Good morning, ladies and gentlemen. Welcome to Galp's first quarter 2022 results presentation. I'll now pass the floor to Mr. Otelo Ruivo, Head of Investor Relations.
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. Filipe will take us through the quarter financial results. At the end, we're 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 refer to estimates, and actual results may differ from factors included on the cautionary statement at the beginning of our presentation, which we advise you to read. I will 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. 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 in 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 Sines if we do not secure alternative supplies of vacuum gas oil. 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. In total, our commitment to humanitarian support totals EUR 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 oil product cracks, were a big help, and Galp enjoyed higher price realizations in upstream, refinery margin uplifts, and also benefited from high solar capture prices.
Galp delivered an RCA EBITDA of EUR 869 million and an OCF of EUR 638 million, with net CapEx very low at EUR 122 million, which is normal for Q1. The OCF minus CapEx looks strong at around half a billion EUR. 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 passed the clients the commodity price increases with some delay. Secondly, due to softness in commercial, where in some cases we had to bridge spot prices and sales contracts. Thirdly, there was a working capital build due to both the value of our stock and an increase in cash in derivative margin accounts.
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 EUR 1.6 billion, and net debt to EBITDA at 0.6. It was a very strong quarter in upstream, with working inThorest production up 5%, as I said, at 131,000 barrels a day. A lot of this is attributed, though, 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 prices now four-fold versus last year. Trading our oil cargoes captured some opportunities also in the quarter. Net oil realization's improving to close to parity with Brent.
All in all, our energy management team provided EUR 60 million boost to upstream results on top of the Brent-led increase. Upstream EBITDA consequently almost doubled year-on-year to EUR 803 million. 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, while we expect increased maintenance activities in future quarters. Please do note that earlier 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 hedges provided some stability.
However, we'll limit part of the upside if oil 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. We still have exciting exploration opportunities too. We did spud Jaca in São Tomé on the 25th of April, an ultra-deep water, high potential frontier exploration well that will target a new play of the Cretaceous Age. In Namibia, there have been very promising discoveries on blocks neighboring to our position. 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, a spike in commodity prices adds challenge to our commercial activities. We also recognize that our clients are also struggling with these price spikes. However, in some cases, we do not pass on these higher prices to the anchor customer, which pressures our margins, particularly in our gas and power activities. Additionally, I remind you that we're allocating costs for new businesses like the Galp Solar distributor business into commercial. Although growing fast, these businesses are not yet contributing positively to our net EBITDA. Therefore, commercial EBITDA was 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 chargers, double of what we had in Q1 2021. We plan to build to 2,000 chargers in 2022, with a medium-term ambition of 10,000 by 2025.
Looking forward to commercial, the summer quarters tend to be stronger, supported by further demand recovery and seasonality. Thus, we maintain our guidance of around EUR 300 million EBITDA for the full year, despite this 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 EUR 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, supply to the Portuguese market is not at risk.
In refining, due to the high volatility, we took the opportunity to lock in a part of our refinery margins. We've hedged 25%-30% of our refinery production at $8-$9 per barrel. 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 EUR 90 million in the quarter. Therefore, all in all, industrial and energy management EBITDA was almost neutral, given this one-off effect. The price lag offsetting the strong contribution from refining. Although quarter one wasn't particularly impacted, we continued to deal with persistent restrictions from natural gas and LNG sourcing.
We're deploying mitigation measures such as lowering our 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 the 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 two 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 EUR 30 million pro forma EBITDA, a strong result for solar in winter months. We started up 50 MW of new capacity in March and another 150 MW in Spain in April. We now have close to 1.2 GW under operation under full merchant conditions. We're well on track to deliver 200 MW more this year, reaching the target of 1.4 GW 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 Setúbal as the location for the Aurora joint venture lithium conversion unit. This location was selected due to strong logistics, nearby customers for our by-products, 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 of 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. 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 of the AGM on the 29th of April to pay the remaining EUR 0.25 per share of the EUR 0.50 per share related with 2021. Also to buy and cancel our own shares.
Everything is set for the EUR 150 million buyback program related to 2021, which should start right after the EUR 0.20 cash dividend payment in a couple of weeks' time. We are committed to delivering compelling distributions. While I look to the remaining year, I see Galp with stronger than initially expected adjusted operating cash flows, and a third 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.
Thank you, Andy. Good morning. Quickly on the Q1 financial results and on slide 13. The group EBITDA was strong, EUR 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 EUR 56 million reflects seasonality and the pressured price environment in the market. Now commercial EBITDA also includes Galp Solar and Flow, which migrated this year from renewables and new businesses. EBITDA for industrial and energy management was only EUR 2 million, but here we have, on the one hand, a robust refining contribution, EUR 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 EUR 90 million in a negative time lag effect.
This reflects the different pricing periods between how we value our input costs and the pricing at which we supply to our clients. Most of the oil products we sell in Portugal have week-before or even month-before average pricing formulas. With the sudden commodity price increases, as we saw during Q1, our inability to reprice fast enough creates this drag. 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. Pro forma EBITDA was EUR 13 million, capturing the strong wholesale power prices and higher generation capacity and good irradiation during this first quarter.
On slide fourteen, now EBIT has a one hundred twenty 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. Financial results account for the usual net inThorests and operating leases and inThorest 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. This explains the higher than expected implicit tax rate. Finally, our net income was EUR 151 million under RCA. Under IFRS, net income was EUR -14 million, reflecting significant mark-to-market swings related with the derivatives we have in place. Now if I move to the cash flow on slide fifteen. Starting with operating cash flow, EUR 638 million.
OCF is really the metric we focus on. It reflects the underlying fundamentals of our business. While CFFO includes volatile items such as special items, inventories, and working capital movements. This quarter's CFFO includes another material working capital build. Well, not unlike our peers, given the spike in commodity prices. However, in addition, our working capital includes EUR 224 million of build in our margin accounts from the increased gas price forward in Europe. At the end of the quarter, we had some EUR 850 million sitting in margin accounts, and this should entirely reverse throughout the year. Net CapEx, EUR 122 million in cash terms. This is CapEx we've paid out, so it's lighter than the 188 economic CapEx, which you'll find in our report as well.
The difference is due to different timings between billings and payments. All in all, free cash flow was a positive EUR 30 million. Net debt was stable against year-end at EUR 2.4 billion. 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. On upstream, we keep unchanged our production guidance, so this is in line with last year. Expect stronger Brent prices of course. Bear in mind that as part of our group risk management decisions, we have around 6 million barrels of our production locked in at about just over $80 per barrel.
About 13.13% 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. Here as well, we have hedged part of the throughput for the rest of the year at about $8-$9 per barrel. Energy management should see its contribution limited by gas supply constraints. Renewables are expected to capture the favorable environment, and we will see new capacity come online in Iberia. We will, however, keep monitoring potential regulatory changes. Overall, under these circumstances, our guidance of EUR 2.7 billion of EBITDA and EUR 2 billion of OCF for 2022 may seem a bit light.
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 EUR 1 billion as we reach peak CapEx in Bacalhau, and we increase the pace of our renewable developments. The financial position is robust. Net debt to EBITDA is expected to be well below 1x by year-end. Thank you.
We will now begin the question-and-answer session. To ask a question, you'll need to press star one on your telephone. Please be advised, only two questions per person are allowed. To withdraw your question, please press the pound or hash key. Your first question today comes from the line of Oswald Clint from Bernstein. Please go ahead.
Good afternoon, everyone. Thank you. 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, you know, 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. I wonder, you know, given all of that or at least the operational environment logistics, is it starting to ease and potentially look a little bit easier for you as you look out over the next year or two?
Would be the first question. Secondly, on the renewable deal this morning, pretty sizable. No real cash outflow, no real CapEx you said, but maybe something in 2023. How does that square up then with the, you know, CapEx 2024, 2025, you know, a third of EUR 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? Thank you.
Thank you, Oswald. I have my colleagues here. I mean, obviously, firstly, I'm gonna ask Thore to talk a bit about the Brazilian upstream and how we're working with Petrobras on operational excellence. Then obviously to ask Georgios to talk about the renewable deal in Brazil and you know, how many projects can we see coming through to ready to build, and how we'll see the cash contribution going out as we build that portfolio. Thore, first to you.
Thank you, Andy. Thank you, Oswald, for the question. Yes, clearly, we are actually seeing now that the COVID restrictions, which have really impacted the operations over the last two 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 two years can now start slowly to be decomposed. It will take some time. For us, it is too early to factor anything of that into the 2022 numbers. We are maintaining our guidance for this year. We had a very light first quarter maintenance program. That will increase during this year.
That's the basis for why we are maintaining the guidance for the year. Thank you.
Thank you for the question on renewables. We are indeed maintaining our allocation, 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. We're looking at Brazil now as a candidate for CapEx in 2023, 2024. As I said before, we are maintaining the allocation as we have discussed in the past months.
Okay. Very clear. Thank you.
Thank you. The next question comes from the line of Joshua Stone from Barclays. Please go ahead.
Thank you, good afternoon. Two questions, please. Yeah, 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 that those run cuts will happen, do you think, and how long lasting could it be? You know, are there signals that maybe there's some other alternatives you can find later on? Secondly, on the gas sourcing restrictions in the energy management business, which seem to be persisting, can you maybe 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 that issue? Thank you.
Thank you, Josh. 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 impact may be to the overall throughput. We, you know, are not receiving the fully contracted volumes from our gas suppliers. We have agreed a schedule of deliveries. We agreed that schedule of deliveries coming into the year. We've done a number of things like, you know, we're not taking that gas, which is obviously attractively priced, into our refinery. We're obviously using, actually, a naphtha to crack the hydrogen at the moment. We've taken some provisions.
I think what I said, 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. You know, clearly, as we look at the coming quarters, we have to continue to work hard at being able to make those balances work. Now, we're not in a position. In Q4 last year, we did go and we bought additional volumes at spot prices, and that did, you know, create some losses for us in terms of the positions that we have with our customers. We avoided that in Q1, and we will continue to try to avoid it in the coming quarters.
It's still tight, and I just need to flag that to all of the shareholders. Thore, can I just hand over to you now and to talk a bit about the vacuum gas oil? Let's put it in context in terms of the volumes and what we're looking at.
Thank you, Andy, and thank you, Josh. Actually, we have done really well when it comes to finding replacement for VGO. We have been able to source VGO in the European and the Middle East market, which has meant that we, during the course of April, has actually been running at full steam. 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. 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.
We are in good shape. Also please factor in that we are producing 50% of the VGO ourselves in the current setup. Actually, it's now slightly more because we also have a FCC slurry product that actually just recently came into operation. 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 its needs. 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. So far April has gone very well and May looks also to work out very well.
We have already started to look into June and also see that we are able to capture opportunities in June. Thanks.
Thank you.
Thank you. The next question is from the line of Sasikanth Chilukuri from Morgan Stanley. Please go ahead.
Hi, thanks for taking my questions. I had two, please. The first was regarding the hedging of the 6 million barrels at $80 per barrel. 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 rationale behind taking these hedge positions, 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. Thanks.
Thank you, Sasi. I'm gonna 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, you know, I don't think we wanna give you a blow-by-blow update on the refinery margin. I can say it's well into double digit at the moment. So it's a very healthy position. 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. Filipe, on the upstream hedge.
Hi, Sasi. 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. EUR 6 million for the entire year. From Q2 onwards, 25% of that has lapsed. We have within our upstream EBITDA about EUR 25 million. That's about 3% of upstream EBITDA was effectively given up by selling at $80 and not at $100-ish. That's where it was, 4.5 million barrels left until year-end at $80. Thank you.
Thanks.
Thank you. The next question is from the line of Michele Della Vigna from Goldman Sachs. Please go ahead.
Thank you very much. I wanted to ask you two questions, if I may. The first one is about your commercial margins in the second quarter. There's 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? Secondly, we've seen a bit of news flow about Angola with reporting of a potential exit from that country from your side. I was wondering, these are non-operated assets, but they're 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? Thank you.
Thank you, Michele. You know, I have to say there is obviously a lot of pressure and a lot of focus on the margins in our retail business. I'm gonna ask Thoresa to talk a bit about that. I have to say that we did introduce some discounts ourselves. You know, I think they were not material in terms of what we can see in the Q1 numbers. But we do track that very closely. I think there's some suspicion that somehow we are not passing on all the discounts and things to the customers.
I think we really just have to make sure everyone realizes it's not just oil price, it's also exchange rate between the US dollar and the euro, and it's refinery margins actually affecting input costs to our commercial business. As you look, you know, if you look at the industrial and 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. You know, I think a lot of the pressure we're under, you know, is not a real kind of somehow we're profiting from the current situation, which I think some would like to believe. It's probably worth me asking Thore to put some more color on the margins.
Sure. 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 year-on-year 10%. This is backed also by the way we have managed our discount policy, and we did in 2021 had a more aggressive discount policy. 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%. We saw a decrease in the margin of 4%, but we did see a good recovery in aviation, which allowed us to be positive here to...
Okay. Michele, let me just address then Angola and news. I mean, I think we have no comment. When we have any news, we will tell you. We will tell you if we did make any moves there, what we would do with the money. At this stage, there is no comment, 'cause we've got nothing to say really. Thank you.
Thank you. The next question is from the line of Alessandro Pozzi from Mediobanca. Please go ahead.
Hi there. I have a couple of questions. The first one, going back to the hedging. I was wondering whether the hedges were taken 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, now assuming you want to hedge ten percent or more of the production. Because if that's the case, if it's just an opportunistic move, I was wondering whether you're going to increase the hedges for, maybe for the rest of the year or maybe 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. The last question on upstream, I was wondering if you can give us maybe an update on Mozambique. The security situation is definitely improving, the macro also. I was wondering if you can give us an update on where you are in evaluating your assets there. Thank you.
Okay, thank you. May I ask Filipe to talk a little bit about our hedging policy? Then I'll ask Thore to address the Mozambique situation. I obviously, you know, our key focus at the moment is the startup of Coral. Filipe.
Listen, on refining margins, it is opportunistic. You know, 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. What really drives the risks of Galp, because of the concentration of our portfolio, is upstream, and it's Brazil, of course. Brent prices have a very large impact in the overall cash flow profile risk. We discussed this at length with our risk committees. We started the year with you know an expectation that Brent price would be about $75. When we see an opportunity to lock in calendar 2022 at a bit over $80, then we protect a bit the downside.
This is a structural decision given that, you know, 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? If downside protection is so important. But at the time, options were very expensive, so volatility embedded in the price of our reserves. 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. We think post-February 2024, we have a different world. We have probably the biggest disruption in energy market we've seen in decades. We think that structurally, this is going to be an unhedged position for 87% of our upstream portfolio.
Thank you.
Alessandro, regarding Mozambique, you know,
Yeah. We are on the energy side, of course. Yeah.
Regarding Mozambique, you know, as Andy alluded to, number one priority and focus is Coral South, you know, which is actually going extremely well. We are looking into first gas now within the next few months into the equipment. We are confidently maintaining as of now that we will have the first cargo in the second half of this year. Secondly, we're continuously monitoring the security situation. As you are commenting, the on-the-ground situation seems to be improving. The security forces in place seems to be getting a better grip on situations. 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.
Actually, as we speak, in the next few days, we will have another sort of, you know, 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 our focus is to optimize the product and making it even more robust and even more competitive. Thank you.
Do you have a potential timeline for an FID or is it, is that too soon to talk about even?
Yeah, that would be too soon, Alessandro, to do. Now, we need to see real evidence on the ground before we can start to talk about that. 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.
Okay.
Thank you.
Thank you very much.
Thank you. The next question comes from the line of Biraj Borkhataria from RBC. Please go ahead.
Hi. Thanks for taking my questions. Two simple ones, hopefully. The first one's on the split in oil and gas realizations. Thank you for that. Could you remind us just how to think about gas realizations in Brazil? Any caps in place and anything relevant there? The second question is on the renewables, the new renewable portfolio, also in Brazil. I think I gather it's very minimal capital commitments in 2022. Just wondering if you could talk about 2023 and then also confirm whether you're planning to utilize project financing to for the development there. Thanks.
Thanks, Biraj. Yeah, indeed. You know, I think we're quite proud of what we've done in Brazil in the gas market. It's only ourselves and one of our competitors that, out of the 7 companies, now are marketing gas in Brazil. I think we've got some very competitive, attractive contracts in place. We've got a handful of contracts in place. We're also marketing gas on behalf of one of our competitors. You know, I think Galp has taken a really leading position in the gas markets of Brazil. You know, we clearly don't want to reveal too much about the gas pricing of those contracts, but just want to note they're 4 times higher than we were getting this time last year.
This is a business where, you know, I think we're building quite a strong position in Brazil, and we're now building obviously a trading position around electricity as well as gas. I think this will become an exciting new string to our bow. I think I would now probably ask Georgios to talk a little bit then about the renewables position in Brazil, the project financing and other aspects.
Thanks, Andy, and thanks, Biraj, for the question. Yes, the second part of your question about project finance, yes, we would of course use this available project finance for renewable projects in Brazil for many years now. Of course we would use that when we take a decision to build a project, which is a decision that we'll be taking on a case-by-case basis when these options that we have acquired mature. That will be something that we'll be discussing in the company in the next two, three 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're acquiring in a portfolio up to a certain value of megawatts.
Once they mature, we will have the decision on whether to build, or not.
I just think it's worth, because it's a big announcement today, just to put a little bit of color around that portfolio. We talk about 4.8 gigawatts or 4.6 gigawatts of peak power. You know, we think about 0.8 gigawatts could be ready to build in this year. I mean, another 1.3 gigawatts next year. I think it's important if you know the Brazilian market. 2.9 gigawatts of that portfolio has what we call the TUST discount, which gives us a real advantage in terms of the grid tariffs that we have to pay for electricity.
This is a really attractive portfolio of projects, some of them short term, some of the longer term, and the majority having this TUST discount, which I think is a really strong attribute.
Thank you. Your next question is from a line of Ignacio Domenech from JB Capital. Please go ahead.
Thank you. Good afternoon. Just one question on exploration, the exploration campaign in São Tomé. I was wondering if you could share with us what are the pre-drill expectations in terms of resources. 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 last result. Maybe you can share some details from Namibia. Thank you.
This is clearly one for Thore. I think what's exciting is that this is the first sort of deep water well in São Tomé. This opens up the potential for a lot of opportunity. Thore, give us some color to the exploration well.
Yes. Thank you, Ignacio, for your question. 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 been in a luxurious situation that we could choose partners. We have a very strong partner now in Shell in São Tomé. We're drilling. We started on the 25th of April and moving rapidly ahead. What is really exciting in São Tomé is that since it is a 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.
There's a lot of ifs there. This is frontier drilling with a high probability of failure. If it works, it can really be inThoresting. I would be a little bit careful of being too precise on this first one. It's certainly 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 PEL 83 that is located now in a system which is clearly has had its petroleum system proven by the Graff and Venus wells. The team's excited.
We are working hard with our seismic now to do reinterpretation based on this sort of new exploration play that we now have seen in Namibia. We think we have a good problem in our hands when it comes to our position in Namibia. We are now exploring what to do with it going forward. Thank you.
Ignacio, I just wanna reiterate, I think we're 45% in São Tomé.
Correct.
An operator and 80% non-operator in Namibia. For Galp, these are really material positions which are sometimes unlike some of the other positions that we have in our portfolio across the world. InThoresting.
Okay, thank you.
Thank you. The next question is from the line of Matthew Lofting from J.P. Morgan. Please go ahead.
Great. Thanks for taking the questions. Two if I could please. First, I just wanted to come back to the earlier observations around the move on hedging, more from a sort of 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 the sort of the hedging move around upstream oil, and even taking account of the observations made earlier around the relative concentration of Galp's portfolio, et cetera. Could you just talk about the philosophical approach on hedging oil upstream going forward beyond 2023 through to 2022, and whether that's something that investors should expect Galp to continue to do over the medium term? Second on renewables.
Obviously scaling up the sort of the position in Brazil. There's been quite a bit of focus and sort of commentary recently around cost inflation in the sector, but particularly through renewables and solar. 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. Thanks.
Thanks, Matt, and I might ask Filipe to comment. You know, I just have to. There is no change of policy in Galp around hedging. 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. We have no intention for the rest of this year to do any more hedging going forward. Just be reassured around that. Then I'm gonna ask Filipe to add anything he would like to that comment.
Then ask Georgios to address a little bit about the, you know, 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.
Yeah. Matt, you ask about the philosophy, and if we look back, say a decade, 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. 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, in electricity prices. Hence, you know, these are untested territory. 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, you know, a bit of a floor here and then makes sense structurally. This is where we are. Thank you.
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're 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 have seen in Iberia 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 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. All in all, and of course, as I was saying before, the investment decisions are not today or tomorrow. They're gonna be in, let's say, a year at least going forward. We will be assessing the revenue cost decision on a case-by-case basis being return focused.
We will use the time that we have between today and then to build and strengthen the teams and have best in class capabilities. Thank you.
If I could just add that, you know, I think in Iberia, we have been comfortable with leaving exposure to the merchant market, and, you know, we've enjoyed some upsides there. That's one side we didn't hedge our position and take a PPA out, 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 PPAs so that we have some clear expectation of the returns we get on the project. A little bit more risk averse in the Brazilian context than we're operating today in the Iberian context.
Great. Thanks, Andy.
Thank you. The final question today comes from the line of Raphaël Dubois from Société Générale. Please go ahead.
Good afternoon. Thank you for taking my questions. 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 refer to merchant prices for your own production. Can you please just confirm that your current 1.2 GW of capacity is still uncapped in Iberia? That would be my first question. The second one is on Coral. Sorry for asking that. I understand your excitement, but we are all aware of one of your peers that is having some issues with its own FLNG.
I understand these are two very different projects, but it would be great to hear from you, how different the two are and what makes you confident that the issues encounThored by this peer you will not encounter yourself. Thank you.
Thanks, Raphaël. Yeah, can I just mention how the Iberian electricity price regulation is not yet implemented, but has been, there's an approval from the European Union for what the Spanish and Portuguese governments have recommended, and that is essentially to cap the gas price assumed to go into the electricity price calculation. At the moment, a small amount of electricity is generated by gas, and the electricity price across the whole portfolio is set by the very high gas price. They want to limit that to 40-50 EUR per megawatt hour, which will give you an electricity price between 110-130 EUR 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 hits a cap. It's still two or three times higher than we assumed when we invested in these projects. You know, just to give you a sense that, you know, this is a disappointment, but it's still a very attractive electricity price. This lower electricity price also helps our commercial business because we're also selling to customers. As I mentioned in my comments, we didn't cover all of our risks there with forward-looking PPAs. Having a lower electricity price from the wholesale market to offer to our customers is some benefit as well. We're on both sides of this equation at the moment.
I have to reassure you that from a renewables perspective, although 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, you know, have a little bit of experience on what you may be alluding to in terms of one of our competitors in floating energy. This is a simpler project. It doesn't have the LPG export. Some of the power systems are designed differently. I think the lessons learned from that are 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 floating to where it is today.
We can never rely on the fact there won't be some teething problems when we start that up, but if the record to date is anything to go by, we can be pretty confident about this particular unit.
If I just may add actually, Raphaël, now we FID-ed this in 2017. Through COVID, through all the issues that has been in the market, this project is still essentially 98% complete. It is ahead of plan, and it's below budget, which actually makes us very excited. But of course, you are right, that these two months now with offshore commissioning and getting the all of the processes that work together in at -143 degrees centigrade, yes, that's a big step. But so far it has gone really well and there's a real possibility that we can have first gas in the system during June, and that's why we're excited.
We actually also see there is some upside on the volume side, but we'll come back to that later. Thanks.
Thank you.
Thank you. 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.
This concludes today's conference call. Thank you for participating. You may now disconnect.