Thank you for standing-by. And welcome to the Santos' 2021 Full Year Results Question-and-Answer Conference Call. All participants are in a listen-only mode. The call will begin with Mr. Kevin Gallagher, Managing Director and Chief Executive Officer providing some opening remarks, and we will then move straight to Q&A with both Kevin Gallagher and Anthony Neilson, Chief Financial Officer. [Operator Instructions] I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead.

Thank you. Good afternoon and welcome to the Santos full year results question and answer call. Joining me is CFO, Anthony Neilson. Anthony and I recorded a video presentation on today's results, which you can find on our website, along with the presentation pack. We're not going to repeat the video presentation on this call. We will, however, be happy to take your questions. But before we do that, let me make a few brief opening remarks. I'd like to start by acknowledging the traditional lines of the Aboriginal people of the Adelaide plains from where Andy and I are speaking today. I pay my respects to elders past, present and emerging. I also acknowledge the traditional owners of all the areas where Santos operates, including in PNG, Timor-Leste and Alaska. I'm pleased to present yet another strong set of financial results that demonstrate the strength of a discipline low cost operating model. There are record results, the highest revenue free cash flow and underlying profit in Santos’ history. I would particularly call out record production volumes over 92 million barrels of oil equivalent. Sales revenue increased 39% to just over $4.7 billion, which is a record. Lower unit costs, our focused on safe, low cost and efficient operations delivered a free cash flow breakeven of $21 per barrel in 2021. EBITDAX was up 48% to $2.8 billion driven by higher oil prices and lower unit costs. Underlying profit was up 230% to a record $946 million. I remind you that these reported results include only three weeks of the oil search assets. If we include them for the full year, then sales revenue would have been $6.2 billion. EBITDAX would have been $3.8 billion and free cash flow would have been over $2.3 billion. These numbers demonstrate the size and scale of the new Santos, we’ve now delivered more than $5 billion in free cash flow since 2016. Include the oil search assets for all of 2021 and that would have been more than $6 billion. In 2022, once again, we are targeting a free cash flow breakeven before hedging of less than $25 per barrel. I remind you that this figure is after we include all of our sustaining and restoration CapEx. And for every $10 the old price is above our free cash flow breakeven, the portfolio generates around US $450 million in free cash flow. This means that at an average oil price of $65 per barrel this year, we could fund all of our major growth CapEx from free cash flow, including potential FIDs on Dorado and Pikka. As I've always said cash is king. And at current oil prices, Santos is generating a lot of cash. This cash allows us to fund growth from the energy transition and to provide returns to our shareholders. I am pleased to also announce that the board has declared a final dividend of US $0.085 per share, a 70% increase on last year's final dividend. The dividend is franked to 70% and consistent with a sustainable dividend policy is 20% of free cash flow for the merged entity less dividends paid in the first half by both companies. Our reserves and resource position has been transformed through the merger and FID on the Barossa project. 2P reserves increased by 80% to 1.7 billion barrels of oil equivalent, the merger added 416 million barrels in PNG, including a much higher interest in the world class PNG LNG project, and Barossa FID added a further 373 million barrels at our 50% interest following the sale down to JERA . Barossa is now 25% complete and progressing on schedule and budget. Barossa is basically an offshore scope with an FPSO and a pipeline tied into the existing Darwin LNG plant. So we are not materially exposed to cost or labor pressures in Australia. 2C contingent resources increased by 40% to 3.2 billion boes with the largest increase associated with a Papua LNG and Alaska projects. We also noticed a booking of 100 million tons of co2 storage resource in the Cooper basin. This follows FID Moomba CCS project in November. We see co2 storage as a strategic competitive advantage and involving cleaner energy, clean fuels and carbon markets. This globally significant capacity is another tangible example of Santos leading the way and establishing the foundations to support the energy transition. 2021 brought global energy security into the spotlight with higher prices and a supply crunch in the wake of rapidly recovering demand and a lack of investment in new supply. Oil demand is expected to reach pre-COVID levels this year. Investment in new low emission supply projects are needed to ensure reliable and affordable supply during the energy transition. Our Dorado and Pikka projects fell into this category with low emissions intensity. But target of these projects ready for FID by the middle of this year. LNG demand is also at record levels with underinvestment driving significant price increases, as we have seen in Europe, and limiting access to energy for those who can least afford it. It is vitally important that investment in new supply occurs in a sustainable way in order to ensure adjust and fair transition. At Santos, we are focused on supplying critical fuels more sustainably to meet society's demand. Our Moomba CCS project, which will be one of the biggest in the world paves the way for a significant carbon reduction and storage story for Santos and for Australia. We are also exploring a potential multi hub CCS strategy across our operating footprint. Decarbonizing natural gas supports the long term supply of reliable and affordable energy as well as the production of clean fuels, including hydrogen and ammonia. As the head of the International Energy Agency has said, reaching net zero goals without CCS will be almost impossible. I said earlier, the merger has delivered a stronger portfolio of long life, low cost assets with significant growth potential and has also delivered high working interests and some assets and development projects. Therefore, this year we will seek to further optimize the portfolio, reducing gearing and future CapEx and conduct a review of the Capital Management Framework including returns to shareholders. This will ensure we are in the best positioned to provide returns for shareholders, reduce debt, invest in growth and invest in the energy transition. Santos has a proven track record in delivering integration synergies from acquisitions. The Quadrant and ConocoPhillips acquisitions delivered over $160 million in synergies from areas like duplicated overhead and corporate costs and OpEx and CapEx savings through applying a low cost operating model. For the oil search measure, we're using the same playbook. I am pleased with how our team has hit the ground running and is delivering some early wins with around $30 million in synergies captured already. We're on track for a target of between $90 million and $150 million in annual synergies. In summary, as I said at the outset, I'm very pleased to present a record set of financial results. We have been and remained unrelenting and sticking to our strategy and implementing a disciplined low cost operating model, an operating model that has proven its value by delivering consistent results, keeping the business resilient and performing strongly. We continue to generate strong free cash flows, maintain the strength of our balance sheet and provide dividends to our shareholders. With that brief opening, we would now be happy to take your questions. Thank you for listening.

[Operator Instructions] Your first question comes from Daniel Levy from Citi.

Hi, guys, thanks for taking my questions. So you've had a greater than 100% reserves replacement at GE LNG for a couple of years now. Can you give me any more detail on what field that increase came from last year? And then maybe some insights on whether that reserves growth can continue this year?

Okay, thank you, Dan. Look, it is very pleasing. And that's really a case of more than just one field. This year, it was predominantly Fairview, a little bit in Roma and Ross and Mason the other the other sort of fields but predominantly Fairview and a bit and Roma. Look, ultimately what we're seeing over time is better field performance than maybe we had assumed earlier on, Arcadia, of course, has been very pleasing. And we recently FID the KDF Phase 2, which I think we start to see the first wells coming on the second half of this year. And so right across the fields, we're seeing improved performance over our early remodeling, of course, the well costs coming down some bigger wells being drilled horizontal wells, et cetera. And some of the calls have ever been very successful. And so look, it's pleasing. We're not going to predict what that looks like in the future. But it's a good trend that we're starting to see develop across the GLNG asset.

Yes, it's great to see. Okay, so just staying on GLNG, given you guys are producing below nameplate capacity and your neighbors are basically at capacity. Is there any scope for tolling gas from your neighbors to capture some of that elevated spot pricing at the moment?

Look, we've talked about this before, of course, and we've had a few initiatives over the years, we're looking at opening up the access to the plant, we continue to have those discussions with our joint venture partners. I think I said last year that they'd sort of taken a backseat as we were dealing with COVID in 2020 in 2021. But yes, and the ongoing conversations and discussions with the joint venture partners to open up that access to bring more gas through.

Excellent. I'll sneak one more in just quickly. So the Beetaloo results are a little bit disappointing. At least that's what I was expecting, any insights there on what happened on those wells and what the plan is going forward?

Look, testing program on these wells is over a 12-month period. So the long extended well tests I think you're reacting to the announcement by our joint venture partners, the wells haven't cleaned up yet. And so the wells has still got a lot of the completion fluids and frack fluids and those wellbores. And it takes time for those to clean up on these long extended well tests. And I think it's still early days, we're still -- we know there's a lot of gas here. We're still optimistic that we're going to see some improved flurries as these wells clean up. Basically, we're going to get all the fluids over the wells, what we expect at the end of the rainy season. So we're constrained operationally right now, as it will go run tubing now help clean the wells up, and then we'll see what we've got. I think it's too early to call, Dan.

Your next question comes from Tom Allen from UBS.

Good morning, Kevin, Anthony, the team, just regarding to $2 billion to $3 billion of proceeds from asset sell down that are targeted at ‘22. Could you please break out what proportion of which assets are implied in that target range? And also if there's any implied CapEx carry?

You've to explain what you mean by the implied CapEx, but let me just talk about if the sell down process. First of all, look, there's a number of assets that we've got very high equity levels and there was a lot of options across the portfolio and terms of where we raised our revenue from but ultimately, we're very heavy in PNG, we are heavy in Alaska. And of course, we're still quite heavy in Dorado, 80% equity in Dorado. So, look, I'm not going to give a specific target range for each individual asset because we'll wait and see what offers we get. And ultimately, if we sell down more or less than one asset, we may not have to sell down as much in another and we've got a lot of options and that I want to use that to provide a bit of price tension as well through that process. So we're not going to be specific in terms of how much equity in any one asset, we'll see how that plays out. We'll see what levels of interest we get to our sales processes. We'll keep you informed as and when we've got something to announce on that.

Thanks Kevin. You mentioned PNG, Alaska and Dorado. The one there that you didn't mention was the midstream business. So there's still potentially a plan to reduce your exposure. They have already sell down.

Well, Look, I'm glad you asked that, because I'm sure someone else would if you did, and but we always say that our intent was to set up the midstream business to give us the optionality to do that. But it's not -- it wasn't with the express intent to sell down midstream. If the right offer comes, that's something we'd always consider across any of our midstream assets. We're not completed that journey of separating all the assets into standalone joint ventures, we've got most of the assets, most of our midstream assets in that position now, but we've still got some work to do in one or two, we're not quite there yet. If and when those offers come and they do come continually, we will evaluate them. And if it makes sense for us, we'll consider it, if not, the key was to separate them out and run them separately. And we've now been doing that for about 18 months running our midstream separately. And our midstream business is a business is focused on developing new revenue streams like CCS and clean fuels in the future. And so it's not about separating but the intent to sell. It gives us the option to sell if we want to, but it's really about running them for value.

Yes, that makes sense. Thanks Kevin. Just quickly the last one you noted that Barossa is 25% complete and on budget. I think there's a comment there you weren't -- we're not experiencing any material cost push inflationary pressures, can you just refresh that under the various lease or EPC arrangements? What indicative proportion of the CapEx as fixed or floating exposure just obviously some increasing input prices and labor rates.

Look, I think the way they think about the CapEx profile for Barossa is that around 80% of it is fixed. And if you think of it through that lens, the real variable cost part of it as the drilling as you'd imagine, pipelines or factory contracts the SBS source factory contract. And so, overall about 80% of the projects on fixed price contracts.

Your next question comes from James Redfern from Bank of America.

Hi, Kevin and Anthey, be well, one of the reasons for the US energy sector substantially outperform the sector last year is their focus on increasing free cash flow and shareholder returns. Some interesting comments regarding increasing share returns for Santos investors, particularly once gearing is below 25% with the sale proceeds. Can you please discuss whether this will involve changing channels as dividend policy or special dividends or share buybacks? And I've got one more. Thank you.

Well, James, if I could, if I was going to answer that question, today, I would have completed the review, because that you picked all the sorts of things we're looking at in that review, right. And so step one is to reset the balance sheet we're going to do that, actually through three means one is generating significant cash flows from the operating business, you can see the businesses very cash flow accretive right at this point in time, we are generating a lot of cash flows from our assets, and in this price environment, and whether our continued low free cash flow breakeven. But obviously, it will be our target to raise between US $2 billion and US $3 billion from sales proceeds by selling down some of the portfolio, we do that. And that allows us to then reset our balance sheet or gearing metric with a cap at 25% on gearing, you'll recall that our operating model parameters were communicated previously at a cap at 35% during growth, right. And so what we're saying is that right now, we're thinking that will move back down by 10% to 25%, even during growth phases, and then as a consequence of that, what does that mean in terms of what we do going forward in terms of dividends, and the old capital management framework. The details of that though, I think we'll wait until we've done that review. And I'd read that with a board. But needless to say, it's with an intent of trying to increase returns to shareholders through the cycle. That's why we're doing the review.

Perfect. Thanks Kevin. And just one more quick one, please, I'm just wondering if in light of the higher oil price environment, whether your view has changed around the Pikka unit, in terms of, I guess, maybe retaining a stake in that project, rather than complete divestment, just given the higher oil price environment that we're seeing now and the outlook. Thanks.

Well, as oil shares run their own process for the sale down of Pikka. And that had its challenges during 2020 and 2021. We refreshed that process. And so we were just kicking that off now. Along with the other assets that we're looking at, the bottom line is that the price of oil won't change my view and whether we should hold an asset or not, because prices go down just as they go up. And so it's really about the value, our long-term planning prices that will determine what we think is good to be in a portfolio or not, not any short term or even medium term. Although I do think structurally, we're looking at a period here of extended oil prices, but we won't fall in love with oil prices. To the extent that we'll start making different or bad investment decisions or consequence, our focus is very much on cost of supply, maintaining a low cost of supply and driving that free cash flow breakeven price as low as we can and maintaining that, so that when we get these periods of high prices, we can maximize the benefits of them, we can maximize the cash flows that come from the portfolio and in terms of the projects themselves. I mean, I think we just have to wait and see where we are when we get to those points in time when we're ready to make decisions. I mean, ultimately, we'll clarify today that we're focused on getting these projects Dorado and Pikka to FID ready state. And then we'll allow you what we do at that point in time, based on a number of considerations, including the micro environment.

Your next question comes from Dale Koenders from Barrenjoey.

Good morning, just a couple of questions. Firstly, on the $2 billion, $3 billion asset sale range, Kevin can you provide some color is effectively like a risk to adjust number, just thinking about the independent expert report, estimating a $3 billion fair for PNG LNG doesn't leave a lot of room for the other assets.

Well, no, look, I wouldn't mistake, the range we have given with any valuations on assets or anything like that. I mean, this is basically just us saying that we want to strengthen the balance sheet by raising between$2 billion and $3 billion. And it can be any combination of asset sales that gets us there. But ultimately we think that's the right amount of proceeds, a right range of proceeds that we want to raise to reset our balance sheet, it was more reverse engineered from what we want to do with our balance sheet going forward and give us the foundation for a different Capital Management Framework and as opposed to thinking about the valuations of individual assets.

That’s clear, thank you. The coming around FID that you're ready for Alaska and Dorado and the various turns of subject to be one of them, is sell down to these. –

Sorry, you broke up at the end, Dale, could just repeat the last one?

Sure. Is one of the conditions for FID sell down of interest in these assets before they move forward to?

And, look, we've not made any conditions around any of the assets, whether it be FID or anything else for that matter. We're going into the sales process, and dependent on that our teams are working to get the project's FID ready. And as I said earlier, FID decisions on projects. We will take those decisions at the time when the projects are ready to take those decisions. And we will consider all of the factors that need to because at that point in time, and that will include how we've got on with a sell down processes, the equity levels, it will include the balance sheet strength, it will include the microenvironment and the cash generation that we've been able to generate during that period. So we'll take all of those things, any consideration when it gets to the point we're ready to take FID, as you know the world is dynamic. And I don't want any sort of state conditions when I'm going into sales processes that end up limiting us further down the line.

Sure. And then just finally, production guidance. Santos lost [Indiscernible] the mmboe, oil search was about 30 mmboe, you've caught out Darwin LNG in deadlock between two steps down by 10 mmboe, only gets to the top end of the guidance range of 100 to 110. If the production is flat, I'm just wondering, should we be thinking you hit the top end of guidance or the downside risk to other assets to get towards the middle? Or the bottom end of that?

Yes, well, look, I mean, we have really separated our assets into two buckets, right. So you've got your core asset portfolio, which gives us a range and every year we give you a range on that and when we risk that range deal, we will look at things going wrong, we look at things like weather impacts your operations, whether that be cyclones offshore, whether that be floods through the center of Australia, or whatever we look at operational reliability and risks across when we do these field rescues. And that's why we come up with a normal range. This year, of course, we've got the added confusion, if you want to call it that, of having a declining asset lately of asset, which has a much greater range of uncertainty on it. And so with buy one and this year, of course, our midpoint that we're giving us is 10 million boe lower than what we produced last year. And there's three real reasons for driving that. The first one had remained everyone over is that we sold 25% of it to SK last year. And as I'm not sure everybody was sort of remembering that when they saw that guidance, but we sold 25% to SK, there's a lower gross production because of natural fuel decline and coming to the end of field life. And that's a rest number that we give you because of course, you're never 100% sure how fuel will decline at the end when the water comes, it's performing very well right now. And I would add to that to that last year, of course, we got the benefit of higher production on Bayu-Undan because of the inflow wells that were drilled in, we got really good results and those not boosted production over the previous year. And of course, that worked out well for us with the JKM pricing spike. And that was a very successful program that has the potential to extend the fuel late by a few months, but we don't know, it’s sort of rush decision we've taken on that. And so you've really got to think of that declining through the year towards the end of the year. And we're still seeing, as I've always said that we expect field life here to be around the end of 2022. And then of course, the third thing is lower net entitlements who have taken a position on pricing this year that the prices will be higher than in previous years. And the consequence of that is that reduces your net entitlement. But I would remind everybody, that's not a bad thing. That's because at lower prices, you get more bottles, and the government takes less, at higher prices, you get lot less bottles allocated because you get the higher prices, and you get more revenue. And of course, the government takes a bit more of that as well as part of the rest sharing and profit sharing agreement. But we're only doing that because we're getting higher revenue streams, there is a net higher revenue stream outcome for Santos.

And sorry, just in terms of the rest of the portfolio, is it flat production outlook then?

Yes, relatively, so in terms of a core assets whether that be WA it’s relatively flat, PNG is relatively flat, Cooper Basin, we are hoping for a bit of a name clean this year, because we're ramping the drilling back up at the Cooper over the last two years, during COVID. You saw those well numbers in the pack, you'll see the well numbers came down quite significantly. We're ramping up to around about 100 wells this year. So we should see that start to bottom out and turn around again, like we did a few years prior to that. And of course by Bayu-Undan we’ve just talked about. So yes, I would say that relatively flat, I mean, the only assets that you'd see any natural decline and that we'd expect not to decline in this year would be the oil assets in the West, which is Pyrenee which is a non-operative asset, and of course Van Gogh and that's just as per plan. The gas assets are all relatively flat.

Your next question comes from Mark Wiseman from Macquarie.

Yes, hi, Kevin, Anthey, thanks for the update today, and congratulations on getting a lot of search done. So that'll go down as one of the great deals in the region. I just wanted to ask you a little bit further to one of the previous questions about GLNG supply cargoes, I mean at face value, this is a spread that's opened up between spot gas prices well at below and the spot prices offshore. I just wanted to get a little bit more color on your comments that you're speaking to your JV partners is that specifically the GLNG partners as to whether you want to ramp up export?

Well, look, it's more about with GLNG, the conversations has really always been about open access so that we can tow Santos gas or third party gas through the facilities and take advantage of the fact that we've [Indiscernible] and hopefully that would help encourage the development of more resources on these costs. If we can even if they've got a domestic gas obligation associated with them, just because of the scale benefits of being able to get some export volumes. That's been an ongoing conversation for some time now. So that's what that was about. It's not really about spot cargoes and taking advantage of the eminent situation. We don't sell many spots from GLNG. Typically, we sell the old one, for operational reasons only. All of the volumes are contracted, and are sold under contracts. And under solid contracts that are sold under contract. Our main JKM exposure for Santos is the Bayu-Undan project, and it's in late phase where the majority of the cargoes are sold on JKM. And of course, we've got JKM exposure for Barossa in the future.

Okay, great. Could I just follow up, could you not take some gas out of your storage facilities in the [Indiscernible]? Or buy some gas from other producers in the spot market to export those into spot? Is there something preventing you from doing that right now?

Well, what would be preventing us from doing that right now as we are doing a half a lot in storage these days, Mark, we don't hold much gas, because the demand is so strong, right. And I think if we were storing gas today for the domestic markets, we probably get accused of managing the market. And we don't do that. So we have very little in storage, we only really put gas in storage these days for operational reasons when something down. And so we're not using storage like we did when we had access volumes in the past, we don't really have access volumes today.

Okay. That's very clear. And could I just ask on Narrabri East Coast market clearly needs supply and Narrabri is one of the sizable solutions. Could you maybe just give an update on the appraisal program and the extent of those activities?

Well, look, good question, you'll have seen that we successfully navigated the most recent legal challenge, as we have with all the other legal challenges over the years. And so now that's a final hurdle. So we're now cleared to get on and start that appraisal and look to ramp up some of that's in the budget this year. So we've been looking at ramp up Narrabri appraisal activities during the year. And so the team, the onshore team are working on their plans right now. Because really, we didn't want to commit any CapEx to those operations until we knew a clear pathway in front of us. My view on these things is we shouldn't be spending CapEx unless we've got a line of sight to development. And we know how that so we'll go forward and do that appraisal, and finalize our project design. And I expect that to be over the next 24 months or so, before we'd be close to being a final investment decision.

Okay, great. And just a final question, if I can. This one's probably for Anthey, just on the franking status of the dividends. Could you just give us a bit more color on the tax losses? How much of that's coming from oil search versus immediate deductibility rules? And how long are those tax losses going to last?

Thanks for that, Mark. Anthey, celebrating here. She got a question. So a hand over to you. Go, Anthony, help yourself?

And I got a question on tax which is awesome, thank you. So from a banking perspective, there's no losses from Australian company tax that came across them all search. So these are Santos losses that are carried forward and they're set out in our account. I think, I give you the page number but so that there clearly certain accounts is carried for tax losses. And that number is $860 million. It comprises predominantly Australian tax losses. There is some PNG from the point of view of when we start to generate franking credits. Again, it's dependent on a lot of factors. So it's very hard to predict. Oil price is one, mix of revenue is another, activities and other. So it really depends on what we do in the interim period to give you a line of sight on when we start to generate franking credits, but it will be when we start paying Australian tax.

Okay, that's clear. And just the conduit at foreign income will apply through this whole period for offshore investors.

Sorry, can you just repeat that?

In terms of offshore investors having to pay withholding tax? I think you mentioned on the video that they would not need to do that for this final dividend. Is that going to be the status for the next year or two?

Sure. So we have a conduit for an income balance, which is effectively foreign income earned that we can pass back out of Australia free of withholding tax on the front portion. And we expect that to remain for the next several years.

Next question comes from Adam Martin from Morgan Stanley.

Hi, Kevin, Anthey, just a question on sort of investor feedback or your thoughts, I suppose on selling some of the PNG LNG for free cash asset, productivity attractiveness so maybe divesting some of the last Dorado, but just give us your thoughts around PNG LNG, please.

Well, look, I mean, we look at all of these assets, not just as to what they're doing today, but for the longer term. And it's really around your risk profile for the longer term, whether that be CapEx exposures in the future, whether it be a single asset or country risk level that you take on any individual asset, and/ or other factors as well. And look, we take all of those things into consideration when we're thinking about sell down, we also take the strategies, and the development plans for each of those assets and to place and so in the case of PNG, is a very attractive asset, as I'm sure you can imagine, I mean, since announcing that, you can imagine we've already had some interest in that asset but we are at 42.5%. So that doesn't just mean we get 42.5 5% of all of the sort of revenue streams coming out of that asset. It also means we get 42.5% of all the future CapEx exposures for that project as well. But look, I mean, we take all of those factors into consideration, Adam, when we're making these decisions. And let's wait and see what that ends up looking like again, I'm not going to give specific asset targets, when we're looking at raise that $2.3 billion, as you could probably imagine, it raise, you kind of raise that quite easily PNG LNG, but I don't expect that will necessarily be the case. But as I was saying it's more than just financial, it is also strategic. And if you think of some of the strategic rationale for doing that, better project alignment, and if you get certain sales outcomes can be very beneficial to the future expansion of that project also.

Yes, make sense. And just a quick one on restoration CapEx at the top. So the $300 million, $200 million or so how should we sort of think about go for these’ 23, ’24, ‘25? Is this sort of new numbers, is this a bit of a high yield to sort of think about that going forward please?

Look, that's a good question. I think there's -- when it comes to CapEx just three numbers, we want to be very transparent on every year to you guys to the market that is our sustaining CapEx, which, of course, I'll emphasize, again, is self-funded within that free cash flow breakeven number that we talked about. So in other words, when we say we're going to be less than US $25 that includes the $1.1 billion of sustaining CapEx self-funded. And then the other two CapEx numbers that we, it also includes the restoration CapEx I should have said that, so that includes the $200 million you're talking about. And what it doesn't include, of course, is then the third bucket, which is the growth CapEx. And so we want to be transparent on reporting those three buckets every year. My expectation over the next several years, is that you can expect our restoration and decommissioning CapEx to be in the range of around US $200 million each year, may be slightly above or slightly below that. But that's not a bad gate to be thinking about as a gate over the next few years that we'd be spending around $200 million each year. And in fact, and in recent years, we've been spending money on restoration across all of the assets. And we spent, I think around the $20 million mark each year in the Cooper Basin, decommissioning all flowing and all wells on an ongoing basis just to manage those liabilities over the longer term.

The next question comes from Mark Samter from MST.

Yes, good morning, guys. A couple of questions, if I can. Kevin just first one on Bayu-Undan and it seems like people continue to struggle so they understand the PSE. But these tend to be the best production and it come down that you can ever have and I think lost over $3 million, just because of high prices or were due for higher revenue. Can you give us any feel for what gross production declines are expected to be within the forecast?

Yes, well, look, I mean, what we're looking at this year, Mark, is from a growth point of view, around 10 million boes, from our share that sorry, is 10 million boes. And that's made up of those different things I was talking about earlier, if you ramped that up, and you want the gross number, it'd be about 70 million boes, right. And that's just basically due to natural field decline. Yes, 70 million boes.

Thank you. Just quick question on the infrastructure, there -- the possibility of doing something when the production has been out in for a while now. And I guess it's a bit less clear to me exactly what the internal thinking is on the seller partial stake and other things, personal IPOs, and things like that. But I'm interested and thinking about the division reporters, infrastructure. And we're thinking again on the GLNG infrastructure of the potential.

Yes, look, I mean, I think that, looks a good question. Thank you for that. The bottom line is, we've said that we want to set our assets up so that we have our midstream assets running separately, and under separate joint venture structures, so that we can, a, we can run them for value, we can execute midstream strategies, and develop new businesses off the back of, like hydrogen assets like CCS opportunities in the future. Well, that doesn't make sense, of course, and then those midstream assets, then really, the only benefit you get from doing that is to give you the ability to sell down some of that infrastructure structure stake and take some of that capital off the table. And so all of those things are options for us. It's not a priority to sell them. But of course, you saw some deals being done last year, and some of them were very interesting from a valuation perspective. But of course, you lock in the OpEx, if you do that, right, you're locking the higher OpEx. So, look, all of those things are under consideration. I mean, the strategy was not to do it with the intent of selling their infrastructure to the market. And I want to emphasize that we weren't setting these midstream markets up so that we could sell them or sell down in them, or we were setting them up so it gave us the option to do that. But more importantly, give us ability to run them separately from the upstream to open up to third party. And that's why those conversations about third party access are really important in terms of how you build value around any of those assets that have value. And of course to give us the flexibility to be able to drive on with other business opportunities or green fuels and our de-carbonization projects.

Perfect, thanks for that. If I take just one quick, more questions. I'm just going to ask a silly question on sell down that you're not going to tell us about, but I'm getting curious about where Dorado where there might be useful information and knowing where you get oversold and processes how you think about Dorado I think you mentioned, your decision might be influenced on either sale downs, but you obviously can't entirely control the timing of other sell downs. Does it feel quite sensible to potentially FID to either 80% and then make that decision with full information either, I guess what I'm asking is that other sell down don't need to be a condition precedent for the FID of Dorado.

Yes, look, that's a great question. And the answer is you're correct. They don't have to be a condition precedent for the FID on Dorado, there are other factors in there, right? I mean, I'll give you an example. If you look at our free cash flow generated in 2021, that alone paid for the entire Dorado project at100% equity on top of the $2.3 billion, right so if you're talking about project, there's around $2 billion in CapEx that would more than 50 cash flow that was generated between the two businesses last year with more than pay for that entire project. I'm not suggesting for a minute that's a justification to go forward in 80%. But the point is that based on the cash we are generating to do today, every single day from these assets, we take all that into consideration at that point in time as well, just where we are in terms of balance sheet that ultimately Dorado was 80%. It's a very high equity stake. We're currently drilling the 8% wells, and an important consideration as a result of those wells. And why is that important is not going to significantly change the design of the facilities? No, I don't think but whether there's gas or oil that comes in and those assets can considerably change the value of those assets going forward. And we have longer-term aspirations for phase two of the Bayu-Undan basin development, which includes bringing gas back into our West Australian gas assets as backfill from around 20-30-ish onwards, and given the long term backfill strategy for those assets. So, look, all of that as part of our thinking, but we really need to wait till we drill these two wells and see what interest we get in the sales process. And being frank, I think I've said many people before we run a sale process last year, we suspended that because we were on the oil search a transaction at that point in time. And because we couldn't see any late line of safe to any value we're going to get for the wells, we're about to drill. So we're as well drilling them to see if they're going -- we're going to get value for them or not. And then we can revisit the sales process.

Your next question comes from Mark [Picitol] from JP Morgan.

Good afternoon, everyone. Just, again, just sticking to the asset sale side of it. I get the sense from your commentary on this call that sort of $2 billion to $3 billion is kind of the goal set that you want for the balance sheet. So if you were to generate greater free cash flow than you expected, if you were to get a good offer for infrastructure assets, would you then start revising what you are thinking about asset sales around these assets that you're having an interest in or is it more that you're looking at de-risking the projects as the -- as how you come to the $2 billion to $3 billion in value?

Yes, look, Mike, thanks for that. Look, at the end of the day, it's a combination of all of those things that you just mentioned, right? So we want to strengthen the balance sheet, as I said, by reducing, I guess we're just getting at this point time by something like $2 billion to $3 billion, right impact on the balance sheet. And how you get or gives what percentage of which asset doesn't really matter, other than it's also about smoothing out your CapEx profile in the years ahead. And so when we look at the next sort of five year journey, and we're building stuff is think about what level we want that annual growth CapEx spend to be at. And so the sales don't process as both straighten the balance sheet and are managing our future CapEx exposures. So we've got a more steady state environment that we can plan around.

Okay. In terms of PNG LNG, you are now the largest, you've got the largest interest there. I mean, is it your intention to remain the largest holder of that asset, even though you don't operate it? Or have there already been discussions with joint venture partners about potential unitizing interest across the two projects to make it sort of even across both?

Well, we've had the keys for about seven weeks or so we haven't had a lot of conversations about unitizing, the joint venture or anything like that yet, Mark. And not that we're driving to do anything like that, anyway. But what I would say is that and it's very important being the biggest, as in something, I'm particularly driven by any joint venture or any project where we operate, we want to retain an operating control. Because we believe we've got a very solid operating model, we can drive cost synergies, and we can create value for our Santos joint venture partners, we're very focused on being a good joint venture partner, a partner of choice who delivers value, good value outcomes for all of our partners. And we're not the operator. We don't want to be a partner that sits here blocking everything because we can have a pray over the operator just because I wouldn't maintain a state just for that without any real strategic rationale for doing so. So there's no driver here to be bigger than x one in terms of a state in PNG LNG, we got a view on the range of equity, we'd be willing to sell down but by the same token, it's a very good asset, so I don't want to sell too much of it. And so it's a balancing act. We're not going to sell too much of PNG LNG because we think it's one of the best LNG projects on the planet with a lot of upside potential.

And just shifting tack to slightly down LNG, you've talked about Bayu-Undan and sort of saving production by the end of the calendar year. Can you sort of walk us through Darwin LNG in terms of plant utilization until the commencement of Barossa? I mean, how long do you think that plant is going to be idle for?

Well, yes, so if you assume that Bayu-Undan and sort of ends at the end of this year, if you just take that as your starting point, we're looking at Barossa coming online in the first half of 2025. That's the guidance we've given previously. And nothing's changed from that. We lost a year you'll recall, in 2020, when we suspended FID, we put it back when COVID hit the markets and there was a lot of uncertainty around shipyard availability and things like that. And we decided, conical we're still, we operate at time but we decided as a joint venture, not to take FID at that point in time. And we pushed it back. And fortunately, we're able to just over a year, reset the project, re-contract where we had to, and take FID in May2021. So, yes, the guidance is first half of 2025. And we're on track to do that.

Your next question comes from Saul Kavonic from Crédit Suisse.

Thanks Kevin. Thanks, Anthey, three quite quick questions. My first one is just regarding could you give us a bit more color again on that sustaining base business CapEx? You've got it the $1.1 billion this year, including the OpEx according to the old oil surge kind of projections $200 million of that is oil search for next couple of years, should we be expecting basically about $1.1 billion of base business CapEx including OpEx for the next few years?

I think that's a good gauge. I think the $200 million is a good gauge. So going forward, we probably said versus around the $900 million, Mark. And if you add the $200 million then you have $1.1 billion, good gauge.

Thanks. Second quick question is just on Alaska. You mentioned how it's a low breakeven project in the presentation. Are you able to confirm, is it essential to view that the breakeven is below $40 is oil search guided? Or has the view changed on exactly how competitive this project is?

Yes, look, I mean, as a very competitive project, and as a low fee, cash flow breakeven. The guidance and oil sets gave was less than $40. We have no reason to change that, at that point in time, our reviews of that project are in line with that. We're currently going through a review process for Santos going through the FID readiness review process that we have and house. And so what we will do when we get that to the point where we're ready to update the market, prior to FID we will restate the economics as we normally do with that decision, but there's no reason to think it's any different, Saul.

Thanks. And just last one back on the Beetaloo well results. You mentioned still looking to clean up those flow tests and watch for the next 12 months and events actually, we don't see a big pick up over that next level or the rest of the year. Is there going to be appetite to throw more money at new wells next year in the Beetaloo?

Well, look, our CapEx guidance is we're not going to change that, we're not going to add any new CapEx to that. In terms of future programs, look, I'd rather wait until we evaluate the well results. And we'll know what we have. And we'll take it from there. So I mean, I think where these things are, it's very dangerous to be putting too many updates. So until you clean them up, and you see what the wells are actually going to flow out. And I'd rather wait until my technical guys who are much more qualified than I am, tell me if it's a good result or a bad result. And so I'll withhold my judgment on that until I see the results later in the year.

Your next question comes from Nik Burns from Jarden Australia.

Thanks, Kevin and Anthey, just another question of relation to Alaska. You mentioned the sale processes kicking off there. Can I ask if operatorship is being offered as part of this process? And the reason I ask is that I expect the sale process will likely take a few months to complete and that you're bringing in a new operator, but likely want to undertake a full scale review, it might also changes potentially to the proposed development plans, which could potentially kick FID back to late this year, even 2023. Is that a possibility here?

Well, look, what I've learned rather not to, Nik, is speculate on any of these sort of different bets and different conditions have different bets or different options that we may consider. What we've said is that we're going into an asset sell down process. And we'll wait and see what comes from that, we'll keep you updated if and when we get offers or accept offers on those things. But these sell down approaches can be very complex. As we've seen in the past, we've been very successful in selling down assets when we're wanting to do that over the last four or five years when we're going to do that. But sometimes, even though we can get to an agreement, to sell down something very quickly, it can still take a year or more to complete some of these deals. And so you've got to take all of that into consideration as well, quite often you've got cross border approvals are required, and it can just prolong the completion of any sell downs. And so I'd rather not speculate on further that will or will not involve operatorship, or anything like that. And the meantime, what we've said is we're focusing on progressing the project, the best way to build value in the project is to progress it to get FID ready, and have a real project value.

Got it. That's clear. Just a question on Barossa and Bayu-Undan CCS some six months ago, I think we talked about the need to progress, the proposed Bayu-Undan CCS project, as it has implications for your plan for Barossa LNG in terms of co2 removal facilities, the pipeline, et cetera. Can you talk about where you're at in relation to talking to relevant stakeholders around this? Thanks.

Yes, look, I mean, obviously, this was a post FID initiative led by Santos, we want to develop a CCS Bayu-Undan. And it's for more than just Barossa. So let's be clear, we would not be developing Bayu-Undan CCS project just for Barossa. This is Bayu-Undan CCS project, it is not a Barossa CCS project, and Barossa is an approved project. It's under construction. It's 25% complete, and it's on the way. And that project design does involve cutting into the original pipeline, you're correct. So if we go with Bayu-Undan CCS project, it will involve an alternative arrangement, they're either tied back in with a co2 pipeline to the current Bayu-Undan pipeline, or alternatively, twinning the pipeline to Darwin, and both options are under consideration. We're in discussion with the joint venture partners, there's a lot of enthusiasm about the project, because as the capacity to take up to 10 million tons per annum, it would be the largest CCS project globally, at this point in time, and that will allow other projects in the region, other businesses in the region to sequence their co2 emissions. So we see a big prize if we can get it up. Work has continued, the engineering work is continued. And if we can get partner Lehman on it over the course of the next few months, I would hope to take feet on that project sometime in 2022.

That's great. Just one really quick one. For some growth LNG sanction in March, I believe there was a $200 million FID payment trigger to Conoco. Can I just check to see whether that has been paid? Thank you.

Thanks for that, Nik. Look, that's subject to confidential process we're in with Conoco at this point in time. It has not but I can't comment as under -- that's a confidential process we're in with Conoco. We're in discussions and I would hope that will come to a resolution sometime in the near future.

So can I take it that the -- your breakeven oil price guidance for 2022 excludes that payment or does it include that payment?

It excludes it.

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

Thank you very much. The pool of LNG, obviously, you're progressing with FID there I just wanted to ask and probably a bit early oil search had previously stated they wanted to lock in their equity LNG sales volumes prior to FID and just wanted to see if channels had a slightly different view from them.

As you spoke, Papua, Gordon, right?

Yes, Papua.

Yes. Look, I mean my view is I would like to lock in a portion of them before we FID that project. That's correct. That is typically been a review on other projects like Barossa, that would want to have offtake agreements in place. And I wouldn't see any reason to think differently on Papua.

And type of pricing JCC verse JKM, considering is on JKM contract that were awesome.

Yes, look, I mean, I wouldn't want to give any guidance or not at this point in time. I think it's too early Gordon to give guidance, other than to say that we would look for a balanced approach to our portfolio. As to not all too, not all in the one sort of pricing structure. But yes, we look to balance risk across a portfolio by having a blend.

Are you also able to confirm if this Chinese interest in offtake, specifically from Sinopec?

I'd rather not make any comment on who we may or may not be talking to.

Okay, just last one for me just on unit production costs. They're going up. And one of the reasons obviously is the Bayu-Undan decline. But you've also mentioned PNG, the oil production assets, their costs on a unit basis are a bit higher. If we look on a percentage basis, how much of it is driven by Bayu-Undan? So I'm just talking about going from 776 to 850 in 2022? How much of that on a percentage basis would be Bayu-Undan because you've actually given us $1.20? But it's not really you can correlate that across?

Yes, look, I have to circle back on your percentages to $1.20 is the way that I think about if it's, look, I mean in 2021 COVID added their own $0.20 per boe, FX I think just under $0.50 or $0.45 or so. And but what we're seeing is we expect some higher unit costs in 2022, as you see, rightly, to the PNG operated assets and of course, Bayu-Undan, the Bayu-Undan is quite a big driver to that but look it up to circle back in terms of percentages. I'm not sure I truly understand what you're asking there, Gordon, but yes.

I mean, I'll follow up with later.

The bottom line is, yes, the bottom line is I'd expect them to go back down again once Bayu-Undan owe the system. I'll get on to the follow up on that one with you at the end.

Your next question comes from Daniel Butcher from CLSA.

Hi, everyone. Really just one question from me just under new gearing target from 35% to 25%. Was sort of curious to get good bit of color on what's driving that is actually the S&P discussions, or was due to ESG issues and sort of being more conservative for the future around your capital structure. How much that interact with your country exposure in PNG? So the first part of my question.

All right, well, first of all, Dan, thank you for that question. And it's a great opportunity for me to see that it's got nothing to do with any of our rating agencies. It's got nothing to do with country exposure to PNG. So I'm really glad just a question so that I could clarify that. And now categorically make that point, it's purely to do with us thinking about how we want to reset the business, through this transitional period for oil and gas companies, we have undoubtedly seen a de-rating across the sector over the last couple of years, driven purely by ESG and transition focus. Now, I think some of that may be coming back and I suspect some of that will come back as we see a more balanced discussion around the need for gas particularly but even oil for quite some time to come and particularly and ensuring that we get a just and fair transition. And the poorest people in the world are not starved of energy to simply by staking supply. So during that period, we will look how we reset the company in order to provide larger returns to our shareholders and it's really just about setting the balance sheet to change that capital management structure and free up more cash to return to shareholders, either whether that be through higher dividends, or whether that be through share buybacks.

Okay, thank you. I guess the second part of the question is just when you're 27.5 and gearing now, aim for 25. You said you are breakeven, including all your growth project to the pre FID is 65. So we still suggest you're going to generate, even after all your growth, more than a $1 billion of free cash flow this year with oil near $90. So I'm sort of curious how -- why you need to sell down $2 billion or $3 billion of assets to get below 25% when you got too much free cash flow over and above ground?

Yes. Again, thanks, Dan. Good question, look, I think it's whether you look at this through a one year oil price range, or whether you look at this across the longer term. And we'll look at across the longer term, what I'm seeing is that we want to say getting at a maximum of 25% through the cycle. So not just for this year, but through the cycle. And that includes our CapEx spending to build a project include the funding of our clean use projects, the future hydrogen projects, or ammonia projects or whatever else that we're doing further down the line. So we're setting the business up, so we can fund those projects at a lower gearing ratio. And of course, deliver strong returns to shareholders while we're doing that.

There are no further questions at this time. I'll now hand back to Mr. Gallagher for closing remarks.

Well, look, again, I just like to thank everyone for your time this morning. And as summarized earlier on, we're very pleased with a very strong set of results. I think the pro forma numbers for the business with sales revenue of $6.2 billion, EBITDAX of $3.8 billion and free cash flow of over $2.3 billion and we had we also charges for the full year of 2021 shows that we now have a very, very different business to the one that we had before. I'm very excited about the future. And I'll look forward to discussing all of that in more detail with many of you over the course of the next week or two as we get ready to meet your one to one. So thank you again for your time. And we'll sign off for that. Thank you.

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