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, welcome to the fourth quarter and full year 2018 results conference call, together with the 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 including the cautionary statement available at the beginning of our presentation, which we advise you to read. Carlos, the floor is yours. Thank you.
Thank you, Pedro, good morning to you all. Welcome. I will start with a quick recap of 2018. During the year 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 the 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 the unit number nine that has been located in 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 the Kaombo Norte project, that is in Block 32, started in July, the second unit for Kaombo Sul is already on location. In Mozambique, the development plan for the first phase of the Rovuma LNG project was submitted now with much larger trains than the initial plan. On the downstream side, we have taken advantage of the planned maintenance works 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.
We have done so whilst continuing to develop our business with a more client-centric approach, making progress in adapting our value proposition to meet customers' demands. Everything we do reflects our commitment to sustainable practices. 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 four, a quick note on the progress we made in building our upstream resource base. The successful development of our core assets, together with the increased exposure to a strong set of new ones, have led us to a 15% increase in 2P reserves and 2C resources to 2.4 billion bbl of oil equivalent.
In respect to 2P reserves, we were slightly up due to the upward revision of Lula and Iracema fields performance and the updated estimates on Iara from the newly drilled wells. This 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 the interest in high-potential exploration assets in Brazil, the Uirapuru, and also in Campos Basin, the Block-C-M- 791, which we will now work to appraise. Now on slide five and to close my overview of 2018. Production growth was at the lower end of our guidance due to the late startups of the new replicant units in Lula.
We had already flagged this last summer. Financials were supportive, even adjusting macro assumptions with EBITDA reaching EUR 2.2 billion. In what respect to free cash flow, it was half more than 10% year-over-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 seven, you can see our upstream activities and 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 two of nine 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 bpd 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 break-even that should stand below $35 per barrel. Regarding appraisal works, which will support the next development phases, we expect to spud a second well in the northern area very soon. Carcará looks quite promising based on its recoverable resource estimate of circa 2 billion bbl of oil equivalent.
Still in Brazilian pre-salt, the first exploration well in Uirapuru is expected by 2020. In Mozambique, we are working towards an FID this summer for the first development phase of Rovuma LNG, with off-taking, financing, and EPC well underway. We have also been making good progress with the Coral FLNG project, with activities intensifying significantly this year, both with the unit's construction and as well in what respects to the drilling activities. In Angola, I've mentioned before, the second unit in Cabinda is already on location. We may see first oil slightly before what we consider in our plan, which was around mid-year. Regarding exploration activities, we have started in January the 3D seismic campaign in our operated in the medium deepwater offshore license in PEL 83. The survey will comprise an area of around 3,000 sq km and should be completed during March.
Moving on to slide number eight with our production guidance. Our 2020 production is now reflecting the late startups of the latest two units in Lula and the revised timeline for Iara. Lula North, the unit P-67, just started, having been originally expected to start last summer. 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. No surprises here. As always, all our operational and financial projections include the expected outcome of the unitization processes in Brazil. Both plans are fully comparable. With these grounds, production is expected to grow 8%-12% this year, and at a 12%-16% compound annual growth rate to 2020. Post to 2020, we are assuming a 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 plant capacity and larger exposure to Carcará. 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. Moving on to the downstream on slide nine 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 a recent operational upset in our Matosinhos refinery, which may also lead to slightly suboptimal operations during the Q1. The planned 40-50 days outage from maintenance that is planned in the atmospheric distillation units in Sines 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 dollar 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.
As we move closer to the start of the IMO sulfur cap, Galp is ready to supply compliant fuel. We are actually expecting a more supportive environment for 2020 onwards, mainly driven by middle distillate crack increase. This effect should more than offset the increased sourcing costs from sweeter crudes diet. 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, 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 customer's journey.
In gas and power, we are ensuring the long-term sustainability of our supply and 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, 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 this segment.
Ladies and gentlemen, 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 proposing a 15% increase of our dividends related to the 2018 financial year to around EUR 0.63 per share. I will now pass on to Filipe to go to the economic and financial matters. 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, looking at the bottom of slide 13, cash flow from operations was EUR 402 million. That's down 18% year-on-year, driven by a 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 bpd and continued to reduce our production costs after high maintenance during Q3. E&P was impacted by about EUR 50 million in underlifting adjustments related to production from the previous quarter. On the positive side, we had EUR 156 million of working capital release during the quarter.
Net CapEx totaled EUR 282 million, of which about half was allocated to the refining and marketing business given refinery maintenance and the optimization investments during the period. Free cash flow reached EUR 120 million in the quarter. You will have seen on the P&L we published this morning a EUR -71 million in market-to-market changes and the financial results. This is mostly related to financial derivatives we entered into to hedge the price risk of natural gas we place with a B2B client in Iberia. The positive impact from these economic hedges should be realized over the coming quarters as the underlying gas volumes get delivered.
For the full year, and still on this slide 13, EBITDA plus associates was over EUR 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 EUR 1.6 billion, t hat's in line year-on-year, negatively impacted by a EUR 230 million working capital build. After CapEx, interest, and dividends to Sinopec, group free cash flow reached EUR 619 million. This is a solid number if you consider the refinery maintenances, the working capital build, 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. Let's now look at our plan to 2020, and I'm on slide 14. Just for context, our Brent price assumptions remain unchanged from the previous plan, at $60 per barrel in 2019 and $65 in 2020. Same for the dollar, which stays at 1.2 to the euro, throughout the period. We are revising upwards the Galp refining margin assumptions for 2019 to about $5-$6 per barrel.
That's on the back of the expected strong demand for middle distillates. For 2020, we add another dollar per barrel driven by the full contribution from the refining efficiency initiatives and the expected IMO disruptions during that year. 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 sub-sea equipment. 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%-15% compound 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% 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 EUR 800 million and EUR 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. For gas and power, we expect to be at the lower end of the EUR 100 million-EUR 150 million EBITDA guidance due to the end of the structured contracts. You need to add about EUR 90 million per annum from our associates. For 2019, group EBITDA is expected at EUR 2.1 billion-EUR 2.2 billion, and this will trend towards EUR 3 billion+ from 2021 onwards.
Regarding CapEx on slide 15, we are keeping our guidance at about EUR 1 billion per annum in 2019 and 2020. E&P should still account for about 70% of group CapEx now with Mozambique gaining traction, given Coral and the larger onshore trends of the Rovuma LNG project. Our CapEx estimates assume that the unitization processes in Brazil will be completed by 2020. As of the end of 2018, considering the unitization processes under approval, Galp was in a net receiver position of about EUR 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 EUR 250 million to EUR 300 million per annum until 2020. This reflects a higher concentration of payments related to the $1 extra per barrel initiatives in the refineries, which are now nearing completion.
After 2020, we expect this number to fall to a more normalized EUR 200 million- EUR 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 billion euros by 2020 and grow rapidly as we get into the mid-2020s. This is already net of the dividends to Sinopec, and we also assume long-term Brent of $70 and Galp refining margins of about $6 per barrel. Net debt to EBITDA is expected at below one time 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.
Thank you, ladies and gentlemen. If you wish to ask a question at this time, please signal by pressing star one on your telephone keypad. Please ensure the mute function on your telephone is switched off to allow your signal to reach our equipment. Again, please press star one to ask a question. We will now take our next question from Oswald Clint of Bernstein. Please go ahead, sir.
Good morning, Carlos and Filipe. Just two questions, please. Firstly, on Lula and Iara, in terms of the reserve revisions upwards 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 are you talking about some of the enhanced oil recovery techniques yet, the WAG technique or gas injection? 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 three and five, 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.
Secondly, just with the dividend going up this morning quite materially, does that signal 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 rights and some of the new license rounds in Brazil in the next year or two? That's the second question. Thank you.
Hi, Oswald. Good morning. I will share the first question with Thore, 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 allocation between finding new optionalities to redeploy our CapEx and find new value-creative assets, which we have been done. 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 C-M-791 in Campos Basin and also Uirapuru. We continue to look at that. At the same time, as we are focused on value-driven approach, we have also to look at how we can share that value with our shareholders.
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 all together in terms of total shareholders return on the same page. In what relates to the reserves and resources, I will let Thore go in more details. 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 five to the ninth units, we have increased our revision in terms of plateau period of time by one additional year. Just please recall that the first unit that I always said and mentioned that is a pilot, so it's a field lab unit.
It's now entering in the eighth year of production. Therefore, we have to look at this in a holistic way. It is important also to guarantee that we will have the 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 future value. I will pass now 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 have increased that to 389 million bbl, which is a 2% increase since last year. You should factor in that we actually produced 38 million bbl during the course of the year. Even so, we were able to add 44 million through revisions. The revisions are mainly increased expectation for Lula and Iara, which continue to perform very well. We have also actually increased the expected oil in place for Iara, which led them to the upgrade. That impacts both the 1P and the 2P reserves, which is now 755 million bbl. 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%, which now reach 425 million bbl. The key factor for that has been an upstate of the Mamba reservoir and segment of reservoir that is now, we believe, is going to be performed better than what we originally expected. This also actually led to that the 2C resources was increased with 23%, in totality now reaching 1.658 billion . Overall, a good maturation of the portfolio of Galp. If we are able to FID Mozambique and Mamba in 2019, that would of course be a significant addition on reserves for next year.
That's very helpful. Thank you.
We will now take our next question from Flora Trindade, CaixaBank. Please go ahead.
Yes, hello. Thank you for taking my questions. The first one is on CapEx and a follow-up on what you've just said. Do you have any budget for these inorganic CapEx? I think you mentioned the potential for assets rotation. What could be the kind of assets that you would be willing to rotate in this case? What are the characteristics? The second question is if you can explain the change in the view on the IMO impact in downstream. I think you'd mentioned higher cracks in Middle East, is this also related with investments that you are doing? Can you just update us on your more optimistic view on refining, both in terms of margins and the IMO impact? Thank you.
Hi, Flora. Good morning. 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 the chance to continue to invest in opportunistic assets with high quality and high lead potential, as it was the case of the C-M-791 and Uirapuru, and also the BM-S-8. Anyway, we will be attentive, yes. The word that is prevailing in our decision is value. Anything that we might think that could create value, we will be attentive. That's the reason why we are saying that rotation is a must. We will continue with our financial discipline, that we will stand below the net debt to EBITDA below twice.
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. Let's not speculate on which of them. In due time, we will analyze that. In what relates to IMO, effectively we are ready to go. That is the first message. We have mentioned to you that we are reviewing our expectations, lowering a little bit due to the fact that we think that 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 distillate will tend to increase relevantly.
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. As time will go by, we will see if this will be the case, but all the signs that we are getting for the market is that this should be in that direction. I should also remember all of us 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 compliant fuel, and there are not sufficient capacity in what relates to scrubbing alternatives in the market.
The disruption that the IMO could impose will stand in the market for a couple of years, at least between one, two years up to having some stabilization. Thank you.
Thank you.
We will now take our next question from Biraj Borkhataria. Please go ahead.
Hi, thanks for taking my questions. Just a couple of these. The first one's 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. 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 FPSOs? I think for the later ones, you assume a shorter plateau period. Is there any evidence to suggest that should be a longer plateau period? Thank you.
Hi, Biraj. Good morning. From the hedging refining strategy, we have hedged approximately 20% of our capacity for the year, which means around 20 million bbl at around $4 per barrel. It's what we have for this year. In terms of Brazilian production, you know that we are now ramping up two units. In our plans, we continue to use the 15 months as a ramping up period of time. Nevertheless, the last unit, they have ramped up between 10 and 11 months. That's the experience that we have and the plans that we have considered. I think with that, you can have an idea of where we will stand in terms of Brazilian production. I will also ask Thore to complement. Please, Thore.
Thank you, Carlos. In addition to this, what you will see as an impact as of 2025 is that in our production guidance now, we're expecting significantly bigger trains in Mozambique. We used 5 million tons per year trains in Mozambique in our previous guiding to the market. Now we're using 7.6 as one effect. In addition, on Carcará, we used in our previous plan, we expected a unit of 180,000 bpd . Now we're expecting 220, and we are now also having an ownership share of 20%. All of these contribute 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. Please go ahead, sir.
Hi, gentlemen. Just one question from me around refining. Could you provide a little bit of color as to how you think about the 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. Could you give us the underlying view in that refining margin guidance as it relates to gasoline? Thank you.
Hi, Rob. Good morning. In the end of last year and beginning of this year, we always expect, so during the wintertime, gasoline cracks tends to depreciate. What we are observing this year, comparing with the previous years, is that they are being negatively impacted. I mean, it's not only European grades, but also the RBOB grades. That means that it's not only the cracks of Eurobob, but also the arbitrage between Europe and the United States. 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. That's our view and that's the way we have considered that on building up our going forward refining margins estimations. Thank you.
Okay, thank you. I'll turn it over.
We will now take our next question from Josh Stone of Barclays. Please go ahead, sir.
Hi. Good morning. Two questions, please. Firstly, on the optionality in the portfolio you talk 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? Secondly, on the unitization in Brazil, when are you expecting an agreement to happen? Can you give us an estimate of what production impact you're budgeting for in 2019? Thank you.
Hi, Josh, and good morning. Going to your first point, optionality. During this energy transition moment that we are living today, we have to look attentively for alternatives and take very careful on the way we diversify our portfolio. That said, we are looking broadly for value 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 will start to redeploy some CapEx. The bandwidth is between 5% and 15% of our CapEx to lower carbon business, which means that we are progressing and feeding our pipeline of renewable projects toward a less carbon-intensive economy. In what respects to the upstream, we look attentively for the new coming bid rounds, and we will see. We will take the decision in due time.
Also how we can maximizing and transforming our business in the downstream in a moment that we are in a, I would say, in the mature level of this activity and requires a transformation. 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. Unitization, what can I say? It should happen soon because the agreement between the partners and all the entities involved has been already achieved. The process is no longer in none of our hands from the ANP decision. Therefore, what we have done was considering in our plan as the unitization happened since the 1st January.
What can I share with you is the fact that all combined with the unit that will be put under operation and unitization impact will be in annual basis. Imagine that we will not take unitization up to the end of the year. This will take an impact of about 2.5 thousand bbl a day in annual basis. Today, as Filipe has mentioned, we are net receivers from the economic point of view. If as per 1st January, unitization will be enforced, we have to receive EUR 100 million. We have to update you as the time goes by. Please also take in consideration that the range that we provide to you in terms of production growth already included this. It's important for the full year already included this. Thank you.
Thank you.
We will now take our next question from Michael Alsford of Citibank. Please go ahead.
Hi there. Thanks for taking my questions. I've just got a couple, please. Just firstly on E&P, particularly around sort of the exploration story. Forgive me, I might have missed what you said, but you were talking about Uirapuru potentially being drilled by 2020. Maybe can you talk specifically on that well, but also the broader exploration plans for 2019? Just secondly, coming back to refining. Clearly, refining OpEx was hit pretty hard through the turnaround activity that you had in 2018. I was just wondering if you could give us a guide on what refining OpEx is expected to be for 2019. Just finally on refining, could you give us a bit more color as to exactly what gasoline crack you are assuming in refining?
As I say, it has started very weak, as the previous comment you mentioned. It does feel like it needs a pretty big uplift to get towards that $5-$6 refining margin, even with a positive view on middle distillates. Thanks.
Hi, Michael. Good morning. Yes, I've mentioned that the exploration well in Uirapuru should happen next year. Of course, we have to review the inside the consortium. This is what we can say as, not longer than two if we will be able, agree internally on the consortium to anticipate, we are more than keen. It's too early to tell you that 2019 will be the case. If possible, we are all working hard to anticipate as much as possible, and that is Galp's position. Just to sake of clarity. In what relates to the OpEx, yes, it has been higher due to the fact that we had several planned maintenance activities during the year. If you take the consideration of a standard or regularly realized OpEx, should stand between $1.8-$2 per barrel. That is what you should consider.
In terms of the cracks, we are speaking about and we are considering about a gasoline crack of about EUR 100 per ton. I think that answers to your question. Thank you.
Thanks, Carlos. If I could, just to 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? Thanks.
I will let Thore to elaborate on that. Thank you.
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 are operating. Number two, to work together with, as Carlos said, the consortium, to try to anticipate Uirapuru to 2019, that needs the decision on the rig rather sooner than later. Thirdly, it is to agree with the partners in São Tomé e Príncipe to drill worthy prospects. We see some interesting opportunities in São Tomé e Príncipe, and the goal is to be ready to drill the first well in 2020.
Thank you.
All right, thank you.
We will now take our next question from Jon Rigby of UBS. Please go ahead.
Yeah. Thank you. Hi, guys. Two questions. The first is, given the delays and everything, can you just maybe go through an update on status of the FPSOs that are directed at, where they are so we just have an idea about how far along the construction process or installation process they are. 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. 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. I'm just trying to get really a handle on how you think about that in terms of sort of relating it to underlying performance, because obviously, there's a degree of volatility in pricing.
Is the 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 operating or free cash flow contribution to the business. I guess therefore implying that the prospects are that dividend growth can continue at a fairly rapid pace over the next few years. Thanks.
Jon, good morning. Starting by the dividend, as I would say, the first question relates to the dividend policy. Our OpEx flow generation cycle dramatically different from what we had in the past. We have been trying for many years over-investing. I believe that in the future, we will get back good results. That's the case. Now we are in a more balanced position, we are being capable to start to generate free cash flow, while continuing to reinvest the future. [Inaudible] mentioned to you that 70%, seven-zero, has to do with future prospects. It's future investments with the future of this business. The volatility that you mentioned is there if I take that into consideration, but the capacity to generate cash will be different from what we had in the past.
We are much more hopeful on continuing the value with our shareholders in both perspectives, looking at value as total shareholders' return. Dividend is one of the points that we are rebalancing our position. 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, Lula North, that was pointed out last year that should start before almost in 6 to 9 months, and it's 6 months late. The key reason that has been also flagged was due to the late sail away from China. We have that clearly pointed out as the reason. We continue to work towards that, but I will let Thore to go into details.
Thank you, Carlos. To give you a bit of an update, as Carlos and as we have mentioned, on the 1st of February, P-67 Lula North came into production. That would be now an important ramp-up. On P-68, which is the unit that is going to go to Berbigão and Sururu, there is now very important finishing work that is happening at the shipyard in Brazil. We are, as Carlos said in his opening statement, expecting first oil in the second half of this year. That is also dependent on successful execution on the finishing work in Brazil. Thereafter, it is Atapu-Sul, which now has been delivered to the COSCO shipyard and is being completed there. We are expecting first oil in 2020 for Atapu-Sul.
When it comes to Lula West, that is now being discussed in the consortium, what is the best solution. In our plans, we have factored in contribution of that FPSO in 2022. What is the good news is that we see that there is potential for faster ramp-up, and that should contribute to good performance. In addition, we're expecting now the second FPSO in Angola, Kaombo Sul , which we expect will also start in the first half of this year. Overall, and in the big picture, there's a good ramp-up of production.
Thank you.
We will now take our next question from Michele Della Vigna of Goldman Sachs. Please go ahead.
Hi, it's Michele from Goldman. Thank you for taking my questions too. If I may, the first one 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. Secondly, I was wondering if you could give us some guidance around the tax rate for 2019. Thank you.
Technical difficulty, sorry.
Hi, Michele. Are you there?
Yes. Could you hear me?
Yes. Now I can. Sorry. Petrogal Brasil, yes, it is free cash flow 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. 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. Plan A on the business plan is 100% of the free cash flows, post-tax, come to Lisbon and Beijing. On the tax rates, we are keeping our guidance from last year. On a P&L basis, about 50% of pre-tax income. On a cash flow, about 40%. As we move close to the 2020s, the two rates will converge at around 50%. Thank you.
Thank you.
We will now take our next question from Alwyn Thomas of Exane. Please go ahead.
Good morning, gentlemen. Could I ask on the IFRS uplift that you discussed, the EUR 170 in the call this morning. Could I ask whether you're able to break that down amongst the divisions? I guess the forward outlook, whether that changes any of your estimates for OpEx or basically how that's reflected in the business going forward for modeling purposes. 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 say what equity stake you're assuming for those two FPSOs when they come on field post unitization. Thank you.
Hi, Alwyn. Good morning. I will take your second question, and Filipe will take the first. We didn't mention, we are providing global production guidance, which take already in consideration the unitization impacts. We don't still have the formal approval from the ANP.
Between parts, which means between the different parts of the consortium. The parties that also be included in the unitization are also ANP. There is a full alignment in terms of the principles. We are still waiting for that. Our guidance is taking that into consideration, and the unit should be in place in the second half of this year. In respect to your first question, I will pass to Filipe. Thank you.
Alwyn, on IFRS 16, I'll start by making a very broad statement that nothing changes but accounting. We're still paying MODEC or SBM the same EUR 100 every month as we've always done. Accounting-wise, now we will consider this lease payment as part as a reduction. We will no longer have the operating cost, and this goes into a interest and to amortization of principal line. 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, 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. The impact actually reduces very materially over time.
On day one, if we had booked IFRS 16 in 2018, which we have not, it's only starting in 2018, but had we done it in 2018, our EBITDA would have gone up by EUR 170 million, and our net debt would have gone up EUR 1.2 billion. Those numbers reduce significantly as we progress. Again, it's mostly E&P. In Iberia, we have a few buildings, a few retail stations that we rent out. There is a number there, but it is not very significant. We do plan to continue to publish our numbers the same way so that you have a view on what our real OpEx costs are per barrel.
Okay. Sorry, could I just clarify that you're still planning to do the adjusted EBITDA exactly as you did in 2018?
No. From 2019 onwards, the EBITDAs that you will see will be better by about EUR 170 million.
Yes. Okay.
This number reduces over time.
Okay. Thank you. That's pretty clear. Thank you, Filipe.
We will now take our next question from Yuri Koktanich. Please go ahead.
Good afternoon, gentlemen. Very quickly, I have a follow-up question 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? The second follow-up question is on your refining margin upgrade for 2019. You mentioned that you are now expecting higher distillate demand. 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? Thank you.
Hi, Yuri. Good morning. To your first question, we don't have plans for additional refining capacity anywhere else, including outside of Europe. What we do have, we are studying and analyzing, is how we can deepening our conversion capacity and improving the valuation of our throughputs. No decision taken whatsoever, and you will be updated timely and periodically about these projects. In what relates to the middle distillate. Today, we are observing a shortage in terms of availability. We are also looking at the demand that continues to grow. Moreover and more important is the IMO impacts that we are looking at this as a requirement in terms of a blending increasing in terms of marine diesel. That will put more pressure in diesel.
That's the reason why we have considered in our plan and in our refining margin 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. The jet fuel, so the aviation fuel continues to progress with the demand increasing heavily comparing with the other products. All in all, that puts a lot of pressure in middle distillates products.
What changed since your last guidance for the Galp refining margin?
It puts upward the cracks that we are seeing for the diesel. We are in a shorter period of time evaluation comparing with what we had before. We are now being more optimistic than we were in this respect.
Okay. Thank you very much.
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.