Galp Energia, SA (OTC:GLPEF) Q4 2018 Earnings Conference Call February 11, 2019 6:00 AM ET
Pedro Dias - Head, Strategy & IR
Carlos Gomes da Silva - Vice Chairman & CEO
Filipe Silva - CFO & Executive Director
Thore Kristiansen - Executive Director & COO
Conference Call Participants
Oswald Clint - Sanford C. Bernstein & Co.
Flora Trindade - CaixaBank
Biraj Borkhataria - RBC Capital Markets
Robert Pulleyn - Morgan Stanley
Joshua Stone - Barclays Bank
Michael Alsford - Citigroup
Jonathon Rigby - UBS Investment Bank
Michele Vigna - Goldman Sachs Group
Alwyn Thomas - Exane BNP Paribas
Yuriy Kukhtanych - Deutsche Bank
Good morning, ladies and gentlemen. Welcome to Galp's Full Year 2018 Results and Outlook Conference Call. I will now pass the floor to Mr. Pedro Dias, Head of Strategy and Investor Relations. Please go ahead.
Good morning, ladies and gentlemen, and welcome to the fourth quarter and full year 2018 results conference call together with a short-term outlook. Today, Carlos will start with a quick overview of Galp's strategy execution during 2018 and an update on what to expect in the medium term. Filipe will then briefly cover the Q4 full results and full year results and also update us on key financial metrics going forward. At the end of the presentation, we will be available to take any questions you may have. Thore is here with us as well.
I would like to remind you that we may be making several forward-looking statements. Actual results may differ due to factors included in the cautionary statements available at the beginning of our presentation, which we advise you to read.
Carlos, the floor is yours. Thank you.
Carlos Gomes da Silva
Thank you, Pedro, and good morning to you all. Welcome. I will start with a quick recap of 2018 year. During the year - during 2018, the energy sector faced very significant volatility, with oil prices moving up and down more than $20 per barrel throughout the year. This only reinforces, once again, the strategic importance of Galp's integrated business model. On the upstream front, we continue to develop the giant Lula and Iracema fields, ending the year with eight producing units, with the deployment of P-69 that has been located in Lula Extreme South at the end of October. Earlier this month, we had the first oil in unit number nine that has been located in the Lula North. Now the consortium is working on the enhancements that will allow us to maximize the value extraction from these outstanding assets, with the ambition to reach a 40% recovery factor. In Angola, production from Kaombo North project, that is in block 32, started in July; and the second unit, or Kaombo South, is already on location. In Mozambique, the development plan for the first phase of the Rovuma LNG project was submitted, now with much larger strength than the initial plan.
On the downstream side, we have taken advantage of the planned maintenance work in our refining system to implement some of the projects included in the one extra dollar per barrel initiative that you all are aware of. We have also taken the opportunity to make some adjustments to meet the future demand specifications that will arise from the upcoming IMO regulations that will enter in force next year. We continue to deliver a solid performance from our oil and gas marketing activities in Iberia and also in Africa, and we have done so whilst continuing to developing our business with a more client-centric approach, making progress in adapting our value proposition to meet customers' demands. Everything we do reflects our commitments to sustainable practices, and once again, I'm glad to reinforce that this year, Galp was recognized by several of the most important independent entities as an industry leader in environmental, social and governance matters.
Jumping now to the next slide, in Slide 4. A quick note on the progress we made in building our upstream resource base. The successful developments of our core asset, together with the increased exposure with strong set of new ones, have led us to a 15% increase in 2P reserves and 2C resources to 2.4 billion barrels of oil equivalent. In respect to 2P reserves, we were slightly up due to the upward revision of Lula and Iracema fuels performance and the update estimates on Iara from the newly drilled wells. These more than offset the 2018 production. 2C resources were also up 23%, mostly considering the larger trends in Mozambique and the additional 3% stake that we bought in BM-S-8, where we have now 20% shareholding. On top of these upward revisions related to our development portfolio, we have also acquired interests in high-potential exploration assets in Brazil, the Uirapuru and also in Campos basin, the block 791, where and which we will now work to operate.
So now on Slide 5, and to close my overview of 2018. Production growth was at the lower end of our guidance due to the late start-ups of the new replicant units in Lula. We had already flagged these last summer. Financials were supportive, even adjusting macro assumptions, with EBITDA reaching €2.2 billion. In what respect to free cash flow, it was up more than 10% year-on-year despite the working capital build and covering 1.3x the dividend paid during the year. Let's now talk about the future with a brief update of what you can expect from us until the end of the decade. In Slide 7, you can see our upstream activities and the priority - our priority will continue to be development of our world-class portfolio. We have big and competitive projects in-house, which will keep us busy for many years.
In Lula and Iracema, we are ramping up the last 2 of 9 units already producing. In Iara, we expect first oil from the new FPSO that will be located in Berbigão and Sururu during the second half of 2019, while the new FPSO for Atapu is expected to start next year. In Carcará, we are moving towards the phased development. The first phase is now assuming a larger FPSO with 220,000 barrels per day of capacity, with full reinjection capability since the first day to increase the options around the development plan. This project should see first oil in the next decade between 2023 and 2024 and has a breakeven that should stand below $35 per barrel. Regarding appraisal works, which will support the next development phases, we expect to spot a second well in the Northern area very soon. Carcará looks quite promising based on its recoverable resource estimate of circa of 2 billion barrels of oil equivalent.
Still in Brazilian pre-salts, the first exploration well in Uirapuru is expected by 2020. In Mozambique, we are working towards an FID this summer of the first development phase of Rovuma LNG, with offtaking financing and EPC well underway. We have also been making good progress with Coral FLNG project, with activities intensifying significantly this year both with unit construction; and as well in what respects, to the drilling activities. In Angola, and I've mentioned before, the second unit in Kaombo is already on location. We may see first oil slightly before what we consider in our plan, which was around midyear. Regarding exploration activities. We have started in January, the 3D seismic campaign in our operated Namibian Deepwater Offshore Licence in PEL83. The survey will comprise an area of around 3,000 square kilometers and should - to be completed during March.
Moving on to Slide 8 with our production guidance. So our 2020 production is now reflecting the late start-ups of the latest two units in Lula and the revised time line for Iara. Lula North, so the unit P67, just started, having been originally expected to start last summer. And Berbigão/Sururu in Iara, is now expected to start in the second half of this year; and Atapu, next year. This is the guidance we have been sharing with you since the summer, so no surprises here. And as always, all our operational and financial projections include the expected outcome of unitization processes in Brazil. So both plans are fully comparable.
With these grounds, production is expected to grow 8% to 12% this year and at a 12% to 16% compound annual growth rate to 2020. Post to 2020, we are assuming higher production versus the previous guidance. We expect to benefit from the increased contributions from Lula and Iara, where we see positive signs that should lead to longer plateaus and an increased planned capacity and larger exposure to Carcará, and of course, the larger development solution for the Rovuma LNG project in Mozambique. Beyond 2025, the upward revision is even higher as we see additional upsides from the recent additions in Brazil.
To sum it up, 2019 and 2020 production growth should be less steep compared with the previous plan, but production is higher in the medium to longer term. Now moving onto the downstream on Slide 9, and starting with the refining activity. 2019, so far, has been challenging for refining, with margins impacted by the high levels of gasoline inventories. In addition, we are having some constraints in our system, given our recent operational upside in our Matosinhos refinery, which may also lead to slightly sub-optimal operations during the Q1. The planned 40 to 50 days outage for maintenance that is planned in the atmospheric distillation units in Sinos during the second half of the year is not expected to compromise the operational availability of the conversion units that should run at the optimal capacity. We will use the opportunity to perform works to increase the efficiency and the conversion ability of our refining system towards achieving the full capture of the extra $1 per barrel in refining margin by 2020.
Additionally, we aim to capture the benefits of data-driven operations through various projects, which are currently underway and which will leverage on the digitalization and the supply chain management to increase the efficiency and the profitability of our operations. And as we move closer to the start of the IMO sulfur cap, Galp is ready to supply compliance fuel. We are actually expecting a more supportive environment for 2020 onward, mainly driven by middle distillate cracks increase. This effect should more than offset the increased sourcing costs from sweeter crudes diet. And please note that on the upstream, we will have the reverse effect of selling our medium-gravity, low-sulfur crudes at a higher price. All in all, IMO should be a clear net positive for Galp, and I will say that both in the upstream and also in the downstream.
Regarding our marketing activities, we will continue to adapt our value proposition and invest in digital and innovative solutions to improve the customers' journey. In Gas & Power, we are ensuring the long-term sustainability of our Supply & Trading activity, securing new natural gas-sourcing contracts, for which we are considering alternative options, including our equity gas from Mozambique. We are also strengthening our commercial position in Iberia, leveraging from digital tools and innovative business models to provide gas, electricity and services as an integrated commercial offer.
Additionally, and aligned with our strategy to develop low-carbon businesses, we are building optionality and integration alongside our electricity value chain. We will continue to develop a portfolio of renewable energy projects. Our growing presence in the electric mobility business will also allow significant synergies with the existing network of retail stations. We plan to expand the EV network and associated services, positioning Galp as a leading brand in these segments. So ladies and gentlemen, and to conclude, these are the projects which will continue to strengthen our growth and value story for many, many years to come. Our organic developments are expected to generate over €1 billion of free cash flow per year from 2020 onwards at $65 per barrel in 2020, and $70 thereafter. With strict financial discipline, we enter this upcoming cash cycle committed to shareholder value. Based on the recent performance, we will be to proposing a 15% increase of our dividends related to the '18 financial year to around €0.63 per share.
I will now pass on to Filipe to go to the economic and financial numbers. Filipe, please?
Thank you, Carlos, and good morning. Let me start with a quick overview of Q4 2018 and the full year results. For Q4, and I'm looking at the bottom of Slide 13, cash flow from operations was €402 million. That's down 18% year-on-year, driven by lower contribution from refining. This was mostly the result of the lower gasoline cracks and the impact of refinery maintenance on volumes processed. Maintenance also impacted refining OpEx.
In upstream, we reached a production of 113 barrels per day and continued to reduce our production costs after high maintenance during Q3. E&P was impacted by about €50 million in under-lifting adjustments related to production from the previous quarter. Now on the positive side, we had €156 million of working capital released during the quarter. Net CapEx totaled €282 million, of which about half was allocated to the Refining & Marketing business, given refinery maintenance and the optimization investments during the period. Free cash flow reached €120 million in the quarter. You will have seen on the P&L we published this morning a negative €71 million in mark-to-market changes on the financial results. This is mostly related to financial derivatives we entered into to hedge the price risk of natural gas we placed with the B2B clients in Iberia. The positive impact from these economic hedges should be realized over the coming quarters as the underlying gas volumes get delivered.
Now for the full year, and still on this Slide 13. EBITDA plus associates was over €2.4 billion, and that's up 21% year-on-year with the increased contribution from E&P more than offsetting refining weakness. Cash flow from operations stood at about €1.6 billion. That's in line year-on-year, negatively impacted by a €230 million working capital build. And after CapEx, interest and dividends to Sinopec, group free cash flow reached €619 million. This is a solid number if you consider the refinery maintenances, the working capital builds and that a full 70% of CapEx is expansion-driven. Actually, E&P is already generating half of the group's cash flow from operations minus CapEx, which speaks for how important this business is fast becoming.
Now let's now look at our plan to 2020, and I'm on Slide 14. Now just for context, our Brent price assumptions remain unchanged from the previous plan at $60 per barrel in '19 and $65 in 2020; same for the dollar, which stays at $1.20 to the euro throughout the period. We are revising upwards the Galp refining margin assumptions for 2019 for about $5, $6 per barrel. That's on the back of the expected strong demand for middle distillates. And for 2020, we add another $1 per barrel, driven by the full contribution from the refining efficiency initiatives and the expected IMO disruptions during that year.
Now I would highlight that our figures are now based on IFRS 16. Slides 19 and 21 provide some detail on the expected impacts to Galp, and this relates mainly to leased FPSOs and subsea equipments. So for clarity, IFRS 16 has no impact on free cash flows.
On this basis, we are guiding towards organic cash flow from operations, annual growth of 10% to 15% compounds to 2020, mostly driven by upstream growth and a supportive refining environment. Even with oil prices lower than during 2018, upstream cash flow from operations should grow at above 10% percent compounded to 2020, benefiting from higher production but also from higher unit cash margins in the upcoming Iara FPSOs, which are less heavily taxed. Downstream cash flow from operations should range between €800 million and €900 million per year during the period, unchanged from previous guidance. This basically reflects a slightly better refining environment, which we expect later this year.
As for Gas & Power, we expect to be at the lower end of the €100 million to €150 million EBITDA guidance due to the end of the structured contracts. We need to add €90 million per annum from our associates. For 2019, group EBITDA is expected at €2.1 billion, €2.2 billion and this will trend towards €3 billion-plus from 2020 onwards.
Regarding CapEx, on Slide 15. We are keeping our guidance at about €1 billion per annum in '19 and '20. E&P should still account for about 70% of group CapEx now with Mozambique gaining traction, given Coral and the larger onshore trains of the Rovuma LNG project. Our CapEx estimates assume that the unitization processes in Brazil will be completed by 2020. Now as of the end of 2018, considering the unitization processes under approval, Galp was in a net receiver position of about €100 million under the equalization calculations. We will be updating you on this net position over time as things progress.
Non-upstream CapEx is expected to average €250 million to €300 million per annum until 2020. This reflects a higher concentration of payments related to the one extra dollar per barrel initiatives in the refineries, which are now nearing completion. After 2020, we expect this number to fall to a more normalized €200 million to €250 million, including low-carbon, renewable power production and the new business solutions.
Finally, free cash flow on Slide 16. This is expected to be over €1 billion by 2020 and grow rapidly as we get into the mid-2020s. Now this is already net of the dividends to Sinopec and will also assume long-term grant of $70 and Galp refining margins of about $6 per barrel. Net debt-to-EBITDA is expected at below 1x from next year, this already considering the IFRS 16 impact. New projects not currently in the plan would be expected to be funded by incremental cash flows and from a more active portfolio rotation strategy.
I will stop here, and we're happy to take your questions. Thank you.
[Operator Instructions]. We will now take our next question from Oswald Clint of Bernstein.
Carlos and Filipe, just two questions, please. Firstly, on Lula and Iara in terms of the reserve revisions upward that you spoke about. Could you just perhaps talk about that a little bit more? Is that really the wells performing better than you expected that led to the upward revision? Or is it - are you talking about some of the enhanced oil recovery techniques yet, the wide technique or gas injection? And ultimately, what does it mean for your assumptions or your expectations for the length of the plateau on each of these FPSOs? I remember you've moved that up over time to 3 and 5 and some of them potentially seven years at plateau. I just want to get a sense of where that number may have moved to, please. And then secondly, so the dividend going up this morning quite materially, does that signal, I guess - or I mean, almost you're happy with the size and scale of the Brazil portfolio? Or are you still interested in adding to that, given things like transfer of license, some of the new license runs in Brazil in the next year or two? So that's the second question.
Carlos Gomes da Silva
Oswald, I will share the first question with Thore but starting by the dividend question. As we have mentioned before, we will continue to have a balanced approach on cash flow generation in terms of location between finding new optionalities to redeploy our CapEx and find new value-creative assets, which we have been doing. So you should bear in mind that we have increased our exposure in BM-S-8. We have been present in the last bid rounds, and we have taken 71 in Campos Basin and also Uirapuru. So we continue to look at that. But at the same time, as we are focused on value-driven approach, we have also to look at how we can share that well with our shareholders. So we will continue to do that, looking at both sides of the same question and having a balanced position in order to guarantee that we are altogether, in terms of total shareholders' return, in the same page. In what relates to the reserves and resources, I would let that to Thore, let go in more details. But it is important that as time goes by, our experience in what respects to the plateau period of time and the initiatives that we have established and the experience that we get, the new units that have been put in practices, I would say, from the 5th to the 9th unit, we have increased our revision in terms of plateau period of time by one year, one additional year. Just please recall that the first unit that I always say and mention, that is a pilot - so it's a lab, a field lab unit, is now entering in the eighth year of production. And therefore, we have to look at this in a holistic way, but it's important also to guarantee that we have a proper and adequate management of the entire reservoirs going forward. Our ambition of having at least 40% of recovery factor means that we have to properly manage today in order to secure our future value. But I will now pass to Thore.
Thank you, Carlos. Let me try to give you a little bit more insight into our reserves portfolio and our resource portfolio. When it comes to the 1P reserves, you have seen that we had increased that to 389 million barrels. So it's a 2% increase since last year. Then you should factor in that we actually produced 38 million barrels during the course of the year. But even so, we were able to add 44 million to the revisions. And the revisions are mainly increased expectation for Lula/Iracema, which continue to perform very well; and we have also actually increased the expected oil in place for Iara, which led them to the upside. And that impacts both the 1P and the 2P reserves, which is now 755 million barrels. But let me also spend two words regarding the resources, which is also very important. During the course of 2018, we have increased the 1C resources with 43%. We've now reached 425 million barrels. And the key factor for that has been an up-stake of the Mamba reservoir and segments of reservoir that is now, we believe is going to be performed better than what we originally expected. And this also actually led so that the 2C resources would increase with 23% in totality, and now we're reaching 1,000,000,658. So overall, a good maturation of the portfolio of Galp. And if we are able to FID Mozambique and Mamba in 2019, that would, of course, be a significant addition for reserves for '19.
We will now take our next question from Flora Trindade, CaixaBank.
So first one is on CapEx and a follow-up on what you've just said. Do you have any budget for this inorganic CapEx? And also, I think you mentioned the potential for asset rotations. What could be the kind of assets that you would be willing to rotate in this case? What are the characteristics? And then the second question is if you can explain the change in the view on the IMO re-impacting in downstream. I think you'd mentioned higher cracks in middle distillates, which is also relating this with the investments that you are doing. Can you just update us on your more optimistic view on refining, both in terms of margins and the IPO - and the IMO impact?
Carlos Gomes da Silva
Flora, in terms of CapEx, the answer is no. We don't consider inorganic activities in our CapEx, even though, as you have observed during 2018, we have taken chance to continue to invest in opportunistic assets with high-quality and high potential, as it was the case of - in the Campos 791 and Uirapuru and also the BM-S-8. Anyway, we will be attentive, yes, but the word that is prevailing in our decision is value. So anything that we might think that could create value, we will be attentive. And therefore, that's the reason why we are saying that the rotation is a must, because we will continue with our financial discipline, that we will below - spend below the net debt-to-EBITDA, below prices. And therefore, we might be required to make some rotation if we think that there are other assets, business or optionalities that could create more value for the company.
So let's not speculate on which of them. We - in due time, we will analyze that. In what relates to IMO, so effectively, we are ready to go. That is the first message I mentioned to you - we have mentioned to you, that we are reviewing our expectations, lowering a little bit, due to the fact that we think the differentials between sweets and sours could not stand so high. But still high, let's say, between - at least between $2 and $3 upper, which means that our upstream activities, which are medium sweet crudes will benefit from that. In the refining, what we are observing is that the cracks in the middle distillates will tend to increase relevantly. And that's the reason why we are taking a more positive view on that, which should affect also positively our operations, due to the fact that we will have our conversion units prepared to benefit and to capture that. So as time will go by, we will see if this will be the case. But all the signs that we are getting from the market is that this should be in that direction; and that I should also, to remember all of those, that there is no other alternatives because the global conversion capacity is not capable to address this without blending fuel with diesel. We have this compliance fuel. And there are not sufficient capacity in what relates to prescribing, like, alternatives in the market. So the disruption that the IMO could impose will stand in the markets for a couple of years, at least within 20 years up to having some stabilization. Thank you.
We will now take our next question from Biraj Borkhataria.
Just a couple, please. The first one is on refining margin and your hedging strategy for 2019. Could you just update us on where you are there? I'm assuming you're not hedging much, given the expectation is for higher margins later in the year. And the second question is just following up on Oswald's. The 2025 Brazil production, if I compare the numbers you've given today versus this time last year, it looks like Brazil's gone up significantly. Could you just clarify what decline rates you assume for the - like, for the FPSOs? I think for the later ones, your assume a shorter plateau period. Is there any evidence to suggest that, that should be a longer plateau period?
Carlos Gomes da Silva
Biraj, from the hedging - refining strategy, we have hedged approximately 20% of our capacity for the year, which means around 20 million barrels at around $4 per barrel. So it's what we have for this year. In terms of Brazilian production, so you know that we are now ramping up two units. In our plants, we continue to use the 15 months as a ramping-up period of time. Nevertheless, the last units, they have ramped up between 10 and 11 months. So that's the experience that we have and the plans that we have considered. So I think with that, you can have an idea of where we will stand in terms of the Brazilian production. I will also ask Thore to complement. Please, Thore?
Thank you, Carlos. And in addition to this, what you will see as an impact as of 2025 is that in oil production guidance now, we're expecting significantly bigger trends in Mozambique. We used 5 million tonnes per year trains in Mozambique in our previous guiding to the market. Now we're using 7.6 million. That's one effect. And in addition, on Carcará, we used - in our previous plan, we expected a unit of 180,000 barrels per day. Now we're expecting 220,000, and we are now also having an ownership share of 20%. So all of this contributes to the fact that we now are more optimistic regarding our 2025 production than we were last year. Thank you.
We will now take our next question from Rob Pulleyn, Morgan Stanley.
Gentlemen, just one question for me around refining. Could you provide a little bit of color as to how you think about gasoline margins within the range of products you provide and within the refining guidance that you've given? I think many share your view on middle distillate, but it feels like gasoline is going to be under a lot of pressure. So could you give us the underlying sort of view in that refining margin guidance as it relates to gasoline?
Carlos Gomes da Silva
Rob, in the end of last year and beginning of this year, we always expect - so during the wintertime, gasoline cracks tends to depreciate, but what we are observing this year comparing with the previous year is that they are being negatively impacted. And I mean, it's not only European grades, but also the RBOB rates. So that means that it's not only the cracks of Eurobob, but also the average price between Europe and the United States. So we hope that during the driving season, that could recover. But frankly speaking, we are less keen and optimistic on that than we are in middle distillates, and namely, with diesel. So this is our view, and that's the way we have considered that on building up our, going forward, refining margins estimations. Thank you.
We will now take our next question from Josh Stone of Barclays.
Two questions, please. First question, on the optionality in the portfolio you talked about. Can you give us an indication of the sort of options you're looking at? Are they mostly upstream or are you looking downstream as well? And then secondly, on the unitization in Brazil. Can you just - when you're expecting the agreement to happen, and can you give us an estimate of what production impact you're budgeting for in 2019?
Carlos Gomes da Silva
Josh, so going to your first point, optionality. During this transition - energy transition moment that we are living today, we have to look attentively for alternatives and stay very careful on the way we diversify our portfolio. So that said, we are looking broadly for value and creative opportunities, both in the upstream and also in the downstream. Of course, we have already released to you, a couple of years ago, that we - progressively, we start to redeploy some CapEx. The bandwidth was - or is between 5% and 16% of our CapEx to lower carbon business, which means that we are progressing and feeding our pipeline of renewable projects toward a lessened carbon-intensive economy. In what respects to the upstream, we look attentively for the new coming lead routes, and we will see - we will take the decisions in due time, and also, how we can - maximizing and transforming our business in the downstream in a moment that we are in, I'll say, in a - in the mature level of this activity and requires a transformation.
And we are looking attentively and mainly investing on changing the client journey and the experience and the efficiency of the business. In what respects to unitization, so unitization, what can I say? It will happen soon because the agreement between the partners and the old entities involved has been already achieved. So the process is no longer in - no longer our end. It's from the NAP decision. And therefore, what we have done was considering in our plan as unitization happens in the 1st of January. And what can I share with you is the fact that all combined with the units that will be put on our operation and the unitization impact within annual basis, and imagine that we will not take unitization up to the end of the year. This will take an impact of about 2,500 barrels a day in an annual basis. So it's - today, as Filipe had mentioned, we are net receivers from the economic point of view. We - if, as per 1st of January, unitization will be enforced, we have to receive €100 million. So we have to update you there within - time goes by. But please also take in consideration that the range that we provide to you in terms of production growth already included this. So it's important for the full year activities. Thank you.
We will now take our next question from Michael Alsford from Citibank.
I've just got a couple, please. Just firstly, on E&P, in particular, then so the exploration story. Forgive me, I might have missed what you said, but you're talking about Uirapuru potentially being drilled by 2020. It sounds like it's later than you previously guided. So maybe could you talk specifically on that well, but also the broader exploration plans for 2019? And then just secondly, on - so coming back to refining. Clearly, refining OpEx was hit pretty hard through the turnaround activity that you had in 2018. So I just wondered if you could give us a guide on what refining OpEx is expected to be for 2019? And then just finally, on refining. Could you give us a bit more color exactly what gasoline crack you are assuming in refining? As I say, it started has very weak, as the previous point you mentioned, but it does feel like it's creeping up just to get towards that $5 to $6 refining margin, even with the positive view on middle distillates.
Carlos Gomes da Silva
Michael, yes, I've mentioned that the exploration well in Uirapuru should happen next year. Of course, we have to read this inside the consortium. And this is what we can say as the - not longer than two, if we will be able to read internally in the consortium to anticipate. We are more than keen. But it's too early to tell to you that '19 will be the case. If possible, we are all working hard to anticipate as much soon as possible. And that is Galp's position, so just - to sake of priority. In what relates to OpEx, yes, it has been higher due to the fact that we had several planned maintenance activities during the year. So if you take into consideration of our spend or our regularized OpEx, it should stand between $1.8 and $2 per barrel. So that is the - what we should consider. In terms of the cracks, we are speaking about them, and we are considering about - gasoline crack of about $100 per tonne. So I think that answers to your question. Thank you.
Thanks, Carlos. And if I could, just a sort of follow-up on the broader exploration strategy. Are there many sort of major wells that you're planning this year to talk to?
Carlos Gomes da Silva
I will let Thore to elaborate on that. Thank you.
So Michael, the most important thing for us on the exploration side during 2019 is: one, to shoot our seismic and complete our seismic campaign in Namibia, where we're operating; number two, to work together with, as Carlos said, the consortium to try to anticipate Uirapuru to '19, but that needs the decision on the rig rather sooner than later; and thirdly, it is to agree with the partners in São Tomé and Príncipe to drill worthy prospects. We see some interesting opportunities in São Tomé and Príncipe, and the goal is to be ready to drill the first well in 2020. Thank you.
We will now take our next question from Jon Rigby of UBS.
Two questions. The first is, can you - given the delays and everything, can you just maybe go through an update on status of the FPSOs that are directed at Iara, where they are so we just have an idea about how far along the construction process or installation process they are, and maybe sort of - maybe if you possibly can, characterize where the sort of as yet unidentified FPSOs are in the sort of thought process or development process for those fields? And the second is just on dividend policy. Obviously, you now have a history of bumping the dividend up fairly meaningfully over the last few years. And I'm just trying to get a - really, a handle on how you think about that in terms of sort of relating it to underlying performance. Because, obviously, the degree of volatility in pricing is a way of thinking about it, to just map it rather broadly, but map it towards your underlying production growth, if we just assume that production growth is generating some kind of consistent operational free cash flow contribution to the business, and I guess, therefore, implying the prospects of dividend growth can continue to a fairly rapid pace over the next few years.
Carlos Gomes da Silva
So John, starting by the dividend, and I will share the first question with Thore. The dividend policy, our cash flow generation cycle is dramatically different from what we have in the past. We have been friends for many years over investing. [Indiscernible] I believe that in the future, we will get back full results. That depends how we are in a more balanced position. So we are being capable of generating free cash flow [indiscernible] positive, continuing to reinvest for the future. Filipe had mentioned to you that 70%, 7-0, has to do with future prospects, so it's future investments with a future of business. Therefore, the volatility that you mentioned is there. It's, as I said, in operations. But the capacity to generate cash will be different from what we had in the past. Therefore, we are much more thoughtful on considering the value with our shareholders, in both the prices, looking as well in total shareholder return. But dividend is one of the points that we are rebalancing our position - and keeping a strong balance sheet, meanwhile. In what relates to the delays in the FPSO, we have to point it out that the delay that we had, clearly it was with the P-67, so Lula North. That was pointed out last year. It should start before, and it's been delayed [indiscernible]. The key reason is that the trade wars reached a delayed trade-away from China. We have that clearly [indiscernible]. So we continue to work towards that, but I will let - now I will let Thore to go into details.
Thank you, Carlos. So to give you a bit of an update. Then on - as Carlos said and as we have mentioned, on the 1st of February, P-67 Lula North came into production. So that would be now an important ramp-up. Then on P-68, which is the unit that is going to go through in Berbigão and Sururu, there is now very important fishing work that is happening at the Jurong shipyard in Brazil. And we are, as Carlos said in his opening statement, expecting a first oil in the second half for this year. That is supposing there has been a successful execution on the finishing work in Brazil. Thereafter, it is Atapu Sul which is now - had been delivered to correct shipyard and is being completed there. But with the - and we are expecting first oil in 2024 for Atapu Sul as well. Then when it comes to Lula West, that is now being discussed in the consortium, what is the best solution in our plants. We have factored in contribution of that as of 2022. What is good news is that we see that there is potential for fast ramp-up and that should contribute to good performance. In addition, we're expecting now the second FPSO in Angola, Kaombo, soon, which we expect will also start in first half of this year. So overall and in the big picture, there's a good ramp-up of production.
We will now take our next question from Michele Vigna of Goldman Sachs.
Michele from Goldman. Two, if I may. The first one of is on your Brazilian subsidiary. Now that it's cash flow generative, I was wondering what we should assume in terms of dividend to your Sinopec minority in the coming years? And then secondly, I was wondering if you could give us some guidance around the tax rate for 2019? [Technical Difficulty]
Michele, are you there?
Yes, could you hear me?
Now I can, sorry. Petrogal Brasil is, yes, it is free cash flow will be very positive and will be very significantly so as CapEx goes materially down and production ramps up. The intention is that we distribute 100% of the free cash flow on an annual basis. 30% of that goes to Sinopec. Now we're not giving specific guidance because this will depend on opportunities for growth and value creation that would directly compete with the distributions out of Brazil. That's plan A on the business plan, is 100% of the free cash flows, post-tax to Lisbon and Beijing. On the tax rates, we are keeping our guidance from last year. On a P&L basis, about 50% of pretax income; on a cash flow, about 40%. And as we move close to the 2020s, the two rates will converge at around 50%.
We will now take our next question from Alwyn Thomas of Exane.
Can I ask on the RFRS uplift that you discussed, the €170 million and the €420 million? Could I ask whether you're able to break that down amongst the divisions, and I guess, the forward outlook, whether that changes and if your estimates for OpEx - or basically, how that's reflected in the business going forward for modeling purposes? And my second question, just related - I couldn't quite hear the answers before. Just going back to Berbigão and Atapu FPSOs, whether you're able to just say what equity stage you're assuming for those two FPSOs, when they come on field post unitization.
Carlos Gomes da Silva
Alwyn, I will take your 2nd question and Filipe will take the first. We didn't mention, so we are providing global production guidance, which takes already in consideration unitization impacts. But we don't still have the formal approval from NAP, even though between parts - which means between the different parts of the consortium, the parts that also we included in unitization are also in NAP. There's a full alignment in terms of the principles. And so we are still waiting for that. Our guidance is taking that in consideration. And units should be in place in the second half of this year. In respect to your first question, I will pass to Filipe. Thank you.
Alvin, on IFRS 16, I'll start by making a very broad statement that nothing changes but accounting. We're still paying MODEC or SPM the same €100 million every month as we've always done. Accounting-wise, now we will consider these lease payments as part - as a reduction. So we will no longer have costs - the operating costs, and this goes into interests and into amortization of principal lines. So it does introduce a bit of noise, but does not change taxation nor our free cash flow. The bulk of the assets we have, which are subject to IFRS 16 - so which assets do we have that have operating leases today? It is mostly FPSOs and subsea. All the new FPSOs coming our way from last year onwards are actually replicants. They are owned. So the impact actually reduces vary materially over time. So on day one - and if we had hooked IFRS 16 in 2018, which we have not, so it's only starting in '19. But had we done it in '18, our EBITDA would have gone up by €170 million and our net debt would have gone up €1.2 billion. And those numbers reduce significantly as we progress. And again, it's mostly E&P. In Iberia, we have mature buildings, mature refill stations that went out. So there's a number in Iberia, but it's not very significant. We do plan to continue to publish our numbers the same way. So that's we view on what our real OpEx costs are per barrel.
Okay. Sorry, just to - can I just clarify that? You're still planning to do the adjusted EBITDA exactly as you did in 2018?
No. From 2019 onwards, the EBITDA that you will see will be better by about €170 million. And this number reduces over time.
We will now take our next question from Yuriy Kukhtanych.
Very quickly, I had follow-up questions on your capital allocation. Could you please tell us whether you are going to spend any money or you're planning to spend any money on additional refining capacity outside Europe? Would it be one of the options that you would consider? And the second follow-up question is on your refining margin upgrade for 2019. You mentioned that you're now expecting higher distillate demand, and just - could you please just discuss what exactly changed in that expectation for the higher distillate demand? Have you seen higher interest from your clients, perhaps in Iberia?
Carlos Gomes da Silva
Yuriy, to your first question, we don't have plans for additional refining capacity anywhere else, including outside of Europe. What we do have [indiscernible] and analyzing is how we can dip in our conversion capacity and improving the valuation of our throughputs. But no decision taken whatsoever. And you will be updated timely and periodically about these projects. In what relates to the middle distillates. So today, we are observing a shortage is in terms of availability. We are also looking at the demand that continues to grow. But moreover and more important, is the IMO impact, that we are looking at this as a requirement in terms of blending, increasing in terms of marine diesel. That will put more pressure in diesel. So that's the reason why we have considered in our plan and in our refining margin, a forecast that this will have an upside going forward. There is also, within the middle distillate, another press up that is related with the jet, so the jet fuel. So the aviation fuel continues to progress with the demand increasing heavily, comparing with the other projects. So all in all, that puts a lot of pressure in middle distillates products.
So - but what changed since your last guidance for the refining margin?
Carlos Gomes da Silva
It puts upward the cracks that we are seeing for the diesel. And we are in a shorter period of time evaluation comparing with what we had before. So we are now being more optimistic than we were in this respect.
So ladies and gentlemen, thank you very much. We hope you have found this update useful. And I remind you that our IR team is always available for additional clarifications. Have a great day.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.