That's available to be returned to shareholders as well if necessary. Of course, we do that with a gearing range of 15%-25%. Nothing's changed on that front. Now to the Australian domestic oil and gas portfolio strategic review. There's really four sets of assets we've been looking at, and I want to take you quickly through what the outcome has been in each of those cases. I'm going to start with the Cooper Basin. Very important. Cooper Basin, I think we'd already flagged this to most of you in the market anyway back in February, but our priority here really is to focus investment going forward on the central areas of the Cooper Basin. Something like 85% or 80% of the resource to be developed in the Cooper is in this part of the Cooper Basin. That's the MCO project we FID'd earlier this year.
The contract we've signed with the South Australian Government, which Brett will touch on later on, is basically as a consequence of that MCO project. That will supply secure gas into South Australia for 10 years. 20 petajoules of gas was a very significant number. You can do the math. It's a very significant number for Santos, 20 petajoules of gas per year for 10 years to the South Australian Government. Importantly, through this work, with this reprioritization of capital, that will result in a reduction in capital spent in the Cooper Basin between now and 2030 of around $300 million during that period, then $150 million less CapEx spent in the Cooper Basin year-on-year thereafter. That's a consequence of really just focusing our capital around that central area of the Cooper going forward.
The way to think about the rest of it is basically we'll run that to meet our current contractual commitments, and then run it for value thereafter. When it comes to the collection of assets that we have, some of which have been stranded for some time in the Bowen, the Surat, Eastern Queensland, Narrabri, the Browse Basin, a spattering of assets all over the place. In very quick order, Eastern Queensland, Crown-Lasseter, Poseidon, deprioritized. Not going to spend any effort or money on those assets. Taroom Trough is being appraised by others. I don't know if you're all aware, we've actually got a fairly significant position in the Taroom Trough. We've not made any comments on the quality of the Taroom Trough.
We'll let other people run that commentary for the time being, but we're pleased that we've got a few farming arrangements where other people are drilling and testing that for us. We'll let that play out and we'll see where we get to as a result of that. With Narrabri, it's really about just focusing on approvals and continuing with that, but again, not spending any capital or overly exerting any effort on Narrabri. Some of these assets will be reevaluated once we've appraised the Beetaloo. For obvious reasons, if the Beetaloo works, it changes what we might want to do with some of those assets. There'll be less of a requirement in some cases to do anything with any of them, because the Beetaloo has a scale. In fact, I should have said that on the previous slide.
When we talk about being excited about the Beetaloo Basin, our acreage alone in the Beetaloo Basin has enough gas in it, we believe, has enough gas in it to supply 10 million tons of LNG and supply the East Coast market for more than 50 years. It's a phenomenal resource, Brett will take you through that later on this morning. It's all about the cost we can get it to the wellhead. Carnarvon Basin, possibly a more strategic asset in light of what we heard yesterday. Really the focus there is just pursuing low-cost tiebacks. The Halyard-2 well, which was supposed to be coming off production shortly, is performing like it was day one. We have seen no decline. It's 80, 85 million standard cubic feet per day of gas, no decline, indicating significantly more reserves than we ever thought it was going to be.
That's a really low cost. I think with production costs in WA this year around the $5 mark, $5 per BOE because, and it shows the value of bringing regular low-cost tiebacks. Another one we're going to drill there I think next year or the year after called John Brookes-7. A $42 million CapEx project, almost instant payback. We'll pursue those low-cost near-field tieback opportunities, and again, that's part of that business that's repurposed now to be a higher capital efficiency, low-cost, higher-margin business, essentially meeting our domestic gas obligations, whatever they end up being, and funding our decommissioning activities so that we're not dragging cash away from our three core growth hubs. When it comes to Dorado and the Beetaloo Sub-basin, I think the key messages here is through this review, what we've identified is the really strong economics of Dorado. Dorado's got strong economics.
Dorado's also a project that potentially has significant energy security advantages for Australia and for this region. More importantly for you, it's a very high IRR project. It competes very successfully against our growth hubs, effectively what we've done is we've lifted the Beetaloo Basin out and we've put that into the three growth hubs. That's an Australian growth hub, and we'll evaluate that basin and see if that's got the scale to warrant being part of that growth story going forward. We know what Dorado in isolation looks like, but Brett will show you the opportunity set across that basin. It's really about thinking about has that basin got the scale to compete with those other basins we want to invest in over the longer term or not? When it comes to those three regions, those three growth hubs that we're focused on going forward.
In Australia, this is just a good indication of the sort of things we're going to be doing over the next few years on that development pipeline. You can see in Australia the Beetaloo appraisal is a priority. We're going to drill three wells, hopefully, over the course of the next year, and test them for nine to 12 months to establish our type curves and determine the economics and the potential around that basin and whether it can work going east and going north. Very confident on the economics going north, but it's all about cost of supply, whether it can stack up to go east, because obviously it's a longer pipeline, and the pipeline cost would be higher.
As I say, enough gas there to supply 10 million tons in our acreage alone, not the basin, our acreage alone, 10 million tons, and the East Coast market fully supplied for more than 50 years. It's a phenomenal potential resource. We'll do that campaign, of course, in Dorado, and I should say the Bedout Basin. It's more the Bedout Basin than Dorado. Dorado's FEED-ready. It's ready to go back into a short FEED if we decide to do that. We'll appraise the Bedout Basin in 2027 with three wells. We're planning to drill three wells offshore in the Bedout Basin. All those costs for all that activity and all the activity on this page are in that 45-50 free cash flow breakeven number that I talked about earlier on.
In PNG, we've already announced the FID of the APF Tie-In project, which will provide additional gas to help combat any decline in production towards the end of this decade before the Papua project comes on. CPF expansion is another one of those projects that Brett will talk about this morning. Haven't FID'd that yet, but you can expect that shortly. With Papua LNG, I don't know if you saw Prime Minister Marape's statement yesterday confirming that Total had promised him or guaranteed him or whatever the words he used was in that announcement. Very positive statement saying that they're going to FID the project this year, and that's our understanding. We're aiming to do that in the second half of this year with the development forum that I know many of you are tracking, scheduled, I think, for July, August, to support that timing.
Of course, one that you will not have heard of is Mosa. Mosa is an oil project in PNG. While Brett will show you that we're continuing to do those little infill programs, which give us those little infill oil wells, high IRR, but not really big material adds, just keeping the oil business going, this is different. This is something that's 3 km away from our existing infrastructure within our production development license, so no new licenses required. It's a very significant oil play that's appeared after our most recent mapping exercises right next to those really high perm, high volume oil fields we had many years ago. If this comes in, this would be the largest oil play to be discovered in PNG in something like, where's Brett, 30 years or so.
A really exciting project right next to our existing infrastructure, at a time when the world's starting to appreciate oil again. It's a really exciting play that we didn't have on our books 12 months ago. This is really exciting, it's coming from the great work the team in PNG have been doing. In Alaska, Pikka's about to come online and start ramping up to its 80,000 barrels a day. Previously, we talked about Pikka Phase 2. I want you to rethink about that now as really just Pikka expansion. I'll be expanding that. The next phase of Pikka is expanding it to 120,000 barrels per day. We got Quokka, we just recently announced a very exciting appraisal well in Quokka, Bruce will take you through that. What's exciting about that?
Our Pikka oil is currently getting a very strong premium to Brent. I've not got my specs on, but this is the Pikka one. If this goes missing today, it's $110 a barrel, right? We've worked out the volume in here. We can tell you exactly what it costs, right? We'll be hunting you down for the money if this goes missing. I want to pass this around the room because what's exciting about Quokka is when you turn it upside down, you see how dark the bottle goes, and that's an indication of the viscosity of the oil, right? We know the flow rates we get from these wells. For similar reservoir conditions, this is lighter. I think it's 36-degree API oil versus 30- 32 for Pikka. You'll see this clears a lot faster. The glass clears a lot faster.
What that tells us is for similar reservoir positions, we can expect much higher flow rates from Quokka going forward than you get from Pikka. I'll pass this around, and I hope to see the two of them again at the end of the day. That's a very valuable commodity, right? We don't want those going missing. Please have a look at them. It'll give you a feel for the grade. This is premium oil commanding very significant premiums to Brent today in Asian markets, and Sean will take you through that later this morning. That was a very successful market. We've already got 177 million barrels of 2C booked from our previous drilling activities in Quokka, and Bruce will take you through the potential scale opportunity there. Then we've got Horseshoe, another exciting prospect to the south of Pikka. Incredible running room in Alaska.
I go back to our three region growth strategy, looking at large scale, that sort of scale of basins that Santos has never had to invest in. In the past. We've got them in Alaska, we've got them in PNG, and we hope to have them in Australia going forward. What does that mean? That means that all your investment in the future, all your focus, is developing fewer but much larger basins, driving lower unit cost developments, lower development costs, lower unit cost of production, and higher margin barrels out of the business. What does that mean? Because many of you are saying, "Okay, well Barossa and Pikka coming online, how should we think about growth going forward?" This is really just to tell you, we've got a lot of optionality in that portfolio.
If things get tough in Australia for a while, we've got a lot of growth opportunities in Alaska and in PNG. That's a great thing and great flexibility for a business our size to have. I think we've got a portfolio that would be the envy of most of our peers. In fact, I saw a chart recently by WoodMac that showed our growth opportunities out to 2035 way above anyone else in the market. I include the majors in that. Most of them are pretty flat or going down. What does that say? That says you should expect to see what you're seeing in the market right now, significant consolidation plays as people buy growth. We have organic growth. We have very significant organic growth.
We obviously have Barossa and Pikka coming on right now and giving us that initial production uplift, but we're still targeting a 4% CAGR growth rate all the way through to 2025. We believe we can do that with that capital discipline within that framework we've described earlier on with an all-in breakeven of $45-$50, which allows us then to continue to drive really strong returns for our shareholders at the same time. Sustainable strong returns, sustainable reinvestment in the business, recycling CapEx out the Cooper Basin into higher return growth hubs going forward will give us a very sustainable business for decades to come. It's all about growing free cash flow at the end of the day. In terms of cash flow per barrel, here's a WoodMac chart. This is not a Woodside chart, this is a WoodMac chart.
You can see where it places Santos between 2026 and 2040 for margin per barrel. It puts us number one globally on a go-forward basis. It might take some premiums into account, but I do not believe that will be taking the premiums for Alaska into account, and I do not believe it will take the full extent of the opportunities in Alaska into account. You can see through that some of the takeaways. Obviously, we get that stronger free cash flow generation from Pikka and Barossa coming online today. I think they use $65 oil for this comparison, as their comparison. Their view of our premiums is that results in $71 revenue per BOE for Santos. When they look at our products, that's how they see that.
Of course, you can see that we're getting around $20 a barrel at 65, and that kind of fits with the $45-$50 model that we've actually put out there, if you think about it. What I would say is one of the things that's driving that for Santos is you're now beginning to see the benefits of us having all these organic opportunities adjacent to our advantaged infrastructure position. We'll be talking about for many years that we can develop fields around existing infrastructure, which should give us a lower cost of development advantage over our competition. Importantly, another announcement for today, is that we are targeting getting our gearing down to the lower end of our gearing range. Not overnight, we're setting a net debt reduction target of $2.5 billion by 2030. $2.5 billion.
Importantly, like the Cooper Basin, taking CapEx out and recycling that will result in approximately a reduction in interest payments by around $150 million per year by 2030, freeing up more cash flow from the portfolio for reinvestment and of course, for returning to shareholders. That's $2.5 billion net debt reduction by 2035, taking us down to the lower end of that gearing range. I look forward to seeing that debt, if you like, transitioning to equity in our share price. That's what I'm looking for by making us a lower geared company. We think that makes the Santos value proposition very, very clear. It's based on investing and growing our business around high-quality asset base with an all-in free cash flow breakeven of $45-$50 per barrel. That then is focused on growing free cash flow.
Every $10 of that free cash flow, or every $10 the oil price is above the breakeven price of $45-$50, will generate between $550 and $600 from the end of this year. Actually, really from the both projects coming online at full rates. That will drive stronger shareholder returns for years to come. That's my introduction section. What I'm going to do now is hand over to Lachie to take you through the finances. Thank you very much.
Thanks, Kevin.
Want me to move?
What's up?
If you want.
Thanks, Kevin. Good morning. For those I haven't met in the room, my name's Lachlan Harris, I'm the CFO of Santos. I'm going to take you through the finance and balance sheet section of today's presentation. I've got three key messages which are going to build on what Kevin's gone through. The first of all is to bring the capital allocation framework to life and to give an example as to how you can really see or predict, forecast what our free cash flow generation will be, and by default, the level of shareholder returns. The second is to go through the net gearing target that Kevin just spoke to. The third will be to unlock or show how our EBITDAX margins are generating returns by investing in higher growth barrels.
Aligning to what Kevin mentioned in regards to CPI and our ability to absorb CPI in our cost base. Kevin's shown you this chart just before, shareholder returns and growth. Two key pillars in the discipline operating model. Free cash flow breakeven from operations at or below $35 a barrel. We've had it for 10 years, it's continuing. We've got a relentless focus on bringing that number down. The lower we can bring that number down, that'll generate more shareholder returns and free cash flow, and I'll take you through that in a second. On top of that, as Kevin mentioned, that $10-$15 increase from the operating model to the target and free cash flow breakeven is where we've got growth CapEx, development CapEx to come forward. I'll show you what we can do with that CapEx.
Kevin's shown you the projects we've got to do with that CapEx. What I'll do is I'll show you how that works in reality in terms of the model. Underpinning that, we used to always talk about a $400 million movement or $10-$40 movement in free cash flow for every dollar of Brent. As Kevin mentioned, now that's getting closer to $550 million-$600 million when the two assets, Barossa and Pikka, are at plateau rates. That's just going to be higher production, higher free cash flow generation. Underpinning the discipline operating model is the capital allocation framework. Kevin's already mentioned target gearing 15%-25%. No change there, we're going to target to drive down the bottom towards the 15%. Minimum 60% of free cash flow we generate above that price is in shareholder returns. 40% maximum of 40% de-gearing the balance sheet.
If I bring that to life with a simple example in terms of the capital allocation framework, and Kevin's already mentioned it. If we take a $50 oil price as the breakeven in any one year, if we take the top end of that range and I say, "Well, how much free cash flow will Santos generate?" If I give you a simple example of saying, if the oil price was $75 for the year, 75 minus 50 is 25. That's the delta. That 25 times the sensitivity, say 600 just for ease of purpose for the calculation, 25 times 600 will be $1.5 billion in free cash flow generated for the year. You can move that up and down. If you've got a higher oil price, add another 550-600 for every 10, or conversely, if you're going down, take it off.
$75 oil price, the asset's at plateau rate, we'd expect around $1.5 billion in free cash flow generated. Of that 1.5, we've already said 60% minimum return to shareholders. That's about $900 million. To give you a level of an understanding as to where we're at, $75 oil price, 1.5, $900 million. It's just the delta between the oil price assumption you have and the $50 breakeven times by the sensitivity. You can take that away and work it out. At whatever oil price you want to run, you can get an understanding to what free cash flow we expect to generate. Obviously the competitive advantage that we will have is to drive that 45-50 down. As I mentioned, we can do that two ways. In the operating cost base at the $35 level, getting that down, or lower development CapEx.
The reality for the development CapEx will be, or the growth CapEx, it will go up and down through the cycle. It's not going to be a linear spend profile. We'll continue to guide you through or guide you every year as to where we expect to be in that phase. One thing that Kevin did mention, I want to reiterate, is that we're now past peak CapEx from both the Barossa and Pikka project as they've come online. To reiterate, that $550-$600, once those two assets are in plateau rates. That's the exciting part of what the capital allocation framework will do and generate, and we think that the model's quite simplistic in its calculation and hopefully easy to understand.
I should have said, and I will reiterate, all this is going to be underpinned by our target gearing range and our investment-grade balance sheet. Moving to the balance sheet. The balance sheet's well-positioned for Santos as we move into this 2026 to 2030 phase of Santos's life. The balance sheet is strong. It's well-supported. We've got strong liquidity at $4.3 billion. Kevin's already mentioned the net debt target reduction coming down from where we currently are. It was around 27% at the end of the year, bringing that down and targeting to get down to 15%. In a $75 oil world, using the same oil price that I just went through, we expect to get there by 2030. It will be underpinned by a discipline operating model. We don't need to do anything else. At $75, we'll get there.
Stronger oil prices initially, sure, they'll provide a bit of a tailwind for us in that instance. The discipline operating model will be what will get us there. $4.3 billion in liquidity. Just last week, Moody's upgraded us from stable to positive, so a great announcement as we continue to move into this phase of cash generation. The drawn debt maturity profile, same as where we were at the end of the year. The balance sheet's underpinned by five investment bonds in the market. No debt maturities until September 2027. We've taken an FX hedging position and we've taken some commodity hedging to protect the cost base through the cycle. In terms of what we're going to do with the cash and generate the cash, another example of a $75 scenario for the next five years. This is how much operating cash flow we expect to generate.
Of that operating cash flow, we will then be investing in CapEx. That's going to be a CapEx. That's the mix going to be of growth CapEx and sustaining CapEx. We will then, shareholder returns will come in at the minimum 60%. That de-gearing wedge by 2030, as I said, in a $75 oil world, that will be the balance sheet hitting that 15% target gearing range. Once we hit that, as the model indicates on the previous couple of slides, the shareholder return bucket goes up once the de-gearing has got down towards the bottom end of that 15%. This slide also demonstrates that we've got strong capacity to fund future growth. That's important. There's a lot of optionality we have.
Kevin's gone through some of the slides, and we're going to go through further with Brett and Bruce and the team in regards to the great optionality that we have for future growth. This model and the balance sheet and the framework is fit to be able to sustain growth and to sequence growth that will allow us to continue to grow in the $45-$50 model. That's what's important. Before I get onto how many projects we think we can do, I just wanted to update you on the Papua project financing. Now Brett's going to talk about the project, but just in terms of the Papua project financing component, we are continuing to pursue, with the partners, a project financing solution for Papua, and it is going very well. ECA and commercial bank support is very strong.
We anticipate that this financing will be in a ring-fence type incorporated structure. It will provide potentially up to the first 60% of the capital required for the Papua project. That's important because if the project financing is providing the first 60% of CapEx, that'll be front-loaded, meaning that the equity contribution that the partners will put in will be towards the back end. If Papua does move forward, the project financing is going to be there ready to take the first heavy lifting in terms of the cost of the project. What that does is important to the bottom point because that'll allow us to do at least the Papua project and one, potentially two other development projects at one time and fit within the 45- 50.
Now that will be dependent on sequencing, phasing, and working interest of where we get to with some of the projects. The balance sheet is positioned to fund growth in the model at the $45-$50 level, and that's what the strength of the balance sheet is currently designed to do. My last slide is to take you through and just to reiterate what Kevin's already spoken about in regards to our growing margins and excuse me, our ability to absorb inflation. By investing in higher margin barrels targeting lower unit costs, we are driving higher margins throughout the decade, throughout the period, especially against our peer group, and we are flattened out. We are keeping it at a lower level. We are continuing to focus on the cost base and to drive that down. It drives competitive advantage and is what Santos is known for.
As you can see, we had record low unit production costs last year, and unit production costs have reduced by 20% since 2016. We want to continue to be peer leading in the space, and we're not going to stop at any point. We're going to continue that focus, and you'll hear that throughout the rest of the morning when Brett and Bruce and the team go through the assets. My last point is just in regards to the structural cost savings. We last year announced a $150 million cost out target. We delivered $50 million to the end of last year, and we are continuing to pursue that project, and we'll aim to update you throughout the year as we get to that $150 million annual cost-saving initiatives. That concludes my presentation today.
I just wanted to reiterate my three key messages today were the capital allocation framework and how it's going to generate free cash flow and shareholder returns. Secondly, the net debt reduction target of $ 2.5 billion and how we expect to get there by 2030. Lastly, the margins and expanding on what Kevin already mentioned in terms of our unit production costs and our cost discipline. Thank you very much. I'm now going to hand over to Tracey.
Thank you, Lachy. My name is Tracey Winters, and I'm the Chief Strategy Officer for Santos. Today, I'm going to make the case that this is the best time in more than a decade to be in oil and gas and LNG and oil. We live in an era of global energy addition. By the middle of the century, the world will have 2 billion more people, mostly in the developing world, all needing energy. Artificial intelligence is also reshaping global energy markets, accelerating electricity demand growth after years of stagnation in many developed economies and increasing the importance of reliable baseload power. Demand for energy keeps rising because demand for human progress keeps rising. The challenge is not choosing between energy sources, it is producing more energy with fewer emissions.
Despite the world's best efforts and trillions of dollars of investment over the last 35 years or so, hydrocarbon fuels still make up 80% of the global energy mix today, down only around 5% compared to 50 years ago. Oil and gas alone account for around 50% and will continue to do so through 2040 and beyond. There are limited alternatives for them in many applications. Oil and gas are not just fuels. They are essential to make things like plastics, fertilizers, synthetic fibers, pharmaceuticals, steel, and electronics components. Historically, energy transitions take 40-150 years depending on the system, technology, and policy support. Today's energy system is the largest and most complex ever built. This means all energy sources will grow simultaneously. For the oil and gas industry, several factors have aligned in a way that our industry has not seen for a long time.
First, demand resilience. Despite years of peak oil expectations, global oil demand is still around record highs above 100 million barrels a day while LNG demand growth has accelerated, especially in Asia. Second, under-investment from 2014 to 2021. Following the 2014 oil price collapse, COVID-19, ESG pressures, and transition uncertainty, global upstream investment was materially constrained for many years, tightening spare capacity and new supply growth. Third, LNG has become geopolitically strategic. After Russia's invasion of Ukraine, LNG shifted from being viewed as a transition fuel to an energy security commodity. Long-term LNG contracting returned strongly, especially from North Asia, Europe, and emerging Asian buyers. Fourth, higher long-run price expectations. The floor price for both LNG and oil is likely to be higher because upstream decline rates are relentless, replacement volumes are more expensive, and geopolitical risk premiums are persistent. Finally, public policy realism has increased.
More and more governments around the world are now acknowledging that renewables alone cannot sustain modern industrial economies. Gas is needed for grid stability and reliability, and oil demand in heavy transport, aviation, and petrochemicals is proving very hard to displace. All of these factors are benefiting incumbents in the relatively small number of countries that will dominate low-cost, low-emissions future supply, and those include Santos supply hubs in Australia, Papua New Guinea, and Alaska. These hubs are on the doorstep of Asia, which has over 50% of the world's population and accounts for almost 50% of the world's total energy consumption, and where 55% of global energy demand growth is forecast to occur in the next 15 years. In particular, the center of LNG demand growth is Asia.
The outlook for LNG is arguably the strongest since the original Asian LNG expansion cycle of the 2000s, with growing demand, renewed European dependence, long-term contracts returning, and limited new supply, with buyers likely to be more wary of Middle Eastern supply in the future. What we are showing here is sustained demand growth driven by industrialization, urbanization, electrification, rising living standards, and energy security concerns across both developed and developing Asia. According to Wood Mackenzie, global LNG demand grows by more than 60% through to 2040, with Asia accounting for around three-quarters of total growth. The left-hand chart highlights an increasingly important issue for the global market, supply adequacy. Existing LNG supply begins to plateau over time as mature assets decline. Even with projects currently under construction, Wood Mackenzie identifies a substantial supply gap emerging through the 2030s.
More than 65 million tons per annum of additional LNG supply will need to reach final investment decision to balance the market by 2040. There remains considerable uncertainty about the future of Qatari supply growth, including the return to service of the 12.8 million tons of capacity damaged at Ras Laffan during the current conflict. LNG consumption is broadening from traditional North Asian markets across Southeast and South Asia. Countries such as India, Vietnam, Thailand, the Philippines, and Bangladesh are increasingly using LNG to support power generation, industrial growth, and energy security. South and Southeast Asian LNG imports alone are expected to increase from around 60 million tons today to 200 million tons by 2040.
While these markets are price sensitive today, demand growth will increasingly require supply from higher-cost suppliers distant from market in an environment of rising project costs, tighter engineering and labor markets, geopolitical risk premiums, and shipping constraints. This creates a real opportunity for reliable, low-cost Pacific basin suppliers like Santos. Australia and Papua New Guinea remain exceptionally well-positioned, geographically close to Asian demand centers, highly experienced in LNG operations, and capable of supplying long-term contracts into the fastest-growing energy markets in the world. The broader strategic point is that despite rapid growth in renewables, the world is still going to require very large volumes of gas, particularly LNG, to support economic development, industrial activity, and power system reliability across Asia for decades to come. Global oil demand is also proving far more resilient than many forecasts anticipated only a few years ago.
Despite rapid growth in renewables and electric vehicles, the world still relies on oil for heavy transport, manufacturing, petrochemicals, aviation, agriculture, and heavy industry. As a result, most major outlooks now see oil demand remaining at or near historically high levels well into the 2040s. The chart on the left illustrates two important trends. First, global demand remains broadly stable over the long term. Demand plateaus rather than collapses, supported by petrochemicals, aviation, and emerging Asia. Second, and arguably more important, existing supply declines materially over time. Mature oil fields naturally decline every year, meaning the industry must continually invest simply to maintain current production levels. What the chart demonstrates is the emergence of a significant supply gap from the mid-2030s onward, unless substantial new investment is sanctioned.
Wood Mackenzie estimates prices above $70 a barrel are likely to be required to incentivize sufficient new supply to both offset decline rates and meet long-term demand. This dynamic is reinforced by years of global underinvestment that I talked about earlier. At the same time, the composition of demand is evolving. Petrochemicals and aviation are major growth drivers. The reality is that there are no viable scalable alternatives yet available for jet fuel. The chart on the right reinforces the central role of Asia. While demand in some OECD economies stabilizes or gradually declines, growth across India and the broader Asian region offsets much of that reduction. The broader conclusion is that the market increasingly appears characterized not by imminent peak demand, but by a long demand plateau combined with tightening supply conditions. For low-cost, reliable producers like Santos, that creates an attractive long-term investment environment.
A theme that has become increasingly important in global energy markets over the past several years is that geography and geopolitics now matter as much as geology. Global LNG and oil markets are no longer driven purely by lowest cost supply. Buyers are increasingly prioritizing energy security, reliability, shipping resilience, and geopolitical alignment, and reducing emissions is still important. This shift strongly favors Santos supply hubs across Australia, Papua New Guinea, and Alaska. The map on the left highlights a key strategic advantage, direct Pacific basin access into North Asian demand centers. Unlike Middle Eastern supply, Pacific LNG shipments avoid some of the world's major maritime choke points. The current conflict has reinforced how vulnerable global energy systems are when too much supply is concentrated through narrow trade corridors, and that will have an impact on how buyers look at their LNG and oil security in the future.
Santos assets are positioned close to premium North Asian buyers and the growing Southeast Asian market. That proximity delivers several advantages simultaneously. First, shorter shipping distances reduce freight costs and improve delivered competitiveness into Asian markets. Second, shorter voyages lower shipping emissions and reduce fuel consumption, an increasingly important consideration for customers focused on supply chain emissions intensity. Third, Pacific basin supply provides enhanced reliability and schedule certainty compared with longer, more exposed trade routes. Energy security has become particularly important for North Asian buyers following the European gas crisis after Russia's invasion of Ukraine and growing strategic tensions across global shipping lanes. Many customers are now seeking long-term supply relationships with politically stable and trusted jurisdictions. Australia already exports 90% of its LNG into Asia, while Australia itself imports most of its refined liquid fuels from Asian partners, reinforcing the depth of regional energy interdependence.
This creates a strategic alignment between supplier and customer that extends beyond simple commodity trade. Relationships matter. The broader message is that Santos is not simply advantaged by resource and asset quality. It is advantaged by location. In a world where energy security, geopolitical resilience, and reliable supply chains are increasingly valuable, Pacific Basin LNG and oil have a strong competitive position. That strategic advantage is likely to become more important, not less, as global markets tighten through the 2030s and beyond. I'll now hand over to my colleague, Sean Pitt, to take you through how our marketing, trading, and shipping team is leveraging these strategic advantages for Santos.
Good morning. Thank you, Tracey. Firstly, my name's Sean Pitt. I'm delighted to be here. I'm the Executive Vice President for Marketing, Trading, and Shipping for Santos. It's a great company. You've seen some of the opportunities, the assets. You'll hear more about it from my other colleagues today. I still think I've got the best job in the company. I get the ability to bring the products to the globe. Marketing, trading, and shipping, we see it as a direct value driver for Santos. Our purpose is to maximize the realized price and by extension maximize the margin available for the broader business. Our LNG strategy is deliberate and layered, spanning spot, midterm, and longer-term positions with high-quality end users at its core. Established relationships with Hokkaido Gas, Shizuoka Gas, and Nippon Steel exemplify this approach.
This layering enables Santos to respond dynamically to market conditions while maintaining a Brent slope equivalent to or greater than 14%, a benchmark that reflects the quality of both our portfolio and counterparties, and the result is a strong sustainable realized price of near $1.50. Sorry. How do I go back? Sorry. Thank you. Our Sweet Australian Crude competes strongly against West African grades such as Bonny Light. It carries a material freight advantage into the regional market and is ideally suited to Asian refiners optimizing production of jet fuel, motor gasoline, and naphtha, delivering near double-digit premiums over Brent, similar to what Tracey just alluded to on the demand for those products. LPG remains a versatile and highly transportable fuel across developing Asian economies. Domestically, demand continues against the backdrop of declining local supply, a structural dynamic that works in our favor.
Again, factors that support strong to selling indices such as the Saudi Contract Price or Saudi CP. Finally, Alaska North Slope, a middle-weight sour grade, highly sought after as both a replacement grade for its strong middle distillate yield, making it well-suited for complex refining configurations across our Asian Pacific region. Santos operates a formidable and highly valued portfolio. Several attributes combine to make it genuinely differentiated in the eyes of our buyers. First, our regional location. Our postcode is one of the most valued in the global economy. Proximate to the highest demand LNG and crude-consuming nations in the world, many participants are looking to grow their Pacific supply and reduce their Atlantic positions. Second, as both operator and an equity lifter, buyers are actively seeking to reduce complexity and counterparty risk in energy supply chains.
In some cases, and in recent times, I've certainly seen a cargo pass through 44 sets of hands before arriving to its original lifter. Santos did not participate in this transaction, I can assure you of that, Kevin. Each one of those touch points is a potential failure. Santos, as a direct operator and equity participant, eliminates that risk. Avoiding long chains of intermediaries and strategically positioned away from contested choke points is increasingly valued by sophisticated end users. We're a preferred supplier because of these key points. Can be seen on the chart on the right, our portfolio is in a strengthening position. Materially new supply tends to be from the Atlantic. It's the wrong postcode, with new supply also typically lean.
While Santos' portfolio LNG is both of a high quality HHV value or High Heating Value and an MOC specification or market on close, a suitable and sought-after trading position. The combination of our local advantage, high heating value portfolio, and direct equity participation has translated into measurable and incremental value through short, mid, and long-term contracting. Our contracting strategy is built around deliberate layering, as I mentioned before. Spot exposure through short-term markets providing liquidity and market intelligence. Mid-term positions are structured to capture periods of structural price strengthening. Longer-term contracts with high-quality end users provide stability and underpin our financial planning horizons. The mid and long-term arrangements rest on deep, established counterpart relationships, leveraging our world-class, highly capable shipping, trading, and marketing team, which is located in Australia, Japan, and Singapore.
We've invested considerable time understanding what our customers value most, optionality and contractually, and where we can constructively offer flexibility in return for portfolio optionality that benefits us, Santos. The result is a set of contractual structures that are generally bilateral in their very value creation. This approach has translated into sustained strong pricing that you can see through the results today. The Santos portfolio originated as a set of joint venture contracts. As it's evolved toward a greater equity participation model, we have successfully captured incremental value and realized price following that trajectory, and you see that each quarter as you compare to our peers. Looking forward, as the equity proportion of the portfolio continues to strengthen increase, we expect that trajectory of incremental value and superior realized pricing relative to our peers to be sustainable, if not grow.
This is reflected in our current Brent realization of approximately 14.6%, a strong outcome by any measure, and envy for many of our competitors. We continue to maintain approximately 80% of our volumes contracted with around 20% available as a spot exposure. This balance allows us to respond to market movements, whether that means extending into mid or longer-term positions, capturing secondary market pricing, or providing support or supply assurance to valued customers or countries. Importantly, as the portfolio has matured and contractually flexibility has been embedded, Santos has begun to actively monetize that optionality. In 2026, we have already delivered approximately half a million tons of that optimized or traded position. This will continue to grow and generate higher margin value at a low risk without the requirement of any additional capital. Alaska North Slope crude.
We often refer to it as Pikka, but it is ANS, which our project will supply via the Trans-Alaska Pipeline System or TAPS. It is in exceptionally high demand. Headline premiums of $20 per barrel above Brent reflect a market that is actively seeking supply security from outside contested maritime zones and potential choke points. I've spent much time with many Japanese counterparties, and they have all indicated that even despite a cessation of activities in the Middle East, they will pivot away from a supply that would be fully dependent on Middle Eastern crude. ANS is a middleweight sour grade, highly valued in its distillate yield, making it particularly attractive to complex refining systems across North Asia. The grade's technical fit with these facilities underpins a structural demand base that extends well beyond any near-term political premiums. The security of supply dimension cannot be overstated.
As I mentioned, Japan has great interest. On 26th of April 2026, Japan marked a landmark moment when a Suezmax tanker of 900,000 barrels of U.S. Gulf crude procured by Cosmo Oil, a company that we're very close to, entered Tokyo Bay. It was such a monumental effect that it televised the arrival of the ship on national TV. A measure of just how significant energy security has become to the Japanese consciousness. Even beyond any eventual ceasefire, the stabilization structure drives Pikka crude remains compelling. West Coast refining capacity on the West Coast of the U.S. is contracting 7% year-on-year, reducing domestic competition for the grade. Jones Act shipping constraints makes U.S. distribution expensive and logically complex, where Asian buyers are highly motivated and are seeking sources away from the Middle East.
It also adds and supports their ambitions to support the Trump administration in its trading activities. In conclusion, I'd like to leave you with three observations. Santos operates a formidable portfolio, one that is geographically advantaged, technically differentiated, and commercially sophisticated. Our established and high-quality customer base generates genuine co-benefits for both Santos and our buyers, relationships built on trust, transparency, and a shared commercial interest. Our products command strong, sustained premiums relative to their indices, a function of quality, reliability, and strategic positioning of everything I've described today. Well, thank you very much, passing to Mark.
Good morning. My name is Mark Burgoyne. I describe myself as a deeply technical reservoir engineer. I'm also subsurface vice president at Santos, responsible for the disciplines of geophysics, geology, reservoir engineering, production engineering. That includes reserves, which is the topic of discussion this morning. I'm going to take you through how much we have, how we manage it, and what it costs to replace it. 4.7 billion barrels of 2P plus 2C resource, 1.5 billion barrels of 2P, 3.2 of 2C resource. Put that in context, the world consumes about 100 million barrels of oil a day. That's spread across three assets, Australia, PNG, and Alaska, and it's weighted over 80% of premium product, LNG, and liquids. Those three geographic hubs give us diversity of geography. They also give us diversity of geology.
In Australia, we've got quite diverse, but it spans Jurassic, prolific gas reservoirs, big bore, 300 million scf per day wells in Barossa. Factory mode development of marine shales in the Beetaloo. In PNG, it's a prolific gas province. Many fields of high-rate wells have been already developed. Classics in the highlands and coming up with Papua with a reef carbonate shortly. In Alaska, we've got our conventional oil where we're developing with horizontal wells placed through sandstones in the shelf edge. We're developing those with a water alternating gas flood from the get-go to efficiently sweep from the injectors to the producers. This diversity of geology and geography and product gives us optionality, so when the world throws us curveballs, rather than just seeing challenges, we see some opportunities as well. For a portfolio of this size, how do we manage it?
Plot here is what we call a Reserve Life Index or RLI. Quite simply, each one of those data points is the reserves at that year divided by the volume produced in that year. This one's a 1P. It's not a measure of how long our reserves will last for. It's a discipline and health check. It guides us as to when we need to replace reserves and how much for a given target offtake rate. We see a sweet spot there. If you go much below the sweet spot, you run the risk of shortfalling, and you get pushed into making hasty decisions. If you go too high, you're over-investing on long-dated production. We see that sweet spot is between 8-12 years on a 1P basis, and we are well-placed compared to our peers in that area.
That position gives us the ability to pick and choose the when and the what we select next. When we're making that selection, the cost per BOE is one of the key aspects we look at, and those costs are going down. 10 years ago, Firstly, to set this up, what we're seeing here is the cost to replace a developed 2P barrel of oil equivalent, all in. 10 years ago, that was $20. Over the forward five years, we would drop that by 20% to about $16. Now, we're proud of that. That reflects our capital efficiency. It reflects an operational focus. It also reflects a choice in the projects that we're executing, a pivot to a more tier 1 focus.
It's that pivot that we've been doing and continue to do that is going to deliver the target of less than 13 going forward, and let me explain why. First, advantage portfolio. Some examples, Pikka Phase 1, we've already seen first oil. Factory mode development. The wells are performing. There's a Pikka Phase 2 around the corner. This model of two developments sharing the facilities, we see copy-paste over into Quokka, and we see a copy-paste over into Horseshoe. That's not even taking into account the exploration upside, which is phenomenal. Second, would be Papua. This is a proven high deliverability gas play. When I say high deliverability, I'm not sure if anyone remembers, but back in 2009, the Elk-2 well tested over 700 million scf per day on test. Phenomenal rate.
In fact, if anyone can find me a validated test that's higher than that, I'll buy them a beer. First personally, but I'll buy them a beer. Second is the internal competition. We've got Bedout competing with Beetaloo competing with Quokka and Horseshoe. It's an enviable portfolio. It's not enough just to get a certain metric, a certain investment metric to get up. They've got to compete and be the best one in our portfolio. That drives the efficiencies. Resource depth, I'm not talking depth below the ground. I'm talking materiality size. The poster child there is the Beetaloo. We've got great position, three shales, A, B, and C. Just the B shale alone has been assessed at having over 200 TCF in place across the play. A, B, and C together, I think you'll see this report, is over 400 TCF.
This is foundational gas that has decades of running room, and it's those decades of running room where the costs get ground out. It's been assessed as being analogous to Utica and Marcellus, which deliver about 1.6 Bcf per 1,000 foot of recovery. We compare favorably across the subsurface elements of that, which include frackability or quartz content, productivity index on a normalized length basis, shale thickness. When I say compares favorably, I'm not talking about just scraping the bottom of the barrel or just squint slightly. This is right in the cluster, right in the cloud, if not at the top end. It's really exciting. We've got two appraisal wells in the B coming up soon, 3,000-meter length, 60 frac stages, 2,200 pounds per foot. Red hot go at this one. We're also testing the A as well with a shorter 1,000-meter well.
I'm super excited to get the results of those and run my eyes over them next year. Last is leveraging our operator positions with the tier-one assets and these larger assets. It really opens more avenues there. Two examples, Pikka Phase 1 already being executed. Pikka Phase 2 is just around the corner. It's just plug and play, factory mode development back into the same facilities. APF Tie-In in PNG. This is gas associated with our oil fields that's just been stranded. We're plugging it into the PNG LNG project, 135 million scf per day, no additional compression. It's some of the most attractive barrels, BOEs, you'll ever find. Our track record says we've dropped our costs by 20% already. Our portfolio says there's much more to go. If I wrap this all up back from the top, materiality, 4.7 billion barrels across the three hubs.
Different products gives us the options. Reserve life index, we're in the sweet spot. Gives us the luxury of being able to pick and choose what comes next, and our costs are coming down. That's the reserves picture. I think it looks pretty good. I think with that, we're off to coffee.
Lachlan, how long is the break?
About 25 minutes.
We'll take about a 20, 25-minute break, and then we'll get back in for the really exciting stuff. Thanks very much.
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Well, welcome back, everybody. Hope you managed to get whatever it was you got during the break, and refreshed and ready to go for the next session. That video, actually, it's worth commenting on that video. One of the things I think has been a real transformation for Santos over the last five to six years has been the effectiveness and the contribution that we're having on local communities, and the real commitment across our organization to making a difference. We changed our purpose statement in 2021 to reflect that, when we said it's not just about shareholder returns. That's very important, and that's really important to all of you people in this room, as it is to all of the management team and the board. It's also about making a difference in the communities where we operate and creating a better world for everyone.
That's a really important part of the Santos ethos. You saw some great examples there, the foundation's work in PNG. That 7,800 cervical cancers screening that we've done has saved almost 800 lives that otherwise would have had cervical cancer with no road to treatment. We can identify that through the screening, and on that same day, apply treatment courses for those individuals and start treating them for those diseases that would have been undetected. There is no health system that picks that sort of stuff up. You saw the COVID vaccinations, the typhoid, the other vaccinations that we give that just aren't readily available to people in PNG. The foundation's now moved into the Northern Territory, and you saw some of the work we're doing there in those local communities, helping those communities get a better way of life.
In the long term, that is good for Santos because we partner with those communities. We're operating in those communities. The good thing now is we're offering and developing a lot of local jobs, sustainable jobs for the young people in those communities that hopefully will help break the cycle over the longer term. It's a long-term objective. The reason I share it with you and share my thoughts on it, and let me tell you, it takes a lot to bring a tear to a Scotsman's eye. There's a few things that I have experienced up in the highlands of PNG reading to five-year-olds, and they didn't say, "That's a funny accent you've got," by the way. They understood every word I said. I don't know what that tells you about the PNG kids.
When you go and experience it and see it for yourself, it's something that makes the employees at Santos immensely proud of the work that we do, even up in the North Slope of Alaska. You see some of the involvement. What we're seeing now is indigenous employee numbers. If you look at a sustainability report, indigenous employee numbers that are way above the national average, way above the national average at Santos because it's a great company to work for, because they know we're genuine with what we're doing in their communities. I just want to share that before we go to the next section. Now we're going to change pace a little bit. That was a slow session.
Now we're going to go and look at the growth hubs themselves, and we're going to hear from Brett and Bruce initially taking you through their portfolio. You can see, it just reminds you on this chart of the opportunities. That focus in those three regions, those three growth hubs, the three regions around the world, focusing and prioritizing the investment on those tier one basins. I'm going to keep saying that as we go forward. That is the focus of Santos' strategy going forward, tier one basins. You can see the list. I'm not going to go through them again because Brett and Bruce are going to take you through those. Then you're going to hear from Alan on midstream and the energy solutions part of our business, and then Steve.
I'll wrap up at the end, and we'll get some of the guys back on the stage for some Q&A. Brett, over to you, mate.
Thanks.
Thanks, Kevin. Good morning, everyone. I'm Brett Darley. I'm the Chief Operating Officer for Australian PNG Upstream, and I'd like to just take you through the assets. A bit of an update in the first quarter, and then I'm going to dig in on a little bit more detail on some of the areas that Kevin's covered already. I would say that in the last 10 years and in previous presentations, we've spent a lot of time talking about honing our operating model, our discipline low-cost operating model, to make good money to hold inflation flat in some of our non-tier 1 assets. They are good assets to run, and we've had to run them hard. As we're pivoting to tier 1 assets here, and we'll talk about some of them in a second, with that ability to operate and keeping that model with tier 1 assets, look out.
There's a lot of assets here as well to go through. Competition's going to be fierce. I'm not really sure how we're actually going to allocate it. I think we're going to need an octagon or something with Bruce and I. He looks like he's got that farm boy strength, so I'm going to have to watch out for that. Yeah, there's some excellent things we're going to be running through, and I think this is a great problem to have. Let's just start with the asset update for 2026 so far. On the Cooper, a couple of things to talk about. MCO, so that's Moomba Central Optimisation. This is going to transform the area where most of our remaining reserves exist for the Cooper Basin.
It's our oldest equipment, our least reliable equipment, and ultimately, it's the place that we're going to produce the majority of our reserves going forward. We are going to modernize that area. We're going to target the capital for that area, and it'll make it more reliable. We're basically going to fold seve satellites into one that'll be able to be remote operated, electrically run. We'll be able to turn these things, instead of sending people out to them, we'll be able to actually operate these things remotely. We're going to revolutionize the area we have the most of our remaining reserves in with MCO. On the sales side, Kevin mentioned we actually did sign or we ventured into a 10-year agreement with the South Australian Government to supply 20 petajoules a year from 2031.
That really underpins Santos and our commitment to the domestic gas market going forward as well. In WA, Kevin spoke about Halyard. Again, it shows the value of these tiebacks to Varanus Island. These are really low-cost operating barrels. Halyard 2 is over-performing. It's already produced more than 85% of what we thought it would produce, and we actually haven't seen any water breakthrough or pressure decline. That's going to continue to provide value there, but again, shows the value of those tie-ins to Varanus Island. Also, Steve will go through in a bit more detail about the Harriet Alpha platform being safely removed ahead of schedule. That's the largest platform that's been removed in Australia to date. What is that showing? Below budget and ahead of schedule with no incidents. That actually you can start to project that forward with our decommissioning liabilities.
We can do these things cheaper than we thought we could do them, and that adds value to the business as well. GLNG, good run rate. 24 cargoes shipped to date. We are seeing some good performance, particularly in Fairview with some of the longer wells we drilled. We actually just drilled a 5,500-meter well in that field, and we're starting to see some good flow rates, some really good flow rates, in an area that we thought was on decline. We've actually arrested decline in Fairview. Roma is actually producing just above what we expected at the moment as well. Some good strong performance from these base assets. Barossa, I'm going to talk to Barossa in the next slide or two to give you an update on where we are with that. PNG LNG continues to perform really well.
We've got two projects that we FID in the first quarter. The FSO, which is actually a way that we will export the liquids. Currently, we're doing it from a marine terminal that's reached the end of its life. The FSO gives us a lot more flexibility, and also we've integrated the FSO, so that's our liquid exporting for PNG LNG into the new scope for the Papua project as well. Papua Liquids and PNG LNG liquids will both be exported from that FSO. The storage will actually be offshore as opposed to being on tanks onshore, and we're actually running very well at PNG LNG. With the higher oil prices, we've been focusing on more Hides gas backing Angore off, or the operator has, and we've seen some good liquids upside in that.
We're actually half a million barrels above plan to date, Santos share, in the first quarter of 2026. I'll just dig into Barossa a little bit. As Kevin said, Sunday, we had the Prism Brilliance completed its load out, and it departed on Sunday. The next vessel is on its way for, and it'll be there next week for load out as well. The issues we had that have been mentioned on the fouling of the heat exchangers, so this is to lower the temperature of the gas. We had fouling issues that we reported. Those fouling issues happened very quickly. We did not expect them to occur. What I can say right now is we understand what caused them. We've cleaned the heat exchangers back to factory condition, and we know how to prevent reoccurrence.
The facility's been running around 70%-75% of planned rates for the last 10- 14 days. It's going very well at the moment. I think Kevin also mentioned these are high-quality wells. Each one of the six wells that we've drilled out there, 300 million standard cubic feet per day of potential. There is no constraint from the reservoir. At the moment, we expect to get the plateau rates about mid-year as we bring our production up. We'll bring that up in a stable way so that we continue to operate in the meantime. We're going to just take that slowly up to production rates mid 2026. The issues we had with the fouling on the FPSO are well and truly behind us. Just let me remind you, this is a world-class project. Barossa is world-class.
These are the sorts of charts you want to see. Barossa keeps GLNG full out till 2040. This project is going to be producing 3.7 million tons per annum of gas or of LNG into a market or out of a location, as Sean explained, that is actually a really good postcode to be producing gas in. Really low unit production cost and ultimately CCS opportunities through Bayu-Undan that Alan will take you through as well. Barossa, world-class asset, and it's now producing and we'll keep you updated on that. Look, I'll go through this in a bit more detail, and we talked about this, but the basins that we're looking at, PNG tier 1, lots of plans to keep that full in the long term and before Papua comes in, and I'll show you that in a minute. Beetaloo, fantastic asset.
We're hoping that's going to be a tier 1 province for us in the future, and the same with Bedout. These are great assets to have on the books. All right. Beetaloo. The Beetaloo Basin here, Beetaloo is going to need scale. It is remote. We have the scale. We've got the ability to have export pathways to generate scale to make this development happen. You'll see on the brochures that you've got on there, the Northern Territory Government estimate more than 430 TCF of undiscovered gas in place in this basin. That's not just important for Santos, that's important for Australia. It's important for the region. This is a game changer. As Kevin said, from our block alone, we don't need anybody else's block. We got the best block in the basin. I'll talk about that in a second.
We can not only just fill GLNG trains, we can expand Darwin, we can provide domestic gas and more. This is an absolute game changer. We've got the scale right now to be able to define and to be able to make a development happen with the export pathways that we have. We've got a train at GLNG that by the early 2030s will require to be backfilled from a resource, and that timeline works for us. We've got the ability through a number of different pathways, but CCS connection, either through Moomba CCS or through Bayu-Undan, gives us the ability to place the CO2 into the ground. This is very low CO2 gas, mind you. It's pipeline spec gas anyway. It's got 3%, but at the scale we're talking about, we still have the option for a CCS solution for that.
We've got some wells coming up, as Kevin said. We've got two wells or three wells over the next year that we're planning to drill. Those three wells, along with a nine-month production test. These aren't just test wells. We are going to put in basically development wells so we can test not just the resource size, but the deliverability, so we can make a final investment decision after evaluating these wells. That would give us five TCF in the basin if we took FID on a project, which would give us about 500 TJs a day over 20 years, enough to fill a train. From an export route point of view, like I said, it is remote, but there's a number of options for us. I always say which ways are going to go. It's not which way, it's who goes first.
For us right now, our privileged infrastructure here through Moomba and the ability to put gas into the East Coast market, but also to come down to Ballera and be able to put 500 terajoules a day through the current pipelines into Gladstone via Wallumbilla, that actually gives us an advantage right now. So that's our quickest way to market. In saying that, we have multiple ways to market. On the rocks themselves, so Mark went through some of the rocks. I won't go through it, the technical details, but these are high-quality rocks. The things I wanted to point out is we've got 360,000 acres of resource area. They are comparable to the Utica and to the Marcellus shales, so high carbon content, high pressures, all the things you need, good thickness.
The other part I wanted to point out here is we've actually got three shales. If you're looking at who's got the best stuff in the basin, this is what you see on the western side. This is what you see on our block here, is not only do we have the B shale, which is what everyone talks about, and you can see the size of that and the depth. Our B shale is deeper. It's got more pressure. We also have two others. We're actually really bullish on the A shale, and we think there's potential with the C as well. What that enables you to do is pretty much at least double that acre size from a stack play perspective. From a development perspective, you can actually access, it's a cheaper overall development cost if you can access two shales.
The program that we've got coming up in the next year is going to be two wells in the B and one well in the A. These are development style wells, long horizontals, 60-stage fracs, nine month flow backs. At the end of that, we'll be able to make a decision and we'll know what we've got. We're very bullish on these ones. Bedout. Just look at the amount of opportunities here. There's nearly 1 billion barrels already of risk prospective resource in the Bedout. This is the next North West Shelf. If you have a look at all of these opportunities, we've only just scratched the surface. We've got a development-ready oil development in Dorado and Pavo, you can see the resource numbers there.
What we're going to be doing in the next year is drilling three wells, and those three wells are going to inform us on a greater development opportunity. Again, we'll be drilling those three wells and very eager to see the results of those. Already, we actually have opportunities there that you could monetize. In PNG, this is a very prolific, obviously, resource play right along this ridge here. We continue to see success in PNG. Actually, if I just go through to this supply stack here, again, this is a tier 1 asset and it is filled way past 2040. Again, this is another place that continues to deliver. If you look at our current stack here with Hides and APF, CPF, so this is the PNG LNG operated production.
This is our production that goes into PNG LNG, and then you have Papua and you'll see the expansion at Papua. That'll be an additional 4 million tons built in the expansion and 2 million tons of capacity that it will be tolled to the Papua joint ventures. P'nyang out in the distance as well, and I don't even think we have Muruk on here. The running room or the ability to provide PNG LNG in its expanded form well into the future, this is a fantastic province. You would've seen there's a little dip just before you get to Papua, and we'll talk about Papua in a minute. We are trying everything we can with the joint ventures to fill that ledge. There's a bunch of things we talked about.
APF Tie-In, which was already spoken about, 135 million standard cubic feet a day of additional gas that goes into PNG LNG. CPF expansion, we have been getting good reliability up there since the Oil Search merger, but adding another compression train there to be able to get some more gas through CPF. Again, huge value if you've got leverage at PNG LNG. APF expansion, we can quickly put some compression if we need to on the APF Tie-In and actually add another 50 million a day. Gobe just keeps on keeping on. At the moment, we had end of field life originally two or three years ago. We're still doing 50 million standard cubic feet a day from Gobe.
Just doing the sort of production engineering to try and add little bits, reperfs, we've continued to extend Gobe, and our target is to get that well out past 2030. These are high heating value gas that is actually really not important but prioritized by PNG LNG as part of the process. Ultimately, Steve will talk a little bit about this. Not to be sneezed at, these are the cheapest barrels you can get. Going into our wells and actually optimizing them, starting to use AI, starting to use every new technique we can to get the most out of our legacy wells. These are very cheap barrels, and we're going to do all of that to try and make sure that we minimize the amount of outage before Papua comes online.
If I talk about Papua, 6 million tonnes, so 4 million expansion. Ultimately, this delivers 1 million tonnes per annum to Santos net, 11 million barrels equivalent per year, the Papua project. At the moment, there's a couple of things between milestones between now and FID. Kevin talked about the Prime Minister's press release yesterday. He's just met with Patrick in Paris. There's a commitment to make FID happen before year-end. What do we need from the government? We need the development forum, which is where the landholders get together and agree on the benefit sharing. That is now being committed to by the government to start late June, early July. We need the project financing. Lachie spoke about that. We need the CapEx reviewed, so the rebid.
There was a couple of things that happened in that CapEx review to get the number down from where it was. One was different tenderers. Tenders went out, a bit more competition. Change in the scope, so there was a little bit of scope reduction, and then some integration savings. Even the use of Papua using the FSO for PNG LNG, that is a half a billion dollar saving right there. The joint venture's working together to make this work. We're really confident by year-end, Papua will actually be FID'd. The other thing on Papua as well is that not only are we part of the gas production, but as a 39.9% owner of PNG LNG, there is an access fee and ongoing tolling. There's quite a bit of value in that, as well as OpEx sharing on the shared infrastructure at PNG LNG.
It's not only just production, we're actually getting quite a lot of benefits from that. Look, what I would like to talk about as well is some of the oil, and one of the ones that we wanted to talk about today was Mosa. First off, we've got an infill drilling program coming up. These things are very high IRR. Small volumes, but ultimately, two of these four wells will actually be required for gas production in the future. We're just advancing, accelerating a bit of CapEx to take advantage of getting the oil out before they're converted to gas wells. At the end of that campaign, we're going to look at Mosa. Mosa is something that has only just been brought up.
You might say, "Why didn't we discover it 30 years ago?" What we actually have used in the last year is a technique, Lidar. I think it's used in Teslas. Light, it's basically laser beams that you send out and you receive. The ability for this advanced laser has been able to get underneath the canopy of the rainforest. In PNG, the connection between the subsurface and the topographical map is very important for PNG geology. The maps that they've been using, the topographical maps they've been using, basically were not correct. What we've found is a very similar reservoir to the foundational reservoirs. In fact, it was the same way Hides was found. The connection between topographical maps and subsurface maps was actually how Hides was originally discovered.
Using this advanced LiDAR that can get underneath the rainforest canopy and integrating that with our subsurface model, Mosa has come up. 3 km from the existing CPF facility. We have a lot of ullage in here. This is the KMT out here. This oil export pipeline in the 1990s, this was producing a lot of oil. There's no additional cost for us to be able to use that capacity there. It's a couple of wells and a pipeline back to CPF. We're very excited. Large scale. It's in the same PDL. There's no permitting. There's no fiscal agreements to work out. There's no infrastructure to build. A very quick tieback to the CPF and hopefully to give you a bit more information on that in the coming months.
For us, we're going to do that well next year, and that's going to be a great addition to our oil business. Before I get Bruce to come up, I just did want to go back through a couple of things. Reiterating what Kevin said. From our base business, we're going to focus on areas where our high margin barrels are. It's about focus, and that's going to allow us to explore and continue to put money into our tier 1 assets, which is where we're going to get the most value. The number of tier 1 assets we have is a problem. It's a good problem to have, and I think that's going to be a unique thing for most oil and gas companies to decide which tier 1 asset they want to spend their money on.
To be honest, that is a fantastic problem to have. Without further ado, I'll welcome Bruce up. He's got some pretty good stuff as well, but we're going to have to fight it out, Bruce.
All right, thanks, Brett. Thanks very much. Cage match, huh?
Yeah, I think. I don't know.
I don't know. I started out as a strong young farm boy, but I feel like an old man right now. I don't know if I can take you in a cage match. All right. Thanks very much, Brett. I'm Bruce Dingeman, I lead Alaska business for Santos, reporting to our CEO, Kevin. I'm going to jump straight into our Pikka Phase 1 status and ramp up to start with. We're laser focused on it because as Phase 1 transitions from development to production, it'll be the anchor asset that underpins our long-term growth. I'd like to point out this photo up here. This is actually the Nanushuk Processing Facility, or NPF for short. This is some time ago, before all the modules were placed and things were hooked up. On my next slide, I'll show you what the current state looks like.
This is a key piece of kit for the project. That's where the magic happens with the crude oil processing. After I cover the Phase 1 update, I'll pivot to the long-term growth story, and it's really quite compelling, as others have talked about leading up to this point. It really underpins the key set of opportunities that support Alaska as a core growth pillar in Santos' portfolio. With that, here's the photo that looks a little bit more recent from that same processing facility. You can see we used a modularized and truckable approach, and all these facilities stitched together allow for extensive crude processing ready for oil shipment. You'll also know that last week we announced first intermittent oil through our custody transfer meter having been achieved. It's a huge milestone for the team and also for me personally.
It's a culmination of eight years of work for me. In the first week of June, we'll proceed to continuous production instead of intermittent, which is another milestone. In the remainder of June, we'll bring on our gas compression and produced water subsystems. That'll allow us to hold at 20,000 barrels a day as we bring on our seawater treatment plant and water injection, at which point we'll then ramp to 80,000 a day in the third quarter timeframe. The key drivers behind that plateau attainment are both the water injection and the well inventory build that'll drive that plateau attainment. You can see on the text, I think I've covered most of those points there about the ramp up in plateau. Moving to the next slide.
These are some of the attributes for Phase 1, really the key point I'd like to make is that Phase 1 is foundational for the business in Alaska. It's the basis from which our future growth will proceed. It establishes a long life, high margin production base. While Phase 1 develops 400 million barrels of 2P gross by itself, there are an additional 600 million barrels of currently booked 2C resource attributed to Pikka. When that will be developed through subsequent activities, that gives rise to a total resource volume of 1 billion barrels recognized for Pikka. This 1 billion barrel gross field potential is on a 2C, 2P basis. There's further prospective resource upside beyond that billion barrels. That's what I mean when I say it's a foundational part of our business that we can grow from.
Some of the key attributes from Phase 1 are shown here as well. I've already mentioned the 80,000 barrel a day gross plateau rate. Thinking of it on a Santos net after royalty basis, our volumes will be about 12 million barrels per annum, which is roughly about 29 billion barrels gross per annum when we're on plateau. The 2P volume that now will be moving into production phase is that 400 million barrel gross, which on a net after royalty basis is 164 million barrels. Mark talked earlier about resource life, and I think he showed it on a 1P basis when comparing to others. On our 2P basis, it's a 14-year reserve life, so that's a long-lived asset. Also, not on the slide, I would like to point out that there is a point there about under the $8 a barrel production cost.
There's a sub-point about tax royalty and fiscal stability. The key point there, though, is that we have durable margins because our tax royalty structure is fixed and the fiscal regime is compelling. Together, all these things give us a full cycle internal rate of return from FID, the full cycle for the project, that's in the high teens, which for a foundational entry where you have to build all this infrastructure is really quite amazing. The last point speaks to our Scope 1 and Scope 2 net equity share of emissions being net zero. How did we get there is really through electrified operations, and those are low-carbon intensity. The other part of it is, so that's low by nature, our emissions. The other part is that we realized offsets by partnering with Alaska Native corporations to offset the remaining emission share.
It's the first oil and gas project in Alaska to have these kind of attributes being net zero. Moving to the next slide. There's a lot to look at here, but just to give you a sense, this is a picture of the North Slope of Alaska, and it runs about 600 km from west to east. Really a pretty extensive area. This represents the North Slope Basin. The Santos leasehold is highlighted in light blue, and I'd like to call your attention to what we call our core area. That's Pikka, Quokka, and Horseshoe. We'll dig into that in a bit more detail. We also have significant leaseholding with Apache out in Lagniappe, where some discoveries have been previously announced, and then a large leaseholding with Armstrong in NPRA called Nanushuk West. There's a couple key things I'd like to point out.
It says here the heart of the Nanushuk play. Santos really enjoys a first-mover advantage in this new generation play. It's now central to North Slope resurgence. This is a mature basin that has a new generation play that has now come to the fore. Part of that is you might have noticed that there was a large lease sale recently in the National Petroleum Reserve, and it had significant activity where over a quarter billion dollars was exposed in acquiring leases. You can see the company names highlighted on the maps here of different owner companies. I'll make a shout-out in terms of Shell and Exxon both as either re-entrants or new entrants to Alaska in that lease round. This is really a validation of the play.
It's evolved from being what I'd call an emerging play into a play under development that now is understood and being pursued by multiple companies. Why is that? If you look at the geology, the coastline here is with the Beaufort Sea, and there's a basement uplift that runs parallel to that coastline. That basement really results in a regional culmination. Then there's three world-class source rocks that are in this basin, the HRZ, the Kingak, and the Shublik shale. Those provided the charge that filled this basin with hydrocarbons. You have the world's, or the North America's largest conventional field with Prudhoe Bay sourced from those rocks. Well, there's a Colville High in our core area that allows a focal point for that, and that's why these Nanushuk sands are so well charged. That's what all these new entrants are chasing.
It's really a good ZIP code, a postal code with significant industry activity and material de-risking through time. The potential rate stack in the upper right-hand corner we'll go into a bit more as I dig into the other slides, that bottom blue wedge is Phase 1, and that's our 80,000 barrel a day plateau. You can see the subsequent increments across different resource classes giving rise to up to a 3x multiple of that 80,000 barrel a day gross production. With that, I'd like to zoom into the core area here. I talked about how in Pikka Phase 1 establishing cash flow and production with its billion barrel resource potential. If you look at the Quokka field and the Horseshoe field, they each have similar resource potential as Pikka. The core infrastructure's already in place, that helps lower future development cost.
Really the way we think about it is two separate areas. This northern area, that's where our Pikka Phase 1 project is. That's where we have our processing facility. We have fuel gas supply import. We've got existing roads and infrastructure. We see very much a satellite development approach that leverages that infrastructure yielding high returns at fairly quick pace. Our southern area is really geologically interesting where we do have some exploration success, for example, in our Stirrup-1 well, as well as a previous Horseshoe well. It's farther away. It's outside three-phase flow limits to tieback, and it's a bit less infrastructure here. This area would require a new hub for development, but provides significant long-term running room for the company. Before moving off this slide, I'd also like to highlight a couple things about our offset operator activity.
In this area where Pikka is, just to our west, Conoco is actively developing the Narwhal project adjacent to Pikka. Here where Quokka is to the north, Conoco's currently got production and continuing to develop the Coyote field north of here. Over at Horseshoe, there's active activity in what they call the Minke area that Conoco is pursuing further appraisal work that's a continuation of this trend. That nearby offset operator activity is further validation of how we've de-risked this area. We already talked about the base of Pikka, the Phase 1 activity, our plan to get to ramp up in 3Q to 80,000 a day. I want to shift about now to three vignettes, and then I'll wrap up, one for each of those fields. At Pikka, there's a series of growth wedges.
The graph here on the right are just in the Pikka area what we see as incremental or accretive opportunities. There's a clear pathway to expansion with the stage development at Pikka Phase 1. The second drill site, NDC, is ready for decisioning later this year, and the facility expansion, as Kevin mentioned, would be an FID event for the following year. The important point about Pikka is that all the major key permits are already in place. These can be moved at pace. The growth is very capital efficient because these incremental development wedges leverage that existing infrastructure. I haven't touched on our drilling program, but we're actively progressing through our learning curve. Our drilling times have gone from 50 to 40, now down to about 30 days per well.
We're seeing this continuing improvement in efficiency in drilling that not only lowers our unit cost but unlocks additional potential because it can be done so at lower cost. Our facility expansion and integration with nearby resources are under evaluation, and there's these backfill and extension opportunities. We see these growth opportunities as being well over 20% rate of return type projects, but sizable as well. That's an update on the growth opportunities at Pikka. The next vignette is on Quokka. You will have noted that we drilled this Mitquq well in 2020. That was the discovery well of what we call the Nanushuk-0 clinoform. That's the well to the northeast here. Just recently, we announced the Quokka-1 well results, and that's the one where Kevin handed out the oil sample on.
That's a 10 km distance, and we have directly correlatable sands between the two wells and supported by seismic data. We feel that this northern area of Quokka, separated by this point here, is fully appraised and ready for permit advancement. That's what we're well in progress on, advancing the permitting pathway. Moreover, we think that the permit for that will be what's known as an EA rather than a full environmental impact statement, which will allow for a quick permit cycle time. I think I've already talked about the well results, I guess we did with the oil samples about how good the flow was and why that was. The high-quality reservoir, the light oil, all those things conspire to strong well results.
The thing that hadn't been mentioned is that these wells will actually be simpler than the wells at Pikka, because at Pikka, we're drilling out under the Colville River, and those represent large extended reach drilling targets. We've had wells up to 27,000, 28,000-foot departures. At Quokka, the surface geology is much more forgiving, the well departures will be shorter, which will also lower cost. Overall, we see returns at or above Pikka Phase 1 levels for this set of opportunities. The southern Quokka area represents additional upside that can be developed either tied back to the north or potentially tied back to a new processing hub with Horseshoe. Really thrilled about the Quokka discovery.
Before I move off it, I would point out the reference that we had 177 million barrels of net 2C resource booked for this opportunity prior to drilling the appraisal well. The appraisal well obviously confirmed that number and makes us more confident in it. That equates to 450 million gross, but that is just for that northern area. We are knocking on 0.5 billion barrels just in the northern area. Again, that supports the notion that this could be a billion-barrel field similar to Pikka. My last slide is about Horseshoe. You can see here the map where we had the Stirrup-1 well drilled. That well was drilled in 2020. It had the highest single-stage flow rate of any of the 20 odd exploration appraisal wells we have drilled in the area. It is like 3,500 barrels a day.
It's an area we're really excited about. We have approval both internally and with our partner to drill the Stirrup-2 well this coming winter season. It's a significant offset from Stirrup-1, and that'll begin the journey of appraisal and delineation for this feature. You can see based on its aerial extent that we've mapped, it has significant volumetric potential. A bit longer dated, bit different risk profile, but compelling very much so. To wrap up, there's a text box at the bottom of this slide, and there's a lot of words there, but I really simplify it to that we're unlocking Pikka's 1 billion barrel scale potential at Quokka and Horseshoe in a very disciplined way. The timing can be adjusted to comply with our corporate financial guidelines. This is a really deep portfolio.
It's got significant running room, but it has huge optionality in terms of the pace at which we want to execute it. That means we can responsibly deliver not only reinvestment but also cash flow back to the corporation to meet the dividend and debt paydown and other requirements. It's part of the plan that Kevin outlined earlier. With that, I'll turn it over to Alan Stuart-Grant, who will talk about our Midstream & Energy Solutions, and he might fight by proxy for me, I guess, in the cage match if needed. Thanks.
Morning, everyone. I'm Alan Stuart-Grant, the EVP for Midstream & Energy Solutions. Our Midstream & Energy Solutions business is an infrastructure platform, and it exists to unlock value for Santos by getting the lowest-cost barrels to market. We really have two levers, cost and reliability, and as I'll talk to you in a moment, we have a bunch of development opportunities that come from using the low cost and the capital that we're going to develop from that. The accountability that my team has really spans across all of the gas and liquids and LNG plants in Australia from a midstream perspective. That's Moomba and Port Hedland, including the CCS projects in the east. On the west coast, Varanus Island and Devil Creek, linking back to our CCS option there as well.
We have a large pipeline portfolio, almost 3,000 km, that brings deep expertise in running assets like those, which will become valuable in the years to come. On the LNG side, we have the Darwin LNG project, which links into Bayu-Undan CCS, and our group also provides engineering and maintenance services to the downstream operations of Gladstone LNG. The way to think about the business is that it's contracted cash flows. We generate a lot of cash, and that's actually quite predictable. We don't have any oil and gas price exposure, and that's quite an important point as we think about some of the development options we have. There's quite a bit of spare capacity in the portfolio today, so there's a lot of backfill options that we'll need to make decisions on.
The way I talk to the team about how we're going to win is because we think in cents per barrel rather than dollars per barrel. Really trying to get every last cent out of there. We bought these assets under a single umbrella in recent times, and the logic for that was really so that we could deploy the disciplined low-cost operating model and eke out as much cost benefit as we can. Ultimately, we'll be judged on the barrels that we can get to market as a result of that. The business unit actually has a very good proven track record in delivering across both cost and reliability. You can see in 2025, we're actually pretty close to 100% in terms of reliability across the gas and liquids and the LNG assets. Moomba CCS is improving.
We're not quite at 100% for that yet, we're up in that mid to high 90s, which is a good place to be. We can always squeeze more value out of this. Last year, we brought the unit operating cost down by about 15%, and that, as Kevin's outlined, always wanting to beat inflation, and that's the benchmark against which we are tested. The way we do that is by getting really good at campaign maintenance and shutdown planning, excellence in both the planning and the excellence in shutdowns. I'll use a couple of examples to try and bring that to life from last year. We did the longest shutdown in Varanus Island's history last year. That was done at better economics and around 18% shorter duration than was planned.
If you add up all of the benefits of that improvement since 2022, it equates to over 6 million barrels of additional production through the upstream. Similarly, at Darwin, where we just completed the Darwin life extension project and the pipeline duplication project, the former of which was done around $200 million cheaper than the prior owner's concept study shows back in 2020. Now we're processing all of the Barossa gas under a tolling arrangement there. Really exciting that we're able to use that tolling arrangement to put in place a really neat project financing, which will become very valuable as we look to develop more in Darwin and at Bayu-Undan.
This strong performance, coupled with an increase in diversification of revenue that we're getting from ACCUs being generated from the CCS project, means that we can improve our margins and deliver that to the bottom line. What I hope for the next few years or intend for the next few years is actually just much more of the same. We're going to be applying this ethos to the expanded portfolio, and Steve will talk in a minute to some of the technologies that we're partnering on to make sure that these assets hit their full potential. From a portfolio perspective, across Australia and Timor, there's a lot of exciting optionality within the portfolio. We've got across three different buckets, upstream development adjacencies, CCS to decarbonize at scale, and then ultimately low carbon fuels and power. We've got a lot of options and really heaps of backfill.
You've heard from Brett whether it's across the Cooper Basin through the MCO project or the Beetaloo, where there's going to need to be a pipeliner and indeed potentially pipelines, plus an additional train at Darwin over time. All of that is going to require development, and Bruce, I'll challenge you in that cage fight if you wish. What I would say, however, is that this business is subject to the same hurdles and the same capital allocation framework as the rest of the business. Wherever we can use third-party financing or other funding techniques like we've done at Darwin, that's something we'll definitely explore. The way I tend to think about the business is what's good for upstream is good for midstream. That's where the additional flows are going to come. This is very much a sort of complementary or support arrangement that we have in place.
Over the next few slides, I'll show you some of the CCS opportunities that we're going to be developing again for upstream. I think everyone's aware of how the energy transition's evolved over the last couple of years. That's something we've watched very closely and been very realistic about what we should invest in and what we should dodge. We are very committed to carbon management services. If we think about the Moomba CCS project in particular, that project is performing to plan. It's been mentioned we've now sequestered over 2 million tonnes of CO2, and amazingly, that accounted for over one-third of the total Safeguard Mechanism reductions in Australia last year. A huge contribution. What that allowed us to do is get issued by the Clean Energy Regulator, 1.2 million tonnes worth of ACCUs. That's new and additional revenue and diversification that's coming through.
When we think about what's next for Moomba CCS, we'll be super targeted. In the near term, you've heard from Brett, we're going to be getting some CO2 from the Beetaloo, probably equates up to around 1 million tonnes, so not huge given its low CO2 production. When given the size, it is actually still a reasonable amount that will help with backfill and over time expansion. When we've had these discussions in the past, we've talked quite a lot about third-party CO2 as well. That's something we're still focused on for sure. The way I'd encourage you to think about Moomba CCS is that it's set up, it's established, it's ready, and over time, as the transportation of CO2, both domestically and internationally proliferates, we are ready to go.
Bayu-Undan is the next cab off the rank from a CCS perspective. We intend to develop a 10 million tonne per annum hub there in Timor-Leste. It's one of those assets that is so well-placed because it can cater not only to domestic volumes, adjacent offshore volumes, but also Asian volumes in time. To take you a little bit through the timeline of what's happened at Bayu-Undan, in the middle of 2025, we ceased production at the upstream field, and that precipitated the suspension of operations phase, which we're well progressed on now. What that phase really does is develop the asset and get it ready for transition into a CCS project, but critically, also allows us to defer the big decom liabilities that we have, which obviously has a value there as well. This is a large scalable CCS project, and very importantly, it's brownfield.
There are other CCS projects that are looking to be developed in the region. They're greenfield, and almost by definition, they're going to be higher cost. The first thing that we'll be doing is having Barossa as the anchor CO2 tenant for this project. We will be able to give that 2.3 million tonnes a year of CO2 that Barossa has a home and give it a low-cost physical hedge against the Safeguard Mechanism. We completed all of the FEED engineering studies during the course of last year, and now the sole focus really is on getting the approvals, the fiscal and regulatory arrangements in place with the Timorese and also the G2G arrangements that we need with the Australian Government.
We're getting pleasingly very good engagement from the Timorese government right up to the Minister of Energy there, and he's personally engaged on this, and sometimes it feel like Dili's my second home. We are making very good progress there. My final slide, I'll just talk a little bit about geothermal and what we're doing in the Cooper Basin, which is super exciting. Kevin alluded to it earlier. For those of you who not aware, the Cooper Basin is a world-class hot resource. It's a basin that we understand extremely well, given the decades of experience that we've had there. What we're looking to do is develop a pilot close to Moomba so that we can look and try and displace fuel gas, get that sold as sales gas, and then have a new lower cost form of power to run the plant there.
In doing, we're going to use what's called Enhanced Geothermal Systems, EGS. This is a technique that uses fractured stimulation to inject liquids into hot, dry rock and then generate steam, which can then be used at surface to generate power. This is being used pretty widely in the U.S. at the moment. What we're trying to do is use some of the capability in Brett's team for oil and gas drilling and applying that to decarbonization whilst learning from what's going on in the U.S. If you've read anything about it, the AI data centers are really trying to use geothermal as a low-cost baseload power for their data centers. There's a couple of companies out there who are using this technique that we're looking to replicate.
The first thing that we'll be doing, we'll drill a vertical appraisal well in the back end of this year. What we'll be doing is using that initially to test the temperature. We're targeting about 200 degrees Celsius or more, but we're pretty confident we'll get that because there's already been about 45 wells over the last years that have intersected those sort of temperatures. What we can do is use the data from that appraisal well to then plan what comes next, which will be a multi-well campaign and ultimately bring down the cost. The way I'd sort of encourage you to think about this is if we get the initial pilot plant up and running close to Moomba, it'd probably be a 1 MW or 2 MW power station, which is about 5%-10% of Moomba's load today.
We've got a vision that we can get that over time to more like 20 MW of power. If we can do that starts to take out close to 100,000 tons of CO2 from Moomba. That's real change. If we can use this to demonstrate geothermal as a viable alternative, that goes to what Kevin was saying earlier about how we're thinking just carefully around that third horizon of our strategy. Before I hand over to Steve, just maybe a few comments in closing. We've got within Midstream and Energy Solutions a fantastic irreplaceable set of energy infrastructure across Australia and Timor-Leste. We're focused on bringing down costs, increasing and maintaining reliability so we get better margins whilst decarbonizing as well. Ultimately this will mean lower cost barrels to market and unlocking value for Santos. Thank you.
Good morning. My name's Steve Trench. I'm the EVP of Operations and Technical Services. You just heard about all the great assets and the high-quality growth opportunities that we have in front of us. I'm here to talk to you a little bit about how we're going to get this done, and not only that, why I have the confidence that we're going to continue to outperform well into the long term. We will build off our proven high-performance, low-cost operating culture. We will transform our infrastructure returns and our personnel efficiency through technology and AI. We'll connect some of the best capabilities across the company and the globe with world-class technologies in a centralized global operating hub to help us connect these capabilities and perform at scale.
We've got a strong track record of delivery, and I'm really proud of the people and the culture that sit behind this. You've seen this track record of delivery through some of the financials that Kevin and Lachie showed a little bit earlier. The team have been able to deliver a world-class safety culture, delivering record personal and process safety results. Why does that matter? Well, not only is it important for the safety of our people, but this is a demonstration of a disciplined operating culture that focuses on sustainability, compliance, and manages risk, which means it's managing your returns. We've also delivered world-class reliability across our assets.
If you take a look since the start of our reliability improvement program several years ago, we've been able to deliver up to around 7 million barrels of oil equivalent additional production from our Varanus Island and our PNG assets through the application of these techniques. Importantly to our strategy going forward, in particular, the operation of LNG assets and the growth of our LNG business, as you heard from the folks before me, we've sustained 99% production reliability across those assets. Now, we don't focus on these metrics just for the charts. They lower production costs. They increase production, which therefore results in improved margins, both sides of the equation. It all matters.
I share this stuff with you because I want you to leave here today knowing that this sort of a performance culture and this focus on continuously chasing the margins and continuously chasing the barrels is in our DNA. I'm confident that we'll continue to outperform as we bring these tier 1 growth assets into the portfolio and wherever the capital gets allocated across the various asset managers. Technology is going to play an important role in improving return on capital and in lowering production costs, particularly so because our strategy is leveraging the use of existing infrastructure. We're not only just talking about technology like many others out there are doing, we are actually implementing it all the way through our integrated value chain.
I wanted to just share a few examples of how we're doing that at the moment, but this is only the start of what's to come. For example, we're seeing the potential of greater than $60 million of annual production benefit through the application of AI-driven oil field technologies. We've already seen $18 million in annual benefit as we built out these models and as the AI starts to take hold, and we can see the running room to scale out to this magnitude. Classic example of this would be in our Cooper Basin, where we're shifting from a reactive response type operating model through the use of this capability to an autonomous, continuously monitored operating model. What does that mean? Well, take 400 gas wells. We've seen three times the production enhancement opportunities through the application of this technology, essentially free barrels.
Something that it would've taken months, if not years, for the humans to be able to identify those opportunities. Another example is $70 million worth of CapEx out as a result of machine learning-assisted bottom hole pressure modeling across some of our onshore assets. Through building out this sophisticated model overlaid with machine learning capability and AI response, it's enabled us to have the confidence to no longer need to install physical downhole gauges in hundreds of wells going forward. What? Well, that reduces CapEx up to this level, but it also reduces operational complexity and improves response time. Another great example of that technology in play. We're also lowering drilling costs.
An example that we've seen recently here in Australia, through the application of an auto-drill AI-assisted technology that connects the drill string to our integrated remote operating center in Brisbane, which I'll talk to you a little bit more shortly, has enabled the harnessing of thousands and thousands of geological data points, drilling parameters from our years of drilling capability, and sending predictable signals to the drill string to essentially continue to operate in the zone. Taking out all of the human variability and human error that comes with our operations. It's a fantastic outcome. When we go abroad into our U.S. operations, through the application of technologies that are being used extensively across the U.S. in the Marcellus, the Eagle Ford, but also in the Montney and here in Australia, we've been able to increase our lateral drilling length by 130% in Alaska.
We've had a 50% reduction in the time to drill to 10,000 feet. We've actually drilled a 11,000-foot-long lateral, and in fact, we've just drilled our third combo well. What does that all mean? Well, essentially the money section is the horizontal section. That's where it's fracked. That's the productivity section. We're now able, through these technologies and this capability, to essentially be able to combine two wells into one through the extended reach capability of the team. Now, when you look at the running room that Bruce talked about before in Alaska, avoiding the need to install all of that surface well bore infrastructure and surface infrastructure across a number of those developments, that's significant capital out.
It's one thing lowering the drilling costs, but you need to improve the quality of the well bores and the productivity of the well bores that come with it, and we're doing just that. More recently, we've seen an 80% increase in frack installation productivity in our U.S. operations. What does that mean? Well, we're basically pumping more proppant faster, which essentially for the same unit cost is resulting in greater productivity in our well bores. More locally, we're seeing reductions in pumping time in the frack operations that we've got through a world-first application of Halliburton's OCTIV technology outside of U.S. shales into conventional reservoirs, allowing us to automatically feed instructions to the frack units out in the field, improving the quality, reducing the chance of screen out, and improving our well productivity across a number of our fracked wells.
More recently as well, we've seen the use of AI technology to remove people from the field. A great example of this, and sorry to any of the geologists in the room, would be the use of this AI lithological capture system, which essentially is using photographs and video technology to scan cuttings, send the information back in through the model, have it verified onshore in our operating center, removing the need for geologists in the field. That's only the start of this sort of technology and how it can be applied across the hundreds of operations that we run across the globe. I share these things with you because they are going to be critical enablers in driving the cost down and the performance up across our tier 1 growth assets. The Beetaloo Basin, we've already got this U.S. shale technology in play.
We have U.S. shale capability within the business, and we're going to connect that up and apply it to continuously perform and drive the cost out on these future opportunities. It was mentioned before that I'll talk a little bit about decommissioning, and I think it's really important that we do. Decommissioning costs and lowering our decommissioning costs is an absolute priority for us. Our application of technology doesn't just stop at the identification, the extraction, and the production of our resources. It's actually being applied right across the value chain. We've just built a highly capable, dedicated decommissioning campaign team that will focus in a progressive manner, working across each of the key assets that are moving into the retirement phase, planning them, executing them, locking back in the learnings, and delivering outstanding outcomes.
I'm really proud to be able to share a few examples of that with you today. In the well space, in the Mutineer, Exeter, Finucane, and Fletcher project or asset, we set new benchmark performance levels in well decommissioning durations when we compare to global activities of a similar nature. Why is that important? Well, it lowers the cost of executing that work. For our Ningaloo Vision FPSO, we set new benchmarks from the time that the operations were suspended, AKA when it stopped delivering returns, to the point in time when that asset is off the books. Offshore operations are high risk, high cost activities, shortening that time and pivoting to the next stage is of crucial importance to us. Finally, the one that we're most proud of, is the Harriet Alpha platform removal.
This is a classic example of that campaign team combined with the use of technologies and how it's delivered outstanding outcomes. This is Santos's, well, I would say this was Santos's, largest fixed platform and decommissioning activity, and it's behind us. In fact, it was Australia's largest fixed platform to be removed offshore. This was a classic example where through the application of technologies like submarine ROVs, removing divers from the line of fire, 3D models, drones, specialized cutting techniques, staged removal process from barges through to smaller vessels and larger vessels, we were able to deliver this activity well below cost and ahead of schedule.
I share these examples with you because I want you to have the confidence that not only are some of the largest decommissioning activities behind us, but that we will continue to liquidate this scope in a capitally efficient manner, and I'm feeling pretty confident that we'll deliver this well ahead of promise. Finally, connecting up the best capabilities under a global remote operation center designed to scale the performance and capabilities that you've seen to leverage the economies of scale and apply that across our global operations, whether that be in advisory, surveillance, support, or control, the operating model is open as we choose. How are we going to do it? Well, extending off some of the experiences we've had with remote operations in our upstream operations, we'll extend that out across upstream and into our midstream portfolio.
We'll also build out our pilot integrated remote operating center that we're applying in the drilling and completions arena. We'll create a centralized, highly technologically capable hub in Brisbane that will be the brain and the operating center, and it will provide support out to the operating sites across the globe. Why would we do this? Well, firstly, it lowers cost. Not only is it going to reduce overheads and bring people out of the field and surround them with like-minded capability and technology, but let's take, for example, the opportunities that Alan just talked about. Like I talked about with the decommissioning side, our drilling and completions experience.
When you bring people together in a campaign fashion, like in our maintenance and turnaround capability, you have the opportunity for the best in the business to plan, to scope optimize, to coordinate large-scale contractor workforces, to travel around our Australian sites and execute these large-scale turnarounds. That lowers the cost of those activities, and it improves the productivity and the production from those assets because the duration is continually coming down. That is direct bottom-line benefit that we can see coming from these sorts of activities. We'll see the same in the drilling space. As we enhance and reduce the overheads, we improve the drilling performance and lower the cost. We expect that it's going to improve reliability.
By having a centralized capability that provides surveillance, advisory, and support across our operating assets, we expect to avoid trips, to improve uptime and throughput, which is ultimately going to improve returns. We also expect to identify a number of debottlenecking opportunities. What I'm most excited about when I look at the Barossa to DLNG value chain, my experience in running large-scale integrated LNG assets, I believe that there's quite some potential in that particular asset base. Finally, the magic in all this is that it scales with growth. As we bring in these tier 1 assets, this centralized operating center can expand in a pod-like manner out and supporting the operations to continue to bring that capability to bear.
In closing, as you can see, I'm pretty proud of the results and the culture that we have in Santos because our operating performance matters to our strategy and to your returns. I want you to leave here with the confidence that we will continue to deliver this performance throughout our base business, and we'll extend these capabilities into those tier 1 growth assets you heard about before. Thank you.
Thank you, Steve. Look, I realize we've filled the time. We still would have some Q&A if you've got the patience to stay with us. Maybe if I could get four chairs put up here, we'll just get that done as I'm wrapping up. You've heard from the management team. I've said it many, many times. I think I'm often blown away when I look inside the organization at the depth of talent and capability we have. I still put this management team up with any management team across our sector in this region as the best in the business. I truly believe that. You can see some of the great work that they're delivering today.
Today's been about communicating to you our focus on our tier 1 assets in order to grow our free cash flow and deliver consistent strong shareholder returns through the cycle and for decades to come. In summary, some of the key takeaways. You heard from Brett and from Bruce about the status on Barossa and Pikka, that they're ramping up now or close to ramping up in Pikka. In Q3, we'll have both those assets. We expect both those assets at plateau production, and that's the start of that cash flow inflection point. Lachie talked about the capital allocation framework and took you through how the $45-$50 free cash flow, all-in free cash flow breakeven works, and controlling and providing discipline into the business, and works alongside the disciplined operating model.
That cash flow inflection point, how we talked about every $10, the actual oil price is above that 45-50 breakeven, will generate between $550 million-$600 million in free cash flow each year from that portfolio going forward. We also talked about the net debt reduction target, $2.5 billion between now and 2030. Again, driving value, bringing discipline into the business, and freeing up around $150 million per year in interest payments because of that lower net debt position. We gave you feedback from the strategic review and showed you the four chunks of assets and what that means. Particularly in the Cooper Basin, now we're focusing going forward or prioritizing, I should say, our capital investment in the Cooper Basin into that central area where the majority of our resource across the Cooper, our future resource, undeveloped resource exists.
Taking out $300 million in CapEx between now and 2030, and $150 million a year thereafter into the future. I know you heard from Alan and Steve how we're leveraging our midstream position and our application of technology, fast application of fast developing technologies, through simplification, infrastructure optimization, and the energy solutions capability to drive emissions down, to drive value, create new value from those assets. The day, as I say, has been around or about the focus on those tier 1 basins across three regions to drive the future growth and prosperity for Santos, and particularly focused on developing those tier 1 basins in Alaska and PNG.
Also fully appraising the Beetaloo Basin that provides us the ability, if we can make it work, to backfill and expand our current Australian LNG capacity, and very importantly, to test the Bedout Basin to see if we can create a fourth tier 1 basin for the longer term. The Bedout Basin stacks up economically. It looks great. It is now about testing for scale. It provides energy security advantages for Australia and the region. That is a wrap-up of the presentations you had today. What I would also add is that it brings us right back to our value proposition, which I think is as clearest as it has ever been.
It's about focusing on that high-quality asset base to grow the free cash flow across the business and continually grow that going forward to provide strong shareholder returns whilst being able to sustainably invest in the growth of business over the longer term. That concludes the management team presentations this morning. I'm going to ask Brett, Bruce, Lachie, and Alan to join me on the stage, and I'm happy to take any questions and throw it to them or anybody else. Feel free to ask anyone else who presented a question, too. We can get them out to them if you want. I'm going to ask that I know I'm running late, and apologies for that, but there's a lot of content to get through. I did expect us to be a wee bit quicker. You heard some really interesting things from the management team.
I thought it was really interesting to see the videos for the foundation and all that sort of stuff at the break. I was telling you, we almost brought a tear to a Scotsman's eye as we came back from the break, and it was just so refreshing to hear Steve, where's Steve? Steve referring to his workforce as the humans. I thought that was really warm and fuzzy as well as we got to the end of the presentation. Look, happy to take any. We've got some mics. Can we get some mics up here as well for the guys? Oh, you're all miced up, aren't you? Cool. One question at a time, please, and we'll come back to you if we run out of questions. Who's first? All right, go for it.
Hi, Dale Koenders from Barrenjoey. Thanks, Kevin, for the presentation. Thanks to the team. Pretty clear message around increasing free cash flow and growing returns to shareholders. As part of that, on slide 22, I think you've provided an outlook for those cash flows, which included CapEx of about $10 billion over the next five years. I'm just hoping you could provide some color about that number, which is very similar to this year's guidance for CapEx. What's included there in terms of projects? What's included sustaining versus growth, decommissioning, et cetera?
Well, first of all, I'm going to hand that one to Lachie. I'm going to give you 30 seconds to think about your answer. What I would say is that in terms of what projects, I'd say it can be any combinations of different projects. You can see there's a lot of optionality across that. I would always put it like this, that if things get difficult in Australia for a little while, like they did a few years ago, the great news is we can fast-track some of that stuff in Alaska ahead of Australia. We can pivot. We've got the ability to pivot within that portfolio. I think Lachie talked about the fact that it would also depend on equity levels as well, which ones. Lachie, I'll hand it to you. I'd love it.
Thanks, Kevin. Thanks, Dale, for the question. Look, that chart demonstrates where we'd be if we're around the midpoint of our guidance in that $45-$50. That gives you a pretty good feel for how full we could have the CapEx level. That $10 billion is around the right number. That number in terms of development CapEx is not fully defined in terms of the amount of projects that we will do. We're sort of saying that we've got capacity to spend up to that level while generating that free cash flow generation in that model. That model I think is struck at around $47.50. What you'll probably find is the development CapEx or the growth CapEx, it may be higher or lower within that $10 billion range, and that also depend on where the operating base is.
Obviously, all the projects that we've got taken FID on and committed to are fully in those numbers. There's a wedge that we've taken up that we've got obviously the competition for capital, which will fill that void, Dale, to the end, which is effectively the competition with the projects that the gentlemen on my left have all presented on.
Papua's in that.
I should say, sorry, yeah, Papua, we have assumed that Papua would go ahead, and the Papua CapEx profile is within those numbers.
Cheers. Thank you, Dale. Yep, go for it.
Yeah, morning. Adam Martin, E&P. I suppose a lot of focus on the Beetaloo today. Maybe we could just talk a bit about those three wells that are upcoming. You talked about sort of three different shales there that have got potential in the east. What's the sort of, I suppose, what are you trying to learn from those three wells? To get to that FID situation, particularly the bigger project, how many wells do you need to get done in that acreage, do you think, in the next few years?
Brett
Thanks, Kevin. Thanks, Adam, for your question. Yeah, look, as I had on the slide there, we have three shales. The one that everyone's talking about is the B Shale. That's a no-brainer. That's where we're planning to have two of the appraisal wells. We'll actually intersect, and then we also want to appraise the A, which is the one below that, so it's higher pressure. For us, that's an opportunity for us to even get a lower cost development, right? Ultimately, the number of well pads you need, because you've got stack developments, it's got a huge advantage, not just from a resource size, but from a cost of development point of view. What we're trying to do out of the appraisal campaign is not just prove the resource up. We actually want to prove the deliverability of the wells.
These will be drilled as if they were development wells as opposed to appraisal or trying to get subsurface data. Hence, the reason we're going to drill pretty much the same well length that we would in a development scenario. We are planning to do 60 stages of fracking as if these were the development wells. Then we are looking at our long-term well tests, so at least nine months of well testing to get the type curves that we need to prove up five TCF, which for us is 500 terajoules a day, which is a development size that we would need to evacuate that gas to the East Coast via Ballera without having to build a pipeline from Ballera to Wallumbilla and then Wallumbilla to Gladstone. It's sort of back calculated on the minimum development size.
You need scale, you need somewhere to put that gas, and then ultimately that's driving what we're trying to do with the appraisal program. Five TCF, 500 TJs a day for 20 years, three wells that are drilled as basically development wells to test the B and ultimately the A. Yeah, that's what we're trying to do with the program.
Of that 3.2 billion 2C number that Mark took you through earlier on, 1.3 TCF, whatever that is in BOEs, 1.3 TCF is booked for the Beetaloo today. We're looking to add another 3.7 TCF to that through this campaign. That is not in the 3.2 billion 2C that we have. It's a very significant add to that. I think the other thing we should say is not in any of our forecast production numbers, but we intend to produce from these wells rather than flare the gas during the well testing, so produce to market. That'll be sales gas once those wells come online.
There has been 12 wells drilled there since we last drilled there as well. Obviously we're learning a lot from the other operators up there who are targeting the B Shale. We're getting lots of information from that. Tamboran's a joint venture in the EP-161 as well. We're using all the expertise and all what they've learned as well to make sure we can do this as quickly and as efficiently as possible. We don't have the answers. We are a sponge learning everything we can, not just from the local folks operating in Beetaloo, but from the other shale operators as well.
Hello, Sarah Kerr from Argonaut. Thanks so much for the presentation. Just touching on the reservation policy, I understand it's just under the draft mode at the moment. What is Santos' strategy during the consultation period to the end of June, and where does that place GLNG if that 20% domestic commitment stands?
The question is, tell me your strategy for engaging with the government. Yeah, right. Look, I've said it many times, I said it last week at the APPEA conference. First of all, we are comforted by what every minister has said, that existing contracts will be protected, and we're going to take them to their word on that, as they always have done for the last 10 years. That in itself is comforting. As for the document that was released yesterday, I think it raises more questions than it gives answers. When you read it, I don't know how many times it says that existing contracts will be protected. It has a lot of contradictory sort of statements or what could be interpreted as contradictory statements.
I think you'll find even as recently as the last couple of months when the Prime Minister was going around meeting other governments, we were giving assurances. I heard Minister Bowen online on national television, I think it was, saying that existing contracts will not be impacted, and indeed that this would apply to uncontracted gas. Look, we'll engage with the government in good faith as we always have done. We'll continue to be a major contributor to the domestic market as we currently are. I'm very confident that we'll be able to continue to export and meet our contractual commitments. Thank you for the question. Tom.
Thanks. Tom Allen, UBS. Just following your last answer, Kevin, in the context of a consistently uncertain policy environment in Australia for the sector, it's encouraging to see two big growth opportunities in northern Australia around the Beetaloo and the Bedout Basin. Wondering if all of these growth projects, and there's plenty in the portfolio, are going to compete for capital amongst each other. Your capital framework clearly isn't going to pursue all of them at once. They're going to be selectively brought forward. Could you talk to some of the post-tax asset returns that you think would support an investment decision for a Dorado compared to a Beetaloo or maybe some of the others? I think Bruce, in your section, you made reference to some of those incremental developments in Alaska supporting over 20% IRRs, but keen to see where Australia fits.
Well, I'm not going to tell you what the hurdle rates are within Santos. What I can tell you though.
Maybe a range.
It's competitive though, right, between them. The fact Bruce put his number out there, to me that was the first step in the cage fight he's talking about. Put his numbers out there, which I actually think was a bad tactic, Bruce, because Brett now knows what the number is, right? What I can tell you though is that what we see in that portfolio is a lot of projects the likes of which we've never been able to look at in years gone by with numbers around that level or better. In fact, if I look at the Pikka Phase 1 expansion, that's even higher. That's mid-to-high 20s. We're now seeing IRRs on assets and project opportunities that historically we just never had. With the Cooper Basin, with CSG, these are tough assets to make money from, and it's a slog.
It's about constantly just doing it better and better year in, year out. This is a different scale. We've built a company now that has the opportunity to go to a different scale. We've got to keep that disciplined operating model working across those assets that supply other benefits to the portfolio. In this case, what we've got the opportunity now is to scale up and focus our major investment capital in those higher return assets. I'd say, that's not going to be an unusual level, particularly where we're leveraging off existing infrastructure. I think the one you're probably thinking, wanting to ask me about is Papua. Maybe.
I did, but.
Yeah. Papua is really good.
You got enough equity in it, right?
That's a very vague, accurate number, right? Have I got enough equity in it? Look, I would like more equity in Papua, but I don't have more equity in it. It is what it is. We do create value from the access fee, from the toll, and from the shared OpEx. That is very considerable value. That adds about 2% IRR. This project screens without that for us. Papua screens without that for us quite easily, meets our investment hurdles. We get about an extra 2% IRR because of those leveraged position because of our infrastructure position in PNG LNG, our foundation project. Look, you're looking now at the competition between these guys for capital is across, I think Brett said it's a good problem we have. We've got a lot of high return projects.
We will deliver them within that free cash flow all-in breakeven of $45-$50. That means you've got to deliver them in a disciplined way, ordering things, probably two and a half at a time that we could fit into the portfolio, depending on equity levels. Yeah, cheers.
Yeah, good day. Rob Koh from Morgan Stanley. Thanks very much.
Sure
Presentation today. Can I maybe just ask some infrastructure type questions around Beetaloo development? There's other people with other plans. Equinor is talking about Train 3 and the like. Can you talk to the opportunity for shared infrastructure and lessons from Queensland and things like that?
Well, I'm going to let Brett answer that. Alan, you feel free to jump in as well. What I would say is the development of the Beetaloo must not be like we've done in other parts of Australia, where we build our own infrastructure, and we don't get the leverage positions and sharing. In fact, I was talking to the new CEO of Tamboran last week, and we were making that point, looking at putting in place an operators forum to get it right from day one. From day one, let's start working on that master plan to get shared infrastructure so that everybody gets the benefit of lower development costs. Brett, anything you want to add to that?
The Northern Territory Government is also very supportive of us getting together and make sure that investments that they want to make as well in that infrastructure is done in a combined way. In the end, there's no value in us all creating our own hubs, our own airports, our own bases. Our third-party contractors that need to set bases up to supply to all of us as well are asking the same questions. That cooperation is key. As Kevin said, there's a long list of projects in Australia where you haven't seen that cooperation. I can assure you, we are working not just with the other operators, but the Northern Territory Government is incredibly supportive. You can see what they're doing with the pipeline easement, and it's not just for that, it's for data, it's for gas, it's for water, whatever.
They're getting heavily involved. We've got a very supportive jurisdiction up there that wants us to cooperate. I believe we've got a good relationship. One of the other major players up there, Tamboran, is actually one of our joint venture partners. Yeah, we will do our best because it's in no one's interest to build two, three sets of infrastructure. This is going to be a hard slog. It is remote. You need scale, and you need to be disciplined on your costs. We need to do all of those things. All the other operators there, I haven't had one person say we shouldn't pool our activities. There's a lot of sharing already up there. I think, yes. Yes is the answer.
I'll add to that, we are talking to all the major pipeline operators in Australia, aren't we, Alan? Including Alan.
Yeah, look, it goes without saying that we'll work through what the split between the upstream and the midstream spend will be between now and FID. There's a lot of water to go under the bridge yet. We've got an inflation-beating model. We've got the best acreages, as Brett said. We're going to play an important role in determining how the infrastructure gets set up. As I mentioned before, what we've done at Darwin in terms of using other financing and working with partners, all of that IP can be applied here.
I think very importantly, our model must be one that we get the benefit of depreciation on the assets over time. That's an absolute. Whatever the infrastructure we're putting in place in the Beetaloo, we're talking about multi-decades of operations here. We will ensure whatever model we go with, we get the benefit of that infrastructure depreciating over time. We don't want that getting recapitalized and keeping our base OPEX costs high. Nick
Thanks, Kevin. It's Nick Burns here. I've just had a question on your Pikka and Alaska more broadly. Thinking back over time, obviously, you've been on a bit of a journey with Alaska post Oil Search acquisition. At the time, you called Pikka non-core and you looked to sell it. You've kept it. You've really done the hard yards through that, and you've copped a bit of criticism for holding onto your equity. Now you're at the point of startup, you've got a 51% interest. I'm just interested in, first of all, what your key lessons are from holding on projects which have got long-dated assets like this through that period. Also from here, you've got a 51% stake. Are you keen to retain that stake in Alaska? Could you sell down maybe equity in Horseshoe, Quokka, et cetera?
Are you getting a lot of interest in the asset given what's happening in the Middle East at the moment? Thanks.
Well, look, great question. I met you at the start of then. I said, "You have any questions for me?" You said, "Not yet." That's a cracker. That's a good one. I like that one. Look, let me start by saying let's go back and repeat the history lesson there. Yes, we reluctantly took FID in 2022 at the current equity level. Our intent was to sell down. You think what was the world like in 2022? It changed very quickly with ESG pressures. The banks wouldn't finance the North Slope. People were selling out. Shell left. Others, Exxon, had backed out a little bit from the North Slope, and you just couldn't give it away, quite frankly. Yet here we were with this really attractive asset, you couldn't get interest.
Well, we did get interest, but not from the sort of parties that were able to follow through and close the deals. Fast-forward a couple of years. Some of those companies have just made record bids to get leaseholds in this area, in the acreage around us, to develop the same place. Record bids. I could tell you the numbers they bid on some of these blocks. They are mind-blowing what they bid just to get a permit. That's really exciting, and a testament to the work that Bruce and the team and ConocoPhillips have done developing these plays and bringing this to life. I saw an article the other day, I think it was Bill Armstrong.
Bill will promote his own case, of course, but I think he wrote the other day that Alaska North Slope is now the hottest province in the oil and gas world, and it probably is, and you're seeing that with everybody trying to get in. Is there interest? Well, I can't see whether there is or isn't. Nobody's actually stopped me in the street yet and said, "I want to buy Pikka off you." Would I sell down or not? Probably not right now unless the value actually made sense. Certainly would be not at any discount. Is it core? You bet now. We've done the hard yards. You said it. Bruce just summarized there Pikka's most likely a $1 billion-barrel field. That's a 2P plus 2C position of Pikka, a $1 billion barrel gross.
We've got two other prospects, Quokka and Horseshoe, that have the potential to be billion-barrel fields as well. That's game-changing for a company our size. That's like winning the lotto, if you can make that the case. You don't step out of that too easily or too readily. When you start thinking of the diversity of that portfolio that we have today, now we've got PNG development friendly, Alaska development friendly, Australia, lots of good development opportunities. Still a bit to go on its transition, I would say, and working out what it wants to do with its vast oil and gas resources. We're here to develop the ones we've got if it gets to the right place. If not, we've got really good opportunities and options elsewhere, and I think that's what I'd say.
The reason I was a bit hesitant, I'm just holding Bruce's feet to the fire to see it producing, I think you said next week, and seeing us ramping up to plateau. Look, really excited by what we have in Alaska. You heard from Mark today talking about the exciting prospect. Sometimes it's better to be lucky than good, I've always said, and I'll take lucky any day of the week in this business. Right now, I'm feeling pretty lucky that we've got Alaska in the portfolio. I hope that answered, probably answered 80% of what you asked, maybe if not all, but thank you. Oh, wait.
Tom from Citi.
Tom.
Thanks, Kevin, and the team for the presentation today. Just on the domestic strategic review, Kevin, you mentioned optimizing value of the Australian portfolio. In the event that we see continued success at Beetaloo, further de-risking of that asset, at what stage might we expect to see some further deprioritization of some of these non-tier 1 basin assets? Further, any proceeds that are generated from any future sell downs or divestments, how might we balance those proceeds between reinvesting back into the business, shareholder returns, and repairing the balance sheet? Thanks.
Well, first of all, there's no need to repair the balance sheet. The balance sheet is good and strong. You threw that out just to kind of poke me. The balance sheet's good. It's strong. This is about making it stronger. You saw Moody's rating change last week to positive. We're in a good place on the balance sheet. This is about making it stronger and positioning us to be more opportunistic in the future should a good opportunity arise. To me, that's just good business. I don't know how you deprioritize more than deprioritize, maybe further deprioritize, but our capital will go where it gets the best returns. I think what we've done is repurposed that Australian portfolio. Now we're saying, "We're not going to spend money here.
We're not going to spend money there. What we are going to do is make that a business that helps us meet our domestic gas obligations, which is part of the question I was asked earlier on, from a social license and ability to export, got to support our export business and to fund the decommissioning obligations that we have so that that's not a draw on the growth hubs, the main hubs around our business. That frees up the cash flow from that business. The capital we're taking out the Cooper, I deliberately used the term earlier on, was to recycle that capital to invest in higher return projects. Of course, we'll have the capital that comes from paying less interest on our debt if we're successful in achieving, which we will be successful in achieving that net debt reduction target.
Based on that, we free up more free cash flow from the portfolio and the capital allocation framework, as it points out, says that whatever that free cash flow is, a minimum of 60% of that will go back to shareholders. I want to keep re-emphasizing that. That's a board-approved policy. Chairman's in the room, so if you don't believe me, ask him in the break, it's a board-approved policy, we made that point. 60% will be returned to shareholders. What we're not saying, I think this is really important, we're being really clear about it. We're not going to starve the business of capital and go backwards after five years and fall off a cliff. We are going to reinvest in high return projects.
We're going to continue to grow the business, continue to make it a larger scale, higher return business over time. Lachie, anything you want to add to that?
No, like any other use of proceeds that do come through, they're out of the model. It's a matter for the board what we would do with those proceeds. The numbers that we present to you don't rely on any of those assumptions or scenarios. In the model, we're at $75, and we think that we'll deliver the net debt reduction targets. If there are anything that comes along like that, then that is a matter for the board at that time.
I'm going to give you 10 out of 10 for not using the phrase that you know I don't like in that question. Anyway, good. Well done.
Hi, Rohan Bowater from Accella Research. Thanks, Kevin and the team, for the presentation today. My question concerns Barossa now producing and with offsets or ACCUs bridging the period before Bayu-Undan CCS is developed. Could you help me understand what carbon cost is embedded in Barossa's economics, perhaps as it compares to Moomba's benchmark of $24 per ton? More specifically, how that impacts or factors into the free cash flow sensitivity that Lachlan covered at the top, given the contribution of Barossa there?
I think Brett described Barossa as a world-class project today, and he showed you that production profile. I think from memory, correct me if I'm wrong here, I think the production costs, or the cash production cost for Barossa, including the actual cost of carbon, is still less than $3 per MMBtu. It's still very low, and you put that in the context of the price we get for the LNG. What I can tell you is when we FID that project, it's safe to say now, back at the time we FID that project in 2021, the LNG price assumption was under $7 per MMBtu. Just think where the LNG price has moved to in that four, five-year window, right? This is a really good, solid economic project.
The price we're paying for ACCUs today, and I think we got four or five years bank of those. We're developing our own and obviously buying some off the market to position us as per the rules of the Safeguard Mechanism, is less than the carbon price we put in the economics for the project at the point of FID. Quite a considerable bit less. You'll remember back in the days, everybody was assuming $40 or $50 by 2025 or 2030. Of course, we're not seeing those carbon prices, right? The carbon price for ACCUs is still in the mid-30s AUD. It's actually not a bad story at all. It's a pretty good story. The project economics are very, very strong in Barossa. We're getting a premium because that's even better spec LNG than PNG.
It's right in the sweet spot of the spec for our customers in Northern Asia. It's a very, very robust project. Thank you. Mark, were you want to ask a question or just scratching your head? Just scratching your head. All right. Any other questions before we wrap up? Look, again, or Mark, do you want to ask one? Yeah, go on. You waited for the last question.
Yeah. Last minute. Just in terms of FIDs, we think you'll be rewarded from these two growth projects ramping up and your CapEx structurally comes off. You're out of that last investment cycle. The message that I heard today was that Papua FID later this year and then that second drill pad at Pikka by the end of the year. Effectively two FIDs this year. I just wanted to clarify. Is that the message?
Well, yeah, the Pikka numbers are already in our budget for the year, but the pad, I wouldn't call that an FID. It sort of is, but it's really just building it, a decision to take a drilling pad, which we will approve in the second half of this year. That will actually get some cost benefits from Phase 1, from putting that pad in, i.e. shorter wells, right? I think about six of the wells from Phase 1 will be drilled from that pad. Is that correct? Yeah. Look, we'd expect to do that. Yes, Papua is the other one. I don't see any sizable FIDs. You'll see things like the CPF things and PNG and small projects like that, but there's nothing sizable really, I would say for a couple of years. We've got to appraise the Beetaloon.
If you listen to what Brett said about the plan there, that takes you to sort of first half of 2028 before you've finished that program, with the extended well testing. Anything we do in Bedout Basin, really it's drilling those three appraisal wells in 2027 and then the time to assess the results of those. Timing-wise, I'm feeling pretty good. I think the good thing about Papua, Lachie, you talked about the financing today, but there's virtually no CapEx draw for two and a half to three years from Papua because the project financing, what did you say, up to 60%?
60.
60%. That's front-loading the financing of that project, or the funding of that project. Really, from a CapEx point of view, we're in a really good place for the next two or three years. No, thank you. Look, going to wrap up for that. What I would like you to do is if you could just please show your appreciation to the management team. Put a lot of work into this presentation. I hope you found it useful and informative. Like I said on my last slide, in my view, the value proposition to invest in Santos, to hold Santos and to buy more of Santos has never been stronger than it is today. It's about focusing on tier 1 assets, growing free cash flow, and driving stronger for longer shareholder returns. Thank you very much.
Again, thanks to all the management team for your help and the staff who prepared it. Thank you. Have we got coffee and stuff outside if anybody wants to join us? Yep. Okay. Well, thanks very much.