Galp Energia, SGPS, S.A. (GALP) Earnings Call Transcript & Summary

Good day, ladies and gentlemen. Welcome to the Galp's Second Quarter 2022 Results Presentation. I will now pass the floor to Mr. Otelo Ruivo, Head of Investor Relations. Please go ahead.

Hello, everyone, and welcome to the analyst Q&A session related to Galp's second quarter and first half 2022 results. Thank you for joining us today. Early this morning, we released all the results materials and included a video presentation from Andy and Filipe, highlighted the key achievements during the quarter and covering the financial results. As such, this session should be shorter as we will go straight to Q&A. Together with Andy, we have Filipe, Teresa, Georgios and Thore. So the full executive team here available to take your questions. As usual, I would like to remind you all that we are -- be making forward-looking statements that refer to our estimates. Actual results may differ due to factors included in the cautionary statements presented at the beginning of the presentation we released this morning, which we advise you to read. Andy, do you want to say a few words before we start the Q&A?

Thank you, Otelo. I just want to reiterate some of our messages. We were pleased with the results we presented earlier today. Cash generation, close to EUR 0.5 billion of free cash flow despite a working capital build. This is supported by strong performance on all business segments. As a result, today, Galp is in even more robust position with our leverage now down well below 1 net debt to EBITDA, giving us additional financial strength to execute our strategy. And with our distribution framework, we should be able to offer 2022 dividends, 1/3 of our operating cash flow. And operating cash flow is now expected to be close to EUR 3 billion. As I also alluded to in my video presentation, we made really good progress on the execution of our key projects that underpin our portfolio reshape. So exciting times for Galp, and we're all here ready to take your questions. Thank you very much.

[Operator Instructions] The first question comes from the line of Biraj Borkhataria from RBC Capital Markets.

Thanks for the new format, much appreciated. So 2 questions. The first one is on the low carbon portfolio. So following the Titan deal, if we think about 2023, how much CapEx is being from sort of deconsolidated to being consolidated? I'm just trying to understand the moving parts versus the prior plan. And then the second question is on shareholder returns. You guide to the 1/3 payout, EUR 500 million in buybacks for fiscal year 2022. How are you thinking about second half of this year? Given where the share price is and the visibility you have on volumes and, I guess, commodity prices to some extent, you may want to accelerate that. So how should we think about the balance of the second half of this year and then into next year?

Thanks, Biraj. Look, firstly, I think we've given some guidance on where we see the commodity prices for the remainder of this year, around $90 -- $15 a barrel refinery margin that gives us as close to EUR 3 billion of OCF. We have no additional guidance at this moment on how we will distribute the 2022 dividend, but I think we're pretty clear, that will be 1/3 of OCF. Now on the Titan deal, clearly, this was an opportunity to take control of this portfolio. The reason we take control isn't per se to consolidate it, but was to create some more flexibility going forward to unlock more value. But perhaps I can hand over to Filipe to give some guidance on how this may affect CapEx going forward. Early days for us to actually announce anything particularly, but Filipe, how do we see the numbers?

So in the real world, so the assets are generating and producing as before. So Galp now has increased exposure from 75% to 100%. That's really what has happened. From an accounting point of view, before, when it was deconsolidated, we would put in our equity into the project. Our partner would put in its 25% share. We have project finance and some of the underlying assets. So the plan is that we keep 100% of the top co that we now fully controlled. The underlying assets have project finance, and what you had in our cash flow statement before was whatever money would come to Galp after the assets would service their debt. So it was a relatively small amount. So you will now see the full cash flow coming to us. You will also see more CapEx going out and also the project finance debt that we have now brought on board to Galp. So net-net, we have -- we're bringing a lot of visibility of this business into our consolidated statements. And so the market will have a much better view of the true cash flow generation without the project finance associates movements. Thank you.

Sorry, are you able to quantify the CapEx that is being consolidated for '23?

So if you look at our long-term plan assumption, what we've disclosed early this year, we're growing the portfolio 300, 400 megawatts per year. If you put in, assume a round number EUR 700,000, EUR 800,000 per megawatt, it's giving you EUR 300 million, EUR 400 million of gross CapEx before asset rotations, and that would also -- you'll see that as a CapEx number.

I think Biraj -- can I just -- I mean, obviously, this is a great portfolio. It's exposed to the merchant market, generated EUR 200 million in the last 12 months in Titan. And you may ask, well, why do we do this? I might ask Georgios to just say a few words about what this flexibility that we'll bring by taking full control of this asset base.

Yes. Thanks, Andy, and I think that will perhaps also preempt other questions. So Biraj, that was the opportunity to do a deal -- a comprehensive deal to get control of the assets and be able to have execution of the portfolio in our own, let's say, hands. We had the opportunity to get this deal in a comprehensive way, exchanging also certain other things that we had to sort out with Cobra. Cobra is not a natural, let's say, owner of this 25%. Cobra wanted to focus more on the development and on the execution of the portfolio. We had agreed EPC prices at different times. So that was an opportunity also to update the EPC prices to more, let's say, current context. We also had the opportunity to change the engineering of those projects to change the scope of the EPC agreement so that we have higher yields. And that, all in all, with getting the 25% on our hands, gives us the opportunity to be able to market the energy ourselves, to consider other value pools in the future from energy management, but also eventual asset rotation. So all in all, it's a deal that gives us more control and more optionality for the future.

The next question comes from the line of Oswald Clint from Bernstein.

Could I ask about Bacalhau North, please? Good to see the rig secured. So that's still a 2023 drilling, I think, to appraise Bacalhau North, if you can confirm that. But I just wanted to get your broader thoughts around Bacalhau North. Are you -- at this point, do you think it could feed into a [ section FPSO ] or still very much a resource [ addition ] for the first FPSO? And perhaps more broadly, just what's the latest on the Tupi redevelopment plan, please? That's the first question. I mean the second question, just a little bit further on renewables, please. The -- I mean, there's comments around continual licensing and permitting delays. I thought in the context of Russia gas that Europe was going to Portugal to speed up some of these approvals. So if that's the case, does it make you lean more towards the acquisition side of the renewable portfolio, especially given your financial strength? Would you look to do more such acquisitions here?

So can I ask Thore to talk about Bacalhau North and update on the PoD for Tupi?

Yes, Andy. Thank you, Oswald. So when it comes to the latest rig that we have taken in for Bacalhau, it actually has 2 purposes. One is exactly as you're alluding to, that we are going to use that rig to drill the ADR well in the north in order to better understand what is really the potential for Bacalhau North. Of course, the outcome of this well will very much determine what will then be the way forward. Is it going to be a tieback or is it going to be a stand-alone? So that has not been decided at this stage. But the latest rig we took in has also a second purpose, namely having additional drilling capacity to make sure that Bacalhau Phase 1 have all the available production capacity when it comes on stream so that we get the swift ramp-up. When it comes to Tupi and the second phase and the new PoD, it is moving ahead according to plan. We are just now starting to drill the first infill wells for the product. And then we are in active dialogue with ANP with respect to approvals of the new PoD that has been handed in, and that is a dialogue that goes back and forth between the partnership and ANP.

On renewables, on the licensing delays, look, I think clearly, the European Union has set out an ambition to accelerate these permitting. And what happens now is the different countries are putting in legislation to kind of underpin that and to create the environment where they can accelerate those approvals. Portugal has recently put a package through. And so I think for us, the jury is out a little bit about how effective these are. Does that change our strategy from going from a kind of organic growth to one that's inorganic? No, I don't think you can draw that conclusion. But I think we will continue to make the point that there is more money pointed towards renewables growth in Europe than there is the capacity for the government to give the permits to actually pursue them. And if repower Europe is going to become a reality, we are going to have to accelerate permitting not only just for electricity but also for value streams like hydrogen. And so this is a really important point that we want to work very closely with government to make sure that all the money we want to spend in renewables can actually find a home.

Hello? Can you hear me?

Yes.

Mehdi, your line is open.

Okay. Sorry. This is Mehdi Ennebati, Bank of America. Two questions, please, on my side. First question on the maintenance schedule in Brazil. So can you please remind us how many maintenances you realized on FPSOs in Brazil in the first half of this year? And how many maintenances are scheduled during the second half of this year? Because it seems that this year, I know it was -- the first half was pretty heavy in terms of maintenance. So should we expect, let's say, a little bit less maintenance in the second half? And maybe can you also tell us more about the current production level of the FPSOs, which were on maintenance in the first half? Would you say that production is back to 2019 levels? Or would you say that the depletion started having an impact, and it is almost impossible for you or to changing for you to come back to 2019 production on those FPSOs, which were on maintenance in the first half of 2022? And the second question is about your gas business. This quarter, again, you've highlighted that you've met some gas sourcing issues. From what I understood last year, let's say, in February, you were highlighting that you took some measures to significantly limit those gas sourcing issues, but we can still see this quarter quite a significant impact. So would you say that you have been surprised by -- you were thinking that it will be much easier for you to find some natural gas or to, let's say, lower the purchase on the spot market. So negative surprise? Or would you say that this is in line with what you've scheduled, but unfortunately, you have been surprised by the price of the natural gas? In fact, the real question behind that is, is there a very significant risk for you this winter in case there is some difficulties of gas supply in Europe? Should we expect that division, that business of yours to be under pressure?

Thanks, Mehdi. And I will hand over a second on both actually subjects to Thore. But firstly, on the maintenance schedule, I think we can roughly see the planned shutdowns to be evenly distributed between the first half and the second half of the year. But in the first half, they were really concentrated in the second quarter, not the first quarter. And I think that's something we see. Now do we have to fight against declining production as the pressure comes out of the reservoir? Yes, I think as a normal oil business, we do. But Thore might be able to add some color on the maintenance planning. And I'll just address the gas topic as well now. We had a schedule of deliveries for our gas business that is being maintained. It is below what we had originally contracted, and we have taken whatever measure we can to reduce our own gas consumption. And part of that was to fire our hydrocracker on naphtha instead of gas. That is a new operation, and it's one where it creates some additional fouling, and Thore can talk a bit about how we will be looking forward to see how we can balance the gas versus naphtha in using in the hydrocracker. What I can tell you, it will all rely on whether the deliveries can keep up with the schedule that we're being promised now probably 9 months ago. And if it does, then we will be in a reasonably -- reasonable position to cover the obligations of gas we're sold for our own use, but also for the use of our customers. So I hope -- we hope, Mehdi, that we aren't going to have to go to the market again, but this all rely on receiving the cargoes as per the schedule we've given before. So Thore, perhaps a little bit more color on maintenance and then anything more on the naphtha or gas use in the refinery.

Sure, Andy. Thank you, Mehdi. It is very correct, what Andy said. The heaviest part of our maintenance this year as we see it today, actually took place in the second quarter of this year. All the FPSOs are planned to go down for maintenance during the course of the year, but it was a heavy bunch in the second quarter. We expect there will be maintenance also in the third quarter, and then it will be -- the lightest quarter will be the fourth quarter. So that is what you can expect in the ramp-up. I will not go into the details on each one of the units, but that is what you can expect, production impacted by the maintenance also in the third quarter and even less in the fourth quarter. That is what the planning is today. When it comes to production, the production potential is remains very good. Tupi is astounding when it comes to sort of the level of production capacity. But it is a depletion business, and there is a decline in Tupi, which is not very high, but it's still there. So we have to really run fast in order to stand still. And that's why the infill drilling program that I just spoke of is so important, and we have fantastic economics on these infill wells that is now being contemplated. And when it comes to gas sourcing, yes, the refinery has shown an astounding level of flexibility to adjust to market. We work really as one team within the company between the refinery and the energy management team to see what is it that creates the most value for the company, successful switching into naphtha during the second quarter and very high operational availability of the facility. What I perhaps was most impressed with and satisfied with was that we had such a high availability of the refinery during the second quarter, which, of course, was very nicely timed versus also fantastic refining margins. And that's one of the key reasons why the refinery contributed in such a good way in the second quarter and continue to do so as we speak. Thank you.

This is Sasikanth Chilukuru from Morgan Stanley.

The next question comes from the line of Sasikanth Chilukuru from Morgan Stanley.

Can you hear me? This is Sasikanth from Morgan Stanley.

We can hear you perfectly.

Yes. Great. I had 2, please, both on the refining side. The first was on throughput. Last quarter -- during last quarter's earnings call, it was highlighted that securing VGO supplies remain the risk to refinery throughput. But today, it appears that this risk is largely minimized. I was just wondering, what were the actions taken? And also if you could comment on the impact of securing these new sources of VGO, what the impact was on refining margins. And also if you could comment on the sustainability on securing these VGO supplies from these new sources. Is that sustainable over the period as well? The second question was also kind of related to this, mostly on the refining margins. You have laid out reference conditions of $15 per BOE, Galp refining margin for the second half. And -- but lately, we've been seeing benchmark refining margins decrease quite materially, although they're from record high levels. Just wondering if you could possibly give some details on how you're currently -- or how you see the refining market evolve in the second half and what level of refining margins you're currently witnessing.

Okay. Thank you very much, Sasi. So yes, VGO sourcing, we have managed to secure all the cargoes of VGO that we needed to keep the refinery at full throughput. I have to say that some of those are secured just weeks before you need them. So it's an active work of our energy management. We're sourcing them from Europe. We're sourcing some from the Middle East. Now those cargoes have been sold at quite a high margin themselves. So we always have to check whether there's actually positive economics in buying them. And over time, that looks attractive and sometimes it looks marginal, but all of these have been positive in terms of our overall financial delivery. We will continue to do that. And our refinery margins are much lower, I think around $10 per barrel per day. Particularly, they were much higher the earlier part of July, but we are seeing some softness. So July kind of to date, I think we're looking at about $17. Now going forward, clearly, we haven't got a crystal ball. I don't know if you have, Thore, you want to say a few words. But at the moment, it's hard to tell how the market is responding. We're getting -- we're in the driving season now. We'll see how the volumes are affected and how stocks are affected vis-à-vis an economic downturn. But clearly, the situation is with weaker refinery margins than we had previously. I don't know, do you want to add anything, Thore?

No, I think you have basically captured it. It is just volatile. Actually, the cracks this morning was expanding again actually. So the market is just volatile. What we do is really just make sure that we are really optimizing the runs on a daily basis, making sure that the refinery runs through the highest possible availability so that we can maximize what the market has. But for sure, we don't have a crystal ball, and let's see where the margins are going to -- pans out by the end of this year. But right now, still quite good margins, at least when you see it in a historic perspective.

The next question comes from the line of Joshua Stone from Barclays.

Two questions, please. First, if I just come back to the Titan acquisition and the decision to fully consolidate. Is this a change in the approach of Galp in renewables? In particular, how should we think about the ownership structure going forward in renewables? And is the intention to still reduce your stake over time? And if so, over what time frame do you think it's likely? And then a second question on Brazil. There was an EUR 85 million write-off on exploration assets. Maybe if you could just provide a little bit more detail about what those were. And what else is left in that portfolio that could be impaired?

All right, Josh. Well, I think the first thing I'd say, look, our strategy hasn't changed. We have taken 100% control of this asset. It is delivering significant cash flows at the moment. It is a position clearly that we're enjoying. There's some additional debt that appears on our balance sheet, some EUR 220 million. Now going forward, I think as Georgios has outlined, we have a lot of flexibility, and that may include asset rotations, may, in turn, include deconsolidation again. But at this stage, I think we are not giving any clear guidance on that. And I think when we come back to the market, we'll create some clarity. What I can say is that we, in control of this asset, have a lot more flexibility to actually unlock value for the shareholders. And in due course, we'll see which levers, whether they're rotation, energy management, hybridization, of those, we will pull to extract even more value from those assets. I'm going to hand over to Filipe to talk about the Uirapuru impairment. Are you going to do it, Filipe? No, Thore is going to do it. Thore, talk about the Uirapuru impairment.

Okay. So we have not made commercial discovery in Uirapuru. That is the reason why we then decided to make the impairment in this quarter. There are still prospects in that license that we would like to explore. We have not aligned in the partnership when the next step will be, but we do see structures that could potentially be interesting. The current plan is, therefore, to do that ADR in Bacalhau North first. That will enrich our understanding of the northern part of Bacalhau. And the northern -- or the next-door neighbor to the northern part of Bacalhau is actually the Uirapuru license. So that is why we take it in sort of a step-by-step approach, first, figuring out Bacalhau North, and then the partnership will decide what will be the next step for Uirapuru and its license. Thank you.

The next question comes from the line of Henri Patricot from UBS.

One on the downstream and then one on CapEx. On the downstream, follow-up on previous question around refining margins. Can you perhaps comment on what you're seeing on demand in your own retail network? Are you seeing much of an impact from higher prices or not so much from the time being? And secondly, just on CapEx, the guidance for the full year, no change to EUR 1 billion despite the acquisition. Can you talk about some of the moving parts offsetting the acquisition there?

So I'm going to first ask Teresa to talk a bit about what we see in the oil demand side. I think one thing to say is that with year-on-year, I think we were 22% up, but we're still a bit shy of 2019. Teresa, give a bit of color on what we see in the demand side of the business.

Yes, we definitely see -- and thanks for the question. We definitely see an increase, an overall increase in demand versus last year. And that is coming mostly from the B2B segment, aviation with very, very high volumes and marine bunkering also with very high volumes. On the retail side, we do observe a slightly different picture. So volumes are not picking up as much as in the B2B segment. Still, we see improvements coming. And it depends if -- geography by geography, what we see improvements coming.

So I'm going to ask Filipe to talk a bit about the CapEx. I think we spent EUR 365 million in the first half, but EUR 1 billion for the year, we think. Filipe?

No change in guidance despite bringing the whole of Titan on board. And the reason is we were not planning on having project finance on our CapEx in Titan this year anyway. So the only difference is the 25% share goes up. But we have other areas of Galp where we're having timing, phasing of payments will likely move to the right. So this gives us cushion to absorb the original guidance of EUR 1 billion. Thank you.

Our next question comes from the line of Giacomo Romeo from Jefferies.

Yes. Two questions for me. The first one is there have been some headlines regarding a potential for windfall tax in Brazil. Just wanting to get sort of your view on the likelihood of something happening before elections and how do you think this could shape. Second question is about Coral FLNG. You said you expected first cargo in Q4. Just wanted to have a view -- your latest view on the time line to get to capacity level of liquefaction there. And when do you expect this to happen? And finally, if I may add -- squeeze a third one, is -- just wondering if you can quantify the impact from your discount offering on retail customers and whether -- until when you expect this to continue.

Thanks. On the windfall tax, I think clearly, it's something that's talked a lot, and there have been word discussions actually earlier on this year in Brazil, and those draft legislations were never put through. So we, at this stage, we can never say never, but it's now only a few months of the elections. We're not expecting that to pass through Congress. Clearly, we're going to keep an eye on that going forward. But obviously, as we make more money in Brazil, taxes go up. Our taxes have doubled as well as our revenue to the upstream business. It's probably good for Thore -- obviously, we're not the operator. I have to say Eni is doing a fabulous job on Coral. Some of the Galp employees are also working hand in hand with Eni. But -- so Thore, do you want to give a little bit about where we are and what we can say about the progress, but it has been impressive, yes?

Correct, Andy. And really, remember, this -- we FID-ed this in 2017. First gas came into the facility on the 18th of June, virtually exactly 60 months after the FID. Now the commissioning -- final commissioning is going on for the LNG factory. Actually, as we speak, the defrosting has started, which is a very exciting part of the commissioning. But it looks still good. And that's why we expect first cargoes in -- latest by the fourth quarter. We expect to be at plateau during the course of next year so -- if this ramp-up now go according to plan. So still very, very healthy and a very robust project in this market environment, very well.

Teresa, you're going to say something about discounts. I think I have to stress, this is for our loyalty customers. This isn't a general discount across all our forecourts. But Teresa?

Yes, sure. Given the highly pressured current price environment, it is important that we support our clients and alleviate some of the strain that has been put upon them by a very volatile context. And as such, we have indeed launched some campaigns within our loyalty programs, namely with our key retail partners, Sonae in Portugal, and this offers a top-up of discounts of EUR 0.04. So it goes into the EUR 0.14 per liter, which is a very good value proposition for our customers. In Spain, we're also launching summer discount promotions, aiming at acquiring new customers and also activate and retain existing clients during the summer. These discounts can add up to EUR 0.25 per liter. So just one final note that the B2B recovery more than compensates in terms of the margin that we're generating in the business.

The next question comes from the line of Raphaël DuBois from Societe Generale.

The first one is about Sao Tome and Principe. I understand you're still analyzing the results of the drilling, but is there any chance you could already share with us some of what you already know? I guess if you encounter hydrocarbons, you should at least already know that. So that would be my first question. And then on the dividends to noncontrolling interests, I note that it dropped from EUR 110 million to just EUR 1 million in Q2. Can you also maybe give us some idea of what it could look like for the next few quarters? Is this -- is the drop in Q2, is this something that was planned? Is this due to a special schedule of payment to Sinopec? Or is this because of the Bacalhau spending?

Okay. Can I ask Thore to talk about Sao Tome?

Yes, Andy. Thank you, Raphaël. So the rig is still on location in Sao Tome. So we are finishing now a very comprehensive data acquisition program that we've had there. And what I can tell you is that, yes, we are analyzing the data. And I will not conclude anything or communicate anything before we have done a really proper and thorough job there and aligned in the partnership in the -- this is, of course, very exciting. It is completely frontier area. So we need also to be very careful to make sure that we spend enough time so we really also understand what we have acquired. But I can tell you, we have had a big acquisition of data that has been acquired and which we know we'll use some time to analyze. Thank you.

Thanks, Thore. And perhaps I'm going to ask Filipe to give a bit of a color to the dividends to our minorities, particularly Sinopec through the year.

Yes. Raphaël, I would not read much into the timing. So we usually pay in Q1 and then later in the year, we see how the year is going in Brazil, and we adjust the dividend. So we had budgeted some EUR 200 million for 2022 of payments to Sinopec. Given the macro, this could go up, but it was never meant to be done in Q2. So it could be Q3, Q4, to be decided. Thank you.

The next question comes from the line of Pedro António Alves from CaixaBank.

The first one, on upstream. We have seen some players closing or at least analyzing disposals in their upstream businesses. So would you consider crystallizing value at this point of the cycle? Because portfolio management in upstream was something that you have flagged in your Capital Markets Day 1 year ago, and the price or the valuation context is perhaps more appealing now. So your thoughts on this topic would be helpful. And then the second question regards working capital evolution for the full year. Given your commodity price scenario, what is your base case for working capital?

Thank you, Pedro. So you'll excuse me not to say too much about upstream disposals. Clearly, we have guided that it's something that we will continue to look at. And so I think that's all we want to say at this stage about that. When it comes to working capital, I think as you've seen in our numbers, there was a working capital build of EUR 1.1 billion, just really from our stock and inventory position this year. Clearly, you take that away from our net debt, then you're getting even better numbers. But Filipe, what do we assume in terms of the end of the year? Any working capital release? This is in addition to the EUR 630 million we have on margin accounts. So we can expect quite a lot of working capital to come back certainly versus the end of Q2.

We do, Pedro. So we have 2 components. You have the margin account related to the hedges, EUR 630 million, June 30. This should tend to 0 by year-end. And then you have the fundamental working capital that is client receivables and inventories, and this is highly dependent on Brent prices. So if Brent prices correct downwards, we should see a meaningful adjustment downwards of our working capital balances on top of the margin account releases. Thank you.

And the next question comes from the line of Alejandro Demichelis from Nau Securities.

Just one very quick question. Could you please update us on how you're seeing the development of the Bacalhau FPSO in terms of timing and also in terms of the costs?

Thank you, Alejandro. Thore, this is one for you, I think.

Thank you, Andy, and thank you, Alejandro. So the project is going quite well. The major construction is taking place in China. We have had some issues -- the project is going quite well. The major construction is taking place in China. We have had some issues in China with respect to COVID and the very strict closedowns that has been put in place from time to time. So there is a slight delay. Still, the latest forecast is that we will still see first oil in 2024. So overall, quite good. And on the cost side, there is good control. The major cost positions has been -- is a lump sum contract. So at least for the time being, there is good control on the cost side in the project. Thank you.

And just as a quick follow-up from what you're saying, then we should expect kind of late 2024. Is that what you're saying?

So what we have said is the second half of 2024, and that's what you should continue to expect. Thank you.

The next question comes from the line of Matt Lofting from JPMorgan.

Two quick ones, if I could, please. First on hedging, businesses effectively giving up some of its strong leverage to higher oil and refining at the moment through the hedging positions that are on, particularly given the clear potential to deleverage the business under prevailing macro conditions. Could you just talk a bit about the philosophy around hedging here and triggers and whether investors should expect further opportunistic hedging mechanisms to be entered into 2023 and beyond? And then second, if I could just sort of come back on the distribution policy and just clarify there. I think you were in the context talking about the working cap and margin releases earlier, the potential for in the region of sort of EUR 500 million of buybacks for calendar year '23. I think Filipe mentioned earlier that sort of derived primarily from the underlying OCF generation rather than headline CFFO, inclusive of those effects, if I understand correctly.

Thank you, Matt. And look, I'm going to ask Filipe to say a little bit about hedging strategy and what to expect for 2023 on. On the distributions and working capital, I just thought so he might talk about that, but I just want to stress, we did move from a working capital, 1/3 of CFFO to 1/3 of OCF basically because we wanted to take the big swings of working capital out of that distribution framework. But Filipe, a bit on hedging and what to expect going forward.

So given the extraordinary volatility that we've seen in 2022, really unprecedented, yes, we did have a lot of hedging noise in our numbers. So the one thing that we will do differently going forward is that we'll be using options and not swaps so that we would be -- if we take a decision -- and you asked about the philosophy behind this. So if we take a decision sometime in the future to protect some of the downside on Brent, which is really what moves the needle at Galp, then it would be done through options. So we would invest in premiums, and we protect the downside without giving up any of the upside. Thank you.

And the question comes from the line of Ignacio Doménech from JB Capital.

My first question is on the refining cash costs during the second quarter. We saw refining cash costs going down on the insurance receivable, but at the same time for FY '22, you are guiding towards $2 per barrel, which would imply a significant increase during the second half. So if you could provide us some light here. And then on -- my second question is on Namibia. It's exciting to see Galp going forward with the exploration campaign there. So it would be interesting if you could let us or give us an idea of what we should expect -- we should expect Galp to lead the exploration from an operator's perspective. Or is Galp looking to farm down a stake in the 2 license or 2 blocks in Namibia.

Thank you, Ignacio. So I'm going to ask Filipe, actually, to tell us a little bit about the refinery cash costs and what this insurance receivable was. And then I'll ask Thore to talk a bit about Namibia and the exploration prospect there.

Yes, that's right. You recall, we did have an incident in the refinery late last year. So the OpEx this quarter looks artificially low because there is EUR 10 million, EUR 15 million of insurance collection. We continue to guide to $2 per barrel as recurring fundamental OpEx. Thank you.

And Ignacio, what I can tell you regarding Namibia is that we really like our zip code in Namibia. I think we have a good address, good location. Actually, the Galp team has been quite persistent in Namibia. We have been there since 2014, and we have drilled 3 dry wells in Namibia. But I think we, through those 3 dry wells, learn something about where there could be an additional potential. So quite excited. Next step for us now is to derisk this further, and that would be by drilling a well. So our target is to drill an exploration well there during 2023 or 2024. That's really where we're going to focus right now.

Our next question comes from the line of Jason Kenney from Santander. The next question comes from the line of Mehdi Ennebati from Bank of America.

Just yesterday, I was reading that there were some issues regarding the pipeline connecting Algeria to Spain. And I wanted to know if you observe some gas sourcing issue today because of that. And what are the measures that you could take if this last for quite some time?

At the moment, we -- there's nothing to report there, Mehdi, from our side in terms of gas sourcing through from Algeria. Of course, the line for Morocco into Spain is actually -- has not been flowing at all since earlier this year. But we haven't got any notification of an issue with gas supplies from Algeria.

All right. Okay. I think it was an operational issue at some compressor units in Spain, but all right, no worries, maybe it's not that important.

And the last question comes from the line of Raphaël DuBois from Societe General.

Two quick follow-ups. I noticed that you've received EUR 9 million of dividends from associates in Q2. Could you please confirm that it's coming from the solar JV maybe? And also on the buyback, what sort of visibility do you have on who participates? When could we know whether Amorim Energia is participating?

Raphaël, I'm going to ask Filipe to answer both of these questions.

Yes, Raphaël, so we have the Titan dividend payments. We also have a bit of our Brazilian JV related to biofuels that is also paying dividends. On the buyback, we have no visibility nor do we seek to have any visibility. So we have contracted the bank to do this for us. They don't -- so they intervene in the market without actively seeking specific sources of shares or price influence. So we have no visibility from any shareholder on who is selling and what their intentions are. Thank you.

So I think this was the last question. So thank you all for participating on the Q&A session. We hope it was a useful one for you -- all of you. Do reach out to our IR team if there are some additional clarification needed from our side. So to conclude, I would just like to wish you all the best for the rest of the earnings season and hope it is followed by a great summer holiday. Hope to see you all in person after the break.

That does conclude the conference for today. Thank you for participating. You may all disconnect. Have a nice day.