Santos Limited (STO) Earnings Call Transcript & Summary

Santos Limited 2022 Full Year Results Webcast. [Operator Instructions] I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and CEO. Please go ahead.

Thank you, and Good morning, and welcome to the full year results question-and-answer call. Joining me this morning 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. 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 from where Anthea and I are both speaking today, and I pay my respects to their elders past, present and emerging. I also acknowledge the traditional owners and indigenous people of all the areas where Santos operates including in Papua New Guinea, Timor-Leste and Alaska. I'm pleased to present yet another strong set of financial results that demonstrates the strength of our business and our disciplined operating model. They are record results; the highest production, revenue, free cash flow and underlying profit in Santos' history. Importantly, they are driven by higher commodity prices and strong cost of demand for our products. The results for the year were outstanding, and I'd particularly like to call-out record production volumes of over 103 million BOEs. Sales revenue increased 65% to $7.8 billion, which is a record. EBITDAX doubled to more than $5.6 billion. Free cash flow was up 142% to $3.6 billion. Net debt was reduced by $1.7 billion and gearing down to 18.9% and underlying profit up 160% to a record $2.5 billion. I'm also pleased to announce that the Board has declared a final dividend of $0.151 per share, a 78% increase on last year's final dividend. This brings total announced shareholder returns for the year to $1.5 billion, including dividends and the previously announced $700 million on-market buyback. This is consistent with our policy to return at least 40% of free cash flow generated per annum. Our diverse portfolio and low-cost operating model are designed to deliver free cash flow through the oil price cycle. Since 2016, this portfolio has delivered $9 billion in free cash flow. This is the cash that enables us to deliver shareholder returns and undertake disciplined investment in sustaining and growing our business. I was pleased to see our personal safety performance improve last year, back to the trend we experienced pre-COVID. Our process safety or should I say on-process safety, we are pleased to see our performance maintained even though we have added new assets in PNG through the merger. However, we had a total of 6 Tier 1 and Tier 2 loss of containment incidents with the more significant being a condensate leak from a loading lane at Varanus Island in Western Australia. All Tier 1 and 2 loss of containment incidents are treated as high potential incidents and investigated fully, including independent expert investigations where appropriate to identify root causes and lessons to prevent reoccurrence. I remain focused on ensuring that we learn from all personal and process safety events and drive forever safer workplaces and fewer incidents. Turning now to an overview of our operating performance, starting with the Upstream Gas and Liquids division. Our Upstream business comprises 3 LNG producing projects and 2 producing Australian domestic gas assets. Upstream produced record volumes in 2022 and delivered EBITDAX of $5.7 billion. The onshore assets performed well. In the Cooper Basin, we added a fifth drilling rig and production started to increase again towards the end of the year as we connected and brought online new wells. GLNG achieved record Upstream equity production, driven by excellent results from the Arcadia field, and we look forward to bringing the next phase of Arcadia development online this year. We've also had some excellent results from horizontal drilling in the Greater Fairview and Arcadia and Scotia areas. Both the Cooper Basin and Queensland added reserves before production. Our assets in PNG also performed well with PNG LNG producing 8.6 million tons and reserves added in our operated gas and oil assets. With our partners, we are targeting a feed entry decision on the Papua LNG project in the first quarter this year. Bayu-Undan has been a success story with production extended into the first quarter of this year and expected to deliver a couple of additional spot cargoes from Darwin LNG. And finally, in Western Australia, we have had some challenges with lower production and accelerated natural fuel decline at Reindeer and Spar/Halyard. This combined with the temporary outage at John Brookes over the end of the year meant lower production than we had expected from our WA assets. Pleasingly, however, the Spartan development well has demonstrated excellent reservoir quality and deliverability and we'll provide the next tranche of gas supply for Varanus Island when it comes online in the second quarter. We're progressing further near-field gas backfill opportunities in WA, including an infill well in Spar/Halyard, potential development of the Spar Deep and Corvus resources and of course, Dorado and the Greater Bedout Basin. Last week, we released our annual reserves and resource statement showing 2P reserves increased to 1.7 billion barrels, which provides us with a reserve life of 17 years based on 2022 production. Importantly, these numbers are the result of our disciplined annual reserve review, which includes external audit of approximately 97% of total 2P reserves. 2P reserves increased by 170 million barrels before production, providing an annual reserve replacement of 166% and 3-year reserve replacement of 366%. Gas comprises 84% of 2P reserves and 75% of reserves plus resources. And we maintain a booking of 100 million tons of CO2 storage capacity in the Cooper Basin, which underpins the Moomba CCS project. Turning now to our upstream projects. Barossa is a world-class LNG asset that utilizes existing infrastructure at Darwin LNG to deliver a low-cost source of supply into Asian markets. Execution of the project is well underway and was more than 50% complete at the end of the year. Manufacturing of the FPSO, subsea equipment and gas export pipeline continues to progress well. Drilling of the development wells, however, remains suspended following the decision by the Federal Court last year. I am pleased to advise that we are progressing all remaining approvals and undertaking community consultation using the guidance provided by the court. This has included a series of community engagement sessions on country on the TV Islands earlier this month. The sessions were designed to provide information as well as help Santos understand first-hand from the local traditional owners and the community, what is important to them and how they want to consult. We believe in developing strong, mutually beneficial relationships with communities wherever we operate. In Alaska, the Pikka Phase 1 project is progressing to plan since we took FID last August. Phase 1 will execute a responsible development plan with a small surface footprint and utilize existing infrastructure. We are committed to delivering a net zero project for equity share Scope 1 and 2 emissions and have signed MOUs with Alaska native corporations to deliver high-quality carbon offset projects. Santos Energy Solutions division is our energy transition business focused on delivering decarbonization projects and clean fuels. Decarbonizing natural gas supports a long-term supply of reliable and affordable energy as well as the production of clean fuels. We're developing a 3-hub CCS and clean fuel strategy across our operating footprint in Australia and Timor-Leste. Our Moomba CCS project, which will be one of the biggest new world paves the way for a significant carbon reduction and storage story for Santos and for Australia. The project is 40% complete and on-track for first injection of CO2 next year. We also look forward to commencing trials of Direct Air Capture technologies in the Cooper Basin later this year. These technologies could have success to leverage our significant infrastructure, CO2 storage capacity and Moomba CCS project to build a new carbon reduction business for Santos that also helps other industries decarbonize. FEED studies on the Bayu-Undan CCS projects are nearing completion and engagement with governments and regulators continues. Bayu-Undan provides a potential CCS hub for the region with a capacity of 10 million tonnes per annum. In Western Australia, we are undertaking feasibility studies and working with potential customers for CCS services, utilizing our existing infrastructure and offshore reservoirs. Let me finish with some further comments on energy and the role for gas. Russia's invasion of Ukraine brought global energy security into the spotlight, particularly for natural gas with higher prices and a supply crunch in the wake of rapidly recovering demand. Gas remains a critical fuel for an orderly energy transition, but we must invest in new supply. People still need to have access to affordable energy, which requires more gas supply, not less. LNG demand is at record levels with under-investment driving significant price increases as we have seen in Europe and limiting access to energy for those who can least afford it. In the Asia-Pacific, LNG demand is expected to double by 2040, according to Wood Mackenzie. As a leading global independent LNG supplier, Santos is well positioned to benefit from this increasing demand. With our Japanese and Korean partners, we are investing significant capital and bringing new supply to market through Darwin LNG from Barossa, but we need stable regulatory and fiscal regimes to enable this and any future investments in Australia. We are however, facing unprecedented government intervention in domestic gas markets here in Australia. This, combined with ongoing challenges in securing regulatory approvals for the development of new resources puts at risk future supply of the critical fuels needed to meet ongoing support and strong demand from our customers. These challenges are shaping our corporate strategy and the allocation of capital to prioritize shareholder returns and investment in sustaining development, along with the need to maintain a diversified and balanced portfolio of assets. They have strengthened our resolve for Santos to be a low-cost, high-performance business throughout the cycle and to become a global leader in the transition to cleaner energy and clean fuels that are both affordable and sustainable. In summary, it was a great year for Santos. I am pleased to present a record set of financial results. Record operating performance drove strong free cash flows and delivered higher returns for shareholders. The business is running well. We have created a global energy company of size and scale. With size and scale comes the opportunity to accelerate our aspiration to become a clean fuels company and reaching our net zero commitment by 2040. We have been and remain unrelenting in sticking to our strategy and implementing our disciplined operating model, an operating model that has proven its value by delivering consistent results, keeping the business resilient and performing strongly. With that brief opening, we would now be happy to take your questions. Thank you.

[Operator Instructions] Your first question comes from Tom Allen with UBS.

Can you please provide an update on when you expect to complete the sell-down of PNG LNG, in particular, some color on what's driven the delay and what risks you see, if any, around Kumul being able to fund the additional stake?

Look, as you're aware, we've announced the extension to their validity period for their offer through to April. And consequently, that gives them the time then to complete the waivers they require for the preemptive rights from other partners and, of course, to complete their financing for them. In our interactions with Kumul, everything seems progressing on plan. And we have no reason to doubt that, and we'll keep working with them to complete on that schedule. There's nothing else I can really say. Any other question about their process is really a question for Kumul.

And then maybe sticking with timelines. Can you please provide an estimate of the timeline to resume drilling at Barossa. So when do you expect to resubmit the drilling EP, some color on the other key unknowns? And I guess, importantly, what is the date that if you hadn't resumed drilling by Barossa, it could crystallize the delay to first gas?

Well, Tom, I think that's a very comprehensive question. I'm sure you're going to understand why I don't want to go into too much detail on those timelines. The bottom line is we are progressing on all remaining approvals, including the drilling AP. And we will continue to work to our schedule to do that. I'm not going to set any public deadlines on that, because I can't. We're working with the regulator and the rest of the industry is in the same space. But we've commenced the consultation processes and the engagement with our TV Island stakeholders and other stakeholders for that matter. And that's going well at this stage. We'll continue to do that. And as soon as we have something more material to announce, we will do.

And then just finally, perhaps on production costs, maybe an easier one. 22 upstream production costs ex-Bayu-Undan were $6.80 a BOE. I think this year, Santos is guiding to $7.25 to $7.50 a BOE. I was hoping for some color on the drivers of higher production costs and which assets specifically are attracting those higher unit costs.

Well, look, maybe Anthea, I want to put a bit more color on that, and I'll give her some work to do here this morning in a second. But look, I think it's a function mainly of unit cost because volume is dropping, right? So our production volumes are dropping, as you'd see from our market guidance as WA comes back a bit. Obviously, we've lost Bayu-Undan, an ongoing asset and consequently, the unit costs go up as our volume comes down. We expect to see that go the other way in a couple of years' time, of course, when the new projects come online. But Andy, do you want to add to that?

Yes. Well, I think, I mean, you’ve stolen the glory on the production cost. I think we are trying to hold nominal production cost as stable as we can. So the driver between the difference from 2022 to '23 is largely as a result of reduced production in WA, particularly.

Next question comes from Dale Koenders with Barrenjoey.

Kevin, I was hoping you could provide some comments around your outlook for excess cash flow going forward from the organization and [indiscernible] bigger start-up really with a strong cash result and dividend announced this morning. You've given free cash flow breakeven of $34 a barrel in '23. Is that reflective of the business over the next few years? And then major CapEx of $1.8 billion in '23. Is it fair to assume something similar going forward Papua, Dorado, Narrabri, CCS, all are sanctioned and the balance of those 2, what does that mean for potential for programmatic buybacks going forward?

Look, I think that is for actually a bit higher than I would have liked. Again, it's a bit of a consequence of the volumes dropping off, driving a large chunk of that. So as those volumes come back up, we would expect to see that unit cost at breakeven come down. Obviously, there's a bit of inflation, and there we're seeing inflation globally. Although generally speaking, our operations are managing that very well, managed to absorb a lot of that, and we've been doing that now for a few years. But I think 34 is not a bad guide somewhere between 30, 34 for the next couple of years. I then expect to see that come back as we get the production coming on at 25, 26 from Barossa and from Pikka. We should see that drop down quite significantly then. And maybe you want to repeat other parts of the question. That's the free cash flow part.

What's the right level of CapEx going forward for major growth projects, $1.8 billion in 2023.

Well, look, I mean, we've given -- I mean, the way we sort of think of that deal is that we think about our gearing range that we want to operate with and stay within that gearing range, right? And so it's very much that 15 to 25 range that we put out there previously as part of our operating model. And if we go below that, we'll probably -- if we're able to go below that, we'd probably be in a position where we'd be giving more returns to shareholders in that instance. And if we go above that, then our focus would be very much on getting back down below that as quickly as possibly can. And so that is a target range that we're planning to operate in and that sort of determines when FID projects and how we prioritize the next round of growth projects.

Okay. So it really is a balance between excess returns and growth or getting the right balance between those 2 still?

It's just trying to maintain that rate balance. That's right.

Okay. And then just second question, GLNG, 350 to 400 wells in '23. What does that do in terms of the outlook for production, given previously spoke about sort of 200 to 300 wells to sustain 6 million tonnes per annum?

Yes. Well, look, I mean as you saw, we drilled a fair few wells last year, not as many as we wanted. We were impacted by the floods a little bit. We were hoping to drill a few more wells than we got down last year. The drilling levels we have over the next few years should maintain or slightly even increase organic production across the facilities. And ultimately, if you think of organic production replacing third-party gas over-time, that's effectively the GLNG model. And so yes, we're still giving guidance to maintain around 6 million tonnes per annum. However, the one thing I would say, Dale, is that we've also seen with some of the horizontal wells we've been drilling in Queensland, some very impressive rates from some of those wells. So that gives us a lot of confidence for what we're doing going forward in terms of potential higher conversion rates in the future from 2C.

Your next question comes from James Byrne with Citi.

Just wanted to talk on PNG LNG. So we obviously saw 8.6 million tonnes of production from the asset last year. Hard venturing decline, that's going to be offset by Angore. I understand the drilling there is late, which I think has been flagged historically. I want to get an understanding of how good your visibility is on when Angore's going to be tied in. Like I'm a bit worried that maybe it's a little later than the market expects in volumes for 2024 could be lower? And then sort of beyond, as I think about now that Hides is in decline, do you think that, that sort of mid 8 million tonnes per annum is still achievable going forward or is that maybe now a sort of peak production is behind us in that asset because I think the market is potentially overestimating production from the asset. And I just want to have you sort of clear that up for us because obviously, the excess production goes into JKM, so there's a big sort of cash flow implication, if that's true.

Yes. Look, our target is to maintain around the Middle East here, James, until we get on Angore and we could keep it flat all the way through until the next expansion project. So that is a target. You're right though. There's been some problems in the early slot recovery operations on Angore on the 3 wells. However, they seem to making good progress now. And as I always say, we're drilling, it is bit like a cricket match. You don't make your call after the first team bat, you've got to let both teams bat before you make your call, right? And the drilling is a bit like that. So they had problems early on in the slot recovery in the milling operations. But as I say, the drilling seems to be picking up now. So we'll see how to do over the next few months. But we're still aiming for and as are the operator for those wells to come online in 2024.

And then secondly, I wanted to ask about Bayu-Undan, CCS and safeguard mechanisms. Do you think it's likely that the CCS project is going to be ready for first gas at Barossa. And if not, then you have to sort of rent that CO2 then under the new safeguard mechanism, would you expect to be above your allowance there? And how would you look at offsetting that versus, say, taking penalties?

Yes. Well, look, I mean, the safeguard mechanism is something that we've been engaging with the government and we've given our feedback to the government on. And obviously, it's not finalized yet. It's still got to go through and get ratified. And so the final version will be what it will be and let's wait and see what that is. But based on our current understanding of what that looks like, we would have the ability for Australian assets to use any SMCs or safety mechanism credits we get from one asset to support another asset. And so that gives us the ability then to take lower cost SMCs, if you like to avoid planting somewhere else. And Barossa is likely to come on-stream, and we would imagine within the first 2 years, the CCS project we ticking, that's what we're aiming for. So not really expected looking at current schedules for that to be there on first gas. However, so in that time, there will be some exposure. But we have to wait and see what that looks like, James, and understand what the extent of that is, what the baseline is, what the baseline would be set at. Remember also that there's also the concept of exposed industries or assets being protected against any negative impact. So we just have to wait to see how that plays out, but I'm pretty confident that across our assets, if we are able to aggregate which the versus we've seen indicate that we should be able to do, we'll be able to use credits that we generate elsewhere on other assets, we will be comfortably below baselines to cover other assets.

I guess just lastly, quickly on Dorado. What do you think is needed here to get a commercial project? Obviously, historically, the FPSO CapEx was a disappointment. So how much leeway do you have on being able to get that down against an inflationary cost environment globally and therefore, how much is relied on the concept. I noted in the presentation seems to imply that you need to appraise Pavo before you'd be able to enter feed. So it seems like feed entry might be some time away, but at least that enables the potential for a commercial project. Am I thinking about that correctly?

No, I don't think we've said we have to praise it before we take feed, I think, possibly before FID. We're doing that work on the concept now, James, and I'm hoping that this year, we'll lock all that down. And it's really about taking the sort of liquids project concept we had and making a more integrated project and having a plan for developing the gas in the basin along with that and bringing that back to the infrastructure down in WA. And ultimately, we think that will make it a stronger project for the longer term. And if we can utilize existing infrastructure, we think that will be a good long-term investment, a higher rate of return investment for us. I'd like to start by pointing out too, we just recently got the Dorado OPP approved by the regulator. And just I think it was a week or 2 ago, we got the approval on the OPP for the current project proposition. And I'd also like to just congratulate Adrian and the guys at an tech [ and over ] this morning for their announcement. And I think that does provide further evidence that is a good project. I believe it's a very strong project. We're quite excited about doing it. But if I go back to the previous question, of course, we'll aim to FID that project at the right time as we progress our other projects, and it's all about balance across the portfolio.

Your next question comes from Adam Martin with E&P Financial.

Just on sort of M&A strategy, the business has done, I'd say, quite well over the last 5 to 6 years around M&A, matures out on the gross at the moment, but assuming you deliver there, that should do well. But how are you thinking about M&A in the next few years, particularly given that balance sheet is declining in terms of debt and you've obviously got the other option of paying out more capital to shareholders as well. So perhaps you could talk through that, please?

Well, Ad, I mean we'll always be open for the right deal if we think it's going to add value and be accretive for shareholders. So we're never going to say we're not going to do something. If we're going to do something, and it's not known about, we're not going to announce it on an investor call either that we're thinking about doing it. But what I would say is that we've got a lot on our plate right now as a company, and I want to stay very focused on delivering on our plans. We've got Barossa to deliver, and we've got some activist led challenges there that we're working their way through, and we're working closely with the regulator, we're working with our partners and our stakeholders to get that project delivered and I am committed to delivering on that project. We've also got, obviously a Pikka project to deliver. We want to deliver. That's a great project. And so our focus over the next couple of years really is maintaining the core business, the base business, because of the earlier decline in WA, it's very important to me that we do prioritize locking down the backfill and sustained strategy for those assets and getting that conveyor belt of new backfill opportunities moving in WA. And of course, I'd see Dorado being -- Dorado and Bedout Basin as you'd see being part of that. So a lot of organic activity. So without saying that we're looking for anything, we're always open to the right opportunity. We've got a strong balance sheet. And if the right opportunity was to opportunistically appear in front of us, we would consider that. But there's no active sort of M&A initiatives that we're pursuing at this point in time.

And just second question, just on [indiscernible] mentioned on their conference call recently, they're looking at about 30% spots. That product seems to be getting some momentum, but just how are you thinking about the right level of spot in your business going forward, please?

Yes. Well, look, I mean, we are working through that marketing strategy for the project. We expect to take FEED on that project, as I said earlier in a couple of months' time. But yes, it's equity marketing. So every company will do their own marketing on that project, and we'll make any announcements as we do our marketing activity at that point in time. The project, of course, is likely to have a significant portion of it project financed, and that kind of an impact on your marketing strategy also.

Your next question comes from Saul Kavonic with Credit Suisse.

I have a few questions. My first question, if I could direct it perhaps to you, Anthea. Thanks for providing the kind of CapEx and breakeven and sensitivity to oil price outlook. Now on my quick math, if I look for the period, say, through from today to end of 2026 at an $80 oil price using your sensitivities, I get about $8 billion in free cash flow. That would be about $5 billion after your 40% capital management policy, and you've outlined $3.6 billion in growth CapEx. So that leaves about a $1.4 billion surplus, but then you've got a few billion dollars to spend on Papua, buying CCS, capitalized interest, maybe Dorado and Narrabri, FID any of these things, which would push gearing back up to the top end of the range. And that all assumes $80 a barrel when nothing goes wrong. So the question really is, is Santos' actually able to fund a Papua and buy CCS on their target schedules in a stress test case to say, $60 whilst maintaining existing gearing and capital management policy. And what is Santos' options to fund Papua and buy CCS in the event that PNG LNG sell-down were not to occur and oil were to soften.

I think the very short answer to that is we're comfortable with our balance sheet settings. We manage the balance sheet to the gearing range of 15% to 25%. We phased and sequence our projects to make sure that we stay consistent with that. So we do look forward under a range of oil prices, low prices and high prices to understand where we might sit within that range, and we're comfortable we can manage the balance sheet to provide shareholder returns as well as invest in our growth projects and the LNG transition. Having said that, those projects will face a sequenced and the equity interest and those managed accordingly.

And can I just add to that, Saul. Obviously, if there was a major setback in commodity prices by not FID-ing everything at once and phasing and sequencing those activities, we would always want to retain the ability to slow stuff then if we had to. And so you're right in the context that if the world fell apart, we would change the plan.

Perhaps on that front, in the event oil was to soften, are you able to provide some color on what the debt covenants are that are most at risk?

We don't provide details on our debt covenants. But we do predict going forward, we do a lot of portfolio planning. We stress tested stress prices as well as low prices and there's very few scenarios where we're really at risk of compromising our debt covenants, given the levers that Kevin just mentioned and being operated with the majority of that growth project is helpful for that too because we do have that level of control over how we might contract and how we might phase and sequence activities. We do stress test quite regularly against covenants, et cetera.

They're very loyal.

At lower prices, yes.

My next question is just on the governance front, directed to you, Kevin. It's about your incentive, the $6 million growth award that was allocated a while back, which is now season has been amended to include Pikka in addition or instead of delivering Dorado post the merger with Oil Search. So 2 questions that is, I guess, the delivery of Dorado by 25 was a core plank of the regional growth award and Dorado is no longer to be delivered by 25 almost on any circumstances. So the question is why you negotiated the change to the awards to still allow the full what is best despite not being able to deliver Dorado. And can you confirm is it actually possible if you do receive all of your growth award for that to vest before actually delivering Pikka or Dorado, given the both target start-up beyond the end of 25, which is the vesting date for your yard.

Look, Saul, I don't think it's appropriate for me to comment on board decisions other than I didn't negotiate anything. But I think the question is best directed to the Board.

Last one, just quickly on policy. The ADGSM kind of guidelines that have come out recently and this is section at the back, which almost suggests that the government is going to insist projects like GLNG would have to either purchase export approval permissions from an AVA or purchase spot LNG cargoes to meet their long-term LNG contracts before the government would come in and provide additional export permissions. Do those cause us suggest there is risk that the government could force GLNG to purchase spot cargoes to export permissions from neighboring projects in the event the ADGSM is triggered?

Look, I mean, we're still consulting with the government on the ADGSM. I am familiar with the clauses that you're referring to. I think what I'm pleased about is the comments from the government supporting contract sanctity because we've always maintained that contracts have to be protected. And so it's good to hear the government making those points very consistently and very loudly. Look, I think without trying to guess what it ends up being, I think it's very unlikely you'd ever be forced to do anything that's uneconomic. And so typically, when we get into these agreements with governments, there's also a commerciality standard or test that goes with any of those steps in any of those processes. In other words, you could be required to do certain things, but only if they're commercial.

Is it by definition, forcing volumes that could be sold at a higher price into a lower-price domestic market on conversion?

That's correct. Which is what I'm saying. My expectation would be that that would be unlikely to be a requirement.

Your next question comes from Mark Wiseman, Macquarie.

I just had a question on Varanus Island. It's good to see those production rates getting back up around 200 terajoules a day. I was just wondering if you could provide a bit of a guide as to once Spartan comes on, what sort of rates you're expecting and the comments there around future backfill projects. Is that about servicing existing contracts and keeping production in that range or is it about actually lifting VI back towards its nameplate.

Well, let me just get that the opposite around there. The second part of your question, I'll address first. The backfill project is really about lifting WA production back up to higher levels. So take the back up. Spartan should take us back up to -- it produces on plan around the 275 mark daily production rate, although we'll have to wait and see because the deliverability on test was excellent. We might get higher rates from that well. We'll have to wait and see when it comes on. But certainly from a well testing point of view, the permeability and the flow rates during the testing were higher than we had anticipated. So it was a real high side outcome for us in that respect. But I'd say I'd guide you around $275 per day at this point in time. And as I say, the backfill projects that we're looking at developing there at Varanus Island would be about bringing production up overall for the longer term. And on the contracts, the current reserves we have there give us full contract coverage.

And just one for Anthea. Just on the project finance for Papua LNG. I appreciate given your equity interest, it's not a huge investment in the context of the business. But could you maybe just talk around those project finance around that funding market? What sort of debt equity split should we be thinking about there?

I think that's a level of detail that's still being worked through. So obviously, you want to maximize the debt levels within those project finance facilities. We are seeing some strong support from the banks potentially. But really, that process needs to play through to proper finance launch and book build from there. So it's hard to comment with specifics at the moment.

Your next question comes from Nik Burns with Jarden, Australia.

Look, I might just follow on Mark's question on WA Gas and particularly the backfill opportunities there. Just thinking about like Spar, Deep and Corvus, are they classified as undeveloped reserves in your reserve statement. I note that around 1/3 of your reserves are classified as undeveloped. So is that bringing those reserves to market or is that part of the 1,400 petajoules of gas contingent resources you flagged last week? And just trying to think about the investment required to bring this gas to market. You are carrying a high equity level there. Just thinking about when you're planning to go after this and when we should be thinking about that investment coming through.

No, I'm sure I'm going to pretty sure that Spartan was undeveloped 2P. So we've never developed, we've spent the money to do that. Corvus, Spar, Deep, that is all 2C. That's not undeveloped or developed 2P.

And when do you plan to bring that to market?

Well look, I mean, I think it's a bit early to say that, Nik. We hope to get some guidance on that throughout the year. But we just have to sort of do that work and get these things. I see which one is going first, right? And so we'll come back and give guidance on that once we work those opportunities up.

And just on your comments earlier about Carnarvon's announcement this morning on the Dorado sell down. Can you just talk about whether you have any preemptive rights in relation to that transaction and where you're up to in relation to your own proposed sell-down? Is it the right time for you to sell down or do you think it's probably closer to FID, i.e., next year?

Well, look, I mean, I'm not going to give any guidance on when I'm looking to do any sell-downs or anything like that, been there before, haven't we? So what I would say is that it was a good announcement. It shows that even in these tougher times that attractive projects can be sold down, there's interest out there to buy into good projects. And again, I'll congratulate Adrian for that deal. And by the way, it was a very credible joint venture partner. I mean we're pleased to welcome CPC to the joint venture, and we look forward to working with them to move this asset forward. I think I just take encouragement, Nik, from the fact that a good credible buyer has bought a significant stake in the project. And on sell-downs when we've got something to announce, we'll announce that.

RBC Capital Markets.

It's Gordon. Kevin, the PNG government made a statement about the pool LNG possibly moving forward with 4 many liquefaction trains instead of the 2 that has initially proposed for the project. Can you possibly comment on potential cost savings from doing that?

Look, that's right, Gordon. They did make that public statement. I think Total has probably said something about that as well publicly. We'll have more detail on that when we get to the FEED decision, and we'll be able to take you through or take the market through the details of that expansion project. You're right. It's rather than the big expansion trains, it's smaller trains and using some capacity from the existing project. What I would say is that you're also right in saying that, that delivers some CapEx savings and we think they're quite significant. But what we'll do is we'll wait until the operators and our sales take FEED, and then we'll give you more detail on what the quantum and the economics of that look like, other than for me to say it looks very attractive. It looks like a good project.

Just on Barossa, has Santos made its environmental resubmission yet or are you still in the kind of the consultation phase on that?

We're in consultation phase. We're working with all of the stakeholders. And I have to say, I've been pleased with the start of that process. We're not going to give any updates on the progress of our plans and our various steps along the way until we get the approvals to move forward. And I mean, that's all I can really say, Gordon. We're progressing it, progressing as fast and as hard as we can, but doing it as per the new guidelines.

There's been some commentary on the pipeline way possibly being delayed. Can you say anything there? We obviously know what's going on with the drilling.

Yes. The pipeline, we made announcement on that not so long ago, but basically, the pipeline activities are likely to be delayed, but not to the point of impacting critical path. But what I can say is that's not because the EP has been pulled. That is basically our management of change activity and we're managing that business as usual.

Next question comes from Mark Samter with MST Marquee.

I think I'd like to come back to the balance sheet answer, if I could. And I'm slightly boggled by the question you were asked because, I mean, gearing sub-19% maybe sub 15% by the time you sold down PNG LNG. You go back to the middle of 2020 when gold was $40, and gearing was 34% and you still have said your covenants allowed headroom for a number of years have all at that level before they were breached. I mean, am I missing something? Have debt covenants changed terrifically or is literally the last thing this business needs to worry about, is it breach to debt covenants and capacity?

Yes. Look, I'll hand that to Anthea, but just before I do, I mean, I'd make the point that in the scenario testing that we've been doing, we've been doing this for years, right, because I'll go back to the business that we inherited back 2016, and I'm not slanting anybody who was here before me. But obviously, that was a world of pain. I think we're at $26 oil, and the balance sheet was pretty weak at that point in time. And we put in place processes for the business then that would ensure that we're going to maintain a lot of headroom against covenants to never put us in those nervous positions again. I can assure you there's lots of headroom. And you're right. In March 2020, when the peak of COVID, we still had a lot of headroom. And that would be the case if we got a COVID pandemic type outcome, again, we would still have a lot of headroom. And we maintained -- we run the business that way. Anthea, you might want to talk a little bit more specifically to that.

Yes. So we do monitor at each kind of board. We look at capital management. We look at our sensitivity to covenants and also to credit rating metrics, et cetera, gearing metrics. So it is very closely monitored, but also very closely forecast into the future under different development scenarios from a CapEx perspective at a different oil price scenario as the market is very difficult to see a scenario where we could get in trouble from a covenant perspective, even at very low prices. And a part of that also is because of the disciplined offering free cash flow [indiscernible] under $35 per barrel. So which does say when oil prices go down, the base business can still generate revenue on the way through. So that's kind of -- we do manage balance sheet accordingly.

I guess it make to market, isn't it? I'll give you a hard time for not turning enough money, people panic about that you’re going to breach your debt covenants. [indiscernible]

It's not something we're worried about.

I guess, I don't think you got a comment on this, and I think you touched on it just with the Dorado sell down. Maybe it's a surprise, I would think, to a lot of people that being able to sell a stake in that asset and I guess you're probably not going to comment more on your plan, it is probably a validation that there's a lever to pull as well if you did want to pull a leave on Dorado server.

Well, I think that's right, Mark. And it's a credible buyer, right? It's a Tier 1 buyer. We were very pleased to see that transaction go through, and I think it gives us confidence that there's people out there who look at this project and see a very solid and valuable project. And you're right, it gives us a lever. I've made the mistake in the past and very kind of open to learning from mistakes, but made mistake in the path of saying what I'm going to do in the future and sometimes you can't predict how those things play out. And so I'm not going to do that. But what I will say is, of course, I'm pleased that I see that, that lever is available to us. And if we have anything to announce on that, we'll announce it if and when we do it.

I'll just ask one question, Adam asked question about offtake contracting. I think I'm right in saying in the release on the offtake of Barossa, Mitsubishi has the flexibility to be resold. I'm not sure that's connected markets pricing effect, but JKM is down to $14. As of today, it's just about down at contract price. I'm saying it stays there. But I mean a, just you look at those Barossa volumes and b, would it be realistic even if you chose to re-contract those volumes or would you wait until drilling restarted and even move some of that execution risk around it.

Well, the good thing, as you point out, the Barossa volumes is there's no penalties or liabilities that go with the deliverability of those volumes. And so we have the ability to re-contract up to all of the 100% of those volumes or any part thereof over-time. So it's a very, very flexible contract. So you're right, the JKM-linked contracts. We're pretty happy with those contracts and the amount of interest in -- sorry, contracting LNG from our portfolio more generally. So we've got a lot of interactions with Japanese, Korean and other Asian buyers, looking across the portfolio rather than any one project and of course, the Barossa volumes can play into that, right? So we have a lot of flexibility. We're not in a rush to do anything. And again, we'd announced that Mark, if we see the right offer and the right opportunity, we contract it, we'll announce that when we do it, yes.

Your next question comes from Henry Meyer with Goldman Sachs.

Just a follow-up on Barossa, please. Conscious you can't provide details on the timeline for when you may need to start drilling again, but could you share any details on perhaps the flexibility you have in the schedule with a number of wells drilled in Phase 1 versus Phase 2? I believe Phase 1 had up to 6 to 10 wells in the original development followed by Phase 2, 4 years after first production. Is that still the right way to think about the development or do you have flexibility to perhaps do a reduced Phase 1 campaign and perhaps accelerated Phase 2.

The Phase 1 drilling we were planning to do with 6 wells and 2 of those wells were actually contingent wells. So our additional capacity wells. We need 4 wells to produce at capacity. So that does give us quite a bit of flexibility on how we want to execute the plans. But I don't want to get into too much detail on the execution plans. Obviously, what that's allowed us to do is move things around a bit. And that's exactly what we've been doing to ensure that we can keep the critical partner. At this point in time, if everything proceeds to our expectations and our aspirations with respect to the new approvals we have to get, we still believe we can deliver this project first half 2025.

And over at GLNG, I think over a year, you're seeing improved operational performance, 6 year meantime the well is pretty incredible, obviously, accounting for bit survival by some data coming through. With Arcadia Valley stepping up this year, do you see more opportunities in the field to actually debottleneck production facilities and perhaps increase throughput at [indiscernible]? And the joint venture I think you have potentially increasing production there if they did need to supply more into the domestic market?

Look, I mean, first of all, let me just echo your points on the operational performance at GLNG. I really want to take my hat off to all of our operators across our Queensland operations. They do a fantastic job from an integrity, safety and uptime performance. But more than that, the learning culture that they've built over the years to continually strive to improve. And that's what you've seen in those meantime to full year numbers that we've reported in the pack. I'm really glad you've asked a question on that because a great indication, I think, of the culture. Now one of the reasons for that is that this is a project that didn't have enough gas to fill the plant up to capacity. So reliability of wells and cutting costs through work-overs, the number of work-overs required to keep wells working was a high focus for us. We're seeing the same sort of impacts in the drilling with the horizontal well, as I mentioned earlier, and some phenomenal rates, even infill wells in the Fairview area that we've drilled last year, some phenomenal well rates from CSG wells. So look, I think overall, that gives us upside opportunity. We need to see -- it's hard to quantify what that may or may not be at this point in time, but it gives me a lot of confidence. There's a lot of too severe that we can convert if we can keep the drilling unit cost down. And you can see those Roma well costs, I mean, it's quite incredible even with inflation over the last few years, we are still be able to maintain those wells under $1 million per well. So it's something we're really proud of. We just got to keep doing it. I'm not going to make any forecast on what that's going to do. The guidance is still 6 million tonnes per annum until it's something else. And so at this point most likely 6. But yes, I'm optimistic that there'll be some upside there in the future.

And maybe one final quick one if I can for Anthea. Just on the change in restoration assumptions. Will you be able to provide a little bit more color there, please? Is it primarily just a change in discount rate or risk-free rate assumptions?

So if you look at the underlying cost, there's 2 drivers for that. One is scope, and the other one is cost. So from a growth perspective, we've factored in for removal other than [indiscernible] flow lines are assumed to be fully removed. And there has been some inflationary costs going in there as well. But the main driver is kind of scope and cost. And I suppose noting that 221 that went through the P&L was related to assets that aren't producing anymore. So any cost increases to those provisions get taken straight to the P&L, which is a little bit different to the treatment for Varanus Island, which you saw we impaired that asset because it's still producing. And then it needs to be written-off as an impairment.

The next question comes from Daniel Butcher with CLSA.

Kevin, just first I wanted to quickly pick up on something you said earlier about the 4 small trains at Papua LNG may also use some of the existing projects. Should we take away from that, that the project might be downsized slightly at the upstream level -- sorry, at the downstream level for the trains and maybe produce a bit more at the back0end to backfill PNG LNG.

Look, I think Dan, I wouldn't speculate too much on what that means. It may mean pushing a bit of PNG production out. And obviously, PNG LNG would have to be compensated if that was the case for that. So we'll be able to give you details of that on FEED announcement when we get there. And we'll give you a comprehensive sort of explanation of what that all looks like once we've finalized all the agreements and we take FEED.

Second question, just on Cooper Basin, obviously, some years ago, you gave a target of a certain level of production that you want to maintain to turn in 208, hasn't quite gotten there. I'm just curious if you could give us a bit of a steer on what sort of production rate on 5 rigs you didn't get to in the foreseeable future, either next year or a couple of years out, please?

Look, yes, that target is we sort of got to the front end of that target very, very early and then COVID got as you would remember, and all the CapEx got and we came back in the last couple of years. And I think it's just a great reminder the lesson to the Cooper Basin. It's all about the number of wells you drill each year. And if you can maintain 100, 100-plus wells, you can maintain and/or grow your production at the Cooper Basin. But when you drop below that, it drops-off pretty quickly. And so we're only really getting back now to that 100 wells. We got just over 100 last year. We're aiming for something around that level this year. And I want to see it building for a couple of years before I give any targets on it.

And maybe one quick final one or one or 2 very short ones. Just on your PNG LNG midterm volumes rolling off, you sort of implied they will be sold on spot or JKM this year. Is that the plan going forward or is it just because you haven't decided yet that you're selling them spots and that they might be re-contracted at some point in the future?

Yes. Look, our marketing guys are out there talking to the market. And there's a lot of interest in those volumes. We're in no rush, we're pretty happy at this point in time with JKM overall, debt more recently, but let's wait and see how it plays out over the course of the next 6 months or so. And if we benefit, we'll announce it then.

PNG LNG 2P fell by 27 million barrels over 2022, including production, but it developed 2P, one more than that, 42 million barrels. I'm just curious if you can recall or explain why some of the 2P PNGs back into developed category.

The only resource that I know has been written down in PNG with some exploration stuff. I'm aware of that Dan other than production volumes coming off. We can get back to you. I'll get Andrew Nairn to circle back on.

Rob Koh with Morgan Stanley.

Maybe just a quick question on the Barossa secondary approvals now that you have started the consultation with the Islanders. Can you share what Santos' learnings have been there from -- in terms of a local owner priorities?

Rob, I think those processes have to stay confidential. And hence, I'm not really able to kind of share what we discussed. I mean, I respect for our traditional stakeholders. We're not going to discuss what we're talking to them about until such times as we reach any agreements and/or get our approvals for the project.

There are no further questions at this time. And I'll hand back for closing remarks.

Okay. Well, I want to thank everyone for your interest in dialing-in and asking your questions this morning. Thanks again for your support throughout the year. And I look forward to catching up with many of you over the next week or so as we go around on our roadshow. Thanks very much.