BP p.l.c. (NYSE:BP) Q1 2024 Earnings Call Transcript

BP p.l.c. (NYSE:BP) Q1 2024 Earnings Call Transcript May 7, 2024

BP p.l.c. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Craig Marshall: Well, thanks, everyone for joining BP’s First Quarter 2024 Results Call today. As you’ll be aware, we introduced our quarterly trading statement this quarter and this morning also published the slides and script along with a video presentation in conjunction with our stock exchange announcement. Alongside this, the results call has moved to early afternoon UK time and we hope together these updates around our process and disclosures has been helpful to everyone and you’ve had a chance to review everything this morning and this afternoon. So we’re going to aim to finish the call at 2:00 P.M. UK time. As some of you will be aware, we understand our counterparts at Saudi Aramco start their call around that time, and we want to give you a chance to join that as required. So maybe let me start there. And on that note, hand over to Murray for a few brief opening remarks.

Murray Auchincloss: Good. Thanks, Craig, and thanks, everyone for joining Kate and I on the call today. To recap today’s results, we delivered resilient financial performance despite the unplanned outage at our Whiting refinery. First quarter adjusted EBITDA was $10.3 billion and underlying earnings were $2.7 billion. Adjusting for the expected seasonal working capital build, operating cash flow was $7.4 billion in the quarter. We continue to make good strategic progress and this quarter saw the safe start-up of the Azeri Central lease project in the Caspian Sea. BPX also brought online Checkmate, our third central processing facility and in biogas, Archaea brought online its largest modular RNG plant to date and has five in commissioning.

Last week, our JV Azule announced a 42.5% firm-in into an exploration block in the Orange basin offshore Namibia. You’ve also heard about how we are simplifying, removing complexity across the company and today, we have announced a target to deliver at least $2 billion of cash cost savings by the end of 2026. Craig, back to you.

A – Craig Marshall: Super. Thanks, Murray. So we’ll go straight to questions now and we’ll take the first question from Josh Stone at UBS. Josh?

Josh Stone: Yeah. Thanks, Craig, and good afternoon, Murray, and Kate, and appreciate the slightly longer time to study the results. I have two questions, please. First, I want to pick up on your 2025 EBITDA targets, which you reiterated specifically in the TGEs of $3 billion to $4 billion. And if I look at consensus, it feels like few people believe in these numbers and it’s only now almost 18 months away. So if I look at how the business has started, the buyer business looks like it started a bit lower than you might have expected. You talked about TA was impacted by an ongoing recession of freight in the U.S. So maybe my question is, where do you see the biggest risk in these 2025 targets and what do you think the market is missing on that side?

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Q&A Session

And then second question on the Whiting refinery, good to see back online. Maybe now the dust has settled. Can you just talk about what lessons you’ve learned from the outage and maybe some initiatives you’ve put in place to prevent further issues going forward? Thank you.

Murray Auchincloss: Yeah. Sure, Josh. I’ll — thanks for the questions. I’ll take both of these actually. I think on Whiting, it’s a bit too early for lessons learned. The teams had a full electrical outage at Whiting. It took us about six weeks to get it back operating safely. The teams have now done that, well done to the teams for achieving that and they’re now going through the process of lessons learned probably in the design space. So that is still work to do. As far as EBITDA from the transition growth engines, as we reported last year, we made about $1 billion of EBITDA. We’re aiming for $3 billion to $4 billion of EBITDA by 2025. Where does that come from? A full year of TA, continued growth out of Archaea. It comes from EV moving to breakeven.

It comes from real focus inside hydrogen as we focus the portfolio and move to the most likely things to move forward and it comes from growing bio and growing convenience as well. I think on the confidence side, C&M continues to grow very strongly. We continue to see 9% year-on-year growth. And with the expansion in TA, that should be very, very good for convenience. EV remains on track. I think the number is 93% of — 83% of all the fast chargers are EBITDA-positive now. So Richard and the team are doing a good job driving that engine to breakeven. Archaea continues to get plants online. As I said, we got a big one online in 1Q and we’re commissioning five as we speak. So we should be in good shape for the 15 to 20 and RIN prices are holding very high for the D3 RINs in the United States as well.

On the challenging side, bio as everybody knows, the bio margins in Europe were tricky through 4Q and 1Q as mandates were rolled back across some of the Scandinavian countries. We do expect change on that in the future, but it’s hard to predict. It’s kind of like a macro assumption that’s hard to predict. And diesel, as you say, is challenging in the United States. There’s a diesel recession. We feel that will unwind as well as we move towards the back end of the year and into 2025 as well, but we feel confident on the 3% to 4% and we’ll just have to have to see how that goes, but good momentum operationally, good momentum on synergies, and the macro is what we’re fighting against a little bit right now, but let’s see how that macro turns out.

Thanks for your question, Josh.

Craig Marshall: Thanks, Josh. We’ll turn to Biraj Borkhataria, RBC. Biraj?

Biraj Borkhataria: Hi. Thanks for taking my questions, and appreciate the more condensed format. The first one is just on the cost-cutting. When I look at the public disclosures across you and your peers, if I take SG&A, for example, it does look like your figures are quite out of sync. It seems like they’re growing faster than the peer group and I can’t really tell if it’s all accounted for the same or not. I guess in your slides, you do some adjustments here. So maybe the question is, when you benchmark your costs and your performance, what is the starting position for BP? Is it that today you’re better than average or you’re slightly worse? And particularly, where do you see the opportunity there? And then the second question is on another hot topic, which is a relisting is brought up by one of your counterparts.

Where does BP sit on this? Is it a live debate? Do you see as a structural disadvantage? Unlike your counterparts, you do have a big domestic U.S. business upstream and downstream there. So I just wanted to get your thoughts on that. Thank you.

Craig Marshall: Great. Biraj, I’ll ask Kate to tackle the cost question and how different we all account for these things. On relisting, I’ll be consistent with what I’ve said in the past, Biraj. This is not on our agenda. What’s on our agenda is safely performing quarter-in and quarter-out. We’re in a great position with the business. We’ve got strong growth coming through. We’ve got solid targets out to 2025 that we can believe we can deliver. It will deliver 3% to 4% underlying cash flow growth, if we hit our plans through the rest of the decade and certainly through ’25 as well. And as we continue buybacks, that gives us then the chance to increase the dividend over time. We have confidence from it because it’s worked before.

In 2022, in the first half of 2023, we compressed the share price with some of the Americans by a third simply by doing that performance. So that’s what’s on our agenda, not a — not relisting and so we’re just focused tightly, tightly on performance, Biraj. Kate, over to you on the first question, please.

Kate Thomson: Thanks, Murray, and hi, Biraj. Yes, so I’ve seen some of the narrative. Look, it’s incredibly hard under the current accounting standards to really try and compare that like-for-like, line-by-line through the P&L account. There’s a level of interpretation, let’s say, on how companies can actually account for their costs through the — through the income statements, that makes line-by-line comparison quite tricky. What I would say is that, if you step back to February and we talked about the fact that we were going to drive focus through the business and we were going to deliver the next wave of efficiency, what we’re really focused on is how we create our own greater efficiency and our own reduction in our cash costs.

And what I would say is on a unit production cost, our lifting costs, we think we’re very competitive at $6 a barrel. So I guess my guidance to you going forward, Biraj, is to anchor yourself on cash costs, which as you can see from the slide, we’ve tried to point you towards if you toggle from where our total reported costs are down to our cash costs. That’s how we’ve disclosed against in the past. That’s how we’ll continue to disclose against as we deliver this $2 billion of cost reductions through the end of 2026. And then finally, what I would say is, I think IFRS 18, which comes in at the beginning of ’27 will probably make your lives a bit easier. It will force more transparency and probably greater comparability across the sector. So hope that’s helpful.

Craig Marshall: Thank you, Biraj.

Biraj Borkhataria: Thank you.

Craig Marshall: We’re going to move stateside now, given we’re at a slightly more hospitable time, and take the first question from Paul Cheng at Scotia. Paul.

Paul Cheng: Thank you. Good morning, guys, or good afternoon. In K, in the press release, you guys talking about the EJ devaluation, balance impact or foreign currency impact. What’s the — is there a number that you can share that — how big is that number? And also that from the fourth quarter to the first quarter, the gas and LCE is down roughly about $100 million in the adjusted earnings. How is that contribution is coming from the low carbon side? In other words, there is low-carbon getting better or getting worse that we are seeing there? So that’s the first question.

Murray Auchincloss: Great. Kate, over to you on Egypt. I think it answers the second question as well, doesn’t it?

Kate Thomson: Yeah. It pretty much does. Hi, Paul. Yes. So on Egypt, we saw a significant devaluation in the currency. It went from 30 million to 48 million when Egypt 3 fluted ahead of the injection of funds from the IMF and others as you’ll have seen. So that foreign exchange impact has flowed through the first quarter. It’s around about 0.2 and you can also see it driving our tax rate up in the quarter as well. So that’s what’s going on with regard to Egypt and devaluation. With regard to the gas and low-carbon performance, so we were up on production and our comp down — really down just quarter-on-quarter based on lower realizations and FX. So that’s the story with regard to GNLC for the quarter.

Paul Cheng: Okay. Kate, on the cost reduction, the EUR2 billion, how much of them is related to any divestment, or that’s purely on their actual underlying course are performing better?

Kate Thomson: Yeah. So we’ll step through the interventions. There are four areas we’re focusing on. And one of it is focusing our portfolio as you’ve heard us talk about for a little while now since we set out our six priorities in February. So there will be some of that, which is delivered through portfolio change. As we get clearer on the component parts and how they contribute and when they get delivered, we’ll update you in due course.

Murray Auchincloss: Yeah. Paul, it’s more about focusing our engineering efforts. If you think about 2020 to 2023, it was about creating an awful lot of options in the upstream and refining in all of the transition growth engines as well. And we now have 32 final investment decisions to make across ’24 and ’25. So a large part of this focus is getting really clear which ones of these we’re going to take forward. And as we do that, redeploying engineers to the highest-quality ones, redeploying third-party resources, etc. That will create a lot of cost-savings as we really, really focus on these things moving forward. Yeah. A small — a small example of that to think about during the past 90 days is we decided to sanction Atlantis tieback in the Gulf of Mexico.

So you sanctioned that. At the same time, we decided to release Birallah in Yakaar-Teranga in Mauritania and Senegal. So that’s about being really, really driven by returns and deciding the best value and then we can reallocate engineers and yes, and use less third-party services, which creates cost savings.

Craig Marshall: Thank you, Paul.

Paul Cheng: Thank you.

Craig Marshall: We’ll stay in the U.S. and take the next question from Ryan Todd at Piper Sandler. Ryan?

Ryan Todd: Great. Thanks. Maybe a first one on refining. You referenced the impact of narrowing crude differentials in North America. Can you talk about the impact that you expect in the U.S. from the startup of TMX? Any flexibility that you might have to mitigate the impact, whether in the Mid-Con or on the West Coast at Cherry Point? And then maybe a follow-up on the cost that you were talking about there. There is increasing — I mean, increasing focus on cost inflation on the project side that we’ve seen in areas like Deepwater and LNG and the impact that it’s having on some project returns. So can you maybe talk about what you’re seeing across the portfolio, impact on potential future FIDs like, the Paleogene or future LNG expansion phases, and your ability to mitigate those?

Murray Auchincloss: Yeah. Sure. I’ll take the first one, Kate, you want to take the second one? On the first one on TMX and what we’re seeing, obviously, differentials have started collapse on WTI, WCS. I think they’re probably sitting last time I looked somewhere around 14. It’s probably not a bad range, plus or minus a couple of bucks as far as what the range is on WTI, WCS is moving forward. Hard to predict, of course, but that’s our sense of what will occur. We’ve done two things to mitigate against this. First of all, as TMX comes online, it gives a direct route for that oil in the Cherry Point, so that will mitigate. Cherry Point will be able to access some more affordable product moving forward. So that should be a benefit to us that helps mitigate some of that effect.

Plus we have some pipeline re-wheeling that we’ve done over the past few years to be ready to flow product up-and-down across North America to manage risk associated with Whiting as well. So net-net, we think we’re probably still in the same shape we were pre-TMX coming online between Cherry Point and between our flexibility with Whitening and Cushing. Kate, over to you on the capital question.

Kate Thomson: Yeah. Sure. Yeah. Thanks, Ryan. So in terms of inflation, I think the area where we’re still seeing inflation persist is in wage growth. So that’s an area that we continue to battle against and the procurement team that we have inside the organization are working and have worked over the last few years incredibly hard to mitigate all the effects of inflation that we can through things like competitive bidding and moving into much more performance-based models. Alliancing and partnerships have been effective in terms of helping us drive our costs down. What I would say is, yard capacity is tight, utilizations are high, probably the highest they’ve been for about a decade, and we think they may well remain like that for another three to five years perhaps.

So that’s something we will pay attention to. At the end of the day, when we think about the investment decisions, we will be, as you’d expect us to be returns and value-driven. So we will be making sure that all our projects that we sanction are meeting hurdles but we feel pretty good about Cascadia right now. We hope to be able to move to sanction at some point during the remainder of this year.

Murray Auchincloss: And I think on the LNG side from recent bids we’re seeing, we’re okay to continue moving those forward, whether it’s in Asia or the Middle East as well. I think enough companies are now recycling things that we’re seeing some looseness inside the supply chain. But it’s a good question to ask us each quarter to observe as we see the bids come in with the potential sanctions upcoming.

Ryan Todd: Thank you.

Craig Marshall: Thanks very much. We’ll take the next question from Chris Kuplent at Bank of America. Chris?

Christopher Kuplent: Thank you, Craig. Hello. Just two quick questions from me. I was wondering whether there is a specific reason you no longer publish your surplus cash flow metric as that seems to have dropped off the page and just checking whether my back-of-the-envelope minus 1.5 billion in the quarter is anywhere close to where you would get to with your definition. That’s question number one. And question number two is on the ADNOC JV in Egypt. I’m assuming that is yet to close and it’s appearing in your assets for sale. So I wonder whether that will translate into disposal proceeds and obviously, you’re guiding still to $2 billion (ph) to $3 billion for the full year. And if you could give us any more clarity on how you’re going to account for that JV? Thank you.

Murray Auchincloss: Yeah. Sure. I’ll let Kate answer the surplus one and then I’ll tackle Egypt. Okay.

Kate Thomson: Yeah. Thanks, Chris. So when we updated the financial frame in February and set out a two-year frame to the end of 2025, what we were after was creating greater clarity and predictability on distributions. As a consequence of that, we’ve delinked our quarterly share buyback from a surplus cash calculation. It was creating an awful lot of volatility. It remains something when you look at over time. As you can see from the Finn Frame (ph), we’ve said that over time, we expect to distribute 80% of surplus cash to shareholders. And so we’ll think about the rate at which we may or may not want to include further disclosures. It’s not something we intend to disclose on quarter-on-quarter now no longer as it’s not a direct input to the share buyback.

So we don’t feel the need to make any quarterly disclosure on that. At the end of the day, cash flow is going to — go up and down over the quarters with things like working capital movements. So we expected the balance sheet to tolerate some fluctuations in the first half. We saw that come through. We have the typical working capital build and we’ve got heavy CapEx in the first quarter and our divestment proceeds are back-ended, but our balance sheet is strong enough to tolerate that. We can look through that over time. And that’s why we have moved to a frame that stops that quarter-on-quarter linked to a surplus cash calculation.

Murray Auchincloss: Great. Thanks, Kate. And Chris, on ADNOC, yes, we’ve moved forward with the transaction. It’s an asset held for sale. As you say, we’re waiting for completion second half of the year, probably 3Q, 4Q. It depends on — it depends really on how we move our way through the — with the Egyptian authorities. The accounting for that it will show up as proceeds as discussed, I can’t disclose those proceeds now. We’re under a confidentiality agreement, but by the time it closes, you’ll see that inside the accounts, but it will take up a good chunk of the $2 billion to $3 billion target that we talked about. I hope that’s clear, Chris.

Craig Marshall: Thank you, Chris.

Christopher Kuplent: Thank you.

Craig Marshall: Thanks. We’ll take the next question from Lydia Rainforth at Barclays. Lydia?

Lydia Rainforth: Thanks, Craig, and good afternoon, everyone. Two, if I could. Just if we could go back to the cost base and the targets that you’ve got at least $2 billion. Can you just walk us through in more detail some of the examples of what that involves and because actually, it’s sometimes quite hard to go what are good costs and that help growth and what are bad costs reflecting inefficiencies. And I am a little bit surprised that you’re talking about $20 billion of costs that in that transportation and shipping costs that there’s absolutely nothing you can do about and that does surprise me a little bit. So any thoughts you have on that? And then I’m going to come back a little bit to the EBITDA guidance, given the cost savings number, is there a reasonable argument that actually the EBITDA numbers and targets should be moved a little bit higher?

And effectively, I guess what I’m asking for slightly separately is that analysis that you’re not going to give me this, but an exit rate on EBITDA for 2024 as to just — we should be seeing momentum at this stage in that EBITDA number during this year, right?

Murray Auchincloss: Yeah. Great, Lydia. Thank you. Thank you for your questions. Let’s see, cost examples, I’ll tackle. I think the second question, I’ll let Kate deal with. On cash examples, so there are four areas that we’re really focused on Lydia to deliver at least $2 billion by the end of 2026. The first one was focusing on the portfolio. You heard about me talk about that already, so I won’t repeat myself. The second one is your favorite, which is digital transformation. We’ve done an awful lot to digitize many parts of our business and we’re now applying Gen AI to it. The places that we’re seeing tremendous results on are coding. We need 70% less coders from third parties to code as the AI handles most of the coding, the human only needs to look at the final 30% to validate it, that’s a big savings for the company moving forward.

Second things like call centers, the language models have become so sophisticated now. They can operate in multiple languages, 14, 15 languages easily. In the past, that hasn’t been something we can do. So we can redeploy people off that given that the AI can do it. You heard my advertising example last quarter where advertising cycle times moved from four to five months down to a couple of weeks. So that’s obviously reducing spend with third parties. We’ve now got Gen AI in the hands through Microsoft Copilot across many, many parts of the business and we’ll continue to update you with anecdotes as we go through. But I think this is just a tremendous step change in digital for our company and I continue to look for ways to drive higher margin and reduce cost both on capital and cost.

The suppliers is probably a nice little example to think about eliminating waste. Our good partners at Subsea 7 have formed an alliance with us. In the past, we would have overseen what sub — what they were doing. Instead, now we form joint teams. They work together on a job, they try to figure out how to optimize it. We incentivize them for time and efficiency and we have co-located teams that work together on these things. So what it does is it eliminates bid cycles, it reduces the number of engineers involved from both sides in getting everything done, it reduces vessel time, etc. So that’s just one concept of alliances that we’ve been doing in the capital side with projects and drilling for a while and we’re now pushing that into the operation space both in the upstream and the refineries.

So that will take out a lot of waste as we move these alliance as forward as well. And then last, global capability hubs. We have a continuing need for engineering. It’s scarce in the west. So we’re looking east for that engineering capability. It’s a different cost profile sometimes, but fabulous efficiency. We see that both in contractors. So contractors we work with are shifting that way and then ourselves as well across engineering, IT, etc. So those are the four examples of how we think we’ll get to the at least the $2 billion. No, Lydia, I’m not going to give you an update on the ’24 and run-rate to EBITDA. All I’ll say is I’m confident in the growth on an underlying cash flow basis of 3% to 4% through the decade, including in ’24 and ’25.

We see strong growth out-of-the upstream with new projects coming online with BPX growing, with new LNG coming online from ’23 to 25 MTPA, a return to normal tar seasons in our refineries along with all the growth that we see from the TGEs, and business-like Castrol. So we feel comfortable with that 3% to 4% growth per annum underlying on a free-cash flow basis through ’24 and ’25. Will the cost savings add to that? Let’s see. I think it will take time to do some of these things. Some things will come through faster than others. But for now, we’re saying that an end ’26 basis and let’s see how we get on. Kate?

Kate Thomson: I think you kind of did my job for me.

Murray Auchincloss: Did I roll into your question? Sorry about that.

Kate Thomson: The only thing I was going to add is that some of the changes that we’re contemplating take time to affect and execute and we do it in a way that we are confident we’re managing risks. So there may be some parallel running costs at some point and we’ll update you as we get clearer on that path and on any associated.

Murray Auchincloss: Hope that helps, Lydia.

Lydia Rainforth: Great. Thank you, both.

Craig Marshall: Thanks, Lydia. We’ll take the next question from Michele Della Vigna at Goldman Sachs. Michele?

Michele Della Vigna: Thank you very much and congratulations on the focus on cost efficiency despite the relatively positive macroenvironment. Two questions, if I may. On the dividend per share, it looks like we are up for an announcement next quarter. And I was wondering, how should we think about the underlying growth. We’ve got 3% to 4% absolute growth of the business and we’ve got a share retirement that is running at between 6% and 7%. Is it too simplistic to think about growth of the business plus share retirement equal what can be achieved in terms of sustainable DPS growth? And then secondly, on the net interest expense, it’s quite a difficult line to forecast. It’s been around $900 million for the last three quarters. Is it fair to assume we remain at about that run rate in the coming quarters or is there anything else we need to take into consideration? Thank you.

Murray Auchincloss: Kate, you want to handle the dividend?

Kate Thomson: Sure. So, Michele, I think you may have done my arithmetic for me. I guess a couple of points to just to add to that. So if you think about the financial frame, remember to anchor on our balance points and also the fact that we are — our first priority is that resilient dividend and at $60, the capacity to increase by 4% per annum. But as you rightly point out, we’ve had previous increases in 2Q ’22, 4Q ’22, 2Q ’23, each around 10%, underpinned by strong performance and by reduced share count. So as you’d imagine, the Board will look into many factors when we come to that conversation in 2Q, but as you consider what we’ve done with our share count, I think we’re 17% reduced by the end of ’23 and since 2Q ’23 at the moment, we are about 5.5% reduced share count. So I’ll let you add that to your current arithmetic.

Murray Auchincloss: But the Board makes that decision each and every quarter and of course, you can look backwards to think about what we do looking forward. I think, Michele, on your net interest income expense, presuming flat is a sensible thing to do moving forward. I think that’s just the easiest thing to do rather than give guidance. Thank you.

Michele Della Vigna: Thank you.

Craig Marshall: Thanks, Michele. We’ll take the next question from Martijn Rats at Morgan Stanley. Martin?

Martijn Rats: So last quarter, you were helpful in providing a sort of a comment on the EBITDA that was delivered if it was restated under 2025 reference conditions, which, of course, given that we’re sort of tracking towards that 2025 guidance over the next couple of quarters is actually quite helpful. So this quarter EBITDA was $10.3 billion. What can you once again provide some color on what that would have been under 2025 reference conditions? And secondly, I wanted to ask you about yesterday’s FT article. I’m sure you’ve read it, but there was an FT article that said that BP could make some additional changes on it as a longer term sort of. So targets, including the guidance for a decline in production by the end of the decade, the well-known 25% reduction target. I was wondering, if you had any comments on that article.

Murray Auchincloss: Sure. I’ll tackle both of these, Martin. Thanks for the questions. So what we said is that the conditions that prevailed in 2023, which ironically are very close to the conditions that prevailed in 1Q 2024, that was a good starting point for how you should think about 2025 and then, you should just apply underlying growth rate to get to what you think the EBITDA would be across the two years. And we’ve talked about 3% to 4% underlying cash flow growth since CapEx is flat and since proceeds are relatively flat, that implies 3% to 4% EBITDA growth across ’24 and ’25 as well. And you can — you have said the sources of those value numerous times to help you think about how you can quantify that. I think the only thing I’d say is the 10.3 that we had in 1Q ’24, obviously had the unusual incident with Whiting.

We wouldn’t obviously plan for something like that moving forward. It had an impact of around $0.5 billion in the quarter. So you should probably add that back and you’re getting close to $11 billion EBITDA out of both the right conditions for ’25, I think 11 times for, I’ll let you do that math, but you can get a sense of where we are performing and then the 3% to 4% gives you a sense of where we think we’ll be in 2025 and all of you will adjust that based on what you believe will happen with performance and what will happen with the environment. So I think that’s probably about as good as I can do in that space. As far as the FT article about 2 million a day, I’m just going to again be consistent with what I talked about last quarter. We continue to — with the strategy of transitioning from an IOC to an IEC, we will diversify the business over time.

We will focus on bio, EV convenience, hydrogen, and renewables. We will continue investing into this space. We will be pragmatic and we will make sure the investments we make hit our returns hurdles. And of course, at the same time, we’ll be investing into hydrocarbons. On the hydrocarbons 2030 is an aim, it’s not a target. We estimate it at around $2 million a day right now and it will largely be determined by the long list of potential final investment decisions we have to make across ’24 and ’25. There are around 30 of them, some in the upstream, some in refining, some in the transition growth engines. And based on what decisions we make, that will determine the volume outcome, but what I’m really, really focused on with the organization is returns and cash flow, not volume.

So during the quarter, back to that story again, we sanctioned one oil project in the Gulf of Mexico and we let go of two gas resources in the West Coast of Africa. So that tells you we’re return driven, not volume driven and once we’re through deciding the final investment decisions over the next couple of years, we’ll update you with a target for 2030 production. Could it be higher than $2 million a day? Yes, could it be lower than $2 million a day? Yes. It’s all going to be a return on cash flow focused, Martin, as I think you would hope we would be. I hope that provides enough clarity.

Craig Marshall: Thanks, Martin. We’ll take the next question. Actually, we’ll go back stateside from Roger Read at Wells Fargo. Roger?

Roger Read: Yeah. Thanks. And I do appreciate more reasonable time for those of us on this side of the pond. I just wanted to dive back in. Murray, earlier you mentioned a diesel recession going on since you have a pretty impressive global footprint. Just wondering, if you could expand on that a little bit. And then the other question would just be, can we get a little more of an update on how things are going in the Permian with BPX? Just a little more depth into the operations, what you’re seeing in the way of product — productivity and efficiency, things like that.

Murray Auchincloss: Sure. Kate, you want to take diesel recession?

Kate Thomson: Yeah. Sure. Yeah. Thanks, Roger. I was out with TA actually about a month ago. We talked a lot about this. So the sector that TA has historically focused on is a sector where there are probably smaller sized truckers capturing a higher margin. As a consequence, they’re probably far more sensitive to spot price. And actually, what’s happened in the spot freight rate over the last couple of years is it has declined. If these truckers are being sensible, they don’t drive when the economics don’t make sense. So as a consequence, we’ve seen volumes down. What I would say to you is, is having spoken with Debbie and her LT out there and they are all over how they offset that until such point as the recovery starts to kick in and we expect currently that trucking recession will probably start to mitigate towards the end of this year with a full recovery next year.

So as you would expect, thereafter streamline, streamlining their costs, they’re contemplating how to high grade their site portfolio and they’re focused on securing some customers which diversify their customer base into the larger fleets where you may get slightly slimmer margins, but you’re going to capture upside from the non-fuel income.

Murray Auchincloss: Great. Thanks. Thanks, Kate. I think on the Permian, Roger, obviously, we got our third, we got our third central gathering process up online now. I think that takes our capacity for black oil up to around 100 KBD. So I think a lot of the wells are drilled and we should be popping them and filling that up as we move through the second quarter. Conditions inside the Permian, it’s a bit looser there’s, there are more rigs available, obviously from low natural gas prices that’s making the supply side of it a little bit better, and no real change from October on the productivity. All the recent benchmarking we’re doing is showing us at the top of the pack on the productivity on NPV for drilling spent. So we’re proud of the team for driving that as well.

We’re not feeling any constraints. We’re not feeling any constraints on export at this stage and we’re looking forward to getting the fourth and last central facility online mid-next year. So hope that helps. I’ll be out there next week to see the guys and next quarter, I can give you a more detailed report.

Roger Read: Thank you.

Craig Marshall: Thanks very much. We’re actually going to jump to an online question that we’ve received from Alejandro at Santander, he’s struggling with the phone lines. Sorry about that, Alejandro. He’s asking Murray and Kate about Namibia and the investment plans there after the Azule Energy announcement?

Murray Auchincloss: Yeah. Sure. I can take that one. So we’ve been in Namibia as BP for about a decade. We entered back in 2010 or 2011, drilled a couple of dry holes, unfortunately last decade, but we’ve been monitoring it ever since. Given the recent success that’s happened, we started to look at some farm-ins and obviously, we were able to farm into the blocks south of Galp’s big discoveries with Rhino. We farmed in for 42%, and we chose to do it through E&I ourselves, chose to do that through Azule, which is our West African, our West African energy company. So we’re looking forward to completing that farm-in. We then move towards drilling wells later in the year. There are two wells to drill under our agreement and we’ll see how it goes, but it’s a nice little addition to Azule.

It’s got a great growth profile inside Angola to the end of the decade and cross fingers if we get some discoveries, it gives it legs for another 10 or 20 years. So we’ll see how the drilling goes. You can never count on these things, but it looks like it’s at a nice postcode. Craig, back to you.

Craig Marshall: Thanks, Murray. We’ll take the next question from Christyan Malek at JPMorgan. Christyan?

Christyan Malek: Hi. Thanks for taking my questions, and sorry for the background noise, in the airport. And two questions, please. First, just on the cost savings. I have to congratulate you, for continuing to drive efficiencies. My only sort of kind of just sort of question around growth is your liquids growth in ’26 back to that sort of theme. Why aren’t you thinking or framing in the same way you’re doing costs, but more in an upcycle view of you to consolidate or scale up your liquids given your constructive outlook? It strikes me as sort of very bare market to continue to focus on cost, albeit that’s absolute necessary. So just wanted to hear more about your liquids plan, particularly given the U.S. consolidation that we’re seeing and how do you frame that on a medium-term basis given we are after all talking about 2026?

And the second question is around low carbon and trading. Is there a plan or thinking about being more explicit around those businesses in terms of breaking them up to show your cash flow pathway? Clearly, trading is more challenging given it’s more discrete, but on the low-carbon side, just to understand better what the free cash flow trajectory will be on a medium-term basis as we start to think about drawing a path to EBITDA targets? Thank you.

Murray Auchincloss: Great. Kate, do you want to lean off with disclosures on low carbon trading?

Kate Thomson: Yeah. So thanks, Christyan. So the low carbon trading is obviously included in our trading numbers. It’s also included in our transition growth engine disclosures when we make those at the half year and the full year, but we don’t, we won’t be breaking those out beyond the five transition growth engines. I think there’s enough complexity in that disclosure as it is already.

Murray Auchincloss: And on liquid side, Christyan, I guess in our Denver presentation to you, back in October, we talked about a pretty resilient oil portfolio with the capacity to grow production through 2027 by 2% to 3%. As we look at our sanctions moving forward from sanctions in the Middle East to sanctions in the East Coast of Canada to Brazil to the Gulf of Mexico to the North Sea, potentially to Azule and Aker BP. We have an awful lot of oil in the portfolio. And as we make those sanctions, that would give us more duration to grow the oil business as well beyond 2027, but I can’t really, I can’t really commit to that until I’m clear, until I’m clear about which sanctions we move forward. I think on the question of do you want to go buy?

I’m a countercyclical human being with low carbon energy in the doldrums right now, now is the time to go countercyclical. That’s why we’re doing light source BP at a countercyclical moment in time and watch the space, we more do, we may do some more things over the coming years in a countercyclical environment. On the oil side, with oil at $85 or $90, I’m not sure it’s the right time to be buying oil. We might consider some bolt-ons, but we just would prefer to be countercyclical rather than pro-cyclical and we do, we do have some pretty strong growth as we look forward, especially relative to the competition, especially in the high margin basins of the OECD. So I feel okay where we are right now. I don’t want to do high priced acquisitions and instead I’ll go countercyclical with scarce cash where countercyclicality exists.

Hope that helps, Christyan.

Christyan Malek: Thank you.

Craig Marshall: Thanks, Christyan. We’ll go to Irene Himona at Bernstein, next. Irene?

Irene Himona: Thank you. Good afternoon. My first question, Murray, going back to the $2 billion cost saving. You did mention, I believe, 8% cash cost inflation on that $22 billion cost base. So I wonder, should we think of the $2 billion reduction target as partly or wholly removing that inflationary impact and leaving the sort of underlying cost base flat, would you say? And then secondly, on convenience, I mean, your convenience gross margin grew 62% in ’23, and for an increase in site numbers of about 19%. So I wanted to ask so far in ’24, are you seeing similarly fast improvements in that convenience margin or faster, slower? Where do we stand? Thank you.

Murray Auchincloss: Yeah. I think on the $2 billion cost savings, Irene, our intent is to drive that through the business and drive that down to free cash flow delivery. So eating inflation is how I think about these things. And it’s why we say at least two, maybe something above that takes us to beat inflation, but I’d like to try to beat inflation, especially as it’s — as that’s starting to mitigate as we look at all what all the central banks are telling us these days. So I would like to drive that through to bottom-line cash flow delivery and that certainly as a leadership team is what we’ll be working towards moving forward. Kate, do you want to tackle the convenience GM question?

Kate Thomson: Yeah, thanks. Thanks, Irene. Hello. Nice to hear you. Yeah. In terms of convenience, so year-on-year, if you look at 1Q versus 1Q ’23, you’re seeing a significant impact there with regard to TA. We’ve seen which we acquired last year, that’s just opened its 300 sites. So it’s driving significant volume. What I would say on gross margin, if you exclude TA, we’re seeing between 9% and 10% per annum growth in our gross margin year-on-year. So that’s what gives us confidence with regard to convenience delivery.

Craig Marshall: Okay. Thanks very much. We’ll take the next question from…

Irene Himona: Great Thank you.

Craig Marshall: Sorry, Irene. Thank you. We’ll take the next question from Lucas Herrmann at BNP. Lucas?

Lucas Herrmann: Yeah. Thanks very much, Craig and a couple. One is very straightforward. Just on the share count and the reduction this quarter, the buybacks obviously being 1.75, the share count reductions just over $130 million. I presume that the absence of a greater reduction is because you’ve issued a lot of stock with employees, the benefits or not the benefits. And so we’ll see, yeah, more material sums go out on buyback than the 1.75 or so you’re indicating for future quarters? That was the first. And the second was almost, yeah, congratulations, you’ve achieved 30% growth on your 2022 Permian for your 2022 BPX numbers already. Does it make this number seem rather modest, shall we say, but I think more importantly, Murray, can you just comment on the profile we should expect for liquids as you move through 2025?

Murray Auchincloss: For BPX?

Lucas Herrmann: On the startup of. Yeah, for BPX.

Murray Auchincloss: Yeah.

Lucas Herrmann: So as you said, I mean you’re adding 100,000 barrels a day of liquid capacity, but nothing like that as yet is coming through in the numbers, obviously, Bingo or whatever has just started. Just give me some better sense of where you think liquid will actually be at the end of the period.

Murray Auchincloss: Great. Okay, fantastic. Kate, you want to take the first one, I’ll take the second.

Kate Thomson: Yeah. Sure. Hi, Lucas. So you look just on employee share dilution, we haven’t made any disclosures yet with regard to the impact on 2024. If you look back over the last couple of years, I think 2022 was around $500 million and it was just over $670 million last year. It’s probably going to be of an order of magnitude and the same kind of ballpark for 2024, but obviously, it’s going to depend on share price, and actually when employees actually decide to exercise their options, that will drive a levels of impact and we don’t have that level of clarity at this point, but we’ll update you as we step through the year.

Lucas Herrmann: And you would expect to offset that dilution.

Kate Thomson: Yeah, over time.

Murray Auchincloss: Yeah. We will offset over time as you say, Lucas. So a good eagle eye catch. As far as the BPX liquids profile goes, you’re building up the profile from somewhere between 100 and 120 KBD depending on reservoir responsiveness in the Permian by 2025, assuming the fourth facility comes online as well we’re expanding — we’ve got most of our rigs focused on the liquid window in the Eagle Ford right now given where natural gas prices are. So there should be an uplift there. I don’t have a number at my fingertips, but I can make sure we get that for next quarter. Lucas, if you ask the question again. So there is strong liquids growth as we grow across BPX through ’24 and into ’25.

Craig Marshall: Okay. Thanks, Murray.

Murray Auchincloss: Pleasure.

Craig Marshall: Thanks, Lucas. We’ll take the next question from Peter Lowe at Redburn. Peter?

Peter Lowe: Hi, thanks. I guess another question on BPX production, but this time on the gas side, kind of your gas volumes are still growing quite strongly, and a lot of other producers in North America kind of scaling that production. So does that simply reflect your hedging position or can you talk a bit about kind of why that growth is coming through in such a weak gas price environment? And then just a quick one. Are you able to quantify the impact of price lag effects in the Gulf of Mexico and the UAE on the OP&O results in the quarter? Thanks.

Murray Auchincloss: Okay. Kate, do you want to do the price lag and we’ll come back to the gas profile?

Kate Thomson: Yeah. Sure. Thank you. On price lag, the impact in the quarter was about 0.4, pretty much what we said it was going to be in the trading statement, so we were in line with that.

Murray Auchincloss: Great. Thank you. On the gas profile, you’re right, we’ve hedged out natural gas at – for around $4 through ’23 and ’24. So obviously, we’ve kept that going while we’ve got those hedges in place. We’ve started to reduce rig count right now and point it more to the liquids levels of the Eagle Ford as I talked about. So you’re just doing retention drilling inside the Haynesville. I think what I’d say is the Haynesville is prolific where we drill and the amount of production that comes online and the sustainability is quite high per well. We are in absolutely the best spot of the Haynesville through the BHP acquisition and the teams have really got their capital efficiency down. They’ve really got their frac structuring down to make sure that we get a fabulous production out of these wells.

So I think that’s what’s explaining the growth so far. And then, of course, we’ve got a choice as we move into 2025 based on what we see on gas pricing about whether or not we ramp the gas drilling back up or we stick with liquids and oil. All I’d say is we’ll be very, very value driven. We won’t be volume driven and we’ll see where the best value is and then apply our rig count at that rate. So I hope that helps, Peter.

Peter Lowe: Thanks.

Craig Marshall: Thanks very much. Next question from Kim Fustier, HSBC. Kim?

Kim Fustier: Hi, good afternoon. Thanks for taking my questions. Firstly on CapEx, you said $16 billion of CapEx guidance is now evenly spread over the year as opposed to weighted to the first half. I just wondered if there had been any project slippage to the right. And then secondly, sorry for going back to the $2 billion cost savings, but I think you said that some of those cost savings will have associated restructuring charges. I wonder if you could provide any detail on the kinds of areas where you might incur such charges. I mean, is this related, for instance to headcount reductions and is the $2 billion figure net of those restructuring costs or is it going to be lower than $2 billion after those restructuring costs? Thank you.

Murray Auchincloss: Great. Kate, do you want to tackle both of those?

Kate Thomson: Yeah. Sure. So on CapEx, so we’re still confident of our guidance of around $16 billion for the full year. What’s happened over the course of the last couple of months is that a couple of lumpy payments that would you around the back-end of the second quarter have just tipped over into the beginning of the third quarter and we just wanted to make sure that you’ve got line-of-sight to the fact that it probably wasn’t so heavily focused on the first half compared to the second half, it’s a little bit more evenly now spread around the remaining quarters of the year. And with regard to [indiscernible], we’ll update you in due course as we get clear on the implications of that. At the moment, we are allowing each business and function to work on their own plans to deliver efficiencies.

And as we said, some of that will have some [indiscernible] associated with it, but not all of it. And as we get clear on the scale of the numbers and when we report them, we’ll update you.

Craig Marshall: Thanks, Kim. We will take the next question from Menno Hulshof at TD Cowen. Menno, over to you.

Menno Hulshof: Great. Good afternoon, and thanks for taking my questions. So the first is on the simplification of the org structure. You’ve clearly made significant headway already, but where do you think you stand in that process? And then, the second is yet another follow-up on the $2 billion target. And apologies if you talked about this already, but can we get a rough breakdown on how much each of the four initiatives is expected to contribute and whether achievement of the $2 billion is expected to be fairly linear over the next two and a half years? Thank you.

Murray Auchincloss: Sure. Why don’t I tackle both of those since I gave you the last two ones, Kate? I’ll give you a relief. You should think about the four cost initiatives each delivering around a quarter of the benefit. It may end up being different than that, but that’s a good estimate for right now. And as far as the linear nature, we said it’s by the back end of ’26 and it will take time to do some of these things. So I wouldn’t count on much impact in ’24 and ’25. It should be coming in through ’26 as we work our way through it. On the org structure itself, we have announced the first stage of simplification. There will be multiple steps along the way, maybe two or three steps is how I’m thinking about it. We have reduced my direct reports down to 10.

We’ve combined some functions inside the organization as well. Those need to be well-managed. We have to have very, very strong management of change as we go through this and make sure that safety is paramount as we do it. And we expect in due course to announce another set of simplification steps to try to make the place easier to work in and maybe around year end, we’ll see that next step. And so that’s what’s happening on simplification inside the company. Craig, back to you.

Craig Marshall: Thanks, Murray. Thanks, Menno. Three questions left. We’ll take the first one from Henry Tarr at Berenberg.

Henry Tarr: Hi, there, and thanks for taking my question. Two quickly. One on the outlook for U.S. offshore wind at this point in your Beacon wind project. How are you thinking about offshore wind broadly in the U.S. and that project moving forward? And then just coming back to a comment about the potential to be countercyclical in low carbon, where do you see sort of attractive returns today in low carbon either within your own business or sort of externally or where might you be looking across that space? Thanks.

Murray Auchincloss: Great, Henry. I think on — I’ll tackle both of these. I think on Beacon, look, we’re going slow on that one. Infrastructure needs to develop off the Northeast Coast of the U.S. We need to see some changes in pricing mechanisms moving forward so that we can move to — more to an integrated model like we see in Europe and it’s hard to predict at what pace that will happen. But I think on Beacon we will be going slow, I think is what I’d say for now. As far as countercyclical, I’ll have to be careful on this one because the second I say anything about it, I’ll have too much competition. So I think what I’d say is, the — my hierarchy of returns on the growth engines from biogas to biofuel to convenience to electrification are the places that are quite interesting to me and you can figure out what the countercyclical moment might be inside some of those based on what’s been happening recently, and I’ll stop myself saying any more than that because my mergers and acquisitions team might shoot me if I say anymore.

So I hope that gave you enough hints, Henry, to think about, and due course, you’ll see or you won’t see announcements last year.

Craig Marshall: I think, Henry, just to reiterate, obviously, we’ve laid out our CapEx guidance and that’s organic and inorganic in totality. So there’s not any leakage.

Murray Auchincloss: CEO doesn’t get to spend more than $16 that was a code from Craig.

Craig Marshall: So IR, sorry. Thank you, Boss. And then the last question, sorry, I thought there was two, but the last question from Giacomo Romeo at Jefferies. Giacomo, thanks for being patient.

Giacomo Romeo: Yeah. I know, thank you. And sorry, actually slipped off the list and had to go back on. The first question, if I can just ask again about this countercyclical. Just wanted to check with you, Murray. I think that on the Q4 call, you talked about the fact that you’ve done a lot of acquisitions in the previous years and you were sort of focusing more on integration. As somehow this message changes or what kind of size of acquisition countercyclical deal we could expect. The second is on the Namibia farming. Just trying to understand, when Azule was set up in ’22, was always the — was your thinking always about making it your West Africa and West Africa venture, or has this somewhat evolved over time? And just on the deal in Namibia specifically, the PEL 85 is on shallower waters versus where other discoveries that may have been made. Just trying to understand what gives you confidence that the play will extend onto shallower waters. Thank you.

Murray Auchincloss: Yeah. Let’s see on countercyclical, what I’d say is, we have a tight capital frame at $16 billion in ’24 and $16 billion in ’25. Last time I communicated with you, I said we’ve done an awful lot on acquisitions from TA to Arkea to LightSource to EDF, and it’s time to bring — now bring the synergies out of these. And I gave you a caveat saying, however, we will consider one or two more of these things moving forward. So I’m not out of line with what I said in February and what I said in the previous quarter, I’m in line with that. It’s one or two opportunities that we see over the next couple of years. And I guess the point was more, I’m not going pro-cyclical and oil, I’ll think countercyclical and transition while prices are low. And let’s see, if we can actually prosecute anything. Kate, do you want to talk about origins of Azule? I can tackle the geology question.

Kate Thomson: Yeah. Sure. So I mean when Azule was set up with D&I, it was a great marriage of assets. Ours were later life and generating significant cash and E&Is were earlier life. So it was a very nice symbiotic relationship, very similar to the one we created with Aker BP. And since we formed it, we’ve taken just over $5 billion of distributions. A couple of points I’d say on the finances with regard to Azule and Namibia is it’s been set up to be a self-funded vehicle and to continue to distribute back to its shareholders. And for the first part of Namibia, it’s two exploration wells. Let’s see what happens with that. Don’t expect a material impact on the distributions back to us or E&I, but let’s see what happens with those.

Murray Auchincloss: If I channel my inner explorer, really water depth doesn’t matter, it’s what’s happening subsurface. I think the interesting bit about these ones, Galp has had some discoveries, you’ve seen what their announcements are. When you look at the seismic on the block that we picked up from Rhino, it’s a direct extension of the four or five structures that are in the Galp blocks at the same geologic depth. So, who knows what happens with exploration, sometimes it works, sometimes it doesn’t, but there are very clear structures in the Galp block. There are very clear structures in the Rhino block. They lay in a pattern. They should have the same charge, they should have the same origin. Of course, there’s geologic risk around it, but water depth really doesn’t play into it.

So let’s see, let’s see, Giacomo. Let’s see what happens. You have to drill the wells to find out what’s actually down there. I think with that, Craig, shall we close? So thanks everybody for listening to us. Another decent quarter-out of BP. I’m really pleased about bringing growth to the market. So ACE getting up online in Azerbaijan, BPX expanding their operations with the third operation — third plant in the Lower 48 in the Permian. Archaea expanding one big plant, five more in commissioning and we’ve got great momentum around cost as well. So I’m very optimistic about growth for BP as we look through the next couple of years and hitting our targets and in due course, updating you about what’s beyond that. So thanks very much for listening and look forward to chatting with you next quarter.