations you heard today.

What I would also add is that it brings us right back to our value proposition, which I think is as clearest as it's ever been. It's about focusing on that high-quality asset base to grow the free cash flow across the business and continually grow that going forward to provide strong shareholder returns whilst being able to sustainably invest in the growth of business over the longer term.

So that concludes the management team presentations this morning. I'm going to ask Brett, Bruce, Lachie and Alan to join me on the stage, and I'm happy to take any questions and throw it to them or anybody else. And feel free to ask anyone else who presented a question too. We can get a mic to them if you want. I'm going to ask that -- I know I'm running late, and apologies for that but there's a lot of content to get through. I didn't expect us to be a little bit quicker. You heard some really interesting things from the management team. I thought it was really interesting to see the videos with the foundation and all that sort of stuff at the break.

And I was telling you, we almost brought a tear to Scotsman's eye as we came back from the break. And it was just so refreshing to hear. Steve -- where is Steve? Steve referring to his workforce as the humans. I thought that was really warm and fuzzy as well as we got to the end of the presentation.

But look, happy to get. We've got some mics. We get some mics up here as well for the guys, you're all mic up, aren't you? One question at a time, please, and we'll come back to you if we run the questions. Who's first? All right. Go first.

Dale from Barrenjoey. Thanks, Kevin, for the presentation. Thanks. Pretty clear message around increasing free cash flow and growing returns to shareholders. As part of that on Slide 22, I think you've provided an outlook for those cash flows, which included CapEx of about $10 billion over the next 5 years. I was just hoping you could provide some color about that number, which is very similar to this year's guidance for CapEx. What's included there in terms of projects, what's included sustaining versus growth, decommissioning, et cetera?

Well, first of all, I'm going to hand that one to Lachie. I'm going to give you 30 seconds to think about your answer. What I would say is that in terms of what projects, I'd say it can be any combinations of different projects, right? So you can see there's a lot of optionality across that. So -- and I would always put it like this, that if things get difficult in Australia for a little while, like they did a few years ago, the great news is we can fast track some of that stuff in Alaska ahead of Australia. We can pivot. We've got the ability to pivot within that portfolio. I think Lachie talked about the fact that it would also depend on equity levels as well, which ones.

But Lachie, I'll hand it to you to elaborate.

Thanks, Kevin. Thanks, Dale, for the question. Look, that chart demonstrates where we'd be if we're around the midpoint of our guidance in that $45 to $50. So that gives you a pretty good feel for how full we could have the CapEx level. That $10 billion is around the right number. That number in terms of development CapEx is not fully defined in terms of the amount of projects that we will do. We're sort of saying that we've got capacity to spend up to that level whilst generating that free cash flow generation in that model. So that model, I think, is struck at around $47.50. What you'll probably find is the development CapEx or the growth CapEx, it may be higher or lower within that $10 billion range, and that also depend on where the operating base is.

Obviously, all the projects that we've got taken FID on and committed to are fully in those numbers. And then there's a wedge that we've taken up that we've got, obviously, the competition for capital, which will fill that void, Dale to the end, which is effectively the competition with the projects that the gentleman on my left have all presented on.

And Papua...

I should say, sorry, yes, Pap, we have assumed that Papua would go ahead and the Papua CapEx profile is within those numbers.

Adam Martin, E&P. I suppose a lot of focus on the Baloo today. Maybe we could just talk a bit about those 3 wells that are upcoming. You talked about sort of 3 different shales there that has got potential in the East. So what's the sort of -- I suppose, what are you trying to learn from those 3 wells? And then to get to that FID situation, particularly bigger project, like how many wells need to get done in that acreage do you think in the next few years?

Brett?

Thanks, Kevin. Thanks, Adam, for your question. So yes, look, as I had on the slide there, there's -- we have 3 shales. So the one that everyone is talking about is the B shale. So that's no-brainer. That's where we're planning to have 2 of the appraisal wells will actually intersect. And then we also want to appraise the A, which is the one below that. So higher pressure -- and for us, that is -- that's an opportunity for us to even get a lower cost development, right? So ultimately, the number of well pads you need because you've got stacked developments, it's got a huge advantage, not just from a resource size, but from a cost of development point of view.

What we're trying to do out of the appraisal campaign is not just prove the resource up, we actually want to prove the deliverability of the wells. So these will be drilled as if they were development wells as opposed to appraisal or trying to get subsurface status. Hence, the reason we're -- sorry, going to drill pretty much the same well length that we would in a development scenario, and we are planning to do 60 stages of fracking as if these were the development wells. And then we are looking at long-term well test.

So at least 9 months of well testing to get the type curves that we need to prove up 5 Tcf, which for us is 500 terajoules a day, which is a development size that we would need to evacuate that gas to the East Coast by Bowalera without having to build a pipeline from Bowalera to Wallumbilla and then Wallumbilla to Gladstone. So it's sort of back calculated on the minimum development size. You need scale. You need somewhere to put that gas. And then ultimately, that's driving what we're trying to do with the appraisal program, 5 Tcf, 500 TJs a day for 20 years, 3 wells that are drilled to -- as basically development wells to test the B and ultimately the A. Yes, and that's what we're trying to do with the program.

And of that $3.2 billion 2C number that Mark took you through earlier on, 1.3 Tcf, whatever that is in BOE, 1.3 Tcf is booked for the Beetaloo D. We're looking to add another 3.7 Tcf to that through this campaign. So that is not in the 3.2 billion 2C that we have. So it's a very significant add to that. And I think the other thing we should say is not in any of our forecast production numbers, but we intend to produce from these wells rather than flare the gas during the well testing, so produce to market. And so that will be sales gas once those wells come online.

And there has been 12 wells drilled there since we last drilled there as well. So obviously, we're learning a lot from the other operators up there who are targeting the B shale. So we're getting lots of information from that. Canberra is a joint venture in the EP161 as well. So we're using all the expertise and all the -- what they've learned as well to make sure we can do this as quickly and as efficiently as possible. We don't have the answers. We are a sponge, learning everything we can, not just from the local folks operating the B, but from the U.S. shale providers shale operators as well.

Sarah Kerr from Argonaut. Just touching on the reservation policy. I understand it's just under the draft mode at the moment. But what is Santos' strategy during the consultation period to the end of June? And where does that place GLNG if that 20% domestic commitment stands?

So the question is, tell me your strategy for engaging with the government. Yes, right. Look, we -- I've said it many times, I said it last week at the EEP conference. First of all, we are comforted by what every minister has said that existing contracts will be protected, and we're going to take them to the word. on that as we always have done for the last 10 years. So that in itself is comforting. As for the document that was released yesterday, I think it raises more questions than it gives answers. I mean it's -- when you read it, I don't know how many times it says that existing contracts will be protected. But then it has a lot of contradictory sort of statements of what could be interpreted as contradictory statements.

But I think you'll find even as recently as the last couple of months when the Prime Minister was going around meeting other governments, we were giving assurances. I heard Minister Bowen online on national television, I think it was saying that existing contracts will not be impacted and indeed that this would apply to uncontracted gas. Look, we'll engage with the government in good faith as we always have done. We'll continue to be a major contributor to the domestic market as we currently are. And I'm very confident that we'll be able to continue to export and meet our contractual commitments. Thank you for the question.

Tom?

Tom Allen, UBS. I guess just following your last answer, Kevin, in the context of a consistently uncertain policy environment in Australia for the sector, it's encouraging to see 2 big growth opportunities in Northern Australia around the Beetaloo and the Bedout Basin. Wondering if all of these growth projects and there's plenty in the portfolio are going to compete for capital amongst each other, your capital framework clearly isn't going to pursue all of them at once. They're going to be selectively brought forward. Could you talk to some of the post-tax asset returns that you think would support an investment decision for Dorado compared to a Betaloo or maybe some of the others? I think, Bruce, in your section, you made reference to some of those incremental developments in Alaska supporting over 20% IRRs. But to see where it's going.

Well, that's -- I mean, I'm not going to tell you what the hurdle rates are within Santos. What I can tell you though is...

It's a range.

It's competitive, though, right, between them. So the fact Bruce put his number out there, to me, that was the first step in the cage flight he's talking about these numbers out there. And Brett -- which I actually think was a bad tactic, Bruce, because Brett now knows what the number is, right? So what I can tell you, though, is that what we see in that portfolio is a lot of projects, the likes of which we've never been able to look at in years gone by with numbers around that level or better. In fact, if I look at the Pikka Phase 1 expansion, that's even higher, right? I mean that's mid- to high 20s, right? So we're now seeing IRRs on assets and project opportunities that historically, we just never had with the Cooper Basin, with CSG, these are tough assets to make money from, and it's a slog, and it's about constantly just doing it better and better year in, year out.

This is a different scale. We've built a company now that has the opportunity to go to a different scale. Now we've got to keep that disciplined operating model working across those assets that supply other benefits to the portfolio. But in this case, what we've got the opportunity now is to scale up and focus our major investment capital in those higher return assets. So I'd say that's not going to be an unusual level, particularly where we're leveraging off existing infrastructure, right?

I think the one you're probably thinking -- want to ask me about is Papua, maybe right. And Papua is really good, right? That's a very vague accurate number, right? Have I got enough equity in it? Look, I would like more equity in Papua, but I don't have more equity is what it is. But we do create value from the access fee, from the toll and from the shared OpEx. And that is very considerable value. So that adds about 2% IRR. Now this project screens without that for us. Papua screens without that for us quite easily, meets our investment hurdles. But we got about an extra 2% IRR because of those leveraged position because of our infrastructure position in PNG LNG, our foundation project.

But look, I mean, you're looking now at the competition between these guys for capital is across -- I think Brett said it, it's a good problem we have. We've got a lot of high-return projects. But we will deliver them within that free cash flow all-in breakeven of $45 million to $50 million. So that means you've got to deliver them in a disciplined way, ordering things, probably 2, 2.5 at a time that we could fit into the portfolio depending on equity levels.

Rob Koh from Morgan Stanley. Can I maybe just ask some infrastructure type questions around B2u development because there's other people with other plans Ichthys is talking about Train 3 and the like. Can you talk to the opportunity for shared infrastructure and lessons from Queensland and things like that?

Well, I'm going to let Brett answer that. Alan, you feel free to jump in as well. But what I would see is the development of the B2oo must not be, like we've done in other parts of Australia, where we build our own infrastructure and we don't get the leverage positions and sharing. And in fact, I was talking to the new CEO of Tamboran last week, and we were making that point. And so looking at put in place an operator's forum to get it right from day 1. So from day 1, let's start working on that master plan to get shared infrastructure so that everybody gets the benefit of lower development costs.

Brett, anything you want to add to that?

Yes. Look, and then the Northern Territory government is also very supportive of us getting together and make sure that investments that they want to make as well in that infrastructure is done in a combined way, right? So in the end, there's no value in us all creating our own hubs, our own airports, our own bases. Our third-party contractors that need to set bases up to supply to all of us as well are asking the same questions. So that cooperation is key. As Kevin said, there's a long list of projects in Australia where you haven't seen that cooperation. But I can assure you, we are working not just with the other operators, but the Northern Territory government is incredibly supportive.

You can see what they're doing with the pipeline easement and it's not just for that, it's for data, it's for gas, it's for water, whatever. They're getting heavily involved. So we've got a very supportive jurisdiction up there that wants us to cooperate. I believe we've got a good relationship. One of the other major players up there, Tamboran is actually one of our joint venture partners. Yes, we will do our best because it's in no one's interest to build 2 sets, 3 sets of infrastructure. This is going to be a hard slog. It is remote. You need scale and you need to be disciplined on your costs. And so we need to do all of those things. And all the other operators there, I haven't had one person say we shouldn't pool our activities. And there's a lot of sharing already up there. So I think yes is the answer.

And I'll add to that, we are talking to all the major pipeline operators in Australia aren't we Allen, including Alan.

Yes. Look, I mean, it goes without saying that we'll work through what the split between the upstream and the midstream spend will be between now and FID. There's a lot of water to go under the bridge yet. But we've got an inflation beating model. We've got the best acreage, as Brett said. So we're going to play an important role in determining how the infrastructure gets set up. And as I mentioned before, what we've done at Darwin in terms of using other financing and working with partners, all of that IP can be applied here.

And I think very importantly, our model must be one that we get the benefit of depreciation on the assets over time. And that's an absolute -- so whatever the infrastructure we're putting in place the -- we're talking about multi-decades of operations here. We will ensure whatever model we go with, we get the benefit of that infrastructure depreciating over time. We don't want that getting recapitalized and keeping our base OpEx costs high.

Nik?

Thanks, Kevin. It's Nick Burns here. Just had a question on your Pikka and Alaska more broadly. Thinking back over time, obviously, you've been on a bit of a journey with Alaska post Oil Search acquisition at the time you called Pikka noncore and look to sell out. You've kept it. You've really done the hard yards through that. You've copped a bit of criticism for holding on to your equity. Now you're at the point of start-up, you've got a 51% interest. I'm just interested in your -- first of all, what your key lessons are from holding on projects which got long-dated assets like this through that period. But also from here, you got a 51% stake. Are you keen to retain that stake in Alaska? Could you sell down maybe equity in Horseshoe, Kaka, et cetera? Are you getting a lot of interest in the asset given what's happening in the Middle East at the moment?

Well, look, great question. I met you at the start of the end, I said, if you have any questions from me, you said not yet. That's a cracker. That's a good one. I like that one. Look, let me start by saying, go back -- let's go back and repeat the history lesson there. And yes, we reluctantly took FID in 2022 at the current equity level. We -- our intent was to sell down. And you think what was the world like in 2022? It changed very quickly. ESG pressures, the banks wouldn't finance the North Slope. People were selling out. Shell left, others, Exxon had kind of backed out a little bit from the North Slope. -- and you just couldn't -- you couldn't give it away, quite frankly. And yet here we were with this really attractive asset, you couldn't get interest. And well, we did get interest, but not from the sort of parties that we're able to follow through, right, and close the deals.

Fast forward a couple of years, some of those companies have just made record bids to get leaseholds in this area, in the acreage around us to develop the same place, like record bids. I mean I could tell you the numbers that bid on some of these blocks, they are mind-blowing what they bid just to get a permit, right? So that's really exciting. And that testament to the work that Bruce and the team and ConocoPhillips have done developing these plays and bringing this to life. So now it's -- I saw an article the other day, I think it was Bill Armstrong -- and Bill will promote his own case, of course. But I think he wrote the other day that Alaska North Slope is now the hottest province in the world in the oil and gas world. And it probably is, and you're seeing that with everybody trying to get in.

So is there interest? Well, I can't say whether there is nobody has actually stopped me in the street and said I want to buy PC off you. Would I sell down or not? Probably not right now unless the value actually made sense. Certainly, it would be not at any discount. Is it core? You bet. now we've done the hard judge. You said it. Bruce just summarized there. Pikka is most likely a 1 billion barrel field. That's a 2P plus 2C position in Pikka, 1 billion barrel gross. And we've got 2 other prospects, Kaka and Horseshoe, that have the potential to be 1 billion barrel fields as well. That's game changing for a company our size. I mean that's like winning the lotto if you can make that the case. So you don't step out of that too easily or too readily. And when you start thinking of the diversity of that portfolio that we have today, now we've got PNG development friendly, Alaska development friendly. Australia, lots of good development opportunities, right, but still a bit to go on its transition, I would say, and working out what it wants to do with its vast oil and gas resources. We are here to develop the ones we've got if it gets to the right place. If not, we've got really good opportunities and options elsewhere.

And I think that's what I'd say. The reason I was a bit hesitant, I'm just holding Bruce's feet to the fire to see it producing, I think you said next week and seeing us ramping up to plateau. But look, really excited by what we have in Alaska. You heard from Mark today talking about the exciting prospect. Sometimes it's better to be lucky than good. I've always said, and I'll take lucky any day of the week in this business. And right now, I'm feeling pretty lucky that we've got Alaska in the portfolio. I hope that answered -- probably an 80% of what you asked, but if not at all, but thank you.

Tom from Citi. Just on the domestic strategic review, Kevin, you mentioned optimizing value of the Australian portfolio. In the event that we see continued success at Betaloo, further derisking of that asset, at what stage might we expect to see some further deprioritization of some of these non-Tier 1 basin assets? And then further, any proceeds that are generated from any future sell-downs or divestments, how might we balance those proceeds between reinvesting back into the business, shareholder returns and repairing the balance sheet?

Well, first of all, there's no need to repair the balance sheet. The balance sheet is good, it's strong. So you threw that out just to kind of formula. The balance sheet is good. It's strong. This is about making it stronger, right? And you saw Moody's rating change last week to positive. We're in a good place on the balance sheet. But this is about making us stronger and positioning us to be more opportunistic in the future should a good opportunity arise. So it's just -- to me, that's just good business. I don't know how you deprioritize more than deprioritize, further deprioritized. But our capital will go where it gets the best returns. I think what we've done is repurposed that Australian portfolio.

Now we're saying well, we're not going to spend money here. We're not going to spend money there. And what we are going to do is make that a business that helps us meet our domestic gas obligations, which is part of the question I was asked earlier on from a social license and ability to export, going to support our export business. and to fund the decommissioning obligations that we have so that that's not a draw on the growth hubs, the main hubs around our business. And so that frees up the cash flow from that business.

The capital we're taking out of the Cooper, I deliberately used the term earlier on was to recycle that capital to invest in higher return projects. And of course, we'll have the capital that comes from paying less interest on our debt if we're successful in achieving, which we will be successful in achieving that net debt reduction target. And based on that we free up more free cash flow from the portfolio and the capital allocation framework, as it points out, says that whatever that free cash flow is, a minimum of 60% of that will go back to shareholders.

And I want to keep reemphasizing that. That's a Board-approved policy. Chairman is in the room. So if you don't believe me, ask him at the break, but it's a Board approved policy, and we've made that point, 60% will be returned to shareholders. But what we're not seeing, and I think this is really important, we've been really clear about it. We're not going to starve the business of capital and go backwards after 5 years and fall off a cliff. We are going to reinvest in high-return projects. We're going to continue to grow the business, continue to make it a larger scale, higher return business over time.

Lachie, anything you want to add to that?

No. I mean, like any other use of proceeds that do come through that they're out of the model. It's a matter for the Board what we would do with those proceeds. The numbers that we present to you don't rely on any of those assumptions or scenarios in the model, we're at $75, and we think that we'll deliver the net debt reduction targets. If there are anything that comes along like that, then that is a matter for the Board at that time.

And I'm going to give you 10 for not using the phrase that you know I don't like in that question, which anyway, well done.

Rowan Bowwater from Excel Research. Thanks Kevin and the present today. My question concerns Barossa now producing and with offsets or ACUs bridging the period before Bayu-Undan CCS is developed. Could you help me understand what carbon cost is embedded in Barossa's economics, perhaps as it compares to Moomba's benchmark of $24 per tonne? And more specifically, how that impacts or factors into the free cash flow sensitivity that Lachlan covered at the top, given the contribution of Barossa there?

So I think Brett described Barossa as a world-class project today, and it shows you that production profile. I think from memory, I'm going to correct me if I'm wrong here, but I think the production costs or the cash production cost for Barossa, including the actual cost of carbon is still less than $3 per MMBtu, right? So it's still very low. And you put that in the context of the price we get for the LNG. What I can tell you is when we FID-ed that project, it's safe to say now, but back at the time we FID-ed that project in 2021, the LNG price assumption was under USD 7 per MMBtu. So just think with the LNG prices moved to in that 4-, 5-year window, right? So this is a really good, solid economic project.

The price we're paying for Akkus today. And I think we've got 4 or 5 years bank of those. So we're developing our own and obviously buying some of the market to position us as per the rules of the safeguard mechanism is less than the carbon price we put in the economics for the project at the point of FID, quite a considerable bit less. And you'll remember back in the days, everybody was assuming USD 40 or USD 50 by 2025 or 2030. Of course, we're not seeing those carbon prices, right? The carbon price for Akkus is still in the mid-30s, Aussie, right? So it's actually not a bad story at all. It's a pretty good story. The project economics are very, very strong in Barossa. We're getting a premium because that's even better spec LNG than PNG. It's right in the sweet spot of the spec for our customers in Northern Asia. So it's a very, very robust project.

Mark, do you want to ask a question? Just scratching your head. Just scratching all right. Any other questions before we wrap up? Well, look, again -- or Mark, do you want to ask one? Yes, go on. You're waiting for the last question.

Yes, last minute. Just in terms of FIDs, we think you'll be rewarded from these 2 growth projects ramping up and your CapEx structurally comes off, you're out of that last investment cycle. The message that I heard today was that Papua FID later this year and then that second drill pad at Pikka by the end of the year. So effectively 2 FIDs this year? I just want to clarify, is that...

Well, yes, I mean, the Pikka numbers are already in our budget for the year. But the pad -- I wouldn't call that an FID. It's sort of this, but it's really just building a decision to take a drilling pad, which we will approve in the second half of this year. And that actually gets some cost benefits from Phase 1 from putting that pad in, i.e., shorter wells, right? I think about 6 of the wells from Phase 1 will be drilled from that pad. Is that correct? Yes. So look, we'd expect to do that. And yes, Papua. Papua is the other one. And then I don't see any sizable FIDs. You'll see things like the CPF things in PNG and small projects like that. But there's nothing sizable really, I would say, for a couple of years. We've got to appraise the Bal. If you listen to what Brett said about the plan there, that takes you to sort of first half of '28 before you finished that program, the well testing, extended well testing.

And then anything we do in Bedout Basin, really, it's drilling those 3 appraisal wells in '27 and then the time to assess the results of those. So timing-wise, I'm feeling pretty good. And I think the good thing about Papua, Lachie, you talked about the financing today, but there's virtually no CapEx draw for 2.5 to 3 years from Papua because the project financing, what did you say up to 60%. That funds -- that's front-loading the financing of that project so -- or the funding of that project. So really, the -- from a CapEx point of view, we're in a really good place for the next 2 or 3 years. Thank you. So look, I'm going to wrap up for that.

What I would like you to do is if you could just please show your appreciation to the management team, put a lot of work in this presentation. I hope you found it useful and informative. And like I said on my last slide, the -- in my view, the value proposition to invest in Santos, to hold Santos and to buy more of Santos has never been stronger than it is today. It's about focusing on Tier 1 assets, growing free cash flow and driving stronger for longer shareholder returns.

So thank you very much. And again, thanks to all the management team for your help and the staff, thank you.

Well, good morning, ladies and gentlemen, and fellow shareholders. As Chair, it's my pleasure to welcome you to the 2026 Annual General Meeting of Santos Limited. My name is Keith Spence. It's great to see so many of you here at the Adelaide Convention Centre today. Our live webcast is also underway.

I begin by acknowledging that we're meeting on the traditional lands of the Kaurna people, and I pay my respects to their elders past and present. I also acknowledge the traditional owners and indigenous people everywhere we operate, and thank them for working with us.

I hope you enjoyed the opening video and are as proud as I am of the outstanding progress we've made over the year, progressing and commissioning our major Barossa and Pikka projects and continuing to build strength, efficiency and lasting resilience into our base business in addition to our continued success at Moomba CCS.

Kevin and I will talk more about the year that's been during the business of the meeting. And please note that the values referred to are U.S. dollars unless we otherwise state.

Before we commence the business of the meeting, please familiarize yourselves with the evacuation procedures shown on the screen above.

I confirm that a quorum is present and now formally declare the meeting open.

And let me commence our business for today with some introductions. Fellow members of the Santos Board here today include from my far left, Independent Nonexecutive Directors, John Lydon, Janine McArdle, Musje Werror, Vanessa Guthrie. And seated immediately to my left, our CEO and Managing Director, Kevin Gallagher. Next to me on my right is Amelia Senneck, our Company Secretary. And on Amelia's right, our Independent Nonexecutive Directors, Mike Utsler and Vickki McFadden. A number of our executives are also present at today's AGM.

On behalf of the Board and our executive management team, we look forward to catching up with you for some light refreshments once the meeting is concluded.

Also present are Richard Bembridge, Darren Lewsen and Fiona Hancock representing our independent auditor, Ernst & Young.

To allow everyone attending the meeting an opportunity to vote, I now open the polls for all resolutions set out in the Notice of Meeting. Shareholders and proxyholders can vote using their smartphone following the instructions on the registration card provided by Computershare, which are also shown on the screen above. Please make yourself known to a Computershare representative if you need any assistance with casting your votes. I invite you to start submitting your votes on your device from this point onwards during the meeting. You can vote on all the resolutions at any point during the meeting, and you don't need to wait until that relevant item of business, and votes can be changed up until the time the polls are closed.

To ensure there's sufficient time for all votes to be cast, the polls will be closed 10 minutes after the conclusion of today's meeting. As advised in the notice of meeting, I will vote or available undirected proxies in favor of all resolutions. I'll display the proxy voting outcomes for each item of business before moving to the next item.

The formal results of the polls will be notified to the ASX after the meeting and they'll be posted on Santos' website. You may have seen when you entered this morning that there's a question registration table. Many of you have already registered to ask questions for items of business today, and these will take precedent. For those who wish to ask a question today, but are yet to register, please proceed to the question desk located in the adjoining room. The desk will remain open during the meeting, and we welcome you to register to ask your questions at any time.

If you have registered to ask a question at the appropriate item of business, you'll be call to ask your question. If time permits, you may ask further questions on an item of business. However, we ask that you initially restrict yourself to one question at a time on each item of business to ensure that as many shareholders as possible have a chance to speak. There may not be sufficient time available to address all the comments and questions raised. However, I'll provide a reasonable opportunity for shareholders as a whole to ask questions on each item. Further details or comments from the floor may also be considered at the end of the meeting if time permits.

If you require more information about the registration process, please see one of the Santos staff members present and they'll be able to assist you.

So before we proceed with the formal business of today's meeting, I'd like to reflect on what's been a defining year for Santos. A year in which is the strength of our strategy, the discipline of our operating model and the dedication of our people have positioned the company for sustainable long-term growth. Under the leadership of our Managing Director and CEO, Kevin Gallagher, and his executive team, Santos has demonstrated the value of an unwavering focus on what we do best, safely and efficiently producing the energy that our customers and communities across Australia and the Asia Pacific depend on.

From continued success in the Highlands of PNG, the first cargo from Barossa, key milestones at Pikka, to navigating historic flooding in the Cooper Basin, Santos delivered strong performance.

Having completed a phase of intensive capital investment, Santos is now preparing for a 25% to 30% increase in production that will deliver a step change in revenue and free cash flow and ultimately enhance shareholder value.

Our disciplined approach has anchored Santos through many global challenges and market volatility. The current conflict in the Middle East has upended energy markets, making the most significant disruption to core commodity systems since the 1970s, with impact likely to persist for years to come. As a result, Australia's role in ensuring energy security at home and across the region is more critical than ever. And Santos is well positioned to support this national effort both domestically and across our Asian markets.

So turning to our base business, which delivered a strong operational and financial performance in 2025. We achieved annual production of 87.7 million barrels of oil equivalent, generating revenue of $4.9 billion. Our underlying net profit after tax was $898 million, and we generated strong free cash flow of $1.8 billion from our base business. Importantly, we achieved this while maintaining the best unit production cost in a decade. This is a testament to the rigorous cost discipline that's become the hallmark of Santos under Kevin's leadership.

The operational discipline, the rigorous processes, and focus on reliability that drives efficient cost, low-cost production also underpins safe operations. And I'm pleased to say that our safety performance was equally impressive in 2025. We achieved our best personal safety performance on record, and our process safety performance was the best in 10 years.

Safety is a core value at Santos and a nonnegotiable expectation of the Board. So I want to acknowledge every employee and contractor who contributed to this outstanding result.

The Board remains committed to delivering strong and sustainable returns to you, our shareholders. In 2025, the Board approved the payment of a total dividend of USD 0.237 per share, which is a cash return to shareholders of $770 million, equivalent to 43% of free cash flow from operations. This reflects the Board's confidence in the balance sheet.

Following the delivery of our Barossa and Pikka Phase 1 projects, the Board's updated capital allocation framework will target returns to shareholders of at least 60% of all-in free cash flow. The framework maintains gearing in the range of 15% to 25% and balances shareholder returns with investment in value-accretive production growth and decarbonization.

2025 was a year in which Santos demonstrated its ability to efficiently execute complex world-class projects while continuing to run the base business efficiently, reliably and safely. We delivered the Barossa Gas Project, a Tier 1 long-life asset, and the Darwin LNG life extension project, shipping the first cargo in early 2026. Barossa gas will significantly extend the operating life of the Darwin LNG facility and ensure continued supply to our valued customers in Asia. This achievement is the result of years of planning, engineering and disciplined project execution, in which Santos overcame the challenges of COVID, global supply chain disruption, uncertain regulatory approvals and unprecedented litigation.

In Alaska, our Pikka Phase 1 project will reach first oil imminently with ramp-up to plateau production expected around mid-2026. Once at full rates, Barossa and Pikka Phase 1 are expected to lift Santos production by around 25% to 30% by 2027.

So turning now to a subject that's great importance to your Board, to our shareholders and the communities in which we operate, decarbonization and the energy transition. In 2025, Santos achieved its 2030 Scope 1 and Scope 2 equity emissions reduction target, 5 years ahead of plan, underscoring the ambition of our decarbonization targets. The centerpiece of this success was the Moomba CCS project, one of the world's lowest cost carbon capture and storage projects, which the Board visited earlier this week.

Carbon capture and storage is an essential part of the global energy transition that can deliver real emissions reduction at real scale.

Since startup, Moomba CCS has stored more than 1.5 million tonnes of CO2 equivalent, real, permanent, verifiable emissions reduction. We're immensely proud of this project, which positions Santos as a leader in carbon management solutions. We see opportunities to further expand our carbon capture and storage operations through a Northern Australia/Timor Leste CCS hub, supported by vast geological storage capacity, repurposing our existing infrastructure and through proximity to regional emitters with the large CO2 sources.

The current conflict has reminded societies and economies around the world of the ongoing importance of both oil and gas in the global energy system. Historically, energy transitions have taken many decades, depending on the system, the technology and policy support. And today's energy system is the largest and most complex ever built.

Despite the world's best efforts and trillions of dollars of investment over the last 35 years or so, hydrocarbon fuels still make up 80% of the global energy mix, down only around 5% from 50 years ago. And there are still limited alternatives for hydrocarbons in many applications, from fertilizers, pharmaceuticals and plastics, to steel manufacturing and electronic components. We must be pragmatic. The energy transition will take time.

Oil and gas will remain critical for the global energy security for decades to come. And with material oil and gas resources around our existing infrastructure in PNG, Australia and Alaska, Santos is well positioned to grow our production and supply these critical fuels reliably and affordably to our markets in Australia and Asia.

Your Board provides a rigorous oversight and strategic direction to hold management accountable for performance and ultimately, to safeguard the long-term interests of you, our shareholders.

Over the past year, we've continued to focus on the areas that matter most: safety and sustainability, culture, capital discipline, risk management, returns to shareholders and the delivery of our strategic priorities. We've maintained a strong and diverse Board with the appropriate mix of skills and experience to guide Santos through a complex and rapidly evolving operating environment. We're committed to the highest standards of corporate governance and we continue to engage constructively and listen to our shareholders, regulators and other stakeholders.

The Board also remains disciplined in assessing all proposals against long-term shareholder value. We apply this rigor to the 2025 XRG proposal, prioritizing the best interest of our shareholders. And while the transaction didn't proceed, over recent weeks, our share prices regularly exceeded the XRG's proposal taking into account foreign exchange movements and our full year dividend.

As previously advised, I intend to retire from the Santos Board at the conclusion of the Annual General Meeting in April 2027. This is part of our broader commitment to orderly Board renewal, a process which is well progressed, including selecting my successor.

A primary responsibility of the Board is appointing the CEO and ensuring robust and orderly succession plans are in place. Given the timing of my retirement and the CEO's ongoing commitment to his role, the Board expects that the appointment of Santos' next CEO will be a matter for the Board and my successor.

Santos is proud to employ people whose remarkable talent and drive goes far beyond their day-to-day responsibilities, qualities that were on full display at our 22nd Environmental Health, Safety and Sustainability Awards earlier this week.

Teams from every corner of the Santos portfolio submitted over 90 nominations across 9 categories, showcasing the innovation and passion of our people to deliver safer, more environmentally sustainable and efficient operations. And pleasingly, 1,400 employees voted in the highly coveted People's Choice Award, an award which in many ways embodies the One Santos team culture.

Turning now to the strength of our business, which is well positioned for future growth. In 2016, the company announced a disciplined operating model to ensure the business remained resilient through all oil price cycles. This has underpinned the strong free cash flow generation that enabled Santos to invest in 2 major projects while maintaining a strong balance sheet and increasing dividends per share by more than 13% compound annual growth rate since 2018.

In parallel, the company has executed Moomba CCS, the Barossa Gas Project and life extension of Darwin LNG and Pikka Phase 1 project where start-up is imminent.

Our upgraded portfolio is now anchored by 3 Tier 1 assets, PNG LNG, Barossa and Pikka, and that set us up to meet an all-in free cash flow breakeven price target of $45 to $50 a barrel. We have an enviable portfolio of opportunities to power its next phase of growth, including Papua LNG, expansion of Pikka, and development of the highly prospective Beetaloo and Bedout Basins. And we have the financial flexibility to pursue these opportunities while rewarding shareholders and rapidly reducing gearing.

Santos has the strategy, the capabilities and the assets to help meet Asia's growing energy demand, fulfilling out -- while fulfilling our decarbonization commitments.

The recent disruptions in the Strait of Hormuz and attacks on global energy infrastructure have only highlighted the strategic advantage of Australia LNG for our Asia Pacific partners.

Our LNG shipping routes are well removed from high-risk choke points. With a significant shipping, emissions and cost advantage and a proven track record for a reliable supply, Santos will play an even greater role in supporting energy security across the region.

Santos' LNG portfolio is 83% contracted over the next 5 years, leaving a considerable volume for spot exposure, which allows the company to optimize the portfolio.

Our average contract price remains above peers and supports strong cash margins. This is a strong position for Santos to be in.

The Board has great confidence in the company's leadership team, its strategy, and operational performance, and we're focused on long-term value for our shareholders and stakeholders.

In closing, I'd like to thank my fellow directors for their dedication and counsel over the past year. I'd also like to acknowledge Kevin and his leadership team for their outstanding contribution and to express my gratitude to all Santos employees for their hard work and commitment.

On behalf of the Board, I thank you, our shareholders, for your continued support and confidence in Santos.

I'll now invite Kevin Gallagher, our Managing Director and Chief Executive Officer, to deliver his address. After which, we'll proceed with the formal business of today's meeting. Thank you.

Thank you, Keith, and good morning, and welcome to Santos' 2026 Annual General Meeting. I'm very pleased to be here to report on what was a pivotal year for our company. We delivered our strong performance across our base business despite lower commodity prices in 2025 and maintained a laser-like focus on executing major growth projects that will transform our portfolio and ultimately, our business. This was all undertaken and service of delivering long-term value for shareholders and our stakeholders.

The global environment has profoundly shifted since I presented our full year financial results just 8 weeks ago. The Middle East conflict has exposed the fragility of the world's energy security, triggering the largest LNG constraint in history and creating unprecedented competition for reliable energy supply. The world's largest oil stock release is underway. Countries are implementing fuel rationing and reverting to coal-fired power to protect the industry and households.

Australia's role as a stable, reliable energy powerhouse has never been more important. Our gas is the backbone of regional energy security, helping to keep the lights on and factories firing across Australia and East Asia. This is a 2-way street. We supply the LNG that our regional trading partners count on and in return, they provide the diesel, petrol and jet fuel that Australians need to keep the nation moving and fuel rationing at bay.

At Santos, we are leaning into the national effort, supporting domestic refiners to help keep crude and condensate flowing and refining capacity full through the current instability and beyond.

The world has insatiable appetite for energy, fueled by population growth, industrialization and the digital economy. Asia, one of Santos' core markets, is the engine room of this growth, consuming almost 50% of global energy with gas demand set to grow by around 50% by 2050.

Access to affordable, reliable energy is also the linchpin to help lift people out of poverty, foster economic prosperity and support social stability. Without a doubt, the world needs more energy, not less.

And just as critical minerals are essential for the energy transition, gas as a critical resource required to get us there. It's the only scalable, dispatchable fuel capable of supporting the growth of renewables and providing essential feedstock for things that we rely on in everyday life, like fertilizers and plastics.

At Santos, we have a clear and compelling strategy to deliver sustainable long-term shareholder value and support our customers and communities. That means generating strong cash flows, progressing our new Tier 1 projects, Barossa and Pikka Phase 1, reinvesting to backfill our infrastructure, build new capacity and grow production and investing in the communities where we operate and operating safely, reliably and efficiently.

Our financial performance in 2025 reflects a strong business built to perform through the volatility of commodity price cycles. Free cash flow from operations was $1.8 billion, highlighting the value of our diversified portfolio, high-performing core assets, long-term high-margin LNG contracts and continued cost discipline.

Sales volumes of 93.5 million barrels of oil equivalent generated revenue of $4.9 billion. Unit production costs reduced over the last few years despite relatively steady production. And in 2025, we delivered the lowest unit production costs in a decade. That's the Santos operating model in action, generating the strong cash flows required to increase shareholder returns despite softer commodity prices.

Our balance sheet remains in great shape, funding major development projects whilst providing improved returns to shareholders and we maintained our investment grade credit ratings.

Gearing reduced from 33.6% in 2020 to 26.9% at the end of 2025 or 21.5% if you exclude operating leases. This is a marker of real strength as we conclude our peak capital investment phase having successfully delivered 3 major projects.

We continued to drive cost out of the business, saving around $50 million annually so far on our path towards a $150 million annual savings run rate target. Importantly, we delivered this performance safely.

Santos ranked in the top quartile globally for personal safety, achieved our lowest lost time injury rate and total recordable injury rate on record and delivered our best process safety performance in more than a decade.

I want to take the opportunity to thank all of our teams for their laser focus on striving to be the industry's safest and most reliable operator.

2025 was a year that demonstrated our project execution capability as we built two multibillion-dollar projects concurrently that will set the company up with new production and cash flows for the long term. Despite its complexity and scale, Barossa was delivered within 6 months of the original schedule without any additional budget contingency.

We've successfully moved past the early stage commissioning hurdles and have replaced dry gas seals on the FPSO compressors. With heat exchange are flushing underway, we expect to resume production in the coming days. This is a world-class, long-life asset that will deliver low-cost, high heating value LNG for decades to come and will contribute production of around 19 million barrels of oil equivalent a year net to Santos when it reaches steady-state production.

We're also making great progress in Alaska, which has a rich history of oil production and is clearly one of the world's super basins.

Our Pikka Phase 1 project reached mechanical completion in January. Commissioning activities are well underway. Drilling performance remains exceptional, and we recently successfully introduced fuel gas to the plant.

First oil is expected imminently, followed by start-up of the seawater treatment plant, which will drive our ramp-up to plateau production rates in mid-2026.

Pikka Phase I is just the opening chapter of our plans in Alaska. Recent results from the Quokka 1 appraisal well confirmed the exceptional quality of the Nanushuk reservoir, and will significantly extend our development runway on the North Slope.

The base business delivered another strong year. Reliability improved, cost reduced and we continue to extract value from existing infrastructure.

PNG LNG is proving its worth as a high-quality, long-life asset and operated at capacity throughout 2025. Plant reliability reached more than 98%. We delivered the first year of full production from Angore and completed the Hides F2 well.

GLNG produced 6 million tonnes of LNG, with more than 99.5% reliability, and I firmly believe this asset still has its best days ahead of it.

The Cooper Basin demonstrated its operational resilience, returning safely to pre-flood production levels following last year's historic flooding.

Our LNG portfolio is weighted towards high-heating value gas primarily from PNG LNG and Barossa, which account for over 75% of our equity volumes.

Reflecting the quality of our product, our trading and marketing team executed a series of LNG sales and purchase agreements with Tier 1 customers. We have no shortage of upstream options to backfill and grow our world-class LNG plants.

Our 2P reserves and 2C resources position of approximately 4.7 billion barrels of oil equivalent, underpins our strategy to continue to backfill existing infrastructure and grow value-accretive production into the future.

As Keith noted, in 2025, we achieved our 2030 Scope 1 and Scope 2 equity emissions reduction target 5 years early. This was strongly supported by our world-class Moomba Carbon Capture and Storage project, where Santos has delivered real, safe and permanent decarbonization at scale.

In 2025, the Moomba CCS project stored the equivalent CO2 of taking about 508,000 cars off the roads and has received over 900,000 Australian Carbon Credit Units since startup.

CCS is an incredible opportunity for Santos and Australia. It's now incumbent on policymakers to get the settings right, so CCS can be deployed to reduce emissions faster at scale and cost competitively, not only for our industry but for the hard-to-abate sectors like steel and cement.

Over the last 10 years, we have transformed, built and grown Santos into a high-performing cash flow-generative business that has grown its market capitalization by more than 5x. In that same period, we have returned USD 4.8 billion to shareholders. At current exchange rates, that's more than AUD 6.8 billion.

2025 was a springboard for our next phase of growth, and I'm incredibly energized by our growth agenda in 2026 and beyond. With a high-quality, scalable portfolio, disciplined low-cost operating model and increasing cost of demand, we have a clear pathway towards an all-in free cash flow breakeven target of $45 to $50 per barrel.

The Barossa and Pikka teams are laser-focused on reaching steady-state and plateau production, respectively, which will increase overall production by around 25% to 30% by 2027.

My visit to PNG just last month reinforced the scale of its growth potential. We'll continue to invest in and deliver our PNG LNG backfill projects, including the APF pipeline tie-in and an oil infill program.

Papua LNG represents the next phase of development in our PNG platform. This is a great project in a country with a supportive regulatory system that recognizes our industry's vital role and creating jobs and helping communities thrive. In meeting with the operator's CEO a couple of weeks ago, I was encouraged by the project's progress, including the progress of the project financing. And we're heading towards making a final investment decision in the second half of the year.

The Beetaloo sub-basin in the Northern Territory is a potential game changer for our company. Our appraisal program this year and next is focused on improving commercial flow at scale and demonstrating the basin's development potential. If fully developed, Beetaloo would unlock the scale of opportunity for the Northern Territory that the Northwest Shelf delivered for Western Australia 40 years ago, and it will supply both domestic and LNG markets for decades.

Right across our portfolio, we have a pipeline of opportunities that is the envy of many companies and extends from Alaska to PNG, to here at home in Australia, a country which has the potential to be an energy superpower in the Asia Pacific. But this requires a policy framework in Australia that encourages companies to invest to drill and produce more oil and gas and to decarbonize production operations because all of our opportunities compete for capital that goes to the highest value projects with the lowest risks.

Amidst global instability, Australia must focus on what we can control: policy, approval and fiscal certainty to underpin investor confidence to commit capital. Without this, capital will go where it feels most welcome and safe. Markets like the U.S. and Canada that are turbo charging their share of the LNG export market.

I'm more confident than ever in Santos' future. The strength of our portfolio and the capability of our people to deliver on our vision.

With significant scale, a strong balance sheet and an imminent material increase in production, Santos is well positioned to deliver higher earnings and shareholder returns for years to come. So to you, my fellow shareholders, thank you for your support. I look forward to what we can achieve in the next phase of Santos's transformation.

I'll now hand back to Keith. Thank you very much.

Thank you, Kevin. Ladies and gentlemen, we now come to the formal business of the meeting. I'll address each of the agenda items in turn. Shareholders will be provided with the opportunity to ask questions and make comments in relation to each item or group of items.

As I mentioned earlier, I ask that you please register to ask any questions at the question booth in the adjoining room. After I introduce each item of business, James Murphy, who joins us in the room, will call forward shareholders one by one to please move to the nearest microphone in the room to ask their question for the relevant item of business. If needed, the microphone will be brought to you.

All questions should be addressed to me as the Chair in the first instance. Shareholders are requested to restrict themselves to one question to time on each item of business. One thing I will ask of you today is to please keep your questions brief so that other shareholders have an opportunity to have their say. Once you've asked your question, please return to your seat.

I note that a number of questions from shareholders were received prior to the meeting, a majority of which related to strategy and succession and have been addressed in my or Kevin's earlier comments. However, there's one I'll respond to before we start the formal questions from the floor, and that relates to why the AGM is not being conducted as a hybrid meeting? The topic is something that we, as a Board, have given careful consideration to. In our view, a physical meeting best supports shareholder engagement because it focuses on generating real-life discussion in the room and minimizes technology risks. This approach isn't out of step with our peers. And in fact, we've seen a trend in recent years away from hybrid meetings towards physical meetings with companies looking to address technology risks and simplify logistics and cost.

I'll now move to the first item of business. The first item of business is to receive and consider the financial report, sustainability report, directors' report and the auditor's report for the year ended December 31, 2025. I now lay before the meeting the financial report, the sustainability report, the directors' report, and the auditor's report for the financial year ended December 31, 2025. I note there's no formal resolution for this item of business. Rather, this provides shareholders with an opportunity to ask questions about the reports, the management of the Santos Group and its operations.

Shareholders may also ask questions of the auditor relevant to the conduct of the audit, the preparation and content of the auditor's report, the accounting policies adopted by Santos in preparing the financial statements and the sustainability report and the auditor's independence.

James, do we have any questions on this item?

Chair, the first question comes from David Everett.

Thank you, Mr. Chair. So my question is about your comments about the future of the business, especially gas and oil. So peak global gas production, if we look globally, peak gas -- peak global gas consumption and peak global gas price is predicted by energy experts to have reached that peak either now or in the very near future. We're already below peak gas reserves in Australia. Gas demand in Southeast Asia and China has started to decline. So my question is what plan does Santos have transitioning to other forms of energy provision stay-in-business in a low gas demand world and therefore, preserve shareholder value?

Thanks, David, for your question. Look, I would make some comments about your assertions around peak gas and peak oil, and I'd refer to the very latest World Energy Outlook by the IEA, which is the global expert referred to by many as the authority on oil and gas. And their forecasts are predicting for peak oil. It has moved considerably into the future. It hasn't been reached. It's also saying that for gas, we expect demand, particularly in the Asia region to continue to grow. So I think that sort of supports our strategy very much.

Now that's not to say we're not as a company also exploring alternative sources of energy. And I think as we've talked about in previous years, we're looking at things like in methane, for example, as a potential fuel in the future so that our business will have alternative sources of low-carbon fuels when those things eventually become commercially viable. So we're pursuing in the short to medium term our business, and we believe that actually probably will go longer. But we are actually also at a very responsible level, exploring alternative low-carbon fuel sources as potential sort of supplements to our business in the future. Thank you. Kevin, do you want to add anything to that?

I would only add that the IEA amongst others have all agreed -- most experts agree that gas in Asia -- gas demand, I should say, in Asia, it will grow by 50% to 60% between now and 2050. So it's actually very much a growth market, and that's driven by 1 billion people or so still coming out of poverty that have no access to any reliable energy or electricity to this day. So it's very much a growth market for some time. The latest IEA forecast show peak oil beyond 2035. So a decade or so away.

But I think I would add to Keith's point, since the day I joined this industry, I've had people telling me that why you joining this industry? Peak oil is just around the corner, and it keeps going to the right. But we are very committed, and we spend money every year on activities to explore, to develop and identify economic new forms of energy because if it's not economic, it's not good for the company. It won't be good for anybody, it won't work.

We've looked at hydrogen. We've looked at e-methane, which is hydrogen -- methane made from hydrogen and the gas made from hydrogen, which is close to, if not carbon neutral. And this year alone, we're drilling, we're planning to drill in the Cooper Basin, a geothermal well to see if we can make that work and get. Again, that would significantly reduce our emissions out of our Moomba gas plant.

James?

Chair. The next question comes from Michael Davey from the Australian Shareholders' Association.

Thank you very much, and thank you for your address as Chairman and CEO. My first question actually refers to pricing. You did mention this, but let me just say, I mean, last year's profit was affected by lower commodity prices. As you've quite rightly said, it's been a significant increase since the war started. Could you say something about how this affects Santos' pricing? Given that it's not going to happen overnight, some contracts must be tied to other factors than the price. And how does your hedging policy affect returns?

Okay. Thank you, Michael, for your question. I think as we -- as both Kevin and I mentioned in our addresses, one of the lasting impacts of the current conflict is really the light it's shown on energy security. And I think for Santos, that's kind of a key point. We're strategically placed facing the Asia region. We have the shortest shipping distances. We have a track record of reliability of supply. And so -- and there are no choke points in terms of shipping as well.

So strategically, we are very well placed in Australia, but also Alaska assets are facing the North Asia refinery. So our portfolio is ideally placed in terms of the whole energy security sort of concerns that people have now seen elevated. And I think that energy security has fundamentally changed the sort of view of the world's suppliers of hydrocarbons and where they're going to come from. Everyone is going to want an element of secure supply in their portfolio. So that places extremely well.

In the short term, we've seen what sort of happened with oil price, and we'll see some benefits through that, of course. But most of our gas is actually contracted sort of long term, and these are oil price -- these are contracts, I think 92% of the contracts are actually linked to oil pricing that will sort of flow through eventually into our LNG pricing.

I would also say though that on the other side, as supply chains become more complex, services, equipment, et cetera, we're going to see pressures on costs, which will put considerable stress on our low-cost operating model, which we will manage, but it's certainly -- it's going to be, there going to be impacts on both sides of the equation. Do you want to have anything to add?

Thank you, James. Do you have another question?

Chair, the next question comes from David Hansmann.

Thank you, Mr. Chairman. And first of all, I'd like to express our families to delight that the company wasn't taken over. It's a proud company. The only major company in South Australia. And I'd like to express our pleasure that we're still independent. My specific question relates to kind of an Dorado. As both the Northern Territory Gas Project and Pikka are now virtually -- or actually working, the demand on capital will reduce. So will the Board consider the early development of Dorado's excellent reserves of both gas and oil?

So I might make just a couple of quick comments, and then I'll throw it to Kevin. I think it's really important to just note that we -- the Board has put in place a capital allocation framework. The intention of that framework is to prioritize returns to shareholders, managing the balance sheet, gearing in the range of 15% to 25% and with gearing potentially going even lower greater returns to shareholders, but then a disciplined allocation of capital across the business with the remaining capital, if you like. So we're not looking to be in a world where we kind of go after every project. We think the best value creation for our shareholders is to be very disciplined about the investment we make. So if the Dorado project comes to the top of the heap in terms of its benefits, then it would be the first project off the rank, but we still have a lot of work to do in Dorado. We're going to be drilling some wells there. And I think Kevin, you will talk about that now.

Yes. Thank you, Keith. And thanks, David, for the question. It's a great question. Look, we're very excited by the Dorado opportunity in the Bedout Basin, offshore Western Australia. Of course, we couldn't progress that project over the last few years because we were progressing Pikka and because we were progressing the Barossa project. As you rightly say, that put a lot of capital demand on the business and took our efforts at that time.

I think what the current crisis has shown and highlighted is the importance of energy security and oil energy security. The world stops when the flow of oil stops. And that's just a reality, that's a fact. And I've been very impressed with the commendable efforts of our Prime Minister who recognizes us, traveling around Asia right now trying to secure fuel supply for us because we don't have enough domestic oil production.

And so Dorado is something that's come back very much to the top of our thinking, and the broader Bedout Basin, which has, we believe, a lot more liquids and gas in it as well. And so our plans at the end of this year, early next year are to drill 2 to 3 wells in that basin to further appraise it. But yes, we stand ready to accelerate the development of that project if the regulatory and government support is there.

James?

Chair, the next question comes from Michael Davey from the Australian Shareholders' Association.

I did have a few questions but most have been answered. But could I, you've mentioned, of course, the Moomba CCS, which has been a great success. It's been previously mentioned the possibility to reduce from other -- using the carbon dioxide from other sites and outside companies. How has that progressed? And secondly, you also mentioned the possibility of direct air capture. What does this entail? And is Santos actively pursuing it?

Let me start with direct air capture. We are actively pursuing that. We've actually run trials in the field. I think the second phase of trials are about to commence on some new technologies. The challenge with direct air capture is that low concentrations of CO2 in the air that need to be extracted and the costs that are associated with that. So new technology is going to play a role in getting those costs down, but it's a very -- it's got a lot of potential. It's really the thing for us at the moment is to spend not huge amounts of money but to find out how which technology are the ones that are most likely to proceed, and then we'll go to the next stage of potentially trialing that at a larger scale and then eventually kind of doing something with it. But we're taking a very cautious approach to trialing a whole suite of technology in the direct air capture space to understand that.

In terms of hubs and sort of commercial services for carbon reduction, that's one of the big ambitions we have for the Bayu-Undan, CCS hub, where we see a lot of interest from not just emitters in the immediate area but emitters some distance away where CO2 could be transported to the site. And we do have a suite of Memorandum of Understanding or expressions of interest from various people in that regard as well. Likewise, in the Cooper Basin, Phase 2 has the potential to actually offer carbon reduction services as well. It's important to say also, I think, that around the world now in the North Sea, there are several opportunities that are now operating on that sort of commercial basis, collecting CO2 from other. So this isn't -- it's not something that's sort of a dream in the future. It's actually something that's happening now. Thank you. Want to add anything there?

Yes, I would just add to that. You would have read recently, we signed a contract on an agreement with the South Australian government to supply gas to them from 2030 to 2040. And that's primarily for the Whyalla hub, the industrial hub in Whyalla. As part of that, our bigger vision is to see CO2 coming back from Whyalla to the Cooper Basin, third-party CO2 from some of the industries that would be supported there. And so that's all part of a bigger play longer term vision of building that infrastructure to support third-party carbon capture and allow industrial -- industries to thrive here in South Australia, but be low-carbon industries in the future. The third-party CO2 coming from overseas, I have to concede that has slowed down really by virtue of those countries themselves pushing some of those plans out further, pushing some of those plans, because the big capital investment is really at their end for the aggregation hubs to be built to capture CO2 from their industries. Thank you.

James?

Chair, next question comes from Dean Lambert.

Thank you, Chair. Can you please explain how $387 million in total income tax expense in the 2025 annual report reconciles with $1 million recorded in the dividend franking account. As an individual Australian resident shareholder, I equally await the return of franked dividends.

Well, let me start with franking. Look, our franking capacity is driven by our Australian taxable earnings. We've had a very capital-intensive phase of investment in the Barossa project that the buyer -- the extension of the Darwin life extension project. As those projects start to generate earnings over time, that will support the potential return of frank dividends, but it will take time for that to sort of come through the system. We paid the residual of our franking account in 2025. So we have no franking credits available at the moment.

Just on your point around tax. We are very transparent in our tax affairs. We comply with all the tax obligations. We pay our taxes as required in accordance with the laws, the rules or regulations, et cetera. We paid over USD 770 million in government royalties and excises, royalty-related taxes, employment taxes, income taxes in 2025. Some of that was in Australia, AUD 628 million, and some of it was in our other assets overseas. So we pay considerable tax on an annual basis, but not all of it's in Australia. Thank you.

Shouldn't the $128 million in Australian income tax translate to a fairly considerable figure in the franking account?

I tried to plan it to you earlier. I mean, basically, there's a depreciation element that accounts for the large capital investments we've made over the decades -- over the last -- sorry, decades -- the last few years. And that, that actually doesn't earn us tax credits. Thank you.

Next question, James.

Chair, the next question comes from Mark Wilson.

Thank you, Mr. Chair. This is a question about sports sponsorship. The South Australian Tourism Minister has described Santos sponsorship of the Tour Down Under as "significant". Earlier this year, however, high-profile cyclists called for the sponsorship to cease, generating substantial media controversy. Given the resulting brand damage, can the Board explain how this significant scale expenditure delivers value for shareholders?

I personally feel that we have an obligation as a company like Santos to invest in the communities where we operate, including through sport and recognizing the role that we play as being part of the communities where we operate. Our sponsorships are focused on delivering tangible benefits to local communities and to broader economic activity. And sport plays a really important role both at grass roots and professional levels in supporting participation, both in things like the Tour Down Under, but actually in regional development as well. It delivers significant economic benefits and tourism benefits to South Australia. So we're really committed to that. It's just how can you be part of a community and not participate in it?

So basically, it's community support.

No, it's actually being part of a community. Thank you.

Next question, James.

Chair, the next question comes from Michael Davey from the Australian Shareholders' Association.

You'll be pleased to know this is my last question. All the others have been answered. But there's been some progress with the development on the Narrabri project with positive legal action and increased land access for pipeline installation. Is there now a clear way forward?

Well, the Narrabri project is still subject to an appeal process. And basically, until that process is resolved, there will be no progress on the project. We're minimizing our capital spend on that project, awaiting all the approvals that we need to get in place before we would seriously invest in that project. Thank you. Anything you want to add there, Kevin?

Yes. I'd just say we have made progress in the approvals processes and pleasing to signed an LUA recently with the Gomeroi for the pipeline on our Valley pipeline, and we'll continue to work. We'll continue to work through those processes with all stakeholders to finalize the last couple of approvals that we need. And as Keith said, we're not spending any major capital there. We're just maintaining our current operations in Narrabri and until such time as we get to that. It's a very critical project for the East Coast probably more critical than ever now when you look at the energy shortages around the country. But ultimately, other projects will go in front of it as long as it's held up because they'll take priority for capital.

James?

Chair, the next question comes from Catherine Guillouard.

Thank you, Chair. My name is Catherine, representing communities in Papua New Guinea. In the last 6 months, along 12 major financial institutions have fallen like Domino's and to roll out funding for Papua LNG project. This was after the formal complaint -- formal complaint was filed with the -- this was after a formal Ecuador principle complaint was filed on Papua LNG project by a collision of international NGOs at the end of last year, citing severe, human rights and environmental risk, misaligning with their greater principles framework. My question is, how can the Board justify to shareholders the continued capital allocation to this project when Santos partner, TotalEnergies is as yet to provide evidence of pre -- prior informed consent to 12,700 indigenous people in the Gulf province who face potential force eviction, irrepressible loss of biodiversity from the Papua LNG project?

So thank you for your question. Look, in relation to Papua LNG, I think you need to, we're not the operator of the project and you would need to, I think, direct that question to the operator, who I understand will support the PNG government as they facilitate the development forum, where issues such that you have raised will be discussed in detail as is required under PNG law. So what I can say with confidence is the way Santos operates in PNG. We engage with local communities really positively where we operate. We have 483 agreements with stakeholders and landowners across our operations. I think in 2025, we did over 7,000 engagements with landholders and landowners. It's -- those relationships are really important to us, and I would hope they're important to the operator of Papua LNG as they go forward.

Our Santos Foundation is having a huge impact. We delivered over 2 million vaccinations across the regions, 7,300 cervical cancer screenings since 2024. I mean we -- as I said, when we're talking about the sport thing, it's all about us. We're part of the community where we operate. And we -- our intention is that the communities where we operate benefit from our presence. And I think that's the discussion that can be had with the operator of the Papua LNG project as well. Thank you.

Yes, that I work, but you're being a partner and having a huge equity interest in that, that also means that you have a part to play in this as well.

Yes, as a partner, we will play an influence. That's for sure. Thank you.

Next question, James.

Chair, the next question comes from Angelica Mantikas.

Thank you. Chair, you have repeatedly described your PNG assets as the jewel in the crown of the Santos portfolio and emphasized that your strategy is built on proximity to near Asian markets and partners. Specifically, the Papua LNG project is a key pillar of your future production growth. My question -- my first question is, can the Board confirm if the financial support of MUFG and other major Japanese financial institutions is critical for the Papua LNG project to reach its final investment decision as you flagged in the second quarter of this year and proceed to construction?

I think I can be clear that for Papua LNG, a joint venture operated TotalEnergies is progressing project financing with both export credit agencies and commercial banks. And I think as Kevin indicated, we would expect to be making a decision in that investment in the second half of the year. The projects committed to reflecting the FX performance standards, the World Bank EHS standards and guidelines and the equator principles and/or local laws. There's strong engagement and consultation also with the state of Papua New Guinea and other stakeholders.

Yes. However, given that MUFG is currently facing a formal equator principles complaints and serious intense pressure from civil society, both in Papua New Guinea and Japan over these irreversible biodiversity loss and human rights risks, I think it's important that all the shareholders in this room know how Santos intends to convince these banks that the project is actually compliant with those very Equator Principles that you mentioned.

As I understand that the finance is almost complete. And Kevin, you might want to make a comment on that, you were there recently.

Well, that process is actually being led by the operator Total, and they'll keep us informed, of course. But there will be a lot of governance around that process as it completes and we'll be part of that process. I mean, it's really Total who are leading the effort. But there's a lot of banks in the consortium. I don't think it's appropriate for us to talk on behalf of any 1 bank and particularly if they've got any matters such as you've raised that they're dealing with for themselves, that's for them to comment on.

I think over 29 banks have now rolled out the project due to all of these risks. So I think the shareholders deserve to know what those risks are.

And I think we've just told shareholders that we believe that the financing is progressing. Thank you.

Next question, James.

Chair, the next question comes from [ Meghan Hickok ].

Chair, my name is Meghan Hickok. I'm a customer land owner from Mareke village in Kikori district, Gulf of Papua New Guinea. I stand today in front of you representing around 30,000 voices from community within the Papua LNG project area. Communities, host land, rivers, sea and livelihood are directly in the part of your decision. Your partners are working on our land without consulting or even so as talking to everyone, and clearing our land without consent, drilling without our consent. On top of that, the pipeline from this project runs directly to my village, yet we haven't been consulted. You don't have the right to walk in our land. You are just walking in, cutting trees, drilling. Who gave you the right or the consent to come to my land? We have a right to be able to understand what is happening on our lands and to be informed and properly consulted. Because of this, it's just not a project on paper. It is our lives.

I'm here because I want to know what the fate of my village and my people is. So I have two questions for you today. Will you confirm out loud today that the Papua pipeline, the Papua LNG pipeline will display -- displace our communities. And if so, what is your plan for the relocation of 30,000 of my people?

The second question is, and why aren't we've been properly consulted or informed of the risk of this project? So I invite you and the Board to come to my village, Mareke, and walk the pipeline routes yourself to see the land, the homes, their community that is going to be affected by your actions.

Thank you. So look, I think, as I mentioned earlier, Meg, the process, as I understand it, is that the PNG government together with the operator will facilitate a development forum with all the landowners, where these sorts of issues and risks will be discussed and resolved as is required under law in PNG. I really can't say any more than that. The development forum needs to occur and is planned to occur, I understand. Thank you.

Next question, James.

Chair, the next question comes from Chris Warren who has a question for the auditors.

Thank you, Chair. The Australian Accounting Standards Board Standard 137 provides illustrative examples to assist auditors and companies in understanding what sufficient disclosure or provisions looks like in practice and emphasizes that disclosures and provisions should enable investors to understand the nature, timing, and uncertainty of major operations. Carbon Tracker and independent financial think tank specializing in climate-related financial risk recently analyzed Santos' disclosures and found that the company is providing just 19% of the type of material asset retirement obligation information investors would expect Santos to disclose. Key gaps include cash flow estimates, discount rates and precise timing of expenditure. How did your audit consider those illustrative examples and the underlying disclosure principles in AASB 137? And what criteria did you apply to conclude that the disclosures were sufficient, particularly in relation to timing, discount rates and cash flow estimates?

Thank you for the question. Look, I'm going to throw that to our auditor who knows these standards intimately. And of course, checks our accounts equally closely. Darren?

Thank you, Chair. Thank you for your question, Mr. Warren. Note 3.5 to the financial report describes the accounting policies and the significant judgments considered by the directors in determining the asset retirement obligation provisions. It also includes a maturity profile, a table showing the expected timing of the expenditure, which I think addresses part of your question. And it categorizes that expenditure between less than 1 year, 1 to 2 years, 2 to 5 years, and greater than 5 years. Our audit report, specifically Page 267 of your annual report describes why we consider this topic to be a key audit matter. It lists a number of the procedures we performed, and it includes a specific statement that we consider the adequacy and the appropriateness of the disclosures, including the assumptions, the judgments and estimates.

To the part of your question regarding illustrative examples, we absolutely do consider the illustrative examples in the standards noting that they are one, illustrative; and two, very limited. From memory, the 137 examples include just one example on decommissioning costs. It relates to a single company with a single asset, which is very different to the Santos portfolio, of course.

Lastly and perhaps most importantly, Mr. Warren, the basis of preparation of the financial report is not the views of organizations that analyze the disclosures with a particular lens, be it climate related or other. The basis of preparation of the financial report is the requirements of the accounting standards, the Corporations Act, and our opinion clearly states that we consider the financial report to be prepared in accordance with those regulatory requirements. Thank you.

Thank you, Darren. James, next question, please.

Chair, the next question comes from Peggy Smith.

Thank you, Chair. Given the significant discrepancies between the production estimates for the Narrabri Gas Project and the statements, both Santos and government officials have presented to the public and to shareholders, I'd like to address concerns regarding transparency.

Santos has repeatedly claimed the project could supply up to 200 terajoules of gas per day, translating to 73 petajoules annually as stated in the 2017 environmental impact statement. More recently, Santos has claimed the project could produce up to 150 terajoules a day, which equates to 54 petajoules per annum. An independent analysis suggests the actual production is anticipated to be on average only 17 to 28.5 petajoules per year over an anticipated 35-year life of the project according to guidance updates released on the ASX on November 11, 2021, and the Santos and Oil Search merger scheme.

Additionally, during the Independent Planning Commission hearings in 2020, it was revealed that the CO2 content in the targeted coal seams may average between 25% and 30% based on Dr. Andrew Grogan's analysis of publicly available data, contradicting the 10% figure provided in the environmental impact statement. And Santos CEO, Kevin Gallagher previously stating that gas samples showed less than 5% CO2, classifying the project as a low CO2 asset, but this descriptor was later admitted in investor presentations.

It's also been reported that New South Wales gas demand was 114 petajoules per annum in 2022. And to supply half of this demand, the Narrabri Gas Project would need to produce 57 petajoules annually. How does Santos justify these conflicting figures? And with Santos' stated production expectations seemingly misaligned with this demand, can the company publicly clarify how much gas the Narrabri Gas Project can realistically supply to the East Coast gas market? And is there an intention to update disclosure to accurately reflect the true potential of the Narrabri Gas Project in terms of both gas production and greenhouse gas emissions, particularly given concerns about potentially inflated perceptions of the project's value?

Okay. Thanks for the question. I think we might -- do you make a few comments on this from an auditor's perspective at all?

I think, I guess, from an auditor perspective, we do look at forward-looking information and do understand that there is a lot of uncertainty in all forward-looking information, but we look at what is available at the time of undertaking these procedures. We do make sure that any statements that are made in the disclosures can be validated by evidence. I think that's probably the auditor perspective. Thanks.

I would just say the comment you made about the, whether it's 50% of New South Wales future gas needs or not will change with time. So longer the project is delayed, I guess, that number would change with time, but it has not changed materially. It's still approximately 50% of the future needs, gas supply needs for New South Wales. It can -- and those other numbers we say up to because it depends on the development concept that we actually develop as a Phase 1, there's a Phase 2. And it depends, I mean, it's just a function of how many wells we drill at any point in time.

As for the expert, you referred to who suggest it would be 17 terajoules per day production. I'm glad that individual doesn't work for Santos. That's all I can say. I trust my reservoir experts over anyone coming with numbers like that. I'm pretty confident in the numbers that we have publicly released. And of course, if we ever take FID on that project at that point in time based on cost, economics, and the concept that we will develop, we'll give the latest estimate what those numbers are when we take FID. And of course, we would then be held to account on the promises that we make at FID because that's the promises that really matter. Thank you.

Thank you. James?

Chair, the next question comes from Matthew Tompkins.

Thank you, Chair. With Santos pursuing multiple new and expanded projects in a rising cost environment, how critical our new and renewed debt facilities to delivering the company's growth strategy?

I think as both Kevin's and my presentation, we sort of indicated that the cash flows we expect from our business going forward will prioritize returns to shareholders but will actually also enable us to predominantly fund our growth out of our existing cash flows. Thank you.

That leads me to my second question.

Sorry, one -- if you could restrict yourself to one question at a time. Is it a short question?

Reasonably short.

Okay. Go on.

Since last year's AGM, 2 of Australia's biggest banks and long-time financiers of Santos, CommBank and NAB, have both released policies that make Santos ineligible for new and renewed finance. This is because in their view, the company does not have a credible Paris-aligned transition plan. ANZ and Westpac, however, appear to remain supportive, including through reported participation in a refinancing November last year. My question, how important are ANZ and Westpac to Santos' growth strategy? And what gives the company confidence that these banks will continue backing it? Can you assure shareholders that this support will remain in place?

I think I can tell you quite clearly that we have very strong relationships with our banking partners, not just in Australia but overseas. I'd also highlight that our recent debt capital market where we raised $1 billion on a bond issuance, we're over 5x subscribed on that. So I think in terms of our attractiveness for banks and investment in the future, we're very confident about that. Thank you. No, you've done your two questions. Thank you.

Next question, please, James.

The next question comes from Karra Kinchela.

I'm Karra Kinchela, Gomeroi woman from Narrabri. My question to you today, Santos, is will you accept 2 documents from me? The first is the Breeza Declaration. It rejects the Narrabri Gas Project and associated pipelines. It pledges united opposition to compulsory acquisition of land along the pipeline routes.

The second is a statement from the Gomeroi people. It was written by the Gomeroi People in Breeza in March with the same gathering of people. It clearly states the Gomeroi people opposed coal seam gas and do not consent to the destruction of our country. We, as Gomeroi people, as traditional owners of our lands stand united in opposition against coal seam gas extraction in the Pilliga Forest. The alliance behind the Breeza Declaration of firms that it will stand with Gomeroi in defensive country while protecting water and prime agricultural land as it rejects forced industrialization. And we call for a different path to invest in our sustainable region of communities. The declaration is endorsed by Gomeroi People, New South Wales Farmers Association, Country Women's Association New South Wales, and Lock the Gate Alliance. Will you accept our declaration?

So if you pass those to our security people, I'm sure that we'll...

We would like to hand them to you directly today, please?

Right. You pass them to then, please.

And can I just state that is not respectful and the respect of the shareholders in this space for people who don't have a say is also respectful. And you guys are coming into our communities. So there is no respect in this place. And we will not let you come into our communities like this.

Please take your seat. I would make the point that Santos has engaged with the Gomeroi people over many years, and we recently -- please be quiet.

[indiscernible]

I know we are. And if you could please pay me the respect you were just demanding as well. We have executed -- we have engaged with the Gomeroi people over the years. And together we recently executed a voluntary Indigenous Land Use Agreement, which was voted on...

[indiscernible]

Sorry, if you won't take your seat, I'll ask you to leave the meeting. No, I'm not...

[indiscernible]

Please take your seat.

[indiscernible]

No, I would like you to please sit down.

[indiscernible]

That's not true. Please take your seat.

[indiscernible]

Please take your seat.

[indiscernible].

Thank you. Next question, please, James.

Chair, the next question comes from [ Joseph Khaneku ].

Thank you, the Chairman and the CEO and the Board of Santos, shareholders. I'm Joseph Khaneku, tribal leader from Kaimare tribe in the Baimuru area of the Gulf Province of Papua New Guinea. That's where Santos and its partners, Total and the others operating. The operation is upstream from where I come from. I live on the downstream in the Delta area. Purari Delta. It covers about 450,000 hectares. And in it, it's my clan, tribe, Kaimare tribe, and 7 other tribes, about 30,000 people. We are not part of the project because we have been excluded by some stupid laws that we set up in our country. The issue of 5 kilometers away from the area that the company operates in, you excluded.

In October this year, 23rd of October precisely, we saw an error in the paper that suggested or said clearly that an environmental permit has been issued to Total, E&P, your partners in the Papua LNG project.

Part B of that permit said this, and I quote, "the exact wording that the company is allowed to discharge of waste into the environment." It doesn't tell us what waste, it doesn't tell us what environment. You are partners with Total and ExxonMobil in this project, and we are led to believe that you have some social and environmental responsibilities that will take care of my people and makes people as well.

We are not part of the project, but if the company is allowed to discharge the waste, they don't tell us what it is. But in the EIS, there's a statement which says it could be hydrogen sulfide and wastewater. This is scary. They don't even tell us they will dump it. They just said into the environment. You can check it out. The permit is issued already. And it's for 25 years, which means this -- even your partners will be dumping this waste into my people's environment for the next 25 years. This is not on. This, for me, looks like it's a human rights abuse.

So my question is, as corporate and responsible -- responsible corporate entities in this country and my country as well, can you make a statement to tell us if this is so, and what are you going to do about it? I repeat again this amounts to human rights and environmental abuse. Thank you.

Well, thank you for your question, Joseph. And that was a very powerful question. So thank you. I appreciate the comments. We will -- I certainly would like to find out more about this myself. And certainly, as part of the assurance process that we go through as this project goes forward, we will undertake that we will ask the sort of the questions that you are asking as well. Kevin, do you want to add anything to that?

I think the only thing I can say is, obviously, the government, PNG government will work with the operator totality of the development forum later this year where all valid landowners and landholders will be invited to attend. And I think that's where they negotiate the benefits in the terms for the project. And we'll wait to be updated by the operator on that.

When it comes to the standards that the project will operate to, every partner will do its own assurance on those project plans before a final investment decision is taken, and we would need to be satisfied that the project meets our standards, just as we have at PNG LNG, for example, before we would be able to move forward with the project. I'd be very confident they would. But I say that only based on my track record and Santos' track record and Total's reputation. But obviously, we will focus on this aspect of that assurance process given your comments. Thank you.

You are aware too that the open forum will not take place. A lot of plan is the prerequisite for the development forum. Without the environmental plan, the development forum will not take place. So we are questioning the environmental permit. If it's questioned and if it is put in doubt, then the open forum will not take place, which means the FID will not eventuate. So can you assure us that this environmental plan is safe enough to guarantee the development forum taking place? And I want to invite you -- rather to come. You always go to PNG, I know that. But you must come to Baimuru. I invite you to come to Baimuru, and see my place and my people, then you will understand what I'm talking to you about it. Thank you.

Thank you. James, next question, please.

Chair, the next question comes from Amanda Holly.

Thank you, Chair. Last month, Morgan Stanley published a bear case scenario for Santos. Their worst case credible outlook for the share price landed at $3.70, roughly half of today's value. That assumes just a 25% decommissioning cost escalation. Page 220 in your annual report states that Santos has calculated its decommissioning liabilities, assuming that major subsea pipelines will be abandoned in place. If full removal is required, the restoration liability jumps by another USD 550 million to USD 750 million.

The discussion paper underpinning the Australian government's current reforms for offshore decommissioning and financial assurance reinforces the government's position that full removal will remain the legislative expectation. What has the Board done to assess the risk that these assumptions around abandonment may not hold in practice? And how has it satisfied itself that investors are adequately informed about the potential for a $0.75 billion cost blowout in cleanup liabilities?

Thank you for the question. Look, on decommissioning, every year, we have -- we do our own review, but we actually bring in independent experts to review all our decommissioning costs. That's done on an annual basis. So we're very confident about the costs that we actually have there. We have an ongoing program of investment in decommissioning, and we're progressively removing, which is the most efficient way to do it. It's part of our core business. And we have a great understanding of what our decommissioning liabilities are, and we're progressing with those. We've even taken quite a conservative position on some assets where there may be repurposed for opportunities, for example, like CCS, but we're actually taking as a base assumption in these costs that they will be removed. So I think we actually have quite a conservative approach to estimating our decommissioning costs. Kevin, do you want to make a point there?

I'd just say that over the last 3 years we've spent about USD 300 million each year doing decommissioning activities around older assets. And many of those projects we've delivered them for less than we were carrying in our liabilities on our books. We've actually delivered under budget on those. And I'd just like to say, too, that Morgan Stanley Brokers target price for Santos is just under $8 currently. Thank you.

I, just on that, you haven't addressed the question about that $550 million to $750 million having to take the pipelines out of the ocean. Why does the Board feel that it's okay to leave that number off the books?

Well, we do assessments on this on every pipeline. And sometimes, you -- the assessment is that the risk of removing it is greater than the risk of sort of leading in the ground. And that's the sort of approach that we will take to each pipeline.

Have you ever had approval to leave major subsea pipelines in the ocean by NOPSEMA?

Well, a great example there would be where we use the pipeline for repurposing. Thank you.

Next question, please, James.

Chair, the next question comes from Ferris Robert.

Thank you, Mr. Chair. It's actually Robert Ferris. So my question is about the International Court of Justice decision in July last year, described as a landmark decision. The court gave its advisory opinion that estates legal obligations extend to its downstream or Scope 3 emissions. That put Australia on notice that it may face increasing legal risks for the climate harm caused by the Scope 3 emissions of the large amounts of fossil fuels that exports. The exporting of which may become in the court's phraseology internationally wrongful acts. The court clarified the lowest decision apply to states. Those states are expected to take appropriate measures to regulate private actors such as this company.

Given the importance of this decision and its clear implications of future increased regulatory burden and legal liabilities in relation to the Scope 3 emissions of all its LNG and oil exports to Asia, and just in relation to legal liabilities, I can say that Columbia University has reported that by the end of 2025, there were 3,000 climate litigation cases filed in 60 countries, not all of course relating to Scope 3 emissions but increasing constantly. So my question is, is the company concerned about these escalating risks? And if not, why not?

Clearly, we actually have a plan around Scope 3 emissions in general. We have emissions upstream of our business and downstream, and we have worked in a very collaborative approach with shareholders over the last few years. We understand their emissions, and we're working with them on emissions reduction plans over time. So that's our supply chain.

In terms of the downstream, I think probably the thing I would point to there is that we actually have a target underpinned by CCS to actually -- disposal of around 14 million tonnes of third-party CO2 per year by 2040. We see technologies like CCS is enabling those sort of Scope 3 emissions, if you like, third-party emissions to be addressed using a technology we are confident in, a technology that we believe can address those emissions at scale.

Thank you. James?

Chair, the next question comes from Dean Lambert.

Thank you. This question I have formulated before your announcement earlier in the meeting that the share price has gone up past the XRG offer at different times lately. However, I think it makes it even worse. I've been a shareholder in the company for over 20 years, consider myself a loyal supporter. The 16 June 2025 announcement of discussions of a takeover at a 28% premium to the prevailing share price did not seem to me to be a good enough reason to be interested. Given that in the event of the offer proceeding, I would forgo any prospect of future income or capital appreciation and chance of having a say as a shareholder in the running of the company. Indeed, I'm horrified at the prospect of a takeover of the company by foreign interests who may not have as much regard for sensitive local issues facing the company. Was the initial support for the takeover given on purely financial grounds or is there some consideration of a moral or patriotic component?

So to be clear here, our obligation as the Board is to act in the best interest of shareholders. In this particular case, we felt that the level of the proposed offer was sufficient that shareholders needed to be consulted and given the opportunity to decide whether something they wanted to do or not. And based on the consultations I've had with many, many shareholders since that time, there is strong consensus that there would have been a lot of anger if we hadn't put that proposal and made it obvious so that shareholders would actually be able to have a say. They may not have supported it. But at the end of the day, for a Board to say here's an offer, it's not -- it's just not good enough. We need shareholders to have the opportunity to just have their say, as you're saying, right now. That's our obligation.

Thank you. Next question, James.

Chair, the next question comes from Jack Green.

Thank you, Chair. Today, I want to speak on NT, Northern territory. Aboriginal people there, we're all culture people. We're very tied to the land and where they're going to be fracking. We're worrying about our water. The water mean a lot to Aboriginal people, not Aboriginal people -- non-Aboriginal people to get. So we're really worried about that. And when they do a lot of fracking to some of their spring that went dry, and some of the bore and the community, a couple I know in [indiscernible] when they start drilling there, the bore went dry. So I still don't know whether they had any water in there. So the way they're going to drill is ties with a lot of Aboriginal culture [indiscernible]. And my people back home, Alawa, Marra, Gurindji, Garrwa, you name it, we're all worried what's going to happen. So that's why I came up here to try and speak today to -- we're worried about that fracking and the pipeline that's going to go through. That's one of the question. The other question I got, if that's all right, Chair?

Do you want me to address that first question?

Yes.

Yes. Okay. Look, I mean I think the key point to say is you're talking about a pipeline. So we actually don't have a project there that there's drilling that we're intending to be doing there is to test the potential into whether there could be a project. So that's the sort of first point I'd make.

We will be drilling some sort of wells. And there is strict regulatory requirements around things like groundwater protection. It's governed by the Northern Territory, but it's also got oversight by the Commonwealth, the EPA, and there are very strict requirements that kind of pick up the recommendations from a major scientific review that was done in the Northern Territory. Well design, well construction standards, they're all specifically designed to isolate aquifers and prevent any contamination impacts on groundwater. So I don't know whether that gives you any confidence, but there are extreme levels of risk protection to get put in place before these activities can proceed.

Do you want to ask your second question?

Yes. I'd like to ask the second question. I was in Darwin a few months ago, and I was on one of the tour, ran down on about and we came across with a tank that where they're putting gas in, and what we hear, the gas was leaking, the tank was leaking when they put a gas in there. That's what I wanted to find that.

Yes. So to be clear, the first thing I'd like to make -- a point I'd like to make is the tank actually poses no safety risk. There have been future emissions from the tank since when it was first built. When a small incident occurred, it spilled a little bit of liquid gas into, onto one of the, inside the tank. As a result of that, we've had continuous monitoring of the emission levels in place. That level has remained static over the last 20 years. It hasn't changed. It's just recently gone through a major hazard facility licensing process, and that process is run by NT WorkSafe, and that was renewed in July '25. So we maintain monitoring, continuous monitoring of those emissions. It's stable, and it's safe. Thank you.

Next question, James.

Chair, the next question comes from [ Verna Bluett ].

Thank you, Mr. Chair. I'd like to say that I applaud the Board's stated commitment to environmental stewardship. However, Narrabri, as we've heard this morning from many people here, is an example of a Santos project that has been criticized for risks to aquifers, to wildlife habitat and long-term climate pollution and has considerable local objections. Santos has stated commitments to environmental stewardship. If the projects go wrong, and the environmental -- there is environmental damage. What accountability will there be for the Board?

Clearly, all our activities in Narrabri are governed by very strict regulations that are put in place by the New South Wales government, and we're subject to those rules. They're designed to protect the environment. So we comply with those rules. And that's -- and they set the bar extremely high. I think that's about the most I can say on that.

With respect, you have not answered the question. What is the accountability if things go wrong? What will happen?

I think the whole point of our environmental process is to explore all the risks and things that could potentially go wrong and put mitigations in place to prevent them from occurring in the first place. Thank you.

And the accountability?

We're accountable under the law.

Next question, James.

Chair, the next question comes from [ Evynn Moore ].

Thank you, Chairman. There is a cost of living crisis in Australia at the moment, and the higher cost of gas and electricity in general feeds into that cost of living. Has Santos considered given that our gas here that it's extracting is a national resource and a lot of people feel like is an Australian resource. Has Santos considered ever providing cheaper gas for Australians and it charges to international customers in order to address -- help address the cost of living crisis?

The gas that we do provide for our domestic customers is cheaper than the gas that's provided to our LNG customers in Asia.

Oh, can you tell me how much then? Because people are not aware of this at all. You read letters to the paper about the high cost of gas?

Do you want to say something there, Kevin?

I can assure you, without giving specific numbers because, unfortunately, we can't divulge the price that we sell gas at to individual customers. But the cost of domestic gas today is around AUD 8 or AUD 9 into our markets. That's available on the spot market today. That will be the price of domestic gas today here in the East Coast. That's Australian dollars. The equivalent going into customers in Asia would be well over [ AUD 20 ]. And by the time it's -- the price that we sell it for, which is higher than that AUD 8 or AUD 9, I can assure you. And then you've got to liquefy it, ship it, transport to another end. So it's very significantly higher.

And the other thing that's worth saying, too, is that, because of the size and the scale of these remote developments we have to get the gas to market, without LNG to provide the scale and the revenue that is required to justify those investments, you could never develop those fields simply for the Australian market. It's too small, and hence, the gas price would be far too high. So the 2 industries actually work. The export industry and the domestic industry work hand-in-hand. The export industry enables our ability to develop fields and bring gas to the Australian market.

Thank you. James, next question, please.

Chair, the next question comes from Kevin Cordon.

Thank you, Chair. In light of the significant community opposition and subsequent reports of your sponsorship withdrawal from the 2025 Koori Knockout, how does Santos plan to address the clear lack of social licenses from Gomeroi traditional owners for your Narrabri Gas Project while continuing to seek major partnerships within First Nation sporting events?

I'm going to have to pass that on to Kevin. I'm not aware of that.

That's what I call a handball. Look, I mean, with sponsorships, we review the benefits to the communities. And we don't want to sponsor things that people don't want us response them. I'm very happy to keep the money in the bank and give it back to shareholders. But we do look to sponsor and be part of communities. And more often than not, we're welcome for it, and there was a question earlier on about the Tour Down Under, and what I can say on that one, without Santos's sponsorship, that event simply just would not happen here in Adelaide. It wouldn't be affordable.

And we work with local communities. We'd like to think that we will sponsor. We do sponsor events out in the Narrabri region, a lot of sporting events that are very popular with the communities. And we like -- we sponsor First Nations events in PNG and all over Australia. With that particular one, that was regrettable, but the sponsorship wasn't welcome to us. It's just what it was. So we move on.

Yes, I think it's a clear statement from the Gomeroi people that we do not want Santos on their country. Thank you.

Thank you. Next question, please, James. I believe this is the last question.

That's correct. The last question comes from Evynn Moore.

Well, basically, there's a question about taxation. You often read green activists claiming that the gas industry is very lightly taxed. And I understand as a green senator has got a senate inquiry going into the taxation paid by the gas industry. There have been references here today to the amount of taxation paid by Santos, but I just wondered if we could have it repeated again. Thanks.

Sure. Well, I think the best point I'd make is that the oil and gas industry, I think, is the second largest contributor to taxes in Australia, something in the order of $29.1 billion paid last year by the industry. Last year Santos paid in total taxes across Australia and our operator -- remember, we have operations in places like New Guinea and Alaska. We have offices in Singapore. So we pay taxes in many places. We paid over USD 770 million last year in taxes. Of which, around $628 million was in Australia. The year before, we paid over USD 1 billion in taxes across our global operations. We pay taxes as company tax, government royalties in exercise. We pay petroleum resource rent taxes, royalty-related taxes. There are many different taxes that we pay. I'm just giving you the total that we spent in Australia last year AUD 628 million. Thank you.

All right. Look, I think we have no further questions. So I'm now going to move to the next item of business, which is the reelection of directors, Item 2. Item 2(a) relates to the reelection of Janine McArdle. Janine was appointed to the Board on the 2nd of October -- sorry, October 23, 2019, and she's a member of the Audit and Risk Committee, the Safety and Sustainability Committee and the Nominations Committee.

In accordance with the constitution, Janine retires and being eligible, offers herself for reelection. The Board, with Janine abstaining, recommends that shareholders vote in favor of Janine's reelection. Shareholders have an opportunity to ask question in relation to Janine's reelection at the end of this item of business.

I'll now turn to Item 2(b) relating to the reelection of Vickki McFadden. Vickki was appointed to the Board on the April 11, '24, and as she's Chair of the Audit and Risk Committee and a member of the People, Remuneration and Culture Committee. In accordance with the constitution, Vickki retires and being eligible, offers herself for reelection. The Board, with Vickki abstaining, recommends that shareholders vote in favor of Vickki's reelection. I'll now invite questions in relation to the reelection of Janine and Vickki. James, do we have any questions?

Chair, there are no questions on this item.

Thank you. So the results of the proxy voting for the Director reelections are now shown on the screen behind me. The proxy results indicate that each of these resolutions will pass. And I congratulate Janine and Vickki on their reelection.

I'll now move to Item 3 of the Remuneration Report, and this item of business asks shareholders to adopt the company's remuneration report. Firstly, I'd like to thank shareholders and other stakeholders for their feedback on our remuneration framework as part of our commitment to the ongoing improvement in and transparency of our remuneration report. We believe this year's report clearly demonstrates alignment with the company performance and shareholder value creation. The Board is committed to a proactive approach of engaging with shareholders in 2026 to continue to address remuneration queries in a transparent manner to ensure that we have a robust framework.

In 2025, the base business has generated strong cash flows while delivering outstanding personal and process safety results. While the base business has continued to perform strongly and Barossa first gas production was achieved in September 2025, due to commissioning challenges, the first LNG cargo wasn't achieved before the end of year 2025, which is reflected in our performance, our scorecard performance outcome.

The highlights for 2025 include free cash flow of $1.8 billion from the strong base business performance, our best unit production costs in a decade of $6.78 per barrel of oil equivalent, excluding Bayu-Undan, gearing of 21.5% excluding leases and strong liquidity, and underlying net profit after tax of $898 million. Sales volumes of 93.5 million barrels of oil equivalent, generating revenue of $4.9 billion. Our best personal safety performance on record and best process safety performance in 10 years. Moomba CCS has stored more than 1.5 million tonnes of CO2 equivalent since startup. These results contributed to a company's scorecard outcome of 76.1% of target out of a possible 167%.

The long-term incentive award was tested following the end of the full year period. The relative TSR measures against both the ASX Index and the Global 1200 Energy Index, which accounts for half of the LTI were not achieved. Overall, the vesting outcome was 39.5% based on performance in relation to the free cash flow breakeven and return on average capital employed performance measures.

The performance period for the growth in incentive projects concluded on the December 31, 2025. The growth projects incentive was subject to the delivery of key milestones related to major growth projects and energy transition strategy. Performance was measured over a 5-year performance period with progress locked in along the way. Overall, the vesting outcome for the CEO growth projects incentive was 90%. With the conclusion of the CEO growth incentive, we moved back to a more traditional remuneration framework.

The vote on this resolution is advisory-only and doesn't bind the Board of Directors or the company. Now I'm pleased to take questions from you that you may have in relation to the 2025 remuneration report.

If you have any questions that relate to the Managing Director's proposed grant of share acquisition rights, please hold those until we can, and you can raise them during Item 4. James, do we have any questions from shareholders registered for this item?

Chair, there are no questions registered for this item.

Thank you, James. So on the screen behind me, you will see display the proxy voting outcome for this item.

I'll now move to the next item of business, Item 4, which relates to the grant of share acquisition rights to Mr. Kevin Gallagher. This item asks shareholders to approve a grant of share acquisition rights to the Managing Director and Chief Executive Officer, Mr. Kevin Gallagher. A detailed explanation of this item is set in the notice of meeting. The Board is confident that the targets for the CEO's share acquisition rights are aligned with shareholder interests. I'll now take questions on this item. James, do we have any questions from shareholders registered for this item?

Chair, there are no questions on this item.

Thank you, James. On the screen behind me, you'll see display the proxy voting outcome for this item.

Ladies and gentlemen, that completes the formal business of the 2026 Annual General Meeting, and I now declare the meeting closed, subject to finalization of the polls. Please note that the polls will remain open for another 10 minutes. Please ensure you lodge your vote within that time. If you need any assistance with voting, please raise your hand and a Computershare representative will come and help you.

Thank you for your time, for your questions, and your continued engagement and support. The Board and management team look forward to catching up in the foyer through the doors at the back of the room over light refreshments. Thank you.

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.

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.

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.

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 Instructions] The first question today comes from Rob Koh from Morgan Stanley.

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.

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.

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.

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.

The next question comes from Tom Allen from UBS.

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?

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.

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?

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.

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?

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.

The next question comes from Adam Martin from E&P.

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?

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.

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?

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?

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.

The next question comes from Dale Koenders from Barrenjoey.

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?

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.

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?

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 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?

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.

The next question comes from Tom Wallington from Citi.

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?

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.

The next question comes from Nik Burns from Jarden Australia.

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?

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

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.

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.

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?

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.

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?

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.

The next question comes from Gordon Ramsay from RBC Capital Markets.

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?

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.

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?

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.

The next question comes from Henry Meyer from Goldman Sachs.

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?

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.

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

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.

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?

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.

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.

Thanks, Brett.

The next question comes from Mark Wiseman from Macquarie Group.

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.

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.

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?

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.