Santos Limited (STO) Earnings Call Transcript & Summary

Good morning. Let's make a start. Well, good morning to everyone joining the 2020 Santos Investor Day. Welcome to those here in the room. It's great to be back in Sydney for first time in a long time. So it's great to see you all here in person, and welcome to everybody also joining on the webcast. Firstly, I'd like to acknowledge the traditional owners of the country in which we meet today, the Gadigal people of the Eora Nation, and recognize their continuing connection to land, water and culture. We pay our respects to their elders, past, present and emerging. Just in terms of the safety procedures for the building and in case there is any alarm. In case of emergency, you'll hear the beep, beep, beep alarm. And then if we do need to leave this room, the following whoop alarm, the head warden will make an announcement and please follow the instructions of staff here at the venue. The emergency exits are out that way down the stairs. Please don't use the lifts if we need to leave the building. And the evacuation point is at Fitness First, which is at 2 Bond Street. In terms of the agenda for this morning, we'll break the session into 2 pieces. First piece to about 10:30, then we'll have about a 20-minute break for those on the webcast, and then we'll start again around 11 and then aim to finish around 12:30 following some Q&A. For those watching on the webcast, you can ask questions through the webcast. [Operator Instructions] And we'll try and get to as many of those questions on the webcast as we can. For those you in the room, you are welcome to stay and have a bite to eat afterwards if you wish to do so. Thanks very much, and I'll hand over to Kevin.

Thank you, Andrew. And let me just reiterate my thanks and welcome to everybody. I really appreciate you taking the time to come out from wherever you've been for the last 6 and 9 months and spend a few hours with us today. We all look forward to this event every year to share with you what we've been doing in the company and where we're going and what our priorities are going forward. 2020 has been a hell of a challenging year for all of us for many reasons. Obviously, the impact of COVID on the markets, the business and the business environment. We've seen a shutdown of global economies and demand earlier in the year like I have never experienced in my career, I'm sure none of us have ever seen in oil markets. We had a crude price -- WTI price of negative $38 one day. I'm sure you can all remember back, I think that was March or April earlier this year. And quite frankly, nobody knew where that was all going. And here we are at the end of the year, and I'm delighted with the outcome and the way the business is performing as we come towards the end of the year. It's been a really solid performance, I think, for the company this year. And I think further evidence that the operating model, the disciplined operating model that we have in place across Santos is working and able to see us through some of those tough peers in the cycle. I'd just like to start also by thanking my management team. A couple of weeks ago, you all know there was a small outbreak, a quarantine breach, if you like, in Adelaide in South Australia that led to a fairly rapid shutdown. And as a management team, all the presenters who are here today, we took the decision to go home, work from home, isolate, do COVID testing in order to try and preserve the ability to have this event today. So thanks to you guys for doing that and following of all the protocols that we put in place to make today happen. Now some of the headlines that we will talk more detail about today, I want to start by really highlighting some of them. So delighted with some of the guidance updates, the production guidance, upgraded to a range now between 87 million barrels and 89 million barrels with 31 days to go. We've given you 2 million BOEs range on that guidance. It's quite a range, but it's good to see it going up. Been a really strong production year across the assets. The guys have done a phenomenal job. We haven't had 1 COVID case across any of our operations. Very, very strict protocols in place across all the fields. I'm delighted that we haven't missed a beat in terms of continuing with those production operations. Our cost guidance has been strong on cost as well, and that's been continued driving of those efficiency improvements we've been driving for a number of years So good to see the bottom end of that range. And obviously, delighted with the synergies we've been able to realize through the acquisition of Conoco. You remember, at the time we announced that acquisition, I think we said then that the guidance was $50 million to $70 million. So it's great to see that we've been able to upgrade that between $90 million and $105 million. And certainly, my hope would be in the upper end of that range, given the latest forecast. Big news on the emissions front today. We've been talking a lot about the carbon capture and storage project in the Cooper Basin. Made really significant progress on that this year. Brett will talk a lot about that later on this morning. And that's enabled us, following the successful injectivity test we did a month or 6 weeks or so ago to upgrade our targets. And so leading with the net 0 emissions by 2040. And what I'm really pleased about is we'll be able to show you a road map to how we're going to do that. It's not just a number that's beyond all of our retirement dates, and we're all very comfortable putting out there to get us over immediate pressure. And I guess from your perspective and certainly, from my own cynical perspective, I look at some of the targets other companies and other industries are making, some governments are making with a better cynicism, because I don't see it, I don't see a road map on how we're going to achieve that. What we want to share with you today is targets with a planned and a realistic, doable plan on how we're going to achieve that. And we'll share that with you later on this morning. Also pleased with the interest we're getting in that project from all over the globe, and we've announced this morning some MOUs with SK, in particular, our Barossa partner, looking at CCS expansion, international carbon credit bilateral agreements. So that's basically getting access to foreign carbon credits, a qualify for foreign carbon credits from CCS here in Australia, and foreign investment funding, clean energy funding support for those types of projects, and of course, the development of zero-emissions hydrogen. Why do we call it 0 emissions hydrogen? Because it's the development of hydrogen with 0 emissions. And what I mean by that is we can -- we believe we've got a road map to creating hydrogen from our natural gas today, the long-term target prices government are putting out there for the mid-30s, we could make that today, if there was a market to support it. And coupled with CCS, be able to handle the CO2 that it would generate from that processing. And because -- so it becomes a zero-emissions hydrogen capability. And big news. Really pleased to announce that only yesterday, in fact, our joint venture partners in Darwin LNG voted to approve the toll agreement and the various processing pipeline transport agreements and process agreements to support the Barossa LNG project. So that's a huge milestone in any of these projects. We all know that getting those tolling agreements with the LNG facility is always a huge step forward. And it's great to see that alignment around Darwin LNG. And I'd just like to thank all the partners for working so well with us this year. And the Timor-Leste regulator for working so well with us this year to progress a lot of the things around Darwin, Barossa, and of course, Bayu-Undan. And our CCS project, we told you earlier, we're aiming to be FID-ready by the end of the year. We're on track to achieve that. Look, in terms of a value proposition, we often talk about what is that investor proposition or value proposition for Santos, and we're going to cover some of the areas here. And the 5 are listed really, we'll touch on that strategy, that consistent successful strategy we rolled out in 2016. We'll touch on our operating model. For those that aren't familiar, I know a lot of you get really frustrated that I keep talking about that every time we meet, the disciplined operating model. But it's important because it is how we run our business, and I'd like to remind you of how we run our business. Evidence of the sustainability and resilient nature of our business. I think when we look back in 2020, that will be one of the highlights for me, that we'll be able to demonstrate the resilience of our business, again, through another down cycle, 2 massive oil price crashes in 4.5 years that the business has been able to navigate. And then we'll talk about our growth and how we're taking a very disciplined and phased approach to our growth projects. And then we'll talk a bit about that energy transition to clean fuels. Our strategy, look, I mean, we say it's consistent and successful. We think it's been successful over the last 4.5 years. I think those of you that do remember, Santos pre the strategy, I think you have to agree. The company is a lot more reliable now. It's a lot more steady, predictable. And we like it that way. One of the -- it may surprise you, but one of the complements I really look for, for the business is when we're called boring, boring and predictable. And I like to see that in some of the analyst reports when we get results out that we came in, as you would expect us to come in, because we want to have that predictability around our business. But really, the strategy has not changed. We've not changed in 4.5, 5 years. It's to transform, build and grow. We're transforming the business continuously, continuously looking to take those operating costs down through technology, through efficiencies, through elimination of waste. Building is really looking at each of those core assets and looking at what the opportunities around those assets, around existing infrastructure are and trying to maximize returns from those previous investments and the infrastructure. And of course, growers bringing those growth projects on. And we haven't really executed the growth part yet. We have the M&A part, but the big projects really is in the years ahead. None of that's possible unless we are good at what we do, unless we're safe and reliable, and that's both personal safety and process safety. I'm really delighted to show the trend continuing on the injury frequency rate. You can see how we're setting new records for the company at very high activity levels. And across much broader assets, we now operate 4 out of 5 of our core assets, and we're continuing to drive the safety performance. And it's not just on the personal safety. You can see on process safety and loss of containment is the primary metric for process safety that we publish. And you can see we're continuing to drive those spills or leaks, those process safety incidents and potential incidents down. And indeed, you can see that the Tier 1 incidents, which are the higher potential ones, are continuing to drop. A little bump in the Tier 2. That's really more as a consequence of taking on a new asset this year in terms of the ConocoPhillips assets. In terms of our disciplined operating model. I think the power of the model is actually the simplicity of it. And it's a bit like when someone from the U.K. comes to Australia, it takes us 6 months to work out the complexities of AFL because we think the rules to the game initially when we get here, and we're trying to work out what the rules are. And it takes about 6 months to realize there's not many rules at all, right? It's just a bunch of guys running around the field scrapping. And when you work that out, when you work that out, then you fall in love with the game. And it's a bit like that, this operator model, it's actually really simple. It's basically just setting a set of investment rules and operating rules around our core assets. And if the asset doesn't fit those rules, it doesn't fit in the portfolio, and then it's up for sale. It's black and white. There's no emotion attached to ownership of assets. That's just how it is. And hence, if you can't find new opportunities to create new value from an asset, it will quickly become a late life asset, and then we'll look to exit the portfolio. Just like you would with your investment choices. It's simple. These are the 4 things we do around our assets. It's not a whole lot more complex than that. And if we're doing stuff that doesn't affect any of those 4 boxes, we look to eliminate it. And then likewise, when we create funds and hopefully, we're creating cash out of those assets, there's only 4 places we should be looking to spend that cash. It's a very simple model, and it served us well and it drives that discipline. The rules are the key though. The rules. And every asset now has to be cash-free -- well, the portfolio has to be free cash flow positive at USD 35 overall portfolio, and every individual asset has to be free cash flow positive at $35 breakeven oil price. And the combination of those 2 things is quite powerful. We've got gearing rules for the organization as well. What we say is we aim to be 20% to 30% through the cycle, but we'll allow that to go to 35% for periods of high growth and/or M&A, and we'll control our business within those rules, within those guidelines. And that's been public for some time, but that's how we run our business. In terms of our 5 core assets, I said earlier, we now operate 4 out of 5 of those. And that's been really instrumental in helping us navigate 2020 because what that's meant for us is we've now got control over our own destiny, the timing of investment, the timing of activities that we didn't have in the past, we may have been dragged along if a joint venture voted something through. So having material or significant equity positions in these assets and being the operator, gives us a lot more control over our own destiny than we would have in the past. And a prime example of that would be PNG in terms of the opposite example, right? So I think that's a very good example of we just go with a vote more often than not because we're 13.5%. And we support the joint venture. We think there's good alignment across the joint venture. We think the joint venture, and particularly under Exxon's operatorship, is performing really, really well. But ultimately, we have little influence at 13.5% in that joint venture. But the other 4, we have very significant influence. And that's very important because that's allowed us to slow things down in difficult times like 2020 and progress things at a pace that we control. All are performing really strongly. I think interestingly, if you look at the production split, I think it's a nice even spread of production across the assets, good materiality on all of them. And I think it's important to note that they're not all Tier 1 assets, right? We get that. But the combination of these assets in a portfolio sense, I think, is giving us a leading business performance. They're all high reliability. But if 1 asset goes down, like 2 or 3 years ago, one with the earthquake in PNG, the business doesn't miss a beat because the other 4 are all contributing free cash flow above $35 oil price. That's important. That's a really important approach to how we run the portfolio of assets. They all have to contribute. We have to spread the weight and the weighting of our interest across those assets, good production out of each of them so they're all contributing, and that makes the business cumulatively a much lower business, a much lower risk proposition. And how has that performed over the last 4 years or so since we rolled this out? Well, I think this is a good summary of how the business is performing. And I'd remind you, during this time, we've navigated 2 oil price crashes, really significant oil price crashes. The ADGSM, hard to say with a Scottish accent, hard to say fast anyway with a Scottish accent; ADGSM, the government threats of intervention in the gas market; an earthquake in PNG that took our facilities out for over 3 months; a global pandemic; all of these things. And during that period, we've still been able to deliver more than USD 3.6 billion by the end of this year, what we've been forecasting for last month, and free cash flow. The business, and we'll talk about this today, is forecasting, a free cash flow breakeven for the end of this year of USD 20, or less than USD 20 per barrel, less than USD 20 with the effect of hedging. Less than USD 25 if you ignore hedging, right? So it's a very low-cost and reliable business. Free cash flow yield of 8%. And we've got the qualifier on there. That's based on the 1-month VWAP. Of course, that change is depending on what share price one would use, but 8% free cash flow yield. And very importantly, through all of that, because of the rule set operating model, because of the fact we've controlled a gearing within a certain range, we've been able to grow the business and take advantage of those opportunities and grow production by more than 50% during that same period. And so I think -- if you want the evidence of how the operating model is working, the chart here on the left-hand side, as you look at it, I think epitomizes it. And what the line I want to draw your attention to is the oil price line. And if you look at the oil price in 2016 and then take the average oil price in 2020, it's effectively the same number. But look at the free cash flow difference for the business. So what we're building is a business that generates more free cash flow at the same commodity prices over time. And that's why we're able to do that is by having a portfolio of assets that all contribute in growing those assets, growing material positions around those assets and then exploiting growth opportunities using existing infrastructure so they become higher return projects. That's my favorite chart. That's why I labored on it, right? Take note of that chart. That's my favorite chart. This chart is really talking about the way forward, right? This is the growth. And obviously, you can see that bump that used to be 2025, it's going to the end of 2025 now, and has moved up by the time because of the impacts of COVID this year, because of the fact that we had to slow everything down. That won't surprise you. I think that's probably what you all expect to see. However, the quantum is the same. I think another bet, and it took a lot for the organization to do this, is to show you such a long-term outcome into the future. And I think the key takeaway I wanted to highlight here is the base business profile going out as far as 2030. It's essentially a flat production profile. That would make sense for long-life natural gas assets, right? They typically have flat production profiles for long periods. The bumps are really either late-life assets like Bayu-Undan, or the oil liquids projects, as you'd expect, where you see higher decline rates. But the base business, which is predominantly long-life natural gas assets, you can see at a very steady core business through to 2030. What that means for us, what that means for us is that we can really work on getting those efficiency optimizations that cost of production, maintaining those levels of performance you see around those assets because they're more steady state. You're not fighting rapid decline curves like you would see in a shale player like in the U.S. or something like that. So it's a very strong business. Obviously, I talked about the impact of COVID on particularly on the big projects, Barossa and Dorado, where we had to take a pause earlier this year, really scheduling. In the case of Dorado, we'll talk a bit more later this morning. That period has actually led us to see more of the opportunities around the Bedout Basin, which is very exciting, and we'll talk more about that later on. Actually, can I go back to that slide, how do I get back to -- can you move me back to that slide, please? Yes, I've only got 1 hour on here. Yes. I think the sort of big takeaways on here that I didn't highlight really is the targeting dates for the FID. So you can see we're targeting Barossa in the first half of 2021. And I'm pleased to see some of those external macro conditions starting to develop now that will give us the confidence, I believe, to take FID, like the announcement of vaccines and the sort of optimism that we'll have a more stable environment to build the project going forward. Dorado are now targeting FID in the first half of 2022, and we'll talk about why. And that's -- the phasing of that project is really about maximizing the opportunity and making sure we build the right FPSO for that project, in particular, the right FPSO for that project so that we can get the very significant value from low-cost tiebacks, fields being tied back without having to build a second FPSO, and we'll talk about that later on this morning. And of course, Narrabri. I'm not sure. I'd love to ask who thought we'll get the approvals for Narrabri this year at the start of the year. I'm not sure even the own management team have been unanimous. Everybody is setting the same page. It's been such a long, long journey, but I'm really pleased we've had both state and federal improvements -- approvals achieved this year. And we'll talk more about that project in a little while as well. This is really important, the energy transition. You read about this every single day, and the impacts on demand and supply for oil and gas over the next few decades. People talk about hydrogen. People talk about renewables and the need for us to switch. Let me tell you, for the next 2 to 3 decades and more, oil and gas, natural gas is going to be in high demand globally. It has to be. I want to give you a little snippet of how I think you should think about switching to see hydrogen, right? One of the problems we have here on the East Coast gas market is lack of infrastructure. That's after 50 to 60 years of operating a natural gas market. How quick do you think we'll build a hydrogen infrastructure to replace it? 50 to 60 years, and we haven't built the natural gas infrastructure we need for the market. It's not going to happen overnight, and it will cost trillions, not billions, trillions of dollars to build that infrastructure. Now put that on a global scale. As I've you told already, we could deliver hydrogen around $2 per kilogram or even less to date. Who would buy it on scale? Look, they can take it because the transportation challenges haven't been worked out yet. The infrastructure at the other end to process it, transport it has been [ worked ]. We can burn it. That's not actually the heart. Changing the burner tips on compressors and the various turbines and stuff is fairly straightforward to burn it. But all those other things have yet to be worked out, and that will take trillions of dollars and decades. And we will transfer -- and we will transition, if you like, as the markets transition. And so what I really want to get out to our investors is we are a fuels company. We're not an electricity company. So we're not going to make a big announcement about going into renewables. Why? Because I don't see much money in it, number one; and number two, it's already a very, very crowded space. Electricity markets, retail markets are already a very crowded space. We will continue to operate in fuels. And our transition will be one from going to fuels, which we believe are essential today and make up the vast majority of energy supply or energy-consumed worldwide. Electricity today accounts for around 20% of all energy consumed. The other 80% is fuels, right, or most of it anyway is fuels. Now electrification will grow. It may grow to 35%. But it is not going to grow to 50% or 70% or 80%. The world is going to need fuels for a very, very long time. So we will transition to cleaner fuels. And today, we see natural gas as being really critical. It's a critical part of the energy mix because of the pressure on coal. And because of the coal-to-gas switching, we believe the next few decades, gas plays a massive part in reducing global emissions, natural gas. And we want to stay predominantly a gas company. And we believe the transition for gas will be from natural gas, over the decades, to hydrogen gas, but it will still be a gas industry and be a very strong gas industry. And we believe we have the skills and the capabilities and the natural resources to be part -- a very successful part, and there'll be huge opportunities, I believe, for us, if we can get first-mover advantage in that transition. But the timing of that transition will be dictated, in my view, by how quickly the market transitions. It's not about the suppliers transitioning because we need people to sell it to. We need buyers who want it. And we will transition as the market requires. And we're very plugged into that. We're dealing with various organizations across Japan, Korea and elsewhere. And we're involved in those conversations. So we've got a very good feel for what the pace of that will be from our buyer environment. And that's important because we believe the buyers of hydrogen tomorrow are the buyers of LNG today. It's the same buyers. It's the same industries. It's the same companies. And so we will transition with them. But we think we're very well placed. And so today, we're a natural gas-based company, CCS and -- particularly CCS and a lot of the stuff we're doing through energy solutions, it's about reducing the emissions and decarbonizing that base business to make us a stronger value proposition and investment proposition in the short to medium term. We'll then use CCS to enable our hydrogen business, and we have some unique hydrogen opportunities. Brett will talk about that this morning. Some unique hydrogen -- we actually have an internal market we can supply hydrogen to get us going in that space. And then ultimately, decades down the line, we become more predominantly hydrogen than natural gas. That's how we see our transition, and we think we're very well placed as Santos to lead that effort across our industry. We've got some unique opportunities to be a leader in that space. So this morning, that -- particularly CCS has allowed us to talk about our new targets, and I'll quickly touch on those. And really, these reduction targets are designed to support Australia's commitment to the Paris Agreement. And so we had existing 2025 targets. They are maintained. And the good news is we're ahead of those targets. Every year we set those targets, we're beating those targets. So that's good. And you can read about that in our climate change report, which will be issued earlier in the year. Riveting reading. I recommend it to everyone in the room. It actually is riveting reading. You should read it. It's a great report. But today, we've announced some new 2030 targets. And pleasingly, the one around scope 1 and scope 2 emissions is to reduce those emissions from our existing business by 26% to 30% by 2030 based on our 2020 baseline. And what's important about that, we're actually ignoring the savings we've already made over the last 8 and recent years with those energy solutions projects. We're banking them, and we're starting from today's baseline. So it's a further 26% to 30% by 2030. In addition to that, Santos is committed to reduce customer emissions, customer scope 1 and 2 emissions -- or scope 1 emissions by 2030 by greater than 1 million tonnes per annum, and we will do that by fuel switching, by either converting someone from coal to gas or diesel to gas or certainly cleaner fluids than they're using today. And so we work with our customers to do that. And ultimately, as I said, a road map to 0 emissions by 2040. And as a number of technology enablers, I won't go through at the bottom of this slide, as we've already talked about some of those on the previous slides. I talked earlier about how we want to be able to present a road map. And we're putting out there. You can hold us accountable to this if we're all around long enough to do so. But ultimately, we'll put a road map out there. And you can see, I think, it's a very logical road map. This is not time line. So our emissions won't increase like this, the first bar shows. It just builds in the additional emissions that growth brings to the portfolio. We're building in from an accounting purpose so you don't miss it. So you can see the true extent of the reduction that we're actually committing to. CCS -- or land-based office -- offsets, Brett will talk about this morning. Very exciting savanna burning project that we've been doing up in Darwin LNG for years, and it's a real-world class project. UN recognized as best-in-class working with indigenous communities up in the Northern Territory, preventing significant bushfires in the region. So a really exciting program, and we're looking to expand that. Energy efficiency projects. So further identify projects through our Energy Solutions group, driving further efficiencies across our existing operations. Moomba Phase 1, the CCS project. So you can see that's a significant part of this journey. And that doesn't allow for the expansion to meet the 2030 target. And then electrification of the Cooper Basin. That's a really exciting project. So what that's talking about is actually running poles and wires to electrify our upstream satellites in the Cooper Basin. And why that's exciting is because today, we burned 70 terajoules of gas every single day across the Cooper Basin to fuel our operations, 70 terajoules, 5% of the East Coast domestic gas market equivalent, every day for fuel. Cooper Basin is a massive, massive expanse. So by directing all that gas back into Moomba, to provide the power from Moomba, that allows us to capture the emissions from that gas that you couldn't previously capture, which adds to the CO2 we can permanently store at Moomba. And hence, you see, it's quite a big box here that takes us essentially to the 2030 target. And then we see CCS expansion. And there's a number of opportunities we're working on for CCS expansion. And of course the 2040 plan, assumes that we will push our hydrogen business. We'll start to generate some hydrogen. And the great thing about that is that, as I say, we already have done studies and worked on that. We're not announcing a study today. We're announcing our plan. This is a road map to 2040, net 0 emissions. And it's one that we'll share that journey and the progress on that journey with you as we go forward. Switching gears and moving on to ESG. Big focus in 2020. And I think one thing coming out in 2020, I think, is everybody's focus on ESG just generally and the importance of some of these matters. And obviously, on the environmental side, we've announced our new emissions targets today. I talked about the savanna burning project, UN-recognized project as the best example of partnering with indigenous communities on carbon management globally. And in fact, other countries, are now adopting this very same program. And I think it's -- is it Angola? Botswana. Is it Botswana that are doing it? On the social front, really strong engagement with social communities and community organizations, over 140, supported by Santos. Working with 21 traditional owner groups across the country, a very long and proud record of working with traditional owner groups across the company. And that's really important when we think of cultural heritage and the management of those cultural heritage issues that we've all read about this year in the press. We've got a long track record with a landholder engagement teams across Santos, very successful record there and a lot of strong governance across that part of the business. We look forward to sharing more with you as we go forward. And on the overall governance front, we'll talk a little bit about that further on in the presentation today. But really, our EHSS and our -- which is our Environment, Health, Safety, and Sustainability, a subcommittee of the Board, and the People, Remuneration and Culture Committee, subcommittee from the Board, have oversight in all of the ESG matters between them, a very, very busy annual agenda, covering all ESG matters and they take very keen interest in what we're doing in all of these -- all these spaces. And internally, within the management area, I've established a number of centralized functions over the last 4 years with very, very rigorous governance accountabilities on these matters so that we make sure it comes up to the Excom. We're getting to see all these issues and the results of the efforts we're putting in across the business on a very regular basis. In terms of reporting, I touched on our climate change report. This year's one will be our third. And got a lot of positive feedback on that over the last 2 years, and we think we're taking it to the next level this year. We've also issued our first modern slavery report in June of this year, which I think is a bit of an oxymoron as a title, but that's what it's called anyway. But the important thing is we've done this a year ahead of the requirement to do so. And it's a really strong commitment from our procurement community in Santos to work to these standards and be very transparent and report against the requirements of our modern slavery policy. We've conducted a review of industry associations that we support or are members of, and we will release the results of that before year-end, and you'll be able to see that in our sustainability part of our website before year-end. And of course, we will be publishing a sustainability report early in the new year. We reported -- we published that earlier this year, and we'll report -- we'll improve and go to the next level, and that will be reported early in the new year. And very importantly, a lot of you asked the question about remuneration. Management incentives, both short term and long term, are very much focused on ESG performance. And certainly, we have ESG and emissions reduction targets in our short-term incentives plan and in the individual performance contracts I have with all of my direct reports. And I think I finished 1 minute and 4 seconds ahead of schedule so we're right on time. I'm going to ask Jane Norman to come up and talk about market outlook for you. Over to you, Jane. Thanks.

Good morning, ladies and gentlemen, and thank you, Kevin. I'm Jane Norman, VP of Strategy. And today, I'd like to take you through the market outlook. Firstly, looking at the global energy mix. Natural gas is forecast to remain a critical part of the energy mix for years to come, meaning around 1/4 of all energy demand. This is shown in all of the IEA scenarios released this year in their World Energy Outlook. Today, electricity accounts for around 20% of final energy consumption. That means 80% of final energy is coming from fuels. Whilst electricity demand is forecast to grow to around 30%, as you can see with the yellow line, there's still a big role for fuels to play in the future. This is where we see gas playing an increasing role with coal-to-gas switching and diesel-to-gas switching. Coming out of the-COVID pandemic, as economies rebuild, the world will need affordable and cleaner energy. And this is where gas is going to play a bigger and bigger role. New fuels such as hydrogen required trillions of dollars of investment in new infrastructure, and we don't see this happening overnight. Renewable energy needs to be converted to hydrogen if it is to meet this fuel demand. Today, gas can reduce carbon emissions. It can improve air quality, especially in hard-to-abate sectors such as heavy transport and high-temperature heat. Turning to the oil demand outlook. Sentiment around oil has clearly shifted in the last couple of weeks with the prospect of multiple COVID vaccines in the final testing phases. Oil price has been approaching $50, subject, of course, to today's OPEC meeting. The impacts of COVID and oil supply are expected to last longer than that impact on demand. Upstream spending has dropped 30% from 2019 levels, and this is expected to be subdued going into the coming year. U.S. shale is not expected to rebound to the highest we've seen. This year, shale production dropped 2.8 million barrels a day from its peak. The U.S. rig count is down 60% year-on-year. Consolidation in the shale sector is expected to see a more orderly investment approach as shale becomes part of a bigger program. And investors are looking for free cash flow from shale players rather than the promise of future returns. We remain positive on all market outlook. And this forecast from IHS shows oil demand growing for the next 2 decades. We expect the global transport fleet will take many years to transition away from liquids fuels. We're confident the oil market is an attractive investment opportunity for many years to come. Turning to LNG. LNG demand in 2020 has been incredibly resistant -- resilient, sorry. We've seen 3% growth this year despite the pandemic. Key growth markets have increased significantly. China's demand grew 13% year-to-date, and India's demand has grown 22% year-to-date. Over the last 5 years, we've seen LNG growing 9% each year. This chart from WoodMac shows growth at around 4% to 2035, 4% per annum that is. With all the new markets opening up and then traditional LNG buyers looking to move away from coal, these forecasts look to be fairly conservative. The chart also includes new projects that backfill existing plants in the operational supply wedge, projects like Barossa, which are assumed to continue that production. We've only seen 1 FID this year. And further delays in deferrals due to the pandemic could see the gap between supply and demand opening up further. And it's not only energy forecasters who are telling us they see the LNG market growing. Our Japanese and Korean LNG customers are very positive about the long future for LNG, as they're moving away from coal and slowly integrating renewables and hydrogen when the infrastructure is ready. And now turning to LNG pricing. We see a continued shift to gas-on-gas pricing. While oil indexation has been the traditional price index for LNG, we see growing confidence in a price that truly reflects the LNG market fundamentals. Like the commoditization journey, the resources were undertaken, we can see a clear correlation between Asian LNG spot prices and Europe and U.S. hub prices, plus the transport costs into Asia. Today, flat JKM marker is around $7.15. We expect global LNG prices will be set by the cost of U.S. LNG supply delivered into Asia at around USD 7 to USD 8. This is the price required to incentivize new supply and deliver a return on investment. This year, we saw in the lows of the market that U.S. LNG shut-in started to kick in around the $3 to $4 mark. And this effectively creates a floor in the global LNG market. Santos' LNG projects had a cash cost of production approaching $2, which means they're robust and cash flow positive even in the lows of the oil -- the LNG market we saw earlier this year. The Asian LNG market is expected to maintain a price premium due to its large share of the global demand at around 70% and its higher shipping costs from new supply regions, such as Africa and the U.S. Santos' LNG projects are cost competitive and are well-located to meet this growing Asian demand. Turning to the domestic gas markets. Santos is the largest domestic gas supplier in Australia. We have a nationwide footprint and supply customers in every state and territory. Santos' domestic gas is largely sold on fixed-price contracts with CPI indexation, and this creates a natural hedge to oil price volatility in the portfolio. We continue to see strong demand across the country. Both markets require new sources of supply within around 5 years. And gas demand is going to be strengthened by the government's gas-led recovery plans. Gas has multiple uses in these domestic markets, and there are a few substitutes. Gas is used as a feedstock in manufacturing. It's used for industrial purposes and high-end temperature industrial heat, such as the manufacturing of bricks and the production of cement. Gas is used in power gen to provide baseload confirming power and to help integrate renewables. Across Australia, nearly 70% of the gas Santos produces goes into these domestic markets. All of Santos' gas production in WA goes to domestic customers, making Santos the largest domestic gas supplier in the WA market. This year, Santos announced new supply contracts with Wesfarmers for its Kleenheat business and for the Gold Fields to supply 3 gold mines. On the East Coast today, Santos supplies around 11% of East Coast gas demand. In January this year, we signed a 6-year contract with Qenos to supply ethane to Botany Bay. Qenos is Australia's sole manufacturer of polyethylene, and this contract underpinned around 500 jobs associated with Qenos' activities in New South Wales. We can see from the chart on the right, the important role that Queensland coal seam gas plays in keeping the market balanced on the East Coast. New supply like Narrabri is needed from around 2024, and Santos has committed 100% of the Narrabri gas project to the domestic market. And finally, turning to Santos' sales volume production mix. Santos' portfolio is balanced and diversified by market, by product and by price. This diversification has supported achieving relatively attractive realized prices this year despite the pandemic. 45% of sales volumes are sold into domestic markets. LNG across the 3 projects accounted for 36% of sales volumes. And Santos' low sulfur crude and condensates, around 19% of sales volumes. These products have achieved premium prices this year due to their air quality benefits. In terms of the outlook for sales volumes in 2026. Once the major growth projects come online, we see this balance in diversification improving. Overall volumes increased around 120 million barrels, but the relative proportion of the products improves, with LNG, domestic gas and liquids representing around 1/3 of sales volumes each. Liquids volumes increased significantly with Dorado and Barossa coming online. And the price diversification across the portfolio improves with us targeting around 50% of fixed-price contracts and non oil-linked LNG sales. Santos remains very positive on global energy demand growth, driven by population growth and universal access to energy. We're confident that natural gas has a long future. It's affordable, it is the cleaner fuel, and it supports the integration of renewable power and ultimately, generation of hydrogen. On that note, I'd like to hand over to David Banks, who's going to take us through the base business performance.

All right. Thank you, Jane. Is this on? Yes, good. All right. Good morning, everybody. When I look at the title of this slide, we probably should have the word resilient in there as well. Given what the world has thrown at us this year and our demonstrated ability to generate the cash flows that Kevin touched on in his opening address, there is a real strong sense of resilience in our base business. Okay. Looking at the onshore. If you look at that graphic, what it's hopefully registering with you is that our onshore assets are really an integration of multiple fields, multiple basins connected to multiple sales disposition points. Obviously, bringing gas into the East Coast of Australia, also export via LNG at Curtis Island, and then in the future, up in the Northern Territory and the shale plays potential connection into Darwin and LNG into Asia. Our base business, our Cooper Basin and GLNG assets, strong production outcomes this year. And our outlook for the foreseeable future is to maintain production at current levels or a little bit better than that. And then in terms of our disciplined low-cost operating model, we fund the growth in those backyard assets out of that free cash flow that's generated. So the growth opportunities that I'll talk about in the Cooper and in Queensland are really being self-funded, which is the power and beauty of the operating model. Beyond our backyard, obviously, Kevin touched on the Narrabri approvals. So pretty exciting that we've got our approvals now and we'll be entering appraisal in the new year. And Kevin will talk about what that Narrabri development looks like, phased growth over the next few years to deliver gas into the New South Wales market. And some early and quite exciting results up in The Northern territory in the McArthur Basin with our Tanumbirini-1 well, which I'll talk about a little bit later. Okay. Turning to the Cooper. You can see that strong production outcome. This year, we're looking at about 16.8 million BOEs, up around 1 million barrels over last year. And this year, importantly, we've had some real near-field exploration success in Southwest Queensland, which is largely underexplored. I won't say unexplored, but certainly underexplored compared to the South Australian side of the Cooper Basin, and we've got some seismic acquisition going on later this year or early next year to further evaluate what opportunities we have there for future growth. And also, we've tested some horizontals this year with some really encouraging early results, and I'll talk a little bit more about that in just a second. Next year, in terms of well count, you can see the well count falling a little bit from 2019 to 2020 and 2021. That is largely an impact of our participation levels. So our partner is not participating in all of our programs due to capital constraints that they've talked about. And so our participation, our equity level and the overall program is going up. And in terms of our reserve add in production, as you can see, we're certainly building production and maintaining a very, very healthy reserves coverage, which is shown up in the top right-hand side, now tracking at about 100% on a 3-year rolling reserves replacement ratio basis, and we aim certainly with some of those exciting discoveries in Southwest Queensland, to maintain at that level and keep self-funding growth. And just in terms of our conversion ratio, many of you would have seen, over the last few years, we've maintained about a 70% resource-to-reserve conversion ratio in the Cooper Basin. And this year is no exception to that. And then in terms of well cost, you can see stepping down continued focus on technical limit approach to our drill, complete, connect program. You can see there the base wells in the gray, we've continued to drive that down this year to now $1.8 million per well. And the little hatched bar there that you can see, the 2.49, that's the average of our horizontal wells this year. And so our horizontal program, we've drilled 6, and we've got 3 of them online to date. And what we're seeing in terms of the results of that is about a fivefold increase in terms of initial production rates and reserve add versus relevant offset vertical wells for a cost multiplier of only 3. So what the net effect of that is, is that our unit development cost is improving 25% to 30%. So this is giving us some real encouragement around the next step-change improvement in performance across the Cooper Basin. Okay. Turning our attention to GLNG. Again, you can see very robust production. Equity production numbers up there despite some real challenges due to COVID-19 and the downturn in the LNG market. And our partners are not necessarily off-taking all of the cargoes that they had originally planned for the year. But you can see that year-on-year equity production growth. And the stars of that, certainly, this year, have been continued ramping of Roma through the Roma East project, and a very, very exciting ramp in Arcadia, which is certainly exceeding our expectations of Arcadia and giving us great confidence around the next phase of Arcadia development. Again, as you saw in the Cooper, you can see there our performance in terms of drilling time and drilling costs continuing to improve. That little uptick that you can see in the bottom left-hand slide, the 3.1, that's purely a function -- 3.1 days per well. That's purely a function of us now chasing slightly deeper coal measures in the Roma area. But you can see that translating into continued unit cost improvement. And certainly, COVID threw a lot of hurdles and challenges in our way but it's actually presented a really strong cost reduction opportunity to us. And we've jumped on that opportunity, locking in a lot of our costs, our contracts and so forth in a very attractive contracting market. The chart on the top right-hand side is one that we're particularly proud of. And what this translates into is full life cycle well cost. So through design improvements and through improvements in the way that we manage our wells, our mean time to -- excuse me, our mean time between failure, i.e. the time between, on average, a well requiring a workover, is now over 3 years. And we've got line of sight to keep improving that. So that's a really exciting improvement in performance and one that will continue to drive down our overall life cycle costs in the CSG business. Oops, sorry. Okay. In terms of those growth opportunities in our backyard, here are just a handful of examples that are worth talking about. So Moomba South, you've heard about us talk about Moomba South over the last couple of years. Very exciting prospect just south, obviously, of the Moomba gas plant. And what we're finding there is real productivity in the Patchawarra, and also underlying the patch is a Granite Wash section that we're excited about because it should lend itself to significant horizontal multi-well pad drilling. It's a high-porosity zone, and the early results from that are quite encouraging. So at the moment, we're still in the appraisal phase. We've been able to land a horizontal in, in the Patchawarra, which is very -- gives us confidence about our ability to do a horizontal development in the underlying Granite Wash. The Cooper transformation project, Kevin touched on it. It involves essentially rationalizing and electrifying our nodal compression system across the Cooper Basin, introducing a lot more remote control to reduce our base operating costs and also drive significant improvements in reliability, thereby pulling down our overall loss performance. And that project is very exciting in that it will also lower the system pressures across the Cooper Basin which will obviously extend the life of many of the wells and thereby deliver incremental reserves, whilst also reducing overall emissions. As I mentioned before, Arcadia, we're seeing a really positive ramp from Arcadia Phase 1. And on the back of that, we're in the process of bringing forward Arcadia Phase 2. It's a development of some 200 additional Arcadia Valley wells, another compression hub, which ultimately will get our production up in Arcadia to the 130 TJ, 140 TJ per day sort of limits. And then Scotia Phase 2, again, leveraging existing infrastructure. No need to build additional compression. This is purely a drill, complete, connect project of about 50 wells. We're also going to be testing some horizontals here to see if we can extend the economic bounds of the Scotia play even further. And as you can see, look at the breakeven cost of supply on the bottom of that chart, these are all very robust and resilient investments. Okay. I mentioned before the Tanumbirini-1 result. So Tanumbirini-1 is a vertical well in our McArthur Basin acreage. This year, we fracked and tested it, and we got some very exciting results, initial peak rates of over 10 million a day, standard cubic feet per day, with average rates of over 1.5 million standard cubic feet per day. Interestingly, the gas composition is very, very high methane. So it's -- I think, it's 2.5% to 3% CO2, essentially dehydration and Australia into a sales gas spec product which is very exciting. The plans going forward here, next year, we plan to drill 2 horizontal wells and fracture stimulate both of those to understand what sort of uplift we can get in terms of production and reserve add. And in the South Nicholson Basin, very, very large contiguous acreage position; very similar play type to the McArthur where we basically have a dominant position there. And so next year, we'll be doing some gravity surveys to try and plot out the best locations for appraisal wells, which will follow in 2022. But very exciting, relatively close to infrastructure and potentially, we'll have the ability to access both the East Coast through Ballera and Moomba, and obviously, export through Darwin. Okay, turning our attention to the offshore conventional business, where we are the biggest supplier of domestic gas in Western Australia. Fantastic infrastructure position. And really, the business, fantastic EBITDAX margin you can see there and very, very low unit cost of production, which I'll talk a little bit more about in a minute. But we're seeking to leverage that existing infrastructure position to keep that infrastructure full and extend the production plateau through Varanus Island and Devil Creek for a number of years into the future. And you can see here at the bottom, and I'll talk about these individually. Some of these sort of backyard opportunities, near-field development opportunities which will contribute to the extension of that plateau in production through these legacy assets. Okay. First, on the top left is our Western Australian production profile. You can see there with the acquisition of Quadrant Energy, a big uptick, 30 million barrels -- BOEs a year. It's a big business in its own right. And you can see there, even despite the challenges that we've had this year, sort of maintaining that production level, and really encouragingly, look at the trajectory on unit production cost. We continue to drive efficiencies and make improvements to our routine maintenance and integrity management programs to drive those unit costs even lower. Turning your attention to the bottom left where you can see the Northern Australia production through Bayu-Undan. Obviously, with acquisition and our 68% interest there, a big uptick in production this year. And obviously, going forward, with the sell-downs, that will reduce. But very excitingly, we're advancing a Bayu infill program, which will extend the productive life of Bayu-Undan to really bring it up against the Barossa when Barossa comes online. Again, in terms of unit production cost, obviously, a smaller production base there and a late life asset, at least in terms of the offshore infrastructure there. But you can see just some of the synergies coming through in the slight improvement in unit production costs that we're seeing -- that we're forecasting this year. Okay. Those backyard projects, so Bayu-Undan Phase 3, it's a 3-well infill development, which, as I say, will extend the productive life of Bayu-Undan. Both gas and liquid stripping operation there, leveraging the existing infrastructure. And in fact, we're using one of the existing flow lines out there. Van Gogh infill on the back of the success that we had in 2019, this is a 3 dual lateral infill development project, again, to extend the life of Van Gogh. Our Varanus Island compression is a front-end compression project, which pulls down the system pressure for all of our assets that come in, all of our fields that come into Varanus Island. And so not only does that extend the plateau of production through Varanus Island, but it will also extend the life of a number of those fields. And then Spartan is a single well tie-back, again, utilizing existing infrastructure, pulling that in through John Brookes, so making the most of that fantastic infrastructure position we have. It's a very, very capitally efficient way to develop these opportunities. And again, looking at that breakeven cost of supply, incredibly good economics for these projects. And it just underpins the resilience of our business to low commodity price environments. So just digging a little bit more into Bayu-Undan. As I mentioned before, 3-well development, 2 platform wells, 1 subsea. And the development is targeting Trulek West, which sits sort of just on the fringes of the Bayu-Undan structure, discovered resource. And as I mentioned before, we're going to be reusing some flow line infrastructure there to keep the capital development costs down, and then 2 infill wells from platform up in the -- up towards the center of the field. Working with obviously our Bayu-Undan joint venture partners and very proactively and constructively with the Timor-Leste government to create very significant value for not only the joint venture, but also for Timor-Leste in extending the Bayu field life. Okay. And this is Van Gogh. As I mentioned before, we're drilling 3 dual laterals -- yes, thanks. Robin? Cheers. Drilling 3 dual laterals, I think that's actually a typo. That should say 18 kilometers of reservoir footage exposed through 3 wells. So again, an extremely capitally efficient development, targeting about 10 million barrels of oil reserves there. The rig is secured, and we should start drilling in Q2 of next year with first oil from these new wells in Q4 of next year. So very exciting infill development there. Now last but not least, turning our attention to our one core asset that is operated by others. As Kevin touched on before, ExxonMobil, the operator here, does a very, very good job in terms of filling the plant. In fact, you can see up there, the plant has been tracking at about 30% better than nameplate capacity through some very low-cost operational improvements and debottlenecking that has been completed. And you can see there the production cost of $4.85 a BOE is really, really -- demonstrates that this is a world-class asset. And in that $4.85 is something approaching $1 of earthquake impact, which we're in the process of trying to recover through insurance and the like. In terms of backfill options, we have a number. One of them, P'nyang, obviously, is subject to farm-in agreements and so forth, and we're working with partners and the government on that. But also, Muruk and Hides are also exciting backyard opportunities that will enjoy extremely capitally efficient development costs and make the most of a very well-run infrastructure that we already have in place there. So with that, I think I will pass on to Brett -- or are we having a break? Take a break? I'll pass over to Andrew.

Thanks, David. Remarkably, for Santos, we're running ahead of schedule. So we'll take -- for those on the webcast, we'll take our morning tea now, and we'll start again at about 20 to 11. [Break]

Brett Woods, I'm the Executive Vice President for Midstream Infrastructure and Low Carbon. I'd like to take you through a very interesting presentation this morning, giving you a kind of a heads-up of where we are within our business, given it's a journey that's not too long-established within Santos. Within our midstream infrastructure business, Kevin has given us a very strict goal, and it's establishing the division focused on running it for value by increasing our returns, lowering our costs and delivering that with higher reliability and safely. This is about deploying our low-cost operating model to unlock value throughout all our asset base. Through separating the management of our midstream infrastructure business from our upstream operations, we have enabled increased focus and discipline around each of our assets. This mindset is about delivering term, about delivering fixed price and sustainable returns across our business. Across the Cooper Basin, we have delivered over 14% cost reduction over the past 12 months. Following the successful acquisition of the ConocoPhillips assets, we have also integrated the DLNG into our midstream operations. And we've commenced our low-cost operating model across that asset. With regards to our utilization of our business, it's been one of our key focuses. This is about simplification. We're trying to get as maximum volume of product through our infrastructure for the minimum cost we possibly can. This year, we've seen record levels of production in both gas and liquids across the Cooper Basin, which is fantastic. And that is not just coming from one third party. That is coming from over 11 third parties across the Cooper Basin itself. Very pleasingly, I was -- Kevin mentioned it earlier, that yesterday, we signed all agreements with the Darwin LNG joint venture to set the tolls for the -- Darwin LNG facility to accept the Barossa gas moving forward, which is a fantastic opportunity because what that does is that sets term and toll for Darwin LNG for a minimum of next 15 years, giving us a sustainable long life gas asset for the midstream infrastructure to generate revenue from. As highlighted by Kevin, and I'll discuss in further detail, I also look after the Energy Solutions business. Energy Solutions is very focused on delivering lower emissions across our business, lower fuel, flare and vent and effectively leading our view of clean fuels into the future. Energy Solutions is focused on several key projects. And one of them I'll discuss in a little bit of detail is our CCS project, which, at the moment, we are FID-ready to deliver 1.7 million tonnes per annum of carbon sequestration in the Cooper Basin. That is the world's second largest CCS project and the lowest-cost CCS project globally. The exciting thing about CCS is it's not just deployable in the Cooper Basin, where we have opportunities to scale that up, upwards of 20 million tonnes per annum just in the Cooper Basin alone. But we've also got options to scale that into Northern Australia and other parts of our infrastructure business base. That gives us optionality moving forward to further drive our emissions down and hit our targets of being net 0 by 2040. One thing -- additional, and I have a video later in the presentation, CCS is a critical enabler for our hydrogen. So with CCS as a partner, we can convert our sales gas into hydrogen and sequester all the CCS, all the carbon dioxide, to enable that to be 0 emissions hydrogen moving forward. This is a fantastic opportunity for Santos. And as Kevin said, this is not something we're going to do lightly. We have our own market through our own more than 70 terajoules a day of fuel that we can convert through hydrogen so we can build our own market base. But we really have to follow what the rest of the market signals look like until we can deploy that. If there was a market today, we would be able to execute our hydrogen project. But at the moment, there isn't anyone really able to take hydrogen at scale for us to build this opportunity. But our current estimates working with our partners have demonstrated we believe we can deliver hydrogen for well less than $2 a kilogram moving forward, which is well beyond Australia's target aspiration for hydrogen. A key responsibility of the midstream business is really to shed light on the value of our midstream infrastructure assets. The assets we have focused on more recently, including Moomba, Port Bonython, Darwin LNG, already have existing in tolls. And we're extending that to look at Varanus Island and Devil Creek. And the chart up here today is a see-through view effectively what our base midstream infrastructure business looks like with all the existing tolls already built in. And in the middle, you'll see DLNG internal tolls. That's effectively the tolls between Bayu-Undan and Darwin LNG. As of yesterday, this slide should also include external tolls, i.e., the tolls we've agreed between Barossa and Darwin LNG. What this has done, just shedding the light on these assets, has demonstrated that we've got over $400 million worth of EBITDA that we deliver through the business alone at the current oil prices. But this is not the extent -- the total extent of our infrastructure position. Our infrastructure position extends much further than this, and we have future portfolio opportunities at GLNG, Narrabri and McArthur Basin. GLNG expansion was also a critical piece for us. We're not just looking at participating in Darwin just for a single train. We'd love to see a Train 2 and a Train 3 built at Darwin LNG, where we have up to 10 million tonnes per annum of capacity to process gas into LNG. Additionally, we'll talk about later, but CCS and hydrogen is also a potential addition for the midstream infrastructure part of our business. So where are we on that journey? As highlighted, our primary driver for the midstream business is to run our assets for value. Phase 1 was initially focused on the Cooper Basin, giving focus on infrastructure suite to give full visibility and optionality for assets such as Port Bonython, Moomba and Ballera. And you saw from one of David's charts, Ballera is a critical point in which gas from the north can travel through Central Australia and be distributed amongst the total East Coast domestic gas market. We have established South Australia, or Adelaide, as our center of excellence for our midstream infrastructure business. And as with Perth being the center of excellence for the offshore and Brisbane being the center of excellence for the onshore, we're looking at bringing together our group of professionals to work collectively to lower our costs and to improve our operations across our whole total asset base. Driving that flexibility, driving that value through our business is absolutely critical. We are well advanced in one of our key programs in Phase 1, and we're well progressing in our Phase 2. And Phase 1 was about setting term and toll, and we have tolling arrangements for all our assets. That was included in that previous pictorial. Our key objective in Phase 2 is to make sure that we continue to deliver improvements in terms of our operating costs across all our business, and one of the key objectives that we've set for 2025 is to lower our midstream infrastructure costs by over 30%. That reflects about a $60 million per annum saving across our business, of course, across the midstream business. And when you scale that up across our business, that will contribute significant value. Moving forward with the operational synergies. We are focused on running these separately, and we're looking at further executing our legal and commercial arrangements to make sure that we completely deliver that. But executing Phase 1 and Phase 2 leaves us a whole lot of optionality, and that is our structural optionality I've referred to on the right-hand side of this page. We've done a lot of work on our legal arrangements, a lot of work on the commercial arrangements. And we're looking forward to seeing what options that can deliver us, whether they be funding or others, for our asset base. Critical to this part of the business, though, is midstream requires to maintain control of these assets, so that we can further deploy our disciplined operating model and continue to lower our costs across our business. If you want to have a look at some examples of what the midstream -- the focus that midstream has been able to enable, here's a snapshot of where we are in the Cooper Basin. So over the past few years, we've been able to deliver over a 14% reduction in our cash processing costs across the Cooper Basin, and we will continue to drive this efficiency through that business. But not only is it a cost reduction story, it's also about utilization. We've been working with our partners and our customers to make sure that we can increase utilization across the fields. And we're not just doing that, leaving the existing kit in train. We're working very closely to improve our kit and simplifying our kit. We've had benchmarking done -- extensive benchmarking done across our asset base to make sure we know where we compare, and we can see constant opportunities for improvement. And you see the utilization and the throughput growing over the last 4 years. We're investing some capital, around $20 million, in 2021 to continue to improve the operations of our facilities and to simplify those facilities. That $20 million will deliver a long-term lower operating cost for our business. And one of the things that -- one of the only things that we can control, as Kevin always reminds me, is our cost of supply. So long-term delivery of lower operating costs is absolutely critical to make sure that we stay relevant as a midstream supplier of services. And being very connected to our customers, making sure that we can deliver what they need and when they need it, is part of that story. But it's not just the Cooper Basin. In the middle of this year, we concluded our transaction on ConocoPhillips, and the midstream infrastructure group took control of Darwin LNG. Darwin LNG is a fantastic asset, and we're very blessed to pick up some incredible people. I just want to pay tribute to Peter Kirkpatrick, who looks after our facilities up in Darwin. He's done an amazing job integrating the ConocoPhillips people with the Santos people. And on that journey already, we've seen significant cost out coming through our business. The asset has been 2 years without an injury, and it's got a fantastic culture in terms of maintaining production and throughput. For the first time in years, we've been able to deliver -- or the first time in its history, we've been able to deliver spot cargoes out of Darwin LNG. And even though we had some DQTs early this year, we're on track to delivering our sales targets from Darwin LNG through catch-ups towards the end of the year, which is a fantastic outcome from the team. Through our Darwin LNG program, we've also taken charge of the life extension project. So what is that? So when Barossa brings its gas back to Darwin, we have to make front end modifications at the facility to ensure that we can accept its gas. That project is at the point of being FID-ready, subject to FID of the Barossa field. And what we've done through the midstream, it's been able to simplify the execution and modify our costs. So we reduced the cost of the life extension project from our last update by $100 million. So including the tie-in for the gas, it comes to a total of $600 million for the transportation of the gas. And as I mentioned earlier, not only have we agreed tolls, but we've also agreed the gas transportation arrangements and our pipeline tie-in agreements with the Darwin LNG joint venture. So I'm very pleased to have the Conoco team as part of our journey. One of the great things about the people on Conoco, and something you may not have realized, is during the lack of international travel, groups like GE have struggled to get into Australia. And GE need to travel into Australia often to do warranty work across some of our large compression fleet. But the people we have within our Darwin LNG facility are qualified to do all the warranty work themselves, which is unique within Australia. So within Darwin LNG, we were able to deploy those capability across GLNG and other assets. So we have this fantastic ability now to share high-capability people across our full operational base, which is really critical for saving costs. And through periods of COVID, it's key for our operations. And I also want to give credit to guys in the Cooper Basin because as you can imagine, when lifting became very challenged, when the world's oil suppliers were starting to fill, we worked very closely together to make sure we continue to deliver all our product to the market and enabled Santos' facilities to stay fully in production during that period. So the other part of our portfolio is Energy Solutions. Just to give you a sense of what Energy Solutions is, Energy Solutions is not a program to do studies or just to have thoughts about robots or things like that. Energy Solutions is very much about delivery. Since Kevin started with Santos, Energy Solutions delivered or offset over 1 million tonnes of carbon dioxide annually, which is a fantastic effort. In every project that we execute, every project that's in my forward seriatim of opportunities delivers cash back to the business. As you can imagine, Kevin's not going to say to me, "Brett, you can go and do some science experiments," or, "Brett, you can go and do projects that don't deliver value." We are very much about delivering value for shareholders, and make sure that when we leave and the environment we operate in is left in a better place. Across our targets into 2025, we had goals to reduce the Cooper and Queensland emissions by 5%. We're already miles ahead of that. We're far ahead of that as a target. And we should be able to conclude that in the next few years, which is a fantastic pathway to where we're going as an organization in terms of our emissions reductions. In terms of reducing waste, we've had significant opportunities. And Kevin mentioned one of them earlier, which is the Northern Territory savanna burning, which the unions -- the UN regard it as the best relationship with an indigenous group anywhere in the world. That project alone has abated more than 2.7 million tonnes of CO2. GLNG alone, we've also planted trees, and we have sequestered -- we planted over 1.2 million trees and offsetting around 30 million tonnes of CO2. We're doing some really interesting work also in terms of our waste in New South Wales. Our salt in New South Wales is being converted into bicarbonate soda, which we can use industrially. And we've working relationship with third parties to deliver that. And we've also signed agreements with 2 companies to take our CO2 out of New South Wales to use that as industrial CO2 within Australia. Ironically, you may think that Australia actually imports CO2 for industrial purposes. So there is a market within Australia for our CO2, and it's been very much a focus that Kevin has given us. It's not to think about our products that we traditionally, in this sector, think about as waste, but to turn them into value-add products, to turn our salt into value-add products, to turn water into value-add products and, in this regard, turn our CO2 into value-add products. Kevin mentioned also earlier our goal for clean fuels. We're very much trending towards a company where we are a company that's about delivering clean fuels. Whether that is LNG, whether that is domestic gas and, potentially in the future, the journey towards hydrogen, the world requires a molecule-based fuel. That is absolutely critical, and Energy Solutions helps deliver that for Santos. We have initiated studies with many partners associated with hydrogen. Yesterday, we concluded an arrangement with our Barossa joint venture -- feels like the sea breeze has just come in. The Barossa joint venture to work on an MOU for CCS expansion for our international bilateral arrangements. So we're working with not just Korea but also Japan about seeking how we can attract additional value for our carbon credits in Australia. We're also very, very close in signing those arrangements with a couple of very significant Japanese parties, which is exciting for us. So what we're trying to do is position ourselves not only in terms of how -- reducing our local emissions but how do we convert our fuels of the future and playing with the critical partners, which are our LNG partners, who are the critical offtakers, who will be those people in the future who take our hydrogen from our facilities. We're also working with many parties, in particular, about how we transport our hydrogen around it -- either around Australia or international markets. And we have significant arrangements with those parties also. I've got a video coming up in a second, which should come up now, which gives you a bit of an introduction, a bit more detail about what we're doing in our carbon space across the Cooper Basin. So I'll throw it over to the video. [Presentation]

So just a little bit more color about our CCS project, and Anthony would actually argue that I probably shouldn't say anything here because I'll just run it after the video. But I'll -- we can throw rocks at him when he gets up in a few minutes. The great thing about our CCS project is we're on target to deliver less than $30 a tonne CCS abatement, which is by far the lowest cost globally in terms of CCS projects. But we're not stopping there. We're working very, very hard to lower that even further, to try and get that into the low 20s, if that's possible, and that is absolutely critical for us to drive forward. One of our challenges associated with CCS is we're waiting for the government to get the approval that ACCUs are eligible via CCS. Once that comes, and we expect that to come sometime hopefully in mid-2021, then we'll be able to FID our CCS project. It's critical that we don't FID the project until we have accreditation for ACCUs for our CCS project. The great thing about the carbon storage facility at the Cooper Basin is we have a lot of natural advantages. We already capture a very, very clean CO2 stream from our reservoir gas, which currently is vented. We can build a header, put -- connect that to dehydration and compression facilities and transfer that through the basin. The video suggested a couple of fields, i.e., Strzelecki and Mirrabooka. We don't have to select those. They're just 2 examples. There is a lot of opportunity in the Cooper Basin for carbon capture and storage. And in fact, we have over 20 million tonnes per annum of potential for well over 50 years just in that basin alone. And we're looking -- you'll be surprised. Maybe you won't be surprised. My door is getting constantly knocked on for people to come in and join us, and SK was just an example. And a couple of the Japanese companies are just examples of that. Nearly everyone that we're operating with or around are coming to us to see how we're doing this and why Santos can do this cheaper than other places. One of the great things about the Cooper Basin, in fact, is also it's one of the greatest parts of the world for renewable resources. So part of the Energy Solutions story is how do we replace our own fuel gas through renewables integration. And we saw through the video through integration of excess renewables, there's a potential long term to also go into renewable -- hydrogen generated from renewable sources. So we see a pathway -- we see a nearer-term pathway to deliver well sub of $2 per kilogram hydrogen into the market via by our gas coming out of Cooper Basin, coupling that with CCS to give 0 emissions hydrogen. And then over time, with the further electrification that David Banks talked about and further integration of renewables, we could see more and more hydrogen come through renewables integration. CCS is a critical enabler for hydrogen. It delivers 0 emissions hydrogen. That's what we're working with not only internally through our engineering capability, but through our markets, being more customer-centric to make sure that we understand the hydrogen market so that we can respond in a timely manner to make sure we deliver that. CCS, just the Phase 1 alone by 2050, will store approximately 44 million tonnes of CO2. And we know that through the IEA work that CCS is critical for the global energy demand, i.e., we need CCS to make sure that we support the Paris arrangements that Australia has signed up to. I've talked a little bit about this already, but CCS is an enabler for hydrogen. And we've got some incredible natural resources and natural benefits that we have across the Cooper Basin. One of them is access to low mineralogy water. You may be surprised that hydrogen generation requires quite a bit of water, and that water needs to be -- have low mineralogy or demineralized like through reverse osmosis. So if you think about putting hydrogen facilities on the ocean, not on the coast, you have to take that seawater, you have to demineralize it through reverse osmosis before you apply the energy, whether it be your renewables or other, to generate hydrogen. Within the Cooper Basin, we have effectively low mineralogy water that comes out through our production operations. That gives us a significant cost advantage alone. Couple that with our natural gas supply, and what the video didn't show you is when David was highlighting those points on the map that had Northern Territory, there's great opportunities to run Northern Territory gas via Ballera that continues to supply for us to convert hydrogen in this basin. I don't see this coming as a solution today, but we can see a very stepwise approach to CCS to powering our own infrastructure through hydrogen and ultimately to exporting hydrogen around Australia and internationally through our infrastructure. Thanks very much.

Thanks, Brett. Now what we're going to do is just walk through some of our major growth projects. But just before I do that, that last point Brett made, I think, is very important. As we talk about infrastructure build, continued domestic gas infrastructure build, we think it's very important that when the government and other bodies are thinking about where those pipelines need to go, that we think about decarbonization as part of that strategy. And that's why we would advocate that any pipeline coming from Northern Territory to join up to the East Coast market should go via Ballera because it does offer that decarbonization opportunity and potential feedstock opportunity for future hydrogen projects. And it's a novel concept, isn't it, to take a long-term view and infrastructure build and think about the kind of energy markets of the future. But that's why we're making that point because we think it just -- it's almost common sense. But as we know, common sense, there's no guarantee to how decisions will play out. But anyway, I thought I would make that point. Look, before I start, I talked earlier on about ESG and governance more generally. But I thought I would start by spending a couple of minutes talking about the efforts we've put in place over the last 4 years, 5 years or so, to really ramp up the internal management governance and particularly how that applies to major capital projects. And so in addition to the kind of various Board subcommittees that you'd all be very familiar with, my management team essentially sit on the executive committee. But below that executive committee, we have a bunch of management committees that focus on the governance across our business. And you can see here, Contracts Committees for the major procurement activities across the business, making sure that we're right across them, driving the right synergies and the right value-add considerations as we award and manage major contracts. A Corporate Risk Committee, looking at the risks and the enterprise risk register, the major risks across the business, whether they be safety, environmental, financial, whatever they might be, operational, and managing those risks and making sure the controls that we've put in place or that we see are in place to manage those risks are actively monitored and validated. Operating Committee, I chair that operating committee, along with David and the heads of the operating divisions, where every single month, we sit and we go through the operational performance of the business. And we get updates on the various activity plans. We've got the Investment Committee, which sort of speaks for itself, that Anthony chairs, the approvals and beyond that for the big investment decisions. Thanks for that, Anthony, for getting me involved in those. And we review everything, make sure that what we're investing in makes sense, is on strategy and that we're going to get the returns, at least the promising the returns that we want. And the Reserves Committee, I hope you would all agree that over the last 4 or 5 years, we've really put a lot of discipline in the area of reserves bookings and communicating reserves positions as well as resource and much more transparency and clarity on that, and so real effort. But below that, we've built really strong management systems over the last 4 years or so. And the focus for that was because we knew that growth was coming. And as much as we want -- and I think we've proven ourselves to be a reliable, steady and, I'd say, a very strong operating company. And now we will -- and I think I said this last year, we want to demonstrate over the next few years is we can maintain that, and that we can build good growth projects on top of that. Now we manage the risk of those projects by mainly making them brownfield, upstream, sort of tieback type projects and limit the number of greenfield projects. Can't eliminate them, but we will limit them. But it's really important. We have very strong assurance processes and governance processes across M&A. I'm not going to go through the detail of all of this, but you can see we have the phased development process for those major projects. And you can see we're identifying where Dorado and Narrabri sit today, the defined phases when we go into FEED on these projects. Barossa and Moomba CCS are there. At the end of that defined phase is when we take that FID decision before we go in and execute those projects. And there are series of reviews. And we shared with the Board an FID package earlier this year for one of our major projects. And it was just ream after ream of assurance review documents for them to see, where the review team spent 3 or 4 weeks going through every aspect of that project to tell us, to feedback to us whether we've met all the objectives we set out at the start of that journey or not. And that's really to give ourselves the best chance of delivering what we promised. Now I just want to share that with you because that the process we're applying to all of these major capital projects as we go forward. Of course, the proof will be in the eating of the pudding. I get that, but we just want to share with you the effort we're putting upfront to ensure that we've got a very well-governed and well-stewarded project execution part of our business. This slide really summarizes the 4 major capital projects that we have on the go right now, 2 that are, say, are in that FEED process and 2 that are still pre-FEED. But these are the ones we would classify in that major capital growth category. I think David used the term earlier on backyard projects for those infills and other smaller type projects, and they run more within the operating divisions. The big major capital projects are run separately. They're run by dedicated project-focused teams and obviously very, very close senior executive scrutiny. So that's really -- I mean, the description of the projects is fairly straightforward. Brett talked about the CCS project. Again, very important that we do emphasize the fact that we will not take FID on this project until the accreditation or the qualification for Australian carbon credits is in place. And I'm pleased to see the government's very positive announcements in that and the work the government's doing that have kicked off to get that in place next year. And hopefully, that will be in the first half of next year. We certainly hope it will be. We know that's a stretch target for them. But there's a real commitment across all side of politics, I'm glad to see, to get this framework in place. And it's really pleasing for me to see to the highest levels of government worldwide, everybody talking about the need for CCS. And I think it even appeared in some of the U.S. election campaign presentations and debates, presidential debate. So CCS is very much at the forefront of any strategy globally to reduce emissions. And so it's very important to Australia. You can see, I've talked about the brownfield nature of these projects. You can see the cost information on there. We're giving you some clarity around those. I'll talk about the projects in a bit more detail going forward. So let me just jump on to Barossa. Barossa's a very important project to us. Ironically, during the slowdown in activities this year, the recycling of the Barossa project this year, as a consequence of the impact of COVID, it's been a good opportunity for us to really drive value improvements on that project. As I've said, it's predominantly an upstream brownfield project, providing backfill into an existing LNG facility at Darwin LNG. So in our view, that review -- that reduces the risk somewhat. I mean, I always think it's a very important point to make when people refer back to the big LNG boom, well, over the last sort of 10, 12 years or so, and how those projects blew out massively across Australia. And all but one, I think, of those projects, the offshore scopes were delivered on schedule and within budget. And it was the onshore greenfield scopes where most of the challenges and the problems arose. And I think that's important to note. The offshore scope is generally easily or easier to compartmentalize and to coordinate the activities on for a number of different reasons and generally a lot more predictable in its deliverability. We're utilizing existing infrastructure. So we're using the existing Darwin to Bayu-Undan pipeline. We'll be cutting into that and connecting to that pipeline. And so we're not having to run an entire pipeline all the way back to Darwin. Again, that reduces risk and, very importantly, the costs. The cash cost of production, and this is very important. As you know, we're a free cash flow-focused business. Our operator model, all it talks about is what the free cash flow breakeven of all of our assets are. We measure that. We monitor that. We talk about that every single month within the organization. Every single person that's running an asset should know what that is for their asset. They should know what that free cash flow breakeven is for their asset. But more importantly, every single one of them is measured against the targets we set for that, for the assets that they operate. Here, we're around $2 per MMBtu. Now it would be lower than that if we went for a full lease option on the FPSO -- sorry, it would be higher than that if we went for a full lease option. It would be lower than that if we owned 100% the FPSO. What we have done instead, and Anthony will talk more detail about around this in his section, is we have gone for what we refer to as a hybrid. So the lease outcome at this end, you've got the buy-and-own option at that end. We've gone somewhere in the middle. We're effectively a sale lease with an upfront payment during that construction phase. That allows us then to get the free cash flow or the cash cost of production level where we want it to be, so that we think we have a very robust cash flow positive project at all points in the cycle. And that's really important for us that we don't throw the baby out with the bathwater and our operating model for convenience to get an FID decision and then left with that high OpEx, that high lease rate for 15, 20 years in the future. So I think what we've done here is quite innovative. And certainly -- and the discussions we've had with contractors around this type of setup, it was a new concept for many of them. We retain all the usual protections in this type of agreement, where if the contract does not perform or whatever, we can step in and we can purchase for that residual value in order to take control of that, if that was the case. I'm very confident when we announce the contracts and the operator of the vessel that, that will never be a requirement. And we're really looking forward to be able to do that soon. That $2 per MMBtu is the sort of benchmark sort of cost for the project. And Darwin's got a major advantage in its proximity to Asia. The lowest shipping cost of any LNG facility is around Australia, and that is a natural advantage for Darwin. And of course, we want Darwin to become a hub for future expansion opportunities as well. As you know, we have approval at Darwin for 2 new trains. We already have the approval of the land. Some of you would have been on the site visit and seen that for yourselves. But you can see on that sort of long-run marginal cost of supply, where it stacks up. And we've said this before that it's 1 of the top 2 or 3 cost of supply projects in the world. And you can see we're not allowed to give the project names here on this chart for a number of copyright reasons, but I'm sure you can work out some of this stuff for yourself. Qatar and Russia is pretty straightforward. Barossa, we can name that one on the chart, so Barossa is the one -- in case you're struggling to read from there, that's the blue one. Any new trains being built in PNG would possibly fall into that category. West Africa, Australia, if anybody was thinking about building new trains in Australia, that's the column that, that probably fits in; and of course, the East Africa and the U.S. And so you can see by any way, any metric you want to measure it, Barossa stacks up as a low cost of supply LNG project. And I know we've taken a long time to come forward and show you the numbers, but it really depended on how we set this up in terms of the lease and everything else. But it's a very, very attractive LNG project, the right end of the cost curve, as we've always said. And it's well positioned to go forward in the first half of 2021. In terms of project on the project itself, that hybrid arrangement I talked about means that the CapEx phase of this project, the upstream project, has now reduced down to $3.6 billion and from the previous $4.7 billion, I think it was, the last time we updated you on this project. I talked earlier about the recycling of the project to deliver some value. There's been a lot of really good work done by Thyl and the project team over in Perth and Brett Darley and the team and really driven some good cost out and some good efficiencies in terms of the design; and very importantly, reduce the risk in the design, reduce the operational risk through optimizing the design. I've talked about the FID targeted for the first half of 2021 with first gas still first half 2025. In terms of sell-downs, we announced previously the LOI to sell 12.5% equity to our DLNG partner, JERA. And we're still on track for that. We're working with our partner in that. That, of course, would become executionable on FID of the project. And consents for the sell-down to SK are progressing very well. And indeed, we have most of the consents in place now. We're only awaiting one more to finalize that process, and that basically then locks in the sell-down to SK. So we'll have one more. They've all started coming in, in recent weeks. And I think I want to give a big shout out here to the Timor-Leste regulator, ANPM, who we have very quickly established a very positive and healthy working relationship with. And we're really enjoying working with those guys up in Timor-Leste. And we've received their consent, and we thank them for that, for the SK sell-down. But more importantly, a lot of support from the regulator in terms of some of our recent spot cargo awards and their involvement in projects like the Bayu-Undan infill program and their supporting of those activities. So the early days are looking really good in terms of relationship with the regulator up there. In terms of milestones and assurance milestones, you can see we've ticked off a lot of the boxes this year and getting this one ready for FID with the sell-downs. And of course, the LNG offtake agreement still unticked but progressing, and in both cases, progressing well. We've had very positive discussions on the offtake arrangements. Jane talked about the market conditions and the market development, if you like, for FID. And on a personal level, I'd like to see a little bit more exposure to JKM. Where we'll land, we'll see. But I'd like to see a little bit more exposure as opposed to an oil being oil price-linked going forward. And we see the markets diverging that way. And I'm really kind of confident that as we go forward, JKM pricing will be driven by that cost of supply. I mean, ultimately, you can see what happens when the LNG prices drop below the U.S. marginal cost of supply this year. The tap's turned off very quickly to correct the market. And the thing I love saying in investor calls, of course, is you must always remember that the LNG market is not a liquid market. I love saying that because it's just a great kind of irony, but it's true. And it's not a very liquid market. You can't store this stuff, and that means that it changes very quickly, the market. You move from oversupply to undersupply very quickly in this market. I also believe that our -- many of the forward-looking forecasts for LNG are conservative, conservative by underestimating demand. And the reason I say that is that most of the supply side forecasts assume that all facilities existing today globally stay full, and I think that's a big assumption. I think that's a big assumption to make, and I'm not convinced they all will. Only the ones with -- that are positioned correctly on that cost of supply curve are the ones that are going to be able to keep bringing in new supply. That's not a given. And again, I think Barossa's well placed. So look, a question you probably asked me today, I think some of you have already asked me this morning, is around offtake, and we can talk a bit more about that in the Q&A, I'm sure. I would still want to have offtake arrangements in place before FID to answer that question. How much? Not sure, but I'd want to have some offtake agreements in place before FID, and we're working hard to do that. We've made good progress on some aspects so that. You can imagine, it's a tough market. It's been a very tough market during 2020 to contract. You can contract. But as you saw with the Qatari deal earlier this year, it may not be where you want to contract as a seller. And we certainly would not want to undervalue a project like Barossa. It's a good project. We know it's going to get up. It's at the right end of the cost curve. And so we'll be patient and get the right contracts to support FID. In terms of Moomba, I'm not going to talk about the project itself because Brett took you through the details on that. But from an assurance point of view, you can see the only thing now for this project to take FID that we're waiting on is the Australian carbon credits. And so the project is effectively FID-ready now. In terms of Narrabri, you can see the focus really, as I've said to you all before, we're not going to spend much money on Narrabri until we get the approvals. And we know we've got a project to invest in. And I'm glad that in 2020, we've been able to get those approvals. And now the focus over the next 18 months to 2 years is really on appraisal, appraising those projects and taking that to a point where we can make FID decision. We expect to spend about $90 million over 2 years, drilling approximately 10 wells and acquiring new seismic and conducting feed studies during that period. So for onshore, we sort of think of FEED and appraisal going together. And that's really important because we want to take a 2P booking at FID. We will not take a 2P booking before FID. That's the rule we have in Santos. That wasn't always a rule, I know some of you would say that to me. But we think the big difference really between here and the CSG development in Queensland is that we're going to appraise the fields first before we make the 2P bookings, right? We're going to fully appraise, and that's what we're going to do. And some people would like it faster. But we've got to know what we've got before we press the button on a development. And so that puts FIDs around the middle of 2023, if everything goes to plan. And you can see then, that would lead to a likely booking of around 500 PJs of 2C converting to 2P for the Phase 1 project. And Phase 1 is around 80 terajoules per day. That's what we'd expect Phase 1 to deliver for that project. You can see lots of interest in the gas, lots of MOUs signed with potential buyers already. And now we'll be looking to pre-contract a lot of that gas before we take FID for the Narrabri development. We've given some guidance here on the current views on CapEx for Phase 1, breaking that out. Now the whole point of appraisal and FEED is to do better than this, and we're just not promising until we do the work because we haven't done the work. Have deliberately slowed down work on Narrabri until we got the approvals. Now we're going to go in and do the work. We'll appraise. We're targeting -- the EIS has a gas price of around $6.40 ex Narrabri. We're targeting less than $6. And again, we'll update all of that once we get through the appraisal program and we get a better feel for subsurface. What I can say is it's all performing very well. And then post-2026 is when Phase 2 comes in, an additional spend. So that's probably a lot less CapEx than many of you were thinking this side of 2026. But Phase 2 is when we'd start spending some more money. [ You've got a watch ]? Now I know I'm running out of time. The last project I want to talk about is the Dorado project. And as a consequence of COVID and slowing things down, the sort of reprocessing, what we were doing on the seismic has caught up with the project. And one of the consequences of that really is that it's identified a number of prospects and leads across the basin and a number of tieback opportunities, potentially very low-cost tieback opportunities. This is a discovered resource basin. And I want to make that point, there are other discovered resources across this area. And we've got a very strong acreage position, as you can see by our interests in all of these blocks here, 80%, 70%, 50%, 80%, 70%, 100%. And across these blocks, we have established, as I say, numerous leads, I can't remember how many leads in total, 6 main reservoir units identified, 10 plays identified, a risked mean prospective resource of around 990 million BOEs, almost 1 billion BOEs, with approximately or just over 50% of that thought to have liquids potential. So that's a very significant resource. Now that's in addition to the Dorado resource we've already communicated to you, right? So that's in addition to the Dorado resource. So it's very significant. And that's very exciting because it means there's potentially something much bigger than we thought in this basin. But it does come -- does cause a little problem. Because when we're then thinking about what this project looks like, we were planning a liquid stripping project and then the gas from Dorado being Phase 2, as you can see, sort of 4, 5 years later. But -- and this project will come on with very strong production in Phase 1. So we're talking here about 150 million barrels of liquids, between 75,000 and 100,000 barrels initial production rate. And the guys always made me say between 75,000 and 100,000 barrels per day. When they present for me for budget, it's always 100,000 barrels a day. I'll just share that little insight with you in terms of how organizations work, right? My expectation is going to come on a lot closer to 100,000 than 75,000 -- well, it will if it works, right? And that's the point. So a very exciting project, very good reservoir. Upside, upside still at Dorado, I mean, the Baxter formation, we didn't find a water contact. We think that could be significantly deeper than we have used in our model. And if it is, that's a heck of a lot of upside potential in the Baxter formation. And that's something we look to test in the years ahead. But what's really important here is 2 prospects have really jumped out because they're quite close, Pavo and Apus. And that's really important. I had to think there and concentrate because I normally say -- I only get them mixed up, Pavus and Apo. But it's Apus and Pavo. And they're only 40, 45 kilometers away from our facilities. And so if they come in and the liquids, it changes the Phase 2 because Phase 2 doesn't become Dorado gas anymore. Phase 2 happens pretty quickly after Phase 1, and we keep the production up. And what's really good about that is we're not talking about a well. We're talking about fields being tied back to the FPSO. And I'm sure you've already worked out then that, that means those fields don't need their own FPSO. So this becomes really low-cost field development. And so this is what's really exciting about Dorado. Dorado is a great project. But when Phase 2 comes in, if Apus and Pavo come in, and those fields are developed at very, very low CapEx, they're as good as any old project you're going to get anywhere globally. And of course, then Phase 3 becomes a much bigger gas project on the back of the Phase 2 liquids project. In order to get -- make sure that we do it right, though, we need to make sure that we know what's in Apus and Pavo before we take FID. And so it's convenient because it helps us phase the FID in that project. By pushing that back to the first half of 2022, that allows us to drill those wells at the end of '21. And we know exactly what we have in those 2 locations. We make sure the design and the specification of the FPSO is 100% correct, so that we're not either sending it back to a shipyard between developments, which would be expensive, and the loss of value from deferred production and/or we don't overcapitalize on the FPSO upfront. And that's very important. You don't want to overcapitalize and then say they're 2 dry holes. And then you spend all that extra capital, an extra couple of hundred million or whatever, potential loan facilities you didn't need to spend. So look, it's a really exciting project. It's getting bigger, it's getting better, which is not unusual for good basins, right? But the impact of that means that instead of looking at FID at the end of '21, we're looking at mid-'22 because we want to drill these 2 wells first, and that's a consequence of that. But I want to explain that logic. Hopefully, that was clear to you. In terms of the gas developments in the future, you can see we've identified some routes for that gas to come back to the Beach, and that can be anywhere from 400 bs to more than twice the -- or twice that, depending on what we see at these other locations. And in terms of [ projects ], I think I've given you most of this project update already, so I won't dwell on this slide. You can read that at your leisure, but it's going well. One of the good things on the CapEx side, previously, we've said $1.9 billion to $2.2 billion. We brought that down to $2 billion because we're seeing better estimates coming in than we've been previously carrying in our original pre-FEED estimate. So the project is looking in good shape. All 4 projects things are looking in good shape, and we'll just keep managing them in a very disciplined and steady manner. And I hope that gives you great confidence on the deliverability of those. On that, I'll hand over to Anthony to take you through the financials. Over to you, Anthony. And sorry, I took a couple of minutes late. You've got time. Apologies. Just take your time.

Good morning still, everyone. So thanks. Home strike, finished with a bang, as usual. I would like to apologize for Kevin earlier this morning. He didn't really mean to offend all the Aussie rules supporters and potentially half of our shareholder and investor base. We do have a disclaimer at the front of the pack, which covers all of those risks off as part of the presentation. So Aussie rules isn't really that simple. It is a complex game. So -- but look, I'd like to touch on 3 points. In the sense, we've touched on the -- it's quite a resilient base business, really strong performance in 2020. Low free cash flow breakeven, strong free cash flow still coming through despite the lower oil prices and the impact of COVID. And it really is, as you've seen for the topsy-turvy world we've had this year, driving shareholder value as well. Secondly, I'm going to touch on the disciplined approach to capital allocation, which Kevin and David have already touched on slightly. And then lastly, just finish on the balance sheet and how we're preparing the balance sheet, and it's ready for growth. This slide basically dives into those in a bit more detail. So as I said, we've had quite a good strong free cash flow generation this year. We've got a resilient base production. As you saw from the chart earlier today, we've got a flat base production now for pretty much the next decade to 2030, and then the major growth projects kick on top of that and take us up to a peak of 120 million barrels. We've basically got the strong capital in place ready for our growth phase over the coming years. And finally, we're basically putting protections in place, and I'll touch on that through our strong gas fixed-price contracts and also our hedging programs, which give us a good protection to the volatility of the oil price. Free cash flow for the 9 months ending 30th of September this year was $574 million, which is a very strong result given the impacts that we've had of COVID on oil price this year. Pleasingly, we expect 2020's forecast free cash flow breakeven to basically, as Kevin said, be under $25 a barrel, excluding hedging this year. And including hedging, it will be under $20 a barrel. We also see that type of performance moving into 2021 as a forecast as well. Our continuous focus on costs and discipline around that this year has also meant that we've been able to reduce our OpEx guidance this year to now in a range of $8 to $8.50. So the cost reductions that we pushed through the business and announced in March as a result of COVID, pleasingly, are flowing through into that bottom line now, particularly in the second half, as those initiatives have been pushed through. We've also managed to refinance our Conoco acquisition facility a month or so ago with strong support from the banking community, with a 5.25-year facility. So again, getting everything ready to move into our growth phase. We retained flexibility in the broader portfolio to be able to do strategically aligned farm-outs for the high equity positions that we have moving forward. So the balance sheet is in a good position as we are getting ready for the growth projects. Just touching on our operating model in action. You can see from this slide that it really does come through to the bottom line. We're driving strong results across all aspects of the cost management of our business. The operating model is delivering that low free cash flow breakeven. I talked about all of our assets are free cash flow-positive, at less than $35 a barrel. Portfolios, free cash flow positive, as I said, at less than $25 a barrel, excluding hedging. You can see the cost reductions, particularly in the portfolio, OpEx, down the bottom left are really flowing through from the first half. We were down 6% compared to the end of 2019. And that's on a base business, including Conoco acquisition. Conoco does slightly increase our costs for this year due to the fact that we have now 68% of the Bayu-Undan late life asset, which is around about $20 a barrel. But overall, still reducing. And as I said, pleasingly, those cost reductions are coming through stronger in the second half, and we've been able to reduce our full year guidance to that $8 to $8.50 range. Our onshore GLNG well cost discipline has continued. David spoke about that in his presentation. And we also have the efficiencies coming through in the Cooper Basin through the horizontal wells in the program and the continued cost reduction in our vertical wells. The efficiency journey is not over, as David touched on. We'll continue to drive that through this operating model. And the cost efficiency in the business has not stopped, and we're continuing to drive that through to the bottom line and leveraging new drilling technologies and operational efficiencies across our business. So as I said, the result of that is the fact that we can, see moving into 2021, our free cash flow breakeven levels of this year will be maintained at less than $25, excluding hedging. And then hedging, obviously, improves that further. So in terms of our segments and breaking it down into the EBITDAX margin, look, everyone has seen this slide. It's a fantastic slide that we like to show, particularly around results. This is our first half results. Really balanced and diversified portfolio across all of the assets. Pleasingly, the Northern Australian segment there only has 1 month of the Conoco acquisition in it, which happened in May. So the Northern segment will actually get stronger EBITDAX as the full year -- as the first -- sorry, 6 months -- second half flows through to that number. So what you'll start to find is the EBITDAX across all of those 5 segments becomes very balanced, very similar, strong margins across all of our assets. Overall, we've got a 58% margin EBITDAX in the first half. All of the segments have got greater than 40%. And all of them, as I said, have a free cash flow breakeven of less than $35 a barrel. Also, as we touched on earlier in the presentation, with -- a large portion of why we're getting some of those improvements is we're seeing the synergies delivered from the Conoco acquisition actually increasing to a run rate at the end of the year of around about $90 million to $105 million per annum. So again, strong margins, good cost-outs flowing through to a strong EBITDAX margin across our business in a very balanced and diversified portfolio. This slide basically shows the free cash flow generation of our business. So as I said, for the first 9 months, we generated $574 million of free cash flow, and we're on track to have greater than $650 million subject to oil price and how it finishes the year, for the full year. We're less than $20 a barrel breakeven, including hedging for this year, and we'll continue that momentum into 2021. Our forecast free cash flow yield for the year based on the current 1 month VWASP is around about 8%. And pleasingly, the hedging program for this year has been very effective. So for the 9 months ending 30 September, hedging program had delivered USD 45 million into the cash flow for the year. The resilience of the portfolio is strong and it continues into 2021. Around about 40% of our business continues to be domestic fixed price gas contracts. And we've already started our hedging program for 2021, and around about 10% of our oil price-linked exposure is already hedged at a floor of around $40 a barrel. So basically, what that means is going into 2021, we've already got 50% of our portfolio locked in and naturally hedged to the oil price volatilities. For every $10 in oil price movement above our free cash flow breakeven. So as I said, we're aiming for less than $25 moving into 2021. So for every $10 above that, the portfolio will generate around about $330 million, excluding hedging. And the chart on your right-hand side basically shows you some of the sensitivities. And I know all of you wanted to have gearing on that, so we've put gearing on there, so you can run the numbers. To give you an idea, moving into 2021, it's a very strong, resilient base business, and an oil price of around $45 will generate very similar free cash flow to what we're generating this year. Yet, we've actually got higher expenditure moving into 2021 as we pick activity back up post-COVID. So we'll have about $660 million at $45 oil price next year. And gearing basically comes down a small portion. So we're currently around about 33% gearing. So next year, we'll be 32% with that higher activity level and, as you'll see in a couple of slides, also higher growth CapEx coming through. If oil price improves to $55, just to give you that sensitivity, we'll generate over $1 billion in free cash flow and gearing will decrease to approximately 30%. So the gearing is in control. It's within that range of a disciplined operating model of 30% to 35% during that growth period and strongly leveraged to oil price. But pleasingly, even on the downside, assuming we have a $35 per barrel oil price for the whole of the year, gearing is still only 34% and free cash flow is still positive at $330 million. So the business is well set up moving into next year and moving into the growth phase. This slide shows the production and sales guidance for next year. So basically, we've updated our production guidance for this year at 87 million to 89 million barrels for the year. 2020 sales volume guidance has also been narrowed to 103 million to 105 million. As we move into 2021, you'll see that we've got an increase of production guidance of 84 million to 91 million barrels of oil equivalent. Now that does assume we're completing the sell-down of Bayu-Undan and Darwin to SK in the first half, so 25% sell-down from -- so we'll move from 68% down to 43% approximately in that asset. That's included in that guidance. That reduction in production is offset by the fact that we get Ningaloo Vision back on station in the first quarter of next year, so higher oil production. And we're also completing the Van Gogh infill program in the second half, so we'll have wells on late in that second half, which offsets. So basically, we're able to maintain production even with a lower equity limit in Bayu-Undan and Darwin going in 2021. And 2021 sales guidance is 98 million to 105 million barrels. I'd like to touch on the capital allocation process, given that we're about to enter into the growth phase. And as Kevin touched on, we've got good committee structures and governance in place across our business to ensure that we're ready for that growth phase. The overarching element of our corporate strategy has been that Transform, Build Grow slide that you saw earlier in the presentation in Kevin's section. And the transform phase was really about optimizing the business, ensuring we've got the right discipline in place, that we're focused on the right assets. We're generating value. We're generating free cash flow. And we've embedded, as part of that strong Santos management system and [ SMS ] framework that sits into the business, and that's got operating standards under which the business operates. In terms of planning and capital allocation, our disciplined low-cost operating model sets the framework that drives that value. As Kevin said, it is easy. It's -- every asset is less than $35 a barrel. The portfolio, it's less than $35 a barrel, and gearing is less than 35% during the -- and that includes growth phase of that. So basically, what you'll find is that over that 5-year planning cycle that we look at as a business that we make sure those rules are kept. So for the 5-year growth phase that we're about to enter into, we've looked at the capital allocation, we've looked at the projects, and we've made sure that gearing can be maintained and through the phasing of the projects. We've made sure that the assets are not breaking the $35 rule in the portfolio is still balancing at less than $35 a barrel. And that's a rigorous capital allocation we do through the 5-year planning process. As you saw from our portfolio that we looked at with the 10-year look forward of production, we also run a long-term plan called portfolio, corporate portfolio, which looks like a field as well. So we're not only looking at the 1-year plan in detail for joint venture budgets. There's a 5 year plan where we really look through the rigs at allocation, which covers the whole growth phase, and then there's a life of field portfolio that we look at. We also look at a number of metrics, multiple metrics we looked at, including return above WACC, payback periods, capital intensities. We stress test gearing for oil prices, phasing of projects, delays, costs, et cetera. So there's a lot of stress testing and rigor that goes into the capital allocation and planning process that we've looked at to make sure that the balance sheet is set up for the next 5 years. We've also got strong corporate functional oversight, as Kevin touched on, that provides the rigor around the investment decisions, the capital management looked at risk management plans looked at for all the projects. They're reviewed by all of the subcommittees and the Executive Committee. And obviously, for the major projects, they also go up to the Board. So this rigorous process, hopefully gives you some comfort that we really are looking at the stress tests and the capability of the balance sheet and the returns of the project to make sure that we're really picking those projects that are driving shareholder value over the next 5 years. Just a little bit of insight into CapEx. So this slide outlines our CapEx guidance for 2020. Guidance is unchanged at $900 million to what we announced in the first half. $750 million of that relates to our sustaining business and $150 million that of this year was for the growth projects. So basically, we've delivered what we said we would deliver through the cost out journey of 2020. Next year, you can see sustaining CapEx will increase from $750 million to $900 million, and that's as activity starts to increase post cover. So this year, we did cut levels, as David touched on, we will be ramping activity levels back up to that sort of $900 million. And then looking forward, so was a question we get, look, during that sort of 5-year plan period that I just talked about, you could probably say that, that sustaining business is going to be around that $900 million to $1 billion type level over the next 5 years. So that's a pretty good sustaining level to work around. 2021 major growth CapEx guidance is, you can see, increasing from $150 million in this year, up to $700 million next year. That assumes that we will be moving forward with FID in Barossa in the first half at a 50% level. So we're assuming the sell-down to JERA that we previously announced to the market will be completed as part of the, and we're also assuming that we'll take FID on Moomba CCS in the first half, and we'll also take Dorado into feed and commence the appraisal. In terms of capital management, look, we took decisive decisions to reduce CapEx in 2020 due to the lower oil prices in COVID crisis. We've reduced our target free cash flow barrel, as I said, $25 a barrel. And pleasingly, we've been able to achieve that. And we've achieved the CapEx and the OpEx reductions that we pushed through. Through the capital allocation process that I just spoke to, we also looked at phasing of projects. And we looked at the spend of those projects over the upcoming growth period over the next 5 years. Dorado has been phased, as Kevin spoke to, and that's now moved out. We've pushed the FID on Barossa out to the first half. We've pursued a lease opportunity with Barossa, which is something different during this year that we've pulled off. And that's also bought significant CapEx savings. As Kevin touched on, we went for an option whereby it's a balance between getting the lease rate right versus trade-off for CapEx. So the guidance for Barossa, as Kevin said, is $3.6 billion. You might ask, well, previous guidance was $4.7 billion, why didn't it reduce as much? And it didn't reduce by as much because of the fact that we got that balance between just less than half of the OpEx -- CapEx saving from the FPSO comes through an up-front lease payment. So basically, we've almost paid for nearly half of the FPSO, and that's the balance to sort of say, well, you haven't dropped as much CapEx as you thought. But we got that balance right to sort of say, we'd say a large chunk of CapEx, less -- more than $1 billion from our previous guidance. Some of that's been pushed into the go-forward cash cost of production, but we've been able to maintain a low cash cost of production at around $2 per MMBtu, as Kevin said. So we got that balance between saving CapEx and assisting through that growth phase of balancing the portfolio and also maintaining a low cash cost of production as we move forward by not having such a high operating lease rate going through the OpEx. Barossa FEED also has the sell-downs that will be part of the critical decision, as I said, we've -- the JERA at 12.5% to take it down to 50%. And we're still looking at further sell-downs. So we're still targeting a range of 40%, 50% of Barossa as our final hold position. So we will look -- over the coming years, look forward at that further farm-downs of Barossa. And as Kevin said, that also helps as you're potentially looking at offtake arrangements for LNG as well because some buyers do like to hold equity in the project. So we've got the optionality around further sell-downs in the Barossa project. We have strong liquidity. We've got $3.1 billion of liquidity, which consists of $1.3 billion cash on hand and $1.9 billion in undrawn debt facilities. And despite the lower oil prices, we're also looking at that low free cash flow breakeven, which has given us a balance to support our growth projects. But importantly, it also means that we can keep a sustainable dividend policy for our shareholders in the range of 10% to 30% of free cash flow, as we've previously announced as a payout ratio. We're actively managing our debt. As I said before, we've refinanced our Conoco acquisition facility with a 5.25 year term loan. And finally, we've got that flexibility across the whole portfolio, not just to balance the growth projects. We've got full control over our growth projects. We're the operator. We've got high equity positions in all of our growth projects, and it gives us that ability like we did this year to be flexible and nimble as the opportunities move forward. This slide touches on our drawn debt maturity profile. We've successfully completed the refinance, as I said, for that facility highlighted in red. So we moved it out to 2026 for a $750 million 5.25. Pleasingly, and as I've said to a lot of you already in this room, the liquidity support from the debt banks this year has been fantastic, and the support in the market is strong. We were over 3x subscribed to the facility. So we could have taken more money off the table if we needed. We didn't get greedy. It's balanced. You can see the towers are all stacked quite nicely. We're not overgearing any year so that they're manageable and they can be paid through -- paid down out of free cash flow when we get to those periods. So there is support in the market and strong liquidity in the market, which is extremely important when you go through tough times like the economy and -- everyone has gone through this year. Our net debt position is $3.6 billion, which includes the PNG project financing debt. And gross debt is circa $4.7 billion, excluding leases, as shown on the left-hand side of the page there. On the right-hand side, as usual, I'll just show you what it does look like when you take the PNG facility out. The reason I'm taking the PNG facility out, it's not to say that it's not debt. It is debt, but that is paid for out of the cash flows of the project. The right-hand side is paid for out of the cash flows of the corporate. And you can see that it's a much lower cash flow that needs to come out of the corporate entities to fund the $3.4 billion in senior unsecured gross debt on the right-hand side. Our balance sheet is strong. The degearing, as I showed on the previous slides, occurs through the free cash flow generation of the business, and that's including all of the ramp-up in activity and the increased CapEx that I touched on this year. So basically, in summary, the disciplined free cash flow focus that we have continues to drive the shareholder value and lower costs that are flowing through to that free cash flow breakeven of less than $25 per barrel. And we'll maintain that moving into 2021. And you can see from the debt maturity profiles and the gearing numbers that I gave you, that the balance sheet is in strong position as we move into '21 and the growth -- commencement of the growth period. So on that note, I hope we've given you a good overview of the business today. Kevin is just going to quickly touch on wrap-up, and we'll move into Q&A. So thank you.

So thank you, Anthony, and thank you to all of the presenters. I'm going to ask all the presenters to come up and just grab one of these seats for the Q&A session. So if you can come back up, please grab the seats and -- in case the questions are getting thrown around. Obviously, it's a lot -- I mean a lot of stuff we cover at these events. And I know it's a lot to take. And the key -- and I'll just touch on some of the key highlights. For me, again, really pleased to see the core business, the base business, performing really well. And I think that's a testament to the full management team and the focus that we retained through the organization on the nuts and bolts of the base business. And I've always said that, that's what you've got to get right in these types of companies, first and foremost. It's one thing to get excited about growth. But before you do that, get the base business working well. And I think looking at the production guidance updates, cost guidance upgrades, and of course, the progress we've made on the acquisition synergies is a testament to the hard work across the organization in what's been a very, very difficult year. And I think the -- I've said it before, I think we've got the best management team in the industry. There's a lot of experience at the table around the group. And we're continuing to build that depth and that succession capability through the organization. And a lot of good additions to the team from the acquisition of Conoco, as there was from the acquisition of Quadrant before that, that we're building a really strong team and good capability across the organization. Really excited about the new emissions reduction targets, not just because it's reducing emissions but because I think we're now at a point where we can talk confidently about a road map, a realistic road map, real activities and a plan to achieve net zero by 2040. And I haven't seen, as I said earlier, too many folks who can do that yet as much as we have aspirations. And that's why we had a previous aspiration to be net zero by 2050, not a target because we didn't know how. At that point in time, it was an aspiration. Now we've got a clear 2040 target, and we've got a plan to get there. And then on the growth, some real tangible progress. I talked about the stuff on Dorado and how that Bayu Basin is beginning to unfold, and it's very exciting. But on the project itself, taking that [ forward ], we're going to drill those 2 wells during the FEED or simultaneously with the FEED process. We'll still take FEED early in the new year. But FID, really pending the results of those 2 wells. We want to make sure we design it once, we design it right and we get the right development solution for that region. And on Barossa, really pleased to see the progress there, getting that ready. And a very big milestone, as you would all know, is getting those tolling agreements and pipeline transportation agreements in place. And so I'm pleased to see that that's been achieved and that we've got to that milestone of FED-ready -- or FID-ready for our CCS project at Moomba. So on that, I mean, that's just a summary. I want to talk about some of the focus and strategic priorities for 2021. I always like to finish these sessions by talking about some of our priorities for next year. And one, of course, is maintaining that strong base business with a free cash flow breakeven of less than or around that USD 25 mark. We want to keep the business functioning efficiently and keeping that low cost. And that's what that -- those long life assets, that steady production profile allows us to do, with all the activities to maintain that, being self-funded, within those rules of the operating model. We want a [ FID ] Barossa in 2021. We want to take FID in Barossa in 2021 and [ go build ] what you can see clearly is a world-class competitive LNG project. We want a [ FID ] to Moomba CCS project in 2021, and that's dependent on the government getting the ACCU regime in place. So we've got a plan. We've got everything in place now. Just to press the button the minute it qualifies for ACCUs. And the minute it does, we will press that button and we'll start building up. And then within a couple of years, we should be injecting around 1.7 million tonnes per annum of CO2, permanently storage and those deep reservoirs in the Cooper Basin. And take FEED in Dorado. We're going to do that, we said in the first half of 2020, and keep that project moving forward. And of course, we'll commence the appraisal drilling at Narrabri and push that forward, so that sometime in 2023, we're in a position to take FID toward Narrabri. That's the key focus areas for 2021. And on that, I think that concludes our presentations for the day. So we'll now open it up and give you the opportunity to ask us some questions. Thank you very much.

Kevin, it's Mark Busuttil from JPMorgan. Just a couple of things, and I wanted to start with the infrastructure assets and what you're talking about, about the $400 million in EBITDA. Firstly, just a clarification on that. The $400 million in EBITDA, is that -- does that include revenue from oil and gas sales? Or is that based on some sort of toll treatment charge? Because you sort of said $400 million at current oil prices. So does that include the revenue from the oil and gas sales?

Yes. The revenue attributed to those midstream assets is from the internal tolls or tariffing regimes that we have with the upstream joint ventures, right? So we -- in each of those cases, we've got those arrangements in place. Perhaps you want to elaborate on that, Brett.

Yes. So that doesn't just include the internal tolls, it also includes the external tolls. So looking forward, if you think of the deal -- the agreement we've done in Darwin LNG, we've now got external tolls regime set up for Darwin LNG. So it's kind of -- probably misquoted. Probably irrespective of the oil price, we're going to deliver that long-term sustainable cash flow through that throughput tolls. So the oil price impact sometimes impacts the amount of activity in the upstream, not the tolls.

Yes. Okay. And is there an active intention to sell or spin out those assets? Is that the reason why you're doing this?

Look, the primary reason, as I said before, because we want to deliver value through midstream infrastructure assets. We want to develop our management team culture and thinking around how -- around these assets, unlike how conventional oil and gas companies typically think of these assets. So in very simple terms, most oil and gas companies would think about not letting people use that infrastructure because it's a perceived competitive advantage they're going to build on. But all it does is put everybody's unit costs up, right? Whereas we are open for business with infrastructure. We won -- if we've got capacity in our infrastructure, it's open for anyone to bring their products through it. We want see that utilization. I want a management team out selling capacity, selling term in these assets. They cost a lot of money to put in place. I want them to maximize the revenue and the take from those assets. So a very nonintegrated sort of oil and gas company, we are thinking about how to maximize value. And also Brett about the optionality it gives us. It gives us optionality to think about different equity levels, different equity levels in the midstream from the upstream. And that's all part of how you view risk at any point in time as you move forward as an organization. You might want a higher, steady, guaranteed. If you've got term in capacity, you may want a higher sort of steady revenue stream from a certain piece of infrastructure and go lower on the upstream or vice versa, if you think the value is going to work for you the other way. And then in terms of optionality, sure, it gives you ability to think about selling down or selling out. But I'd always caveat that by saying to you, I don't like locking in OpEx I can't drive down. And so selling all of my infrastructure and then having a 20-year toll that I can't do anything about is not how I'm going to become the lowest-cost producer. So you have to -- that's the only caveat, I would say, on selling -- farming down, selling stakes in -- building infrastructure portfolios and selling stakes in that portfolio, sure, all of those are options. Brett and Anthony, do you guys want to add anything to that?

Yes. So we've built all the arrangements associated with the legal structures to do all those things that Kevin suggested. At the moment, it's really focusing on delivering lower cost, making sure the structure is set up to play whatever requirements we need. But fundamentally, the thing that I like most about it is that long-term sustainable cash flows that we can deliver throughout -- whatever the cycle is, we'll be able to deliver that throughput and that value back to Santos. And as a stipulation, Kevin has made it very clear, we need to own, we need to control what we operate. So if we don't have the OpEx going up, we can sit there and continue to drive cost out for the future.

Yes, because -- if I could just add one thing on that. One of the advantages of an infrastructure portfolio is that you can centralize your operation, maintenance, your planning, your shutdown scheduling, all of that sort of stuff. And so as opposed to having -- because quite often, you need the same resources for 1 asset as you need for 2 or 3 to support that activity, the engineering support, et cetera. So you get economies of scale that you can't get on 1 asset. You just physically can't get it. And so we're looking at Varanus Island, Devil Creek, Port Bonython, Moomba, Curtis Island, Darwin LNG, Bayu-Undan offshore facilities, FPSOs offshore. Suddenly, you can start to centralize and get economies of scale around your engineering and maintenance support, which can take significant cost-out of those operations. Spare sharing. The LNG trains in Darwin are the same as the trains in Curtis Island, same technology. So you can start to think about your spares and your backup and your engineering support across multiple assets.

And through that, that's why we're targeting 30% cost out across our infrastructure position. Because of those synergies across our broad asset base, we have line of sight to how to deliver those.

All right. I need to get someone else to ask a question. Yes. [ Mark ]? We'll come to you next, Gordon. We'll come to you next.

I guess the sign of the times, I'm going to ask a couple of questions on CCS, if I can. First of all, I noticed on Slide 47 that you talked about 100% ownership. Can you tell us how you're thinking on, obviously, your technology and Beach have [ exclusive ] rights, obviously, to the reservoir's BP. Let's talk about the agreement with them. Can you tell us how we should think about the ownership going forward?

Right. So Beach will benefit from this as well Santos. But basically, what we're looking at is energy solutions providing that service to the SACB, the joint venture, right? And so we're kind of viewing this, today, is 100% Energy Solutions project that they will deliver that service to the joint venture. And obviously, there's arrangements between the joint venture and Energy Solutions then to make that happen. And so that's why that shows as 100% there. Quite frankly, the project itself wouldn't really matter to me. I mean you can argue that's one way of the joint venture avoiding the CapEx. But ultimately, if they want to pay the CapEx upfront, they can do that as well. The joint venture could do that as well. I think what's important is that we want to do this project, and we want to do it in the time frames that we've identified today. We wouldn't want any of the upstream oil and gas, and that includes Santos and our joint venture partner, which, in this case, was Beach, letting that annual budget constraints or challenges get in the way of that. We think it's too important to do that. So this is really a way of Energy Solutions driving that and taking that on as them delivering the project to the joint venture, and then the joint venture paying them appropriately for that, yes.

And then can we just think -- longer term, obviously, you talked about it being able to do 20 million tonnes a year. You're obviously initially constrained by emissions within the Cooper. Have you done any early work about transporting them? Is it something logically that government's going to spend a lot of money on infrastructure to the government fund, some kind of?

Look -- great. There's about 4 questions wrapped up in that one question, and that's a skill that you do possess. I envy. But, look, let me just say that -- and that's a great question because we've got 20 million tonnes per annum. You rightly make the point, we don't produce that much CO2 across the Cooper Basin there. With other operators in the Cooper Basin now, there's a bit more that we can grab. And they're close to infrastructure, so we think we can do some stuff there. We have done preliminary look and some detail studies, in fact, looking at how we can go to other industries and take their emissions, right? You need around $100 to $150 per tonne carbon price to make that work. And some people believe in that price. I'm not betting on it, right? And so that's very expensive. So I don't see that happening anytime soon. Once we start to generate hydrogen, though, from methane, and as we say, we've got a lot of low-cost ingredients around us that make that possible at $2 or less today per kilogram. One of the benefits of that is that you produce CO2, right, through the processing. And so by being able to capture that and inject that, and that qualifying for carbon credits to create zero emissions hydrogen, we can generate a lot there as well. And so that -- and if you think of carbon credits as your revenue stream, that becomes a revenue stream that heavily subsidizes the cost of the hydrogen generation and then use the hydrogen for your fuel. And that's why having that ready-made market -- internal market can become a real lever for us to accelerate that process instead of waiting for the infrastructure build for export and, of course, the customer market to do that. Other opportunities include bringing other people's CO2 back from other oil and gas operations elsewhere. And you'd be surprised that some of the things we've been asked to investigate, including CO2 from other parts of the world. I don't know how that works, but people want to talk to us about bringing their -- importing CO2 at the Cooper Basin if we can permanently store it. So I think there's a long way to go to see what that will play out like, [ Mark ]. I don't think we understand or know yet what all the potential opportunities will be. But I think the exciting thing is because we're opening this opportunity up, opportunities are developing. This is very much a new market, right? It's a new business, if you like, and opportunities are opening up. But the Cooper Basin, just that natural ingredients that gives us that competitive advantage that we haven't seen replicated anywhere else globally, and that might be good fortune. I'd love to say it's good planning. I'm not sure I can. It's good planning to get the team to get us to where we are today. But Mother Nature has been pretty fortunate to us in terms of giving us the right location for this. Thanks, Mark. Gordon?

Congratulations, Kevin, on the Barossa cost of supply. It's a very low figure compared to some of your peers. And I guess what I'm trying to get my head around is what are the driving factors? Obviously, you mentioned transport distance and brownfield, but also the lease structure that you've got. Just like a little bit more detail on why your numbers look better than your competitors who are also looking at brownfield expansion.

Yes. Well look, I mean, I think there's a simplicity around the project that helps. And one of the benefits that Barossa has is it's got liquid, right? And so liquids, as we know, with any gas or LNG project, given the ability that liquids create, if you like, against the price of gas and give you a lower cost of supply outcome. So that's something that Barossa is fortunate in terms of having. In terms of the lease structure itself, Anthony took you through some of the specifics of that. But it's -- the cost reduction is more than just leasing. It's more than that. We've actually taken some costs out of the project through the value reengineering, simplification of design that's allowed us to kind of get that cost base down. And -- Anthony, I don't know if you want to add anything further to that. I don't know if I've missed anything there, but....

No, it's brownfield project. I mean the liquids and the brownfield nature of the project mean that from an integrated perspective, you've got a very competitive project without extra cost burden that a lot of the other new projects have to bear.

I think for me, Gordon, it was equally important to focus on the OpEx side because once it's built, I've got it for the next 20 years, right? So it's equally important to focus on the OpEx and not put all your focus just in getting the CapEx part of this right. And so I'm pleased that the team has been able to maintain that balance. And that's why we've come up with what I describe as a hybrid lease-type solution, where there's that payment to make sure that our operating cost is down at a very competitive level. Yes.

Just add to this, the $500 million that's being spent at the Darwin LNG plant to handle the Barossa gas. I'm assuming that CO2 and liquids presumably are...

Yes. And it's also some typical life extension stuff you would have, corrosion repair. They thought a thing you'd get every 20 years or so in a coastal LNG facility are just renewal, right? But the guys there have taken $100 million as well. They've taken another $100 million out of that project just by how they've sequenced the events. And of course, by -- able to push the life of Bayu-Undan as well and be able to still not require more time to do that as a cost advantage as well, to do the life extension work, I mean. And so the guys are really just planning a lot of that work in the annual work programs going forward, and that just reduces your costs significantly.