Santos Limited (STO) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Santos Limited 2024 Full Year Results Webcast. [Operator Instructions]. I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead.

Thank you, and good morning, and welcome to the presentation of Santos' 2024 Full Year Results. I'm speaking today from the traditional lands of the Kaurna people of the Adelaide Plains, and I pay my respects to their elders past and present. I also acknowledge and recognize the support of traditional owners, indigenous people and nationals everywhere Santos operates, including in Papua New Guinea, Timor-Leste and Alaska. I'm pleased to present another set of financial results that demonstrates the cash-generative nature of our base business and the strength of a disciplined low-cost operating model. I want to, first and foremost, recognize the hard work of all of our people in maintaining their focus on safe and efficient operations. Today's results are a testament to their dedication and capability of which is the foundation of our ongoing success. I'll begin with some opening remarks about our performance before handing over to Chief Financial Officer, Sherry Duhe, to discuss the financial results. After Sherry's presentation, I'll take you through our operational performance and our strategic priorities for 2025, then open the call to questions. Before we start, I draw your attention to the usual disclaimer on Slide 2. Being always safe is a core value for Santos, I'm very pleased with our personal safety performance over the last 12 months, which is our best in over 10 years. However, as always, continuous improvement is our goal, and there's always more to do. Our lost time injury rate improved continuing a positive trend since 2021. Santos now ranks in the top quartile of IOGP performance for 2023. When you take into account the very high level of activity across the business, including delivery of 2 major development projects and nonroutine decommissioning scope, this is an outstanding achievement. Our moderate harm injury rate and total recordable injury rate also improved. Process safety performance has also been strong, with significant improvement in the loss of containment incident rate and one of the best in over 5 years. Slide 4 summarizes our 2024 financial results. The strength of our base business and the robust revenues, it generates continued to provide a solid foundation for our long-term sustainable growth and profitability. Sales revenue of $5.4 billion generated EBITDAX of $3.7 billion, free cash flow from operations of $1.9 billion and profit after tax of $1.2 billion. Our production for the year was 87.1 million barrels of oil equivalent, which was at the top end of our production guidance. Our strong financial performance has been achieved despite the challenges of an inflationary environment globally, reflecting the success of our disciplined low-cost operating model. I'm pleased to announce that the Board has determined to pay a final dividend of USD 0.103 per share, unfranked, bringing total dividend declared for the year to USD 0.233 per share. We are pleased our annual dividend yield remains competitive, while we're still funding our major development projects. Since 2016, Santos has generated more than $12 billion in cumulative free cash flow from operations and returned more than $4 billion of that to our shareholders. To put that into perspective, since the implementation of the disciplined low-cost operating model, we've returned more to shareholders than the entire market capitalization of the company in 2016. This performance continued through 2024 with shareholder returns of $757 million, equivalent to 40% of free cash flow from operations, in line with our policy. Moving to Slide 6. Our year-end reserves and resources position is strong with 2P reserves life of 18 years and 1P reserves life of over 11 years. Our reserves and resource position of approximately 4.9 billion barrels of oil equivalent is geographically balanced across our infrastructure locations and strategically weighted towards LNG. This places us in a strong position to deliver sustainable growth through lower cost developments with a robust suite of high-quality growth options to choose from, including Papua LNG and other PNG opportunities, Beetaloo, Narrabri, Pikka Phase 2 and Dorado, we are poised for long-term success building on 10 years of the considered evolution of our strategy. We will progress these projects in a phased and disciplined way that delivers maximum value for shareholders and in accordance with our capital allocation framework. We remain well positioned to take advantage of growing customer demand for commercial carbon management services with 2P CO2 storage capacity of 9 million tonnes. Our 2C contingent storage resources increased by 47 million tons to 178 million tonnes in the Cooper Basin, following the successful start-up of Moomba CCS. The performance of Moomba CCS process, reservoir and cost gives us confidence in the future role of CCS and our decarbonization strategy and in achieving our 2040 carbon storage growth target to store approximately 14 million tonnes of third-party CO2 per annum on a commercial basis. This is equivalent to around 50% of Santos' 2023 equity downstream Scope 3 emissions. An impressive operational performance from our base business has continued to provide reliable production and cash flows. Our LNG assets are performing strongly. Our major projects are on track, and our LNG marketers are delivering outstanding value through their execution on our contracting strategy. LNG demand in the Asia Pacific region is anticipated to remain strong throughout this decade and the next driven by growth in Southeast Asia and stable demand in traditional North Asian markets. Our LNG assets are advantaged in this market. Our LNG from Barossa and PNG has a high heating value that is highly sought after by our Japanese and Korean customers. I'm very pleased with the execution of our LNG contracting strategy in 2024. We signed long-term LNG supply and purchase agreements with Hokkaido Gas and Shizuoka gas and midterm LNG agreements with TotalEnergies and Glencore. These agreements with Tier 1 customers strengthened Santos's equity LNG contract portfolio. Indeed, our portfolio is 90% contracted on average to 2029 with flexibility to move volume into term and spot markets. This allows us to quickly capitalize on market opportunities as they arise. A good example of the value of this flexibility was our ability to identify the impact of recent LNG sanctions on demand in Europe then execute an LNG sale at a slope of more than 20% of Brent. Across our entire LNG sales portfolio, we have delivered strong realized LNG prices compared to the market and their peers. The Barossa LNG project is 91% complete and remains on schedule for first gas in the third quarter of this year. We are expecting a key milestone to date with the final wells on the Darwin Pipeline Duplication, connecting the Barossa field to the Darwin LNG plant, an outstanding achievement given the challenges that we have faced. Three wells are drilled and completed. The fourth well is partially drilled and suspended for completion later this year. The fifth well of the 6-well drilling program has reached total depth, and I'm pleased to say that well testing and cleanup commenced on that well yesterday. Very importantly, with 4 wells in production, DLNG can achieve nameplate capacity. So our drilling to date has already materially derisked the project. Progress on the remainder of the project is significant and on track. Subsea infrastructure installation is 87% complete, and the Darwin Life Extension project is 75% complete. The FPSO is on track. I was up in Singapore to inspect and participate in the naming ceremony only last weekend. It is a very impressive vessel incorporating industry-leading design to make it one of the lowest emissions vessels of its type in the world. At our Pikka Phase 1 project in Alaska, we continue to see strong progress and remain on track for our first oil target of mid-'26. The drilling program in Alaska continues to be a success with a 25% improvement in drill time on the last 6 wells and a new technical limit record recently achieved. The pipeline installation is progressing well and set to be completed in 2 winter seasons instead of 3, putting us in a good position to pursue acceleration of first oil to around the end of 2025. However, this will be dependent on logistics and weather allowing for the mobilization of key production modules by barge up the Hay River rather than transport via road. Until we know for sure in a few months' time, we're sticking to existing guidance as first oil in mid-2026. With Barossa and Pikka coming online, Santos' production is expected to increase by more than 30% by 2027 compared to 2024, lowering unit production costs further and putting the company in a great position to generate cash and return value to shareholders. I'll now hand over to Sherry to provide an overview of our financial results.

Thanks, Kevin, and thank you, everyone, for joining us today. Santos has delivered a strong set of financial results with the base business performing well and our major development projects, Barossa and Pikka on track to deliver on time and in line with capital guidance. Our consistent financial performance is highlighted by a free cash flow breakeven cost of less than $33.50 per barrel and unit production cost of $7.85 per BOE, excluding Bayu-Undan, and free cash flow from operations of $1.9 billion, and this is despite inflation and lower commodity pricing. Our balance sheet remains robust with gearing at year-end of 23.9%, including leases. It's pleasing to see Santos' strategy and disciplined low-cost operating model continue to deliver strong shareholder returns. Total dividend of $757 million include the interim dividend of $422 million already paid and the final dividend declared of $335 million. In 2024, operating free cash flow was $2.8 billion. The result is down in 2023, primarily due to lower volumes and lower realized pricing as well as decommissioning costs in Western Australia. But this was partially offset by lower borrowing costs due to an improvement in the weighted average effective interest rate across the portfolio. Our 2024 operating free cash flow demonstrates the strength of our diversified portfolio and is underpinned by the performance of our base business, its strong LNG and inflation-linked fixed price domestic gas contracts and of course, our continued low-cost operations. Our underlying earnings show that product sales revenue remained strong at $5.3 billion, generating EBITDAX of $3.7 billion and an underlying profit of $1.2 billion. As always, we continue to maintain cost discipline across our business. Our unit production cost was delivered within guidance and is on a trajectory to less than $7 per BOE once both Barossa and Pikka Phase 1 are online. For 2025, we're guiding production cost between $7 and $7.50 per BOE. It's of note that from a phasing perspective, unit production costs will be slightly elevated in the first half of the year and then lower in the second half once Barossa is online. Now following on from the cost refresh that we signaled at our recent Investor Briefing Day, we are targeting $100 million to $150 million in annual structural savings from our operating cost and sustaining CapEx to be delivered over the next 1 to 2 years. Now this is as we emerge from the past few years of major acquisitions, integrations and, of course, major project developments. This will be supported by a thorough review of all of our costs across the business and, of course, our supporting functions. And smart deployment of technology is a key focus area. We'll keep you updated on how we're tracking as we work through the cost refresh throughout 2025. As we've said consistently, we're committed to maintaining a resilient balance sheet and investment-grade credit rating as we complete our current development projects and enter into a period of increased production and associated cash flow generation. This will allow us to leverage our financial strength for shareholder returns and long-term sustainable growth while actively managing gearing. In addition, our long-dated maturity profile provides financial stability. Notably, 2025 marks the final full year of our PNG LNG project finance repayment. In 2024, we successfully executed the Moomba CCS transition loan for $150 million. The revolving syndicated facility increased to $850 million and a new syndicated bank loan facility was completed for the Darwin LNG Life Extension work. At year-end, our net debt stood at $4.9 billion, with gearing in our target range. As planned, gearing will increase temporarily in 2025 as we near project completion for Barossa and Pikka and with the inclusion of the lease liability from the Barossa FPSO, after which it's forecast to reduce as development capital expenditures decline and our new revenues materialize. We continue to hold a strong level of liquidity with $4.4 billion at year-end and a combination of cash facilities and undrawn finance facilities. In accordance with our capital management framework, we'll look to protect the balance sheet and safeguard our financial position through hedging strategies for commodity and FX exposures. For 2025, we have 10 million barrels of oil hedged at a floor of $70 and an average cap of $84. Further, we've taken a material position on FX hedges of AUD 1.75 billion in 2025, and AUD 1.06 billion in 2026. This hedging has been undertaken at rates well below the long-term AUD FX averages providing strong FX protection as we complete our current period of major capital expenditure. So overall, we've had a strong financial performance in 2024, returning $0.75 billion to shareholders. Thank you, and I'll now hand back over to Kevin.

Thanks, Sherry. I want to turn the focus now to our operational performance and looking ahead to 2025. Santo's disciplined low-cost operating model has stood the test of time and underpins our business, ensuring we remain financially strong, operationally efficient and well positioned to deliver sustainable growth and competitive returns to shareholders. There are no changes to the model. It's very simple. But as we come out of a growth CapEx phase and having successfully integrated 3 businesses into Santos, we will again revisit our cost base through a comprehensive review. . As Sherry mentioned, we are targeting $100 million to $150 million of annualized structural savings. It will take 1 to 2 years, but our track record of achieving savings and synergy targets give me great confidence that we will deliver on this commitment. And another region, demand for gas and LNG is set to grow out to 2050, geopolitical tensions and regional conflicts along with the retreat from open competitive global markets continued to highlight the fragility of global energy systems in 2024, underscoring the value of energy security and affordability. Alternative technologies for the energy transition are not developing at the pace or scale required, increasing long-term reliance on hydrocarbons. And underinvestment globally in upstream oil and gas over recent years is coming home to roost. Wood Mackenzie forecasts gas demand in Asia to grow by around 34% over the next decade alone. Santos is strongly positioned in Asian markets with Tier 1 customers, a reputation for reliable supply, high heating value LNG taking around 8 days sale to market and increasingly able to offer potential decarbonization services to our customers. The demand outlook for oil also remains resilient. Our Pikka development is well placed to supply into fungible markets with highly competitive breakeven cost of supply. In 2024, Santos' operated upstream assets in PNG produced 10.4 million barrels, accounting for 23% of supply into a world-class PNG LNG project. We completed 3 of the 4 price reviews for P&G, securing win-win long-term outcomes. Further, the participants in PNG LNG agreed to move to equity lifting of LNG in 2024. And Santos lifted and sold 11 equity cargoes. By 2035, 100% of our share of LNG will be equity lifted and sold into our portfolio of LNG contracts. Our Angore project has performed strongly since the project was brought online last November, supplying up to 350 million standard cubic feet of gas per day into PNG LNG. The APF Tie-In Project to produce associated gas from the Santos operated Agogo and Moran fields, is targeting an initial 125 million standard cubic feet a day -- per day with potential to deliver up to 250 million standard cubic feet per day over the longer term. We are targeting an FID ready date of 2026. Fields such as Muruk, P'nyang and Juha are also in the queue to keep PNG LNG full over the long term. This is a great position for Santos and the PNG LNG joint venture to be in. We're spoiled for choice with no shortage of healthy upstream development options. GLNG delivered 6.08 million tonnes of LNG to its long-term LNG buyers. This was a great achievement in a year that GLNG safely delivered a 30-day shutdown with more than 500 people on site who work some 70,000 hours. The GLNG project continues to provide support to the local domestic market in winter through seasonal shaping of LNG supply. This aligns well with our customers receiving more cargoes in their peak winter demand season. Continued production growth in Queensland CSG is being driven by new wells coming online in our upstream fields and success in our technical drilling efforts. Roma has delivered its highest rates so far and achieved record daily production of 207 terajoules. We are now achieving our longest CSG horizontal wells with lateral lengths up to 4 kilometers long increasing access to resources and unlocking higher volume outcomes. The Cooper Basin continues to be an important foundation supplier to GLNG. Our central fields at Moomba achieved a 10-year high production rate. This encouraging result reflects our ongoing focus on optimizing production around existing infrastructure. We are testing the potential of the Moomba South Granite Wash with horizontal wells being drilled at Moomba 390 and Moomba 391. This adds to our 3 horizontal Granite Wash wells that are already online and producing. We have also drilled and connected a vertical well into the interspersed [ course ] of the Patchawarra Formation and are appraising this plate. Both geological plates have the potential to add significant reserves and production supporting a sustainable and profitable future for the Cooper Basin. Last week, we announced first production from the Halyard-2 infill well, 6 weeks ahead of schedule. It will supply an additional 65 million standard cubic feet per day into Varanus Island and add around 47 petajoules to 2P developed reserves. This project highlights the benefit of developing our reserves and resources close to existing infrastructure. In WA, we also delivered significant decommissioning scope safely and efficiently throughout 2024. We will continue to take a phased and disciplined approach to decommissioning sticking within our capital allocation framework while also ensuring ongoing facility safety and integrity and sound environmental stewardship. Santos is in an enviable position with the luxury of choice in our future backfill and sustainable growth projects. And the Beetaloo, which could be one of Australia's last elephants with characteristics analogous to the Marcellus and Utica, Shales in the U.S. I'm very excited about the drilling appraisal program we're planning for 2026. This opportunity holds great potential with a 2C contingent resource of 1.4 trillion cubic feet gross already booked from 2 wells. We recently executed an MOU with Tamboran Resources to undertake a joint study on gas export options through Darwin where Santos has approved expansion capacity for another 6.6 million tons of LNG per annum. The scale of Beetaloo if appraisal confirms its potential would be a game changer, not only for the Northern territory, but for the East Coast domestic and LNG markets as well. Papua LNG is progressing and the rebid phase for the upstream development. But as I said earlier, we have no shortage of backfilling growth options in PNG. We continue to advance approvals for the Narrabri gas project, which the East Coast domestic market needs for supply security and to put downward pressure on domestic gas prices. I note that in December, National Energy Minister has tasked senior officials to work with AEMO to advise on expanding powers for it to address emerging domestic gas supply issues and recommend policy options to address both supply and cost of gas. Removing barriers to the development of Narrabri should be at the top of this list because while Narrabri gas will put downward pressure on domestic gas prices, LNG imports will do the opposite, unless they are subsidized by governments, which would also be a very bad outcome for Australian taxpayers and consumers. We have an excellent resource position on Alaska's North Slope, providing future expansion opportunities. Lastly, we will continue to evaluate the potential for an integrated gas and liquids project in Dorado following further exploration being planned for 2026. I made a commitment at the full year results presentation in February '21 to take FID on Moomba CCS that year, and we have done what I said we would do. One of our most exciting accomplishments in 2024 was bringing Moomba CCS online. Just recently, we [ passed ] 500,000 tonnes of CO2 equivalent stored since startup. At full ramp-up, which we reached within weeks of first injection, Moomba CCS can store up to 1.7 million tonnes of CO2 equivalent per year based on available CO2. That is equivalent to taking 700,000 cars off the road every year. I'm confident our CCS hub strategy is limited only by the availability of CO2. We have proven the technology works. We have available storage in our depleted reservoirs and according to Wood Mackenzie, Australia will lead the APAC region with carbon prices higher than the weighted levelized cost of CCS by 2050 when compared with countries like Japan, South Korea, Indonesia and Malaysia. Our CCS strategy is purposely designed to decarbonize our own operations and provide commercial carbon management services to customers and third parties. As we continue to drive business efficiency, safety and reliability, we are embracing technology and innovation throughout our operations. Through the integration of AI and the use of related advanced technologies, both of which are accelerating rapidly in terms of availability and affordability. We are optimizing field surveillance and production, supporting remote operations and targeting step-change efficiencies and outcomes across every facet of our business. Over the last 18 months, we have done a lot of work to build a positive and engaged culture across the organization. Since our baseline survey in June 2023, our employee engagement has increased by 37%, which the experts tell me is an almost unprecedented improvement over such a short period. Santos has a demonstrated track record in building outstanding leaders. In recent years, a number of our senior executives have gone on to be CEOs in other organizations building on their Santos experience. That's something I take great pride. And I expect more of our people will do so in the future. These changes are a good thing because they open up opportunities for the next generation of leaders, and they are part of a healthy organizational development and individual career progression. Each year, I'd like to set out our strategic priorities so you can monitor our progress. Of utmost importance is delivering first gas on our Barossa project in Q3, and we will continue to progress the Pikka project for first oil in 2026, if not earlier. In the background, we will be working to mature and select our future development projects in a disciplined manner that is aligned with our post-2026 capital allocation framework. And we will refocus on implementation of a disciplined low-cost operating model to achieve annualized structural savings of $100 million to $150 million over the next 1 to 2 years. So in closing, our unrelenting focus on sticking to our strategy has set the business up for an exciting 2025 and to deliver long-term value for our shareholders. Thank you. I'll now open up for questions.

[Operator Instructions] Your first question comes from Dale Koenders with Barrenjoey.

I was hoping you could provide a bit more color around the cost-out target. How are you thinking it breaks down between OpEx and sustaining CapEx and what this means for your sustaining CapEx outlook over the medium term?

Thanks, Dale. Look, it will be a bit of all of those things. But ultimately, think of us really focusing on the base, right? So it's the efficiencies in the corporate center. As we've brought 3 companies into Santos over the last 3 or 4 years, we've integrated a lot of the systems, whether that be the SAP systems or whatever else. We've identified opportunities to further optimize and standardize processes across the business. So the corporate center efficiency will be a part of that focus. But undoubtedly, technology in terms of remote operations and how we manage those operations. And I feel some of which today still require a lot of boots on the ground as opposed to utilization of technology. We see some significant opportunities there. But a lot of it really is just driving efficiencies through the business. If I look forward to the future, I can see a day where AI takes this call, for example, and we can go on with work at the same time, right? That's just a joke, by the way. But we can see very significant opportunities to utilize AI and other technologies in the corporate center to automate a lot of the very labor-intensive processes that take a lot of our people's time today.

Okay. And then just confirming that's incremental to the free cash flow outlook provided in August last year?

Sherry?

Yes. No. So Dale, the free cash flow outlook that was provided last year and just to remind everybody, was notional based on a selective set of projects and the scenario oil price. So we don't want to refer it back to that. What we're really referring back to is the total incurred operating costs and sustaining capital on a cash basis and comparing that back to our 2024 baseline.

But we should see it come through in our unit production cost, right?

Yes, you would see it in unit production cost. As Kevin has said, you would see it in sustaining CapEx, you would see it in corporate cost. Any of those are on the table in terms of the scope for it.

Okay. And then the second question, just in terms of reference to Papua LNG FID ready targeting '25 dropped and talking more about APF, FID-ready '26. Is this a delayed to the project and backfilling with other resource now? Is that what we should be expecting?

No, I don't think so, Dale. I mean if you think back to the December Investor Day, Brett put up the short- to medium-term projects that we had in Juha. APF was right at the front of the queue for those backfill opportunities. It's something that was actually sanctioned at the initial sanction of PNG LNG way back. It's just never been executed. It's always just sat there and ready to go. The good news on that project is that Brett and the team have managed to take significant CapEx out of the project from how it was envisaged to be developed originally. And so it's a very high value call it, fill-in backfill project, where would wait for either Papua or anything else to come online.

Your next question comes from Henry Meyer with Goldman Sachs.

A clear focus this year is Barossa delivery and ramp up. Now that we're getting close to start-up, could you step through the expected time line from first gas to sales lifting? Any variables that could change that?

That's a really good question, Henry. Thank you for that. So look, I mean, first of all, let me start by saying I'm really pleased with the progress in 2024 on the Barossa project. The FPSO is looking great. I know there will be many shareholders out there who have visited that asset over the last 12 months. It's looking fantastic. It's very close to sale. I think the commissioning -- actually the shipyard commissioning is around 85% complete just now. So that's on track to sale over the next couple of months. The SURF is going well. The pipeline, as I say, should be connected up today. That's connecting, physically connecting Darwin LNG all the way to the Barossa field. That should be done today and the drilling is going really well now. So the project is in a great place. In terms of the Q3 start-up, I guess -- I'm saying that because our increasing confidence of staying on track for that. And very pleasingly, we put cost guidance out about 18 months or so ago where we said you could expect the cost of Barossa to be $200 million to $300 million higher than the FID promise. But we haven't seen any of that cost. And so in reality, we're still on track to deliver around the FID promise, which is a very encouraging and very positive news for the project, particularly when you consider the delays and the impacts that those had on the project. So it's in good shape. But of course, going from first gas to first sales requires steady state reliability and for the facilities to run smoothly. The expectation is that would take anywhere sort of 6 to sorry, 8, 9 weeks before you'd see the first sales gas coming in.

Great. That's clear. And your LNG contract position remains very strong. Could you share if there's any contract repricing at GLNG in the near term? And also, any details on plans for the Barossa contract, which we understand has some flexibility to perhaps move away from JKM indexation?

Yes. Well, thank you for that. Well, look, as I say, over the next 4, 5 years, our portfolio is 90% contracted so -- and that does allow us some flexibility to take advantage of the spot market if it's advantageous to do so. Or to recontract somewhat higher slopes if the market is supporting that. You can see on Slide 8 in the pack, a very strong relative pricing relative to our peers. And that's very much a reflection on the quality of the portfolio that we have and the proximity to market and the relationship we have with long-term customers. . The fact of the matter is we just demonstrated that, as I said in my speech earlier on, able to take advantage of some of the volatility really put into the market as a result of the trade wars and the tariffs that have been communicated recently from a geopolitical perspective and gain slopes on, I think, it's for cargo a tranche of sales next year -- early next year at slopes at over 20% to Brent. So that flexibility, we believe, has got a lot of value in our portfolio because we can recontract some of those volumes, and we've just demonstrated how we can take advantage of some of those short-term positions. In terms of GLNG, it feels like there's always some repricing going on. And yes, we're in the process of 1 or 2 of those contracts just now. But as always -- as I said, to folks, I think, 3, 4 years ago, when we were going through some of the same repricing discussions. I've been here that long now, I can remember the last time we've gone through this process. If we were to get the maximum negative outcome, on every repricing for the life of the GLNG contracts, we still end up around 13% slope at the very end of the contracts. Now we don't expect that outcome but that should give you some comfort because as you will recall, Henry, these were very good contracts at the foundation points in the project.

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

Kevin, perhaps you just touched on decommissioning spend. I mean one of your peers had a pretty big uplift on spend for the next 12 months. Just give us some insight next 3, 4 years? We're sticking around the $300 million level, but just also perhaps talk around any large pieces of work or just general inflation that you're seeing in the decomm space well, please?

Well, look, we have been doing a lot of work on this over the last couple of years, Adam. And we've got like a decade-long plan of decommissioning and our -- we have a pretty significant safety incident and decommissioning activity during COVID. I think it was in 2021 and that made us reevaluate the way that we want to do this work to make sure that it's conducted safely because these are one-off operations. They're not our continuous operations. And they bring different risks and different hazards to our workforce who are not experienced in decommissioning -- some of the decommissioning activities. So we've built a schedule of operations, and we're working with the regulators to agree on a longer-term plan that allows us to do this safely, reliably, efficiently. And as you know, we spent [ USD 319 million ] last year on decommissioning activities, predominantly around offshore Western Australia and on Barrow Island. And it would be similar to that this year, just around $300 million this year. We expect to be a little lower next year, and that's really just the nature of the types of operations that we'll be executing next year. But I would say that I'd be targeting somewhere between $200 million, $250 million a year on average, is my thoughts. But of course, it could very easily 10% either way. But it's really about just trying to have a long-term plan allows us to execute consistently year-on-year staying safe and being able to do this efficiently.

Okay. That makes sense. And just on Slide 26, you've got a lot of different sort of backfill growth options. Are there any there that you think is sort of winning the race at the moment in front of the queue. I'm just sort of more thinking at '26, '27 when you delivered to Alaska and Barossa uplift.

Well, look, I mean, I think the reality is what we're showing you here is a lot of choice and a lot of quality options for us to pursue. '26 is really about drilling some exploration wells in the Bedout Basin offshore Western Australia and Beetaloo. We'll probably start some of the backfill activities in PNG, and that will be the focus really in '26 as we bring on a steady state first full year of Barossa. And of course, we're ramping up at Pikka Phase 1. And so from that point forward, projects will be competing. They'll be competing to get into the queue to beat each other to be the next project in the line, and that's going to help you fit into our capital allocation framework. So we're going to be very disciplined and phased and very focused also on the capacity of the organization to deliver these projects and deliver them well. I mean, it's been -- we've been very, very focused on keeping a quality project team on the Barossa project, to ensure that, that meets all of its objectives given all the noise and all the activism that's been challenging that project over the years. I'm glad to say that, that has started to come through as we get to the final stages of that project. We delivered a quality outcome at Moomba CCS in the end. And of course, with Pikka. We will have a cost impact due to the inflation, particularly in the area of logistics, but the progress on that project is going really well. The execution is going really well. So we're very focused on delivering those in the short term. And then we'll reevaluate through '26 what the next cab off the rank is. But my suspicion is we'll do some exploration -- not suspicion, my -- the plan as we see it today is we'll do some exploration in the Beetaloo, in the Bedout Basin. And you're probably looking at something progressing PNG in '26.

Your next question comes from Nik Burns with Jarden Australia.

The first one is just -- or just a follow on from Adam's one there on Slide 26. I guess, I just have another question. Just trying to link it back to your change in capital allocation framework you announced in November last year. Now that it does include growth CapEx. It is quite important for us to get a reasonable steer on exactly what growth is going to come through when? And from what you just said, it doesn't sound like any of these material, I guess, chunkier growth -- new growth projects are likely to reach FID maybe this year or maybe even next year and the focus is going to be more on backfill. So is that the right way to think about it? What do we -- how do we think about sort of annualized or average growth CapEx over the medium term? And given you have flagged these backfill opportunities, that ultimately appears in your sustaining CapEx. So should we be thinking that your sustaining CapEx will lift over the next few years as these projects start to come through as well?

Thank you for that, Nik. Look, I mean, I think what I would say is the one that I'd expect to FID something in the next 12, 14 months in PNG. I expect to FID something in PNG. It will be 1 of the 2 or 3 options that we're looking at there. But you're right, the rest of them are a little bit lot long dated. We've given you guidance that we'll increase our production through '26 so that by the end of '26, our production will be more than 30% higher than what it was in 2024. So we've given that guidance. And then we've given additional guidance at last year's Investor Day where we say we expect to stay in that range between 100 million and 120 million BOEs through the 2029, 2030, so in the 5-year horizon. And that's because that's the period we think we'll be building the 1 or 2 other projects in the portfolio. So that -- for the next growth in production, which would be beyond sort of 2030 or around 2030. And from this slide, you can see what we'll be competing. If you're looking at backfill for LNG projects in Australia, you'd be looking at Beetaloo. If you're looking at [Technical Difficulty].

Pardon me. We'll just reconnect the speakers 1 moment. Thank you for waiting, the speaker has been reconnected.

Sorry, the network, the gremlins got us. Now where did I get to there, Nik, because I was on a role?

Yes, you were on the role. You're talking about backfill for LNG, talking about the Beetaloo that's the last we heard.

All right. So what I was saying there, Nik, was that if it was LNG in Australia, the Beetaloo would be the opportunity we see there that delivers that at scale. If it's PNG, if we're doing Papua or P’nyang in the next 4, 5 years, bringing that on. And obviously, there's nothing else needed while that's coming on. And so the next one goes behind that in the queue if that makes sense. In terms of the oil and gas assets, really Pikka phase 2 and Bedout Basin are the 2 projects out there. What I would remind you, though, is in PNG with project financing. And that will be around the 50%, 60% mark will be project finance. That's the target anyway. And the equity financing of those activities is back-ended within that financing model. So basically, it's the financing capital that's used first, right? And how you finance those. So in terms of how you think about modeling that, I think that's an important thing to sort of clarify. So really, that's how we see the order, and it's got to fit within the capital allocation framework, and we'll work hard to do that.

That's great. I appreciate it. And my second question, you just talked before about Barossa ramp-up. I just wanted to touch on Pikka. It sounds like things are going well on the pipeline activities there, but -- and maybe that's no longer on the critical path, but it sounds like you need to barge some equipment in and now maybe that's on the critical part. Can you just talk about what challenges do you foresee there? And what our best case start-up time line looks like now?

Well, it's like everything else, Nik, you've been in the business long enough, but I'm sure you recognize that once you clear one hurdle, your eyes go onto the next hurdle to achieve the goal, particularly an acceleration goal. And it's great to see that the activities are going well. The drilling is faster. The pipeline activity, the productivity is way higher than it was last year. So unless there's some massive thought that happens this month, we'd be very confident that we're going to get the pipeline activities completed this winter. And that was a big -- the main hurdle to allow for us an early startup. All we're saying is that we need the barge Hay River opportunity to be realized to move our production modules up the Hay River. And so that -- every year what happens is, you get a bunch of snow falling on the mountain ranges around Mackenzie and Hay River regions, and it fills up that Mackenzie River system. And all the indications that we're getting a normal and in some cases, even above normal precipitation levels at this point in time, but you never really know that until the spring. And I always said, we'd make the call. We've make the call in the second quarter sometimes when we know everything is in place. Now I actually thought when I made that statement some time back that the only real sort of barrier to that would be the pipeline because that's a big challenge. But the reality is this is what we've always had is something that we need to clear. And so I just don't want to -- I'm just being conservative at the end of the day, maintaining guidance as mid-'26 because if we don't get that -- if that snow doesn't go and fill up the river to the right levels and I believe last year or the year before was the first time in 84 years, I think the water levels were low. And so we're just being cautious. The other plan, of course, gets us on track with the current schedule of mid-'26. So we'll maintain that guidance until we know for sure, and we'll know that sometime in Q2.

Your next question comes from Tom Allen with UBS.

I was hoping you could please discuss any broader opportunities that you see in the portfolio to accelerate deleveraging and lift those capital returns. So obviously, when Barossa and Pikka come online, that will be the big drivers. But thinking back to 2016 at the outset of your strategy to improve shareholder returns, you had an asset recycling initiative that was successful in contributing to that strategy. Santos also looked at infrastructure tolling with third parties. So do you see opportunities for these types of broader initiatives in the current portfolio?

Yes. I'll have a go at that one, Tom. So I think the one thing that you did mention because you mentioned quite a few of them, and that's all consistent with how we're thinking about it. It's just really looking at our continued partnering strategy around who would we like to partner with us when we think about the long-term prospectivity of the Beetaloo. As we get closer to first oil and first production on Pikka, is there someone who would like to come in now that, that project is derisked and so on and so forth. And so we really look across the whole portfolio to think about. Are there different structures we could think about? Are there things we can do with the midstream. And of course, who could partner with us on that. So there's no stone that goes unturned on that, Tom.

Yes. And I would just add to that, further expand, Tom, if you look at something like the Beetaloo which is getting a lot of interest across the market, our equity position is very high there. So obviously, we'd be looking for a strategically aligned partner to come in and help us develop that.

That's clear. Final question relates to third-party gas supply into GLNG. So the first material contract expiry occurs on 30 May this year. Can you share what proportion of the expiring contract has been recontracted with supply from the domestic market? And can you comment on whether you expect GLNG to face constraints in recontracting expiring third-party gas for the broader East Coast domestic market over the next 5 years?

Well, look, I mean, I think for all contracting of third-party gas into LNG facilities, I think there's going to be a pressure to reserve or commit some of those volumes to the domestic market on a go-forward basis. I mean, I think I'd be -- I think Blind Freddie would see that, that's going to be the case, right? So you got to expect that. You got to remember, though, many times, the pipeline coming south from Queensland is full. And so the reality of how much you can ship down through that pipeline from Queensland to the southern markets is actually quite limited. And so it won't be all the gas. And I can't comment on the recontracting discussions that are going because, obviously, they are confidential. But I'd still expect a significant volume of CSG gas to be committed to the LNG projects going forward. But I do think there'll be some of those volumes that will be committed to domestic market over the longer term. But of course, that brings me back to something like Narrabri. And the fact of the matter is that many of the East Coast gas supply issues go away with the Narrabri project. And my message to all governments, whether it be federal or state, is that if they want to take the pressure off of the gas market, sit around the table and work out how they can help move that project forward because there's a solution there. And it's a relatively low-cost project to deliver up to 200 terajoules per day into the East Coast market and Santos has committed all of the volumes from the Narrabri project for the domestic market. So the solution is there.

Your next question comes from Saul Kavonic with MST.

I'm going to come back just on the GLNG backfill questions. It's obviously been reported in some press that, for example, the Meridian Gas Plant is for sale and GLNG being a lead contender for that. I don't expect you to comment on that, but just perhaps more broadly, should investors at least consider the possibility that there might be some acquisitions for backfill of GLNG. And if there is acquisitions, would that -- the price take for any acquisitions factor into free cash flow for dividend purposes?

That's -- so -- I'm going to try and answer every bit of that question, if I can. So I missed anything, you can pull me up on it. But look, I think the way I would check you're, right. I couldn't comment on whether we were or we're not looking at acquiring any particular assets in Queensland. I think the one thing I can say though is that the GLNG partners are very aligned on the need to get more backfill. And whether that be coming over from the Beetaloo or whether that would be from additional resources in Queensland, time will tell what they're doing. But, we'll, obviously announce anything we do in that space if and when we do that. In terms of the -- how would it be funded? Well, I guess, we'd have to look at that at the time. I wouldn't see any acquisitions being that material. I can't think of anything that significant that we would be acquiring, and therefore, if we were, it would be more about the annual drilling budget to bring online, which is more of that sustaining CapEx -- those sustaining CapEx numbers. And if you think about how our sustaining CapEx profile goes towards the end of this decade. It starts to tailor off as we drill up most of the feedstock of our indigenous reserves across GLNG. So I would see any other CSG type drilling for GLNG really just replacing the CSG drilling we're doing in indigenous field today. And so I wouldn't think you're going to see GLNG, for example, acquire anything in Queensland or get anything in Queensland that's going to fill up GLNG. So it's really just going to go into the queue of sustaining development reserves. And likewise, I would imagine anyone who is in the data room looking at that particular asset you referred to is probably thinking about trying to get that gas to LNG facilities, right?

Understood. I guess, the follow-up to that is if you've got CSG drilling rolling off later this decade, and you need to -- and you do ultimately do something to increase that drilling elsewhere that's going to be CapEx, which is not factored into the all-in free cash flow outlook previously provided.

So Saul, and again, going back to those notional outlooks, I think we put in those with sanctioned projects and excluding major development spend, and they weren't meant to provide a forecast, particularly not for the sustaining CapEx and renewals on that. So I wouldn't try to compare those to when you look at the long-term forecast. But as Kevin said, I think when you think about our new capital allocation framework and the fact that, that's all in free cash flow, it actually doesn't matter because every dollar we spend, whether it be sustaining or major development spend is compared. And of course, the total production is what gives the revenue that helps that balance out and provide the prioritized shareholder returns as well as sustainable growth through the cycle.

And of course, allowing the couple of years for dewatering, of course, you get the revenue from that additional gas anyway, yes. That wouldn't be in our forecast either.

Yes. Understood. And lastly, just on Barossa. Can you just walk us through the time frame for when the FPSO would -- the floater would leave Singapore to first gas? And if there's any outstanding approvals which present risk to that schedule?

Well, we've got 1 more approval to get. It's just like most of the other projects at the EP approval for the FPSO to hook up commission and start production. And we're in the process of -- we're going through that process right now with NOPSEMA. And that process is going like it always goes. So there's nothing irregular about that process. It's just -- it's the normal process. We don't see any major issues there. And in terms of the timing, I think the last window that BW have locked in for the sale is late March to late April. So we've got a lock in a 1-month window, and so I would expect it to sail in that time frame. And that puts us on course. Then we're seeing Q3. Obviously, that can be anywhere from 2 to 5 months to sail and commission the project based on that time line. And, yes, it's on track to deliver in that time frame.

Your next question comes from Mark Wiseman with Macquarie.

Kevin and Sherry, just on the market valuation of the company. I guess, since the Oil Search deal, the value recognition by the market has been disappointing. We think these assets are worse a lot more than what the market has been willing to pay. And back in 2023, you did sort of acknowledge the potential for corporate interest and/or restructuring. I just wonder, with the growth starting to come through, really, by the end of the year, it sounds like your growth strategy is largely delivered either by the end of this year or early 2026. In terms of self-help to get that value uplift better recognized, are there any levers that you can pull in terms of demergers or asset sales? Is there anything you're thinking about or strategizing that you can talk about?

Well, look, I mean, I think, first of all, Mark, that's a good question. It's a great question, in fact. When it comes to growth levers, the myopic focus within the organization right now is delivery of Barossa. And as I said earlier on, remarkably, remarkably given everything Barossa is now on track to be delivered. If we can deliver in Q3 this year like we've promised, then right now it's on track to do that for the original FID promise. So we're not seeing any spend of the additional $200 million to $300 million that we guided the market to around 18 months ago. So that's quite a remarkable outcome when you consider everything that's happened on that project. And with Pikka being on track, on schedule. And to the revised cost estimate we put out there last year, the guidance we put out there last August, I think it was. If we can do that, then I'd be very pleased with an outcome that would have delivered Moomba CCS, Barossa and Pikka, all FID-ed in the middle of COVID for something like within 5% of the original FID budget promises. And so the myopic focus in the organization that I hope and that I think will deliver the value that you're referring to is deliver those projects and deliver them well and have them producing to the original FID promise. And so that's what we're focused on internally. In terms of other things, the other lesson I learned in 2022 is don't see what you're going to do, see what you've done. And we're pretty disciplined up until then. And I acknowledge that I learned a [ sour ] lesson by talking about sell-downs I wanted to do, and then we never realize them. So I wouldn't comment on the levers that we could or might pull. I would just say that we're looking at all the levers across the business and assessing every opportunity. And if it makes sense for our shareholders, we'll pull those levers and we'll announce when we've done that.

Okay. That's clear. And just final question. Perhaps this one is for Sherry. Just on the tax losses on the balance sheet have gone up a little. Could you just remind us, when do you expect to start paying Australian corporate tax again? And as these dividends are expected to rise over the next several years, just wondering when you can start franking them?

No, great question. And the clear answer to that is that getting Barossa on stream and starting to have significant production and revenues around that is going to be the key element that will drive us to have franking credits that can then apply to the dividend in Australia. So you're talking in the coming years, obviously, I can't predict exactly when that's going to be. It will be subject to commodity prices, all the other moving elements, but it's really Barossa revenues that will drive that.

So our next question comes from James Byrne with Citi.

Just conscious of the time, I'll keep these super brief. Just conscious not to double count the benefit of the cost outs. Can I presume that there's little to none of that in the guidance for 2025 for either CapEx or unit production costs?

Yes. I think that would be a very -- that's a great question. It would be a correct assumption. So this is things that we'll think about when we compare it to our 2024 baseline. And as we said, we'll give you more info as that comes through. We're really expecting that to start coming through in 2026 and beyond. You do note when you look at our guidance, we've got a fairly wide range around that, and that's really just around the uncertainty of exactly when Barossa comes in. So obviously, hitting that target or even getting slightly ahead of that will help us to tighten up that guidance as we go through the year.

Very clear. Secondly, Alaska. You've got very good drilling performance, Kevin, 25% sort of savings on drilling time, I think it was. There's no CapEx reduction in that project. I'm just wondering whether the savings you're making on drilling are absorbing higher costs elsewhere? And earlier on the call, you called out some of those logistics challenges?

Well, I mean, No. We are getting some savings in the drilling cost. So they are coming through in the overall project. Too early to say if that's going to result in us coming under materially. Remember, for Phase 1, Phase 1 goes beyond first oil. There's 44 wells, I think, in total drilling and injector wells for Phase 1. And that will go on drilling for next couple of years beyond first oil. And so we will continue seeing the benefit of that drilling performance improvement. But I think the big opportunity is what impact that would make for subsequent developments because when we look at Phase 2 and other growth opportunities on the North Slope. Our current assumptions would have the original drilling times and costs baked into those. And so that's a very significant opportunity. What I would say right now, given the logistics, and we talked about the Hay River stuff earlier on. We're not going to bake any savings in. The guidance we put out there previously last August remains, and we're very confident we can deliver on that.

I might actually just squeeze in another super quick one. Beetaloo some drilling coming up over the next sort of 12 to 24 months, what success looks like in Beetaloo?

Success looks like good well tests and us moving further forward and building conference to an FID of a development that can offer backfill opportunities to potentially GLNG and potentially expansion opportunities for Darwin, which I'll remind everyone, Santos has EIS approval for expansion in Darwin for up to 6.6 million tonnes. So on that, I'm going to cut you off, James. Allowed that third because you were the last person on the call. But I think that's the end of the Q&A. Thank you. And I look forward to seeing everybody on our road show over the next couple of weeks. Thank you very much.

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