Santos Limited (STO) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Santos' 2021 Full Year Results Question-and-Answer Conference Call. [Operator Instructions] 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 the Q&A with both Kevin Gallagher and Anthea McKinnell, 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 morning, and welcome to the Santos Full Year Results question and answer. Joining me is CFO, Anthea McKinnell. Anthea 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 lands of the Kaurna people of the Adelaide Plains for where Anthea and I are speaking today. I pay my respect to the 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 our disciplined low-cost operating model. They are record results. The highest revenue, free cash flow and underlying profit in Santos' history. I would particularly call out record production volumes of 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 focus 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 3 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 oil price is above our free cash flow breakeven, the portfolio generates around USD 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, fund 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 USD 0.085 per share, a 70% increase on last year's final dividend. The dividend is franked to 70% and consistent with our 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 a 50% interest following the sell-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 the Papua LNG and Alaska projects. We also announced a booking of 100 million tonnes of CO2 storage resource in the Cooper Basin. This follows FID on the Moomba CCS project in November. We see CO2 storage as a strategic competitive advantage in evolving cleaner energy, clean fuels and carbon markets. This globally significant capacity is another tangible example of Santos leading the way in 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 fit into this category with low emissions intensity. We're targeting to have 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 a just 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 a 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 agencies have 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 interest in some assets and development projects. Therefore, this year, we will seek to further optimize the portfolio, producing gearing and future CapEx and conduct a review of the capital management framework including returns to shareholders. This will ensure we're in the best position 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 our low-cost operating model. For the Oil Search merger, we're using the same playbook. I am pleased with how our team has had the ground running and is delivering some early wins with around $30 million in synergies captured already. We're on track for our target of between $90 million and $115 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 remain unrelenting and sticking to our strategy and implementing our 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.

So you've had a great -- you've had a greater than 100% reserve replacement at GLNG 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 reserve growth can continue this year?

Okay. Thank you, Dan. Look, it's very pleasing. And it's really a case of more than just 1 field. This year, it was predominantly a Fairview, a little bit in Roma, and RUGS and Mace and the other so fields, but predominantly Fairview and a bit of 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-ed Arcadia Phase 2, which I think we start to see the first wells coming on second half of this year. And so right across the field, we're seeing improved performance over our early modeling. Of course, the well cost coming down, some bigger wells being drilled, horizontal wells, et cetera, and some of the calls, have 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 assets now.

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've sort of taken a backseat as we were dealing with COVID in 2020 and 2021. But yes, 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 were 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, our testing program in 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 frac fluids in 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 flow rates as these wells clean up. Basically, we've got 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 and run tubing, now will help us clean the wells up, and then we'll see what we've got. I think it's too early to call it down.

Your next question comes from Tom Allen from UBS.

Just regarding the $2 billion to $3 billion of proceeds from assets sell-down that are targeted over 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'll have to explain what you mean about the implied CapEx carry. But let me just talk about the sell-down process, first of all. Look, there's a number of assets that have got very high equity levels, and there's a lot of options across the portfolio in terms of where we raise that revenue from. But ultimately, we're very heavy in PNG. We're 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 in 1 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 1 asset. We'll see how that plays out. We'll see what levels of interest we get through our sales processes, and we'll keep you informed as and when we've got something to announce on that.

All right. You mentioned PNG, Alaska and Dorado. The one there that I noted that you didn't mention was the midstream business. Are there still potentially a plan to reduce your exposure there via sell-down?

Look, I'm glad you asked that because I'm sure someone else would have queued it, 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've not completed that journey of separating all the assets still it's stand-alone joint ventures. We've bought most of the assets, most of our midstream assets in that position now, but we've still got some work to do in 1 or 2. We're not quite there yet. If and when those offers come and they do come continually, we'll 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 probably 18 months running our midstream assets separately. And our midstream business is a business is focused on developing new revenue streams like CCS and clean fuels in the future. And it's not about separating what 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, Kevin. Just quickly the last one. You noted that Barossa is 25% complete on budget. I think that was a comment there we're not experiencing any material cost push inflation pressures. Can you just refresh that under the various lease or EPC arrangements? But what indicative proportion of the CapEx has fixed or floating exposure, just obviously some increasing input prices and labor rates.

Look, I think the way to think about the CapEx profile for Barossa is that around 80% of it is fixed, right? And if you think of it through that lens, the real variable cost part of it is the drilling as you'd imagine. And our pipelines are fixed rate contracts, the FPSO's fixed price contract and so overall, about 80% of the projects on fixed-price contracts.

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

One of the reasons for the U.S. energy sector substantially outperformed the Australian sector last year was the focus on increasing free cash flow and shareholder returns. Some interest in your comments regarding increasing shareholder returns for Santos investors, particularly once gearing is below 25% with the sale proceeds. Can you please discuss whether this will involve a change in Santos' dividend policy or special dividends or share buybacks? And I've got one more.

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 sort of things we're looking at in that review, right? And so step one is to reset the balance sheet, and we're going to do that actually through 3 means. One is generating significant cash flows from the operating business, you can see the business is very cash flow accretive at this point in time. We're generating a lot of cash flows from our assets in this price environment and with our continued low free cash flow breakeven. But obviously, we will see our target to raise between USD 2 billion and USD 3 billion from sales proceeds by selling down some of the portfolio. We do that, that allows us to then reset our balance sheet, our gearing metric with a cap of 25% on gearing. You'll recall that our operating model parameters we communicated previously at a cap at 35% during growth, right? So what we're saying is that right now, we're thinking that's -- we'll move that down by 10% to 25% even during growth phases. And then as a consequence all of that, what does that mean in terms of what we do going forward in terms of dividends and the whole capital management framework. The details of that, though, I think we'll wait until we've done that review, and I agreed that with the 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, 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 stake in that project rather than complete divestment just given the high oil price environment that we're seeing now in the outlook?

Well, as you know, Oil Search run their own process for the sell-down of Pikka and that had its challenges during 2020 and 2021. We've refreshed that process. And so we're 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 on 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 we determine what we think is good to be in our portfolio 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 as a consequence. Our focus is very much on cost of supply, maintaining a low cost of supply, driving that free cash flow breakeven price as low as we can in 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 on the portfolio. In terms of the projects themselves, I mean, I think we're just up 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 an FID-ready state, and then we'll evaluate what we do at that point in time based on a number of considerations, including the macro environment.

Your next question comes from Dale Koenders from Barrenjoey.

Just a couple of questions. Firstly, on the $2 billion, $3 billion asset sale range. Can Kevin provide some color? Is this effectively like a risk-adjusted number? Just thinking about the Independent Expert Report estimating a $3 billion sale 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, the guess is there. But ultimately, we think that's the right amount of proceeds -- the right range of proceeds that we want to raise to reset our balance sheet. So it's 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 as opposed to thinking about the valuations of individual assets.

That's clear. The comment around FID ready for Alaska and Dorado and the various terms it's subject to, one of them is sell-down, I mean, the [indiscernible]...

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

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

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. Independent of that, our teams are working to get the projects 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 be considered at that point in time. And that will include how we've got on with the sell-down processes, the equity levels include the balance sheet strength. It will include the macro environment, and the cash generation that we've been able to generate during that period. So we'll take all of those things into 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 to sort of state conditions when I'm going into sales processes that end up limiting us further down the line.

Sure. just finally, production guidance, Santos last year, you did about 90 mmboe Oil Search was about 30 mmboe. You've called out Darwin LNG and [indiscernible] between 2 steps down by 10 mmboe. But early on it gets the top end of the guidance range of 100 to 110 if other production is flat. I'm just wondering, should we be thinking you hit the top end of your guidance? Or is there downside risk to other assets to get towards the middle or the bottom end of that range?

Yes. Well, look, I mean, we have really separated our assets into 2 buckets, right? So you've got your kind of core asset portfolio, what gives us a range. And every year, we give you a range on that. And when we risk that range, Dale, we'll look at things going wrong. We'll look at things like weather impacting our operations, whether that be cyclones offshore, whether that be floods through the center of Australia or whatever, we look at operational reliability risks across when we do these full risk. 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, a late-life asset which has a much greater range of uncertainty on it. And so with Bayu-Undan this year, of course, our midpoint that we're giving you is 10 million boe lower than what we produced last year. And there's 3 real reasons for driving that. The first one that I'd remind everyone of is that we sold 25% of it to SK last year. And I'm not sure everybody was sort of remembering that when we saw in that guidance. But we sold 25% to SK. There's a lower gross production because of natural fuel decline in 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 our fuel will decline at the end when the water comes. It's performing very well right now. And I would add to that, too, that last year, of course, we got the benefit of higher production on Bayu-Undan because of the end fuel wells that we drilled, and we've got really good results in those not boosting 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 field life pipe by a few months, but we don't know if it's a risk decision we've taken on that. And so you're really going to think of that declining through the year towards the end of the year. And we're still seeing, as we've always said, that we expect end of field life here to be around the end of 2022. And then, of course, the third thing is a lower net entitlement. So we've taken a position on pricing this year, but the prices will be higher than in previous years, and the consequence of that is that, 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 barrels and the government takes less. At higher prices, you get a lot less barrels 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 risk sharing and profit sharing agreement. But we're only doing that because we're getting higher revenue streams. It's a net higher revenue stream outcome for Santos.

Just in terms of the rest of the portfolio, is it flat production outlook then?

Yes, relatively. So in terms of our core assets, whether that be WA, it's relatively flat. PNG is relatively flat. Cooper Basin, we're hoping for a bit of a name clean this year because we're ramping the drilling back up at the Cooper. Over the last 2 years, during COVID, you saw those well numbers that's 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, Bayu-Undan, we've just talked about. So yes, outside of that relatively flat. I mean the only assets that you'd see in a natural decline in that we'd expect natural decline in this year would be the oil assets in the West, which is Pyrenees, which is a nonoperated 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.

Congratulations on getting Oil Search done. So that will 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 spot cargoes. I mean at face value, there's a spread that's opened up between spot gas prices at Wallumbilla and the spot price is 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 exports?

Well, look, it's more about -- with GLNG, the conversation has really always been about open access so that we can to Santos gas or third-party gas through the facilities, and take advantage of the fact that we've got oil gen. And hopefully, that would help encourage the development of more resources on these coasts if we can -- even if they've got a domestic gas obligation associated with them. Just because of the scale benefits I've been 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 imminent situation. We don't sell many spots from GLNG. Typically, we sell the odd one for operational reasons only. All of the volumes are contracted and are sold under contracts and they're solid contracts that are sold under contracts. Our main JKM exposure for Santos is the Bayu-Undan project in its late-life 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. But could I just follow up, could you not take some gas out of your storage facilities in the Cooper or RUGS 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 is we don't have 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 is down. And so we're not using storage like we did when we had excess volumes in the past. We don't really have excess volumes today.

Okay. Okay. That's very clear. And could I just ask on Narrabri. East Coast market clearly needs supply and Narrabri 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 will 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 the final hurdle. So we're now clear to get on and start that appraisal. We look to ramp up some of that. Some of that's in the budget this year. So we'll be looking to ramp up our 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 we had 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 now have 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 is probably for Anthea. 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 is coming from Oil Search versus the immediate deductibility rules? And how long are those tax losses going to last?

Thanks for that, Mark. Anthea is celebrating here she got a question. So I'll hand over to her. You go ahead, Anthea.

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 some Oil Search. So these are Santos' losses that are carried forward and they're set out in our accounts. I think I'll give you the page number, but for that the previous account is carryforward tax losses. In that number, it's $860 million that comprises predominantly Australian tax losses, there is some PNG. From the point 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, activity is another. So it really depends on what we do in the interim period to give you line of sight on when we start to generate franking credits, but it will be when we start paying Australian tax.

Okay. Okay. That's clear. And just the conduit foreign income rule apply through this whole period for offshore investors?

Sorry, can you just replay 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 2?

That's right. So we have a conduit foreign income balance, which is effectively foreign income earned that we can pass back out of Australia free of withholding tax on the unfranked portion, and we expect that to remain for the next several years.

Your next question comes from Adam Martin from Morgan Stanley.

Just a question on sort of investor feedback or your thoughts, I suppose, on selling some of PNG, it's obviously best free cash asset sort of see the attraction that maybe divesting some of Alaska or Dorado. But just give us your thoughts around PNG LNG, please?

Well, look, I mean, we'll 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 a 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 think about sell-down. We also take the strategies and the development plans for each of those assets into place. And so in the case of PNG, it's 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're at 42.5%. So that doesn't just mean we get 42.5% of all of the sort of revenue streams coming out of that asset today, 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 to raise that $2.3 billion. As you could probably imagine, you raise, you can raise that quite easily out of PNG LNG, but I don't expect that, that will necessarily be the case. But as I was saying, it's more than just financial, it's also strategic. And if you think of some of the strategic rationale for doing that, better project alignment and to get certain sales outcomes can be very beneficial to the future expansion of that project also.

Yes. Makes sense. And just a quick one on restoration CapEx. It's up the up a touch sort of in it's around $200 million or so. How should we sort of think about the go-forward years 2023, '24, '25? Is this a sort of new number? Or is this a bit of a higher yield just trying to think about that going forward, please?

Look, that's a good question. I think when it comes to CapEx, there's 3 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 talk about. So in other words, when we say we're going to be less than USD 25, that includes the $1.1 billion of sustaining CapEx. So it's self-funded. And then the other 2 CapEx numbers that we -- and it also includes the restoration CapEx, I should have said that. So that includes the $200 million you're talking about. 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 3 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 USD 200 million each year. Now it may be slightly above that or slightly below that, but it's not a bad guide to be thinking about as a guide over the next few years that we'd be spending around $200 million each year. And in fact, 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 on the Cooper Basin decommissioning old flow lines and old wells, on an ongoing basis just to manage those liabilities over the longer term.

Your next question comes from Mark Samter from MST.

A couple of questions, if I can. Kevin, just the first one on Bayu-Undan, it seems like people continue to struggle so they understand the PSC, but these tend to be the best production and the budget coming downward, you can never have I think last year, you lost over $3 million just because of higher prices were due to higher revenue. Can you give us any feel for what gross production declines are expected to be within that forecast?

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

Perfect. And then just a quick question on the infrastructure, there's like the possibility of doing something with the production's been out in the for a while now. And I guess, it's a bit less clear to me exactly what the internal thinking is on do you sell a partial stake? I don't know there's been some press on RPOs and things like that. But I'm interested to know a lot is thinking about, a, the division you now report is infrastructure and b, how we're thinking again on the GLNG infrastructure for total of it?

Yes. Look, I mean, I think that, look, it's 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 that, like hydrogen assets, like CCS opportunities in the future. That doesn't make sense, of course, in 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 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-down. 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 if you do that, right? You lock in 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 down infrastructure to the market. And I want to emphasize that we weren't setting these midstream assets up so that we could sell them or sell-down in them. We were selling up, so it gave us the option to do that. But more importantly, gave us ability to run them separately from the upstream to open up to a 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 haulage and, of course, to give us the flexibility to be able to drive on with other business opportunities, our clean fuels and our decarbonization projects.

Making one quick more question, if I can, actually. I'm just -- I'm not going to ask you a silly question on sell-downs that you're not going to tell us about, but I guess, I'm curious about with Dorado, where there might be useful information and knowing where you get some other sell-down processes, how you think about Dorado, I think you mentioned, your decisions might be influenced on other sell-downs, but you obviously can't entirely control the timing of other sell-down, does it feel quite sensible to potentially FID to ride about 80% and then make that decision with full information. But I guess what I'm asking is other sell-downs don't need to be a conditioned precedent for the FID on Dorado.

Yes. Look, that's a great question. And the answer is you're correct. They don't have to be a conditioned precedent for the FID on Dorado, there are other factors in there, right? I mean I give you an example. If you look at our free cash flow generated in 2021, that alone paid for the entire Dorado project at 100% equity. I'm talking about the $2.3 billion, right? So if you talk about a project that's around $2 billion in CapEx, that would more than -- the free cash flow that was generated between the 2 businesses last year, we'd 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're 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. But ultimately, Dorado is 80%. It's a very high equity stake. We're currently drilling the Apus and Pavo wells and an important consideration as a result of those wells. And why is that important? It's not going to significantly change the design of the facilities now, I don't think. But whether it'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 2 of the Bedout Basin development, which includes bringing gas back into our West Australian gas assets as backfill from around 2030-ish onwards and gives us a long-term backfill strategy for those assets. So look, all of that is part of our thinking, but we really need to wait until we drill these 2 wells and see what interest we get in the sales process. And then being frank, I think I've said to many people before, we ran a sale process last year. We suspended that because of where we were on the Oil Search transaction at that point in time and because we couldn't see any line of sight 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 we're going to get value for them or not, and then we can revisit the sales process.

Your next question comes from Mark Busuttil from JPMorgan.

Just again, just sticking to the asset sales side of it. I get the sense from your commentary on this call that the $2 billion to $3 billion is kind of the goal seek 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 of value?

Yes. Look, Mark, 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 gearing at this point in time by something like $2 billion to $3 billion, right, impact on the balance sheet. And how you get there in terms of 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 5-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 sell-down process is about strengthening the balance sheet and managing our future CapEx exposures. So we've got a more steady-state environment that we can plan on.

Okay. In terms of PNG LNG, you now 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 they already been discussions with joint venture partners about potentially unitizing interest across the 2 projects to make it sort of EBIT across both?

Well, we've had the keys for about 7 weeks. So we have to have 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 isn't something I'm particularly driven by in 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 us and the joint venture partners, and we're very focused on being a good joint venture partner, a partner of choice who delivers value, good value outcomes to all of our partners. Where we're not the operator, we don't want to be a partner that sits here blocking everything because we can and have a threat over the operator just because -- and I wouldn't maintain a stake just for that without any real strategic rationale for doing so. So there's no driver here to be bigger than next one in terms of our stake and PNG LNG. We've 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. I don't want to sell too much of it. And so it's a balancing act. And 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 back just slightly, Darwin LNG, you've talked about Bayu-Undan sort of seizing 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 be idle for?

Well, yes, so if you assume that Bayu-Undan 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 on that. We lost a year, you'll recall in 2020 when we suspended FID, we put it back. When COVID hit the market, some -- there's a lot of uncertainty around shipyard availability and things like that. And we decided Conoco was still the operator at the 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 adjust over a year, reset the project, recontract where we had to and take FID in May 2021. And -- so yes, the guidance is first half of 2025, and we're on track to do that.

Next question comes from Saul Kavonic from Credit Suisse.

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 guided the $1.1 billion this year, including the OpEx. According to the old Oil Search kind of projections, $200 million of that is Oil Search for the next couple of years. Should we be expecting basically about $1.1 billion of base business CapEx including CapEx for the next few years?

I think that's a good guide. I think the $200 million is a good guide, Saul, going forward. We previously said ours is around the $900 mark. And if you added $200 million on, then yes, $1.1 billion is a good case.

Second quick question is just on Alaska. You mentioned how it's a low breakeven project in the presentation. Are you able to confirm or is it -- sounds to view that the breakup below $40 is Oil Search guided? Or has the view changed on exactly how competitive this project is?

Yes. Look, I mean it's a very competitive project and it is a low free cash flow breakeven. The guidance Oil Search 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 with Santos is going through the FID readiness review process that we have in-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'll restate the economics as we normally do with that decision. But there's no reason to think it's any different as, Saul.

And just last one, back on the Beetaloo well results, you mentioned you're still looking to clean up those flow tests and watch for the next 12 months. I mean in the event that we don't see a big pickup over that next level 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 our CapEx guidance. 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, Saul. I mean I think with these things, it's very dangerous to be putting too many updates out until you clean them up and you see what the wells are actually going to flow at, 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 those results later in the year.

Your next question comes from Nik Burns from Jarden Australia.

Just another question in relation to Alaska. You mentioned the sale process is 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 if you're bringing in a new operator but like we want to undertake a full-scale review and make wholesale 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'd rather not do, Nik, is speculate on any of the different conditions of different beds or different options that we might consider. What we have said is that we're going to an asset sell-down process. And we'll wait and see what comes from that. We'll keep you updated of and when we get offers or accept offers on those things. But the sell-down process can be very complex. As we've seen in the past, we've been very successful in selling down assets when we've wanted to do that over the last 4 or 5 years when we've gone 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. Look, 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 whether that will or will not involve operatorship or anything like that. In the meantime, what we have said is we're focusing on progressing the project. The best way to build value in the project is to progress it to get it to FID ready and have a real project to value.

Got it. That's clear. And just a question on Barossa and Bayu-Undan CCS, 6 months ago, I think we talked about need to progress the proposed Bayu-Undan and CCS project as it has implication for your plan for Barossa LNG in terms of CO2 removal facilities, the pipeline, et cetera. Can you talk about where you are at in relation to talking to relevant stakeholders around this?

Yes. Look, I mean, obviously, this was a post-FID initiative led by Santos. We want to develop a CCS hub at 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 a Bayu-Undan CCS project. It's not a Barossa CCS project. 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 would involve an alternative arrangement there either time back in with a CO2 pipeline to the current Bayu-Undan pipeline or alternatively twinning the pipe back 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 tonnes per annum, it would be the largest CCS project globally at this point in time, and it would allow other projects in the region, other businesses in the region to sequestrate their CO2 emissions. So we see a big prize if we can get it up. Work has continued. The engineering work has continued. And if we can get a partner alignment on it over the course of the next few months, I would hope to take FEED on that project sometime in 2022.

That's great. Just one really quick one. Just on Barossa 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?

Thanks for that, Nik. Look, that's subject to confidential process we're on 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, 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.

Papua LNG, obviously, you're progressing with Feed there. Just wanted to ask, and it's 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 Santos had a slightly different view from that.

This is for Papua, Gordon, correct?

Papua. Yes.

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

And type of pricing, JCC versus JKM, considering is on a JKM contract at Barossa?

Yes. Look, I mean, I wouldn't want to give any guidance on that at this point in time. I think it's too early to be giving guidance other than to say that we would look for a balanced approach to our portfolio, so not all in the 1 sort of pricing structure. But yes, we look to balance risk across the portfolio by having a blend.

Are you also able to confirm if there's Chinese interest in offtake specifically from Sinopec?

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

And just last one -- that's fine. 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 oil production assets, their cost on the 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 7.76% to 8% to 8.50% in 2022. How much of that on a percentage basis would be Bayu-Undan then? Because you've actually given us $1.20, but it's not really -- you can't correlate that across.

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

I mean follow up with that...

Yes, the bottom line is that expect it to go back down again once Bayu-Undan is out the system.

No, that's good. I'll get Andrew to follow up on that one with you.

Next question comes from Daniel Butcher from CLSA.

Really just one question from me. Just on your new gearing target down from 35% to 25%. Just sort of curious sort of give a bit more color on what's driving that? Is that due to S&P discussions? Or is it due to ESG issues and sort of being more conservative for the future around your capital structure? How much of that interacts with your country exposure in PNG? That's 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 say 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 you asked the question so that I could clarify that. And I'll 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've undoubtedly seen a derating across the sector over the last couple of years, driven purely by ESG and transition focus. Now I think some of that might 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 in ensuring that we get a just and fair transition, and the poorest people in the world are not starved of energy by taking supply. So during that period, we're looking at 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. And I guess the second part of the question is just, I mean, you're 27.5% gearing now aim for 25% you said your breakeven in all your growth projects, the pre-FID is $65 million, so what sort of suggests you're going to generate even after all your growth, more than $1 billion of free cash flow this year with oil near $90 million. So I'm just sort of curious why you need to sell-down $2 billion or $3 billion of assets to get below 25% when you got a much free cash flow over and above growth?

Yes. Again, thanks, Dan. Good question. But look, I mean I think it's whether you look at this through a 1-year oil price lens or whether you look at this through across the longer term, and we're looking across longer term. What I'm saying is that we want to see our gearing at a maximum of 25% through the cycle. So not just for this year but through the cycle. And that includes our CapEx as we're spending to build our project that includes the funding of our clean fuels projects in future, hydrogen projects or ammonia projects or whatever it is 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'd just like to thank everyone for your time this morning. As I 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 had we had the Oil Search assets 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 look forward to discussing all of that in more detail with many of you over the course of the next week or 2 as we get around to meet you all one to one. So thank you again for your time, and we'll sign off at that. Thank you.

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