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Santos Ltd
Earnings Call Analysis
Q2-2023 Analysis
Santos Ltd
Santos, led by CEO Kevin Gallagher, announced solid financial results for the first half of 2023. Despite a challenging operating environment, the company showed resilience with a disciplined operating model, generating $3 billion in sales revenue, $2.1 billion in EBITDAX, $1.1 billion in free cash flow from operations, and an underlying profit of $800 million. They declared an interim dividend of $283 million, increasing cash returns to shareholders by 14% compared to the same period last year.
Santos emphasized safety improvements and continuous reduction in incidents as a core value. They also reported progress on various business fronts, increasing drilling productivity through innovations like horizontal drilling. Major projects are also on schedule: Barossa is 60% complete, and the Pikka project in Alaska is progressing well, aiming for first production in 2026.
Santos remains committed to achieving net zero Scope 1 and 2 emissions by 2040. The company retains a focus on delivering strong shareholder returns by continuing to generate robust free cash flows to maintain balance sheet strength and support dividend payments.
The company is actively considering the sale of up to 5% of the PNG LNG project to Kumul and remains confident in the quality of their submitted work, with updates expected by the 31st of August. Management is also open to optimizing their portfolio through the strategic divestment of interests and assets to appropriate partners.
Santos has acknowledged the necessity of a significant contingency to manage risks in their projects, with a normal level of contingency assumed to be around 15%. The company confirmed that, despite some project delays, production is anticipated to commence in the middle of 2024, and they are working diligently to adhere to budget and timelines.
Merging with Oil Search has led to improved reliability in PNG operations, jumping from 83% to 96%, reflected in higher production. Santos is looking at plans for domestic gas supply as Bayu-Undan nears its end of field life and exploring ways to maintain value for stakeholders.
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Thank you, and good morning, and welcome to Santos' 2023 half-year results question-and-answer investor call. Joining me today is Chief Financial Officer, Anthea McKinnell. Anthea and I recorded a video presentation on today's results, which you can find on our website along with the presentation. We're not going to repeat the video presentation on this call. We will, however, be happy to take your questions.
Before we do that, I'd like to start by acknowledging the traditional lands of the Kaurna people of the Adelaide Plains from where I am speaking today. I pay my respect to their elders, past, present and emerging. And I also acknowledge and recognize the support of traditional owners and indigenous people everywhere Santos operates, including in Papua New Guinea, Timor-Leste and Alaska.
I'm pleased to present yet another solid set of financial results that demonstrate the success of a disciplined operating model. Santos continues to generate strong cash flow despite the challenging operating environment. I'd also like to touch on some of the highlights from this result.
In the first half of 2023, Santos generated sales revenue of $3 billion, EBITDAX of $2.1 billion, free cash flow from operations of $1.1 billion and underlying profit of $800 million. The Board has determined to pay a dividend for the half of $283 million or $0.087 per share unfranked.
The buybacks announced last year have now been completed. The Board decided not to announce a buyback in conjunction with the interim dividend at this time and will consider the most effective way to return cash to shareholders in the context of the full year results.
We are pleased to continue to deliver strong cash returns to our shareholders whilst also balancing the need to invest in our business. Always safe is a core value at Santos. Personnel safety performance improved in the first half, and pleasingly, loss of containment incidents continue to reduce.
In the second half of 2023, we are focused on implementing programs to improve contractor safety performance. Our performance on reducing spills has continued to improve and we are world class relative to international benchmarks. However, we recognize that some incidents are still occurring and we continue to work on driving the number of incidents down.
Across our business it has been a very busy first half. At GLNG, we have increased drilling productivity through horizontal drilling. In the Cooper, we're on track to drill more than 100 wells. And in Northern Australia, we're expecting at least one more LNG cargo from Bayu-Undan. These are just a few of the operational highlights from across our business.
Across our major projects, Barossa was 60% complete, including the Darwin pipeline duplication project at the end of June. And we successfully submitted a drilling EP to NOPSEMA in July. We continue to consult with the First Nations and other relevant people regarding how the environmental impacts of the project will be managed. And we are making excellent progress on the FPSO with the hull successfully floated in the shipyard.
At our Pikka project, we were pleased to complete drilling of the first well this year and we remain on track for first production in 2026. Pikka is a Tier 1 project. We have a highly capable team in place, supportive stakeholders and partners, including our indigenous communities, and we are operating in a supportive and least sovereign risk jurisdiction with world-class environmental regulations, including for carbon emissions.
In summary, it was a solid first half. The business is strong and benefiting from a diverse portfolio of high-quality assets. We are committed to achieving our net zero Scope 1 and 2 emissions target by 2040. And we are confident our disciplined approach to operating our business and allocating capital will deliver strong returns to shareholders over the long term.
Our unrelenting focus on sticking to our strategy and implementing our disciplined operating model has delivered consistent results and kept the business resilient and performing strongly. We continue to generate strong free cash flows to maintain the strength of our balance sheet and to provide returns to shareholders. Thank you.
We're now happy to open for questions.
[Operator Instructions] Your first question comes from James Redfern from Bank of America.
Just a few questions, please. First one, can you please provide an update on the 5% sell-down in PNG LNG...
Sorry. You cut off at the end there, James.
Please. I just want to get an update on that, please.
All right, on PNG. Look, on the PNG sell-down, we're continuing our discussions with Kumul for the sale of up to 5% of the PNG LNG project. We've given -- we got a commitment to update the market by the 31st of August. I was encouraged by the public comments last week by the CEO of Kumul, Wapu Sonk, in the media.
But really, we don't want to say anything really until we have something to announce before or at the 31st of August. We'll update the market then.
Okay. Next question is how confident are you that Santos will obtain the environmental approvals to resume drilling at Barossa later...
Well, we're working towards that. I mean the comprehensive body of work has been done to this point. And we're very confident in what we've submitted. As you would know, I think, James, I think there's 40-odd EPs with the regulator just now, but the regulator is working flat out on those. And because ours is a live operation, it's giving that focus. So we're very confident that they're giving that the appropriate focus.
Consultation is continuing. It's not just the drilling EP. All of the secondary EP approvals require that consultation. So we're consulting with many stakeholders. And submitting the EP does not actually indicate a line in the sand in that respect. We're continuing with that engagement and we've been doing that now for several months. And it's going well, so a lot of work.
We're confident in the quality of our work. It's a quality product. And if the regulator has any questions, we expect that we come back soon on that and then we would work to resolve those. And we are still working towards getting drilling this year, before the end of this calendar year.
Great. If I can squeeze in one more, please. Just interested in any comments around the Dorado sell-down. Just wondering...
Well, look, I saw the article in the press this morning. Look, we don't really have any comment on any specific sell-downs. I mean the approach I want to take there, James, if we've got something to announce, we'll announce it then.
And -- but as I've previously said, we are always looking to optimize our portfolio and selling down interest and development assets for value to appropriate partners is part of that strategy.
The next question is from Gordon Ramsay from RBC Capital Markets.
Kevin, I just got another question about Barossa. I'm just wondering how you really avoid a CapEx increase with this project. And just want to get a feel for what your cost-to-date have been? And are they still expected to be absorbed by the contingency in the project? Because it's currently got a rig on standby, so other costs obviously involved.
Yes. Look, I mean we've stripped the cost of the standby for the rig down to the bare minimum that we can. We have sublet vessels and stuff like that to help reduce those costs, but we are incurring costs. The reality was that we had not actually incurred or used any of our contingency before this event occurred on the project.
And we had a significant contingency available to us in this project within the confines or within the number that we had previously communicated to market. We're obviously using some of that contingency now. And the longer it goes, the more of that contingency we would continue to use.
But at this point in time -- if we get back drilling before the end of this calendar year and we are successful in executing our pipe line laying activities, we still believe we can do that within the original cost estimate, albeit we'll be going forward with a much lower contingency element to that cost estimate for any other interruptions. And we are still confident first half 2023 -- 2025, sorry, coming online.
So at this point in time, that's what we're aiming for, Gordon. We will be doing, as we always do on these projects, 25%, 50%, 75% detailed cost reviews on these projects, deep-dive cost reviews, risk assessments. And if there's ever any updates following those, we would bring those updates to the market at that time.
And is it fair to assume that contingency is roughly 15%?
Well, we don't disclose the contingency on individual projects. But it's fair to assume that 15% is a normal level of contingency for these types of projects.
The next question is from Adam Martin from E&P.
Just buybacks. I think you said there that the buyback is off for the next 6 months. Just perhaps a bit of insight there of what the Board is thinking? Currently, the balance sheet is continuing to delever. What's the strategy there, please?
Yes. Look, the Board -- well, we look at shareholder returns on a full-year basis. And our aim as per our policy is to return 40% of free cash flow from operations -- from -- free cash flow from operations, should I say, to our shareholders.
The Board decided in this instance not to announce a buyback in conjunction with the interim dividend at this time as they want to consider the most effective way to return cash to shareholders in the context of full-year results.
And based on those first half results, the Board determined to pay an interim cash dividend, which is 14% higher than the cash dividend that we returned to shareholders for the same period last year. So really, it's taken the approach that buybacks we'll decide on a 12-monthly basis rather than a 6-monthly basis and manage that buyback program over longer periods of time rather than shorter windows.
Okay. Okay. It makes sense. Just there was a comment there about potential for domestic gas supply once Darwin LNG ceases. Just perhaps if you can elaborate a little bit more what you're thinking there, please?
Yes. Well, look, I mean we've been working pretty hard with Bayu-Undan and Reindeer actually in Western Australia as well to extend the lives of those fields as they begin to cut water.
And as you would know, I think we originally predicted Bayu-Undan would come into end of field life last year. And when we actually acquired that asset, it was due to come to end of field life in 2021. And we drilled some infill wells to get an extension to that. And of course, we're now continuing to produce around about 9,300 million standard cubic feet per day from that field.
Now, we think we can get one more LNG cargo, at least one more cargo at this point in time. But ultimately, when it gets down to around the 80 sort of million standard cubic feet per day level, that's getting close to turndown levels for the plant.
So we've been working with the joint venture partners, with Northern Territory stakeholders, with our Timor-Leste government, stakeholders and partners to get an agreement that we can -- 80 terajoules per day is still a good amount of gas, right?
So rather than shutting the field and losing that value, even though we shut the LNG plant down, we can continue producing that straight through into the domestic market here in Australia. And we're working on plans to do that. And that could keep Darwin producing for a significant period longer as a domestic gas supply into the Australian markets.
The next question comes from Saul Kavonic from Credit Suisse.
A few quick questions for me. If I could just circle back on the buyback. If you just elaborate a little bit as to, I guess, why we've moved to this annual basis? And we now have to go through a 6-month period without buybacks, given buybacks was able to -- supporting the share price over the last year.
And can you address any concerns that maybe it's because of the delay to the PNG sell-down and the capital management policy might not be sustainable without asset sell-downs?
Well, look, I mean I think that there's a lot packed into that question, Saul. I think the Board feels comfortable with buyback programs on the basis that you're not confining that to too short a period to do the buyback and given that we can't actually control what the share price is in that period or not. And of course, what all activities are going.
So we're looking at this on an annualized basis. We had very strong cash flow production in 2022 as a consequence of very high commodity prices. And so it's very significant volumes we're able to -- or sorry, cash flow we were able to dedicate to buybacks during those 6-month periods.
We just felt in this instance that the impact of the buyback or the quantity of the buyback was not significant enough to really ought to make that decision right now and instead to look at delivering that over the longer period. So giving us a longer period to deliver on that buyback, we think gives us more opportunities to optimize the buyback, if the Board resolves to do a buyback.
I mean it's not a given. I mean, ultimately, they might decide to return as a cash dividend at the full year. But it's really just moving from a 6-month sort of deciding or decision-making process on buybacks to think of that as a 12-month annual decision.
Okay. Got it. So the extra $200 million odd which would be required to get to the 40% PAT, we should just expect that to be added in at the end of the year?
Well, look, I can't say that, Saul, because ultimately that's a decision for the Board, right? I mean the policy states that dividends will be a decision for the Board. But as I said earlier on, our policy aim is to return 40% of free cash flow from operations to shareholders. And that is the policy.
Right. A quick one on just PNG. Just -- I think there's just something in the press from The Australian overnight talking about conflict. Quite a number of deaths up in Angore province, which I think is where Hides is. Is there any sign that, that might be presenting any risk to PNG LNG production?
Saul, look, security in PNG is something that we always work closely with the PNG government and authorities on. And as you would know, through Oil Search and even in our early period of being the operator in our, sorry, non-PNG LNG operations at PNG, we have security issues that we have to deal with.
These particular incidents haven't caused us any concerns in our operating areas. They've got no impact on us. And our communities are actually pretty stable at this point in time. And we work very hard in those communities through both the Santos Foundation as well as our operations teams to maintain our presence in those communities and strong working relationships with those communities, including recruiting and providing jobs for a lot of the local people in those communities.
So we're very proud of our investments here and the work that our community teams do in PNG. Interestingly, the reliability of our PNG operations since we've merged with Oil Search has increased from 83% up to 96% on those assets. And we're seeing that in higher production from those assets as a consequence of that higher operating reliability.
And that's because we're able to get to these locations without interruption from any of the sort of events that you're referring to. But our security is always front of mind for us as an organization. And we get regular briefings and we stay in contact with authorities to make sure that it's safe for all of our people to operate.
Last question for me, just staying on PNG. If we could just get an update on execution of Angore. I think in the last public Q&A we had earlier in the year, you certainly need to see, I guess -- not to judge by the early kind of activity and let some more time pan out. Is there any update there? And does execution at Angore potentially present any risk to the production outlook in 2025 that Santos previously put out about 6 or 7 months ago?
Yes. Look, I mean delays in any of these programs always presents a risk to future production. There had been delays in the 3 wells in the top-hole sections of these wells. But our recent briefings are that Exxon are on top of that now. They're recovering from that and have been able to make up -- as much as the drilling is blown out a little bit in terms of schedule, they've been able to make up for that with some of the facilities part of the project.
So we're still expecting to come in on budget and probably still looking around the middle of 2024 for production to be on stream.
The next question is from Dale Koenders from Barrenjoey.
Maybe just firstly on Dorado. There was a comment that exploration of Phase 2 gas development. Does that now confirm the JV is aligned that Phase 1 is just an oil development?
You broke up a little bit there, Dale. But I think what you said -- what you asked then there was are they aligned on the oil and gas integrated development. Is that correct?
Just oil Phase I.
Just oil Phase 1. Look, Phase 1 is always the liquid stripping part of this project. So Phase 1 has got its OPP approved by the regulator. And that effectively would be the liquid stripping phase of the project. What Santos wanted to do last year when we recycled this project was to then make sure we're designing that for the gas project to be compatible with a gas -- an integrated gas development for Phase 2.
And we probably need a little bit more gas to make that economic coming back to Varanus Island. And that's what we're working through just now. The prospectivity, as you would know, is very high for both oil and gas. But yes, Phase 1 would be liquid stripping with all gas re-injected to maximize liquids recovery and, of course, to store the gas for future gas production.
And then you'd previously also mentioned you needed certainty on the contracting market, both in terms of cost and risk. Are we there yet?
Well, we're working through that right now. But it's fair to say we haven't re-contracted anything for that. We're working towards an FID readiness for the second half of 2024.
Okay. So what else are we waiting for, for that project sanction? Is it sell-down? Is it Santos balance sheet? Is it NOPSEMA?
Well, look, I mean, it's all of those things quite frankly. I mean, it's getting to the right JV equity levels. It's getting the maturity of the subsurface work done, and the contracting strategies in place and the cost estimates where we want them to be.
And of course, it's about approvals as well, right? So it's working through the regulatory approval processes. And as I've always said, I'd need to see that we are well progressed on Barossa before we want to take another offshore project through FID in Australia.
But I'm confident we'll get there. It's just that you wouldn't want to be taking that on prematurely, that risk.
And then maybe finally a boring question for your CFO. The PRT gained in the accounts through the period, can you explain that? And is this likely to be an ongoing benefit?
Yes. Dale, I can explain that. So that's largely related to our WA assets and its augmentation on carry-forward balances. So to the extent for projects particularly like Barossa, when you haven't yet got production utilizing those credits, the credits they carry forward and are augmented. And that goes to the credit to the P&L and a debit to a deferred tax asset, to noncash.
Okay. So will continue.
Will continue, yes.
The next question comes from James Byrne from Citi.
So just the Barossa environmental plan, I'm probably grossly over simplifying the process. But my understanding is that once the environmental plans are submitted, NOPSEMA reviews until, call it, a month and then they'll come back to you with questions or concerns. Just wondering if you could confirm whether you're having to rework anything or is there any major concerns that they've flagged so far in that process?
No. We had no response from NOPSEMA on the plan officially at this point in time. And so what the -- other than they asked for an extra few days, an extra 10 days or so to review that. So you can add 10 days on that approximate month that you stated. And it's not unusual then for the regulator who reviewed -- these are very large documents. I'm sure you're well aware. But it's not unusual for them to then come back with a number of questions or clarifications that they require.
And at that point, we would work through those. But until we see what that is, it's difficult to speculate. The one thing that I will say is we're very confident in what we've submitted. And remember, it's based on an EP that technically was approved previously, right? So a lot of the supplementary work that's done here is around the body of work we've done in consultation.
Got it. Okay. Could I just have a quick conversation on carbon and any potential liability? So I looked -- since 6 months ago safeguard mechanisms a bit more known and certain. The London protocols being introduced to Parliament, that bill. But in the scenario that Bayu-Undan doesn't get up or is significantly late relative to start-up for Barossa, are you better -- how is your understanding there on your liability for CO2?
Well, look, I mean the safeguard mechanism in one regards makes it quite simple for all of us to estimate and to think about what we have to do going forward. And if you think about the Barossa project, Barossa has been impacted quite significantly from the point of view that from day one it has to be net zero reservoir emissions, right?
So what that means for us is if the Bayu-Undan project is not up and running -- Bayu-Undan and CCS project is not up and running at the start of the Barossa production, we would need to have credits available to offset those reservoir emissions until such times as Bayu-Undan and CCS is up and running.
But I'm only focused on Bayu-Undan and CCS being up and running and being approved. And we've got very constructive conversations going on with the regulators in Timor-Leste. I was very pleased to see the Australian government push through on the London protocol. That needs to be in place to allow this project to occur.
And thankfully, we've got that through the parliament now. And so we look forward to the 2 governments progressing on the conversations to put in place the regulatory frameworks below that allow us to get this project approved.
But Bayu-Undan and CCS is the most logical option given the need for carbon capture and storage. It's a reservoir that for many years -- in fact, in the early years, we injected more than 1 billion cubic feet of gas per day in when -- similar to the question I think that Adam asked about Dorado, or maybe it was Dale, that we're injecting a liquid stripping for the first few years of Bayu-Undan.
We were injecting 1 billion cubic feet of gas into the Bayu-Undan reservoir every single day back at that time. So it's a very, very good reservoir for storage and we're very confident we'll get that up. And you can see with some of the legislative and regulatory framework progression such as the London protocol, we're moving in that direction.
Got it. Okay. And my third and final question is just on Alaska. So you've drilled that first well already. And my recollection is you described that as having gotten off to a flying start. What are your lessons learned so far? Are you still confident in your capabilities as an operator there?
Look, as a ex driller, myself, James, I don't think I have ever described any drilling operation as getting off to a flying start, because I always think they can fly much faster than they're flying. But look, I think they've got off to a solid start.
And an actual fact to that comment about one well was at the end of the quarter or the end of the half, they've drilled another –- they've drilled 2 wells, in fact. And so, we're progressing. The drilling is progressing very well. And we're on the third -- so, actually, we're on the third well right now. Apology. And so it's progressing well. We're learning some things as we go, but they're all positive.
And we've got 40 wells to drill all up. So a bit of time to go. But the safety performance has been very solid. The environmental performance has been solid. As I say, we've got a quality team. I was up there in July visiting them. And it's going very well at this stage. So as long that continues. But I do look forward to our drillers continuing to move along that learning curve and improve the performance. And I know that they are very keen to do that.
And in these projects, just like in Queensland, on our onshore operations in Queensland, when they're very heavy drilling dominated projects, which a lot of the costs in these projects are, the risks around cost escalation and/or cost saving opportunities really are driven by how the drilling part of the project is going. So it's been a very solid start and I look forward them continue to improve.
Great. Look, just considering you got through your slides in 6 minutes, I might actually sneak in another question. Just thinking about -- following on from what Saul was asking around PNG LNG production levels of Angore. If we maybe just look at another couple of years, you've got Papua LNG production that potentially come online, uses some of the liquefaction capacity at trains 1 and 2.
And so you're able to push out some of that CapEx you might have otherwise spent such as P'nyang and Juha. But in the event that Papua LNG was late, do you feel like you've got enough gas there in the upstream to be able to continue to operate PNG LNG at higher rates?
My understanding was there was that a JV meeting a few months ago to figure out if you wanted to drill some extra wells or not on that risk of PNG LNG schedule?
Yes. Look, I mean we're always looking at having a bit of -- you like to always have a little bit of kind of buffer in your supply plans, but not too much buffer because that means you spend a lot of capital, of course, and over develop.
I think the key thing to know here is, if that were to happen, then you have options to bring other things forward, including our own operated opportunities, production opportunities from the APF project, which has also been deferred, which is what you're referring to in terms of our CapEx being pushed out by 2 or 3 years.
But we're pretty confident in the plan. I mean, Papua is progressing well. The latest update I got is it's still online to take a FID decision next year. And as long as we do that, we'd be pretty confident that we'll be able to get this on time.
The next question is from Sarah Kerr from Morgan Stanley.
Congratulations, Kevin and Anthea, on the results. I just had a question around Narrabri. What are the critical path items left for that project to reach feed and FID?
Sarah, look -- I have just got to change direction here a little bit because I don't get too many questions on Narrabri these days. But look, the project has got its approvals. It still had its native title award, which is being challenged in court. The decision from the arbitration is being challenged. And so we will respect any decisions from that. We'd expect something in the next 3 or 4 months on that front.
But the main critical path item really for Narrabri now is the Hunter Valley pipeline approvals and getting the pipeline license. And so we've been working constructively along that pipeline route consulting with many of the landholders and community stakeholders along that route, optimizing the pipeline route as we go and signing people up for the survey work that we have to do to progress that licensing approval.
That's going very well. We've been consulting with thousands of people over the last few months or the last several months. And my expectation is that, that's probably a sort of 12-month cycle or so to get to the point where we'd be able to hopefully get our pipeline license in place. And that's the last big formal approval required before you could go forward on the Narrabri gas project.
What I will say about Narrabri, though, it is a project in demand. I mean, we have had more demand-led conversations from people who are looking for gas, needing gas in the future, particularly in New South Wales, and we are oversubscribed in terms of interest for that project.
And maybe just one more question, if I may. Pikka is obviously going really well. Are you considering maybe having a larger footprint in North America?
Well, look, I think at this point in time, the hopper for Santos is pretty full. I mean we want to stay very disciplined. I'm very focused on delivering what we have on our plate right now, continuing to operate well. We can always operate better around our sort of core assets across the business.
Today, Queensland is performing very well. Cooper is getting back to a very strong steady state of operation. Darwin, of course, is coming to end of the Bayu-Undan field life. And we've got a lot of work associated with that and getting that ready for the start of Barossa.
And of course, we have to then get on with delivering the Barossa project. And of course, in Western Australia, we've had some challenges over the last 12 months or so there with Reindeer coming to end of field life, albeit it's showing a surprisingly strong signs of life at this point in time. So hopefully, that will go for a bit yet. And some reliability issues over there as well, which we're really focused on improving. And we expect a stronger second half in WA as a consequence of some of the planned maintenance work we've been doing over the last few months.
So yes, I mean, the hopper is pretty full. I'm not really looking at expanding or developing any other projects at this point in time. We like to get some of these things off our plate before we move forward.
The next question is from Nik Burns from Jarden Australia.
Maybe just starting off with a follow-up to your comments around Bayu-Undan and CCS. I think the last update was targeting FID in 2025. I appreciate that sounds like it's a fair way away. But there's obviously a lot to be done between now and then.
Can you just help us maybe walk through the key milestones that you're looking to achieve between now and then? And what we should be looking out for? And also, once you achieve FID, how long do you think it will take to actually bring the CCS project online, understanding that there is going to be a gap between Barossa LNG start and the start-up of this CCS project?
Look, the technical work for the project is almost done. I mean we're pretty much finished or at the latter stages of our FEED process. And then it's really a case of waiting for approvals.
And if you think about the traditional approach to these projects, we do some pre-FEED concept pre-FEED work, then your FEED, then your FID, and go straight into execution. These projects really have developed a new phase now between FEED and FID, which is our approval phase. And they're getting those secondary approvals in place to derisk that approval process. No longer I think can you simply take FID and get going and get your approvals in parallel.
The regulatory and legislative structure in Australia right now for our industry does not really warranty taking those risks, I think. And so for us, it's about getting all the approvals in place. That's really what comes next.
And the London protocol was a great first step. But we've got to then get the rest of the approvals, the regulatory approvals that we need on both sides, Timor-Leste as well as in Australia. And that has allowed us to take FID and move that project forward.
In terms of the time line to deliver on the project, it's not huge. But the biggest risk to that schedule is actually supply chain. So as the world is heating up and projects are getting developed all over the world, whether they be oil and gas projects or other industry projects, rotating equipment, compression, all that sort of stuff is becoming more in demand and lead times for the delivery of equipment is going out and taking longer.
But we're keeping our eyes on that. But I would think that you're really looking at something like a 2-year sort of period from FID to delivery. And remember, a lot of the kits already in place, the pipelines there. Some of the CO2 separation equipment is already there in terms of Darwin and at Barossa. So it's really about compression and it's really about facilities offshore.
My other question is on another asset that maybe doesn't get as much attention these days GLNG. It's good to see the field performance in recent times and I understand you've got Arcadia expansion underway. You're flagging sort of up at 350 to, I think, 450 wells this year.
But as we sort of look further ahead, conscious that there are some third-party gas supply contracts that do roll off aggressively over the next few years. Just thinking about how we should think about GLNG LNG output over, say, the next 5 years? You've been targeting more than 6 million tonnes per annum over the last couple of years, which has been great.
But is that level of investment in new wells and processing capacity? Will that be sufficient to offset the decline from the third-party supplies? Or should we be thinking about a step down in LNG supply from GLNG over the medium term?
Yes. Thank you for that, Nik. Look, in the short term, no, I don't see our production dropping down. I mean we are very focused on maintaining that production. And what that has steadily been doing over the last few years is, as you rightly point out, they're replacing third-party gas with Project Gas as we keep building those profiles, the indigenous gas production higher and higher.
Look, there's, a lot of good things on GLNG. And it's one of the things I'm proud of across the organization is the way that those guys continually innovate to get better reliability. You can see in our pack. We show you the slide on mean time between failures. And that is world-class performance. Everywhere we benchmarked that.
It really is world-class performance. You can see the sales gas now a much higher percentage of that is either Santos or GLNG gas and not third-party contracted volumes. And so we expect to fully replace that over time and continue to replace that over time.
In order to go beyond 6, I think we need new developments. We need new fields to come into the mix. We are seeing some higher productivity rates from wells. And I mentioned in the pack about the horizontal wells, the lateral horizontal wells that we're drilling at Arcadia, where we're seeing well productivity more than 15x what we would get from traditional vertical wells in those same codes.
And that's an amazing outcome. What that will do, though, rather than simply give us higher production, it will give us much stronger base production and stronger tail production. And so the other thing I would draw your attention to there, Nik, is over the last few years, you were have seen a steadily increase in our reserves position.
And so what we've been building year-on-year at GLNG is our reserves position to allow us to be in a strong position when we get to some of those options in a few years' time. But right now, I think 6 million tonnes per annum is still the guidance I would want to give year-on-year. And we're working hard at maintaining that and working with our joint venture partners to look at opportunities to develop new opportunities to bring into GLNG and take it higher.
The next question is a follow-up from Saul Kavonic from Credit Suisse.
A few quick ones just to run through some projects. Just remember CCS to where the CapEx has gone up, I think, USD 220 million when AUD 220 million. Just give some color on the drivers of that? And if there's any set a sign of broader risk execution or it's very specific to room?
Yes. Look, I mean it's gone up just over 30% on a gross level. The reality of this project has really been driven by contractor I would call it, capability and capacity as the main driver of this. And as we have seen very high turnover in contractor personnel in Australia, I think that is a broader risk for the industry. I think that's a risk we are seeing right across our industry.
And what that's leading to is lower productivity, which then leads to activity delays. The project itself is very well progressed on all the big material items. So all the kits out there now the pipelines are done and in place and commissioned. The wells are all in place, just waiting for the CO2 to come.
A lot of the tie-ins have been done. So 3 of the 4 tins to the trains at Moomba are now completed. And we've been doing that as we've been doing planned maintenance shutdowns at Moomba throughout the year. We've been able to execute that.
But if I was thinking about what was driven the cost escalation, it's really contractor capability and capacity. There were some engineering issues in terms of scope creep in terms of volumes, quantities early on in the project, which is coming through and some of supply chain impacts. I would think they would be more local to this project.
And one of the AFE cost estimate went out with USD 165 million, which I think you said at the time was AUD 220 million but USD 165 million. So that's a 55 million gross increase in CapEx. And one of the problems you have with small CapEx projects, relatively small CapEx projects, of course, the increase is always going to be in the tens and the percentages are much higher on the smaller projects, right?
And that's unfortunate when that happens. But we're pretty confident that we've got a very good, very, very comprehensive start-up strategy for this project. We're still confident it will be in the first half of 2024. That will come online.
But unfortunately, it's going to cost a little bit more to get us over the line, which is not inconsistent with what we're seeing elsewhere. But from an integrity point of view and from a progress point of view is going well. Unfortunately, on the cost side, has blown out a little bit.
Also a question on Varanus, when I just look at some of the gas flows recently, it seems to be quite a bit down versus last month. Are there any issues you can kind of thought in coming online there?
Yes. No, Spartan came online saw and that was producing well. We've got a train shutdown just now. It's a very -- it's quite a long shutdown for the -- one of the aiming trains ever in island and that's a big but a planned maintenance work we're doing, which was always in the plan.
And from memory, I think it's like a 4 to 5-day shutdown. And that's why we've had a lot of -- with the unplanned outage at the start of the year, Spartan came on, then, we've gone into this planned outage.
And unfortunately, what that's meant is a lot of interruption, if you like, in the first half. We expect that to pick up and be a steadier second half. And I think that should all be coming on early next month, and will get back to significantly higher rates.
And in fact, I think Reindeer, which was also shut down for some maintenance activities as duty come on today, I think. So we get that back on and we'll see where we are with that. That was producing between 40 and 50 TJs a day just when that was shut in a few weeks back as well. So a lot of maintenance, a lot of activity, that's been impacting and interrupting our Western Australian operations in the first half.
Hopefully, we'll have a much smoother second half. And we'll get the benefits of that maintenance activity.
And my proper last question. Just on Barossa $3.6 billion budget. I just want to just clarify, I guess, is there a little foot there, something that that's up until it reaches nameplate capacity.
Is there any activity that was in the original FID budget, which is I guess being pushed beyond when the project will reach nameplate, which is now kind of out of that $3.6 billion or the $2 billion is for all the time that was assumed at FID to include within that same number.
Yes. I mean the AFE has not been changed. There's been no change to the scope for the Barossa Phase 1. So all the same activity is still included in that cost estimate.
I mean, I think what may well happen is that we may start up before we finish that scope. But that doesn't change the cost estimate we have out there for the scope. And of course, Barossa always had Phase 2 activity, which will be approved subsequently well down the line for the additional wells I think after about 7 years or something of production.
But no, the Phase 1 is always the same scope as it is right now that represents $3.6 billion. And with the DPD that was increased to $4.3 billion, I believe, yes.
So I think we have time for one more question, I think.
The final question comes from Henry Meyer from Goldman Sachs.
Just to keep it to one. I think we've covered most ground so much. I mean for you left field in and I'm sure we get you less questions around the side and the Narrabri. But just in the context that it seems some of the excess partners are picking up some of the leases nearby.
Has there been any movement in how you're thinking about commercializing those discoveries around excess?
Well, again, Henry, anything we do in terms of portfolio optimization, we'll be happy to talk about when we make any announcements on that. But we are constantly looking at the best ways to monetize all of our assets, whether they'd be exploration or development assets.
So anything we can do to optimize portfolio. We continue to review. But we'll only talk about that really if there's anything to announce.
Do we have time for a few more, if that's okay.
I'll give you one more, Henry. And unfortunately, you've got the last slot, but I know we're under time pressure here. So we'll give you one, how is that?
I appreciate it. Last one and I hope this is pretty quick. I just want to test my understanding on the Barossa Mitsubishi contracts, the gas contract. Am I right in understanding that there's flexibility there to sell the gas at oil-linked rather than JCAM as well and how you're thinking about perhaps adjusting the contract or targeting your spot gas exposure into '25 and '26.
You're right to think that we have flexibility to re-contract part overall of those volumes. And I think I'd leave it at that, Henry, because I wouldn't want to say what we're going to do or not going to do. But we're always looking at opportunities.
And the good thing about the contract is we have the flexibility to do that when the time is right and the best opportunities arise.
And maybe just a bit cheeky at the end to see if I can draw some more on that. Is there like a time line constraints or anything you need to make a decision by on choosing what index to sell that?
No. That was very efficient. All right, Henry. Thanks very much. And look, I think we're going to wrap it up there. So I'd just like to say thank you to everybody for dialing in. I look forward to catching up with all of you over the next week or so, on our road shows. And thanks again for your support. Thank you.