Santos Limited 2022 full year results webcast. All participants are in listen only mode. There will be some opening remarks followed by a question and answer session. If you wish to ask a question, you'll need to press the star key followed by one on your telephone keypad. I would now like to hand the conference over to 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 customer 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. EBITDA 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%. 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 improved 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 six, a total of six Tier 1 and Tier 2 loss of containment incidents, with the more significant being a condensate leak from a loading line at Varanus Island in Western Australia. All Tier 1 and Tier 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 three LNG producing projects and two producing Australian domestic gas assets. Upstream produced record volumes in 2022 and delivered EBITDA 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 toward 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. 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 cargos from Darwin LNG. 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 will 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 reserves review, which includes external audit of approximately 97% of total 2P reserves. 2P reserves increased by 170 million barrels before production, providing an annual reserves replacement of 166% and three-year reserve replacement of 366%. Gas comprises 84% of 2P reserves and 75% of reserves plus resources. 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 Tiwi Islands earlier this month. The sessions were designed to provide information as well as help Santos understand firsthand 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 I project is progressing to plan since we took FID last August. Phase I 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 one and two 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 three 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 in the 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, if successful, 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 project are nearing completion. Engagement with governments and regulators continues. Bayu-Undan can provides a potential CCS hub for the region with a capacity of 10 million tons 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 underinvestment 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 in bringing new supply to market through Darwin LNG from Barossa. 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 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 this 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. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you're on a speaker phone, please pick up the handset to ask your question. Your first question comes from Tom Allen with UBS. Please go ahead. Hi. Good morning, Kevin and Anthea. 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? Thanks, Tom, and good morning to you. As you're aware, we've announced the extension to their validity period for their offer through to April. Consequently, that gives them the time then to complete their waivers they require for the preemptive rights from the other partners and of course, to complete their financing for that. In our interactions with Kumul, everything seems progressing on plan. You know, we have no reason to doubt that, and we'll keep working with them with that, you know, 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. Okay. Okay, thanks for that, Kevin. Then maybe sticking with timelines, can you please provide an estimate of the timeline to resume drilling at Barossa? So when you expect to resubmit the drilling AP, you know, some color on the other key unknowns. I guess importantly, what is the date that if you hadn't resumed drilling via Barossa, it could crystallize the delay to first gas? Well, Tom, I think that's a very comprehensive question. I'm sure you're gonna understand why I don't wanna go into too much detail on those timelines. The bottom line is we are progressing on all remaining approvals, including the drilling AP. We will continue to work to our schedule to do that. I'm not gonna 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. We've commenced the consultation processes and the engagement with our Tiwi Island stakeholders and other stakeholders for that matter. 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. Okay. Okay, that's clear. I won't go any further on that one. Just finally, perhaps on production costs, maybe an easier one. 2022 upstream production costs, ex-Bayu-Undan were $6.80 a Boe. I think this year Santos is guiding for $7.25-$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 will wanna put a bit more color on that. I'll give her some work to do here this morning in a second. Look, I think it's a function mainly of unit cost, because volume is dropping, right? 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 now as an ongoing asset, and consequently, the unit costs go up as your volume comes down. We'd expect to see that go the other way in a couple of years' time, of course, when the new projects come online. Anthea, do you wanna add to that? Yeah. Well, I think, I mean, you've stolen the glory- Sorry. on the production cost. I think, we are trying to hold nominal production cost as stable as we can. The driver between the difference from 2022 to 2023 is largely as a result of reduced production in WA, particularly. Okay. Thanks, Anthea. Thanks, Kevin. Appreciate that. Cheers, Tom. The next question comes from Dale Koenders with Barrenjoey. Please go ahead. Morning, Kevin. I was hoping you could provide some comments around your outlook for excess cash flow going forward from the organization until Barossa and Pikka start up, really with a strong cash result and dividend announced this morning. You're giving free cash flow breakeven of $34 a barrel in 2023. Is that reflective of the business over the next few years? Major CapEx of $1.8 billion in 2023. Is it fair to assume something similar going forward if Papua, Dorado, Narrabri, CCS all are sanctioned? The balance of those two, what does that mean for potential for programmatic buybacks going forward? All right. That's a lot of questions, Dale. I'm not sure I'm gonna be remember all of those aspects, but let me try. Look, I think the 34, that's 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. As those volumes come back up, we would expect to see that unit cost, that break-even 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'll be doing that now for a few years. I think 34 is not a bad guide, somewhere between 30, 34 for the next couple of years. I'd 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. Maybe you wanna repeat other parts of the questions. That's a free cash flow part. What's the right level of CapEx going forward for major growth projects, $1.8 billion in 2023? Well, I mean, we've given I mean, the way we sort of think of that, Dale, is that we think about our gearing range that we wanna operate within and stay within that gearing range, right? It's very much that 15%-25% range that we put out there previously as part of our operating model. You know, if we go below that, if we were able to go below that, we'd probably be in a position where we'd be giving more returns to shareholders in that instance. If we go above that, then our focus would be very much on getting back down below that as quickly as we possibly can. That is a target range that we're planning to operate in. That sort of determines when we FID projects and how we prioritize, the next round of growth projects. It really is a balance between excess returns and growth or getting the right balance between those two still. It's just trying to maintain that right balance. That's right. Okay. Just second question. GLNG, 350-400 wells in 2023. What does that do in terms of the outlook for production, given you previously spoke about sort of 200-300 wells to sustain at 6 million tons per annum? Yeah. 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. Ultimately, if you think of organic production, replacing third-party gas over time, that's effectively the GLNG model. Yeah, we're still giving guidance to maintain around 6 million tons per annum. 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. 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. Okay. Thank you. Cheers. Thanks. Your next question comes from James Byrne with Citi. Please go ahead. Morning, Kevin and Anthea. Just wanted to talk on PNG LNG. We obviously saw 8.6 million tons of production from the asset last year. Hides is entering decline. That's gonna be offset by Angore. I understand the drilling there is late, which I think has been flagged historically. I wanna get an understanding of how good your visibility is on when Angore is going to be tied in. Like, I'm a bit worried that maybe it's a little later than the market expects, and volumes for 2024 could be lower. You know, sort of beyond, as I think about now that Hides is in decline, do you think that that sort of mid-8 million tons per annum is still achievable going forward? is that maybe now a sort of, you know, peak production is behind us in that asset? I think, you know, the market is potentially overestimating production from the asset, and I just wanna have you sort of clear that up for us. Yeah. Obviously the excess production goes into JKM. There's a big sort of cash flow implication if that's true. Yeah. Look, our target is to maintain around the mid-eights here, James, until we get Angore on and we keep it, you know, we keep it flat all the way through until the next expansion project. That is a target. You're right, though, there's been some problems in the early slot recovery operations on Angore on the three wells. However, they seem to be making good progress now. As I always say with drilling, it's a bit like a cricket match. You know, you don't make your call after the first team bats. You've got to let both teams bat before you make your call, right? Drilling's a bit like that. They had problems early on in the slot recovery and the milling operations. As I say, the drilling seems to be picking up now. We'll see how they do over the next few months. We're still aiming for, and as are the operator, for those wells to come online in 2024. Okay. Okay, great. Secondly, I wanted to ask about Bayu-Undan CCS and Safeguard Mechanisms. Do you think it's likely that the CCS project's going to be ready for first gas at Barossa, and if not, then you have to sort of vent that CO2. Under the new Safeguard Mechanism, would you expect to be above, you know, your allowance there, and how would you look at offsetting that versus, say, taking penalties? Well, I mean, the Safeguard Mechanism is something that we've been engaging with the government on. We've given our feedback to the government on. As you know, obviously, it's not finalized yet. It's still got to go through and get ratified. The final version will be what it'll be. Let's wait and see what that is. Based on our current understanding of what that looks like, we would have the ability for Australian assets to use any SMCs or Safeguard Mechanism Credits we get from one asset to support another asset. That gives us the ability then to take lower cost SMCs, if you like, to avoid penalties somewhere else. Barossa is likely to come on stream, and we would imagine within the first three years the CCS project will kick in. That's what we're aiming for. Not really expected, looking at current schedules for that to be there on first gas. However, in that time there would be some exposure. We have to see, 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 export exposed industries or assets being protected against any negative impact. We just have to wait to see how that plays out. I'm pretty confident that across our assets, if we're able to aggregate, which the versions we've seen indicate that we should be able to do, that we'll be able to use credits that we generate elsewhere on other assets, we will be comfortably below our baselines to cover other assets. Okay, great. That's really clear. I guess, just lastly, quickly on Dorado. What, what do you think is needed here to get a commercial project? Obviously, you know, historically, the FPSO CapEx was a disappointment. How much leeway do you have on being able to get that down against, say, inflationary cost environment globally? Therefore, how much is reliant on the concept? I noted in the presentation seemed to imply that you need to appraise Pavo before you'd be able to enter FEED. 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? I don't think we've said we have to appraise 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 of that down. 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. Ultimately, we think that'll make it a stronger project for the longer term. If we can utilize existing infrastructure, we think that, you know, that'll be a good long-term investment. A more, or 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. Just, I think it was a week or two ago, we got the approval on the OPP for the current project proposition. I'd also like to just congratulate Adrian and the guys at Carnarvon this morning for their announcement. You know, I think that does provide further evidence that it is a good project. I believe it's a very strong project. We're quite excited about doing it. 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, it's all about balance across the portfolio. Thanks, Kevin. Cheers. Thanks, James. The next question comes from Adam Martin with E&P Financial. Please go ahead. Morning, Kevin, Anthea. Just on the sort of M&A strategy. You know, the business has done, I'd say, quite well the last five to six years around M&A. Maybe the jury's out on the Barossa at the moment, but, you know, shouldn't deliver there. You know, that should do well. How are you thinking about M&A in the next few years, particularly, you know, given that balance sheet is declining in terms of debts, and you've obviously got the other option of paying out more capital to shareholders as well. Perhaps you could talk through that, please. Well, Ed, I mean, we'll always be open for the right deal if we think it's gonna add value and, and be accretive for shareholders. We're never gonna say we're not gonna do something. If we're gonna do something and it's not known about, we're not gonna announce it on an investor call either that we're thinking about doing it. What I would say is that we've got a lot on our plate right now as a company, and I wanna 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 our way through. We're working closely with the regulator, we're working with our partners, and our stakeholders to get that project delivered. I am committed to delivering on that project. We've also got obviously the Pikka project to deliver. We wanna deliver. That's a great project. 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 sustain strategy for those assets and getting that conveyor belt of new backfill opportunities moving in in WA. I'd see Dorado and Bedout Basin, I should say, being part of that. A lot of organic activity. Without saying that we're looking for anything, we're always open to the right opportunity. We've got a strong balance sheet. If the right opportunity was to opportunistically appear in front of us, we would consider that. There's no active sort of M&A initiatives that we're pursuing at this point in time. That's good. That's clear. The second question, just on Papua LNG. I think TotalEnergies mentioned on their conference call recently, they're looking to about 30% spots. That product seems to be getting some momentum. Just how are you thinking about, you know, the right level of spot in your business going forward, please? Yeah, 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. Yeah, it's equity marketing, so every company will do their own marketing on that project. You know, 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. You know, that can have an impact on your marketing strategy also. Okay. Thanks. Thank you. That's all from me. Cheers. Next question comes from Saul Kavonic with Credit Suisse. Please go ahead. Thank you. 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 outlooks. On my quick maths, 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, you've outlined $3.6 billion in growth CapEx. That leaves about a $1.4 billion surplus. You've got a few billion dollars to spend on Papua, Bayu CCS, capitalized interest, maybe Dorado and Narrabri, GFID, any of these things which could push gearing back up to the top end of the range. That all assumes $80 a barrel and nothing goes wrong. The question really is if Santos actually able to fund Papua and Bayu CCS on their target schedules in a stress test case to, say, $60, whilst maintaining the existing gearing and capital management policy? What are Santos' options to fund Papua and Bayu CCS in the event that PNG energy sell down were not to occur and oil were to soften? Well, that's a very long question, Saul. 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%-25%. We phase and sequence our projects to make sure that we stay consistent with that. We do look forward under a range of oil prices, low prices and high prices, to understand where we might sit within that range. We're comfortable we can manage the balance sheet to provide shareholder returns as well as invest in our growth projects and the energy transition. Having said that, those projects will be phased and sequenced and the equity interest in those managed accordingly. Could 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 down if we had to. You're right in the context that if the world fell apart, we would change the plan. Perhaps on that front, like 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 project going forward. We do a lot of portfolio planning. We stress test at stress prices as well as low prices. There's very few scenarios where we're really at risk of compromising our debt covenants, given the levers that Kevin's just mentioned. Being operator of the majority of our growth projects 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 the activities. We do stress test quite regularly against covenants, et cetera. At very low oil prices. At low oil prices, yeah. All right. Thanks. 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 it seems has been amended to include Pikka in addition or instead of delivering Dorado post-merger with Oil Search. Two questions on that is, I guess the delivery of Dorado by 25 was a core plank of the original growth award, and Dorado is no longer to be delivered by 25 almost under any circumstances. The question is why you've negotiated a change to the award to still allow the full award to vest despite not being able to deliver Dorado? Can you confirm, is it actually possible for you to receive all of your growth award for that to vest before actually delivering Pikka or Dorado, given they both target their start-up beyond the end of 25, which is the vesting date for the award? look, I don't think it's appropriate for me to comment on board decisions, other than to say I didn't negotiate anything. I think the question is best directed to the board. All right. Thanks. Last one, just quickly on policy. The ADGSM kind of guidelines that have come out recently, and there's a section at the back which almost suggests that the government's gonna insist projects like GLNG would have to either purchase export approval permissions from a neighbor or purchase spot LNG cargos to meet their long-term LNG contracts, before the government would, you know, come in and provide additional export permission. Do those clauses suggest there is risk that the government could force GLNG to purchase spot cargos or purchase 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, you know, 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. It's good to hear the government making those points very consistently and very loudly. Look, I think, you know, 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. 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 uncommercial? That's correct. All right. Which is what I'm saying. My expectation would be that would be unlikely to be a requirement. All right. Thanks, Kevin. Thanks, Anthea. Thank you. The next question comes from Mark Wilson with Macquarie. Please go ahead. Oh, g'day, Kevin and Anthea. Thanks for the update today. 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? Thank you. Let me just get at the opposite way around there. The second part of your question, I'll address first. The backfill project's really about lifting it, lifting WA production back up to higher levels. Take the back up. Spar-Halyard should take us back up to, you know, if 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. Certainly from a well testing point of view, the permeability and the flow rates during the testing were higher than we had anticipated. It's a real high side outcome for us in that respect. But I'd say a guide year around 275 per day at this point in time. As I say, the backfill projects that we're looking at developing there for Varanus Island would be about bringing production up overall for the longer term. Okay. On the contract. Sorry. On the contracts. The current reserves we have there give us full contract coverage. Okay, that's clear. Thanks. Just one for Anthea, just on the project finance for Papua LNG. Appreciate given your equity interest, it's not a huge investment in the context of the business. Could you maybe just talk around those project finance, you know, around that funding market, what sort of debt equity split should we be thinking about there? Look, I think that's a level of detail that's still being worked through. Obviously you wanna maximize the debt levels within those project finance facilities. We are seeing some strong support from the bank potentially. Really that process needs to play through to proper finance launch and book build from there. It's hard to comment with specifics at the moment. Okay, great. Thank you. Cheers. The next question comes from Nik Burns with Jarden Australia. Please go ahead. Thanks Kevin and Anthea. 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 they're around a one-third of your reserves are classified as undeveloped. Is that bringing those reserves to market or is that part of the 1,400 petajoules of gas continued resources you flagged last week? 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. Thank you. No, look, I'm sure, I'm kinda pretty sure that Spartan was undeveloped 2P. We've never developed that. We've spent the money to do that. Corvus, Spar Deep, that is all 2C. That is all 2C. That's not undeveloped or developed 2P. When do you plan to bring that to market? Well, look, I mean, I think it's a bit early to say that, Nick. We hope to give some guidance on that throughout the year, but, we just have to sort of do that work and get these things and see which one's going first, right? We'll come back and give guidance on that once we work those opportunities out. Got it. 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 you think it's probably closer to FID, i.e., next year? Thank you. Well, look, I mean, I'm not gonna give any guidance on when I'm looking to do any sell downs or anything like that. Been there before, haven't we? 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. Again, I'll congratulate Adrian for that deal. By the way, it was a very credible joint venture partner. I mean, we're pleased to welcome CPC to the joint venture, we'll look forward to working with them to move this asset forward. You know, I think I just take encouragement, Nick, from the fact that a good credible buyer has bought a significant stake in the project. On sell downs, when we've got something to announce, we, you know, we'll announce that. That's great. Thanks, Kevin. Cheers. Thanks, Nik. Appreciate it. RBC Capital Markets, please go ahead. Hi, it's Gordon. Kevin, the PNG government made a statement about Papua LNG possibly moving forward with four mini-liquefaction trains instead of the two that initially were 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 TotalEnergies' 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, take the market through the details of that expansion project. You're right. It is, rather than the big expansion trains, it's four smaller trains and using some capacity from the existing project. What I would say is that, you're also right in saying that delivers some CapEx savings. We think they're quite significant, but what we'll do is we'll wait until the operators and ourselves take FEED, and then we'll give you more detail on what the quantums and the economics of that look like. Other than for me to say it looks very attractive. It looks like a good project. Excellent. Thank you. 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 still in consultation phase, and we're working with all of the stakeholders. I have to say, I've been pleased with the start to that process. We're not gonna give any updates on the progress of our plans and our various steps along the way until we get the approvals to move forward. you know, I mean, that's all I can really say, Gordon. We're progressing it. We're progressing it as fast and as hard as we can, but doing it as per the new guidelines. There's been some commentary on the pipeline lay possibly being delayed. Can you say anything there? We obviously know what's going on with the drilling. Yeah. The pipeline, we made an 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. Very, very good. Appreciate it. Thank you. Thank you. What I can say is, that's not because the EP has been pulled or anything like that. It's basically a management change activity, and we're managing that, business as usual. Okay, thanks. Next question comes from Mark Samter with MST Marquee. Please go ahead. Morning, guys. I think I'd like to come back to the balance sheet answer, if I could. I'm slightly boggled by the question you were asked because, I mean, gearing sub-19%, it'll be sub-15% by the time you sell down PNG LNG. You go back to the middle of 2020 when oil was $40 and gearing was 34%, and you still said your covenants allowed headroom for a number of years of oil at that level before they were breached. I mean, am I missing something? Have debt covenants changed horrifically, or is literally the last thing this business needs to worry about is a breach of debt covenants and balance sheet capacity? Yeah. Look, I'll hand that to Anthea. 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 in 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. The balance sheet was pretty weak at that point in time. We put in place processes for the business then that would ensure that we were gonna maintain a lot of headroom against covenants to never put us into those nervous positions again. I can assure you, there's lots of headroom. You're right. In March 2020, when right at 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. We run the business that way. Anthea, you might wanna talk a little bit more specifically to that. Yes. We do monitor at each kind of board. We look at capital management. We look at our sensitivity to covenants and also to, you know, credit rating metrics, et cetera, gearing metrics. It is very closely monitored but also very closely forecast into the future under different development scenarios from a CapEx perspective, under different oil price scenarios. As you point out, the market's very difficult to see a scenario where, you know, we could get in trouble from a covenant perspective, even at very low prices. A part of that also is kind of a disciplined operating model, free cash flow break even, that we've given ourselves, you know, to be under $35 per barrel. Which does say, when oil prices go down, you know, the base business can still generate revenue on the way through. That's kind of. You know, we do manage the balance sheet accordingly. I guess it's what makes a market, isn't it? I'll give you a hard time for not turning enough money. Other people panic about that you're gonna breach your debt covenants. What a job being CFO, eh? It's not something we're worried about. All right. I think that's... I guess, I don't think you're gonna comment on this, and I think you touched on it just with the Dorado sale done. It may be it's a surprise, I would think, to a lot of people that being able to sell a stake in that asset. I guess you're probably not gonna comment more on your plans, Adam, so it's probably a validation that there is a lever to pull as when if you did wanna pull a lever on a Dorado sale then. I think that's right, Mark. I mean, it's, and it's a credible buyer, right? It's, it's a, it's a, a Tier 1 buyer. We were very pleased to see that transaction go through, and I think it gives us confidence that, you know, there's people out there who look at this project and see a very solid and valuable project. You're right, it gives us a lever. I've made the mistake in the past and very kinda open to learning from mistakes. I've made the mistake in the past of saying what I'm gonna do in the future, and sometimes you can't predict how those things play out. I'm not gonna do that. What I will say is, of course, I'm pleased that, that I see that that lever is available to us. If we've anything to announce on that, we'll announce it if and when we do it. Okay. I might just ask one question. I know Adam asked a question about Papua offtake contracting. I think I'm right in saying in the release on the offtake of Barossa to Mitsubishi that has the flexibility to be resold. I'm not sure the energy market's pricing the bet, JKM is down to $14. As of today, it's just about to have a contract price. I'm not saying it stays there, but I mean, A, do you still look at those Barossa volumes and, B, would it be realistic even if you chose to recontract those volumes, or would you wait until drilling's restarted and you've removed some of that execution risk around it? Well, the good thing, as you pointed out with the Barossa volumes, is there's no penalties or liabilities that go with the deliverability of those volumes. We have the ability to re-contract up to all of the 100% of those volumes or any part thereof over time. It's a very, very flexible contract. You're right. They're JKM linked contracts. We're pretty happy with those contracts and the amount of interest in contracting LNG from our portfolio more generally. We've got a lot of interactions with Japanese, Korean, and other Asian buyers looking across a portfolio rather than any one project or. Of course, the Barossa volumes can play into that, right? We've a lot of flexibility. We're not in any rush to do anything. Again, we'd announce that, Mark, you know, if we see the right offer and the right opportunity and we contract it, we'll announce that when we do it, yeah. Perfect. That's brilliant. Thanks. Cheers. Thanks, Mark. Your next question comes from Henry Meyer with Goldman Sachs. Please go ahead. Hi, Kevin and Anthea. 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 the number of wells drilled in phase one versus phase II? I believe phase I had up to 6-10 wells in the original development, followed by phase II four 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 I campaign or perhaps accelerated phase II? Yeah. Look, that's a really good question, Henry. Look, the phase I drilling we were planning to do was six wells. Six wells. Two of those wells were actually contingent wells, or additional capacity wells. We need four wells to produce at capacity, that does give us quite a bit of flexibility in how we wanna execute the plans. I don't wanna get into too much detail on the execution plans. Obviously, what that's allowed us to do is move things around a bit. That's exactly what we've been doing to ensure that we can keep the critical path. At this point in time, if everything proceeds to our expectations, and our aspirations with respect to the, the new approvals we have to get, we still believe we can deliver this project first half of 2025. Great. That's helpful, Kevin. Over at GLNG, I think, you know, every year you're seeing improved operational performance. Six-year mean time to failure is pretty incredible, obviously accounting for a bit of survival bias and 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 Roma or Fairview? You know, is the joint venture thinking about potentially increasing production there if they did need to supply more into the domestic market? Look, first of all, let me just echo your points on the operational performance at GLNG. I really wanna 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. 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 mean time to failure 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. Reliability of wells and cutting costs through workovers, the number of workovers 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 wells 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. Look, I think overall that gives us upside opportunity. We need to see. You know, it's hard to quantify what that may or may not be at this point in time. It gives me a lot of confidence. There's a lot of 2C there that we can convert if we can keep the drilling unit costs down. You can see those Roma well costs. I mean, it's quite incredible, even with inflation, over the last few years, we've still been able to maintain those wells at under $1 million per well. It's something we're really proud of. We've just got to keep doing it. I'm not gonna make any forecasts on what that's gonna do. The guidance is still 6 million tons per annum until it's something else. At this point in time, I'll stick to 6. Yeah, I'm optimistic that we'll, you know, that there'll be some upside there in the future. Great. Thanks, Kevin. Maybe one final quick one if I can for Anthea, just on the change in restoration assumptions. Able to provide a little bit more color there, please? Is it primarily just a change in discount rate or risk-free rate assumptions? If you look at the underlying cost, there's 2 drivers for that. One is scope, and the other one is cost. From a scope perspective, you know, we've factored in full removal other than pipelines. All the subsea flow lines are assumed to be fully removed. There has been, you know, some inflation with costs going in there as well, but the main driver is kind of scope and cost. I suppose noting the 221 that went through for the P&L was related to assets that aren't producing anymore. Any cost increases to those provisions get taken straight to the P&L, which is a little bit different to the treatment for Barrow Island, which you saw we impaired that asset because it's still producing, and then it needs to be written off as an impairment. Okay, great. Thanks, Anthea. The next question comes from Daniel Butcher with CLSA. Please go ahead. Oh, hi, Kevin. I just wanted to quickly pick up on something you said earlier about, the four small trains at Papua LNG may also use some of the existing projects. Should we take away from 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 back end 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. We'll be able to give you details of that on FEED announcement when we get there. 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. All right, thanks. Uh-huh. Yes. Second question. Just on Cooper Basin. Obviously, some years ago you gave a target of a certain level of production that you might want to maintain to 2028, and it 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 five rigs you think you can get to in the foreseeable future, either next year or a couple of years out, please? Thanks for that, Dan. Look, we sort of got to the front end of that target very, very early, then COVID struck, as you would remember. All the capex plans got curtailed, and we came back in the last couple of years. I think, you know, it's just a great reminder, the lesson for the Cooper Basin, it's all about the number of wells you drill each year. If you can maintain that 100 plus wells, you can maintain and/or grow your production at the Cooper Basin. When you drop below that, it drops off pretty quickly. 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. I wanna see it building for a couple of years before I give any targets on it. Okay, thanks. Maybe one quick final one or one or two very short ones. Just on your PNG LNG midterm volumes rolling off, you sort of implied they'll 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 spot and that they might be recontracted at some point in the future? Yeah. Look, our marketing guys are out there talking to, you know, to the market. There's a lot of interest in those volumes. We're in no rush. You know, we're pretty happy at this point in time with the JKM overall. I know it dipped down more recently, but, you know, let's wait and see how it plays out over the course of the next 6 months or so. If we've anything to announce on that space, we'll announce it then. Okay, thanks. maybe a very quick one if I can. PNG LNG 2P filled by 27 million barrels over 2022, including production. It's developed 2P filled by more than that, 14 million barrels. I'm just curious if you can recall, or explain why some of the 2P at PNG was put back into undeveloped category. The only resource that I know has been written down in PNG was 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 that. I'll take it offline. Thanks. Sure. That's all. Thanks. I think we're taking one more question. Next question comes from. Yep, go on. Yep, from Rob Koh with Morgan Stanley. Please go ahead. Thank you, and congratulations on the result. 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 in terms of local owner priorities? Rob, you know, I think those processes have to stay confidential. Hence, I'm not really able to kinda share what we discuss. I mean, out of respect for our traditional owner stakeholders, we're not gonna discuss what we're talking to them about until such times as we reach any agreements and/or get our approvals, excuse me, for the project. Yeah. Okay, sounds fair enough, and wish you well with that. Thank you very much. Thank you, Rob. Appreciate it. Again, there are no further questions at this time, and I'll hand back for closing remarks. Okay. Well, I wanna thank everyone, for your interest and 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.