Thank you for standing by, and welcome to the Woodside Energy Group Limited Half Year Results 2025 Conference Call. [Operator Instructions] I would now like to hand the conference over to Ms. Meg O’Neill, CEO and Managing Director. Please go ahead. Marguerite Eileen O’Neill: Good morning, everyone, and welcome to Woodside's 2025 half year results presentation. We are presenting from Sydney, and I would like to begin by acknowledging the traditional custodians of this land, the Gadigal People of the Eora Nation, and pay respects to their elders, past and present. Today, I'm joined on the call by our Chief Financial Officer, Graham Tiver. Together, we will provide an overview of our half year 2025 performance before opening up to Q&A. Please take the time to read the disclaimers, assumptions and other important information on Slides 2 and 3. I'd like to remind you that all dollar figures in today's presentation are in U.S. dollars unless otherwise indicated. Turning to Slide 4. I'm very pleased to present a strong set of half year results today. They demonstrate outstanding performance across our portfolio of world-class assets, efficient execution of our major growth projects and continued strong returns for our shareholders. During the first half, we have remained focused on delivering against all aspects of our strategy and investment case, providing energy, creating and returning value and conducting our business sustainably. We combined strong sale and reliable operations over the half with reduced unit production costs, maximizing value from our core assets. We continue to demonstrate excellence in project delivery across multiple major projects, including Scarborough and Trion. In April, we approved the final investment decision on Louisiana LNG positioning Woodside as a global LNG powershouse. Louisiana LNG builds on our proven strengths in project execution, operational excellence and LNG marketing, to…

And ladies and gentlemen, it seems that we may have a technical issue with the main speaker line. Please stay on the line while we try to reconnect. Thank you. And everyone, we're reconnecting the speaker line. Please proceed. Marguerite Eileen O’Neill: All right. I'm not sure what happened there. But I'll start with Louisiana LNG because it's a [indiscernible]. As I mentioned earlier, Louisiana LNG is a game changer for Woodside, set to transform our company into a global LNG powerhouse and deliver enduring value to shareholders for decades to come. On Slide 15, you will see that since the completion of the acquisition in October last year, we've secured a highly competitive EPC pricing for all 3 trains, selected a high-quality infrastructure partner to share the capital expenditure, secured long-term offtake agreements with Uniper and signed the long-term gas supply agreement for feed gas. Following FID in April, we have maintained strong momentum on the project as we target first LNG in 2029. As outlined on Slide 15, construction of Train 1 is 22% complete, and we are targeting first structural steel on site by the end of this year. In June, we completed a 40% sell-down in Louisiana LNG infrastructure to Stonepeak. This will see Stonepeak contribute $5.7 million towards the expected capital expenditure including contributing 75% of the capital expenditure over both 2025 and 2026. This strengthens our balance sheet and our ability to fund our growth projects and provide shareholder returns. We continue to receive strong interest from high-quality potential partners as we explore further sell-downs. Slide 16. There are several strengths to the traditional U.S. LNG models, including abundant low-cost feed gas and access to Asian and European markets. Louisiana LNG builds on these strengths. The project itself is extremely competitive with a fully…

Thanks, Meg and hello, everyone. I'm pleased to present a strong set of financial results [Audio Gap] it's worth calling out Sangomar's cash contribution of approximately $800 million. Our EBITDA margin of 70% remains peer-leading, an outstanding result given lower realized prices and ongoing inflationary pressures. It's reliable and cost-competitive performance has translated into half year earnings of $0.69 per share, coupled with our consistent approach to capital management, this provides our balance sheet, the resilience and flexibility to continue delivering strong returns for shareholders, while funding value-accretive growth. Moving to Slide 21. We continue to deliver our business in line with our capital management framework, which remains unchanged. We operate with discipline and focus. We continue to exercise strong cost control across our business, once again achieving a measurable reduction in unit production costs. The same discipline is applied when making investment decisions, adhering strictly to our capital allocation framework and ensuring alignment to our strategic goals. And we are disciplined in how we position the balance sheet to achieve these goals. Levers such as the sell-down of 40% interest in Louisiana LNG infrastructure to Stonepeak assist in strengthening our balance sheet metrics while also bringing a quality partner into the project [Technical Difficulty].

And everyone, once again, we seem to be having technical difficulty with the main speaker line. One moment while we try to reconnect the line. And thank you for standing by everyone. We have reconnected the speaker line. You may proceed.

It's Graham Tiver joining again. I do apologize for the technical difficulties. What I'll do is I'll start from Slide 21, the capital management framework slide. We continue to deliver our business in line with our capital management framework, which remains unchanged. We operate with discipline and focus. We continue to exercise strong cost control across our business, once again achieving a measurable reduction in unit production costs. The same discipline is applied when making investment decisions, adhering strictly to our capital allocation framework and ensuring alignment to our strategic goals and we are disciplined in how we position the balance sheet to achieve these goals. Levers such as the sell-down of a 40% interest in Louisiana LNG infrastructure to Stonepeak assist in strengthening our balance sheet metrics while also bringing a quality partner into the project. As Meg mentioned, Stonepeak will provide $5.7 billion towards the expected capital expenditure of Louisiana LNG and importantly, on an accelerated basis, will contribute 75% of expected project capital expenditure in both 2025 and 2026. This innovative approach has improved our liquidity and keeps our gearing within the target range. The capital management framework underpins a healthy balance sheet, allowing us to invest in our future while providing strong returns to our shareholders. When referring to returns, our dividend policy is to pay a minimum of 50% of underlying NPAT. We target paying between 50% and 80% and for more than a decade, we have consistently paid at the top end of this range. As highlighted on Slide 22, we have achieved this once again with a healthy interim dividend of $0.53 per share fully franked, representing a half year annualized yield of 6.9%. We have taken important steps to maintain the balance sheet strength and pay a dividend at the top of…

[Operator Instructions] Your first question comes from Gordon Ramsay from RBC Capital Markets.

Congratulations, Meg and team on a great result, really encouraged with what we're seeing. I just want to pick up on Sangomar. Obviously, you've delivered exceptional operating performance with that field and reservoirs performed very, very well. The Phase 1 production is based largely on the S500 sand development. You made a comment today that Phase 2 could leverage off existing infrastructure. Are you able to provide an update on the performance of the injector producer payers in the S400 sand units? And when Woodside might possibly be in a position to advance what appears to be encouraging initial results from those wells. Marguerite Eileen O’Neill: Yes. Thanks, Gordon, and we appreciate your ongoing interest in Sangomar. As you would have seen in the announcements, we made a reserve add based on the S400 performance early in the period, that was about 7.1 million barrels approved and 16 million barrels to T+P. So some initial positive signs in the S400s. And the second reserve add that we made subsequent to the period that's noted in the report of 18.4 million barrels is associated with the S500. So that main portion of the development continues to perform very well. We continue to gather data. So we believe that we'll need, call it, 12 to 24 months of production data to inform decisions around Phase 2. But conceptually, as I mentioned in the call, the intention would be to leverage the existing FPSO and to continue to tie back subsea wells to the infrastructure. As you can well appreciate, that's a very capital-efficient way of continuing to develop the asset. So we'll keep you posted as we start moving those opportunities through the gate process.

And just one other question for me, just on unit production costs. You brought that guidance down to $8 to $8.5 a barrel oil equivalent. Again, can you just kind of just run through how you've been able to do that? Obviously, Sangomar has performed very well, but also, are there other aspects to the cost reduction that we should be aware of? Marguerite Eileen O’Neill: Sure. So Sangomar has been really a star with really strong production. And if you look at the unit production cost for Sangomar itself, it's very competitive and has helped bring down our average. We also have been working across the business to bring costs down. In the first half, there were some one-off cost reductions in the U.S. and then there's an activity set that will take our full year UPC into that guidance range of $800 million to $850 million above where we are for the first half, which is the $770 million.

And your next question comes from Tom Allen from UBS.

Maybe just starting with Louisiana LNG. So just knowing that we've been through a few updates where negotiations on equity sell down have been ongoing. Wondering, Meg, if you could please provide some color on what or if anything has changed relative to Woodside's expectations on sell-downs that we discussed at the Feb results. Is Woodside and prospective partners seeing stronger- than-anticipated competition from competing projects or is it the subtle differences in the EPC arrangements across projects? Obviously -- Woodside obviously have a fully wrapped EPC with Bechtel. Or is it the political environment, adding complexity and timing risk to the negotiations for project equity? Marguerite Eileen O’Neill: Thanks for the question, Tom. So with Louisiana LNG, as we said in the call and I've said all along, we think this is an advantaged projects. And you just look at the numbers, you look at our construction costs, the UPC -- sorry, the dollars per tonne construction cost, very competitive, and you would have seen numbers released from others in this space that would suggest that there's inflationary pressures affecting costs that are getting locked in subsequent to the Louisiana LNG project. We're being disciplined. The key focus for us is getting the right partner in and getting fair value for Woodside shareholders. So it's really similar to what we did with Scarborough and Pluto Train 2, where we brought in an infrastructure investor early into the part of the project where the investment and the returns met their expectations. And we're being now very disciplined in who we want to bring into the HoldCo. As I think I said -- I probably would have said in a previous call, once we took FID, that really opened the door to companies to come back into the process. So we've been running a very fast process and some companies said, we're interested, but we can't meet your time line. Now that we're post FID and we're proceeding into the execute phase, that's allowed some players who need a little bit more time to come to the table. So again, we're being disciplined, and we'll bring quality partners in at value that's attractive to our shareholders.

Okay. Second question, just over at Beaumont ammonia, please. There's just a little slip in the schedule for first production out of Beaumont to later in the year. Are you able to share just some color on what happened there. I think we've sort of previously guided plans to sell-down the project and enter into offtake, is obviously still ahead. Can we assume that's well advanced with partners and offtake and that will probably come through over the quarter, ahead of first production? Marguerite Eileen O’Neill: Yes. So I don't recall us guiding to sell them. We have no process underway to sell-down Beaumont. Our focus very much is on getting -- working with OCI to complete construction. And just to remind you and the other callers, the obligation to complete construction and to deliver an operational plants to very clear performance standards is OCIs. And so the delay in schedule is due to some delays in construction. But again, that's not Scope that Woodside is managing and there is no cost impact to us other than the delay of the second payment, the completion payments. And as we signaled, I think, in the second quarter, that completion payment is going to likely be made in 2026 and not this year. So that was communicated in the 2Q. So we are working on the marketing. That's really a critical focus area for us is ensuring that we've got buyers ready to purchase the ammonia when we start up later in the year. And the second phase, of course, is starting up the low-carbon ammonia production, which will be in the second half of 2026. And that's when we'll be able to market the products, and we are marketing the product already to try to attract those premium pricing associated with the lower carbon intensity of the blue ammonia that we'll be producing then.

And your next question comes from Adam Martin from E&P.

I suppose, firstly, just on the Bass Strait, could you walk through those sort of potential for development opportunities sort of what needs to happen to get those into FID, please? Marguerite Eileen O’Neill: Yes. Thanks, Adam. And I really appreciate the interest in the Bass Strait operatorship transition. We were very excited to be able to conclude that negotiation with ExxonMobil, particularly with the ability for us to solely develop some of these opportunities. These are gas discoveries that have been -- that were made many, many years ago, they've been in the contingent resource for a period. Our teams have been doing scoping work for well, a number of months to understand what the potential is. So we need to work through our normal technical due diligence. But we do have the ability to take a final investment decision, that would not happen until the operatorship transition has completed.

Okay. And just a second question. Obviously, you got the $443 million restoration movements. I think that relates to sort of CapEx going up a little bit from previous expectations. Can you just talk through timing of that future spend and I suppose why that's not a risk for other programs like the Bass Strait moving forward, please? Marguerite Eileen O’Neill: Yes. So One of the challenges we have faced with -- with the decommissioning work this year has been the condition of some of the closed sites. So these are fields like Stybarrow, Minerva and Griffin that have not produced oil and gas for many years. And the condition of the equipment, as we found it when we got into the field was not as it was documented. And so that's resulted in a number of challenges in recovery. I am very pleased to say that we have plugged all of the wells. So when you think about environmental risk, that is where it is highest. So I'm very pleased that we have completed that scope of work. But we've had to take a bit of a step back, recognizing some of the challenges we've encountered. We're back to doing some more engineering work to understand how do we manage the safety and environmental risks that we've found. The additional spend will happen over the coming years. When we have more information, we can put further information out there to the market. But we're going to take our time. And as you would have seen, NOPSEMA has revised the general directions associated with these legacy assets, giving us more time to ensure we have good engineering work plans, and we are managing the construction and the safety and environmental risk appropriately. When it comes to Bass Straits. So one of the advantages we've seen and we've seen Enfield is probably another good example. When you do the decommissioning work shortly after completing production, you're able to execute it much more efficiently. Bass Strait as we noted in the report, have plugged and abandoned more than 200 wells and the platform removal campaign is deep in the engineering phase, and we've been going through all of the normal engineering and project gating processes to ensure that we have our arms around the cost. That's a scope. And I think we've indicated this before, the bulk of the scope will happen in 2027. So we're working very closely with ExxonMobil. But as we've been advancing that project, everything is remaining on track from a cost perspective.

And your next question comes from Saul Kavonic from MST.

I guess, some latest update on the MOU with Aramco. Are those discussions still proceeding in line with your expectations? And could you elaborate -- include just a bit of elaboration on what it means by collaboration on ammonia and how that might relate to Beaumont. Marguerite Eileen O’Neill: Sure. So not a lot to update on Saul. So we were very pleased to be invited by Aramco to participate in the U.S. Saudi Investment Forum back in May. And very pleased to execute the MOU with them, looking at U.S. investment opportunities in both LNG and low- carbon ammonia. Look, we continue to build a very strong and constructive relationship with Aramco. And when we have something announceable, we will announce.

And your next question comes from Nik Burns from Jarden Australia.

Meg and Tim, just first question, maybe just on the dividend, paying out again at the top end of your payout range. The gearing at 30 June is at the top end of a gearing target range as well and the dividend probably could push you over the top end of that. Maybe can you talk about the factors that led you to be comfortable with retaining an 80% payout ratio for the interim result? And whether being at the upper end places any risk of having to pay out below the upper end over the next few periods. Marguerite Eileen O’Neill: I'll let Graham take that.

Thanks, Nik. Yes, as you know, through our capital management framework, we're not just looking at a point in time, we're looking through into the future as well. We're really comfortable and happy where the business is today. It's performing well and the balance sheet is in a strong position. I guess I'd call out that the strong underlying performance of the business continues to shine through, generating very strong operational cash flows. The strong financial discipline around our cost and CapEx control. We've got the investment grade credit rating. And I guess we've been able to optimize our portfolio during the period as well. So with Stonepeak coming in, as I said in my speech, quite an innovative approach with the funding in that 75% upfront in the 2025 and '26 and then the Angostura sell-down as well. So you bring all that together and the business is in good shape, and we're confident with our forward view on being able to continue to generate strong cash flow invest in our growth projects, our immediate future and also provide strong returns to our shareholders.

Got it. And just a question on marketing. Meg, you called out the strong returns being driven by the marketing team, circa 8% of group EBIT in the first half. I was interested in the fact that you've retained your gas hub exposure guidance of 28% to 35% for the full year. I think on my numbers, the average around 24% in the first half. Can you talk a bit about the current state of the global spot LNG market? And looking ahead, what's going to drive a material increase in your sales into the spot market in the second half of the year? Marguerite Eileen O’Neill: Thanks, Nik. It's a great question. And I think the results really validate our strategy to preserve a certain amount of our LNG to sell at gas hub exposure. So when we look at the difference in pricing between oil-indexed LNG sales versus gas hub indexed LNG sales, it's a $3 premium. So a very significant uplift associated with the way we have our pricing exposure managed. And as you'll note, and as you've caught on, our guidance for the full year is higher than what we've delivered in the first half. So obviously, our performance in the second half will be above where we are today. And when you look at what's happening in the market with softening in Brent, but continued strength in the LNG pricing that bodes well, and that continues to reinforce the value of our strategy. Now when we look further down the road, I think we've been pretty clear that our target in the next couple of years is to retain that exposure of, call it, circa 30% gas hub indexation. And as we start up Louisiana LNG, we'll continue to be refining our intentions around price indexation and exposures. One of the things that's very clear, the fundamentals for the 2030s are very robust. When you look at things like Asian demand underpinned by economic growth, declining domestic supply in many Asian nations that have historically been strong gas producers. So if you referenced WoodMac, for example, they're expecting more than 100 million tons of new pre-FID LNG supply will be required by 2040. And so we're very bullish in the long term. But we'll continue to be refining our price index exposure over time. We've got a fair amount of opportunity and flexibility with the Louisiana LNG offtake. And we'll be looking to balance that in a way that best works for our shareholders.

And your next question comes from Dale Koenders from Barrenjoey.

And this question might be more for Graham. In the second quarter report, you reported CapEx and exploration of $2.5 billion year- to-date, including net contributions in Louisiana, which benefited from the $1.8 billion Stonepeak contribution. It just $4.3 billion, on your cash flow statement, you reported $4.9 billion spend on CapEx and exploration. I'm just wondering what the $600 million difference is.

Sorry. Can you -- so I'm just looking -- yes, so what you've got here is the, is the cash flow view and that number will also include borrowing -- capitalized borrowing cost as well. Whereas what we report to the market is just a pure view of CapEx expenditure. And that's not all. That's the major component or the major differentiating factor between what we're reporting to the market and the actual underlying cash flow version or view.

So the $330 million line item that was called out in your cash flow statement, is that -- what is that? Is that borrowing costs as well? Or -- sorry, go ahead.

What I suggest is maybe the team can take it offline and have a conversation with you, but that's the major difference.

Okay. And then just secondly, in terms of cash tax payments, they're a little bit higher than expense. I'm just wondering sort of on a go-forward basis, how you think that delta will play out.

Yes. So as you know, cash tax payments, there's many different factors that play into the cash tax. And obviously, this year, we have had lower prices across the Australian business that's also flowing in. You've got the PRRT. I guess all we can do is continue to provide as much guidance as possible on that but it's very difficult to sit here and say exactly what that tax number will be because there's many factors that play into it, Dale.

And your next question comes from Henry Meyer from Goldman Sachs.

Just on the LNG carrier position, could you give any update on plans to lease or own carriers to support the Louisiana delivery cargoes? And in light of gearing the balance sheet, just what lease liabilities do you expect to carry when they're delivered perhaps related to the Scarborough carriers on order. Marguerite Eileen O’Neill: Sure. So philosophically, Henry, we think there are other companies that are well equipped and well suited to own LNG carriers. When we started up Northwest Shelf, there were some projects owned vessels, but we've moved away from that, and that's probably the industry standard to use leased vessels. The number of vessels, the balance sheet exposure is something that we're working through as we speak. So too early to advise. But as we progress that work and progress those contracts, we will certainly keep the market updated.

Okay. And following up on the decommissioning costs for Griffin, Minerva and Stybarrow. I just wanted to double check one of the comments before. Have some of those challenges encountered been reflected in the estimates for other fields? Or is there work underway to revise those costs as well? Marguerite Eileen O’Neill: So we always -- as we update our decommissioning estimates, which is typically an annual process, we incorporate things that we've learned as we've gone through the process. One of the positives that I would say we've taken from dealing with these closed sites is we're feeding that back into our decommissioning planning for sites that are still operational today. So for example, in our Australia business, some of the FPSOs will be coming offline in the 2030s. We're feeding the lessons learned from these closed sites into those so that we can be more proactive and avoid the sorts of challenges that we've encountered here, and perhaps a point of success is Enfield. So Enfield is a field that Woodside operated. It stopped operations in 2018. We've had none of those issues when we decommissioned the Enfield subsea equipment that we've seen with Griffin and Minerva and Stybarrow.

And your next question comes from Mark Wiseman from Macquarie.

I wanted to ask firstly on the Bass Strait operatorship decision. Could we talk about what the alternative would have been to this. It sounds like Esso was waiting for policy stability from the government and perhaps has come to the conclusion that they wouldn't invest in those 4 development opportunities, the 200 PJs, and so the alternative would have been to remain non-operator and not see any of that contingent resource come to fruition. Is that right? And I wonder, you made a comment there, Meg, around the workforce. It sounded like you see some benefit in bringing those Esso experienced staff into your team. Could you perhaps elaborate on that as well, please? Marguerite Eileen O’Neill: Yes. Certainly, the alternative mark would have been for ExxonMobil to continue operating. As I said, those 4 fields that we've identified and have the rights to exclusively develop our discoveries that have been on the books and the joint venture is known about for a very long time period. So again, I suspect, although I can't guarantee that those likely would not have matured, had we stayed with the existing operations. And on the people side, yes, we're super excited. There's a lot of talent and capability within the ExxonMobil workforce in Australia. Our Head of Operations in Australia came out of that workforce. So we know the people and I've been really pleased with the positive response we've seen from the ExxonMobil folks who, I think, see potentially a little bit longer horizon to be able to live and work in Australia with Woodside as operator, again, recognizing we've got a little bit bigger footprint and recognizing our desire to continue to be a significant player in the East Coast gas market.

Okay. And just finally for me, just on Santos. Obviously, Woodside and Santos had been in discussions a while back, those discussions come to conclusion. Since then, there's obviously been a nonbinding offer for Santos. Did that offer from [indiscernible] cause you to review the merits of a merger with Santos? And could you perhaps just comment on what was the appeal back then? And would you still see those sorts of benefits from reengaging with Santos. Marguerite Eileen O’Neill: Yes. Short answer, Mark, is absolutely not. The thing that we -- the reason that we had been exploring opportunities with Santos was the LNG portfolio. We've moved on. We've acquired Tellurian. We've got the Louisiana LNG investment going. When you look at the upside opportunity that's created by having a material Atlantic Basin position, coupled with our material Pacific Basin position. That's actually a better portfolio than combining the 2 Pacific oriented businesses. So we wish them well, but we're focused on delivering our commitments.

And your next question comes from Rob Koh from MS.

So I guess my first question is just on balance sheet management. And I guess you've got sell-down possibilities for Louisiana HoldCo. You've got your Chevron asset swap coming. And lots of other things in train, I'm sure. I wonder, could you comment on the possibility to do any further executory contract type deals like the Stonepeak be on any of the other assets? Is that something we could contemplate? Marguerite Eileen O’Neill: Yes. Look, Rob, that kind of model was something that we've looked at a few times. And we looked at it actually before we took FID on Pluto Train 2 and Scarborough because it is one way to unlock capital, but given the joint venture structures of some of our existing assets, it's more complicated. So we're very much focused on the HoldCo sell-down at Louisiana LNG. And again, it's about getting the right partner at the right price and then executing the transactions that we've announced. So the Chevron asset swap as well as the operatorship transition in Bass Strait.

Yes. And then my second question relates to the restoration rehabilitation provisions. I guess, part A of the question is, can you give us a steer on any kind of contingency should the pipelines need to be taken out? Because I think the provision is made on a pipeline in situ basis. And then secondly, I saw that Chevron has a very old legacy deal for Barrow Island, where there's decommissioning is offset against royalty refund. Just wondering, does Woodside have anything similar like that on the books and within the provision. Marguerite Eileen O’Neill: Yes. So when it comes to the provisions, we take a risk approach to certain pieces of equipment that we think there's a good environmental reason to argue and leave in situ, so things like jacket structures and pipeline. So within the restoration provision, there's a risking that reflects a certain percentage chance that those items may have to be removed. We are doing quite a bit of science, both in the Bass Strait with ExxonMobil as well as in our operations to really understand the Marine habitat that has formed around these assets over the decades they've been in situ. So we are doing work to really understand what's the best environmental outcome, but we have a risk provision in the -- or sorry, a risk cost in the provisions. When it comes to royalty refunds, no, we don't have that same access or that same structure that Chevron has in Bass Strait. It probably is worth noting that abandonment expense is creditable on PRRT and income tax, of course. Again, those are expenses for the oilfield developments. And so that's the structure that we have access to.

And your next question comes from Nicholas Morgan from JPMorgan.

Two questions from me. Firstly, on Louisiana LNG. Could you give some further detail on what the targeted split is for Woodside's equity share of LNG just on a contracted verse spot basis? Marguerite Eileen O’Neill: Look, we want to take about 8 million tons into our portfolio. So the FID we've taken for the first 3 trains is 16.5 million tonnes. We want to keep about 8 million tons of that in our portfolio. But we will on-sell a good portion of that. Now how much we on-sell and the contracting structure, actually, we have quite a bit of flexibility. And as you would have seen from our announcements in the half, we've done LNG offtake agreements with China Resources with Uniper. One of the Uniper agreements was direct from Louisiana LNG. So that's -- I would call that in the 8 million tons, that's not for our accounts. So we do have quite a bit of flexibility in our LNG marketing really to work closely with customers to understand what do they need and to negotiate outcomes that work for both players. But 8 million tons is what we intend to take into our portfolio.

All right. Thank you all for listening in and participating today. I look forward to speaking to many more of you in the coming days. in the U.S. and just how those costs are kind of tracking towards expectations taken at FID? Marguerite Eileen O’Neill: Look, the pipeline costs are still tracking within what was announced at FID.

And there are no further phone questions at this time. I will now turn the call back over to Ms. O’Neill for closing remarks. Marguerite Eileen O’Neill: But I would also like to highlight that we have a Capital Markets Day planned for the 5th of November, and we look forward to talking more about the Woodside business at that occasion. Thank you all.

That does conclude our conference for today. We thank you for participating. You may now disconnect your lines.