BP p.l.c. (NYSE:BP) Q4 2024 Earnings Call Transcript

BP p.l.c. (NYSE:BP) Q4 2024 Earnings Call Transcript February 11, 2025

BP p.l.c. misses on earnings expectations. Reported EPS is $0.44 EPS, expectations were $0.56.

Craig Marshall: Welcome, everybody, to BP’s Fourth Quarter and Full Year Results Call. We’ll be focusing today’s call on the fourth quarter and 2024 performance and the contents of the video that I hope many of you will have seen by now. I also understand there is significant interest in our capital markets update in a couple of weeks’ time. However, I’m sure you’ll also appreciate that we can’t comment on any issues relating to that today. So please focus your questions accordingly. With that, let me hand over to Murray.

Murray Auchincloss: Thanks, Craig, and thanks, everyone, for joining Kate and I on the call today. When I look back at 2024, we’ve achieved a lot. We made significant strategic progress, taking decisive action in reshaping our portfolio and laying the foundations for growth, including 10 new FIDs, including Cascadia and Tangguh, new access to Iraq and India, divesting tail assets in Trinidad, exiting the Empire Wind in the U.S. offshore, decapitalizing our offshore wind business by agreeing to form a joint venture, JERA Nex bp, focusing our EV charging business and our hydrogen pipeline, acquiring full ownership of bp bioenergy and Lightsource bp and recently announcing our intention to sell the Gelsenkirchen refinery. In two weeks’ time, we will build on the actions taken in the last 12 months and provide a comprehensive update at our Capital Markets event.

It will be a fundamental reset of our strategy. It will demonstrate our focus on actions to drive performance, and it will enable us to grow cash flow and returns and shareholder value. With that said, let me focus on today and briefly recap our highlights for this year. Many of our businesses performed well during 2024. Upstream production was around 2.36 million barrels per day, up 2% this year with plant reliability above 95%. It was a good year for trading and its track record for delivering an average 4% uplift to group ROACE now extends to the past 5 years despite the lack of volatility. But we have had a difficult year in refining with a widening outage in 1Q and the challenging margin environment, and we were also impacted by the weaker biofuels margins and trucking recession impact on TA.

We remain firmly focused on taking action to improve our performance across refining and on the work to integrate our recently acquired businesses into BP, driving the synergies and underlying performance that we expect. Finally, on distributions, we grew our dividend per share by 10% and announced $7 billion of share buybacks, including a $1.75 billion announced today. With that summary, let’s go to Q&A. Over to you to get us started. Craig?

Craig Marshall: Thanks, Murray. Given my earlier remarks, I’m going to ask you to limit yourselves to one question so we can let everyone get a chance. We’ll look to close the call by 1:45 p.m. time. There’s obviously plenty of time in two weeks’ time for more questions. And of course, the IR team is available to follow up. So with that, let’s get started. I think we will take the first question from Josh Stone at UBS, please.

Q&A Session

Joshua Eliot Stone: With my one question, I’ll focus on the refining and trading performance this quarter. It was another weak quarter, but you talked about improvement plans. So I just want to get a sense how confident are you, the issues you experienced in 2024 are now in the rearview mirror? And what more can be done to improve the profitability of that division? And maybe if you can give any early insights of how trading has performed during the first quarter, given we’re almost halfway through.

Murray Auchincloss: Great. Thanks, Josh. Thanks for the question. You’re right, it was a challenging year for refining. The industry in the basins in which we are operating were probably bottom of cycle for margin and pricing. So I think that’s an industry-wide issue that we’re a part of as well. But of course, we had the outage in 1Q in Whiting as well, an electrical fault that tripped the plant. In 4Q itself, reliability was fine across the portfolio. We, of course, had a massive turnaround at Whiting. It was a huge program. We replaced the coker tops, which is an incredible effort by the teams. And so that obviously dramatically impacted the results in 4Q. As we look forward, we are confident that we will continue to improve the business.

Gordon can talk about this in a few weeks’ time when we talk through what we’re doing to improve the refining business. We’re focused on four things. First of all, getting plant reliability back to that 96%, making sure that we don’t have material trips. Turnarounds are going well. Maintenance is going well, but we have to stick to it and make sure we hit that 96%, and Gordon and the team are laser-beam focused on that. Out of that then comes the ability to commercially optimize. When you have outages, you can’t commercially optimize. So we think between getting back to 96% and steady operations, that then lets us start to optimize and earn more money. The third thing I’d say is there’s a strong cost agenda across all of CMP, and that will really start to take root in refining in 2025.

And last, we will have a year of much lower complexity TARs in ’25 than ’24. That should all take us back to profitability. And I think we feel confident in that. And again, in two weeks’ time, Gordon can take you through those plans. On trading, it was an average year, a 4% year. Despite the lack of volatility on the oil and refined products side, I think you’ll have seen some of that reported out of competitors about how much — how far down they were. So the teams did well to make sure that we continue to hit that track record that we’ve had over the past 5 years. Now looking forward, refining margins started the year very bad in January. They’re starting to uptick now as we move into TAR season globally. I think the RMMs are up a bit, and we’re starting to see some volatility.

So I think that’s probably all I’ll say, Josh, but we are laser-beam focused on it. We know we need to do better, and we will. Thanks for the question.

Craig Marshall: Thanks, Josh. We’ll turn next to Peter Low at Redburn. Peter?

Peter Low: I just had a question on some of your recent upstream announcements. So your deal with ONGC and then also the redevelopment of Kirkuk. Can you perhaps talk a bit more about what you found attractive about those opportunities and then potentially the sort of returns you might see for those sorts of technical service contract type agreements?

Murray Auchincloss: Great, Peter. Thanks for the questions. Look, we’ve established a pretty strong track record in the Middle East and Far East to being able to help operators with late light developments. So as water starts to come into developments, as you have to develop tricky reservoirs, we’ve built a very, very strong reputation, started in Alaska, moved to [indiscernible] is a good example of it, et cetera. So we have a very strong track record in this, and that’s what’s enabling us to take advantage of these opportunities for direct access like in India and like in Iraq. And ONGC, it’s a services contract. We’re very pleased with it. We don’t deploy cost or capital. Instead, we provide people and advice to drive stronger performance inside that business.

I can’t really talk about what the commercial returns are, but they’re quite attractive for India, and they’re quite attractive for us. We found a nice middle ground where both sides actually can do very well for each other if we can start to drive that production higher. And we believe, based on all the due diligence we’ve done that we can certainly help India with that. And then on Kirkuk, we’re in the final throes of the negotiations now, 5 domes of oil, 20 billion barrels yet to produce, a competitive PSA agreement, competitive internationally. And of course, it’s because of our track record inside the nation that we’re able to help them there. So that — we’ll give you more on Kirkuk once we’ve finished off the negotiations and announce it.

Let’s see when the teams can get to completion on that. But we feel very excited about that, and it will be internationally competitive, and we look forward to telling you more about that. Hopefully, at Capital Markets Day, we can update you more on that.

Craig Marshall: Thanks, Peter. We’ll take the next question from Biraj Borkhataria at RBC. Biraj?

Biraj Borkhataria: And firstly, thank you for the breakdown on the operating cost side, and it’s good to see the sort of internal lens versus what we see. Just thinking about your strategy. It looks like you’re going to be including a more capital-light approach and more JVs and things like that, like the JERA deal. As it relates to your cost reduction targets, are you able to say the sort of quantum of costs that will come off your balance sheet as part of the transactions that have already been agreed? Just so I can get a sense of the magnitude of that.

Murray Auchincloss: Kate?

Katherine Thomson: Yes. Biraj, thank you for the comment with regard to our cost disclosure. We have tried to help people by giving, I think, quite a lot more granularity and specificity than we have done previously. So I’m pleased that, that has worked for you so far. So let’s see. With regards to the capital-light approach on renewables, I think for capital, let’s leave that to Capital Markets Day. We’ll update you comprehensively with regard to capital right across the portfolio at that point. And with regard to cash costs. So we have already been successful in reducing some of our cash costs through focusing our portfolio, which we talked about on previous quarterly results calls. It’s part and parcel of the $750 million of structural reductions that we’ve delivered this year, which is great progress.

And beyond that, we will just update you as we go. We will try and be as specific as we can quarter-on-quarter on the areas where we are delivering cost reductions and point out where they’re coming from with regard to third-party supply chain or focusing the portfolio. So we will make sure we give you enough granularity on that going forward, too.

Craig Marshall: Thanks, Biraj. We’ll take the next question from Doug Leggate at Wolfe.

Douglas George Blyth Leggate: I guess it’s a question for Kate. Kate, I wonder if you could just help us with the continued commentary around the $40 breakeven, but to help us benchmark the expectations for what you announced later this month. And what I’m trying to understand specifically is you had this $900-something million — $917 million one-off cost, I think it was this quarter. And I’m trying to understand what that was? How that influences your view of where the run rate breakeven is currently and whether the financing charges below the operating line are included in that definition. So just help us benchmark the starting point ahead of the Capital Markets Day.

Katherine Thomson: Yes. Thanks, Doug. With regard to the balance point, we’ll update the fin frame in totality in 2 weeks’ time. The $40 balance point is important to us internally as we think about our dividend, it’s a key part of ensuring that it’s a resilient through cycle. In terms of the one-off, so there were a couple of one-offs that we called out specifically in oil and gas. I don’t recognize the $900 million. I recognize about $400 million that we highlighted in the OPO segment. There was $300 million in there, which was associated with the hedging and income from a sale of royalties and about $100 million in the gas and low carbon, really trying to be transparent in helping you as we move towards the first quarter I wanted to demonstrate there were a few things in our fourth quarter results that are unlikely to be repeated in the first quarter. But I’m happy that we sweep up after the call if you have a different number in your head.

Murray Auchincloss: Yes. Doug, the financing costs are inside the balance point, including hybrid and interest expense. That’s all part of the balance point.

Douglas George Blyth Leggate: So $917 million remeasurement of joint venture step acquisition is what I’m referring to.

Katherine Thomson: Thank you. Yes, I can tackle that one very quickly. So the transactions that we had with regard to the acquisition of bp bioenergy and Lightsource bp were both step transition — both step transactions as we already own significant percentage of the equity in those organizations. It’s just an accounting term. The $917 million were both arising with regard to Lightsource bp. It’s just a remeasurement of the existing equity we held in Lightsource bp and a remeasurement of the assets that we hold for sale in regard to Lightsource bp. So it’s a technical accounting noncash.

Craig Marshall: Thanks, Doug. We’ll take the next question from Al Syme at Citi. Al?

Alastair Syme: Not the front on the strategy update, but you’ve put the words fundamental reset out there in today’s press release. So can I ask what’s going on in the last few months in the environment and in your discussions with the Board to change the emphasis from the prior wording that you use, which I think was mid-strategy update?

Murray Auchincloss: Yes. Thanks, Al. Nice to hear your voice. All I’d say is, if you look back at the degree of activity we’ve had over the past 12 months, it’s pretty significant. We have sanctioned 10 new projects, top 30 projects across the business. We’ve accessed new countries. We’ve completely decapitalized renewables. So it’s a sizable shift in the portfolio that we have moving forward. And given the degree of that change, it’s now time to reset the strategy and plot a new beginning for us. So it’s just — we’ve done an awful lot over the past 12 months. And this is the right time now to share that with you, the community, and I’m excited to be sharing it with you in a couple of weeks’ time. It’s going to be great.

Alastair Syme: So it’s not the externalities of the macro environment, Murray?

Murray Auchincloss: No.

Craig Marshall: Thanks, Al. We’ll take the next question from Irene Himona at Bernstein. Irene?

Irene Himona: I had a question on your transition engine EBITDA. I presume this is the last time we will get EBITDA given you’re retiring the metric. But I wanted to focus on bioenergy. It seems adjusted to the same definition that has remained flat at around $700 million a year. Can you give us a sense within that of the split between biofuels and biogas. The question is really about our care. Can we assume that our care has improved within that total since we know that biofuels margins were particularly weak. I mean, liquid biofuels?

Murray Auchincloss: Yes. Great, Irene, thanks. Archaea continues to improve, yes. Last year, we got 9 out of the 15 plants online. We wanted to 3 more are now online and functioning. We have 3 still flowing to midstream, but not yet able to declare start-up. So we’ve established 12 new plants this year, which obviously throw through earnings from ’24 into ’25. So certainly, we’re seeing improvement in Archaea as we move forward. As you rightly point out, bioenergy is challenging — sorry, biofuels are rightfully challenging, especially in Europe, it’s quite challenging. So we don’t see a lot of performance momentum inside biofuels in Europe. That’s why we’re being very, very careful with the sanctioning any new plants. You may have seen a recycling in Australia as well.

But we’re pleased with progress on Archaea. We’re not quite where we want to be. We’re probably 12 months behind progress in Archaea because we had to take our time to make the designs work. We had to take our time to get the permitting right. We had to take our time to get the hookups to the midstream providers, right? So we’ve had to take a bit more time than we originally wanted to and that’s on us. But with 13 plants up now, I think the closest competition is 2 or 3 a year right now. So we feel like we’re in a good competitive position. Prices and demand remain very strong for it as well, and we’ll look forward to continuing growth out of Archaea moving forward. And Carol will give you an update on that in a couple of weeks’ time, Irene.

Craig Marshall: Thanks, Irene. We’re going to see the next question from Lydia Rainforth at Barclays. Lydia?

Lydia Rainforth: And just on the cost base, if I can come back to that, and I echo Biraj’s words on that, it’s actually really helpful disclosure. You do talk, Archaea, about the idea of the kind of strong cost margin ratio. I’m just wondering, is there any way you can sort of talk us through how that’s — what you actually mean by that, how you measure it? And how that might have changed over the last couple of years because I think that cost base and generating EBITDA is actually quite an important part for you.

Katherine Thomson: Yes. Thanks, Lydia. So as we’ve said in the disclosures, quite a lot of this variable cost actually a huge part of it relates to our trading business. And as you would imagine, it’s a very, very margin-focused business. So the analysis of that is just part of the way they work. We pay very close attention to the gross margin that we’re generating on trading. If I look at what’s gone on in the last few years. So there’s been about a 45% increase in shipping costs and trading as freight rates are up. And then the other component part, which you’ll be familiar with is the scale of increase in our LNG portfolio, that’s grown by over 50%. That’s what’s driving our cost base inside that part of the base. In terms of variable costs, though, I think it’s really important to understand that these are directly related to the delivery of margin.

And whilst we need to make sure that they are being efficiently managed, which we do, it would be crazy to put a target on those in terms of a reduction. I don’t want to turn around to Carol and say, please could you reduce your shipping costs that wouldn’t be a great decision point in terms of driving value and returns as far as we’re concerned. So that’s how we think about it. And that’s why we’ve provided the level of granularity that we have and we will continue to provide with regard to our cost base.

Murray Auchincloss: In a couple of weeks’ time, Carol will be talking about the trading business again, Lydia. She will unpack some of this as well. And I think you’ll find that there’s a fixed margin that we have across our business that’s driven by this portfolio of shipping oil or shipping diesel, bunkering and the LNG expansion. So more details to come in a couple of weeks’ time, and Carol will be happy to answer more detailed questions on that then.

Craig Marshall: Thanks, Lydia. We’ll take the next question from Lucas Herrmann, Exane — BNP Exane. Lucas?

Lucas Herrmann: And Murray, I hope the — it went well and — that you’re well. Very brief one. LNG and volumes this year, how much of an increment do you expect to receive from Beach from Tortue potentially attaining volumes from venture? Can you just give us an idea of the tonnes of increase that you’re budgeting for? That’s it.

Murray Auchincloss: Yes, Great. Thanks. Tortue — thank you for the kind wishes. I’m feeling great, Lucas. It’s nice to be back in the office. Tortue and Beach are about 3 million tonnes per annum added, assuming a full year flow. Venture, I’m just going to not comment as the arbitration continues, let’s see how that arbitration goes. Hopefully, we see a ruling in the back half of the year on that and then we start to see flow. But I think between Tortue and Beach, we’ve got 3 mtpa that will come through.

Craig Marshall: Thanks, Lucas. Moving on to Matt Lofting at JPMorgan, Matt?

Matthew Lofting: Two, if I could, please. First, just on cost. I think you showed in Slide 12, about 5 billion of structural cost reduction over the last few years. If I understood right, I think that includes divestments. I wondered if you could break down how much of that 5 is divestments versus underlying given the BP has divested about 20 billion of assets over the course of that period? And then second, I just wanted to ask you about Russia and sort of Rosneft, given debate over recent days and weeks around Russia, Ukraine and sort of see fire scenarios, et cetera. Could You see a sort of a feasible scenario? And could it be sort of palatable for BP at Board level around the case for reconsolidating the Rosneft shares in the future onto the balance sheet. I just wondered how you sort of see that today?

Craig Marshall: Okay. Matt, you’ve broken the rule already. So — but we’re going to take that one. I’m going to let Murray answer the question on Russia, but maybe first, Kate, on your cost question.

Katherine Thomson: Yes. So we’re not planning on breaking this down by portfolio movement, Matt. We’re very clear that it does include portfolio, but we’re trying to give you as much granularity as we can. But I think we need to draw the line in some areas, and where it’s a very big portfolio impact, of course, we’ll try and call it out and help you with regard to understanding the underlying cost base going forward.

Murray Auchincloss: Lots of ins and outs in there as well. And then on Russia, look, our principal focus right now is on divesting the stake. There are more than a dozen countries that have sanctions on the entity. So we think the best focus that we can possibly have is on continuing to divest this and we’ll update the market as we go along on that. Thanks for the question.

Craig Marshall: Thanks, Matt. We’re going to just move to a quick question from Ahmed Ben Salem from ODDO who’s online. Ahmed’s question is, how do you see the impact of U.S. tariffs on Canadian crude on Whiting’s refining margins?

Murray Auchincloss: Yes. Thanks, Ahmed. Pretty difficult to predict is my answer. We have the ability to flow volumes south to north in the United States if we need to. Obviously, the Canadian producers have optionality to flow some product to the West Coast and overseas as well. Upon announcement of the tariffs, the WTI-WCS spread opened up quite a bit, probably absorbing half of that tariff. So I think it’s a very, very dynamic scenario, and it’s very difficult to predict what will happen to margins on the northern tier. And so we’ll just have to watch and see how the market turns out on this one. I don’t think it’s straightforward because there are so many different flows that get impacted with Mexican flows with Southern U.S. to Northern U.S. flows, with Canadian flows.

So I have studied it heavily with the teams, and I’m afraid I find it very, very difficult to predict what will happen, but we will update you in due course as we learn about it. Thanks for the question.

Craig Marshall: Thanks, Ahmed. We’re going to turn to Chris Kuplent at Bank of America. Chris?

Christopher Kuplent: And it’s, of course, dangerous to allow breaking the precedent. So let me try, and this could be a very short answer, but you may have your reasons for not publishing what the surplus cash flow is on a quarterly basis. But maybe you can just yes or no confirm that for the full year, it was somewhere around 4 billion? And if I may, I just wanted to get an explanation how you feel about the value equation from issuing more hybrid bonds in November, which, I guess, will push up your cash outflows in the cash flow statement, which I may make out at around an 8% cost of that carrying value. So I just wanted to understand how attractive you think that is issuing — continuing to issue hybrid bonds to lower your net debt?

Murray Auchincloss: Great. Why don’t we just — we’re going to go back to focusing on one question. So Kate, why don’t you tackle the hybrid question. And Chris, we can follow up with you offline on the other question.

Katherine Thomson: Yes. So you all have heard me say in previous calls, Chris, I do think they’re an important part of our capital structure. We’re not seeking to build towers here. Just to be super clear, what we did in the fourth quarter, which others also did, by the way, is take advantage of a really strong environment. The senior sub-spreads were at an all-time low. And so we were able to issue hybrids in advance of our upcoming maturities in this year and in next year. And it’s really just a value play, right? The hybrid market can fluctuate. We wanted to make sure that when it was in a particularly strong moment that we took absolute best advantage of that. That’s all that’s going on with hybrids. I remind you that about half of our hybrids are fixed cost and also the payments with regard to are fully tax deductible.

So yes, I mean, they’re not the cheapest, but it’s an important part of our capital structure. And we will continue to look very carefully and select maturities as and when the value feels right for us.

Craig Marshall: Thanks, Kate. Thank you, Chris. We’re going to turn to Roger Read in the U.S. at Wells Fargo. Roger?

Roger Read: But let me ask a U.S. question. BPX, just kind of update on performance and how you’re thinking about any particular increase in activity in any of the gas areas?

Murray Auchincloss: Great. Roger, Nice to hear your voice. We continue to admire what BPX is doing. They continue to do — perform very well. We’ve got our third central gathering facility up online and full now in the Permian, and we’re looking forward to getting the last one up around middle of this year. I think the most interesting that we’re seeing right now are these refracs inside the Eagle Ford, where the refracs and downspacing are actually creating more flow than the original motherbores. So there’s something about a recharging reservoir going on there that we didn’t really predict in shale. And that’s a very interesting opportunity as the returns are triple digit plus on that space. On the gas side, we’re contemplating increasing rigs right now.

Gas pricing is very, very solid as we look at the second half of ’25 and into early ’26. And so Gordon and Kate and I are debating, should we be doing that, what head strategy would we have around it and how many rigs should we grow. But with the prices that we’re seeing now on the forward markets, the returns inside the gas now beat the returns inside the oil basins. So that will be something that we’re thinking about, and we’ll look forward to more questions in that space in a couple of weeks’ time, where you can ask Gordon about that stuff as well. Thanks, Roger.

Craig Marshall: Thank you, Roger. We’ll turn to Alejandro Vigil at Santander next, please. Alejandro?

Alejandro Vigil: Yes. My question is basically about the Slide #16 of the presentation where you are talking about building momentum into ’25. And you saw this chart with a significant increase in year-on-year in EBITDA, which are the moving parts of this increase? I remind there are some consolidation portfolio, et cetera? And I’m making this question also in the context of looking at consensus number of $37 billion for this year looks like there is a big gap between consensus and this Slide #16. You can elaborate on this, please.

Katherine Thomson: Yes. Thank you, Alejandro. Yes, so if you think about 2024 EBITDA, so we printed 38 billion for 2024. If you were to adjust that for ’23 prices. If you think back, I think it was 2Q earlier this — earlier last year when we talked about the impact of price on our $46 billion to $49 billion EBITDA target. If you adjust our 2024 EBITDA back for 2023 prices, and if you think about ’23, although the commodities move around, taken as a basket, it’s broadly comparable to our planning assumptions. And then if you use rules. Rules of thumb and you adjust for the fact that Whiting will be back up and operating well this year. You adjust for portfolio and you adjust for typical underlying growth that we expect to deliver year-on-year, you get to a number that’s just under our target of $46 billion to $49 billion, which is what we’ve said today.

And to be clear, we’ve said for a while now that our focus is very much shifting to cash. In 2 weeks’ time, we’ll update you fully in terms of targets, metrics and financial frame, and that will help put the retiring of this target into context for you.

Murray Auchincloss: And I think on ’24 versus ’25, obviously, we’ve got the absence of the Whiting outage, depending on the margin, that’s worth quite a bit of money. And then we have the 3% to 4% underlying growth that I’ve been talking about quarter in and quarter out that we see year-on-year across the business for ’24 versus ’25 that comes broadly across cost. So continued cost improvement based on a great start we’ve done this year, along with improvements in things like Castrol, TA doing better, European convenience doing better, Australian convenience doing better and continue to improve performance inside the Upstream, along with, as I said, in the refining coverage, less complicated TARs. So it’s a lot of small things that add up to that 3% to 4% improvement in underlying plus the recovery from the Whiting outage in 2024.

Craig Marshall: Thanks, Alejandro. We will turn to Michele Della Vigna, at Goldman Sachs. Michele?

Michele Della Vigna: And very much looking forward to the CMD. Just one modeling question from my side. We’ve seen two items before below EBIT, which were larger than expected, the net interest cost and the minorities. I was just wondering if you could perhaps guide us on whether we should assume this is a new ongoing run rate or if there was any one-off impact in the quarter?

Katherine Thomson: Yes. Thanks, Michele. In terms of net interest, that was up quarter-on-quarter really just because our gross debt had grown. We took advantage this year in terms of markets and issued a fair amount of debt without actually buying back any more of our maturities. That’s something that we’ll continue to address as we have done previously, based on value and in terms of the cash. It’s a very minimal cost of carry right now given the forward curves as well. So that’s all that’s going on in net interest.

Michele Della Vigna: And for the minorities?

Katherine Thomson: So there’s a movement and that really just related to the change in hybrids in the fourth quarter.

Murray Auchincloss: You would probably expect those to reverse over time — you probably expect both to reverse over time as you decrease your hybrids, again, unless you pay off your debt.

Craig Marshall: Thanks, Kate. Thank you, Michele. We’ll turn to Paul Cheng in the U.S. at Scotia. Paul?

Paul Cheng: Kate, can I go back into the 2025 EBITDA? You’re saying that adjust for the pricing, it will be slightly below the low end of the range? So comparing to the midpoint, that’s probably, say, call it $2 billion less. Can you tell us that comparing to the initial expectation, which area that are seeing the miss and what’s causing those?

Katherine Thomson: Yes. Thank you. So I think the two areas I would highlight, we’ve talked before about bio margins in Europe being suppressed due to two reasons. One, the Nordic countries rolling back to — rolling back their voluntary mandates to the EU mandated levels and also a level of oversupply from Asia. The other area I would call out is TravelCenters of America where it’s been slightly slower than we expected in terms of recovery from the trucking recession. We see green shoots. It’s starting to improve. I think we’re probably a year further out in terms of seeing full recovery. That’s more likely to come through in 2026 now.

Craig Marshall: Thank you, Paul. And it looks like just now the last question is from Giacomo Romeo at Jefferies. Giacomo?

Giacomo Romeo: Just a quick one more on the modeling side. Your leases obviously gone up as you’ve guided. I’m just trying to get a better sense of where we should expect lease payments to move to in going forward, in Q4 that we’re still relatively in line with previous quarters, just trying to understand whether that should go up and by — to what extent into next year?

Katherine Thomson: Yes, I’ll take that. There’s the leases were pretty flat quarter-on-quarter, but we did add to our lease liabilities in the fourth quarter with the completion of Bunge. They’ve got about 300,000 hectares of land leased. So you will expect a small increase with regard to that. And then there was an extension of a lease for trading use in the U.S., but for commercial reasons, I wouldn’t go into that. So 4Q versus 3Q, pretty flat, but you’ll see a little bit of tick up with regard to the Bunge leases.

Craig Marshall: Super. Thanks, Kate. We’re going to let Biraj sneak in with the last question. Over to you, please.

Biraj Borkhataria: Sorry, I assume someone going to ask this, but as a last one, I might as well. Given the news yesterday around your new shareholders, any comments you can make about any engagement you’ve had with Elliott?

Murray Auchincloss: Look, Biraj, it’s market speculation right now, and we don’t comment on market speculation. Thanks for the question.

Craig Marshall: Thanks for the question, Biraj. Okay. I am going to — there’s no more questions online. So we are going to close the call on that note. So that’s the last question. We’ll close the call on behalf of Murray, Kate, myself and also members of the leadership team who will join us on February 26. We look forward to seeing many of you in London, and of course, those of you who will be joining the event by webcast. So we look forward to seeing you in a couple of weeks. And thank you for listening into today’s call.