SSLZY (SSLZY) Q2 2026 Earnings Report, Transcript and Summary

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.