Thank you for standing by and welcome to the Santos Limited 2024 Half Year Results Webcast. [Operator Instructions] I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead.

Good morning, again and welcome to our presentation of the Santos 2024 half year results. Joining me today is Chief Financial Officer, Anthea McKinnell. Anthea and I recorded a video presentation on today's results which you can find on our website along with today's presentation. We're not going to repeat the video presentation on this call. We will, however, be happy to take your questions. Before we do that, I'd like to make some opening remarks. I'd like to start by acknowledging the traditional lands of the Kaurna people of the Adelaide Plains, where I'm speaking from today. I pay my respects to their elders, past, present and emerging. I'd also like to acknowledge and recognize the support of traditional owners and indigenous people everywhere Santos operates, including our local communities in Papua New Guinea, Timor-Leste and Alaska. I'm pleased to present yet another solid set of financial results that demonstrate the success of our disciplined operating model. Santos continues to generate strong cash flow from operations. I'd also like to touch on some of the highlights from this result. For the first half of 2024, Santos generated production of 44 million barrels of oil equivalent, sales revenue of $2.7 billion, free cash flow from operations of $1.1 billion, EBITDAX of $1.8 billion and underlying profit of $654 million. And pleasingly, the Board has determined to pay an interim dividend of $422 million or US$0.13 per share, based on an Australian dollar exchange rate of 0.67, that's approximately AUD0.19, I should say, per share unfranked. We are pleased to continue to deliver strong cash returns to our shareholders while balancing the need to invest in our business. Before I talk about progress on our projects, I do want to mention safety performance. Always safe is a core value at Santos. Our expectation is that every day, everyone who works at Santos is focused on keeping themselves and their workmates safe and going home healthy. Personnel safety performance improved in the first half and we have seen a significant reduction in process safety loss of containment incidents. As you can see from our results presentation, we are delivering on our major projects. Phase 1 of the Moomba CCS project is in advanced commissioning stages. The pipeline is currently being pressured up and CO2 is to be introduced into the processing system imminently. The project remains on track for first injection and ramp up to full capacity this year. Phase 1 of Moomba CCS will be 1 of the lowest-cost CCS projects in the world and have capacity to permanently store up to 1.7 million tonnes of carbon dioxide annually, making Moomba CCS a significant part of Australia's journey to net 0 emissions. The Barossa project is nearing 80% complete with first gas expected in third quarter of 2025 as per previous guidance. The gas export pipeline that will deliver gas from the field to Darwin LNG is now complete. And the third Barossa well has been successfully drilled and completed with better-than-expected reservoir results. And the FPSO vessel is on track to head to Australia in the first quarter of 2025. At full production rates, Barossa is expected to add approximately 1.8 million tonnes a year to Santos's expanding LNG portfolio. In Alaska, Phase 1 of the Pikka project is almost 60% complete and first oil is expected in the first half of 2026. The drilling program is now onto the 1112. 6 wells have been stimulated and pulled back with encouraging results in line with predrill prognosis. Pikka is a low-carbon intensity project that will be net 0 Scope 1 and 2 emissions from first production. And our strong base business continues to deliver with record reliability in PNG. The Angore well is coming online later this year and record production rates in Queensland across our CSG operations. And in Western Australia, we are safely and efficiently delivering on our decommissioning program. The base business provides a foundation for reliable production and cash flows to support returns to shareholders in accordance with our capital management framework. Our unrelenting focus on sticking to our strategy and implementing our disciplined low-cost operating model has delivered consistent results and kept the business resilient and performing strongly over the last few years. We continue to generate strong free cash flows from our operations to maintain the strength of our balance sheet and to provide returns to our shareholders. Thank you and we're now happy to take your questions.

[Operator Instructions] The first question comes from the line of Dale Koenders with Barrenjoey.

Kevin and team, maybe just firstly on Slide 14 and 15, when you've shown quite a strong step-up in free cash flow outlook for the business, potentially up to as much as $4 billion to $5 billion per annum. You've spoken about more like $1 billion per annum being the right sort of level of growth CapEx longer term. I just question if 40% payout is the right level. Those numbers suggest something more like 75% is sustainable. Just wondering, is this level right and when is the right time to reassess if you should be returning more capital to shareholders?

Yes. Well, this is -- thanks for your question, Dale. Look, this chart is based on the free cash flow across the business. Of course, the capital management framework is focused on free cash flow from operations which is typically the higher of the 2 numbers as opposed to the all-in free cash flow. And so that does deliver a higher return to shareholders. But what I've always said is that I would expect us to review and review that capital management framework as we see the production from Barossa and Pikka coming online. And of course, that's not a decision for me. That's a decision for the board to make. And so I'm not going to predict what that will be post that production. But I think the point really is that you can see that the company becomes a lot more cash flow accretive as these projects come online. And the room for that to increase shareholder returns especially the headroom starts to be treated within the business. And you're right, I've spoken about being very disciplined on the level of capital that we invest or reinvest in new projects. And with that, we should always be looking not only at the various projects and the optionality we have across the portfolio to compete against each other for whatever capital is made available for reinvestment. But those reinvestment options should also always be compared against returning that cash flow to shareholders, whether that be through dividends or buybacks. So I think to your point, the answer really is that, as always said, we'll review the capital management framework when we get Barossa and Pikka online. And I would also remind that the current policy states at least 40% of free cash flow from operations. It's not definitive at 40%.

Okay. That sounds exciting time in the future. Maybe a second question for your CFO. Just market seems to have focused on the higher operating costs that have come through in the segment. And I suspect this is Northern Australia and Energy Solutions business OpEx. Can you provide some comments on what these are and how long these sort of costs will continue for? Or if there's a level of one-off associated with them?

So production costs are a little bit higher in the first half. There's a couple of things that are driving that. If we look at some of it, is the timing of maintenance activities, particularly in the Cooper Basin in Queensland. We've had some extreme weather events that have given rise to increased maintenance costs as well across the field and a little bit of inflation has popped through there as well. So that's sort of what's driving pod cost increases from a nominal perspective, they have decreased with the pivot from the Northern Australia assets from LNG production to domestic gas production as well which has decreased production costs overall. But on a unit basis, we have seen increases across Cooper and Darwin CSG assets.

Yes, maybe I can just add a little bit on to that, Dale, because those costs in the Cooper Basin, particularly and Queensland related to extreme weather events are very much in that one-off category. And we had to replace roads. The pipeline got washed out due to those severe floods earlier this year. And that did have a big impact on our costs in the first half. And some of that maintenance stuff that Anthea is talking about, where we've accelerated activities to line up shutdowns to be more efficient, you should see some of that coming back off in the second half of the year.

Okay. And the $30 million of OpEx in Northern Australia, is that domestic gas related, so it's -- it will kind of stop once LNG starts?

That's right. So that's to run Bayu-Undan. So Bayu-Undan, obviously, the offshore fields need to keep running. What we've seen from this last half of last year to the first half of this year is the pivot from LNG production to domestic gas which means the gas quite fast as the LNG plant. So you don't have that cost in your cost base anymore.

Next question comes from the line of Tom Allen with UBS.

Just following up with the last question on costs. Just wondering if you can share a comment on any initiatives to drive lower corporate costs. And then secondly, on production costs, we can see over in GLNG, the horizontal well drilling program at Fairview yielding some strong outcomes looks to be helping the joint venture equity gas production to cover some expiring third-party purchase gas. Could you share a comment, please, on the production cost outlook in GLNG, just given there's more activity and some higher-cost wells being pursued?

Let me start on the operations, first of all. There's a lot of initiatives across the business to drive down cost. We've seen inflation. There's no doubt we've seen inflation, inflation globally come through in the cost base just as all of our peers have done. And the challenge we give ourselves and the organization is to try and absorb that. And so I look forward later this year to share with the market our plans, particularly for the Cooper Basin, where Brett and the team have been working on a reset strategy that will focus future developments very much in the central areas of the Cooper Basin and less activities in the more peripheral fields, the more expensive, higher cost fields, that logistically are much more challenged to support. And so you're going to see a much more targeted investment around the central part of the Cooper Basin which will help drive our cost down. Of course, our electrification activities will be ended and those costs that we're incurring just now will come to an end which not only means that we should see higher reliability where we've electrified and lower maintenance costs, we'll also see more gas sales because were not burning gas for power. And just on that focus area in the Cooper Basin, that also includes a lot of our development spending then in areas such as the Moomba South and the Granite Wash fields in the central areas of the Cooper Basin which more than 90% of our future reserves for development are located. So that's pretty exciting and we'll share a lot more detail on that later in the year. In terms of CSG, yes, the horizontal wells are breaking new records and you can see that production dropping up all the time. But in other areas like number of wells serviced and supported by operators, these metrics are all heading in the right direction. So our challenge here is to keep the technology advancements, the well advancements, the efficiency improvements and the automation that many of you will have seen as you've visited our operating center in Brisbane, where we can run a lot of these wells remotely. We got to keep that at the pace of inflation. And that's the challenge we all have in the industry. But I'm very comfortable of the plans in place that you'll see some of those improvements as we go forward. But it is plain to see that CSG production continue to climb. Every month, we're creating new production records for indigenous production at GLNG. And of course, we think of the Cooper Basin as the fifth field for -- or the fifth asset supporting GLNG, given that 90% or so of the gas goes to LNG. And so it's in our interest also to keep driving those Cooper Basin costs down. In terms of corporate costs, we have very significant initiatives in place. After the recent merger with Oil Search and the previous acquisitions we made in the previous 2 years, getting the corporate center right to support a much more global business and be a low-cost efficient corporate center is very much top of my mind. And we have various projects on the go right now, where we're automating and moving to a regional organization was the first step in that process last year. And I think you'll see those corporate costs coming down quite significantly over the next 18 months or so.

That's clear. Now if I could sneak another 1 just in PNG. I was hoping you might be able to guide on when we will hear a revised development concept and CapEx estimate for Papua LNG? And should we expect that in likely cases, the preferred development concept continues to see around that 2 million tonnes of Papua LNG raw gas told through the PNG plant. That assumption obviously guides the timing of Santos's share of Penang [ph] CapEx. So any comments on that CapEx sequencing would be helpful.

Yes. Look, I mean at this point, Tom, I'd assume everything is in the same order. I mean we're working with the joint venture partners on Papua to reset the FEED phase of the project, as you're well aware. And the best estimate I would view right now is that the joint venture will be looking to line up an FID decision towards the end of 2025. So that's pushed that out from the original plan which would have been end of this year. And so end of 2025 for FID. Concept at this point is largely the same. There are optimizations, design optimizations that we're working with the joint venture to reduce the CapEx of the project. But effectively, the 2 million tonnes aspect is the same. And so you can count on that. And everything just slips a little bit in the -- on the long-term supply plan. No real change to the order in which you can think about those CapEx commitments.

Next question comes from the line of James Byrne with Citi.

So Slide 15, the free cash flow outlook, thanks for providing that color. With the free cash flow I adjust for your assumptions is probably settling a little bit lower than what we have in the long term. And look, maybe that's just me. And I'm not sure where you're at for your understanding of where the market is. But perhaps, there's a good opportunity just to get a bit of a health check on a couple of segments over that sort of medium to long term and their contribution to cash flow. In particular, PNG, I get a little bit worried about when big fields like Hides go into production decline. So I'm interested to hear whether you think that Hides will hold up out to the end of the decade or whether there's a bit of production risk, particularly of Papua LNG doesn't take a timely FID. And WA Gas which I think maybe there's an envelope of uncertainty there about how much free cash flow that commits and what the abandonment profile and costs might ultimately look like.

Okay. Well, Anthea, do you want to go first? And then I'll try and fill in.

Yes. So I think the point to make on the cash flow yield side is that it's only committed projects, so it doesn't include Papua or anything like that. I think the decline rate on Hides is just -- it's 1 of our corporate assumptions. It's not something that we've put out into the market as yet. From a WA Gas perspective, we're really focused on that maintaining a strong free cash flow contribution. And part of that is really phasing and sequencing the decommissioning spend to make sure that we're doing that over a period of time in a campaign manner and working with regulators to appropriately spread that cost on a more average cost over time. So that might be perhaps a difference to your models, some of our assumptions there.

Yes. I mean I think on that WA stuff, it's Vince has done a fantastic job with the team over there at sequencing and lining up those activities. And the plan there, James, is absolutely to run that business cash flow positive. And so to be tailoring the profile of decommissioning activities so that it's self-funded and there's a bit left over at the end of the day. But -- and they've done a great job this year executing the campaign so far. We've got a lot of activities behind us already and we'll continue doing that over the next year or so. So you should see that CapEx really drop off a bit next year. But certainly, the year after that and be much, much smoother over the longer term. There's a bit of a peak this year in that decommissioning which was unfortunate given that lines up with our higher growth CapEx commitments over '24 and '25. But you'll see that come off quite quickly and get to a more steady state level beyond that. And in terms of PNG, it should be noted that the Hides field has shown some decline. But 1 of the really pleasing things over the last 1.5 years has been the improved operational reliability in PNG. We were now over 95% reliable on our PNG operated assets. And what that has done is help us to produce more gas out of those assets to make up for any decline in Hides. And that's why we've been able to retain relatively strong or maintain relatively strong production while we wait for the Angore fields to come on later this year. And so yes, that has been a really pleasing improvement. I mean the historical reliability levels on those assets and PNG was less than 80%. And so to get them up to over 95% has added additional production volumes to our operations.

Okay. So picking up on the comment just around WA cash flows, a bit of cash flow left over at the end of the day, I think you said. It's probably inconsistent with most of the rest of the portfolio. How do you think WA gas fits within the Santos vehicle over that sort of medium term once you get through those cash flows? Does it still make sense for you to own that sort of business?

Well, look, I mean, I think our strategy is very clear. We're focused on developing LNG opportunities and some associated liquids. And of course, we've got Alaska growth project as well. We are 85% gas in that mix and we sort of like that for the long term. So Santos's future will be built on a gas and predominantly LNG thesis and we're very focused on developing that business. We see the demand for gas remaining strong and, in fact, potentially growing to 2050 and beyond. And so we want to be in that. I think what you've seen us do in the last year or so is challenge our WA business to get a much more balanced activity program for the next few years to make itself a self-funding cash flow positive job. You saw 200 positions being let go earlier this year, as Vince was rightsizing for that future and is continuing to drive to optimization in the long-term planning and activity planning for WA. So I expect to see more optimizations as we go forward. But the challenge for WA really is how does it develop its strategy going forward. In fact, with the corporate strategy. But today, it's part of our business and we're very focused on running it efficiently, cash flow positive. And as I say, making sure it gets the best outcome for our shareholders. In terms of whether something fits or doesn't fit longer term, we'll announce that when we make a decision on any asset acquisitions or disposals.

Okay, great. So the second thing that I wanted to ask about, the slide prior, Slide 14 again, with cash flows. It's the footnote about which unsanctioned growth projects you include and you've got Papua LNG in there and Narrabri. And I was perhaps a little surprised to see those in there, particularly Narrabri. And I just wanted to understand your thinking around that. Like is the inclusion of those projects a reflection of your capital allocation priorities or your expectations on the likelihood that those projects can take in FID? Because, of course, the other 2 projects is the second phase on Pikka where the subsurface is de-risking quite rapidly based on what you've disclosed today. And secondly, Dorado, where lease negotiations on that FPSO come good and you've got a line of [indiscernible] commercial return on that oil project that, that would probably be a better use of capital versus, say, a Papua LNG where costs are rising and slopes are falling?

I'll answer that. So I think the data set here, don't read anything into it. What it does demonstrate is the optionality in the portfolio that we have in front of us. I wouldn't read anything into Dorado being omitted as well. Dorado cash flows based on our FEED ready in '25 would come in towards the end of 2019, so they weren't material to the numbers that we're showing here in '29 which is why we didn't put that project in just from a materiality perspective. But the other projects there are really reflective of the options we've got in the portfolio.

And I think that's an important thing here. It's the optionality. And like I said earlier on, each of these projects will be competing for capital. And you can add to that something like Bayu-Undan CCS project. They have to compete for capital. And we'll have our own constraints on how much capital we want to reinvest. But as I said earlier on, also, I think it was Dale's question, the test is not only against each other. It's against better usage for that capital. And if that's -- it was a better use of capital for dividends or buybacks, that will be considered. And those investment decisions. But I think we can say very confidently, we'll not be doing all of those projects at the same time and certainly not at current equity levels. And so that's just optionality we have as we go forward. I think we've been -- I would never want to be the person predicting where Narrabri is going to take FID. I think we've been working on that project for 14 years. It predates me by quite a period of time. And so I'm not going to predict when we'd be ready to FID that project. But I think what is important is that we understand that whether it's Dorado, Papua, Narrabri, Bayu-Undan CCS, etcetera, they're competing for capital. And so equity levels and the CapEx requirements for each of the projects will be very important considerations when we get to any of those decision points. And FID ready, being FID-ready does not mean we take FID at that point in time. So we're getting it to a design confidence level that puts us in a position that when the time is right, we can take FID.

Next question comes from the line of Adam Martin with E&P.

Just another follow-up on this free cash generation. I mean there's really an opportunity for the Santos to differentiate versus peers in the next couple of years. It will come down to what you want to go and spend on. Can you just confirm Dorado that, that historical guidance will only push forward if you sell down from the 80% stands in place, please?

What I would say today, Adam, is the CapEx expectation that I have for that project, 80% equity level is too high. That's too high for me to go forward on. And so we would have to reduce our equity levels before I'd entertain take an FID on Dorado. And so we'll continue to develop the project with our partners and look to do that before we'd ever take FID. But that doesn't stop us getting it to a readiness state which makes it easier, of course, to sell to other parties. And given the fall starts we've had in Dorado, we shouldn't kid ourselves, right? It's pretty hard to sell down something that nobody believes you're going to develop. So we've got to build confidence in that project before that would be the case. And likewise, in Narrabri, I think we're 100% now. In fact, I know we're 100% now. And so before we take FID in that project, that would be something we would consider as well, albeit a significantly lower CapEx project and how we finance these projects also, I think, to be part of our consideration when we get to that FID readiness level on those projects. But in the case of Narrabri, if all of the stars align tomorrow and we got all of the approvals and all of the support we need to FID, there's still work to be done to get to FID ready and we would have to do that work. So look, all I think -- it's important to emphasize about this chart is this indicative. It does not include unsanctioned projects. And we're listing unsanctioned projects in this park is really just to show the optionality we have for future opportunities. And there's no order of preference determined at this point in time or indications of when we would actually FID in this, other than the indication I gave you earlier on Papua.

Okay. And just second question, just sort of learnings on the drilling thus far at Alaska. It looks like that project construction is gradually coming forward. But just can you talk through the learnings on the drilling? Anything you're learning about Phase 2 as well, please?

Yes, sure. Good question. It's not only on Alaska. You can put Barossa into the same case. There's been -- these are big wells. These are big challenging wells. They're breaking records in terms of ERD sort of levels of complexity in these regions. And there's no doubt there's been a learning curve in both projects. But it's really pleasing to see how quickly the teams are adopting the learnings and getting up that learning curve. And these long projects where you've got a lot of wells to drill, I mean Barossa is only 6 but Alaska's 26 to first oil but there's more beyond that, of course, when we get into the sustaining part of that project. It's very important that you lock in these learnings and you incrementally continue to improve the drilling and completions performance of these wells. So really pleased that you see the last well was almost at tech limit. I mean it's a really, really excellent performance, very low NPT levels with our contractors. And we've got a very good well result as a consequence. We want to see more of that now. We've got 10 wells in. We're halfway through the 11th well. 26 wells required to first oil as part of the plan. And so there's a lot of opportunity now to start seeing some gains as we go forward. We can continually turn in performance like we just have done, I think to be fair to the teams, it's been a nightmare for them given that my ex drilling background and I'm always on the case on this one. But I have to say, I've been really impressed with how they have responded and how quickly they're coming up the learning curve. Now what does it mean? It means that, ultimately, as you go forward and you think of new development opportunities, Phase II or whatever in Alaska, you can start to think about lower well costs. And given that well costs are a big part of these projects, that's why it's important to learn this stuff and understand it and be able to create the value from a low-cost efficient drilling group. These really are drill bit-led developments at the end of the day. So the lower cost you can do it, the more value you create from these projects.

Next question comes from the line of Saul Kavonic with MST [ph].

Kevin, I know we like to look at what you put out today and compare it to what you put out previously. If I can just look back at that Slide 14, I think it was a few months ago, you put out a free cash flow outlook in 2028 which was at the top end, $5.1 billion. You've now put out a free cash outlook for the following year in 2029 which is only $4.7 billion at the top end under the same price deck. Can you confirm if the previous 2028 outlook of $5.1 billion is still valid under those assumptions? And if so, why is the free cash flow dropping about $400 million over the 12 months between 2028 and 2029? Given by all accounts, if anything, on your assumptions, prices are going up and production is going up from year to year then.

Good question, Saul. And you're right about those 2 packs. And maybe we should just stick with the same year on each chart, when we put these packs out. So it's a lot clearer in future. Look, it's actually quite simple in this case. It's really just a change in gradient. I’d have to go and check what the 2020 number is what I can tell you. But what I can tell you for this chart, I mean but what I can tell you is it's really a reflection of Papua slipping a year. It's the impact of that pushing out a further year and some of those cash flows being pushed out. That's the biggest single driver. There's a few macro impacts on that. And I think the other one, too, that would have changed since last year's chart is the -- this sale down to Qumu. That we baked into these numbers here as well. So that's the sort of 2.5% of equity in PNG LNG that will be sold to Qumu. Anthea, is there anything on that?

[Indiscernible].

So that would be the biggest sort of movements from that previous guidance. So just reflecting the slippage in the Papua and the sell-down to Qumu and PNG LNG.

Okay. So I mean, I guess, to take that, it does mean that the '28 numbers is going to be significantly less, so perhaps below 4.7 versus what was put out 3 months ago on the new assumptions basis and the slipping of Papua?

Yes. And that is just largely because of the slipping of Papua which is a more recent event.

Yes. So the way to think of it, is if you look at that chart, Saul and you've got the 2027 $4 billion number, this is Slide 14, right, then you just think of that gradient going across those 2 years to 2029. So the cash flows have just moved out in the future.

In the 2029 guidance you've given today, is that now including close to a full year of Papua in 2029? Or are you assuming Papua is actually only starting partway through that.

Starting into the year and assume a ramp-up profile for new projects that ramp up over several months, as you would be familiar to West and sort of LNG ramp-up and other projects you've seen over the years.

Understood. Second question on Barossa. You said everything is remaining on track in terms of CapEx and timeline guidance. Of course, a big part of the CapEx is actually in the floater with BWO which is amortized over a lease. How is progress on the FPSO going? Is there any risk that there's cost flow out there which could see those costs amortize over the lease? So you're still maintaining your CapEx guidance but we'll be looking at higher OpEx post start-up than previously guided?

Good question. That -- the CapEx doesn't directly relate to the lease rates. So there's no kind of follow-through or spillover through those contracts, so it does not automatically mean a higher lease rate. The biggest risk really on the OpEx side has more to do with inflation, EBAs, that sort of thing that we see on all of these operations and that is something we have to be very focused as we go forward. Any lease operation where you've got an external workforce subject to EBAs and other companies' agreements, of course, that is a watch area for you. That is the biggest exposure there. There is no contractual flow-through from the EPC contract to the OpEx contract.

Is there still a risk factor if ultimately, if contractors end up under pressure, they tend to try and renegotiate things towards the end?

Well, not only do they try to negotiate things to the end. And of course, you're speaking to an ex-CEO of a contract, right? We also often see mainly in the CapEx projects, of course, where that happens. I think what you're more likely to see is your contract or taking a 15-year view on this. It's a 15-year lease contract and OpEx contract. And any changes in that regard would be fairly minimalistic, I would have thought, in terms of the value impact they could have over 15-year period. And we're talking about a cash cost of production here between $2 and $3 per MMBtu for Barossa when it comes online. So even if there’s a 10% increase in the OpEx rate, not that I'm suggesting there will be, I’m saying if there was, I don't think that has a very material impact on the value of the project. The one thing I would say though is I would fully expect in the current climate where we've seen inflation everywhere else, we will see some inflation come through in some of those numbers.

I guess following on that, I think the previous guidance, particularly when you took FID, was the ongoing cost once it was up and running would be under $2 a MMBtu. You now said it's 2% to 3%. I mean, what's driven the increase there?

Well, the guidance I remember giving out was $2.30 back at FID per MMBtu. However, what has driven the increase really is safeguard mechanism compliance. And that -- the fact that we've had to factor in the cost of carbon from day 1 rather than from when we thought the CCS project that we're hoping to build would come online has had an impact on that cash cost of production. So basically, we've done the cost of CCS which we wouldn't have done it that $2.30 mark because it was not FID at that point in time, when we took when we took FID on the Barossa project. But that's the difference. It's the cost of carbon which is added a bit of OpEx. We look at that as an OpEx cost.

So think the market has factored that 1 in already. Coming back to like looking at the '29 and I guess 2030 will be similar, the free cash flow you implied, free cash flow you provided on Slide 14, looks significantly higher than the free cash flow yield all in on Slide 15. Can you explain what's the major difference in spend between those 2 slides, given Slide 15 shouldn't actually be including any major growth CapEx in those anyway?

That's right. So if you look at Slide 15, this is just our committed. So all that's really showing is the cash that the business will spin off if we made no more investment in projects going forward, we just completed the projects that we have in front of us for [indiscernible] CCS for offer pickup. The other slide has got the prospective projects factored in as well.

Okay. Understood. If I look at Slide 15, what drives -- we're seeing free cash flow ramp up about 500 basis points between 2027 and 2030. What's driving that?

The construction should be -- that would be Pikka ramp up from 26 to 27 before a close. Barossa should be fairly stable. The other thing would be just your assumptions around commodity price inflation.

And I'm going to squeeze one more. Just on the Pikka, some of those initial wells are quite good. The last few wells you've seen, are they tracking at P50 or above? Or is there risk to the downside from those most recent wells?

Look, I mean, I think all the wells are pretty much on average, some are slightly above, some are slightly below. But I think we -- as per the comment this morning, when we look at the field today, everything's on track and in line with our average expectations across the field. Some of them are water injectors remember as well. So they're not all production wells. But yes, I mean, everything is on plan. And as someone said in the call, earlier today, we're pleased to see that de-risking of the reservoir as we go forward now in the confidence building.

Next question comes from the line of Mark Wiseman with Macquarie.

I just wanted to get back to the ranking of the unsanctioned growth projects. It strikes us that Papua is somewhat out of your control, not being the operator. That may move forward next year, may not. And Narrabri is a smaller project. It seems to us that a face-off between the 2 oil projects, Pikka Phase 2 and Dorado as it was 2 years ago, when you chose to take FID on Pikka instead of building a new FPSO for Dorado which was the right decision. Could you maybe just flesh out between Pikka Phase 2 versus Dorado, is there any sort of timing considerations on work crews in Alaska and contractors or licensing in Australia on Dorado? Are there any things that sort of drive either project to be sooner rather than later.

Thanks, Mark. Look, I mean, there's a lot to that question. Look first of all, all of these projects are competing for capital on the basis of the returns and the best projects should win. Particularly but you look at projects like Dorado which is a sort of stand-alone, it's a stand-alone project. And to fit with our strategy, doing a standalone oil project doesn't really fit with our strategy. So it's really about gas development for us. And we've got to evacuate the oil to get to the gas. And there's about 0.5, 0.6 Tcf of gas in the Dorado field and Papua combined. But ultimately, it's looking for the gas in the Bedout Basin. And we believe there's potentially a lot of gas in that Bedout Basin. As I say, in the southern part where we've been drilling, we've been looking for gas and we find oil. Our expectation is as you go further north, there's a whole lot more gas in that deal. It's about unlocking that gas and maximizing the value for that gas. So it's not only about the cost of developing Dorado. It's about the access to the markets we want to get for that gas. And then that's going to be compared as you see against something like Pikka Phase 2. But don't rule out Narrabri. Narrabri comes up on the outside lane and it's ready at the same time, then it's competing for that capital. And depending on the macro environment and how you guys all treat us, we might look at a buyback as a better option for the capital at that point.

Okay. That's great. I just wanted to ask another 1 on the LNG book. Could you maybe just give an update on Barossa into production 12 months from now, roughly, that Hokkaido deal looked like a win-win deal for both parties and sort of took away some of your spot exposure during this potentially risky period over the first few years for Barossa. Is your intent to sign more contracts between now and first gas from Barossa? And is there any ideal level of spot exposure on the project?

This is the operator. We have temporarily lost our connection with presenter. Please hold the line, the conference will recommence shortly. [Technical Difficulty] This is the operator. The presenter line has been reconnected. Please go ahead. Apologies, I believe we lost the line. Are you still on the line?

Yes, I'm here, Kevin.

What did you get from my answer?

I didn't get any of it, I'm afraid. I was asking a question just on the LNG exposure from Barossa and just the Hokkaido deal looked like a good deal but still the majority is sort of gas hub pricing linked. Any commentary on signing more LNG deals between now and first gas?

Well, look, I mean I think we said previously back at FID for Barossa that we were looking at a 75-25 split. And so I've adjusted that over the last 18 months or so to talk more about aiming for a long-term [indiscernible] medium-term split of around 85% to 15%, 15% spot to 85% contracted and that being predominantly oil price-linked and contracting. And the Hokkaido contract, we think it's a great contract for both parties, a lot of flexibility for the buyer. We've got a competitive price. And we're really excited about the relationship we're building by an end user customer like Hokkaido gas. And 1 of the things to understand about how Hokkaido Island and I'm sure there's a few skiers on this call, who would travel to Hokkaido, there are only 8% of their energy is gas. I think it's something like 24% oil, 49% coal and 8% gas with some nuclear and renewables making up the alternative. So there's a lot of opportunity for more gas to come into that system as part of the decarbonization strategies in Japan. And so we're very excited about the relationships that our marketers are building in country, allowing us to grow that business. And other prospects or more like that, we'll announce them and when we do them. But I think it's important to recognize that Santos' portfolio of LNG from both PNG and Barossa has got high heating value because of the liquid rich nature of our gas. And that makes it very attractive for Japan, Japanese customers where heating value is a significant part of their requirements.

Next question comes from the line of Nik Burns with Jarden Australia.

Kevin and Anthea, look, another question on your Slide 14, the free cash flow. I'm more interested in the 2027 year. By that stage, your sanction growth projects are online and I think you made a comment, Kevin, that you should use the same years on the same chart. But previously, you did show 2026 year. I appreciate there's probably a bit of ramp-up happening there. But just curious as to why you didn't again show 2026. Just wondering if there's any inference here around the Pikka project in particular, maybe with the wells that the ramp-up phase might be taking longer. So maybe the free cash flow in '26 may not be as strong as you previously thought and that's why you're showing a year later here?

No. And so don't read anything into that. What we were trying to do there is just move it to a full first year. So we remove any of the concept of ramp-up assumptions because obviously, there will be a ramp-up for Pikka over 2026. So we just wanted to show a clean year. That's why we showed 2027.

However, what I will add, Nik, is that we did communicate previously that after the winter season concluded in Alaska, we do a full review of the project to look at whether we thought it was possible or not to accelerate first oil on that project. And as is our normal governance process on these major projects, when we get to the 50%, 75% marks on these projects, we conduct thorough reviews to look at cost schedule, all of that sort of stuff to make sure that our guidance is accurate and all the rest is and if we have to, we update. And that's what we did last year in Barossa, you'll recall at that point in time. And what I would say is given the very high productivity we saw where we were able to install all of the vertical support members, the VSMs that support the pipe, these are the structures that support the pipe above ground in Alaska, we managed to get all of that done in 1 winter season. And this project was designed to be executed over 3 winter seasons. And the original plan didn't have all that occurring in 1 winter season. So having that done gives us the opportunity and we can't say whether it has arisen yet but we will at the end of this review determine whether it's possible to do all of the infrastructure activities in 2 winter seasons which would then allow an acceleration of first oil potentially as early as late '25. So there's an upside opportunity there. We're not committing to that. I'm just reiterating what I said previously, what we're going to do in terms of that review. And at the end of that review, if there's any change to our guidance on cost schedule or whatever, we'll give you that. But there's some upside opportunity as well because of the very high productivity that the guys were able to achieve during that winter season which makes my previous comments all the more important about the drilling learning curve and getting as many wells in the ground ahead of that first oil date.

Got it. So do you have a timing for that review? When can we expect an announcement on the outcomes of that?

Nik, you're killing me with that 1. But look, I mean, we're not going to give you any timing on that. The review is ongoing right now. That will occur over the next month or so. And then we will review the results of that and if there's any changes, we'll update the market as we would just as good governance.

That's great. And maybe just 1 more for me. I'm just interested on an update on your offshore CCS projects. I understand you still need to get the regulatory and fiscal settings right here as potentially bringing in third-party CO2 volumes but you're still targeting FID ready next year. Just wondering, at what point can you give us some more details around the technical work scope required to actually make these projects real and happen in terms of costs and timing, etcetera? Yes, is there anything you can tell us? And is there a drop in date for these projects where you need to make a call on whether they're going or not? Appreciating the fact that you've got the infrastructure there, particularly offshore, that may need to be decommissioned at some stage?

Yes. Look, I mean, the -- there's a lot to unpack there, Nik. But the offshore project you're referring to there is Bayu-Undan, of course and that's the big 1 for us. We're very excited by that. We've got a lot of activity going on within our Energy Solutions Group, looking at, in fact, a number of MOUs with potential suppliers, CO2 from Korea, in particular but Japanese interest there as well. And of course, we've got the Barossa CO2, it would take and there's some other CO2 emitters in the region that we're talking to. So we believe we can take up to 10 million tonnes per annum of CO2 through that pipeline, back to Bayu-Undan. As my gut tells me, you'll start to see that accelerate a little bit once we get Moomba CCS Phase 1 online. And that's a very strategically important project to us because it will build momentum, I suspect, across these other projects. Bayu-Undan is the next big project we really want to focus on. It's a material project in terms of the amount of emissions it can capture and third-party emissions that it can capture and that's very exciting for us. And then it should be for anybody whose objective is to decarbonize the planet. In terms of costs, yes, we haven't given any guidance on that. We're 90-odd percent complete on the FEED process and for Phase 1 at Bayu-Undan. And I expect in Q4, we'll complete the FEED process. And from an engineering readiness point of view, there will be some engineering work we might continue. But effectively, that shut down -- that will then shut down waiting on the commercial side to progress to the point of readiness for FID. And of course, the regulatory side. What we saw on that legislation and regulatory side last year was the government passing the London protocol through Parliament and through the Senate. So we've now got the legislative structure in place to support the transportation of CO2 across borders. There's a lot of work going on with multiple governments about bilateral arrangements for the transportation of CO2. There's a lot of work behind the scenes with different governments really working hard to get that in place. But we're sort of at the behest of the regulatory frameworks developing. And until they are in place, we can't FID. We're not going to FID until we have regulatory certainty. But we'll be ready to go. And of course, in the meantime, we've got to offset emissions rather than capture and store them permanently on the ground until that point in time. And so I think we said at the full year results that we got arrangements in place now contracts in place for the procurement of a few years of [indiscernible] to cover a few years production. And so that covers the first 2 years until it comes online.

Next question comes from the line of Mark Busuttil with JPMorgan.

Kevin and Anthea, believe it or not, I'm not asking you about free cash flow or operating costs. I was just interested, Santos obviously made the newspapers just only about a month or so ago about ADNOC and ARAMCO. Could you definitively tell us whether you did have discussions or didn't have discussions with particularly ADNOC over a potential acquisition a couple of months ago?

Thanks, Mark, for the question. Nice question. I remember getting asked at a staff function a few years ago if we were going to try and buy or merge with Oil Search. And it was about 4 days before it broke in the media that we were doing that. And I said to them, why on Earth would you think I could ever answer that question in front of 500 people in a home? And I'm sure you don't expect me to see had conversations with anybody about acquisitions or not. And so we would never comment on any conversations or we have. But what I will say is we look -- we talk to companies all the time about opportunities to develop resources, to develop relationships, to look for opportunities where we could collaborate to create value. Other than that, I would never comment on anything else that comes up in any of those conversations, unless there was something to announce. And that's the way we've always tried to manage these things. So I don't want to lead to speculation or add to speculation. And so it wouldn't surprise me, people are looking at Santos so because we've got a world-class LNG portfolio. So the fact that those rumors get generated from time to time doesn't faze me. We stay focused on what we can control. And everybody knows where our front door is, right? And they know the phone numbers. So if they want to come and talk to us, they know how to get us. In the meantime, we're staying focused on what we can control and that is to deliver on our strategy.

Okay. And just on the other side of the coin, what is your own inorganic growth strategy? Are you actively -- do you see opportunities, I guess, in consolidation in the industry? Are there areas where you would look to make acquisitions, large or small? Can you give us a bit of a sense around that?

Well, I mean, we're not going to announce anything we might be considering or we might consider in the future. What I can tell you is there's a myopic focus within the company right now to deliver on our major capital projects that we are currently executing. And that's the way I want the organization to be focused over the next year, 1.5 years, where we deliver on these projects. And create the sort of next-level of Santos, if you like, that comes out of that. Any M&A that occurs before, during or after that point in time, we'll talk about if and when there's something to talk about. But at this point in time, nothing to talk about. Our focus is on delivering our projects.

Next question comes from the line of Henry Meyer with Goldman Sachs.

Can you expand a bit on the outlook for PNG? Last November, you shared the forecast production decline from the existing PNG fields which would, of course, be backfilled by Papua which is now fast in delay. Are you able to step through just any opportunities that could come forward to offset that delay and kept the trains a bit fuller over the next few years?

Sure. Yes. Look, I mean I think I got all of that question, Henry. If I missed anything, please feel free to correct me but I think you're asking if Papua was delayed. If there's a decline, how would we cope with that? Well, of course, what we've done this year is we've seen a little bit of decline through the Highfield as we'll be locking the production from our own operating fields and producing a lot more gas into the PNG project from our own assets. And so that's helped alleviate some of that decline while Angore was delayed. With Angore coming on in Q4, however, we are very optimistic and confident that, that will cover us through to the next sort of development project. And the next big development project, of course, is planned to be Papua. And the assumption in that, of course, is that we have an FID-able project early '25 and that, that all fits in with the sequence. If that doesn't happen, that could potentially create a hole in the production until something like Penang or something like that came in. However, what we have as a plan B in that case and we're working on the development of that, is the APF tie-in which has always been there in the plan and that was pushed out a few years behind Papua because of the decision to go with Papua a couple of years back. But we will be working to have that available as an option. And that is basically bringing our own project gas, our associated gas from our own oilfields into PNG to fill that gap until Papua or Penang came on whichever order they were being developed. So we have a buffer in there and -- or a plan B, I should say and that's what it would be.

Got it. And it's reasonable to assume that would only be if Papua slips a bit further than late '25?

Yes.

And finally, then just to expand back on GLNG. It's performing well ahead of those major third-party supply contracts expiring. Are you able to touch on what scope and spend is required to drill or add processing capacity to keep exports flat?

Sorry, Henry, can you just repeat that, please? You broke up.

So just what spend and scope is needed at GLNG to offset the third-party supply contracts expiring over the next years?

Well, the primary strategy is to continue building our CSG production by developing our well stock. And that's what we're doing every year right now. We're drilling hundreds of wells every year to keep building that and you can see that growing. I think that they were creating over 17 -- sorry, 718 terajoules per day and digit production from our 4 CSG fields. Of course, we've got around about 150 terajoules per day coming in from the Cooper Basin as well every single day. So we will continue to build that indigenous production. But ultimately, the prize for GLNG is to find another field, to find another supply source. And we are working with the partners on options to do that over the medium to longer term, with the assumption that many of the third-party supply contracts will fade off during time. It will just expire as is the normal process heading into the contracts there.

Next question comes from the line of Gordon Ramsay with RBC Capital Markets.

I'm going to come back to cash flow. When we look at your operating cash flow, it came in below forecast and market expectations and 1 of the key reasons for that appears to be significantly higher restoration cash expenditure. I think it was up $152 million year-on-year. Just taking into consideration your comments earlier, Kevin, where you're saying this is a peak year and we'll reach steady state level after that, can we expect the commissioning restoration cash costs to stay at the same level in the second half of this year and then start to fall into 2025? Can you give us just a feel for how to model that going forward?

I think they'll remain strong this year. So we had about 350 or so in the budget for this year, tailing down over next year. That will be a little bit higher -- not higher than this year but be higher than we would expect on average next year and then it will [indiscernible] down to a more reasonable level. And as Kevin said earlier, strategically and structurally, what we're trying to do in WA particularly, is make sure that we're phasing and sequencing those campaigns, so that we're spending kind of same amount. We're chipping away at those obligations. We're doing it in a measured and disciplined way to really balance that out across the portfolio.

And I think it's important also, Gordon, to do it in a safe way. And I think when you've got too much -- too many different vessels doing too many campaigns at the same time in a very hot economy with few employment, that creates other risks that we don't necessarily want to be taking safety risk. And so getting that steady state operating a multiyear program in place has been a priority for Vince and the team over in the West and they're doing a great job of sort of mapping all that out right now. And I look forward to giving you a better guidance on that towards the end of this year because it is a significant smoothing of CapEx of all wells in the future over what we might have thought that was going to be only 12 months ago.

And just a question on the statement that you had a better-than-expected results from the third Barossa development well. If you continue to get good results and let's say in the next 3 wells, so that has an impact on the performance of the project, from your viewpoint, maybe could you explain what a better-than-expected result means?

Yes, I know you're going to try and get me on that one, Gordon. And this is probably you rubbing your hands right now. But look, what I can say on the 2 wells that we've tested to date, as we've seen very strong flow rates. And I would say, overall, reservoir on track, on track. It's a good outcome. CO2, at the lower end of the range of expectation. And production, I'm going to say really bullish with it. The 2 wells we have today, if we run them at flat out, we could fill the train at Darwin with 2 wells. And drilling 6, of course. Now we're not going to run them that way because that wouldn't be good reservoir management practices to do that. All I'm just saying is that the well test data that's told us that we're getting really strong flow rates from these wells. The most recent 1 that we talked about, it was really the key H which you know what that means. So that deliverability of the well was something like 30% higher than predrill expectation. And so that's a very positive outcome. That just tells us this reservoir's high quality. And that would indicate a well capacity of around 300 million scuffs per day at max, so what we're seeing is very good reservoir outcomes. It gives us a lot of confidence. And as much as drilling was delayed very significantly on this project, as you are aware and that's hurt the project, fact is that we've got 6 wells we're drilling across the field. I'd be very confident we had 4 wells in the ground that got a lot of redundancy in that well stock. So yes, by year-end, we should have 4 tested and setting a very good place for startup in around a year's time.

Okay. Last one, Anthea, you're now recognizing the PNG LNG equity sale as an equity instrument and noncontrolling interest. Can you just kind of run through what changes have happened there? And is it just a reflection of the fact that they're now paying for their stake through the earnings that the project generates?

That's right. So what we've done is we -- it was an asset held for sale in the last set of accounts. We've removed that. So you'll see flowing through the account some catch-up depreciation for that held-for-sale interest which is no longer held for sale. It also -- what we've done is sold an interest in the subsidiary that owns that 2.6%. It's called Labana and that we sold about 59% of that. So we consolidate each [indiscernible] and then show the noncontrolling interest through the P&L balance sheet. That's the predominant areas. And when we do ultimately, [indiscernible] will either earn that remaining interest by way of dividends, notional dividends on that interest, or they will decide to make the final payment of $241 million and take that. And once they do take 100 shares [ph] in Labana, then we'll de-consolidate and it will flow through equity.

Thank you. Due to time constraints, we have reached the end of question-and-answer session. I'll now hand back to Mr. Gallagher for closing remarks.

Okay. I'd like to thank everyone again for tuning into our call and just say that I look forward to catch up with many of you over the next few weeks on our investor road shows. And we'll leave it at that. Thank you very much.

Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.