Welcome to the Q4 2018 YPF Sociedad Anonima Earnings Conference Call. My name is Richard, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. [Operator Instructions] I will now turn the call over to Diego Celaa. You may begin.

Right. Thank you, Richard. Good morning, ladies and gentlemen. My name is Diego Celaa, IR Manager for YPF. I would like to thank you for joining us today. In this occasion, we will discuss YPF 2018 full year results. The presentation will be conducted by our CEO, Mr. Daniel Gonzalez, and our VP of Strategy and Business Development, Mr. Sergio Giorgi. During the presentation, we will go through the main aspects and events that yearly results and share our conclusions for the year and perspective for the year ahead before we start taking questions. We will be making forward-looking statements, so I ask you to carefully review the cautionary statement on Slide 2. Also our financial statement figures are stated in Argentine pesos based on international financing reporting standards. In addition, certain financial figures have been adjusted to reflect additional information to let you better understand our key financial and operating results. With this I will ask Daniel to start with the presentation. Please, Daniel, go ahead.

Well, thank you, Diego, and good morning, everybody. Before we go through our operational and financial results for the year, I would like to provide some macro context to put things in perspective and better understand our performance. Last year can be broken down in two very distinct realities. The first few months of the year showed a strong economy with sales way above the previous year, the peso had devalued approximately 15% to ARS 20 per dollar and seemed stable back then, and local crude and fuel prices had converged with international prices. Unfortunately, starting in May, the peso lost half its value and the local economy started to cool down and then rapidly fell into a deep recession. In addition, export taxes were imposed in all products and services out of Argentina and capital markets closed for remainder of the year. To make things worse, international crude oil prices rallied all the way to $85 per barrel, which under normal circumstances would've been a good thing for us, but in this context just made it tougher for local prices to keep up with international prices. Local gas distribution companies were not able to pass through on to prices the effects of the devaluation creating a dispute with the producers regarding the wellhead price of gas. And local supply of natural gas significantly increased during the year as a result of the incentive price program put in place, but at a time when the local economy was not demanding more gas, especially outside of the winter peak season. This had a negative impact on our production figures of the last quarter and resulted in us rethinking our investments in natural gas development over the near future. I believe the company performed well under these circumstances and was able to…

Thanks, Daniel, and good morning, everybody. Let me start with the 2018 financial 2.4results highlights. Revenues reached ARS 435.8 billion, a 72.4 % increase compared to 2017, while adjusted EBITDA increased by almost 100%. However, our adjusted recurring EBITDA, which excludes the profit from the revaluation of our investment in YPS Luz, amounted to ARS 121.5 billion, expanding our recurrent EBITDA margin up to 28%, versus 26% of 2017 despite the challenging scenario we just discussed. Total CapEx of ARS 95.4 billion, resulting in an increase of 64.4% compared to 2017 but was lower in dollar terms as the devaluation of the local currency allotted some investments in pesos as we'll explain later on. This CapEx amount was exceeded by cash flow from operations, we reached a total of ARS 125 billion in 2018, consistently with our financial discipline commitment. The good news of the year is that our P1 reserves increased by 16.2% in 2018, boosted mainly by our shale and gas recovery operations. Our reserve replacement ratio for 2018 reached 178%. Total hydrocarbon production was down 4.5%, and we'll be going to much more detail on this number. We'll explain all these numbers in detail as we go through the presentation. Moving on to reserves in 2018, we were able to achieve a 178% reserve replacement ratio, reaching almost 1.1 billion barrels of oil equivalent of crude reserves, which represent a 16.2% increase compared to 2017. Net incorporation of reserves amounted to 344 million barrels of oil equivalent per day, of which 254 came from liquids and 90 came from natural gas. This increase in reserves was obtained both in unconventional and conventional fields. It is worth mentioning that our shale reserves already represent 19% of total reserves. Let's move now to the analysis of the 2018 production.…

Thank you, Sergio. In this final slide, I would like to address our outlook for 2019. We have launched a policy for operational excellence last year and I intend to deepen this effort in 2019 and beyond. This should result in even better safety metrics in addition to a more efficient use of our assets. Sustainability remains a core value, and we aim to improve every year our ESG ranking, reflecting the company we are and the one we intend to become. In terms of production, we will continue focusing in accelerating our shale oil developments, following the outstanding results obtained during 2018. This was a first year in which our shale oil production growth was enough to offset the decline in conventional fields, which proves this is a path that will lead us to reach a sustainable growth in production. The strategy here in the shale is to accelerate Loma Campana, replicate its success in La Amarga Chica and Bandurria, which clearly, our first results in both areas, point in the direction. At the same time, we will derisk other clusters within our extensive shale oil acreage. However, we are not going to neglect our conventional production, and we will continue with our commitment of reducing the natural decline of these fields. In 2018, we initiated a turnaround of our secondary recovery production and there is plenty more to improve this year. An enhanced oil recovery will also be a vector of growth as we move from two projects today to over 20 projects in the next 12 months. Of course, the results from secondary and tertiary are not immediate, but they will be an integral part of our oil production growth over the long term. As we previously explained, it makes no sense accelerating shale gas production in…

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question on line comes from Bruno Montanari from Morgan Stanley. Please go ahead.

Hi, good morning. Thanks for taking my questions. First question, maybe to Daniel, is about the production target. I think we were hoping to see an increase in production. It's totally understandable what's happening with the natural gas industry in Argentina. So just wondering were it not for the gas curtailment, would we have seen an increase in production? So if you could mention what do you expect for oil specifically, what type of growth you're seeing this year would be great. On natural gas, would you say now that the pricing scheme has stabilized in 2019? And if you see any risk of conversion to a local currency pricing instead of U.S. dollar happening at some point in time? And finally, field natural gas, if you could give us an update on the gas receivables you have from the government in terms of timing, what FX level is going to be used, whether the government has been paying in kind or not would be great as well. Thank you very much.

Well, thank you, Bruno. Good morning. Yes, I would say that if we didn't have restrictions on the demand for natural gas production – for natural gas, we'd be approximately 10% higher in 2019 than what we are now projecting. So with that, clearly, overall production on a BOE basis would be higher in 2019 vis-a-vis 2018. Regarding Metrogas, it's difficult to say if pricing has been stabilized or not. I think, in a way, it will depend a lot on how the currency behaves. There were changes imposed last year and this year in terms of setting the U.S. dollar wellhead prices into pesos at the beginning of each seasonal period. So there's two seasonal periods per year. So that, in a way, accounts for – or I think it's a step in the right direction in terms of normalization, if you will. But I would rather see another year of normalization before calling it a win already. And in terms of receivables, what we can say is that as of December 31 this year, the receivables with the distribution companies was lower than the ones outstanding as of the end of September. Half of those receivables have to do with the exchange rate differences generated last year with the devaluation. And those – the government is going to be paying in 30 installments starting in October of this year. They will be paying the distribution companies, and the distribution companies are going to be paying the producers like ourselves. Finally, I don't know if it was part of your question or not, but the big receivable we have regarding natural gas is the subsidy of the plan for 2017. And what we can say today is that the government has already issued the bonds that we are all going to be receiving. And just as a reminder, it's also 30 installments starting in February of this year, fully dollarized, that's approximately $750 million for YPF that we are going to be collecting, as I said, on a monthly basis for 30 months.

Super. Thanks a lot.

And thank you. Our next question online comes from Vicente Falanga from Bradesco. Please go ahead.

Thank you very much. Good morning, everyone. I had two questions only. First off all, when you mentioned that on your guidance you expect your EBITDA to be close to flat, this is compared to the adjusted level of $4.4 billion in 2018, correct? Or am I wrong? And then my second question. Today, on the paper, there was news saying that the government will subsidize a winter auction due to the lack of supply for a price of $8 to $9 per mcf. On the other hand, the government will ask the companies that are being subsidized to build the gas pipeline in Vaca Muerta for $1.2 billion. Just wondering if YPF is expected to participate on this. Thank you very much.

Okay. First, a clarification. Yes, the EBITDA, flat for this year, is based on the $4.4 billion of EBITDA of last year. I haven't read the news in detail, but what we knew the government was going to be saying is two different things, okay, which are connected but are not dependent, one or the other, on the one hand, that they will invite people to bid for a new pipeline, which is something that we all know we need in order to satisfy the pent-up demand of gas during the winter season, okay? And what we can say at this stage is that we are already in discussions with other parties in order to be – if it's something that we want to be part of it. But we are absolutely committed and playing a role in everything that allows us to monetize the significant gas resources that we have. So if this is part of it, we will definitely take a serious look at it. The second thing, which I don't know if it's what you're referring to, but the second thing that we know the government was going to be issuing is a bid to buy natural gas for the winter over a long-term period of three to five years, four years I think it is. I don't know if that is what went in the papers or not. If they do that, that is absolutely great news for the industry. It would provide us with additional clarity in terms of pricing going forward. Having said that, we are working with an assumption of blended average price of natural gas not lower than $4, between $4 and $4.50, which is in line with last year, okay, but clearly below our previous expectations, which were around $5. We don't have an issue of pricing, okay? At those levels, what we can say is that all our significant shale gas projects work very nicely because they have breakevens below those levels, okay? The issue that we have today is more an issue of demand of – not during the winter of course, but demand during the off-peak season.

Perfect. Thank you, Daniel, very clear.

Thank you. Our next question in line comes from Regis Cardoso from Credit Suisse. Please go ahead.

Good morning, Daniel, everyone. Thanks for taking my question. First, I wanted to touch again the guidances or outlook for the year of 2019. If you could, Daniel, explore a little the relationship between CapEx increase or CapEx potentially going to $4 billion and at the same time, you have a production decline in the guidance, so whether this means that a $4 billion EBITDA is only sufficient to keep production flat. Or is this something specific to 2019? Then if you could also comment on – in that case, how would you balance CapEx ramp-up, especially in the unconventional projects you have mentioned. And how do you balance that with financial leverage and whether you would be expecting to increase financial leverage from the current 1.7 times EBITDA, seeing, especially, as you don't forecast an EBITDA growth, right? And finally, just a few follow-up – really quick questions. Is there any impact from hyperinflation accounting to fourth quarter results? Also if you could clarify if there was any impact from inventory losses on lower international crude prices. And also if you could explain the difference between Type Well A and Type Well B on Slide 12 of the presentation. Thank you.

Hi, Regis. Well, that's a bunch of questions. First, on guidance, what I would say is that production lacks CapEx. It always does, okay? So the fact that we are projecting CapEx of $3.4 billion to $4 billion basically provides the basis for production growth in 2020 and onwards. Remember that we continue to target a 5% annual production growth on a sustainable basis, and there was a graph in the presentation that Sergio went through that clearly showed how, especially in the second half of this year, we connect I think it's like 50 new horizontal wells in the three main Vaca Muerta oil developments. And that, of course, takes CapEx – significant CapEx. But that is the growth in production for 2020 and onwards. So the answer to your question is at these levels of CapEx, we can definitely grow production. The thing is that production lacks the investments, comes after the investments. In terms of that ramp-up and leverage, there's no concession there from our part. We have always said that we feel comfortable in the 1.5 to 2 times debt-to-EBITDA range, and we are staying within that range, okay? If it's going to remain 1.70 or if it's going to be 1.85 or 1.60, we don't know. That's the flexibility that we will always keep as a management team, but the board has always been clear with us in terms of this range of 1.5 times to 2 times. And the good news is that we believe that we can grow and that we can grow production 5% per year, staying within this leverage. So the short answer is no, we don't expect to increase leverage beyond that. The – let me skip to accounting questions, and maybe I will ask to repeat them for us…

Sure. Thanks for giving very complete answers. And just the two questions on accounting is whether fourth quarter results were impacted in any way by hyperinflation accounting and also if it was impacted by inventory holding losses, given that international crude prices declined during the quarter, particularly in the Downstream segment, right, which typically holds the crude oil inventories.

Hi Regis, this is Diego. Regarding your question on hyperinflation effect, remember that YPF has its functional currencies in dollars. So we do not have an impact there. Yes, we do have it in our subsidiaries where the functional currency is in pesos. But when we consolidate all those figures into YPF numbers, it's really non-material effect. Actually, we estimate approximately between $40 million to $50 million as a positive effect, but it's not really material for us. Regarding the other question on holding losses, I think we mentioned during the presentation that the fourth quarter has a holding loss. And the fourth quarter of the previous year had a holding gain. And actually, if we were to adjust both quarters for this non-cash item, the growth in EBITDA in dollar terms between one quarter and the other would've been 17%, right? Now the holding gain loss this year doesn't have so much to do with Brent price decline. Accounted intuitively, it has to do with reserve growth. Because with higher reserves, we have lower depreciation. And depreciation is a big part of the cost of the products that we have in inventories, okay? So with a lower cost, we had to revalue down those inventories. And that is what had the effect on the quarter.

Very clear, thank you, Diego for the answers.

Thank you. Our next question online come from Walter Chiarvesio from Santander. Please go ahead.

Yes. Good morning. Congrats for your results and thank you for taking my questions. The first one is you could develop a little bit further on the cost – OpEx cost decline in Loma Campana. Is that – it's just a matter of scale? And is that – could be extrapolated in the other blocks? And how fast could that happen? That is my first question. The second one is related to the CapEx breakdown for 2019 because it's below the average guidance for the five years plan. Is that – has to do with the lower investment in natural gas? Or probably you already mentioned what is the reason. And the third question is broadly for the industry. Because there are many – or not many – but some other companies announcing massive developments in some blocks in Vaca Muerta as well. And I wanted to hear your views on whether there is any potential bottleneck. Or what are challenges in terms of infrastructure either in the supply chains, for example, in the proppants' provisions – one side, ore, on the pipes to evacuate crude oil especially; and also related to that if there is any plan in YPF to export oil sometimes in the future if there were the case of an oversupply of crude oil for the company. I understand that you have a deficit. But probably in some years, that could be reverted. That – those are my questions. Thank you for taking it.

Good morning, Walter. Thank you for the questions. Yes, definitely, the OpEx decline in Loma Campana has to do with the scale. It also was possibly affected by the evaluation, and there's absolutely no reason why we should not replicate that cost structure in the rest of the Vaca Muerta oil window. Of course, we have several hundred wells in Loma Campana already and a few dozens and in the others, right? But long term, the plan that we have as a company is to replicate the success of Loma Campana initially in La Amarga Chica and Bandurria, but, as we said during the presentation, in other areas of Vaca Muerta oil – of the oil window that we are derisking. In terms of the CapEx for 2019, it is definitely below the guidance that we have provided in the five-year plan, slightly below. But the CapEx for this year, 2018, was also below our initial guidance. So I think it's a combination of some gas projects that we have delayed, as we said during the presentation, and probably a more efficient buildup of infrastructure facilities than the one that we were envisioning six months ago. In terms of Vaca Muerta and the potential massive developments from third parties, well, we cannot comment on third parties. What we can tell you is that we believe that we are one step ahead of most of the others, and we have all the infrastructure in place. We are probably the only company that has its own proppant facility with enough capacity to provide for all of our proppant needs even with the acceleration of Vaca Muerta for this year. We have a very good water duct or aqueduct in place, so we have all the water that we need for the fracking…

Thank you very much for the complete answer, Daniel. One follow-up question is regarding the shale OpEx costs that we've seen in Loma Campana. Is that $6 a reasonable reference in the long term? Could be more decline? How – what is your view about it?

Well, the five-year plan talked about $6 over the next five years. So with – I think the bar is already high enough. We can definitely sustain that level. It'll be a challenge to go way below that level.

Okay. Perfect. Thank you very much.

Thank you. Our next question online comes from Luiz Carvalho from UBS. Please go ahead.

Hi, Daniel. Thanks for taking the question. I have basically two questions here, trying to reconcile some data. In the last slide, you basically mentioned that at current prices, the EBITDA is going to be close to flat while production is likely to drop 2% to 3%, right? So the first question here is I mean, how can we expect – and one of the – in the sidelines behind the – I mean, the assumptions that you're using to actually – to have an EBITDA – will affect EBITDA while production is dropping and you have a very challenging environment on the – say, on natural gas price. The second one is about production again. I mean, production this year dropped at 4% to 5%. Next year, it's likely to drop 2% to 3%. And I remember I think at the Investor Day, your guidance was to have production over the last three years – said 2018 and 2019, pretty much flat, right? I mean, the long-term guidance is still unchanged even with a lower, how can say, stock base, the baseline, if I can put it this way. And third question, I know that 2019 might be a challenging one because of the macroenvironment in Argentina with the election you had. But any visibility when the potential JVs are likely to come back and now potential negotiations on this front?

Good morning, Luiz, thank you for the questions. Well, one of the reasons why we believe that we can keep EBITDA close to flat in 2019 is that remember that in 2018, we had several months in which prices of our products were below import parity, below our own budget and therefore, it negatively affected margins, Downstream margins of course, okay? And we – luckily, we started this year without any catch-up to make in terms of prices. So we do expect to expand our Downstream margin, more in line with what we had historically had and not with the $10 per barrel that we had last year. And that should provide for the EBITDA being close to flat. In terms of the production drop and how it compares with the numbers that we have discussed in the different Investor Days, yes, you're absolutely right. We were not envisioning the cuts in gas production last year. Remember what Sergio said: We had like 2.5 million cubic meters on natural gas ready to be produced but could not be produced and injected basically because of lack of demand. You can call it that we misestimated demand, and you would be right. But that is the reason why production was not flat in 2018 vis-à-vis 2017. And for 2019, it's not that different in terms that we had several projects in our business plan, gas projects in our business plan for the next five years that we made a decision of delaying, okay? They continue to make plenty of sense as long as you can sell the gas 360 days a year. If you can only sell the gas180 days or 120 days a year, some of these projects make a little bit less sense. So what we have decided is that…

Okay, clear. Thank you.

Our next question on the line comes from Lilyanna Yang from HSBC. Please go ahead.

Hi, thank you for the opportunity. I actually have two questions. One is on the LNG plant and the status. Can you give a little bit more color about how you see plans evolving there on the LNG front? And the other question is on the ESG and the good improvement. That's great, but could you give us an updated status about the Maxus dispute?

Thank you, Lily. Well, on the LNG plant, unfortunately, there's not much more that we can say. We have done conceptual engineering already. We believe we have a feasibility study that we are going to be sharing with other producers and other players in Argentina and globally that have already expressed interest being part of our project. We do not intend to have a controlling or a majority position in an LNG facility. All we want is to make sure that, that project, if it makes sense, happens because that will be the only way that we can develop our Vaca Muerta shale gas acreage for the long term. Of course, because of the size of something like this, as soon as we have any news, we'll make sure to share it with anyone. But as of today, all we can say is that we have a pretty good idea of what is the project that should be done. But we will share that with other potential investors before making it public. Regarding the question on Maxus, all we can say and actually, it is part of the financial statements and was on the news a week or so ago is that unfortunately, we have filed several motions to dismiss on the trial that were denied by the judge. That doesn't change, in any way, the outcome of the trial because it has not even started. But that's the only news in terms of litigation, in terms of the process so far. We believe that we have a case. In my opinion, it has absolutely nothing to do with the ESG because we were not part of that contamination. YPF acquired that company, well, almost 30 years ago or 25 years ago. And while we were at the helm, there was never any contamination at all. The contamination goes all the way back like 50, 70 years ago. But that's all the news that we have on Maxus.

Okay. Thank you. Appreciate it.

Our next question on line comes from Pedro Medeiros from Citi. Please go ahead.

Good morning, Daniel and Sergio. Thank you so much for taking question and Congratulations with the continuous progress in Vaca Muerta development in terms of costs and productivity. So this is one of the calls I haven't actually made a follow-up, okay, to previous questions, okay? And first, I wanted to come back to the guidance for 2019. And then you talked about how refining profits should be the main source of recouping potential losses when you think on a year-on-year basis in terms of prices and then production decline. But I also wanted to understand whether you're counting with improvements in your production cost to actually compose that guidance. And for the guidance itself, you talked about declining production of 2% to 3%. But would you mind sharing your view of exits, production growth rates? There's a significant amount of new capacity in new wells being put out in production from Vaca Muerta in the second half of 2019 especially on the oil front. So anything or any color you could give on fourth quarter 2019 over fourth quarter 2018 exit production growth rates would be very interesting to hear. The second question is on Slide 12, you have outlined the evolution in type curves in Loma Campana. And I know you already talked a bit about those type curves, but I was wondering whether you could share some of the early results from the 3,000-meter lateral wells that were drilled in Loma Campana and put in production in 2018. My third question is coming back to the commercial LNG solution that you have just commented on how you already have a pretty good sense of the engineering and what the project will look like, but I just wanted to understand if there is any sort of like preliminary potential schedule of when a solution like that could come to the market and whether the kind of solution you guys are looking for would be an export hub through Bahia Blanca or from Chile into a commercial-sized facility. And my last question, Daniel, is could you comment a bit on the progress made in plans to divest from assets in power and natural gas distribution? Thank you.

Hi, Pedro, well, let me start from bottoms up, from the end. In terms of progress on asset sales, you mentioned gas distribution. We are not actively doing anything as we speak until the gas market generally and specifically for the LDCs clears and it’s – we have something more concrete eventually to offer to our potential investors. So you should not expect anything right away there. Obviously, the strategy continues to be the one of maximizing the value of the assets for YPF. And those assets, which we believe can be worth more in hands of someone else than in our own, we are willing to divest. And that’s where Metrogas eventually could fall into. But you also mentioned power. In power we are not working and we are never been working on any divestment. What we have been doing is the capitalization of our power generation subsidiary, of which we own 75%. But we would be willing to be diluted – but not to sell our shares, to be diluted if a third party comes in with more equity at the right valuation that would allow YPF Luz to accelerate its growth plan going forward. Your previous question regarding the LNG unfortunately, I understand the question. And I understand why you’re asking the question. But unfortunately, we are not in a position to share absolutely anything regarding this until we share it with people that are interested in eventually investing or coinvesting in this project. So when we have news, we’ll let you know. In the meantime, all we can say is that we are interested in finding the right project and making sure that the right project occurs and eventually, taking a small equity stake, if we have to, in that project. And that’s all we could say. Regarding the 3,000-meter long well that we have drilled, we haven’t disclosed any figures so far. What we can tell you is that the results were good, were okay and pointing into similar development cost than the 2,500-meter long lateral, so not evident yet, the improvement of going to 3,000. But again, it’s just one well. So it is likely that we will drill more of those that we – as I said, that we have planned to drill even 4,000-meter long laterals in order to find what is the sweet spot. And the sweet spot is not necessarily the same in different concession areas or even different areas within one block, okay? As we showed in our well type curve for Loma Campana, we might have – we actually do have several well type curves in each of the blocks that we operate. And there’s – unfortunately, there’s nothing more than we can say about that. And then you had a question regarding guidance. What was that, Pedro?

The guidance – the question on guidance was whether you’re counting with any improvement on production costs for 2019 and if you could share some color on your expectations for exit production growth rates. You talked about average of the year of 2%, 3% decline. But there is significant new amount of activity in the second half in terms of new wells being plugged from the new projects and from Loma Campana. So I just wanted to understand if you’re forecasting growth on a fourth quarter-over-fourth quarter basis?

Well, clearly by the fourth quarter of this year, we will already be growing crude oil production. That’s all we can say. We are not going to be providing any guidance. We never do on a quarter- per-quarter basis. The last thing that we said and we can repeat is that given all that activity that you referenced to in the shale, shale oil production is going to be approximately 20% of crude oil production by the end of the year. So that’s another relevant data point. And in terms of OpEx for the year, we are not assuming any significant savings or cost reductions vis-a-vis last year. Remember that last year, we had the positive impact of the devaluation. And what we intend is to keep all of that – all of those savings for the future, structurally, if I can say. But we are not assuming a significant reduction in costs when we say that we expect to have our EBITDA approximately flat next year.

Okay. Perfect, Daniel. Thank you so much for the answers okay.

Thank you. And our final question comes from Daniel Guardiola from BTG. Please go ahead.

Hi, good morning guys. I have couple of quick ones here given the fact that this is the last question. My first question is regarding reserves. And I would like to know if you could please share with us part of the details with respect to the additional reserves. And more specifically, I would like to understand the contribution from unconventional basins before the implementation of secondary recovery mix and the effect that higher prices had on the additional reserves. So that’s my first question. And my second question is regarding the upcoming elections, Governor elections in Neuquen. And I’d like to know your thoughts on potential implication for the development of Vaca Muerta coming from the outcome of these elections. Thanks.

Well, on reserves, the breakdown that we can provide at this stage is that unconventionals or shale represents approximately 20% of our proven reserves and that the increase in reserves from last year to this year comes from both the good performance in unconventionals generally and in some conventional fields but also with the improved economics of all of the fields. It’s not just about price. It’s price and cost. But clearly, improved economics played a role. And regarding your second question on the elections, of course, we are not going to be commenting on elections, which are 48 hours away. All we can say is that Vaca Muerta seems to be one of the few things in Argentina that everybody agrees on, that it’s a good part of the future. A good part of for future relies on developing Vaca Muerta, and that’s widely understood at a national and provincial levels in all different parties.

Well, if there’s nothing else, thank you, Daniel for the last question and everybody else for all the questions and keeping up with us during this long call. If there’s any follow-up, please feel free to call either Sergio, Diego, Pablo or myself anytime. Have a great day, a good weekend. Bye.

And thank you ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.