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

Thank you, Sharon. Hello, everyone and thank you for joining us today on the analyst Q&A session related to Galp's third quarter and nine months 2022 results. As usual, we released the results materials early this morning, including a management presentation video highlighting the key achievements during the quarter and covering the financial results. Therefore, we will start with some words from Andy, our CEO and then go straight to Q&A. As in previous occasions, we will have Andy, Filipe, Teresa, Georgios and Thore at the call. So the full executive team here available to take your questions. If you want to participate, please follow the operator's instructions at the end of the call. Also, as usual, I would like to remind you all that we will be making forward-looking statements that refer to our estimates. Actual results may differ due to factors included in the cautionary statement presented at the beginning of the presentation that we released this morning which we advise you to read. Andrew? Do you want to say a few words before we start the Q&A?

Yes, please Otelo. And so before we start, I'd just like to say a few words about my decision to step down at the end of my mandate at the end of this year. Two years ago, I received a challenge, a challenge to transform Galp to change its portfolio to embrace the energy transition, to professionalize the operations, to improve an external image and to adapt to the internal leadership style. I was asked to complete the 2 years of Carlos Gomes da Silva's mandate to end 2022. I came out of retirement resigning my Board and advisory roles in order to avoid conflict. Over these 2 years, we have expanded our renewables position doubling our portfolio and our equity generation capacity. We've launched a whole new hydrogen biofuels business on the verge of world-scale FIDs, withered a joint venture with Northvoltl to enter the battery value chain. We've launched the project to transform Matosinhos refinery to an innovation district. In commercial, we have new businesses e-mobility distributed solar and we're building our convenience retail contribution. In Upstream, we've cemented 25% growth with the Coral start-up and the progression of the Bacalhau project through FID into construction. Meanwhile, we have transformed the focus on operational excellence and safety and are now delivering in line with our plan. What is not so visible is that we've reorganized and recruited the talent needed to take the businesses forward. Many new recruits are taken from the international world. And perhaps most importantly, we've changed the internal leadership culture, empowering staff and holding them accountable in a much more open and dynamic Galp. And whereas for many of you, 2 years appears very short and there's still a lot of work to do. The changes are deep-rooted and hardwired. And going forward in 2023, without the Galp root of hedges committed in 2020, Galp can go forward from strength to strength and reap the benefits of this transformation. Galp has extraordinary people and world-class assets. It’s been a pleasure to lead Galp and I will continue to the end of the year. I wish the new Chief Executive Officer, every success in taking the company forward next year. Thank you.

Thank you Andy. Sharon, can we start the Q&A session, please?

[Operator Instructions] And now we will take a question. Your first question comes from the line of Oswald Clint from Bernstein.

Thanks Andy, for the reminder of everything you've executed over this last 2 years and obviously, good luck with what's next. Perhaps a question just on CapEx, please. And really in the content I mean, you've taken up a little bit. I understand the FX, I understand the Titan acquisition but there's a lot of discussion around cost inflation more internationally now going into next year. So I wondered if you could perhaps speak around what you're seeing there with rigs and vessels, subsea, even exploration and perhaps even across into the renewable side of the market? And perhaps how protected you feel you are or Galp will be to those potential inflationary pressures. And then secondly, I wanted to ask about Brazil. I see good, stable oil volumes in the last 9 months relative to last year. So that's good. I was curious around the natural gas realizations now given the increased marketing in Brazilian gas. The realization $55 per barrel in the quarter. I had in my head that there was some cap there for that gas. I thought it was sub-$50. So perhaps you could talk -- remind us perhaps of the pricing formula as it relates to Brazilian natural gas. Thank you.

Thank you, Oswald. So firstly, I think on CapEx, I think the change in guidance on the CapEx is as much about the exchange rate actually between the dollar and the euro. And obviously -- and now we're paying 100% of the Titan portfolio. So that has increased our CapEx guidance. But I'm going to pass the floor to Thore and then to Georgios to talk a little bit about how in upstream and renewables, what we see in the market and how much it actually effects of us, how much is already locked in at a lower price. So, Thore?

Thank you Andy. So when it comes to the major project that Galp has underway right now and in particular, I'm thinking then about Bacalhau, we are largely well protected to the contracts that we already have in place and where we have locked in for a large part, the costs associated with it. So Bacalhau should be overall quite well protected. There are some exposure when the unit comes to Brazil and the scope of work in Brazil. But overall, that product is well protected. What we do, however, see is that the rig market is firming up, new rig contracts will retain higher rig rates. So we see a pressure in that market which, over time, of course, also will have an exposure for Galp and our operation. And we also see that in the other part of the value chain. But in particular, the rig market is now firming up a bit. I'll pass to Georgios.

Thanks, Thore. Thanks, Otelo [ph]. On renewables, we are obviously seeing an increase in CapEx as in many other activities. We have had in the Titan negotiation and the acquisition, we have made an arrangement so that there is a certain part of the civil cost is secured. We are seeing in Brazil, we are seeing an increase in CapEx as we put -- as our projects mature. But we're also seeing in Iberia, in particular, we're seeing a very high, very strong price environment that is more than reflecting these CapEx increases. So we are very comfortable with those levels today.

So, can I -- so just on one point, we are above the guidance of €1 billion net CapEx on a 5-year basis. I think you need to reflect that we haven't had any divestments this year. So in the round, over the years to come, we're expecting divestments that will balance this net CapEx number over. So this isn't a one-off increase in guidance. This is just a reflection, this is a year without divestments. Now on the natural gas realizations, we have actually something like 30 contracts in Brazil. We're selling our gas. We're selling third-party -- other people's gas and we have a number of deals in -- that we're negotiating where we will increase that amount of third-party gas we're selling into the Brazilian market. The prices are based on Henry Hub and Brent and different indexes for different contracts at different forms. So there was no hard ceiling at $50 a barrel. So 55%, I think, was the realization for this quarter, it was a little bit up from previously. But what is it, 5x more than we had last year? So clearly, this is a significant cash flow for us.

We will now go to our [indiscernible].

Next question, please.

We will now go to our next question. And your question comes from the line of Biraj Borkhataria from RBC Capital Markets.

The first one is on Nigeria LNG. Looking through your slides, it looks like you’re assuming one missed cargo there. I was wondering if you had any commentary from the operator and the basis of what goes into that assumption. And secondly, as it relates to securing the LNG, I know there’s a lot of LNG weighting off the coast of Spain. But have you had any initial conversations on the availability of cargoes for October and November? And then the second question is on Brazil, looking into 2023. I know ‘22 was a heavy maintenance year. Could you just talk about the 2023 schedule relative to 2022? And so how you can compare and across them help us with our modeling?

Thanks, Biraj. And to you and Oswald, I know I was with you both quite recently. And obviously, I couldn't give you indications of my impending departure. So you might -- apologies for that. Now on Nigeria, so clearly, we -- I think the first thing to say is simply goes to the people that are suffering the floods of Nigeria. Many hundreds have lost their lives. And I think 1 million, 1.5 million displaced people. So this is a real tragedy. Clearly, for us, this is a concern in terms of our own deliveries, force majeure has been called and we've heard that the cargo scheduled for the end of October has some impact on it, whether it's us a delay or cancellation, we're not quite sure. But I have actually invited to this call also Rodrigo Vilanova, who's our Head of Energy Management and he is quite busily buying up some alternative supplies, I think at very reasonable prices. So give us a bit of update about what you're buying, how you're buying it and the thing about the LNG tankers waiting to dock in Iberia. Rodrigo?

Thank you very much Andy and thanks for the question. So as Andy mentioned, we received a notification of first majeure from Nigeria a week ago which is still in effect. The latest update from Nigeria is that one LNG cargo might be impacted at the end of October and they are currently not expecting a further impact in November. For the volumes potentially impacted in October, our gas trading team has already succeeded in acquiring most of the value -- of the volumes, sorry, under natural gas pipeline purchases. And we are seeing currently a limited impact, especially because pipeline gas prices are reduced due to the full inventories that you mentioned. So far, we are expecting 100 LNG cargo impacted late October. And most of the replacement gas has already been procured. Thank you.

Yes. And I think it's -- we're in lower actually than we indicated in the presentation. So I think the impact at this stage and we don't know what the spot prices will do but the spot prices have moderated significantly, obviously which is pursue to us for this mine [ph]. In Brazil next year, this is always a balance between maintenance and natural declines and infill drilling. Sorry, any -- no guidance at this stage, I guess but any indications of how 2023 will pan out.

So what we can say is that we have to expect that maintenance will be kept basically at the same level as it is in -- wherein 2022. We have a backlog to catch up from the time of COVID. So this is well invested time and money in order to make sure that we secure the integrity and long activity of these facilities. So basically expect maintenance activity to be in line with 2022. The final programs aren’t still not firm. So I take a little bit of reservation that it could happen something in the end towards the end of the year but it’s basically the same.

Let me just reflect on -- clearly, having Brazil is declining, obviously, maintenance activity, some infill. But also, we now have Coral that as we say in our presentation, we'll be contributing. It's already contributing some volumes but contributing increasingly through Q4 into next year. So that would -- that's one of the areas where we hope to compensate for some of the natural declines on the field -- for the fields that are producing today. So thank you, Biraj.

We'll go to our next question. And your next question comes from the line of Mehdi Ennebati from Bank of America.

So I will limit to 2 questions, please. First one regarding the Rovuma project. So it clearly became a very strategic project but it also remains super challenging due to the political situation in Mozambique. And I read on the specialized press that there was some news about developing part of Rovuma project with FLNG units. So maybe can you tell us, please, the pros and cons between onshore energy trains and FLNG units, especially regarding the CapEx? Are we talking about much, much higher CapEx if the consortium decides to develop FLNG units, or no? And what could also be, let’s say, the other positive and negative regarding that project? The second question is for you Andy. So you’ve announced that you are leaving the company at the end of your mandate. And I wanted to ask you during those years as Head of -- as Chief Executive Officer of Galp Energia, what has been the most challenging for you as a Chief Executive Officer when it’s running the operations or more the setup of a new strategy for the group? Anything that you would have considered as particularly challenging just for us to better understand the challenges at Galp?

Thank you, Mehdi. Let me say a few words on Rovuma I might ask Thore, if you want to add. Clearly -- well, the partners are discussing the options for Rovuma because clearly, what we've seen is floating LNG is working. It's working well. It's cost-effective on time and on budget. So there is an opportunity clearly. If you wanted to stay well offshore would be to build another or you can get nearer to the coast, you can go modular, you can go small scale or the big scale scheme that we had before. And the partners are looking at all these schemes and I have to say that there's no decision at this stage. But what I think Coral has done, it creates optionality, even in a deteriorated onshore security position, it does clearly show that the asset has significant value even on offshore solutions. That's not to say that's the way we're going but it creates the optionality for that. Thore, do you want to add anything to that? Because I think it's…

So just underlining, first of all, Coral out seems to be really, really well done. It’s on time and it’s below budget and we got first LNG drop in October. We do see that by doing a second one, you can actually optimize and make it even more efficient. So that is a natural that we study. But as Andy said, we have not taken the decision. In my mind, the likely case for will be that you will do in both. You will both -- because the resources are so enormous in Rovuma. We’re talking 85 trillion cubic feet. So a dual development offshore, onshore is most likely the way it will go forward. But the partnership is now starting the solutions and also learning from the very successful modular development that has been achieved in the U.S. which might be applicable also for a situation in Mozambique.

Now the other one, obviously, I've got my team listening to me here. So I think one of the issues has been tackling the legacy issues that the company has faced. And of course, as you all know, we've had problems with the gas derivative hedges. It has meant that every single quarter without some bad news which hasn't been very easy clearly as CEO. So getting through that and seeing ourselves and I think 2023 looks like it's -- we're going to have a much clearer path going forward, particularly in our gas positions. I think the second thing is within the company, driving operational excellence and safety and really getting everyone to understand their role in delivering to the bottom line. And lastly, would be getting our message across to the people of Portugal and to society and that Galp is transitioning. It's seen as a company, I think, in many ways, that is an oil and gas company that is a bit rigid but getting much across, we're much more open. We're much more dynamic and we're much more embracing the energy transition is a story we're still trying to tell and still trying to make sure that everyone understands that we are wanting to be on the right side of history as we go forward as a company.

We'll go to our next question. And your next question comes from the line of Joshua Stone from Barclays Capital.

Two questions, please. First perhaps about the gas business and the restrictions there. Can you just talk about when you’re looking to 2023, the additional flexibility you’ve got to have in, does it come at least from January? Is it the contracts expire in January and for how much volume do you still expect to presell any gas? And when do you expect to get the venture global US LNG in the business as well? I’m just trying to work how protected is this business going to be in 2023, if there are any further restrictions on sourcing? And then secondly, just looking at the -- coming back to the inflation point in Brazil, just looking at the upstream operating costs, they have a tick higher for a few quarters in a row now on a unit basis. Can you maybe just talk about what’s driving that? I presume there’s some decline on the older fields in there and where you think through cycle steady-state unit costs should be now?

Thanks, Josh. So I think the first thing to say is one thing that we've managed to do is to reposition us. So we don't have any hedges for 2023 which means the contracts we have from Algeria and Nigeria will be exposed to hopefully some upside so the gas prices are still solid. We haven't committed too much within the overall energy management and commercial areas for sales for next year. So we retain a buffer because clearly, we've been a little bit bitten by having no flexibility when Nigeria volumes don't appear as they should. So I think one message is we will have flexibility to cover all our commitments. And secondly, we are retaining at this stage what we believe should be a reasonably strong margin for the volumes we have from our legacy contracts. So we go from what is significantly negative. Let's be clear, we're probably €150 million loss in Q3 as a result of the PBB to TTF spread and due to the restrictions in supply. So that's a negative number that will flip in -- from January onwards to a positive contribution. And then, the -- the Venture Global is -- we're hoping to receive it as early as possible next year. There's a long stop date in Q3 but it is now running. So we're looking forward to those supplies which are clearly destination and flexible fixed price contracts which will be extraordinarily accretive once we have those online. So both of those items, I think, will put Galp in a very different position next year when it comes to making money from the gas business rather than losing money in the gas business. And I'm just disappointed I won't be here to enjoy that. Now when it comes to production costs, these are very small numbers, around $3 a barrel. I think we went from slightly below -- slightly above $3. Thore, anything sinister in those numbers?

No. Actually, that's -- for one, it's actually a good cost. It's good cost because actually, they were largely due to the fact that we paid some performance-related bonuses to the operating companies due to better-than-anticipated performance. So that's the main driver of the increased production costs in the year for the quarter. Going forward, we still remain that you can expect that to be below $3 per barrel. It's the guidance that we can give you at this stage.

We will go to our next question. And your next question comes from the line of Henri Patricot from UBS.

Yes, everyone, thank you for the presentation. Give you the best for the future from my side as well. I have two questions on the outlook, please. The first one on the upstream side. If you look at your guidance for the full year, it seems like the fourth quarter take into account the absence of the utilization and the lower oil price but not much for reversal of the lower sales volumes because of the larger number of cargoes in transit in the third quarter. So is that fair that there is no reversal in the end guidance for the full year? Or is there another negative that we should have in mind when you think about the fourth quarter upstream? And then secondly, I just want to get a bit of an update on your thinking on the hedging policy for next year. So we like to see more of the refining upstream volumes due to be hedged over the next few months.

Thanks, Henri. On the upstream guidance, as I say, we're sticking to our guidance of 127,000 barrels a day. We're slightly shy of that at the moment but we're actually -- we're doing well in Q4 and we're maintaining the guidance for the full year. Clearly, we have 3 cargoes in transit. It's more than normal. So some of that money will be coming back to us in the fourth quarter. But those are the only 2 things. I think we talked about $3 billion EBITDA guidance for the full year. I think that assumes something like an $85 going forward or $90 for the second half of the year. Now when it comes to hedging, we -- I said the gas derivative hedges, I say, won't be there. Also, the oil price hedges won't be there. But we will have some legacy refinery hedges. I don't know if Thore want to discuss a little bit about that. Not significant volumes but there will still be some refinery hedges for 2023.

Yes, that's correct Andy. That was put on back in 2021 early. So there's around 7 million barrels that has been hedged on the refinery margin, partly directly refining margin and partly cracks but it's limited to 7 million barrels and we have no further plans of any further hedge at this stage.

So €7 million in -- about €90 million is what that was the run rate that...

Correct.

Yes, so relatively minor.

We'll now go to the next question. And your next question comes from the line of Raphael Dubois from Societe Generale.

Can you hear me?

We can.

Great. The first one is about shareholder distribution. I guess there are always pros and cons on doing more buybacks at a certain point of time, there is certainly some pressure at the moment on all oil and gas companies to maybe refrain from being too generous with shareholders. But in the meantime, at current low share price, very strong balance sheet and strong cash flow generation. I would like to understand why do not you decide to increase the buyback program now and still talk about a €500 million potential buyback for next year. It will look like the best economic decision will be to accelerate it instead of adding opposed. That would be my first question. And the second one is about your pipeline in renewables. It would be great if you could give us an update on those 0.3 gigawatts of projects that are in construction, when will they be in production? And when I look at what's under development, how quickly do you think some of it will be put into the construction phase? Is not the 4G plus target in 2025 at risk, considering we're already at the end of 2022?

Thanks, Raphael. I'm going to hand over in a second to Filipe but I could just say that we clearly have this distribution policy with a dividend growing at 4% and then up to 1/3 of our operational cash flows, then the balance distributed in a buyback if our net debt to EBITDA is below 1, it's now, as you know, 0.6. So we have some scope. The scheme is designed to be flexible based on our OCF and we do live in very volatile times. So Filipe, any news or any update on distribution frameworks?

Yes, Raphael. So whilst it is true that our balance sheet is very strong and we are generating OCF. The formula already provides for that. So 1/3 of OCF if OCF is higher than distributions will be higher through share buybacks. And this comes on top of the 4% increase on the cash dividend. So for now, we're in October. The plan is to -- we'll stick with about 500 of share buybacks related to fiscal year 2022 until further notice. And we will see early next year how 2022 will close and how 2023 will look like. But for now, this is unchanged.

Georgios, can you give us a flavor of how quickly we can see projects coming into the final to ready to build and then meeting our 4-gigawatt target for 2025?

Sure. Thank you Andy. Thanks Raphael for the question. As you said, we have 1.3 in operation now and 300 in construction. We expect 100 of those to be delivered in operation by the end of this year. The other 200 if their online date is expected sometime in the second half. We have a very -- our pipeline in the meantime is maturing. And we have -- we expect in the next 6 months to have about a gigawatt of new capacity and ready to build. So we will be ramping up considerably in start of construction in the next year and we will be seeing much higher CODs, obviously, based on our decision of how many to deploy but we will be seeing much higher numbers of CODs in 2024 onwards.

And your next question comes from the line of Pedro Alves from CaixaBank BPI.

Just two. The first one regarding the decision of the Portuguese government to allow the temporary shift of clients in the gas market from the liberalized to the regulated tariffs. How do you see until the end of the year and perhaps even for the next year, the number of clients moving to the regulated market because I think there were some delays in having this decision. And what could be the financial impact for you? And the second question, I think you mentioned potential divestments to over the coming years to offset also some of the CapEx inflation. And I know that you have touched this on your Capital Markets Day and you mentioned the potential portfolio management in upstream and sell-downs in renewables. But could you just give us additional color on how do you see this going on, especially with this new cost of capital environment?

Thank you, Pedro. So yes, clearly, for us, this regulated market move was very unexpected. It wasn’t in line with previous indications from government and from the European Union. It means that we’re actually having to deliver gas to the regulated market at a price that we don’t have the supplies for that because of our hedges. But I think we’ve seen about 90,000 of the 1.5 million customers move across. And we’ve seen, clearly, spot prices go down a lot. So the impact is not significant. I think the move in many ways, we don’t think is appropriate from the government side to regulate the market and to apply just to deliver at a certain price of gas we don’t have. But the cost at this stage, I would say, is not as high as we was concerned it could be. Now, what happens next year? Clearly, we -- I just need to note that both in Nigeria, there may well be a price review which may mean that the price passed on to the regulated customer will go up. So that’s part of a discussion we have with Nigeria LNG at the moment. So we reserve our position with the government on this particular move and we have to see what’s going to have to transpire next year. But for 2022, it is because of the low -- relatively low number of clients, perhaps nervous that the price will go up on January 1 anyway, have not moved across. Now in terms of divestments, you will probably appreciate it’s very difficult for me to say anything about divestments. I have to say we continue to actively look at our portfolio, not just in upstream but I’d say, renewables in other as of our business and we have no announcement at this stage on those divestments but I just need to note that we haven’t changed our guidance on a net CapEx basis of €0.8 billion to €1 billion of net CapEx per year. So in the round, clearly, there will be divestments at some stage in the coming years.

We'll go to our next question. And your next question comes from the line of Giacomo Romeo from Jefferies.

The best of luck with your future endeavors. But on the change in I, just wondering whether you have been involved in some capacity in terms of selecting your successor? And if you can give a sense of the search parameters that the board has. And if the mandate will be a one-off continuity, it sounds like this is the case but it would be helpful to have some color around this. The other question is I have that is remaining. It’s about your OCF EBITDA guidance and which for upstream which remains unchanged. And obviously, your operational guidance is also unchanged, production, operational costs and you said $90 to wage [ph] which was the same as we had last quarter. But at the same time, obviously, there is an FX effect which that you have discussed for net CapEx. So just wondering why the upstream EBITDA guidance hasn’t changed on the back of the FX that has impacted CapEx? Just very more of a maintenance question. That’s the one I’ve got left.

Yes, Giacomo, if you will -- excuse me, I don't really want to divulge or go into details around individuals and succession. And at this stage, I have to say there is no change to the strategy. I have to say that the transformation we're on and the strategy that the Board has embraced with me as CEO remains unchanged. So clearly, I think successor would be someone able to take that journey forward and continue with the transformation of Galp and particularly the transformation of the portfolio and the way we lead our organization internally. On the EBITDA OCF guidance, Filipe, anything to add on?

No. Giac, you make a good point. I think we’ve built a bit of cushion in our guidance. I know we’ve -- I want to make sure we don’t miss our expectations again. So it will depend on a number of cargoes in transit as of December 31st on the dollar. But yes, this could be -- this is a conservative guidance on the upstream front.

We’ll go to our next question. And your next question comes from the line of Matt Lofting from JPMorgan.

Two, if I could, please. First, just coming back to Gas & Power. I think Andy, you had talked about some of the key steps or bridging points to think about for ‘23 versus ‘22 earlier. I wonder if you could just talk a bit behind that around latest company thinking on diversification of supply from the perspective that in some ways even before Nigeria more recently in the last 6 to 12 months has arguably been characterized in the business by challenges around gas sourcing in a market that globally that potentially stays tight for a period of time and also given Galp’s relatively modest upstream equity gas position, I wonder if the venture global volumes that come in next year is enough or whether from a risk management perspective, there’s planning and a scenario around ways that position could be further diversified through the medium term? And then secondly, just coming back to the upstream and the point around the cargoes in transient, I understood that in transit is high versus the normal one to two. Just wondered if you could give us a sense of the standard deviation or range around that historically, the extent to which three is an abnormal quarter or something that we could see reoccur looking into next year and beyond?

Thank you, Matt. So look, diversification of gas on [indiscernible]. Clearly, that's something we do discuss. The Venture Global clearly adds another string to our bow which particularly with destination flexibility, with a fixed price, Henry Hub linked. It does diversify not only the sources but also the pricing basis of our cargoes. And we will continue to look forward at how that develops over time. As you say, we clearly need to look very much into the long term, meeting our customers' needs, particularly in Iberia. But I might say that we're also not linked into fixed sales volume within Iberia. We can flex how much we're selling in this market at the same time. The one lesson learned going forward is not to box ourselves in too much the situation we found this year. So I do think we're going to be in a better place but we are going to keep a very careful eye at diversification of sources and pricing basis. I don't know if we can say much about the cargoes 3 is more than normal. So much more than normal. I think it -- I don't know if you can say, Thore, this would be as high as it ever get to but it's normally 1 or 2 of the most, isn't it? How do you see it?

No, I say exactly Andy. And thank you, Matt, for the question. On average, what we have seen is that it is between 1 and 2 cargoes. This is, of course, very dependent on exactly what happens at the end of the quarter. So it’s a bit passed as well. But I think for planning purposes, for your estimation purposes, you just 1 to 2 cargoes, that’s what you can do.

We'll take our next question. And our next question comes from the line of Jason Kenney from Santander.

I’m going to go back to the share buyback. Just a point of clarification, I suppose, €150 million this year, €500 million for the calendar year 2022. Does that mean you do €350 million in the first part of next year? Just an idea of phasing of the balance to €500 million would be useful. And then secondly, on exploration, obviously, some disappointment with [indiscernible]. Any lessons learned from [indiscernible]? And then maybe more broadly on exploration, you’ve still got Namibia second half of next year but would that be a last traditional effort on new resource because my understanding was no new exploration out of -- outside of current licenses on a medium-term basis. So I’m assuming that’s going to be your last well next year.

Okay. Jason, so a couple of points. So on the buyback, so €150 million this year is going to be for -- basically for 2021 reward for the shareholders in 2022. €500 million is extra but it will be bought back over next year on a smooth basis. We want to avoid any market abuse issues in terms of making sure that we buy those back in a very steady way across the year. On exploration, I have to say [indiscernible] was actually quite exciting. And we saw some very interesting things in this well. No commercial discovery. It's what you call an exploration success, I guess, not a commercial success. And just -- I'm going to hand over to Thore, just say something about -- we have said we are not going to pursue new areas, new licenses for frontier exploration. That doesn't mean to say that in the blocks and the areas we have now that we'll fully appraise and develop what we discover which is true in [indiscernible] and it's true in Namibia. I think what we're saying at the moment, we're not actively looking to buy into new upcoming frontier areas as we focus our attention more now to the energy transition. So Thore, do you want to say something about our position [indiscernible] or the blocks we've got and what we can imagine going forward?

So thank you, Jason. And it's a relevant question on the exploration side. Actually, I would like to start in Namibia. Remember, what is our story in the Namibia is that we participated in for dry wells. But we learned so much from those 4 wells that we decided to hang in Namibia even though it looked very bleak and it was difficult to see the opportunities. But we knew that we had the factors. We saw a working petroleum system in one well. We saw that we had the reservoir conditions in another well. It was all about and what exploration is a lot about is to get the most sakes to fit together. And thank God, I would say that we chose to hang in, in Namibia and we are going to have a very interesting exploration phase coming up in Namibia. When it comes to [indiscernible]. As actually Andy said, yes, it was not commercial but we actually found the working petroleum system. And that is a very important achievement. So we know that there is a source flock that is working in [indiscernible]. We actually found higher open that well, also very interesting reservoir conditions. And Galp has positions in 3 blocks [indiscernible] with quite significant ownership share. So we do actually see that we have a very interesting exploration portfolio [indiscernible]. And what we're doing right now is then to analyze all the data, including that we have, as we speak, fluid samples that are in the lab and how we are interpreting them and then we will sit down with our partners and agree and what will then be the go-forward program, both with respect to further exploration and possible appraisal. So [indiscernible] remains a very interesting area for Galp to further export. But what we will not do and what is not in our plan is then to go further and beyond to look for new frontier exploration. Our focus then will be infrastructure-led exploration, i.e., exploration around our existing assets to see how can we maximize the value of these assets and smooth in the plateau phase. That would be our focus going forward beyond [indiscernible] and Namibia.

We will go to your next question. And your next question comes from the line of Pablo Cuadrado from Kepler.

Yes, two quick questions. The first one is on the outlook on the refining margin for Q4 is actually more a clarification. I was wondering that the $15 per barrel that you mentioned as a guidance, is that reference assumes, let's say, the new methodology of calculation or if it refers to the old one? And the second question will be on volume the renewable segment. Now that you have the time consolidated clearly, you have gained full exposure to that asset and clearly, it's a new business line for the future. And clearly, the current environment with increasing gas prices, marginal technologies cash in Europe, so price has been very high. But the question is more strategic provided going forward. If you think you are comfortable now having that consolidated 100% to maintain everything on merchant? Or if you have started to consider probably to move to a more PPI framework? Or if you think that you are finding right now with the current capacity, maybe on merchant and providing focus on PPA just on the future commissioning of assets?

Okay. So let’s start with the refinery margin. So I’ll hand over to Thore to talk a bit about the guidance and where we are with the new way of calculating that.

So it's correct. And thank you, Pablo. It's correct that the guidance that we're giving you are including the fact that we are basing the refining margin on the spot gas prices, PVB. And actually, month to date, we see very healthy significantly, actually, even above 15%. Let's see how that develops during the quarter. But right now, the margin stays very healthy with very strong diesel cracks and actually quite reasonable jet cracks as well. So for now, it's good. And our guidance is based on the new gas spot assumptions, yes.

So I’ll say a few words on Titan consolidation. And we are on the merchant market. As I think we’ve reflected, we had all these assets in consolidated form for the last 12 months, it would generate €240 million EBITDA on about €1 billion of investment. So this is obviously a very good portfolio for us, particularly on a consolidated basis. And so at the moment, that’s where we have that position. What we want to say is we remain flexible. We remain flexible to get the most return for shareholders. And having an on the merchant today is certainly the most attractive way for us to do that. But I don’t know if Filipe or Georgios, you want to say any more words than we remain flexible. And at the right moment, we may need to lock in some long-term contracts. But at this stage, we are very much enjoying that merchant position.

Galp is an integrated player. So we are a keen off-taker of those electrons. Could we consider internal PPAs? We could. We could do that. One of the topics for next year will be, can we maximize project funding if we have PPAs even if internal. Can we get much longer maturities at very competitive terms, yes, we could do that. We need to keep -- and be very mindful of regulation. It's not indifferent and taxation but it is not obvious why a company -- an integrated company like Galp would sign offtake agreements with third parties. So most likely, we would do it internally. Now if we also want to rotate some assets, if we want to do dividend recaps which would reduce the CapEx, so we had -- in our CapEx guidance, if you recall, we had not only asset rotation, we also had dividend recap. So we can do that to also reduce how much of the Galp shareholder stands behind those assets.

We'll go to our next question. And your next question comes from the line of Alessandro Pozzi from Mediobanca.

Just wanted to talk about maybe the commercial. You alluded to the weakness potentially in the gas and electricity market with sales down in Q3. I was wondering if you can give us maybe a same of the impact that had on your EBITDA? And also, I guess, whether there is risk for clients not paying and therefore, maybe it’s a good time to increase the provisions against that risk? And also on the second question on the Energy Management, I believe you mentioned you’re not hedging anymore, I’m not sure if I got it right but I guess that’s a margin business in a way. So I was wondering, if a certain level of hedges will be in place for that business line. So I was wondering if you can give us a sense of that as well.

So I think Tere probably wanted you to talk about the oil market where we're 12% up year-on-year. But you've asked about the gas and power market which is, as you might imagine, is quite tough at the moment. So Tere, what can we say about that? And any provisions?

Well, it's true that the sales of natural gas and power are down quarter-on-quarter, partly because of seasonality, of course but also because of some reduction in demand observed given the high prices. There's no -- the impact on EBITDA is small. As you know, this business line is small in terms of the overall commercial EBITDA. What we expect in Q4 is actually some increase in volumes, volumes picking up also because of seasonality. We are working with our clients and trying to recover part of the demand that is being taken away by the high prices. But overall, we expect the situation to improve in Q4.

Good. Thank you, Tere. So look, it is a margin business on the gas business. Clearly, we will be -- if you look at the Venture Global volume, we’re potentially looking at placing some of the volume on a medium-term basis at a price where, clearly, we would lock in a margin. So we are looking at those ways to secure the upside. Now clearly, there will be a moment where we see the actual market prices and the price of our supply contracts closing and which team we may want to take some limited hedges and very much on the principle of hedging. It’s when the value we can create is small versus the exposure we take. And as long as the value is high and the exposure is relatively small, then we won’t hedge. The second, we see those things reversing somewhat we will consider taking out hedges but only on a basis, clearly, where we can retain flexibility going forward.

We will now take our final question. And the final question comes from the line of Mehdi Ennebati from Bank of America.

Just a follow-up question regarding the refining margin for 2023. So you said earlier that you hedged 7 million barrels in 2023 out of 90 million barrels, let’s say, of throughput. Can you please tell us at what refining margin level you hedged, please? And second, did you hedge for a quarter in particular, Q1 2023, for example? Or did you hedge 8%, 9% of your throughput in Q1, Q2, Q3 and Q4 2023?

Committees [ph], yes, 7 million out of 90 million, so were less than 10%. What I can say is smeared across the whole year, so it's not on any specific quarter. I don't think we have at hand exactly the price of that hedge that we can reveal to you, Mehdi. We can follow up through our IR team and give you some indications on that. Okay. I just wanted to -- I think that was the last question. Before we formally close, can I just thank you all because I knew most of you in my Shell career and I’ve known most of you in my Galp period and I found you all extraordinarily professional and supportive of everything we do. And I just want to thank you for your professionalism and your engagement and your willingness to understand our business and the direction we’re going. So, thank you all. You never know, there may be a third time. Let’s see what happens next. All right. Nothing firm. So no speculation, please. All right. So, thank you very much. Operator, you can close the call now. Thank you.

Thank you. This does conclude our conference for today. You may now disconnect.