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

Good morning, ladies and gentlemen. Welcome to Galp's Third Quarter 2021 Results Presentation. I would now pass the floor to Mr. Otelo Ruivo, Head of Investor Relations.

Good morning, and welcome to Galp's Third Quarter in 9 Months 2021 Results Presentation. I would like to thank you for joining us today and wish that you are all in good health. Today, Andy will provide an overview of the quarter performance and key strategic developments as well as an updated guidance for the full year. Filipe will then take us through the quarter financial results. At the end, we are happy to take your questions, where Andy and Filipe will be joined by the remaining members of the Executive Committee. If you want to participate, please follow the operator's instructors at the end of the call. As usual, I would like to remind you that we will be making forward-looking statements that refer to our estimates, and actual results may differ due to factors included in the cautionary statements at the beginning of our presentation, which we advise you to read. I will now hand over to Andy.

Good morning, ladies and gentlemen. Galp's Q3 operational results were robust capturing the improved macro namely higher Brent prices and improved refining margins. We delivered over EUR 600 million of consolidated EBITDA already at pre-COVID levels. On top of this, we now have a renewable business not consolidated, but fully capturing improved market conditions, delivering EUR 28 million of pro-forma EBITDA in the quarter. We also generated a healthy operating cash flow of EUR 468 million, therefore, a robust contribution despite some operational challenges. However, our free cash generation reflected the temporary effect related with our gas hedging strategy and the significant spike in gas prices during the period. Due to this effect, as well as the interim dividend of EUR 200 million paid to shareholders during the period meant our net debt increased to EUR 2 billion. This puts us slightly above our targeted net debt-to-EBITDA ratio of 1. However, we're expecting further deleverage through Q4 and confident that the dividend variable component will be distributed, and I'll cover that again later in this call. In addition to the actual Q3 financial numbers, we also made progress towards executing our strategy to create a more sustainable company. Finally, I'm happy to see the external recognition of our strategy, with Galp recurrently holding leading positions on the relevant ESG rankings. Acknowledged further by the EUR 700 million lending we have secured from EIB. Now let's look at the businesses in more detail. During the period, we have seen some operational improvements in upstream, namely in 2P in Brazil, leading to a stronger oil output, welcome at a time of high oil prices. However, due to some maintenance activities on gas exports, overall oil and gas production was flat quarter-on-quarter. During the quarter, the largest FPSO so far in production in Brazil was started up on the Sepia field, Petrobras' delivery of the FPSO in these difficult times is to be commended. Although a small production contribution took up in the period, the production rate from the 1 well hooked up is prolific, boding well for the full potential of the field. The FPSO and Atapu is also now producing at high levels close to plateau production with only 4 wells connected. The Brazilian pre-salt continues to be an amazing story with new wells demonstrating high productivities and strong reservoir potential. The improved operational conditions allow us to resume some inspection and maintenance activities. And through Q4, we hope to see progress on working through the maintenance backlog. We remain confident on the full year production guidance updated last quarter at 125,000 to 130,000 barrels of oil equivalent per day. Going forward, we expect the business to maintain its strong cash delivery, with disciplined approach to CapEx focused on key attractive low-carbon development such as Bacalhau, a project which continues to progress well. Coral FLNG for Mozambique also progresses well and is on track for first gas during 2022, with sale away from Korea expected during Q4. On the exploration front, we are keenly anticipating key wells in the Campos basin in Brazil and in São Tomé and Príncipe to be spudded later this year and early next year. On the industrial side, refining margins have now recovered from the weak environment throughout 2020 and early 2021. They're up 70% quarter-on-quarter to $4 per barrel supported by an increase of middle distillates and gasoline cracks during the quarter. This refinery margin includes all energy costs such as natural gas and electricity and any CO2 licenses we may need to acquire. On top of this, we're seeing Galp's refining margin October to date at above Q3 levels at around $5 a barrel. However, we need to report that we will see some production limitations during this quarter. As announced a few days ago, there was an unplanned event in one of the 2 furnaces of the Sines atmospheric distillation unit. There were no injuries, but it's led to a temporary stoppage of the unit. However, during the rest of Q4, the throughput of the distillation unit will be restricted while repairs are completed on the impact in furnace. We expect the issue to be fully resolved during this quarter. In addition, we have a planned maintenance in the hydrocracker which will start this week and should last around 20 days. Considering these operational limitations for Q4, we expect throughputs of 15 million tons, about 30% down quarter-on-quarter, while realized refining margin should stand at $4 to $5 a barrel. On Energy Management, this was a weak quarter, impacted firstly, by the extra costs related to the access to the LNG regasification terminal in Portugal. These extra costs are now no longer charged from Q4 onwards. Also, we've been impacted by negative effects by the oil product supply pricing lag resulting from the commodity price increase during the period. But most importantly, by unplanned natural gas sourcing restrictions related to our long-term suppliers, which oblige us to acquire some volumes at expensive spot conditions. All in all energy management contribution was negative in the quarter. And going into Q4 we're setting with our main suppliers any potential deviations from the planned deliveries given the cost of securing alternative supplies. And we're preparing contingency plans to mitigate any potential shortfalls. Clearly, shortfalls could have an impact on our operations and results. And in such cases, we may continue to see some weaknesses on the energy management contribution. Therefore, unfortunately, Q4 for industrial energy management may not be stronger than Q3. Looking further ahead, we should have our Sines refining system operating in normal conditions by the end of this year. And I'm confident on the work we're doing on our gas trading strategy to allow some more flexibility and increased contributions from 2022 onwards. In commercial, mobility in Iberia is recovering with an oil product sales increasing both in B2B and B2C segments, but still some 20% below pre-COVID levels. Our results show this progressive positive trend, where B2C has been recovering faster, but we now also see some positive signs in B2B, but aviation and marine segments do still remain weak. And the same time, we're taking steps to transform this business to adapt to consumer needs. Our efforts to extract more from nonfuel have been proving successful, and our convenience retail is already delivering at pre-COVID levels and today represents over 20% of the commercial contribution margin, which is up 5% on 2019. We're progressively increasing convenience sales and expect convenience contribution to more than double by 2025. In renewables, our production is sold under strop merchant conditions. And our generation capacity could have been higher this quarter. However, 4 plants have been restricted due to an issue with 1 transformer. And we've been implementing mitigations with some of the 200 megawatts of impacted electricity, and we hope to get back to full operation in early 2022. But in addition, we plan to bring online an additional 236 megawatts of solar projects by year-end. Meanwhile, we're executing our strategy and progressing with our renewable expansion inside and outside Iberia. In Q3, we acquired additional solar capacity in Spain of 220 megawatts and last week, we announced an important step in our renewable venture in Brazil, where we acquired 600 megawatts of solar capacity of high-quality projects in a preconstruction stage. The acquisition costs in Brazil were not material. Further payments, however, will be made, but only when the project hits specific development milestones. These projects are expected to be online before 2025. This is a clear step forward for Galp in a country where we've been present for over 20 years. And we've recently reinforced our renewables team in Brazil, a country which offers an opportunity to develop profitable renewable power generation platform, but we will maintain our discipline. Entering in early a preconstruction stage and creating value by building our portfolio from there. Our energy management team will be fundamental to capture market dynamic opportunities, monitoring the market development and evaluating the best way to sell our power generation with a mix of PPAs and merchant exposure. These acquisition positions Galp with a 4.7 gigawatt portfolio with projects both under operation, development and construction. This puts us in a strong position to at least meet our 2025 goal of having over 4 gigawatts operating and well positioned for the 12 gigawatt ambition we have for 2025. Thriving through the energy transition is not just about renewable capacity, but also about developing low carbon businesses and making sure we have access to finance structures that provide us an efficient capital structure to develop these projects. So what are we doing on this front? In early August, we launched a pilot of a new convenience concept store in Portugal with no fuel offering. And in Spain, we've upgraded around 35 stores, which are also showing strong results. We're also proceeding with our electrification plans having acquired in the quarter, 280 EV charging points across Iberia, and we will end the year with over 1,000 points, more than doubling since last year, and step further to reach the company's ambition by 2025. On new energies, green hydrogen plants are becoming real, currently developing a 2-megawatt pilot with FID expected by year-end. This will accelerate our learning curve before the larger capacity electrolyzers get closer to reality. And we're advancing simultaneous with 2 projects of 100 megawatts each. One by ourselves and the other one in a consortium. On another front, we are thrilled to have secured access to funding to our low to no carbon projects, by prestige entity like the European Investment Bank. This includes an up to EUR 750 million to finance solar PV projects in Portugal and Spain as well as the rollout of 550,000 EV charging points across Iberia. We have also secured project finance for 50-megawatt project in Spain, operating in full merchant conditions. All our operating projects in Spain have now been project finance, all with debt levels above 70%. Looking at 2021 overall, considering the status of operations and adjusting to the short-term macro outlook, assuming a $70 Brent for the year, we estimate now full year EBITDA and adjusted operating cash flow to stand above EUR 2.3 billion and EUR 1.8 billion, respectively. While on the operational side, commercial and industrial energy management should stand below the estimates we provided last June on the back of slower anticipated Iberia in demand recovery and restrictions in energy management. But upstream and renewables will benefit from higher oil, gas and power prices. Our CFFO, non-adjusted operating cash flow is predicted to have a EUR 400 million difference to our adjusted operating cash flow. This impact is mostly driven by a hedging strategy to protect the commodities price risk related with our gas sourcing and supply activities. In the recent months, we saw an increase in margin deposits related with future contracts. As a result, of the unexpected significant spike on gas prices. This impact drives mostly from contracts that will end in 2022 when the supplies are delivered to the customers. Therefore, going forward, we will see cash inflows yielding CFFO levels above the OCF, either when we make these gas deliveries or when gas prices adjust downwards. Filipe, he will elaborate a bit more on this later. But let me reinforce despite currently materially impacting our CFFO and net debt. This is a temporary effect, one that will be reverted on the short term during 2022. We are aware this may impact our shareholder distributions framework. We will need to monitor how gas prices evolve and what will the effects on our financials be at year-end. By then, we will take a view of some adjustments to the dividend framework should be considered when proposing our 2021 distributions, given the one-off and temporary nature of this impact. Lastly, on net CapEx, we are now estimating at the year-end to be at the lower half of the previously provided guidance, so to stay within EUR 0.5 billion and EUR 0.6 billion, demonstrating our continued capital discipline. So to wrap up, this quarter benefited from the more supportive macro and we continued seeing positive signs of recovery and a strong commodity price environment ahead. This environment is causing some temporary impacts on our cash delivery. But as I mentioned, these are temporary and will revert. More importantly, looking further ahead, we are starting to show clear and important signs of strategy execution, both around our legacy businesses growth and transformation, but also around expanding our renewables footprint and moving forward of new businesses. Our operational momentum has room for improvement, and I am confident we will see a turnaround allow us to deliver even stronger results. Finally, a relevant part of our investment case is to maintain a competitive shareholder remuneration. We are conscious that our shareholders deserve to be rewarded in such a strong macro environment. Therefore, we are monitoring very closely the evolution of the lines impacting our net debt and CFFO and confident that we will be able to recommend a variable component related with 2021. Now over to you Filipe, to look more deeply at the financials.

Thank you, Andy, and good morning, everyone. I am on Slide 12, where we have the upstream EBITDA of EUR 522 million, which clearly benefited from the rise in Brent prices, even if we did continue to see below average premiums on the cargoes we sold to Asia. And this comes from China restrictions on some local importers and regional crudes being priced more competitively versus Brent. Our oil and gas realizations versus Brent were also affected by the cap we have for now. On our Brazilian associated gas sales. So the current gas price formula is kept at $55 Brent. Upstream CapEx was EUR 187 million, and this went primarily to our pre-salt developments, namely Tupi and Bacalhau and Coral in Mozambique. The CapEx line this quarter also includes EUR 34 million payment for the acquisition of stake in BM-S-8. This increased the Galp stake from 14% to 20% back in 2017. And the payments were contingent on certain milestones and a final one should be distributed in Q4 or early Q1 next year of about $40 million to $50 million. Commercial EBITDA was EUR 87 million in the quarter. Now this with seasonal quarter-on-quarter higher oil product sales and the gradual easing of lockdown measures. Still, commercial EBITDA was down year-on-year as the margin environment is being pressured by the current much higher commodity prices. Industrial and energy management EBITDA was only EUR 15 million. That's down EUR 35 million from the previous quarter. The Sines refinery had a healthy contribution with realized margin of $4 per barrel and cost of $1.5 per barrel. Energy management, however, saw gas sourcing restrictions, leading to spot purchases to comply with our commitments with clients. Also, as we had flagged before, the increased regasification costs in Portugal impacted EBITDA with about EUR 10 million during this quarter. In Oil products, the rapid commodity price increases that we're seeing in the period has caused negative price lag effect under the formulas we have established with our clients. Industrial & Energy Management operating cash flow includes the contribution from associate companies, such as the Galp stakes in the international pipelines, which bring the gas from Algeria through Morocco and Spain. Now after some 25 years invested in those assets, these concessions will end this month. So we will now bring the Algerian gas through the Med gas pipeline where we are not an investor. On renewables, we don't consolidate this business. So what we show here, our pro-forma numbers and the pro-forma EBITDA was a very healthy EUR 28 million in the quarter. Now we do continue to see significant supply chain and permitting challenges to develop and build the renewable projects in Iberia at the speed we wanted to. But we remain committed to deploy the ambitious pipeline of projects and grow the installed capacity. So short term, we have over 200 megas of new build capacity coming online by year-end. This is most welcome in this environment. And in addition, we should also see the transformer issue resolved shortly, and this has kept about 200 megawatts offline. On Slide 13. Here, you have the P&L where you see EBITDA EUR 607 million in the quarter and EBIT follows this in tandem. Associates were up too, mainly from the increased net income from our solar JVs. Net income was EUR 161 million and the RCA. Now under IFRS net income was negative EUR 334 million, driven by the negative EUR 545 million in special items, and this comes mainly from the mark-to-market of our hedging positions. Now these price protection contracts do not qualify under IFRS hedge accounting rules, so we need to take this volatility to the P&L as opposed to equity. So throughout 2022, the revenues we generate from the gas volumes that underlie these derivatives will compensate these mark-to-market variations as it is designed to. So the hedges are made to reduce our economic risks. So no worries here other than and welcome temporary volatility. The cash flow on Slide 14. You see a strong operating cash flow for EUR 468 million. Now CFFO is affected by the working capital built resulting from the margin deposits to cover the exchange rate derivative positions. And maybe Otelo Ruivo should spend a minute on this derivative and margin deposit topic. So in the P&L, we have the mark-to-market of the entire derivative book. And in the cash flow statement, we have the cash that we need to post as collateral with the exchange. The number is quite high this quarter, EUR 373 million and EUR 444 million for the full 9 months. And this is a reflection of how much gas prices have gone up. And why do we enter into derivatives in the first place? So we buy gas from our suppliers, and we sell the gas to clients. And the business model is to make a commercial margin between the 2. However, the gas that we buy is mainly priced off Brent and our sales say, to industrial clients are normally TTF-linked. So we, therefore, protect the basis risk of the price of what we buy and what we sell through the derivative market. So effectively, the gains that we could have made from the recent sharp increase in TTF versus Brent, those gains are neutralized by the derivatives. So if you exclude these derivative margin accounts, which are temporarily, the free cash flow was a healthy EUR 260 million in the third quarter. This is all from my side, Otelo. We'll now take your questions. Thank you.

[Operator Instructions] Your first question comes from the line of Biraj Borkhataria from RBC.

Apologies I cut off, this might have already been covered, but 2 questions. The first one is on the shareholder distributions. You mentioned a number of times about the temporary nature of the margin impact. So as we're thinking about your full year dividend, is it fair to just strip that number out and then run the calculation on that CFFO number? And then the second question is on -- what you mentioned on gas sourcing. You highlighted some contingency plans for gas sourcing in fourth quarter. I was wondering what exactly that would entail?

Thanks, Biraj, and then thanks for your question. Look, I have to say that we have said up to now that we're just going to do a mathematic calculation on the supplementary dividend, and we will do a mathematical calculation on that. And depending on that working capital build, we'll see what that yields. What I think we're saying here is there will be -- we've agreed with the Board that there may well be a discretionary element that we will add to that. I can't tell you today how that will be calculated or what they will be, Biraj. But I think what we're indicating here is that we think this is very much a one-off issue and the shareholders shouldn't be penalized for it. So more to come on that one. On the gas sourcing, I think this is about -- we are having some issues with our gas supplies. And with the current gas markets, as you might imagine, replacing and buying new cargoes can be really expensive. So we're very much looking at the demand side of that and seeing what we can do to reduce our own use as well, to be honest with you, Biraj, and to see how we can mitigate any potential sourcing constraints we get in the quarter. So we're turning every stone and would be very reluctant to go and buy new volumes to the kind of spot prices we're seeing today, to be honest with you.

Your next question comes from the line of Alessandro Pozzi from Mediobanca.

The first one is on the upstream guidance. I believe in Q2, you mentioned you would have been bottom end of the range for 2021, but you've maintained it. And I was wondering how should we think about maybe the exit rate in Q4? And maybe if you can give us maybe some key dates for 2022. I believe the start-up of Coral South is one of them. And maybe if you can give us an update on that one as well? That's my first question.

I think -- thank you, Alessandro, for your question. I think I'll hand over to Thore to talk about the upstream position.

Thank you, Andy. So with respect to the upstream production and the guidance for the fourth quarter, I think you can expect the production that is very similar to the one that you have seen in the third quarter. That's our key guidance to you. With respect to 2022, that's a bit early. Let's revert to 2022 at the Capital Markets Day when we have consolidated all our numbers and analysis for next year. With respect to Coral, the project is going extremely well. And now it's very visible that we will have a sale away from Korea in the middle of November, then its sales to Mozambique, for the offshore commissioning. And in our plans, we have first gas in the second half of 2022. Thank you.

Okay. The second question on renewables. I think part of your strategy is to farm down some of your positions in certain assets. And given the spike in electricity prices, do you think this is potentially happening sooner rather than later. And yes, generally, I was wondering if you can give us an update on potential disposal opportunities there.

Thank you for your comment. I mean what I'd like to just say is that what we're doing is we're building portfolio, we talked about 4.7 gigawatts. We're continuing to build the portfolio to give us more options to make sure we are delivering the growth capacity of the 4 gigawatts. In terms of our sell-down strategy, clearly, we haven't yet got firm plans of when we're going to kick that process off. We're diversifying the countries we're working in with our announcement now we're moving into Brazil. But there will be a moment when we will both look at some sell downs, particularly when we derisk the projects. But also -- what timing we would take some more PPAs because we're entirely merchant at the moment, which is obviously good with the current prices. But over time, I think we will want to position more in the long-term markets. But nothing definitive to say at the moment. So thank you for that.

Just a follow-up on Brazil. And do you expect to sign PPA for the new asset?

Yes. I mean Brazil has quite attractive index-linked both public, so both open commercial and government PPAs that we can take part in. But it also has a very attractive merchant market at the moment. We probably will plan to do a bit of both to get a strong underpinning for the project, but then to enjoy some of the upside in the merchant market. At the moment, in Brazil, there is -- has been quite a significant drought, which is putting some distress into the electricity system. And therefore, I think there will be -- it'll be very welcome for us to build some more renewable capacity there and take part in the electricity growth that they are seeing in that country. I think they have an ambition for something like 40 gigawatts of renewable capacity by 2030. So a very attractive market for us to participate in.

Your next question comes from the line of Michael Alsford from Citi.

I've got a couple. Just firstly on the upstream. I was wondering whether you could update us on when we might expect a new development plan for 2P, which could help offset the declines that we're going to see from the field, I guess, in the next year or so? And then secondly, just to follow up on the gas sourcing question from earlier. I appreciate you're looking at mitigating the cost impact of the gas sourcing in 4Q. But I don't know if you could maybe look out a little bit more into 2022. And why do we not still see, I guess, a headwind around the costs associated with buying nat gas for more of a medium-term impact on the business in Energy Management?

So firstly, can I ask Thore to talk about the plan one for 2P? Thore?

Thank you, Andy. So the work with the new plan for operation and development on [ 2PN ] at [ RSM ] is actually going really well and the partnership. It is significant work already done. I think the document is now in the order of around 900 pages. The expectation and the full intention from the partnership is to deliver this plan to ANP by the end of this year. So that's the forecast and the plan seems to be -- being at robust.

Yes. So on the gas sourcing, quite early to talk too much about 2022. Clearly, we want to build more flexibility into our position in terms of -- I think, for us, the lessons learned a bit that we did hedge 100% of the volume. And I think going forward, we're going to have to look to give ourselves a bit more flex if we do have supply restrictions. I'm quite optimistic about the long term. We've got venture LNG coming in 2023. I mean, I think we can position that in the market hopefully in a strong, profitable basis. So no specific guidance on 2022. The only thing I can say is we've secured the regasification here in Portugal without the premium that we paid up to the end of Q3. So going through 2022, we'll still enjoy a lower cost of regasification of the LNG that is delivered. But I think we've now got much better handle on our ability to respond to any supply shortfalls, particularly looking at some of our own use and how we can, how we can build more flexibility in that balance over time.

Great. And then just a follow-up on Thore's point on the field development plan in Tupi. Is it there a prerequisite, sorry, that you need to get a license extension? And if that is the case, how is that going in terms of that negotiation?

Thank you, Michael. Without going into too much detail on this, Michael, but you can expect that we will have several elements into this plan. And some of the elements in the plan will also then be requiring a license extension, correct? So this -- we are expecting that there will be some discussions going in an order before the whole plan is for -- we are looking for 20-year plus extension on the field life, actually.

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

I had 2, please. The first one was related to Brazil production. Last quarter, you talked about preventing maintenance impacting production uplift in the second half of 2021. Just wanted to check if you could comment on the progress here. Is the maintenance activity completed in 3Q? Or is it still persisting into the fourth quarter? The second one was related to your shareholder distribution policy. Again, last quarter, you've mentioned that you're reviewing the option of using buybacks. I was just wondering if you have reached the decision on that? Or will we see the incremental -- the increase in the shareholder distribution all reflected in the additional dividend.

Let me just start with the second. What I have said and what we are doing is looking at and consulting with shareholders around buybacks versus cash dividends, and that work is still ongoing. So I have nothing to report on that at this stage. But just to reaffirm, we're looking and consulting with the very shareholders about that. On the Brazil production, I'll hand over to Thore, in a second. I think one of the difficulties that we've had, and actually, we see this in other parts of the world as well, where through COVID, clearly, there was a maintenance backlog increase, but also a delay in hooking up wells, a delay in doing workovers. And so I don't think this is constrained just to Brazil. But Thore, anything more to add on the normalization of the situation in Brazil?

So Sasi, we are moving in direct direction still, however, being constrained, just to give you a sort of one indicator while the POB was restricted around 60% of the capacity has now increased a bit. So we are around 80% of POB capacity on the different installations. So we have more hands on the deck in order to work with the backlog. It's not being worked systematically, and we expect that there is 2 units that is scheduled for maintenance in the fourth quarter of this year. So it's picking up, but there is a backlog, and that will take some time to be sorted out.

Your next question comes from the line of Jon Rigby from UBS.

I think this is for Filipe, which is I noticed the sort of step-up in contribution from renewables, obviously, with the high electricity prices. And that sort of flows through from your pro-forma EBITDA into -- mainly into associates as you've noted. Can you just help and run through the sort of how both the earnings and then also the cash flow cascade kind of works into your income statement into your consolidated accounts. So I'm particularly interested maybe where you're doing refinancing, does that reappear back in your cash flow statement as a dividend? Or is it divestment? And I just wanted to sort of understand what the allocation and priority of cash flows would be to paying interest versus paying dividends back to yourselves? Paying back some of the capital on the loans, et cetera. So if this makes sense, some sort of map of how cash flows and earnings work back into your business, if that's possible.

Good morning, Jon. I don't think what we are doing and will do is different from what we've done with other associates or what everybody else does. So what you have unconsolidated entities are currently generating more cash. So that cash goes to pay project finance and OpEx, of course. And whatever is left under the financing agreement as long as you comply with debt service coverage ratio, then you distribute the cash as dividend. And when you use that cash for CapEx, but we will show the numbers growth. So all the cash that comes to Galp comes from -- in the cash flow statement as a dividend income. And CapEx will be gross. So the money goes back into projects for expansion. On the P&L, what you see is the share of profits at an accounting number, share of profit that goes under associates in the P&L. So because we have a very long term funding. And other one we've just closed as an 18-year maturity. We do expect, depending on power prices, of course, we do expect significant cash flow money is coming in over the next few quarters.

Yes. Okay, cool. That makes sense. Can I just ask a follow-up question? Just on Mozambique. It's really about the onshore project itself and not really about the delays or visibility around that. But just as the sort of at a higher level, just as the world is starting to focus very much on Scope 1, Scope 2 emissions around new projects, is -- there's a dilemma or a paradox with LNG is that Scope 1, Scope 2 can be actually quite high or very high, although Scope 3 sort of full life cycle can be relatively competitive and clearly there's some advantages in terms of clean air where you're using the gas to generate electricity, et cetera. Does that present a problem for you in the context of your plans around going to lower emissions to net 0 in terms of being a participant in that project? Or is there plans ultimately to physically deal with the carbon that will be emitted as part of the process of liquefying the gas?

Thanks, Jon, and I'll be asking Thore to follow through. Clearly, our net 0 position is 2050, a long way off, particularly gas, as you know, particularly in the Asian context, replaces coal so it's positive. But we are very focused on what the Scope 1 and 2 emissions of the LNG plant being designed are. So I mean, Thore, do you want to explain some of the things we're looking at.

Yes. I'll do that. Thank you, Jon. So yes, actually, one of the things that is being looked at as the product now is being revised and we're using this time in order to see how we can optimize it further. One of the things that also then is looked into is how to reduce the CO2 emissions from the plant. And with that in particular mind, what you just mentioned, Jon. So that is one of the factors that is now being put on the drawing board.

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

I have 2 left on my list. And the first one is, if you can talk a little bit more about the size of the Brazilian renewable opportunity and sort of -- what sort of -- what sort of pipeline beyond the sort of capacity that you announced, you see. And the other question still on renewables is if you can give an update on how the search for the new CEO role is going? And when do you expect to sort of have an update on that?

Okay. Thank you for the question. Look, the Brazilian pipeline is a significant one. We've announced our participation in 2 projects of total 600 megawatts. But we are looking at a much bigger funnel of opportunities there, both in solar and some in wind as well. But no deals done yet, but we continue to look at how we can expand away from that position. Look, I can -- we have selected someone to be the new CEO. We haven't gone public on who that is yet. But just to say that, that process has gone well. I'm very excited about individual that we will be able to announce that will take that business to the next level.

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

Two questions, please. Firstly, just a clarification on the dividend again. You mentioned there's going to be some discretionary elements. But you've quantified the year-to-date number at EUR 400 million of what you're losing on these temporary derivatives. So would you not be able to know exactly what that number is at year-end, just add it back? And then a comment on that is why not change the structure to be linking your dividend to the operating cash flow, ex working capital, you might like, create more simplicity in the structure. And then the second question on the upstream production run rate as you're going through the rest of the year, you mentioned that the maintenance backlog is improving, but it looks like quarter-on-quarter, volumes looking pretty flattish. Can you maybe just -- how much are you losing in production due to this maintenance issue? And therefore, how much is to play with when we're going to next year and thinking about what might come back.

Thanks, Josh. I don't want to give any definitive guidance on how we will calculate the supplementary dividend. It will -- we believe it will be partial. We have permission from our Board to say that this will be considered, but no clear mandate on the magnitude of that. When we -- yes, when we look at our mechanism, we use CFFO because normally, managing working capital is quite a bit of hard work in terms of managing stocks and everything else. I mean this is a distinct one-off that we really couldn't control. But actually, it not only affects CFFO, it affects net debt. So both those parameters are affected by this one-off margin account build. But I can't -- I'm not in a position today to give you a definitive calculation method for how that supplementary dividend will be calculated. We'll have to see how the rest of the year plays out with the macro what our OCF is, how strong the company is at the end of the year before we declare what that supplementary dividend will be. I think I'll hand over to Thore to talk a little bit about what we've seen in terms of shut-in production and how much there is behind the pipe there. Thore?

Thank you, Andy. Thank you, Josh. So when it comes to maintenance is a part of life, that's the natural part of the way we do the business. So also going forward, you have to expect that we will have a periodic maintenance on the different units in all of our operations. Typically, the chartered FPSOs have a 10 to 15 days of maintenance every year. On the replicants, we have a longer but more periodic maintenance. Typically, that is 20 days, but then only every 3 years is done with more force and typically also connecting with the flotel so you have more people to contribute. So what I can say is that we expect going forward that maintenance will be more or less as we have guided before and have an impact in the production in the order of around 5,000 barrels per day. And that is the best guidance I can give you also going forward, Josh, on that.

If I could just follow up -- did you say how much the impact is this year so far versus the 5,000 barrels a day?

So Josh, actually, in front of me, I don't actually have that number in front of me. So sorry, I can't answer that here now. I can get IR to follow up with you.

Your next question comes from the line of Mehdi Ennebati, from Bank of America.

Sorry if my questions have already been answered, I have some issues with the connection. But 2 questions on my side. First, regarding your gas sourcing issues. Can you tell us if you could get some compensation from your insurance as it seems you are not receiving contracted natural gas from supplier or maybe explaining again why you can't get any compensation, please? And given the natural gas price development, should we expect a significantly higher negative impact in the first quarter compared to the third quarter? Just for us to avoid, let's say, a big negative surprise, please. And the second question is more about Petrogal dividend paid to Sinopec. So since you didn't pay any dividend in the third quarter. Should we then expect 2 dividends to be paid in the first quarter? Or are you just decided to skip the third quarter dividend?

Let me -- thank you, maybe. Let me answer the first question. I'll ask Filipe to do the second and third. No, we are in the -- we're in intensive negotiations with our suppliers to say, to try and mitigate any impacts. There are some penalties, but I have to say that there are a very small fraction of the difference between the spot price and the market -- and the price we have actually secured for those volumes. So that really doesn't compensate the difference. But indeed, it is a discussion we have, and we're obviously working really hard to make sure that there is no interruption and we're able to supply our customers without missing a beat. So I can't give you any numbers on how much we would recover from any lack of supply. I can say we are in active discussion with them to make sure that they do supply. So Filipe, second, third question?

Mehdi, Your question is on working capital in Q4 and how does TTF change that, if I understood correctly.

No, no. There's a question about Sinopec.

Okay. Yes -- that's one I got. Okay. So on Sinopec, what we have agreed with Sinopec way back then is that free cash flows after paying all CapExes are distributed out 30%, 70%. So depending on the free cash flow this year and next and the following years, the role is quite straightforward. So this year, we're expecting a payment. So within fiscal year 2021, say, [ 120 ] [indiscernible] depending on what the macro will do. And next year, it's not necessarily payable in Q1 is we'll look at what the cash flows for 2022 look like and 30% of the free cash flows will be distributed out sometime during next year.

And the first quarter payment in Sinopec? Should we expect it to be back to normal EUR 30 million, EUR 40 million?

Again, it is not necessarily payable in the first quarter. So we paid the Galp shareholders in the second quarter and we discuss with Sinopec depending on what the cash flows or CapEx commitments, the best timing of payments. So we have quite flexibility on timing of payment. But within 2022, then it should be about 30% of the free cash flows.

Thank you. Your next question comes from the line of Michele Della Vigna from Goldman Sachs.

It's Michele here. Two quick questions, if I may. The first one, I just wanted to check that Coral FLNG because it's offshore would not be in any way affected by the security concerns that are lingering in Mozambique? And then secondly, I was wondering if you had a chance to start looking at your business through the lenses of the EU green taxonomy and if you have an early indication of what percentage of revenue and CapEx will be taxonomy compliant for you.

Thank you, Michele. So on the Coral security issues, largely, this is well offshore, and therefore, we believe, outside the current in security. Clearly, shore bases exist, but in places which where I think security is better guaranteed. So at this stage, we do not have any specific concerns around that, but we need to stay alert of course. On the EU taxonomy, I think it's early days for us to make any clear indications to the market about the proportion that would fall under that requirement. So at this stage, no update on the EU taxonomy.

Thank you. Your next question comes from the line of Jason Kenney from Santander.

Going back to Brazil and maybe a couple of the earlier questions. Is the Brazil renewable asset base going to be consolidated or nonconsolidated? We treat it differently from the Iberian renewable business. And what kind of CapEx do you think is needed to build out that Brazil solar, 2025? And if I may, obviously, you're looking at asset rotation in renewables, and you've got this targeted 12 gigawatts by 2030. Am I best to assume around 50% of that would be net capacity for Galp, 2030?

Thank you, Jason. I mean, I think, firstly, the way we're actually approaching Iberia as well. So the 1 gigawatt we've essentially added to the original ACS deal plus Brazil is that in the first instance, we develop it. And then only after the COD, when it's online, that we will sell down and be consolidated. So that is our current modus operandi. And clearly, we will also finance these projects. So I think that's the way we will go about projects. The CapEx renewable costs have gone up a little bit in the -- globally in the last 6, 9 months. But yes, I'm not -- I won't give you any clear guidance, but anything between, what is it, EUR 500,000 and EUR 700,000 per megawatt would be in the ballpark of how much it costs to develop these projects. But we hope to get 65%, 70% or more financing as well. So the equity contribution is far lower. And I think that also answers the asset retail -- yes, the 12 gigawatt I think we will continue to -- we talked about essentially a dilution of 50% in our portfolio on the 12 gigawatt position. And we maintain that. I think this is all going to be based on opportunities on being able to maintain the deconsolidation. And when we can rotate it. So the timing of it, when we can rotate those assets that we've [indiscernible] significantly that we can sell down to a strategic investor in order to leverage up our own returns. So I don't want to give any firm indications when we're going to do, how we're going to do it. But I think it's about a discipline that we want to instill within the renewable business, about how we make sure that we do get and have an opportunity to get double-digit equity returns on our renewable investment.

That's great. Just to clarify the 500,000 to 700,000 was dollars?

Euros. Euros.

Your next question comes from the line of Ignacio Doménech from JB Capital.

I have 2. My first question is on refining and the positive evolution of refining cash costs. Can you comment on what has been driving this trend? And where should we see refining cash costs going forward? And then my second question is on renewables. I think you mentioned generation was impacted by a transformer upset. So my question is, when do you expect this issue to be reverted? And if you would expect any compensation to this impact?

So let me start with the transformer issue. Clearly, this was part of the legacy in the joint venture we had with ACS. We've had 200 megawatts that have been out of capacity. We have -- we're on the verge of putting 65 megawatts back in online to compensate for that, essentially transformer that was allocated to a future project, we've now retrofitted. Clearly, at this time of year and going forward with lower solar radiation, that really helps mitigate -- if not totally mitigate the losses we may get in the fourth quarter. But we have new transformers arriving, to installed in, just in the new year, early months of next year to have us completely ready to go once the sun comes back in Iberia for Q2 onwards. Now when it comes to refinery cash costs, we've talked about driving down to $1.70 per barrel. Clearly, safety comes first and costs come second as we continue to emphasize to our people on the ground. But Thore, do you want to talk a bit about the cash costs and what we might see in Q4, particularly with also the work we need to do on the furnace?

Yes. Thank you, Andy. You're right. The overall ambition has been to drive down the cash cost and be in the area of slightly below $2 per barrel. However, as you know, we have had an operational issue in the atmospheric distillation unit, which we will need to repair. The repair is actually ongoing as we speak. That will impact our cash cost for the fourth quarter, and our current best estimate is that we will be spending around $10 million to $12 million on those repair that will translate into the cash cost. So I guess, the best guidance I can give you today is that the fourth quarter, you will see it around $3 per barrel. That's an indication for what the cash cost will be for the fourth quarter. We, however, believe that by this quarter, we should be back into normal operation unless we are getting any surprises during this repair work. So all work is that this is completed during this quarter. Thank you.

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

I have 2 left. The first one is still about this working capital buildup. Assuming that the TTF price stay where it is now, can you give us a feel for what the working capital buildup could look like in Q4? And then I have another question about renewables. You talk about EUR 60 million of pro-forma EBITDA. Can you tell us what utilization rate you assume as well as solar capture price that you assume as well?

So can I ask Filipe to answer the first question?

Raphaël, compared with what we have on the balance sheet on September 30, we have calendar 2022, TTF was trending at about EUR 57, it is currently at EUR 54, I think. So given what's -- where we are today and where we stand, I would say it should get a bit better, but it is incredibly volatile. So it's very hard to call the shot on what December 31. And this is a daily mark-to-mark number. It varies every day, else. Thank you.

Raphaël. Yes, just on this renewables question, in a moment to Q3, we enjoyed about EUR 110 per megawatt hour as a solar capture price. Clearly, our generation capacity comes down in Q4 as we get less on. But we will have about an extra 100-megawatt available online to enjoy whatever sun we do get in the fourth quarter. So that's really EUR 28 million was the pro-forma EBITDA for the Q3 to give you an idea of what kind of run rate clearly would have the extra 20% that would have been somewhat higher. So that's the current position we're in.

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

Two, if I could, please. First, just I wanted to come back to the operational outlook in Brazil and the earlier comments, could you just share a sense of how the operational backdrop has evolved since perhaps the update you provided in the summer, where the sort of the maintenance backlog sits today compared to the middle of the year? And how long you expect it to be able to work through before you get back to the normalized 5,000 barrels a day plus/minus of annual maintenance effect, Thore, I think you referenced earlier? And then secondly, just on price realizations on the upstream, we've seen a wider average oil and gas realization discount to headline Brent in the last couple of quarters. I think you've highlighted softer pricing or more competition into Asia on the Brazil exports. How do you see the outlook there into 2022? Is this something that you still expect to be temporary and ultimately revert or something that could become more of a medium-term structural issue?

If I can just start, and I'll hand over to Thore to add on the Brazilian outlook. And we did a quite a full analysis of what we produced this year versus what we'd hope to produce this year and to try and understand what the key issues for the shortfall were. I mean what we found was one of the biggest thing is just how it takes a lot longer to hook up wells now, whether they're new wells or they're work over activities that need to be done. We had also -- and we've mentioned this issue about the riser issues and tests we've been doing on the corrosion that -- stress corrosion cracking and corrosion of arises. And Petrobras done a lot of work on that. And that has an impact of a couple of points of availability at the moment and for a short time to come. And then as the overall availability level of the various FPSOs that Thore, was alluding to. And then lastly, there's a reservoir performance, and I know a lot of people are being concerned about what we found, is the reservoir actually performed slightly better than we expected this year. So I think there's some good use below the wellhead in terms of the reservoir itself. It's these compounded issues that we have above the wellhead that I think that we -- that Petrobras is working through. Any more to add, Thore?

No, I think, Andy, on the maintenance, I think you covered it well. It's actually to sum it up 50% of the shortfall we have seen year is due to delays in well connections and then there's another 20% that is related to delays in well workover. So that's really is capturing the majority, it actually has been slightly positive. What have happened on the issue of stress corrosion. We -- the inspection that was done over the summer actually proved to be better than anticipated. So that meant that a few producers could be put back in operations before expectations. So hopefully, and crossing fingers, that is now going forward in a good way. The long-term solution. However, that will take some time because that will require new materials to be qualified for that issue. When it comes to the price realization, the market that's very much dependent on the situation in China. We have seen that the Chinese market has been somewhat more difficult in the third quarter. So the discounts has had to be a little larger in order to place the volumes. Let's see what the role of the independent refiners in China will be going forward. That has a direct impact on that market and the outlook. So we will stay with the sort of same guidance that we have given you, but expected to be for this quarter in the area of $8 to $10 per barrel less as a discount overall. And that's factored in, which is very important, what Andy also said in his speech, in the beginning that our gas prices in Brazil, just for the associated gas is actually capped at $55. So there's limit to how much we can get on the gas side. However, that ends by the end of this year. So from next year, we will actually dispose and handle the natural gas -- associated gas ourselves in Brazil, and that should give us some more capturing higher margin on that.

Your final question comes from Anish Kapadia from Palissy Advisors.

Just had one question remaining, you touched on it slightly. But we're seeing evidence of quite strong inflation, and it could be quite persistent inflation in the market. And I'm thinking about that both from the raw materials side of things, but also the potential for higher inflation and higher interest rates going forward. So I was just wondering if you could cover the impact of that, in particular, on the renewables business of those higher input costs coming through, but also from a financing perspective and a returns perspective of how you think the higher inflation and higher interest rates could potentially impact that business?

I'll ask Filipe in a second to talk a bit about interest rates. I think one of the benefits of our joint venture that we secured with ACS was it locked in construction costs going forward. So we've largely derisked, particularly with the 2.9 gigas that we have in that particular deal. But what's interesting about these higher costs and perhaps the risk of higher interest rates is, you also see a bit of a slowdown in people building more capacity. And as a result, that feeds into what we also see, particularly at the moment is clearly pretty high solar capture prices. So I think these things have their own balance to them. We have a pretty strong position in that we've derisked the construction costs in our deal with ACS. But Filipe, do you want to talk a bit about the interest rates and how exposed we are to that?

And because we project finance, the banks ask us for a very significant proportion of the funding to be swapped fixed rate. So we're fairly hedged on the funding cost. We're fairly hedged through the EPC contracts we've signed with ACS, we are seeing unit CapEx prices going up. So everything is becoming more expensive, access to land, interconnection, equipments, actually quite a number of auctions took place recently. A number of bidders were betting on declining CapEx numbers, and they've bid very aggressively. So also to be seen how many of those projects will actually get funding and get off the ground. So we'll see less projects being built, more challenged for those that are not hedged. Having said this, we're seeing a lot of inflation on the price of the electrons that we see. So net-net, this is not necessarily bad for the projects in the short term. in the longer term, well, we will see. But Galp is mostly hedged. Thank you.

Okay. I think this ends our session. Thank you for your time and for participating. We hope you find this update useful. As always, the Investor Relations team is available for any additional clarifications. We will be on the road again from November onwards. So I really hope to meeting you in person soon. Have a great day and a productive [ felling ] soon.

That does conclude our conference for today. Thank you all for participating. You may now disconnect.