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 U.K. time, and we hope, together, these updates around our process and disclosures have 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. U.K. 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.

Good, thanks Craig and thanks everyone for joining Kate and me 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 East 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 5 in commissioning. Last week, our JV Azule announced a 42.5% farm-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.

Super, thanks, Murray. So we'll go straight to questions now and we'll take the first question from Josh Stone at UBS. Josh?

And appreciate the slightly longer time to study the results. Yes, 2 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. If I look at consensus, it feels like few people believe in these numbers and it's only now almost 18 months away. So yes, 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 talk about TA was impacted by an ongoing recession of freight in the U.S. So 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? And then the second question on the Whiting refinery, good to see it 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?

Yes, sure Josh. 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 6 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%. 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 5 as we speak. So we should be in good shape for the $15 million to $20 million 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 a 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 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.

Thanks, Josh. We'll turn to Biraj Borkhataria, RBC. Biraj?

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 slide, 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. It's brought up by one of your counterparts. Where does BP sit on this? Is it a live debate? Do you see it as a structural disadvantage? Unlike your counterparts, you do have a big domestic U.S. business upstream and downstream there. So, just wanted to get your thoughts on that.

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 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 a 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 1/3, simply by doing that performance. So that's what's on our agenda, not relisting. And so we're just focused tightly, tightly on performance, Biraj. Kate, over to you on the first question, please.

Yes, so I've seen some of the narrative. Look, it's incredibly hard under the current accounting standards to really try and compare like-for-like, line-by-line the P&L account. There's a level of interpretation, let's say, on how companies can actually account for their costs 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 our 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 2027, will probably make your lives a bit easier. It will force more transparency and probably greater comparability across the sector. So I hope that's helpful.

I'm going to move stateside now, given we're at a slightly more hospitable time. I take the first question from Paul Cheng at Scotia, Paul?

Kate, in the press release, you discussed the impact of the Egypt devaluation and foreign currency. Can you share a specific number regarding that? Also, from the fourth quarter to the first quarter, the gas and LCE decreased by about $100 million in adjusted earnings. How is that contribution from the low carbon side? Is low carbon improving or deteriorating based on what we are observing? That's my first question.

Kate, over to you on Egypt. I think it answers the second question as well, doesn't it?

Yes, that’s correct. Regarding Egypt, we experienced a significant currency devaluation, with the exchange rate moving from 30 to 48 following the country's decision to free float its currency ahead of receiving funds from the IMF and others. This foreign exchange impact was evident in the first quarter, contributing around 0.2 to our results. Additionally, it influenced our tax rate for the quarter. This is the situation concerning Egypt and its devaluation. Regarding gas and low carbon performance, production has increased, but ARCOP has decreased quarter-on-quarter due to lower realizations and foreign exchange effects. That summarizes the performance in G&LCE for the quarter.

Okay. Kate on the cost reduction, the $2 billion how much of them is related to any divestment or that's purely on the actual underlying cost performance better?

Yes. We will go through the intervention. There are four areas we are focusing on, one of which is refining our portfolio. As we have mentioned for some time since we established our six priorities in February, we will implement changes in the portfolio as we gain clarity on the components and their contributions, and we will provide updates on this in due course.

Yes. 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 about which ones we are going to take forward. And as we do that, redeploying engineers to the highest quality ones, redeploying third-party resources, et cetera. That will create a lot of cost savings as we really, really focus on these things moving forward. A small example of that to think about. During the past 90 days as we decided to sanction Atlantis tieback in the Gulf of Mexico, so you sanctioned that. At the same time, we decided to release BirAllah and 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 fewer third-party services, which creates cost savings.

We'll stay in the U.S. and take the next question from Ryan Todd at Piper Sandler. Ryan?

Maybe 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 start-up of TMX, any flexibility that you might have to mitigate the impact, whether in the Mid-Con or on the West Coast to Cherry Point. And then maybe a follow-up on the cost that you were talking about there. There's 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?

Sure, I'll address the first question. As for TMX and our observations, we have noticed that the price differentials between WTI and WCS have started to narrow, currently around 14. This seems to be a reasonable range for the future, give or take a couple of dollars. While it's difficult to make precise predictions, that's our outlook. To counter these changes, we've implemented two strategies. First, with TMX coming online, we will have a direct route for oil to Cherry Point, providing access to more cost-effective products, which should benefit us. Additionally, we've been working on pipeline reconfiguration over the past few years to enable us to transport products across North America, helping to manage risks related to Whiting as well. Overall, we believe we are in a similar position to where we were before TMX began operations, given the capabilities we have at Cherry Point and our flexibility with Whiting and Cushing. Now, I’ll turn it over to you for the capital question.

Yes, sure. 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. 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 cost down. What I would say is, the odd capacity is tightly, utilizations are high, probably the highest they've been for about a decade, and we think they may well remain like that for another 3 to 5 years perhaps, so that's something we'll 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 Kaskida right now. We hope to be able to move to sanction that at some point during the remainder of this year.

And I think on the LNG side from recent bids we're seeing, we're okay to continue moving this 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.

We'll take the next question from Chris Kuplent at Bank of America. Chris?

Just 2 quick questions for me. I was wondering whether there is a specific reason you no longer publish your surplus cash flow metric. 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 $2.2 billion 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?

Yes, sure. I'll let Kate answer the surplus one, and then I'll tackle Egypt.

Yes. So when we updated the financial frame in February and set out a 2-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 surplus cash calculation. It was creating an awful lot of volatility. It remains something we look at over time, as you can see from the fin frame, we said that over time, we expect to distribute 80% of surplus cash to shareholders. 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 any 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 link to a surplus cash calculation.

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 really on how we move our way through 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.

We'll take the next question from Lydia Rainforth at Barclays. Lydia?

If I could circle back to the cost base and the targets that include at least $2 billion, could you provide more detailed examples of what that entails? It can be challenging to distinguish between costs that support growth versus those that indicate inefficiencies. I am a bit surprised by your mention of $20 billion in transportation and shipping costs, as it seems there may be aspects you could address. I'd appreciate any insights you have on this. Additionally, concerning the EBITDA guidance, with the cost savings figure, is there a case for potentially raising the EBITDA targets? Specifically, I'm interested in whether we should anticipate some momentum in the EBITDA figures for this year as we look towards an exit rate for 2024.

Thank you for your questions, Lydia. Regarding cost examples, we are focused on four key areas to achieve at least $2 billion in savings by the end of 2026. The first area is portfolio focus, which I've already discussed. The second is digital transformation, where we've made significant progress in digitizing many parts of our business and are now implementing GenAI. For instance, we require 70% fewer third-party coders because the AI manages most of the coding, with humans only needing to validate the final 30%. This represents substantial savings for the company. Additionally, our call centers have benefited from advanced language models that can now operate in multiple languages, allowing us to redeploy staff since the AI can handle these tasks. Last quarter, I mentioned how advertising cycle times have significantly decreased from 4 to 5 months to just a few weeks, further reducing our spending with third parties. We've integrated GenAI widely across our business, and I will continue to share updates as we progress. This transformation is a significant step forward for us, and I'm continuously looking for ways to increase margins and reduce costs. A good example of eliminating waste is our alliance with Subsea7. In the past, we would oversee their work, but now we collaborate through joint teams to optimize projects, incentivizing them for efficiency. This collaboration reduces bid cycles, minimizes the number of engineers needed from both sides, and decreases vessel time. This concept of alliances has been effective in our capital projects and drilling, and we're expanding it into operations in both upstream and refinery activities. Lastly, we are establishing global capability hubs to address the ongoing demand for engineering, which is scarce in the west. We're looking east for engineering capabilities, which can sometimes have a different cost profile but offer excellent efficiency. This shift also applies to contractors we work with, as well as our internal engineering and IT functions. These are the four examples of how we aim to reach the $2 billion in savings. Regarding your question about 2024 and run-rate EBITDA, I'm not providing specific updates on that right now. However, I am confident in a growth rate of 3% to 4% on an underlying cash flow basis throughout the decade, including in 2024 and 2025. We anticipate strong growth in the upstream sector with new projects and a return to normal operating conditions in our refineries, alongside growth in our other businesses. We feel assured about maintaining that 3% to 4% annual growth on a free cash flow basis through 2024 and 2025. As for the impact of cost savings, it may take time to realize some of these benefits, and while some will materialize quickly, we will monitor our progress.

I think you kind of did my job for me.

Did I roll into your question. Sorry about that.

The only thing I was going to add is that, some of the changes that we're contemplating take time to effect 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 red tapes.

I hope that helps you, Lydia.

Great.

We'll take the next question from Michele Della Vigna at Goldman Sachs. Michele?

And congratulations on the focus on cost efficiency despite the relatively positive macroenvironment. 2 questions, if I may. On the dividend per share, it looks like we are up for an announcement next quarter. 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, quite a difficult line to forecast. It's been around $900 million for the last 3 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?

Kate, do you want to handle the dividend?

Sure, Michele, I think you've already done the calculations for me. I want to add a couple of points. When considering the financial framework, it's important to keep our balance points in mind. Our top priority remains the resilient dividend, with the potential for a 4% annual increase at the $60 mark. As you've noted, we've had previous increases in the second quarter of 2022, the fourth quarter of 2022, and the second quarter of 2023, each around 10%, driven by strong performance and a reduced share count. The Board will take various factors into account when we have that discussion in the second quarter. Regarding our share count, I believe it has decreased by 17% by the end of 2023, and since the second quarter of '23, we've seen about a 5.5% reduction. So feel free to include that in your calculations.

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.

We'll take the next question from Martijn Rats at Morgan Stanley. Martin?

So last quarter, you were helpful in providing 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, it's actually quite helpful. So this quarter EBITDA was $10.3 billion. 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 its longer term sort of 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?

Sure, I'll address both of those, Martin. Thank you for the questions. We indicated that the conditions in 2023, which are quite similar to those in the first quarter of 2024, provide a good baseline for considering 2025. You should apply the underlying growth rate to estimate the EBITDA over the two years. We've mentioned a 3% to 4% underlying cash flow growth, given that CapEx is stable and proceeds are fairly consistent, suggesting a similar EBITDA growth of 3% to 4% for both 2024 and 2025. I’ve provided details on the sources of value before to help you quantify this. Additionally, the $10.3 billion reported in the first quarter of 2024 was significantly affected by an unusual event with Whiting, which resulted in a $0.5 billion impact for that quarter. You might want to add that back, bringing you closer to an $11 billion EBITDA under normal conditions for 2025. Multiplying that by 11 gives you an idea of our performance, while the 3% to 4% growth indicates our outlook for 2025. Everyone will adjust their expectations based on their assessment of performance and market conditions. That's about as detailed as I can provide. Regarding the FT article mentioning 2 million barrels per day, I want to remain consistent with what I shared last quarter. We've been transitioning from an International Oil Company to an Integrated Energy Company and will gradually diversify our business. We're focusing on biotechnologies, electric vehicles, convenience, hydrogen, and renewables while still investing in hydrocarbons. As for hydrocarbons, 2030 is our aim, not a firm target. Currently, we're estimating around 2 million barrels per day, largely dependent on a series of potential investment decisions we need to make in 2024 and 2025, totaling about 30 projects in areas like upstream, refining, and growth engines for the transition. The outcomes will be determined by our decisions. My primary focus is on returns and cash flow, rather than volume. Recently, we sanctioned an oil project in the Gulf of Mexico and divested two gas resources on the West Coast of Africa, signaling our return-driven strategy. Once we've finalized our investment decisions in the next couple of years, we will provide an update on our target for 2030 production. Could that figure exceed 2 million barrels per day? Yes. Could it fall below that? Yes. The emphasis will be on returns and cash flow, as you would expect. I hope this gives you a clearer picture.

We'll take the next question. Actually, we'll go back stage side from Roger Read at Wells Fargo. Roger?

Just wanted to dive back in, Murray, earlier, you mentioned diesel recession going on since you have a pretty impressive global footprint. Just wondering 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 productivity and efficiency, things like that.

Sure. Kate, do you want to take diesel recession?

Yes. Sure. Yes. 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 having spoken with Debbie and her LT out there. They are all over how they offset that until such point as the recovery starts to kick in. And we expect currently that, 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, 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 their larger fleets, where you may get slightly slimmer margins, but you've got to capture upside from the non-fuel income.

Great. Thanks, Kate. I think on the Permian, Roger, obviously, 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 little bit looser. 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 spend. 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 I 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.

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

Yes, 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 block south of Galp's big discoveries with Rhino. We farmed in for 42%, and we chose to do it through Eni and ourselves, chose to do that through Azule, which is 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 2 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 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 in a nice postcode. Craig, back to you.

We'll take the next question from Christyan Malek at JPMorgan. Christyan?

2 questions, please. First, just on the cost savings. I have to congratulate you continuing to drive efficiencies. My only sort of kind of just a question around growth, is your liquids growth in '26, back to that sort of theme. Why aren't you thinking all 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 a very bare market to continue to focus on cost, albeit that's absolutely necessary. So I 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, so I just understand better what the free cash flow trajectory will be on a medium-term basis, as we start to think about drawing a part through EBITDA targets?

Great. Kate, do you want to lead off with disclosures on low carbon trading?

Yes. 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 won't be breaking those out beyond the 5 transition growth engines, I think there's enough complexity in that disclosure as it is already.

In our Denver presentation last October, we discussed a resilient oil portfolio that can increase production by 2% to 3% through 2027. As we consider our sanctions moving forward, including those in the Middle East, the East Coast of Canada, Brazil, the Gulf of Mexico, and the North Sea, we have a substantial amount of oil in our portfolio. These sanctions would allow us to expand our oil business beyond 2027, but I cannot confirm that until we decide which sanctions we will proceed with. Regarding acquisitions, I believe in being countercyclical; with low carbon energy currently struggling, this is the right time for countercyclical strategies. This is why we are engaging with Lightsource bp now. We might explore more countercyclical opportunities in the coming years. With oil prices at $85 or $90, I’m not convinced this is the right moment to buy oil. We may consider smaller acquisitions, but we prefer to adopt a countercyclical approach rather than a pro-cyclical one. We have strong growth prospects, especially compared to our competitors in high-margin basins of the OECD, so I am content with our current position. I would rather avoid high-price acquisitions and focus on countercyclical strategies with limited cash where opportunities exist. I hope that clarifies things for you, Christyan.

We'll go to Irene Himona at Bernstein next. Irene?

My first question, Murray, going back to the $2 billion cost savings. 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 underlying cost base flat, would you say? And then secondly, on convenience. I mean, your convenience gross margin grew 62% in 2023 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?

Yes. I think on the $2 billion in 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 that's why we say at least $2 billion, maybe something above that takes us to beat inflation. But I'd like to try to beat inflation. Especially, as that's starting to mitigate if we look at 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, we'll be working towards moving forward. Kate, do you want to tackle the convenience GM question?

Yes, thanks Irene. Yes, in terms of convenience, so year-on-year, if you look at 1Q versus 1Q, 2023, you're seeing a significant impact there with regard to TA, obviously, which we acquired last year. That just opened its 300th site, 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.

We'll take the next question from Lucas Herrmann at BNP. Lucas?

I have a straightforward question regarding the share count and its reduction this quarter. The buybacks have amounted to $1.75 billion, leading to a share count reduction of just over $130 million. I assume the limited reduction is due to the stock issued to employees. Will we see more significant buybacks in future quarters beyond the $1.75 billion you mentioned? Additionally, congratulations on achieving 30% growth in your 2022 Permian or BPX numbers already. This makes the current figure seem quite modest. More importantly, can you comment on the expectations for liquids as we move through 2025?

For BPX?

From the startup of BPX, you're adding 100,000 barrels a day of liquids capacity, but nothing like that is reflected in the numbers yet, as Bingo has just started. Can you provide a clearer idea of where you expect liquids to be at the end of the period?

Great. Okay. Fantastic. Kate, you want to take the first one, I'll take the second. Yes, sure. So you look, just on employee share dilution, we haven't even 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 in 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 level of impact, and we don't have that level of clarity at this point. We'll update you as we step through the year. And you would expect to offset that dilution.

The intention to offset, right?

Yes, over time.

Yes, we will offset over time as you mentioned, Lucas. Good observation. Regarding the BPX liquids profile, we anticipate building it up to between 100 and 120 thousand barrels per day depending on the reservoir responsiveness in the Permian by 2025, assuming the fourth facility becomes operational. Additionally, we are majority focused on the liquid window in the Eagle Ford at this time due to current natural gas prices, so we expect an uplift there. I don’t have a specific number right now, but I will ensure we provide that information for next quarter, Lucas, if you ask again. There is strong liquids growth expected across BPX through 2024 and into 2025.

We'll take the next question from Peter Low at Redburn. Peter?

Actually another question on BPX production, but this time on the gas side, kind of your gas volumes are still growing quite strongly. A lot of other producers in North America kind of scaling that production. Does that simply reflect your hedging position? Or could 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 P&O results in the quarter?

Okay. Kate, do you want to do the price lag and I'll come back to gas profile?

Yes, sure. 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're in line with that.

Thank you. On the gas profile, you're right, we've hedged out natural gas at 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 is sustainable is quite high per well. We're 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 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.

Next question from Kim Fustier, HSBC. Kim?

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 some of those cost savings will have associated restructuring charges. I wondered if you could provide any detail on the kinds of areas where you might incur such charges. 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?

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

Yes, sure. So on CapEx, 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 were due 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'd 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. With regard to RATX, 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 RATX 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.

We will take the next question from Menno Hulshof at TD Cowen. Menno, over to you.

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 4 initiatives is expected to contribute and whether achievement of the $2 billion is expected to be fairly linear over the next 2.5 years?

Sure. Why don't I tackle both of those since I gave you the last 2 ones? Kate, I'll give you a relief. You should think about the 4 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 org structure itself, we have announced the first stage of simplification. There will be multiple steps along the way, maybe 2 or 3 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 maybe around year-end, we'll see that next step. So that's what's happening on simplification inside the company. Craig, back to you.

3 questions left. We'll take the first one from Henry Tarr at Berenberg.

2 quickly, one on the outlook for U.S. offshore wind at this point and 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 where might you be looking across that space?

Great, Henry. I'll address both of your questions. Regarding Beacon, we are progressing slowly with that project. Infrastructure needs to be developed along the Northeast Coast of the U.S. Additionally, we need to see changes in pricing mechanisms moving forward to transition towards a more integrated model similar to Europe. It's difficult to predict how quickly that will occur. For now, my assessment of Beacon is that we will be moving cautiously. As for countercyclical opportunities, I need to be careful about how much I disclose, as discussing it could invite too much competition. However, I can share that my focus is on the hierarchy of returns from biogas to biofuel, convenience, and electrification, which I find quite interesting. You can infer where potential countercyclical moments might exist within those areas based on recent developments. I'll refrain from saying more on this topic to avoid giving my mergers and acquisitions team any reason to be concerned. I hope that provides enough insight for you, Henry, and you'll either see announcements in due course or you won't.

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

CEO doesn't get to spend more than 16, and that was code from Craig.

I apologize for the confusion earlier. Thank you for your understanding. Now, I'll move on to the last question from Giacomo Romeo at Jefferies. Giacomo, I appreciate your patience.

Can you provide an update on the countercyclical aspect? During the Q4 call, you mentioned that you were focusing on integration after a series of acquisitions in previous years. Has there been a change in your message regarding this, and what size of acquisition in the countercyclical space should we anticipate? Additionally, regarding the Namibia farm-in, I would like to understand if Azule, which was established in 2022, was always intended to be your West Africa venture, or has this idea evolved? Specifically about the Namibia deal, PEL 85 is in shallower waters compared to other discoveries. What gives you the confidence that the play will extend into these shallower areas?

Yes. Regarding countercyclical strategies, I want to highlight that we have a firm capital framework set at $16 billion for both 2024 and 2025. In my last communication, I mentioned that we've engaged in numerous acquisitions, including TA, Archaea, Lightsource, and EDF, and it's time to start realizing the synergies from these investments. I also noted that we may consider one or two additional acquisitions in the future. So, what I shared in February and in the previous quarter remains consistent. We foresee one or two opportunities over the next couple of years. Importantly, I'm not shifting toward a procyclical approach in oil. Instead, I believe in pursuing countercyclical and transitional strategies while prices are low. Let's see if we can make any progress. Kate, would you like to discuss the origins of Azule, or should I address the geology question?

Yes, sure. So I mean, when Azule was set up with DE&I, it was a great marriage of assets, ours were later life generating significant cash and E&I were earlier like. 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 has been set up to be a self-funded vehicle and to continue to distribute back to its shareholders. For the first part of Namibia, it's 2 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.

If I channel my inner explorer, really water depth doesn't matter. It's what's happening subsurface. I think the interesting bid 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 4 or 5 structures that are in the Galp in the gout 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, 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 plant in the Lower 48 in the Permian, Archaea, expanding one big plant, 5 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 I look forward to chatting with you next quarter.