Good morning, ladies and gentlemen. Welcome to Galp's third quarter 2021 results presentation. I will now pass the floor to Mr. Otelo Ruivo, Head of Investor Relations.
Good morning, welcome to Galp's third quarter and nine 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 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 instructions 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 statement 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 a 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.
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. I'm happy to see the external recognition of our strategy, with Galp currently holding leading positions on the relevant ESG rankings, acknowledged further by the EUR 700 million lending we have secured from EIB.
Let's look at the businesses in more detail. During the period, we have seen some operational improvements in upstream, namely in Tupi in Brazil, leading to a stronger oil output, welcome at a time of high oil prices. 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 to Galp in the period, the production rate from the one well hooked up is prolific, boding well for the full potential of the field. The FPSO in Atapu is also now producing at high levels, close to plateau production, with only four 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 125-130 thousand barrels 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 developments, 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 sail 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 distillate 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 refinery 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 two furnaces of the Sines Atmospheric Distillation Unit. There were no injuries, but it 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 impacted 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 margins should stand at $4- $5 a barrel. Energy management, this was a weak quarter, impacted firstly by the extra costs related to the access to the LNG Regasification Terminal Portugal. These extra costs are now no longer charged from Q4 onwards. We've been impacted by negative effects by the oil product supply pricing lag, resulting from the commodity price increase during the period. Most importantly, by unplanned natural gas sourcing restrictions related to our long-term suppliers, which obliged us to acquire some volumes at expensive spot conditions. Energy management contribution was negative in the quarter. Going into Q4, we're assessing with our main suppliers any potential deviations from the planned deliveries given the cost of securing alternative supplies.
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. 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. We now also see some positive signs in B2B. Aviation and marine segments do still remain weak. At the same time, we're taking steps to transform this business to adapt to consumer needs. Our efforts to extract more from non-fuel have been proving successful. 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 convenient sale and expect convenience contribution to more than double by 2025. In renewables, our production is sold under strong merchant conditions. Our generation capacity could have been higher this quarter. However, four plants have been restricted due to an issue with one transformer. We've been implementing mitigations with some of the 200 MW of impacted electricity.
We hope to get back to full operation in early 2022. In addition, we plan to bring online an additional 236 MW 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 MW, and last week we announced an important step in our renewable venture in Brazil, where we acquired 600 MW of solar capacity, of high-quality projects in a pre-construction stage. The acquisition costs in Brazil were not material. Further payments, however, will be made, but only when the projects hit 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.
We've recently reinforced our renewables team in Brazil, a country which offers an opportunity to develop profitable, renewable power generation platform. We will maintain our discipline, entering in early a pre-construction stage and creating value by building up a portfolio from there. Our energy management team will be fundamental to capture market dynamic opportunities, monitoring the market developments, and evaluating the best way to sell our power generation with a mix of PPAs and merchant exposure. These acquisitions positions Galp with a 4.7 GW 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 GW operating, and well-positioned for the 12 GW ambitions 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 to provide us an efficient capital structure to develop these projects. 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. 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.
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 plans are becoming real. Currently developing a 2 MW pilot with FID expected by year end. This will accelerate our learning curve before the larger capacity electrolyzers get closer to reality. We're advancing simultaneous with two projects of 100 MW 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 a 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 MW project in Spain, operating in full merchant conditions. All our operating projects in Spain have now been project financed, 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 €2.3 billion and €1.8 billion respectively. On the operational side, commercial industrial energy management should stand below the estimates we provided last June on the back of slower anticipated Iberian demand recovery and restrictions in energy management. Upstream and renewables will benefit from higher oil, gas, and power prices. Our CFFO non-adjusted operating cash flow is predicted to have a €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 derives mostly from contracts that will end in 2022, when the supplies are delivered to the customers. 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 will elaborate a bit more on this later. 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 if 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 the year end to be at the lower half of the previously provided guidance, to stay within EUR 0.5 billion-EUR 0.6 billion, demonstrating our continued capital discipline. 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 with 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. 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. 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. The current gas price formula is capped at $55 Brent. Upstream CapEx was $187 million. This went primarily to our pre-salt developments, namely Tupi and Bacalhau and Coral in Mozambique. The CapEx line this quarter also includes $34 million payment for the acquisition of a stake in BMS-8.
This increased the Galp stake from 14%- 20% back in 2017. 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- $50 million. Commercial EBITDA was EUR 87 million in the quarter. This with seasonal quarter-on-quarter higher oil product sales and the gradual easing of lockdown measures. 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.
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 effects under the formulas we have established with our clients. Industrial and 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. After some 25 years invested in those assets, these concessions will end this month. We will now bring the Algerian gas through the Medgaz pipeline, where we are not an investor. On renewables, now you know we don't consolidate this business. What we show here are pro forma numbers, and the pro forma EBITDA was a very healthy EUR 28 million in the quarter.
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. We remain committed to deploy the ambitious pipeline of projects and grow the installed capacity. Short-term, we have over 200 MW of new build capacity coming online by year-end. This is most welcome in this environment. In addition, we should also see the transformer issue resolved shortly, and this has kept about 200 MW offline. On slide 13, here we have the P&L where you see the EBITDA of 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 under RCA.
Under IFRS, net income was negative EUR 334 million, driven by the negative EUR 545 million in special items. This comes mainly from the mark-to-market of our hedging positions. These price protection contracts do not qualify under IFRS hedge accounting rules. We need to take this volatility to the P&L as opposed to equity. 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. The hedges are made to reduce our economic risks. No worries here other than unwelcome temporary volatility. The cash flow on slide 14, you see a strong operating cash flow for EUR 168 million. CFFO is affected by the working capital built resulting from the margin deposits to cover the exchange rate of derivative positions.
Maybe, Otelo, I should spend a minute on this derivative and margin deposit topic. In the P&L, we have the mark-to-market of the entire derivative book. 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, $373 million, and $444 for the full nine months. This is a reflection of how much gas prices have gone up. Why do we enter into derivatives in the first place? 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 two. However, the gas that we buy is mainly priced off Brent. Our sales, say to industrial clients, are normally TTF linked.
We therefore protect the basis risk of the price of what we buy and what we sell through the derivative market. Effectively, the gains that we could have made from the recent sharp increase in TTF versus Brent, those gains are neutralized by the derivatives. If you exclude these derivative margin accounts, which are temporary, the free cash flow was a healthy EUR 260 million in the third quarter. This is all from my side, Otelo. We will now take your questions. Thank you.
To ask a question, you will need to press star one on your telephone. In the interest of time, we ask participants to limit their questions to two each. To withdraw your question, please press the hash key. Please stand by while we compile the Q&A roster. Your first question comes from the line of Biraj Borkhataria from RBC. Please ask your question.
Hi there. Thanks for taking my questions. Apologies, I got cut off. This might have already been covered. Two questions. The first one's on the shareholder distributions. You mentioned a number of times about the temporary nature of the margining impact. 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? The second question is on what you mentioned on gas sourcing. You highlighted some contingency plans for gas sourcing in the fourth quarter. I was just wondering what exactly that would entail. Thank you.
Thanks, Biraj. 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. 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 that will be, Biraj. 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. 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. 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. We're turning every stone and would be very reluctant to go and buy new volumes at the kind of spot prices we're seeing today, to be honest with you.
Okay. Thank you.
Your next question comes from the line of Alessandro Pozzi from Mediobanca. Please ask your question.
Hi. Good afternoon. Thank you for taking my questions. The first one is on the upstream guidance. I believe in Q2 you mentioned it would have been a bottom end of the range for 2021, but you maintain it. I was wondering, how should we think about maybe the exit rate in Q4, maybe if you can give us maybe some key dates for 2022. I believe the start-up, of course, is one of them, maybe if you can give us an update on that one as well. That's my first question.
Thank you, Allesandro, for your question. I think I'll hand over to Thore to talk about the upstream position.
Thank you, Andy. 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. 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. Now it's very visible that we will have a sail away from Korea in the middle of November. It sails to Mozambique for the offshore commissioning. In our plans, we have first gas in the second half of 2022. Thank you.
Okay. Thank you. The second question on renewables. I think part of your strategy is to farm down some of your positions in certain assets. Given the spike in electricity price, do you think this is potentially happening sooner rather than later? In general, I was wondering if you can give us an update on potential disposal opportunities there.
Alessandro Pozzi, thank you for your comment. What I'd like to just say is that what we're doing is we're building a portfolio. We talked about 4.7 GW. We're continuing to build the portfolio to give us more options to make sure we are delivering the gross capacity of the 4 GW. 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. There will be a moment when we will both look at some sell downs, particularly when we de-risk the projects. Also, look at what timing we would take some more PPAs because we're entirely merchant at the moment, which is obviously good with the current prices.
Over time, I think we will want to position more in the long-term markets. No, nothing definitive to say at the moment. Thank you for that.
Just a follow-up on Brazil. Do you expect to sign PPA for the new asset?
Yeah. Brazil has quite attractive index linked, both public, so both open commercial and government PPAs that we can take part in. 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 has been quite a significant drought, which is putting some distress into the electricity system. Therefore, I think it'd 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 GW of renewable capacity by 2030. A very attractive market for us to participate in.
Thank you.
Your next question comes from the line of Michael Alsford from Citi. Please ask your question.
Thank you. Good afternoon. 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 Tupi, which could help offset the declines that we're going to see from the field, I guess, in the next year or so. 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 that gas for more of a medium-term impact on the business and energy management? Thank you.
Firstly, can I ask Thore Kristiansen to talk about the plan development for Tupi? Thore Kristiansen.
Thank you, Andy. The work with the new plan for operation and development on Tupi and Iracema is actually going really well in the partnership. It is significant work already done. I think the document is now in the order of around 900 pages. The expectation and full intention from the partnership is to deliver this plan to ANP by the end of this year. That's the forecast, and the plan seems to be being robust. Thank you.
Yeah. On the gas sourcing, kind of early to talk too much about 2022. Clearly, we want to build more flexibility into our position. I think for us, the lessons learned a bit that we did hedge 100% of the volume, 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 think we can position that in the market, hopefully in a strong, profitable basis. 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. Going through 2022, we'll still enjoy a lower cost of regasification of the LNG that is delivered.
I think we've now got a much better handle on our ability to respond to any supply shortfalls, particularly looking at some of our own use and how we can build more flexibility in that balance over time.
Great. Thanks, Andy. Just to follow up on Thore's point on the field development plan in Tupi. Isn't there a prerequisite that you need to get a license extension? If that is the case, how is that going in terms of that negotiation? Thank you.
Thanks. 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. This, we are expecting that there will be some discussions going in an order before the whole plan is firm. We are looking for 20-year-plus extension on the field life, actually. Thank you.
Okay. Thank you.
Your next question comes from the line of Sasikanth Chilukuru from Morgan Stanley. Please ask your question.
Hi. Thanks for taking my questions. I had two, 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 mentioned that you are reviewing the option of using buybacks. I was just wondering if you have reached a decision on that or will we see the increase in the shareholder distribution are reflected in the additional dividend. Thanks.
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. That work is still ongoing. I have nothing to report on that at this stage. Just to reaffirm, we're looking and consulting with the various 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. I don't think this is constrained just to Brazil. Thore, anything more to add on the normalization of the situation in Brazil?
Sasikanth, we are moving in the right direction still, however, being constrained. Just to give you one indicator, while the POB was restricted, around 60% of the capacity has now increased a bit. We are around 80% of POB capacity on the different installations. We have more hands on the deck in order to work with the backlog. It's now being worked systematically, and we expect that there is two units that is scheduled for maintenance in the fourth quarter of this year. It's picking up, but there is a backlog, and that will take some time to be sorted out. Thank you.
Thank you very much.
Your next question comes from the line of Jon Rigby from UBS. Please ask your question.
Hello. Thank you for taking the question. I think this is for Filipe, actually, is I noticed the sort of step-up in contribution from renewables, obviously with the high electricity prices. That sort of flows through from your pro forma EBITDA 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? I'm particularly interested maybe where you're doing refinancing. Does that reappear back in your cash flow statement as a dividend or as a divestment? 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.
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. You have unconsolidated entities are currently generating more cash. That cash goes to pay project finance and OpEx, of course.
Yeah.
Whatever is left under the financing agreement, as long as you comply with debt service cover ratio, then you distribute the cash as dividends. When you use that cash for CapEx, we will show the numbers gross. All the cash that comes to Galp comes from in the cash flow statement as a dividend income.
Yeah.
CapEx will be gross. The money goes back into projects for expansion. On the P&L, what you see is the share of profits. It's an accounting number, share of profit, that goes under associates in the P&L. Because we have very long-term funding, the 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 monies coming in over the next few quarters. Yeah.
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. Just as at a higher level, just as the world is starting to focus very much on Scope 1, Scope 2 emissions around new projects, 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 full life cycle can be relatively competitive. Clearly, there are 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 and to net zero in terms of being a participant in that project?
Is the plan ultimately to physically deal with the carbon that will be emitted as part of the process of liquefying the gas? Thank you.
Thanks, Jon, I'll be asking Thore to follow through. Clearly, our net zero position is 2050, a long way off. Clearly gas, as you know, particularly in an Asian context, replaces coal, it's positive. We are very focused on what the Scope 1 and 2 emissions of the LNG plant being designed are. Thore, do you want to explain some of the things we're looking at?
Yeah. I'll do that. Thank you, Jon. Yes, actually, one of the things that is being looked at as the project now is being revised. 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. With that in particular in mind, what you just mentioned, Jon. That is one of the factors that is now being put on the drawing board. Thank you.
Thank you.
Thank you. Your next question comes from the line of Giacomo Romeo from Jefferies. Please ask your question.
Good morning. Good afternoon, actually. Thank you for taking my question. I have two left on my list. The first one is if you can talk a little bit more about the size of the Brazilian renewable opportunity and what sort of pipeline beyond the sort of capacity that you announced you see. 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 have an update on that?
Thank you for the question. The Brazilian pipeline is a significant one. We've announced our participation in two projects of total 600 MW. We are looking at a much bigger funnel of opportunities there, both in solar and some in wind as well. No deals done yet. We continue to look at how we can expand away from that position. We have selected someone to be the new CEO. We haven't gone public on who that is yet. Just to say that that process has gone well. I'm very excited about the individual that we will be able to announce that will take that business to the next level.
Thank you.
Your next question comes from the line of Joshua Stone from Barclays. Please ask your question.
Thanks. Hi. Joshua. Two questions, please. Firstly, just a clarification on the dividend again. You mentioned there's going to be some discretionary element, but you've quantified the year-to-date number at EUR 400 million of what you're losing on these temporary derivatives. Would you not be able to know exactly what that number is at year-end and just add it back? 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 create more simplicity in the structure.
The second question on the upstream production run rate, as you're going through the rest of the year, you mentioned the maintenance backlog is improving, but it looks like quarter-over-quarter volumes looking pretty flattish. Can you maybe just quantify how much are you losing in production due to this maintenance issue? Therefore, how much is to play with when we're going to next year and thinking about what might come back? Thank you.
Thanks, Josh. I don't want to give any definitive guidance on how we will calculate the supplementary dividend. 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 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. This is a distinct one-off that we really couldn't control. Actually, it not only affects CFFO, it affects net debt. Both those parameters are affected by this one-off margin account build. 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.
What 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. When it comes to maintenance is a part of life. That's the natural part of the way we do the business. Also going forward, you have to expect that we will have a periodic maintenance on the different units in all of our operation. Typically, the chartered FPSOs have 10-15 days of maintenance every year. On the turnaround, we have a longer but more periodic maintenance. Typically, that is 20 days, but then only every three years. It is done with more force and typically also connecting with the flotel, so you have more people to contribute. What I can say is that, we expect going forward that maintenance will be more or less as we have guided before and have impact in the production in the order of around 5,000 barrels per day.
That is the best guidance I can give you also going forward, Josh, on that. Thank you.
Thank you. If I could just follow, are you able to say how much the impact is this year so far versus the 5,000 barrels a day?
Josh, actually, in front of me, I don't actually have that number.
That's fine.
...in front of me, so sorry, I cannot answer that here now.
Yeah, that's fine.
I'll do the follow-up with you. Thank you.
Thank you. Thanks.
Your next question comes from the line of [Mehdi Ennebati from Bank of America. Please ask your question.
Hi. Good afternoon, all. Thanks for taking my questions. Sorry if my questions have already been answered. I had some issues with the connection. Two 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? Maybe, explain again why you can't get any compensation, please.
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. The second question is more about Petrobras dividend paid to Sinopec. It seems you didn't pay any dividend in the third quarter. Should we expect two dividends to be paid, in the first quarter? You just decided to skip the third quarter dividend? Thank you.
Thank you, Mehdi. Let me answer the first question. I'll ask Filipe to do the second and third. We're indeed in intensive negotiations with our suppliers to, as I 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 price we have actually secured for those volumes. That really doesn't compensate the difference. 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. 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.
Filipe, second, third question.
Hi, Mehdi. Your question is on working capital in Q4 and how does our TTF changed that, if I understood correctly.
No. The question was about Sinopec.
Yeah, that one I got. 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%. Depending on the free cash flow this year and next, and the following years, the role is quite straightforward. This year, we're expecting a payment, within FY 2021, say EUR 120 million, EUR 100 million, depending on what the macro will do. Next year, it's not necessarily payable in Q1, we'll look at what the cash flows for 2022 look like, 30% of the free cash flows will be distributed out sometime during next year.
Thank you. About the first quarter payment to 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. 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 payment. We have quite a flexibility on timing of payment. Within 2022, it should be about 30% of the free cash flows.
Understood. Thank you.
Thank you.
Your next question comes from the line of Michele Della Vigna from Goldman Sachs. Please ask your question.
Thank you. 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. Then secondly, I was wondering if you had a chance to start looking at your business through the lenses of the EU taxonomy, and if you have an early indication of what percentage of revenue and CapEx will be taxonomy compliant for you. Thank you.
Thank you, Michele. On the Coral security issues, largely this is well offshore, and therefore, we believe outside the current insecurity. Clearly shore bases exist, but in places where I think security is better guaranteed. 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. At this stage, no update on the EU taxonomy.
Thank you.
Thank you. Your next question comes from the line of Jason Kenney from Santander. Please ask your question.
Yeah, thanks. Going back to Brazil and maybe a couple of the earlier questions. Is the Brazil renewable asset base going to be consolidated or non-consolidated? Were you treated differently from the Iberian renewable business? What kind of CapEx do you think is needed to build out that Brazil solar 2025? If I may, obviously you're looking at asset rotation in renewables, and you've got this target of 12 GW by 2030. Am I best to assume around 50% of that would be net capacity for Galp 2030? Thanks.
Thank you, Jason. I think firstly, the way we're actually approaching Iberia as well, so the 1 GW we've essentially added to the original ACS deal, plus Brazil, is that in the first instance, we develop it. Then only after the COD, when it's online, that we will sell down and deconsolidate it. That is our current modus operandi. Clearly we will also finance these projects. I think that's the way we will go about those projects. The CapEx renewables costs have gone up a little bit globally in the last six, nine months. Yeah, I won't give you any clear guidance, but anything between EUR 500,000 and EUR 700,000 per megawatt would be in the ballpark of how much it costs to develop these projects. We hope to get 65%-70% or more financing as well. The equity contribution is far lower.
I think that also answers the asset retail. Yeah, the 12 GW. We talked about essentially a dilution of 50% in our portfolio on the 12 GW position. We maintain that. I think this is all going to be based on opportunities on being able to maintain the deconsolidation. When we can rotate it, so the timing of it, when we can rotate those assets that we've derisked them significantly, that we can sell down to a strategic investor in order to leverage up our own returns. I don't want to give any firm indications when we're going to do it, how we're going to do it.
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 investments.
No, that's great. Just to clarify, the 500,000-700,000 was dollars?
Euros.
Oh, euros. Okay, thank you.
Yep.
Your next question comes from the line of Ignacio Domenech from JB Capital. Please ask your question.
Yes, good afternoon, and thank you for taking my questions. I have two. 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? My second question is on renewables. I think you mentioned generation was impacted by a transformer upset. My question is, when do you expect this issue to be reverted? If you would expect any compensation to this impact. Thank you.
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 MW that have been out of capacity. We're on the verge of putting 65 MW back in online to compensate for that. Essentially, a 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. We have new transformers arriving to be installed 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. 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. 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. Our current best estimate is that we will be spending around $10 million-$12 million on those repairs. That will translate into the cash cost. I guess the best guidance I can give you today is that at fourth quarter, you will see it around $3 per barrel, as 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. All work is that this is completed during this quarter. Thank you.
Thank you.
Your next question comes from the line of Raphaël Dubois from Societe Generale. Please ask your question.
Hello. Thank you very much for taking my questions. I have two 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? 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 the solar capture price that you assume as well? Thank you.
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 trading at about EUR 57.
It is currently at 54, I think. Given where we are today and where we stand, I would say it should get a bit better.
Okay.
It is incredibly volatile, so it's very hard to call the shots on what December 31st. This is a daily mark-to-market number. It varies every day. Thank you.
Thank you.
Thank you.
Hi, Raphaël. Yeah, just on this renewables question. At the moment, well, in the Q3, we enjoyed about EUR 110 per megawatt hour as a solar capture price. Our generation capacity comes down in Q4, as we get less sun. We will have about an extra 100 MW available online to enjoy whatever sun we do get in the fourth quarter. 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. We had the extra 20%, that would have been somewhat higher. That's the current position we are in.
Okay. Thank you very much.
Your next question comes from the line of Matt Lofting from JP Morgan. Please ask your question.
Hi. Thanks for taking the questions. Two, if I could, please. First is, I wanted to come back to the operational outlook in pre-salt 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 to work through before you get back to the normalized 5,000 barrels a day, plus, minus of annual maintenance effect that, Thore, I think you referenced earlier. Then secondly, just on price realizations in the upstream. We've seen a wider average oil and gas realization discount to headline Brent 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 looking 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? Thank you.
If I can just start, and I'll hand over to Thore to add on the Brazilian outlook. We did quite a full analysis of what we produced this year versus what we'd hoped to produce this year, and to try and understand what the key issues for the shortfall were. 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 workover 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 stress corrosion, cracking, corrosion of risers. 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.
There's the overall availability level of the various FPSOs that Thore was alluding to. Lastly, there's the 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. I think there's some good news below the wellhead in terms of the reservoir itself. It's these compounded issues that we have above the wellhead that Petrobras are working through. Any more to add, Thore?
I think, Andy, on the maintenance, I think you covered it well. Actually, to sum it up, 50% of the shortfall we have seen this year is due to delays in well connections, and then there's another 20% that is related to delays in well workovers. That really is capturing the majority. It actually has been slightly positive what have happened on the issue of stress corrosion. 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 expectation. Hopefully, I'm 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. The discounts 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. We will stay with the sort of same guidance that we have given you, but expect it to be for this quarter in the area of $8-$10 per barrel as a discount overall. That's factored in, which is very important what Andy also said in his speech in the beginning, that our gas prices in Brazil for the associated gas is actually capped at $55.
There's a limit to how much we can get on the gas side. However, that ends by the end of this year. 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 a higher margin on that. Thank you.
Your final question comes from Anish Kapadia from Palissy Advisors. Please ask your question.
Hi. Yes, just had one question remaining. I think you touched on it slightly. We are seeing evidence of quite strong inflation, and it could be quite persistent inflation in the market. I am thinking about that both from the raw material side of things, but also the potential for higher inflation and higher interest rates going forward. I was just wondering if you could cover the impact of that, in particular on the renewables business, of those higher import costs coming through. Also from a financing perspective and a returns perspective of how you think that higher inflation and higher interest rates could potentially impact that business. Thank you.
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. We've largely de-risked, particularly with the 2.9 GW that we have in that particular deal. 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. As a result, that feeds into what we also see, particularly at the moment, is clearly pretty high solar capture prices. I think these things have their own balance to them. We have pretty strong position in that we've de-risked the construction costs in our deal with ACS.
Filipe, do you want to talk a bit about the interest rates and how exposed we are to that?
It's because we project finance, the banks ask us for a very significant proportion of the funding to be swapped fixed rate. We're fairly hedged on the funding cost. We're fairly hedged through the EPC contract we've signed with ACS. We are seeing unit CapEx prices going up. Everything is becoming more expensive. Access to land, interconnection, equipment. 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. Also to be seen how many of those projects will actually get funding and get off the ground. We'll see less projects being built, more challenge 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.
Net-net, this is not necessarily bad for the projects in the short term. In the longer term, well, we'll see. Galp is mostly hedged. Thank you.
Thank you.
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 really hope to meeting you in person soon. Have a great day and a productive earnings season.
That does conclude our conference for today. Thank you all for participating. You may now disconnect.