Galp Energia, SGPS, S.A (OTCPK:GLPEF) Q1 2022 Earnings Conference Call May 3, 2022 6:30 AM ET
Otelo Ruivo - Head of IR
Andy Brown - Vice Chairman of the Board and CEO
Filipe Crisóstomo Silva - CFO and Executive Director
Thore Ernst Kristiansen - COO of Production and Operations and Executive Director
Georgios Papadimitriou - COO Renewables and New Business
Teresa Abecasis - Executive Director and COO Commercial
Conference Call Participants
Oswald Clint - Bernstein
Joshua Stone - Barclays
Sasikanth Chilukuru - Morgan Stanley
Michele Della Vigna - Goldman Sachs
Alessandro Pozzi - Mediobanca
Biraj Borkhataria - RBC
Ignacio Domenech - JB Capital
Matt Lofting - J.P. Morgan
Raphael Dubois - Societe Generale
Good morning and thank you for joining us today on Galp's First Quarter 2022 Results Presentation. Today, Andy will provide an overview of our quarterly performance and key strategic developments. Then, Filipe will take us through the quarter financial results. At the end, we are happy to take your questions, where Filipe and Andy 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 refers to estimates and actual results may differ to factors included on the cautionary statement at the beginning of our presentation, which we advise you to read.
I would now hand over to Andy.
Thank you, Otelo, and good morning, everyone. Welcome to the Galp's Q1 results call. It's now just over a year since I started as CEO. What a year it's been. A year that's been unprecedented in our industry. And this quarter Galp delivered strong operational performance and a good set of results.
Firstly, I'd like to address the war in Ukraine. I want to reiterate that Galp supports the Ukrainian people and their war with Russia. We are proud to have been the first European integrated energy company to suspend all purchases of Russian products. We recognize these restrictions might limit refining throughput in Finnish, if we do not secure alternative supplies of Vacuum Gas Oil. But I'm also proud of Galp's response to the humanitarian needs of those Ukrainian people most in need. Galp is both donating money and fuel, as well as supplying energy and support to refugee centers across Portugal. And in total, our commitment to humanitarian support totaled €6.5 million, up to this point.
The first quarter in 2022 was a strong quarter in terms of operational performance, but also strategy execution. Upstream production is up 5% year-on-year and refinery system utilization above 90%. Commercial sales are increasing and we have achieved increased capacity and availability in renewables. The improved macro conditions, namely rising oil price and all product cracks were a big help. And Galp enjoyed higher price realizations in Upstream, refining margin uplifts and also benefited from high solar capture prices.
Galp delivered an RCA EBITDA of €869 million and an OCF of €638 million. With net CapEx very low at €122 million, which is normal for Q1, the OCF minus CapEx look strong at around €0.5 billion. Despite these strong numbers, we've had headwinds due to the spike in commodity prices. Firstly, due to a significant lag in oil supply pricing formulas in Portugal as we only pass to the [clients the] commodity price increases with some delay. But secondly, due to softness in commercial, where, in some cases, we had to bridge bulk prices and sales contracts. And thirdly, there was a working capital build due to both the value of our stock and an increase in cash in derivative margin accounts. But ultimately, net debt was flat versus the end of 2021 and net debt-to-EBITDA is now below 1. Excluding the margin account build in working capital, which is entirely temporary, net debt would already be at €1.6 billion and net debt-to-EBITDA at 0.6.
It was a very strong quarter in Upstream with working interest production up 5% as I said at 131,000 barrels a day. A lot of this is attributed to less planned shutdowns. We improved the price realization, reducing the overall implicit discount to Brent. The energy management team already secured new contracts for about 60% of our equity gas, realizing gas price is now 4-fold versus last year.Trading our oil cargoes captured some opportunities also in the quarter. Net oil realizations improving to close to parity with Brent. And all in all, our energy management team provided €60 million boost to Upstream results on top of the Brent-led increase.
Upstream EBITDA consequently almost doubled year-on-year to €803 million. And looking forward, we are sticking to flat production guidance around 127,000 barrels a day, this is because there was less planned maintenance in Q1 whilst we expect increased maintenance activities in future quarters. Please do note that, early in the year before the war, we covered around 6 million barrels of our production in a hedge at just above $80 a barrel. This corresponds to just a small part of the expected volumes for the year, about 13%. At that time, our Brent expectations was at $75 a barrel. These financial hedge provide us some stability, however, we will limit part of the upside of all [plot] prices remain at current levels.
In Mozambique, Coral execution continues to be outstanding, slightly ahead of our plan and below budget. And first gas is scheduled for the second half of the year. And we still have exciting exploration opportunities, too. We did spud Jaca in Sao Tome on the 25th of April, an ultradeep water high potential frontier exploration well that will target a new play of the cretaceous age. And in Namibia, there have been very promising discoveries on block neighboring to our position, and Galp has an 80% operator stake in PEL83. And we're now reassessing the potential of our block following the recent seismic acquisition.
In commercial, we're seeing our volumes recovering following increasing demand in Iberia and we're also increasing the client base for our gas and power activities. Nevertheless, the spike in commodity prices adds challenge to our commercial activities. We also recognized that our clients are also struggling with these price spikes. However, in some cases, we do not pass on these higher prices to the end customer, which pressures our margins, particularly in our gas and power activities. Additionally, I remind you that we're allocating cost per new businesses like the Galp Solar distributed business into commercial. Although growing fast, these businesses are not yet contributing positively to our net EBITDA. Therefore, commercial EBITDA were squeezed and down from last year. Nevertheless, we're making a lot of progress expanding our non-fuel contribution, as well as our e-mobility business. We now have EV charging network of 1,300 charges, double of what we had in Q1 2021. We plan to build to 2,000 charges in 2022 with a medium-term ambition of 10,000 by 2025. But looking forward to commercial, the summer quarters tend to be stronger, supported by further demand recovery and seasonality. And thus, we've maintain our guidance of around €300 million EBITDA after the full-year, despite the softer start.
Galp's Industrial performance is improving both in terms of safety and reliability. Refining activities delivered in the quarter a very strong contribution to results, with EBITDA of almost €90 million and more than 90% utilization. The refining environment is very strong. And Galp's Q1 refinery margin was robust at $6.9 per barrel, which included high energy and CO2 costs. We have been successful in securing VGO supplies through April. However, we may need to reduce throughput. And some diesel exports may be impacted if we don't get those VGO supplies. However, the supply to the Portuguese market is not at risk.
In refining, due to the high volatility, we took the opportunity to locking a part of our refinery margins. We've hedged 25% to 30% of our refinery production at $8 to $9 a barrel. But the strong Industrial contribution in the quarter was largely offset by a significant impact from the lag in pricing formulas, in periods of steep variations in commodity prices, customer prices structurally lag the assumed input costs, resulting in a loss of around €90 million in the quarter. So, therefore, all in all, Industrial & Energy Management EBITDA was almost neutral given this one-off effect. The price lag offsetting the strong contribution from refining.
Although quarter 1 wasn't particularly impact, we continue to deal with persistent restrictions from natural gas and LNG sourcing. And we're deploying mitigation measures such as lowering own consumptions in the refinery system, leading to the higher energy costs there. We expect to continue to have limitations on the gas front in the coming quarters. We are, however, actively pursuing new gas sourcing options. Venture Global in U.S. has started up and we will start receiving gas from this project next year. We're also looking into our industrial low-carbon projects. We sanctioned a 2-megawatt electrolyzer project in Q1. This is the kind of pilot to test and accelerate learning curves for our gray to green hydrogen ambitions in Sines. We also continue advancing the 2 remaining larger scale 100-megawatt green hydrogen projects, as well as our HVO project.
In renewables, we had a strong performance in the quarter. With generation increasing 27% year-on-year demonstrating improved availability, we delivered €30 million pro forma EBITDA, a strong result for solar and winter months. We started out 50 megawatts of new capacity in March and another 150 megawatts in Spain in April. We now have close to 1.2 gigawatts under operation under full merchant conditions. And we're well on track to deliver 200 megawatts more this year, reaching the target of 1.4 gigawatts by year-end. We are happy with the pace which we're expanding and diversifying the portfolio of renewable opportunities. I will touch on that in a minute.
In terms of regulation, just last week, the European Commission approved a cap on gas prices to cut electricity prices here in Iberia, which will limit power price in Iberia for 12 months. It will reduce the revenues of renewables, but we do recognize this is also an important measure to protect customers. We're also making progress on new businesses, namely our project in the battery value chain. We selected Setubal as the location for the Aurora joint venture lithium conversion unit. This location was selected due to strong logistics, nearby customers for our byproducts and the availability of skilled labor.
Let me take the opportunity to provide some insight into the recent renewable portfolio additions that will be important to support our targets. We have just doubled our renewable funnel now at almost 9.6 gigawatts after the addition of 4.8 gigawatts in Brazil announced today. We acquired a selection of projects at different stages maturity all in a relatively early stage of development, although a good portion could reach ready-to-build, RTB, in 2022 and 2023. These projects have little upfront spending and most of the payments are still subject to execution milestones. These solar projects are located strategically north and south across the Brazilian solar belt. We're also diversifying technologies acquiring the rights of a 216-megawatt onshore wind project located in the north of Brazil. We're starting to have material options in the portfolio, making the case more robust to achieve our 2025 target of 4 gigawatts. These options allows us, not only to meet our targets, but also to be selective and high-grade returns. So, we're progressing on the growth of well established businesses, as well as on the low carbon front.
Let me end by reiterating what we announced in February regarding our distributions. We secured the approvals at the AGM on the 29th of April to pay the remaining €0.25 per share of the €0.50 per share related with 2021, but also to buy and cancel our own shares. So everything is set for the €150 million buyback program related to 2021 which should start right after the €0.20 cash dividend payment in a couple of weeks' time. We are committed to delivering compelling distributions. And while I look to the remaining year, I see Galp with stronger than initially expected adjusted operating cash flows, and 1/3 of which we expect to distribute to our shareholders.
I will now pass the floor to Filipe, who will cover the financials of this quarter. Filipe?
Filipe Crisóstomo Silva
Thank you, Andy. Good morning. Quickly on the Q1 financial results and I'm on Slide 13. So the Group EBITDA was strong €869 million, now with a overwhelming contribution from Upstream, and this is given the higher production and, of course, higher Brent prices. Commercial EBITDA of €56 million reflects seasonality and the pressured price environment in the market. Our commercial EBITDA also includes Galp Solar and Flow which migrated this year from renewables and new businesses. EBITDA for Industrial & Energy Management was only €2 million, but here we have, on the one hand, a robust refining contribution, €90 million, now supported by refining margins and the full availability of the system.
On the other hand, non-refining activities, which includes different items, but the highlight here was this €90 million in a negative time lag effect. Now, this reflects the different pricing periods between how we value our input costs and the pricing at which we supply to our clients. So most of the oil products we sell in Portugal have week before or even month before average pricing formulas. Now with the sudden commodity price increases, as we saw during Q1, our inability to reprice fast enough creates this drag. Now, if macro conditions remain stable, we don't expect time lag impacts going forward.
On renewables, our assets are not consolidated, as you know, so we use this pro forma EBITDA to highlight how well this business is doing. So pro forma EBITDA was €30 million, capturing the strong wholesale power prices and higher generation capacity and good irradiation during this first quarter.
On Slide 14, now EBIT has a €120 million impairment related to exploration and appraisal assets in Brazil. Now, these assets we have impaired had no contribution to our production guidances. Associates, the contribution was supported by the solar operations, while financial results account for the usual net interests and operating leases and interest on operating leases.
Taxes reflect the increased contribution from Upstream. Now, do keep in mind the impairments are not tax deductible for special participation tax purposes in Brazil. So this explain the higher-than-expected implicit tax rate.
Finally, our net income was €151 million under RCA. Under IFRS, net income was minus €14 million reflecting significant mark-to-market swings related with the derivatives we have in place.
Now, if I move to the cash waterflow on Slide 15. So starting with operating cash flow of €638 million, OCF is really the metric we focus on. It reflects the underlining fundamentals of our business, while CFFO includes volatile items such as special items, inventories and working capital movements. So, this quarter CFFO includes another material working capital build, while not unlike our peers given the spike in commodity prices. However, in addition, our working capital includes €224 million of build in our margin accounts from the increased gas price forward in Europe. So, at the end of the quarter, we had some €850 million sitting in margin accounts and this should entirely reverse throughout the year.
Net CapEx €122 million in cash terms, so this is CapEx we've paid out. So it's lighter than the €188 million economic CapEx which you will find in our report as well. So the difference is due to different timings between billings and payments. So all in all, free cash flow was a positive €30 million, net debt was stable against year-end at €2.4 billion, and net debt-to-EBITDA just under 1x or 0.6x if you exclude the cash sitting in margin accounts.
For the 2022 outlook on Slide 16. So on Upstream, we keep unchanged our production guidance. So this is in line with last year, but expect stronger Brent prices, of course. So, bear in mind that as part of our Group risk management decisions, we have around 6 million barrels of oil production locked in at about just over $80 per barrel. So about 13%, 1-3%, of what we produce until year end will not capture Brent prices over $80, so we only keep 87% of the upside.
Commercial is expected to maintain the planned contribution. Refining, after several really tough years, is seeing strong cracks, especially in middle distillates. And here, as well we have hedged part of the throughput for the rest of the year at about $8 to $9 per barrel. And energy management should see its contribution limited by gas supply constraints. Renewables are expected to capture these favorable environment and we will see new capacity come online in Iberia. We will, however, keep monitoring potential regulatory changes. So overall, under these circumstances, our guidance of €2.7 billion of EBITDA and €2 billion of OCF for 2022 may seem a bit light. But given the very high volatility out there, we think it is way too soon to change our full-year guidance. Our investment plans remain unchanged, with CapEx closer to €1 billion as we reach peak CapEx in Bacalhau and we increase the pace of our renewable developments. And the financial position is robust. Net debt-to-EBITDA is expected to be well below 1x by year-end.
[Operator Instructions] Your first question today comes from the line of Oswald Clint from Bernstein.
Two questions. The first one on, just on Brazil and the Upstream, I've noted some encouraging reports from the regulator that the offshore is now fully staffed and getting up to 100% on the platforms across the basin. I know that you -- I think you came into the year pretty conservatively in terms of operations, logistics. And I think you talked about 85% FPSO utilization. You're reiterating again you've said a few times this morning, your volume guidance for 2022. But I wonder given all of that, is our -- at least the operational environment logistics it is -- is it starting to ease and potentially look a little bit easier for you as you look out over the next year or 2 would be the first question?
And then, secondly, on the renewable deal this morning, pretty sizable, no real cash outflow, no real CapEx, you said, but may be something is ready '23. How does that square up then with the CapEx 2024, 2025, 1/3 of the €1 billion of CapEx into renewables, does this slot into that? Or do we need to see some of that renewable CapEx stepping up in, let's say, 2024, 2025, please?
So I have my colleagues here. I mean, obviously, firstly, I'm going to ask Thore to talk a bit about the Brazilian Upstream and how we're working with Petrobras and operational excellence. And then, obviously, to ask Georgios to talk about the renewable deal in Brazil and how many projects can we see coming through to ready-to-build and how we will see the cash contribution going out as we build our portfolio. So, Thore, first to you.
Thore Ernst Kristiansen
Yes, clearly we are actually seeing now that COVID restrictions, which have really impacted the operations over the last 2 years are becoming less severe, so that we are able now to bring POB up to normal levels. That means that the backlog of maintenance that we certainly have built over the last 2 years can now start slowly to be decomposed. It will take some time. And for us it is too early to factor anything of that into the 2022 numbers. So we are maintaining our guidance for this year. We had a very light first quarter maintenance program that will increase during this year. So that's the basis for why we are maintaining the guidance for the year.
Thank you for the question on renewables. We are indeed maintaining our allocation, the CapEx allocation guidelines in the medium-term. It is a sizable deal but, as Andy said, we're talking about options that this deal increases our optionality on selecting exactly where to place our CapEx in any given year. So we're looking at Brazil now as a candidate for CapEx in 2023, 2024. But as I said before, we are maintaining the allocation as we have discussed in the past months.
The next question comes from the line of Joshua Stone from Barclays.
Two questions, please. Firstly, just on the refining business, you talked about the Vacuum Gas Oil replacement and potential run cuts in May if you can't find alternatives, maybe just share what alternatives are you looking at and how likely is it -- does these run cuts will happen do you think and how long lasting could it be? Are there signals and maybe there's some other alternatives you can find later on?
And then secondly, on the gas sourcing restrictions in the Energy Management business, which has seemed to be persisting. Can you just say how much of an impact that's having on the business today? And how soon do you think you might be able to find alternative gas supplies to help mitigate the issue?
Let me start by talking a bit about the gas sourcing and I'll hand over to Thore to talk a bit about the refining and the VGO limitations and what the impacts may be to the overall throughput. Yes. So we are not receiving the fully contracted volumes from our gas suppliers, but we have agreed the schedule up deliveries. And we agree that scheduled deliveries coming into the year. We've done a number of things like we are not taking that gas, which is obviously attractively priced into our refineries. So we are obviously using -- actually we're using naphtha to crack the hydrogen at the moment. So we've taken some provisions. And I think what I said and I just need to flag that, we were able to manage Q1. We were able to manage the balance of our gas supplies and our commitments to our customers. Clearly, as we look at the coming quarters, we have to continue to work hard, being able to make those balances work.
Now, we're not in a position, so in Q4 last year, we did go and we bought additional volumes at spot prices and that did create some losses for us in terms of the positions that we have with our customers. So we avoided that in Q1 and we will continue to try to avoid it in the coming quarters. But it still -- it looks tight and I just needed to flag that to all of the shareholders.
So, Thore, can I just hand over to you to talk a bit about the Vacuum Gas Oil. So let's just put in context in terms of the volumes and what we're looking at.
Thore Ernst Kristiansen
Actually, so far, we have done really well when it comes to finding replacement for VGO. We have been able to source VGO in the European and Middle East markets, which has meant that we, during the course of April, actually been running at full steam. And for me what is really important is that, we have been able to keep the FCC and the hydrocracker at full steam, which is sort of really the key contributors to the most valuable products right now, that being diesel and jet. And actually May is starting to look good as well. We have now started to secure quite a bit of supply for the VGO supply of May. So we are in good shape.
Also, please factor in that we are producing 50% of the VGO ourselves in the current set-up, actually now with slightly more because we also have a FCC slurry product that actually just recently came into operation. So we are well covered, and as was said in the opening remarks from Andy, that's why we are very confident that we will continue to be able to supply Portugal with all needs. But, of course, we want to do more, and we would like to really to capture these opportunities that are in the market right now, and which we indeed are doing. And so far, April has gone very well and May looks also to work out very well. And we have already started to look into June and also see that we are able to capture opportunities in June.
The next question is from the line of Sasikanth Chilukuru from Morgan Stanley.
I had 2 please. The first was regarding the hedging of the 6 million barrels at $80 per barrel and some clarifications related to that. Just wondering if it was possible to clarify when these hedges were taken? How much is left for the remaining 3 quarters in 2022? And how much of this had been realized already in 1Q? I'm a bit surprised given this was not mentioned with the full-year results back in February. As a result, if you could remind us on the hedging policy in the Upstream and the rational behind taking these hedge positions, and that would be quite helpful.
The second one was, if you could provide color on the current refining environment on how this is translating to Galp? If you could highlight the current refining margin levels that you're seeing right now or have seen for April? On Slide 16, you've noted upside to your 2022 outlook from current macro conditions. Just wondering what refining margins were included in this upside case scenario?
Sasi, let me first -- I'm going to ask Filipe to talk a bit about when we took the hedges out and just to give some color around that.
On the refinery environment, I don't think we want to give you a blow by blow updates on the refinery margins. I can say it's well into double-digit at the moment. So it's a very healthy position. So that's really all I want to say at this stage, because I think it's too early to declare numbers for the second quarter.
But Filipe on the Upstream hedge?
Filipe Crisóstomo Silva
Sasi, so the hedges were taken early this year. Of course, we buy the hedges at market prices, so that's what the market was looking for calendar 2022. 6 million for the entire year, so from Q2 onwards, we have 25% of that has lapsed. We have within our Upstream EBITDA about €25 million, so that's about 3% of Upstream EBITDA was effectively given up by selling at $80 and not at a 100-ish. So that's [where it was]. 4.5 million barrels left until year end at 80%.
The next question is from the line of Michele Della Vigna from Goldman Sachs.
Michele Della Vigna
I wanted to ask you 2 questions if I may. The first one is about your commercial margins in the second quarter. There is a lot of government pressure to keep prices lower. One of your competitors in Iberia has announced a major discount. I was wondering, what should we expect for the second quarter and how much could that pressure amount to?
And secondly, we've seen a bit of news flow about Angola with reporting of the potential exit from that country from your side. I was wondering, these are non-operated assets, but they are very cash generative. If you decided to exit, how would you think about recycling that capital between incremental CapEx in areas like low carbon or potentially an increase of the buyback?
And I have to -- there is obviously a lot of pressure and a lot of focus on the margins in our retail business. I'm going to ask Tore to talk a bit about that. I have to say that we did introduced some discounts ourselves. I think they were not material in terms of what we can see in the Q1 numbers. But we do track that very closely and I think there is some suspicion in somehow we are not passing on all the discounts and things to the customers. But I think we're really just have to make sure everyone realizes, not just oil price, it's also exchange rate between the dollar and the euro and it's refinery margin is actually affecting the input cost from our commercial business. And if you look at the Industrial & Energy Management and the Commercial business, which is essentially our Iberian business, we didn't come away with a lot of money in terms of our position in Iberia this quarter. So I think a lot of the pressure were -- it's not a real kind of somehow we're profiting from the current situation, which I think some would like to believe. But it's probably worth me asking Teresa, put more color on the margins.
Sure, and thanks for the question. It is actually true that there has been a lot of pressure from the regulation on the margins. Actually, the first quarter unit margins for the oil business have actually performed above 2021 values. In the B2C segment, the unit contribution in Portugal has increased at year-on-year 10%. This is backed also by the way we have managed our discount policy and we did in 2021 had the more aggressive discount policy. So we were able to secure part of the net margin in Portugal. In Spain, the unit contribution margins, despite the discounts that were announced, are aligned with the previous year. It is worth mentioning in the Commercial business, the B2B margin has also fallen somewhat, because of this pressure 4%. So we saw a decrease in the margin at 4%, but we did see a good recovery in aviation, which allowed us to be positive here, too.
Okay. And so, Michele, let me just address then Angola news. I think we have no comment. And when we have any news, we will tell you. And we will tell you if we did make any moves there, what we would do with the money. But at this stage there is no comment because we've got nothing to say really.
The next question is from the line of Alessandro Pozzi from Mediobanca.
I have a couple of questions. The first one, going back to the hedging. I was wondering whether the hedges that we're taking as a just an opportunistic move to take advantage of the perceived, let's say, commodity prices at that time, or whether you have a more structured policy in place whereby every year, for example, in Upstream that you want to hedge 10% or more of the production? Because if that's the case, if it's just an opportunistic move, I was wondering whether you are going to increase the hedges for maybe for the rest of the year or may be looking at 2023 as well the same thing in refining, of course, with the refining margin double-digit, I was wondering whether you are going to increase the hedges there as well?
And the last question, in Upstream, I was wondering if you can give us maybe an update on Mozambique, the security situation is definitely improving the macro also and I was wondering if you can give us an update on where you are in evaluating your assets there?
Okay. May I ask Filipe to talk a little bit about our hedging policy. And then I'll ask Thore to address the Mozambique situation, that obviously our key focus at the moment is startup of Coral. But Filipe?
Filipe Crisóstomo Silva
Alessandro, on refining margins, it is opportunistic, we've had so many really bad years over the last many years that when we see the opportunity to lock in at $8, $9, it looked very attractive. But what really drives the risks of Galp because of the concentration of our portfolio is Upstream, and it's Brazil, of course. So Brent prices have a very large impact in the overall cash flow profile risk and we discussed this at length with our risk committees. So we started the year with an expectation that Brent price would be about $75. So when we see an opportunity to lock in calendar 2022 at a bit over $80, then we'd protect a bit the downside. So this is a structural decision given that, we do not enjoy a vast geographical or portfolio of assets across the globe. It is very concentrated, so we want to protect downside.
Now, you may ask, why haven't you done options and kept all the upside? Why did if downside protection is so important? But at the time, options were very expensive. So volatility embedded in the price of oil reserves. So we consciously took the decision to give up a bit of the upside to get some downside protection. Are we planning to do more? No, not really. And we think, both February 24, we have a different world, we have probably the biggest disruption in energy market we've seen in decades. So we think that structurally this is going to be an unhedged position for 87% of our Upstream portfolio.
Thore Ernst Kristiansen
And Alessandro, regarding Mozambique, as Andy...
Yes, on the [LNG] side, of course, yes.
Thore Ernst Kristiansen
And then regarding Mozambique, as Andy alluded to, number one priority and focus is Coral South, which is actually going extremely well. And we are looking into first gas now within the next few months into the equipment. So we are confidently maintaining as of now that we will have the first cargo in the second half of this year.
Secondly, we are continuously monitoring the security situation. As you are commenting, on the ground situation seems to be improving, the security forces in place seems to be getting a better grip on situation. So what we are doing in Area 4 is that, we are working in the partnership now to see what are the ways to further optimize the development of -- the onshore development of the field. And actually as we speak in the next few days, we will have another sort of partners meeting in order to discuss optimization options. But for now, it is too early to go back on the ground and that's why we -- our focus is to optimize the product and making it even more robust than even more competitive.
Do you have a potential timeline for an FID or is that too soon to talk about even?
Thore Ernst Kristiansen
Yes, that will be too soon, Alessandro, to do. That would be -- now we need to see real evidence on the ground before we can start to talk about that. But we are preparing and working as hard as possible to have the plans ready, so that we can push the button when the situation enables it.
The next question comes from the line of Biraj Borkhataria from RBC.
Two simple ones that would be. First one is on the split in oil and gas realizations. Could you remind us how to think about gas realizations in Brazil? Any caps in place and anything relevant there?
And then the second question is on the renewables, the new renewable portfolio also in Brazil. I gather, it's very minimal capital commitments in 2022, just wondering if you could talk about '23. And then also confirm whether you're planning to utilize project financing to development there?
Yes, indeed. So I think we're quite proud of what we've done in Brazil in the gas market. So only ourselves and one of our competitors of the 7 companies now are marketing gas in Brazil. And I think we've got some very competitive attractive contracts in place. We've got a handful of contracts in place. We are also marketing gas on behalf of one of our competitors. So I think Galp has taken a really leading position in the gas markets of Brazil. And we clearly don't want to reveal too much about the gas pricing of those contracts. But I just want to note they are 4x higher than we were getting this time last year. So this is a business where I think we're building quite a strong position in Brazil and we are now building obviously a trading position around electricity as well as gas. So I think this will become an exciting new string to our bow.
So, I think, I would then probably ask Georgios to talk a little bit then about the renewables position in Brazil, the project financing and other aspects.
Yes, the second part of your question about project finance, yes, we would of course use, there is available project finance for renewable projects in Brazil for many years now, and of course, we would use that, when we take a decision to build a project, which is a decision that we will be taking on a case-by-case basis when these options that we have acquired mature. So that will be something that we'll be discussing in the company in the next 2, 3 years. As I was saying, as these projects mature, not all of them might -- some of them might not mature, that's why we're saying we are acquiring portfolio up to a certain value of megawatts. Once they mature, we will have the decision on whether to build or not.
I think, it's worth, because it's a big announcement today just below the color around that portfolio we talked about 4.8 gigawatts or 4.6 gigawatts of peak power. We think about 0.8 gigawatts could be ready-to-build in this year. I mean, another 1.3 gigawatts next year and I think it's important, if you know the Brazilian market, 2.9 gigawatts of that portfolio has what we call the [twist] discount, which gives us a real advantage in terms of the grid tariffs that we have to pay for electricity. So this is a really attractive portfolio of projects, some of them short-term, some of them longer-term, and the majority having this twist discount, which I think is a really strong attribute.
Your next question is from the line of Ignacio Domenech from JB Capital.
Just 1 question on exploration. Your exploration campaign in Sao Tome. I was wondering if you could share with us what are the pre-drill expectations in terms of resources?
And then maybe if you could also share with us what is the latest situation in exploration in Namibia? We've seen some progress already since the latest -- since the last results. So maybe you can share some details from Namibia?
So, this is clearly 1 for Thore. I think what's exciting is this is the first sort of deep water well in Sao Tome. So this is -- this opens up the potential for a lot of opportunity, but Thore, give us some color to the exploration well.
Thore Ernst Kristiansen
Yes. Of course, we are really excited about this because this is truly frontier. It has been an area where many of the leading companies in the industry wanted to farm in. We have had been in the luxurious situation that we could choose partners. We have a very strong partner now in Shell in Sao Tome. We are drilling, we spudded on the 25th of April and moving rapidly ahead.
What is really exciting in Sao Tome is that, since it is the frontier play, and Galp is an owner, not only in Block 6 where we're drilling right now, we're also an owner in Block 11 and in 12. We actually see 10 to 12 additional prospects that then potentially could work if this works. But there is a lot of ifs there. This is frontier drilling with high probability of failure. But if it works, it can really be interesting. And I would be a little bit careful of being too precise on this first one. But it's certain where we're drilling right now could be a standalone development if it works.
On Namibia, I would like to say that we are very happy to be an 80% owner of PEL83 that is located now in a system, which is clearly has had its petroleum system proven by the Graff and Venus well. So 1 significant risk element has largely been taken out. The team is excited. We are working hard with our seismic now to do reinterpretation based on the sort of new exploration place that we now have seen in Namibia. And we think we have a good problem in our hands when it comes to our position in Namibia. And we are now exploring what to do with it going forward.
And Ignacio, just want to reiterate. I think, we have 45% in Sao Tome?
Thore Ernst Kristiansen
And operate an 80% and operator in Namibia. So for Galp, this is a -- these are really material positions which are sometimes unlike some of the other positions that we have in our portfolio across the world. So interesting.
The next question is from the line of Matt Lofting from J.P. Morgan.
Two if I could, please. First, I just wanted to come back to the earlier observations around the move on hedging more from us the philosophy perspective than necessarily the mechanics that you already explained. I think historically Galp has opportunistically hedged refining margins at times in recent years. I was a bit surprised though to see this with the hedging move around upstream oil and even taking account of the observations made earlier and the relative concentration of Galp's portfolio, et cetera. Could you just talk about the philosophical approach on hedging oil upstream going forward beyond 2020 through 2022 and whether that something that investors should expect Galp to continue to do over the medium term?
And then second, on renewables, obviously, scaling up the sort of the position in Brazil, there has been quite a bit of focus and sort of commentary recently around cost inflation in the sector, but particularly through renewables and solar. So I wondered if you could talk a bit about what you're seeing from that perspective at the moment and the comfort that you have that the company can manage that through the Brazil piece as the pipeline grows?
And I might ask Filipe to comment, but I just have to -- there is no change in policy in Galp around hedging. So I just want you to be reassured that we're not going to expose you less on a structural basis to the oil price going forward. It was an opportunity to move at a time when the market had started to look a bit softer. But we have no intention for the rest of this year to do any more hedging going forward. So just be reassured around that.
And then I'm going to ask Filipe to add anything he would like to that comment, and then ask Georgios to address a little bit about the position in the renewable business, the cost inflation, how we make sure we get a decent return for the projects once we launch them. Filipe?
Filipe Crisóstomo Silva
Yes. Matt, you asked about the philosophy. And if you look back, say, decades, most of the cash flows and cash flow risks of Galp were heavily exposed to refining. Hence, we used to do refining hedges. Now as our portfolio has shifted so dramatically into Upstream, Brent becomes the dominant force that our risks committee wants to see managed. And of course, we model all this. We model extreme scenarios, we test correlations across different businesses. What is very different today is that, you have simultaneous shifts upwards, be it in Brent, in refining margins, in the dollar and electricity prices, hence and all these are untested territory. So risk committee is, obviously, as a philosophy concerned about a very adverse macro scenarios and hedging. Most of our hedging is natural hedging when negative correlations do happen between, say, Refining, Commercial and Upstream. Of course, taxation itself serves as a buffer to free cash flow volatility hedging. But when we test all that, risk committee takes the view that a bit of a floor here and then makes sense structurally. So this is where we are.
And Matt, thanks for the question on renewables. On EPC, the question is very clear. I think from our side, I will focus, again, and I will stress the fact that we're adding optionality to the portfolio, which means that we will select the best projects returns being very much focused on the returns when we make final investment decisions. We are building the capability of the team and the partnership with the best EPC suppliers across the markets where we operate and we make sure that we have very good contracts.
On the revenue side, we see -- in Iberia, we have seen that the prices, these past few months have been, let's say, extraordinary, much higher than what we could have expected about a year or so ago. And what they have been for many, many years, which is obviously a mitigating factor in the eventual increase of EPC costs. In Brazil, we expect PPA prices to follow suit these increases in EPC prices. So all in all, and of course, as I was saying before, the investment decisions will not -- are not today or tomorrow, they're going to be in, let's say, a year at least going forward. So we will be assessing the revenue cost decision on a case by case basis being return focus and we will use the time that we have between today and then to build and strengthen the teams and have best-in-class capabilities.
If I could just add, I think in Iberia, we have been comfortable with leaving exposure to the merchant market and we've enjoyed some upsides there. So that's one. So we didn't hedge our position and take a PPA hedge, so we've enjoyed the upside of that. I think in Brazil, we're more likely to cover before we go forward with the projects with a good proportion of PPA, so that we have some clear expectation of the returns we get on the project. So, a little bit more risk averse in the Brazilian context than we are operating today in the Iberian context.
The final question today comes from the line of Raphael Dubois from Societe Generale.
Two, please. The first one is, Andy, you said during the introduction that there was now a cap on gas prices in Iberia, a cap on electricity prices, but you still reserve to merchant prices for your own production. So, can you please just confirm that your current 1.2 gigawatt of capacity is still uncapped in Iberia? That will be my first question.
And the second one is on Coral, and sorry for asking that. I understand your excitement, but we are all aware of one of your peers that are -- that is having some issues with its own FLNG. I understand these are 2 very different projects. But it would be great to hear from you, how different the 2 are? And what makes you confident that the issues encountered by this peer, you will not encounter yourself?
So, yes, can I just mention how the Iberian electric price regulation has not yet implemented, but has been -- there is an approval from the European Union for what Spanish and Portuguese governments have recommended. And that is essentially to cap -- the gas price assume to go into electricity price calculation. At the moment, a small amount of electricity is generated by gas, and electricity price across the whole portfolio is set by the very high gas price. They want to limit that to €40 to €50 per megawatt hour, which will give you electricity price between €110 and €130 per megawatt hour. Now, if that comes into effect, for us, it means we get slightly lower returns in our renewables. It's still in a way merchant because it's a cap, it's still 2 or 3x higher than we assumed when we invested in these projects. So just to give you a sense that this is a disappointment, but it's still a very attractive electricity price. But this low electricity price also helps our commercial business, because we are also selling to customers. And as I mentioned in my comments, we didn't cover all of our risk there with forward-looking PPAs. So, having a lower electricity price from the wholesale market to offer to our customers it's some benefit as well. So we are on both sides of this equation at the moment. I have to reassure you that from a renewables perspective, the less than we enjoyed in the first quarter, this is still a very attractive electricity price that will support our ongoing investments in our renewables projects in Iberia.
I might just address your second question on Coral and have a little bit of experience on what you may be alluding to in terms of 1 of our competitors in floating LNG. This is a simpler project. It is -- it doesn't have the LPG export, some of the power systems is designed differently. I think the lessons learned from that. I think kind of well embedded. I have to say that Eni as the operator has done a superb job so far to get the floating LNG Coral here to where it is today. We can never rely on the fact that there won't be some teething problems when we start that up, but if the record today is aimed to go by, we can be pretty confident about this particular unit.
Thore Ernst Kristiansen
And if I just may add actually, Raphael, we FID this in 2017 through COVID, through all the issues that has been in the market, this product is still -- it's actually 98% complete, it is ahead of plan and it's below budget, which actually makes us very excited. But, of course, you are right, these 2 months now with offshore commissioning and getting the -- all that the process that work together in -- at minus 143 degree centigrade, yes, that is a big step. But so far, it has gone really, really well and there is a real possibility that we can have first gas in this system during June and that's why we are excited. We actually also see there is some upside on the volume side, but we'll come back to that later.
I would like to hand back over to Mr. Otelo Ruivo for final remarks.
I think this concludes the call for today. As always, the IR team will be happy to help on any follow-up questions you may have. Just reach out and enjoy the rest of the result season.
Thank you very much, everyone. Thank you.