YPF Sociedad Anónima (YPF) Q2 2017 Earnings Report, Transcript and Summary

Welcome to our second quarter 2017 YPF Sociedad Anónima Earnings Conference Call. My name is Sophia and I will be your operator for today's call. [Operator Instructions]. I will now turn the call over to Diego Celaa. Mr. Celaa, you may begin.

Great. Thank you, Celia. Good morning, ladies and gentlemen. My name is Diego Celaa, Head of Investor Relations at YPF. I would like to thank you for the joining the YPF second quarter 2017 earnings webcast. The presentation will be conducted by our CFO, Mr. Daniel Gonzalez. During the presentation, we will go through the main aspects and events that explain our second quarter results. And finally, we will open up call for questions. We will be making forward-looking statements, so we ask to carefully review the cautionary statement on Slide 2. Our agenda today will include the review of the second quarter results, including an update of our shale and development project, our brief description of our financial situation and a brief summary to conclude. Also, our financial statements figures are stated in Argentina pesos and in accordance with international financing recording standards, IFRS. In addition, certain financial figures have been adjusted to reflect additional information to let you better understand our key financial operating results. Please, Daniel, go ahead

Well, thank you, Diego. Good morning, everybody. Thank you for joining us today for the review of our second quarter 2017 results. This was a solid quarter, generally in line with our expectations, with 2 exceptions. On the positive side, demand for our products was particularly strong during the quarter; but on the other hand, production of crude oil was weaker than the plan. Revenues were up by 14%, when compared with same period of 2016, despite prices for our main products being soft during the quarter, however, these prices recovered substantially in July. Adjusted EBITDA reached ARP 16.2 billion which represent a 6% reduction. And we recorded a net income gain of ARP 272 million compared with a loss of ARP 750 million a year ago. As in the first quarter of 2017, we had another period with strong operating cash flow of ARP 13 billion this time, an increase of around 96%. And for the second straight quarter, we had positive free cash flow before interest. Total CapEx was down in this second quarter by 10% in pesos as a result of a reduction in activity that we had budgeted for the year in our upstream business and the finalization of projects in the second half of last year in our downstream operation. Total hydrocarbon production was down 4.2% vis-à-vis a year ago. Natural gas production was essentially flat and crude oil production was down 10%, heavily impacted by some of the worst weather conditions on record in the south of Argentina. We will explain this in more detail in a second. In this slide, we show our main financial figures measured in US dollars. This second quarter, the local currency depreciated by 10.6% when compared with the same quarter of 2016. Revenues in dollars were up by 3%, driven by a strong demand of gasoline and other refined products. Prices, on the other hand, for the most relevant fuels were lower than a year ago. In dollar terms, 6% and 3% lower for diesel and gasoline respectively. However, export prices were up, in line with the recovery of the international prices. And the price for natural gas was also up. In this case, in average, 3.8% in dollar terms. Cash costs expressed in US dollars increased by approximately 7.5%. Listing cost was essentially flat, in dollars, in absolute terms, although slightly up on a BOE basis due to the reduction in total production. Royalties which is the only cost component fully denominated in dollars, were down close to 8% as crude oil domestic price and production declined more than the growth in natural gas sales. So the one item that caused this cash cost increase is the purchases of the crude oil biofuels. Crude oil purchases were up by 47%, as our own production was down while we processed more crude than a year ago to cope with strong demand of the quarter. EBITDA in dollar terms was down 14.8%. By the comparison, it's affected by the fact that in the second quarter of 2016, EBITDA had been positively affected by a one-off gain derived from the deconsolidation of Maxus approximately $100 million. Let's switch back to Argentine pesos to go over a more detailed analysis of the quarter. Operating income was down by 35% and this decline was concentrated in our upstream segment that had a difficult quarter on lower production and lower crude oil prices. Downstream operating income, on the other hand, stood almost flat vis-à-vis a year ago, due to combination of higher demand and slightly higher crude prices. Finally, our gas and power segment showed better results due to better rates in our subsidiary, Metrogas gas which will actually improve further with the second and third legs on the increase -- of the price increase kicking in the next few months. Additional power duration business also improved, showing an increase of 80% in the period. In order to better understand the reasons behind the reduction of ARP 1.9 billion in operating income, we've broken it down into more detail. Revenues grew by ARP 7.4 billion or 14%, resulting for different factors, first, an increase of ARP 1.9 billion in gasoline sales, with higher prices in pesos of 7.4% and an increase in sale volumes of 8.9%; second, ARP 1.8 billion increase in natural gas sales due to prices which were 19% higher in pesos and on a slight increase in sale volumes of less than 1%; third, ARP 1.6 billion increase in natural gas sales in the Retail segment which is mainly explained by our subsidiary, Metrogas, on an increasing price of 145%, but lower volumes of 26% due to the milder weather in the fall and in the early winter. Then there was a ARP 500 million increase in asphalt sales with higher prices in pesos of almost 20%, but an increasing sale volumes of 188%. Then there were higher exports of ARP 680 million on higher volumes and also higher prices. And we had diesel sales which were almost flat because we had 4.5% increase in prices which was partially offset by a 4.1% reduction sales volumes and I'll explain that in a couple of slides. Finally, fuel oil sales decreased by ARP 1 billion on lower volumes of approximately 25% and 16% -- sorry, 17% lower prices in pesos as a power generation sector had plenty of gas available to replace fuel oil. Cost of sales. Our depreciation increased by ARP 1.9 billion. The factors explaining the increase are the following, First, the listing cost which, in absolute terms, grew by ARP 1 billion or 11%; second, transportation expenses which increased by ARP 380 million or 23%; third, the refining cost which was up by ARP 295 million or 13%; and finally, the Royalties which, as I mentioned, are fully dollarized, as they are baked to the promises on wellhead prices which are set in dollars. And they presented a slight increase of only ARP 79 million or 2% driven by the 11% devaluation within periods but partially offset by the lower crude oil prices and the lower production of crude oil during the period. Depreciation was up by 7% or ARP 716 million as CapEx intensity has been lower than in previous periods. And the value of our assets which are carrying dollars, did not suffer significant increase in during this last couple of quarters. Purchase of crude oil and other products for sale increased by ARP 4.2 billion. And here's how that numbers broken down: First, crude oil purchases from third parties increased by ARP 1.5 billion, mainly as a consequence of a 55% increase in the volumes which were driven by the lower production of the period. Second, purchases of biofuels increased by ARP 1.1 billion as a result of higher prices in pesos and higher volumes of both SNL and biodiesel. In the case of SNL, fueled by increased blend rate to 12% and also fueled by the higher demand in gasoline; third, purchases of natural gas by our subsidiary, Metrogas, increased by ARP 835 billion, driven mainly by the price increase that is of public domain of 73%; then purchase of grains in our agrobusiness had an increase of ARP 356 million, mainly due to an increase in volumes of 27%; and finally, imports were up by ARP 277 million due to higher imports of diesel oil of ARP 290 million and lower imports of jet fuel of only ARP 12 million. SG&A was up by 12% as a consequence of higher transportation expenses and salary increases. Exploration expenses increased by only ARP 95 million which was mainly due to higher charges of unproductive exploratory wells. And the other operating results in the second quarter of '17 decreased -- that gain decreased by ARP 1.6 billion or 100% almost due to a net gain of ARP 1.5 billion that had been recorded in the second quarter of 2016 because of the deconsolidation of Maxus. Entering now into our upstream business segment. In this second quarter, we registered an operating loss of ARP 884 million. Revenues showed a decrease of 4.4%, reaching ARP 26.6 billion, driven by following combination of factors: On the one hand, lower crude oil sales by ARP 3.1 billion or 16% due to a 10% lower volumes transferred to our downstream business segment at 4.4% lower prices in pesos; and second, higher natural gas revenues of ARP 1.8 billion or 20% on higher prices in pesos and also higher in dollars, by the way and a slight increase in volumes. In line with the terms of the agreement between the refiners, producers and the government signed earlier this year, the average realization price in dollar terms for crude oil decreased to $52.5 per barrel with average prices of $56.1 per barrel for light crude oil and $49.3 per barrel for heavy crude, respectively. For natural gas, the average price was $4.91 per million btu which was 3.8% higher than the second quarter 2016. Now on the cost side, these were up by ARP 1 billion which was a 3.8% increase compared with last year, explained mainly by the increase in 'items related to the lifting cost. Now the listing costs on per-barrel equivalent basis increased by 4.5% compared to the second quarter of last year to $12.08 per barrel. This was mainly due to the production decline. And the total cash cost per BOE reached $21.03 per barrel, including royalties and other taxes of $5.5 per barrel. Exploration expenses increased 13%, as we also described in the previous slide. Crude oil production in the second quarter decreased 10% to 218,000 barrels of oil per day. Approximately half of the decline was already expected and reflects the reduction in activity that we started last year. The Perales was mostly a consequence of an unprecedented flooding in the south of the country and the beginning -- at the beginning of the quarter followed by heavy snowstorm 3 months later. Additionally, some labor conflicts in the provinces of [indiscernible] and Mendoza also had a negative effect in production. Now natural gas production showed a slight increase -- sorry, a decrease of 0.5%. We produced 44.6 million cubic meters a day, while NGLs production increased by 3.7%, producing 51.4000 barrels per day. As a result, total hydrocarbon production dropped 4.2% vis-à-vis the same quarter of 2016 to 550,000 BOEs a day. Now let me provide an update on our shale gas and shale oil activity. Net shale production of the quarter reached 35.3000 BOEs a day which represents a new all-time high. In terms of our activity as operators, during the first quarter of the year, we connected a total of 22 new wells, taking the total count to 577 shale wells in production and increasing the total gross operator production to 67.4000 of oil equivalent per day. Now let's bear in mind that during July, we have finalized the formal process of our Jaramillo block to Shell, including the assignment of the operation. So the next quarter and periods thereafter, the producing wells and production coming from this block will no longer be included in these figures as operator. In relation to the well cost, I would like to highlight that as we have started to test longer lateral length wells, we have excluded from the well cost comparison those that have a design with longer laterals than our 1,500 type well -- 1,500 meter type well. Having said that, in this quarter, our type well cost in Loma Campana continued to be in the $8.2 million area. As we mentioned in the last quarter, several wells are well below the $8 million cost mark. So as long as we continue moving through the learning curve and improving our operational performance, there is no reason to think that we will not reduce this cost further. In this quarter there was devaluation of 11% which was clearly below inflation in that same period. Therefore, we went through our real appreciation of the peso. This obviously negatively impacted costs expressed in dollar terms. Let me go through some of the positive things that we're doing in our shale operations and that injects additional optimism regarding the future of the development of the shale in Argentina. In this quarter, we have successfully completed 2 wells with 2,500 meter long laterals, one, with 32 frac stages and the other one with 30, both in Loma Campana. These wells were connected in the first week of August, so we're still in flow-back mode and we will only have meaningful production data in the next couple of months. We have also drilled -- are in the process of stimulating 6 wells in line in one part, each of them with 2,000 meters long laterals in El Orejano. And by the way, we're seeing a significant increase in the efficiency of the fracing operations. We're doing 5 or 6 frac stages per day in El Orejano while we were doing half of that a year ago. Additionally, we have drilled in El Orejano a well with a longest lateral length in Vaca Muerta of more than 2,700 meters and that was drilled in 18 -- 28 days. We have tested geo steering technology while drilling 2 wells in Loma Campana. This will allow us to drill and navigate within the best quality zone of the rock, improving productivity and lowering the risk of casing information during the stimulation process. Now regarding our new shale pilots, we started to stimulate wells in Rincon del Mangrullo at La Ribera blocks, where we have 100% stakes. And we have also begun to drill in Baja [indiscernible], in Bandurria, Aguada de la Arena on the first 2 weeks with stakes of 50% and the last one which is a fully owned by YPF as -- was acquired last year. And we expect to start another 2 shale pilot projects before the end of 2017. With regard to our tight gas projects, I would like to clarify that we're now adding to the tight gas production, the tight gas derived from 3 blocks which produce mainly conventional gas and that we were not showing as tight in the past. Having said that, we're showing the chart on net tight gas production which continued to show encouraging results, reaching 13.8 million cubic meters a day. And this way, tight gas production represents now 31% of our total natural gas production. In terms of activity in tight gas, we have put in production 8 wells probably in the Lajas formation in Aguada Toledo, where we own 100%; 4 wells targeting the [indiscernible] confirmation in the Rincon del Mangrullo, where we own 50% and 9 wells in Estación Fernández Oro where we also own 100%. Now turning to the downstream segment. We reported an operating income of ARP 3.1 billion, slightly above the ARP 3 billion operating income reported last year. Revenues were up by ARP 4 billion or 10%. And as I explained before, gasoline sales were up by ARP 1.9 billion on 7% higher prices and 9% increase in volumes. And sales volume of our premium gasoline, Infinia, increased by almost 30%. Diesel sales were almost flat compared with the same quarter of 2016 due to the combination of a 4.5% increase in diesel mix prices which was partially offset by a 4.1% decrease in sales volumes. However, here is also worth highlighting, the increase of 23% in sales volumes of our premium product Infinia Diesel. Sales of asphalts increased by ARP 500 million, explained by almost tripling the volume which underscores the strength in the construction activity and public works in Argentina. Fuel oil sales dropped by ARP 1 billion on lower volumes and prices, as we explained before. And finally, sales in the export market increased by 17% or ARP 700 million due to good volumes of jet fuels, LPG and petrochemicals. And I will also add virgin Nafta. Costs increased by 10% or ARP 3.5 million compared with the same period of 2016. And there, we have to highlight: First, lower crude oil purchase of ARP 1.2 billion on lower prices and lower volumes transferred by our upstream which was partially offset by higher volumes purchased to third parties; then, higher purchases of biofuels of ARP 1 billion with higher prices for both biodiesel and ethanol of 12% and 21%, respectively; and ethanol volumes increased by 20% due to increase in the blend rate for gasoline from 10% to 12%, while biodiesel volumes increased by only 6%. We had higher diesel imports of ARP 277 million. We have an increase in the refining cost of almost ARP 300 million. And finally, higher depreciation of ARP 350 million. During the quarter, the volume of crude oil processed in our refineries was 295,000 barrels of oil per day which was 2.2% higher than last year. Regarding domestic market, total sales increased by 1.1%, driven mainly by the 9% decrease in gasoline, the increase in asphalts that I also made reference to before and partially offset by the reduction of diesel oil and fuel oil demand of 4% and 25%, respectively. As we can observe in the graphs noted in this slide, demand was very strong for gasoline with our 9% increase, as mentioned in the previous slide and weak for diesel with a 4% reduction. As with respect to diesel, the drop in sale volumes was mainly driven by a significant reduction in the demand of powerplants explained by a much higher availability of natural gas due to the mild weather and this was partially offset by an increase in sale volumes in the agro and transportation market. So if we were to perform at the sales of diesel for those sales to the power sector, the diesel sales to the agro and the transportation and industrial customers would have been up in the quarter vis-à-vis last year which is a big difference with the previous quarters in which we were seeing a reduction vis-à-vis the previous year. Now in July, despite the price increase in the first week of the month of 6% and 7% in diesel and gasoline, respectively, sales of both products showed a similar behavior by the previous months. And actually, in the case of diesel, sales were actually even stronger than the second quarter. So these are all good signs. Market share for both bricks continued to be strong with 55% in gasoline and 57% in diesel. And market share for premium products is even stronger with 61% in premium gasoline and 58% in premium diesel. In our gas and power segment, we continued construction of the 4 new projects that will allow us to reach a total generation capacity close to 2 gigas. Our thermal projects at Loma Campana 1 and Loma Campana 1 which will add a total of 205 megas, are expected to start up in this second half of the year. Regarding the thermal project in Tucumán, operation is expected to start during the first half of 2018 and this will add 270 megas. Similarly, the project is also expected to start up during the first half of 2018 and will add 100 megas. In terms of new projects, we're expecting to participate in today's power auction for power generation and/or combined cycles. But finally, as we mentioned in the previous call, we do not intend to allocate any meaningful capital in new power projects as we continue making progress to incorporate an equity partner to capitalize on power subsidiary. During the second quarter, total CapEx for the company amounted to ARP 13 billion which was 10% lower than last year or 18.7% down if we measure it in dollar terms. Upstream CapEx amounted to ARP 9.9 billion, an increase of 13% and our activity is mainly focused in drilling and workover which represented 71% of the upstream CapEx, followed by buildup of facilities with 25% share of the total and exploration and other activities representing 5% of the upstream CapEx. During the quarter, we drilled and put in production a total of 112 new wells, including 22 new wells in shale areas and 21 wells in tight gas formations. The most meaningful investments have been taking place in the Neuquina basin, most specifically in unconventionals, in all the shale and tight gas blocks where we have activity. And in conventional areas, in that basin. It was basically in the Chachahuen block. In the Golfo San Jorge basin, activity was concentrated in 2 blocks, Manantiales Behr and El Trebol. In Neuquina basin, we continue the development of Barrancas, La Ventana, [indiscernible], Vizcacheras and in the basin, preparation activity commenced in La del Fuego block. With regards to exploration in this quarter, we completed 3 explorative wells, 2 of them with natural gas objectives and 1 looking for oil. In downstream, CapEx was ARP 1.9 billion which is 19% lower compared with the same period of last year. And to highlight, during this period, was the advance in the revamping of the topping 3 units in the Lujan de Cuyo refinery and some logistics and safety improvements. Last year, we were still finalizing the [indiscernible] facility and that is part of the explanation for the decrease in downstream CapEx in this quarter. And finally, in our gas and power segment, CapEx reached ARP 1 billion and this is a result of the construction of power plants which I discussed a couple of slides earlier. Now let me address our financial situation. Solid operating cash flow of ARP 13 billion which represents a 96% increase compared with the second quarter of 2016. And this was mainly driven by an improvement in working capital, mainly due to collection of receivables arising from the gas plant program, but also for lower income tax payments. This is the second quarter in a row that we're showing positive free cash flow before interest. And we can see in the graph at the left how operating cash flow slightly exceeded CapEx in the period. This cash generation, coupled with a sound financing performance and including the dollar denominated sovereign bonds that we hold in treasury, result in a strong cash position of ARP 29 million at the end of the second quarter of 2017. The previously explained cash position is enough to cover our debt maturities of almost the next 12 months, as our the next important debt maturity is only in December 2018. This cash position was strengthened further with the recent $750 million bond with a 10-year tenure on 6.95% deal which we placed in July. Our leverage ratio stood at 1.98x net debt to EBITDA inside of 2x target for the year. The average interest rate in pesos was 22% and in dollars was 7.8%. So in summary, strong demand for fuels seen in this first half of the year. We affirm our view that the economy is looking better. And we're optimistic that the rest of the year will improve even further. The application of the fuel pricing formula agreed earlier this year between producers and refiners on the government resulted in soft prices in the second half. But since devaluation has accelerated by the end of the quarter, we have been able to adjust prices upwards in July. And we expect to continue to pass through the effects of crude oil prices, biofuels and the effects into prices. As we explained in previous quarters, we're committed with our objective of achieving structural cost reductions which, we think, are core for the industry as we're preparing the road for our local industry with prices fully converged with international prices. And our cost structure is evolving well below inflation and we yet have to see additional cost reductions derived from rebidding of contracts at lower rates and derived also from the full application of savings coming from the amended labor agreements. In addition, the recent improvements in our completion works in Vaca Muerta should result in further cost reductions and efficiencies, in line with this objective. It was a difficult quarter in terms of production, as weather conditions had a material negative impact. It was painful for all of us to see the complications that these unusual heavy rains and the strong snowfalls brought to the cities in the south of the country where we operate, but we have recovered most of the effects. Unfortunately, we will not be able to make up for the lost production. And therefore, we're revising downward our production guidance for the year to minus 3.5%. Finally, for the second consecutive quarter, operating cash flow was -- have outpaced the amount of CapEx, maintaining our leverage ratio within the 2x area and proving our commitment to financial discipline. So with this, I would like to pause it here and take your questions. Thank you.

[Operator Instructions]. And our first question comes from Bruno Montanari from Morgan Stanley.

First question is about fuel prices. So there have been a lot of questions about the next price readjustments because of the currency move. Could you address how the policy has behaved, especially -- and then what you -- what do you expect in terms of timing for the next movement? Understand it's challenging because it would probably be early October, so does it make sense to defer the next movement maybe to November or later? The second question, very encouraging to see the company going for the longer laterals with the horizontals. I know you mentioned in series, you talked about the extra production data, but can you share with us the potential recovery of those wells and then what the normalized cost of those could be? And if I can add a third one. You did mention that the new labor contract from conventional, so can you give us an update on the relationship with the unions, how the new contract for unconventional is going and if there are any efforts to implement similar flexibility also for the conventional areas?

Good questions. On the fuel prices, why I would say is that formula that was put together is working well for all parties. I think it was a very good way of coping with this soft landing of local crude oil prices with the international prices. We're almost there. As I said, average realization price for crude oil was -- I think, it was $53 per barrel during the quarter. So we're almost there. That is a very good news. I think Argentina is going towards a normalization of prices, generally. And frankly, I don't see any reason why that will change. So -- of course, the adjustments for the fourth quarter will be determined upon what happens in the last few weeks of September, with what happens with local crude oil prices which are denominated in dollars, what happens with biofuels which are also denominated in dollars. And I don't see any reason why we would not apply eventually a pricing increase if that is warranted as we did it in early July. Someone could have made the argument also in early July, we're a month away from the primaries and still, there was no pushback from anybody. And the best news, I think, Bruno is that demand was really strong in July, despite of price increases, okay? So clearly marking that we don't have an issue of prices. So as always, we will be sensitive of when is the right moment to increase prices, but no reason at all to be concerned regarding our ability -- our future ability to continue to comply, all of us refiners and producers with that formula that we all put together. Second, on longer laterals, I shared with you -- [indiscernible] that it is good news. Having said that, we yet do not have any figures to share. Certainly, in our next webcast next quarterly call, we will have some figures to show. The reason why we're moving to longer laterals is because, at least the theory, the economics look much more promising because obviously, they are more expensive than the 1,500 meter wells, but the productivity expected out of these longer lateral wells more than offset that increasing cost. So hopefully, in a couple of months, we will have news. But so far, what we have seen is all positive in terms of the cost of the wells and the initial production, although they are still in a flowback mode. And as I have repeatedly said, we usually do not disclose IPs because that depends on our choke management policy. And we'd rather just talk about EURs or eventually provide initial production after wells have several months of history and not just 30 or 60 days, as our people do. Finally, on the labor relations, I think labor relations continue to be extremely good. We have, as you know, this year, put in place amendments to some of the contracts. Officially, everything applies for the unconventionals in Neuquén. And then to some of the labor agreements in Chubut, I think we're going to be doing something similar. Hopefully, the province of Santa Cruz. where we definitely need to improve profitability there. Otherwise, it's difficult to continue to develop. But I think that what we've seen this year is a significant change in the trend of the labor relationships of the industry with the unions, by which both parties understand that a more efficient industry will result in longer activity over the medium and long term. And I think we're all focused on that and the good news is that the most union leaders are in agreement with that either. So we're positive. Of course, these things take time to implement. The amendments to the unconventional labor agreement is taking some time to implement, but we're starting to see improvements. As I mentioned, we're seeing a record of frac stages per day. And this would have been impossible to be achieved without the commitment of our workers. So I think it's a good trend, the one that we're starting to see here.

Our next question comes from Andre Natal from Crédit Suisse.

My first question would be in regards to the plan gas. I would like to know, from what you can see now, what are the prospects for the evolution of residential prices and whether in 2018, we should already see the normal regular market prices already above what the plan gas would offer you or if otherwise? I think my second point would be in regards to cost. You mentioned a couple of things you're now doing in order to compensate for the wage inflation that is already -- can be foreseen to the second half. I would like to understand, as you can see if those initiatives are likely to more than compensate for that or how we should think about cost if all the -- over the couple of quarters ahead. If you'll -- will those other initiatives compensate for the wage inflation or not? And in regards to production, a quick update if you can give us, please, on the time line and the potential cost related to the recovery of the impacted areas in [indiscernible] Santa Cruz, et cetera, if you could give any color on how fast and how costly that should be would be great.

Okay. Andrew, thank you very much for those questions. On the gas prices, the new tariff -- or well head price of gases -- of gas for residential customers was put in place last year. And it's working well, in my opinion. And the new gas rate for the distribution companies, at least the first leg, also came in place in April. So we're only starting to see the beginning of a normalization in residential gas prices. I -- we do not see any reason why the price pass that was announced by the government earlier this year would not be applied. So we do believe that residential customers will gradually start paying gas prices more in line with the cost of gas at the well ahead and towards a reduction in the size of the subsidy. So I don't think that will be changing. That doesn't imply that we will be above the plan gas, okay? We're, as I said, in average, at $4.91 per million BTU . That number is expected it to continue to increase in the next couple of years, as we have more unconventional production as part of a total mix of our production with prices in line with the new gas plant that will be put in place that starts at $7.50 and all -- goes all the way down to $6 per million BTU. So gas prices, I think, are okay, are the kind of prices that we need in order to develop all of our shale and tight gas projects. In terms of costs, what we're expecting for the second half is that cost will probably be flat or slightly down in dollar terms because the devaluation of the last month has helped us. We were concerned, I think I discussed this in one of our calls, where the effects of real appreciation of the peso, the effects on costs in dollar terms, especially if we think that our revenues are dollarized. Now we believe that with the effects of devaluation catching up with inflation which is what we've seen in the last couple of months -- or last couple of weeks, I would say, coupled with those efficiency initiatives I've made reference to, I think we have everything in place to see a slight reduction in lifting and -- lifting cost in dollar terms on a per barrel basis. In terms of the recovery of production, in the South, I can tell you that today, we're above 90% recovered in terms of daily production. What we will not be able to do is to make up for that production that was lost during the weeks of -- that were affected. And that is the main reason why we -- unfortunately, we're revising downwards our production estimate to 3.5% area.

Just a quick follow-up, if I may. If you could also update us on -- in regards to the -- what should happen to gas prices for the other markets like the -- everything else than the residential, so thermal power plants and the industrial consumers, how should that evolve in the next couple of quarters or years?

Well, the gas prices for the IPPs and industrial customers, the most relevant industrial customers were already well above residential prices, right? So the issue of prices that we've had for many, many years was basically concentrated in the residential segment. So what we really care about is what is our weighted average price of our natural gas. With the increase in that residential price, what we will see some reduction in the subsidy and a slight increase in the weighted average price of gas. So I think, as I said, that we're trending towards the $5.5 to $6 range per million BTU. Residential prices will take longer to get there. Some of the industrial customers on IPP are not really far from there. So as I said, I think that we're gradually trending towards where we need to be in order to assure that all of our shale and tight gas projects make economic sense. And by the way, it's a no-brainer for Argentina as a whole because the alternative for the local gas being sold, let's say at $5 to $6 per million BTU is importing LNG at prices which are higher today and I would say when you take a longer period of time, substantially higher, right? And again, the alternative to LNG would be burning diesel oil which is, obviously, much more expensive, either. So I think structurally, we're in a very good position in terms of assuring the price that we need in order to develop all of our shale and tight gas potential.

Our following question comes from Frank McGann from Bank of America Merill Lynch.

Just in terms of the outlook for nonconventional production growth over the next couple of years, with the -- and next couple of quarters as well, with the changes in JVs and the expected CapEx and development spending that you're doing in different areas, I was wondering what -- how you think overall production trends will develop, both -- again, over the next couple of quarters and next couple of years? Secondly, just in terms of CapEx, what's your expectation now in terms of CapEx for both this year and next year?

In terms of CapEx for this year, we had guided approximately $4 billion. I think we're going to be below that because in the first half of the year, in both quarters, we were below our own expectations in terms of CapEx. So we're going to be slightly below this $4 billion mark. That is our projection today. Going forward, I think, as I've said in the past, this company should be able to grow hydrocarbon production between 3% and 5% per year with CapEx in the $4 billion to $4.5 billion area, okay? We don't need to go back to $6 billion CapEx numbers as we had to go through in the past, where we were building up a lot of the infrastructure that now we can leverage on, right? In terms of our production trends, the JVs that we have signed will only have a positive effect on production because we're not JVing areas where -- that had any significant production in the past, right? So it's not that we're giving away 50% of production that was already in place. What we're giving away is 50% of production that will come. And when I say giving away, of course, it is in consideration for the current investments that these partners are doing for us. So from an economic perspective, they make plenty of sense. From a production perspective, they will only add production going forward. And as the general trend has been for the company that I don't think will change is we have a legacy conventional production with a high decline rate. We have been fighting that decline and keeping it essentially flat. I think, going forward, it's going to be tough to keep it flat. Having said that, between the tight and the shale, we're the partners, net YPF, we should be able to offset all of that legacy production decline and then provide for that total production growth. That is our vision for the future.

Okay. If I can follow up just in terms of the balance sheet and how you're seeing the balance sheet in an environment where oil prices look increasingly uncertain and the overall look is somewhat complicated. How are you feeling about the balance sheet today?

Well, we feel very comfortable with our balance sheet today. I think that you will continue to see our leverage at around 2x. It could be slightly higher, could be slightly lower. And over the long term, our reason is to take that down to 1.5x. We have proved a few weeks ago, when we accessed the international debt dollar market, we had a -- we did a very successful 10-year new issue at record low yields for us, below 7%. So I'm not seeing any difficulties at all. As usual, we're being conservative in building up our cash cushion in advance of potential volatility, in this case not so much related with the -- with crude oil prices which we've seen for a couple of years already, that volatility, but connected with the results of the elections in Argentina. So we have all the cash we need for the next 12, 18 months. And as I said, we feel very comfortable in situation where we stand. And we will continue to plan always under the assumption, under the, I'd say, the mandate that we have from our board to keep financial discipline and not to increase leverage.

Our next question comes from Anish Kapadia from Tudor, Pickering, Holt.

I just wanted to go back to some of the wells you've been drilling in the Vaca Muerta this year. In terms of the standard design that you've been staking towards the 1,500 meter and 18-stage laterals, can you give an update on what the -- how the production rates when compared to this year versus last year? Have you seen any kind of uptick in the IP rates or the EURs that you're seeing? And in terms of the new well design, the 3,500-meter wells, what would your expected well cost base for those wells? The second one was just in terms of the other well that you've been drilling outside of the Loma Campana area. Can you just give some idea of how those wells have been performing in some kind of comparison, those 1-component wells for the initial pilots that you're seeing? And then just a final one on your EBITDA guidance. I think previously, you've talked about $4.2 billion for 2017. Does that still stand? And assuming a flat oil realization in 2018, what kind of EBITDA growth do you think we can see?

Okay. Thank you very much for that. In terms of the horizontal wells with 1,500 meter laterals that has been on a well type curve, although as we've said, we're moving towards longer laterals, especially if the results of the first wells that we're drilling and completing are successful. What I can tell you is that the wells drilled in 2017 are looking better than the wells drilled in 2016 and earlier, okay? So that is good news. I will not provide IP figures yet because the '17 wells are being in production for -- depending when we have the -- pull them in production, but from 30 days to 180 days, it's probably not enough for us to provide IPs. But what we can provide is EURs and we're targeting 570,000 barrels of liquids plus gas, so we're talking about in the mid-600,000 BOEs of cumulative production for wells with 1,500 meter of laterals and 18-frac stages. So that looks good. Now going to the next question, I think I, unfortunately, will be less precised. But for the longer laterals, the reason why we're doing this is because we're targeting the 1 million BOE mark for some of the -- of these wells, right? So still, I'm not in a position to disclose a well type curve, okay, because in a way, we're designing it. And we have very little experience yet or very little hard data to base as on. But if we can get close to those marks, the economics of those wells are just going to be much more compelling than the previous wells. So more to come in next couple of quarters regarding that. Now your third question regarding our wells outside of Loma Campana, in crude oil, the area where we've done the most is La Amarga Chica which is the JV with Petronas. And from a productivity perspective, those wells are looking similar to those in the Loma Campana. Still, the cost is higher. It's a combination of factors. Some factors have to do with how that pilot was designed with the partner. And what we have jointly decided, we would get out of each well. In a way, we're still in delineation mode there, okay? Another factor has to do with scale. Still, this is a much smaller project for now. And thirdly, there are a few structural issues that we need to overcome that have to do with transportation and logistics, generally, to make sure that we can achieve, over the medium term, the same cost that we have in Loma Campana. Structurally, there's no reason why, over the medium term, those wells should not be costing us the same than those in Loma Campana are. And finally, on the EBITDA guidance, I think what we have said is EBITDA flat to plus 5% for the year. We're still sticking to that guidance. I think it's probably going to be closer to the flat -- to the low end of the range than to the higher end of the range.

Our next question comes from Juan Manuel Vazquez from Puente.

Yes. The first question is -- this is a follow-up to a previous question, but what's going to happen with the current unconventional natural gas areas and wells once the current gas incentives expire in December of this year? Are these blocks and wells going to be automatically included under the new gas incentive program? How is that going to work precisely? The second question would be, what have they gave us regarding possible future dividend payments? After you suspended a previously announced payment, are you reviewing some indentures to modify restricted covenants? What can you tell us about that? And the third one, if I may. What's the main driver behind the healthy sales of Infinia? In addition to economic recovery, is it a pricing advantage versus competitors, an advantage in terms of your distribution network? Any additional color on that would be appreciated.

Well, thank you, Juan. Those were all very good questions. In terms of pricing -- gas pricing for unconventionals going forward, there's Resolution 46 of the Ministry of Energy. Still, the details of the resolution need to be ironed out and nothing is automatic. We, the producers, need to present investment plans for each of the concession areas where we require this new gas plan price application. Because all of those areas where -- unconventional areas that we already have in production still have plenty of investment upside going forward. And we believe that we will be able to present good plans. In terms of new investment going forward, there's no reason for us to think that we will not get the full benefit of the new gas plan for the future, okay? And that is what we're counting on. But to me, 100% to be honest with you, that will be decided by the province and by the state once we have presented our plans. And we have not yet presented our plans. The plans are per block or per concession area. And therefore, in most cases, we have partners, so those plans need to be concentrated with our partners before putting them forward to the authorities. That will all happen before the end of the year. And as I said, we're optimistic regarding the outcome. Regarding your second question on the dividends, we made a decision several weeks ago that could imply some risk to pay the dividend. At this point, we're working on potential remedies to that. I cannot -- I will not elaborate further. In any event, this is just for the dividend for this year which, as we all know, it's almost a token amount. It's a very small dividend. The only reason why we've kept this dividend despite being so low is to send a signal that we know that our company like ours needs to pay a dividend, okay? And that dividend, of course, needs to be higher over the medium and long term. When putting together our long term plan, we're always assuming that dividends will have to increase. At this point in time, I'm not in a position to provide you with any guidance of how and when it will increase. But yes, to leave you with the impression that we know as a mission, as a company that dividend needs to be maintained as a concept and increased in terms of its size. Finally, regarding sales of Infinia, I think it's a combination of factors. Clearly, there's no perception in the customer base that gasoline is expensive. Otherwise, the first behavior that customers do with this product and in consumption, generally, not just in the gasoline business, is shifting from premium brands to ordinary or second brands, okay and we're seeing exactly the opposite. We're seeing the shift from the normal fuel to the premium. So I think that is a very good sign in terms that we still have a pricing power with us, okay and that gasoline is not expensive in Argentina relative to, of course, other areas of the economy or consumption, generally. Now the reason why our market share is higher with Infinia than it is with our ordinary products definitely has to do with our brand, has to do with our network, has to do with our marketing efforts. We put a lot of efforts when we launched Infinia a few years ago and when we launched Infinia diesel last year. And I think that is paying off and that underscores the strength of the YPF brand and network in Argentina.

Our next question comes from Pavel Molchanov from Raymond James.

This is Muhammed on behalf of Pavel. You guys recently signed an agreement with BP and Total and Wintershall in Vaca Muerta. This comes after several after deals with Chevron and Schlumberger. Are you considering any such further deals? Or are you planning to slow down dealmaking in the area for now?

Yes. We're planning -- we're still working on a couple of a new joint venture deals. As I've repeatedly said, we're not in business of just doing deals. We're in the business of maximizing value here. But we still have a couple of areas where, we think, we can accelerate development and the acceleration probably makes sense, in line with our strategy in the last few years, to share it with potential partners, some partners that carry us on 100% of the investments of the beginning of a pilot or a full pilot. So unfortunately, things have not been finalized. We cannot comment further. But the trend is that we will continue to work on this path of this strategy of farming out some of the growth in Vaca Muerta to partners. And we're in active discussions, at least, in a couple of cases.

And second question, can you provide an update on your asset monetization plans? What is the status of Metrogas which, I guess, you guys were ordered to divest from earlier this year due to -- by regulators?

Well, we have not been ordered to divest Metrogas. We believe that we're in good shape from a regulatory perspective. However, we've made it clear that Metrogas, as other assets, could be considered for a potential sale if we can realize value in line or higher than what we have in our own plants, right and if we find a good way to allocate that capital elsewhere within our company, We're not actively working on a potential sale of Metrogas. But it is under strategic for review, as there are a few other assets. I don't expect any monetization of any significant asset to occur this year.

Our following question comes from Julia Ozenda from UBS.

You answered most of my questions, but just one quick follow-up. You mentioned that production growth from shale and tight should more than offset the declining from legacy. But do you think you can provide a range of growth for the next year? Or maybe, actually, can we expect, already, growth in 2018?

Julia, yes. You can expect production growth for next year. Actually, our Chairman made a comment in that direction a few days ago and we're totally aligned with that. What I cannot provide at this point in time is a guidance of how much growth we will see next year. But yes, we believe that we have, in a way, touched the floor in terms of production. And we're optimistic regarding growth going forward.

Our next question comes from Felipe Dos Santos from JPMorgan.

Just have some two follow-ups -- quick follow-ups. The first one, the tight gas, do you see any infrastructure or any hurdle that you have there that could cease you from increasing production in tight gas? And the second one, you mentioned in the beginning of the call about diesel and gasoline price expectations for the next year. I couldn't to hear the answer well. Can you just go over it again?

On infrastructure, both for tight as well as for shale, I think the great news that we have seen this year is that many other players have also announced significant amounts of money to be deploy in the unconventionals, generally. So that means that, as opposed to last few years where we were pretty much the only ones really active and therefore, we had to build the 100% of the infrastructure, I think that some of that infrastructure, going forward, is going to be shared by many of us which makes it more economic and, obviously, less heavy on us in terms of our CapEx deployment. I cannot disclose, but we're working with some of the players that have announced the largest investments in Vaca Muerta to share some of that infrastructure going forward. So I think that is a good thing that we're going to be seeing more. And I think in the future, what we have not yet seen is that infrastructure being put in place by midstream players. There aren't any significant midstream players in Argentina. I think there's plenty of room for some of them to appear and to start consolidating natural gas infrastructure. So that's a one thing. On prices -- on gas prices, I think what I made reference to is the fact that we have not yet presented the plans for the full application of the Resolution 46 for the new gas plan, that we're going to be doing that in the next few months and that we expect, as a result of that, that we will get the full benefit of the new gas plan mechanism on all of our unconventional areas where we have no investments to be made.

In the -- about the diesel and gasoline, now that you have the real adjustments now beginning of October and then in January, it starts to move according to the market. Is that correct?

Well, we haven't yet discussed what will happen in January. But it is correct that, that formula and soft landing was for 2017. So assuming that the Brent stays pretty much where it is, we're -- we're very close to converging. And if that is the case, if we have a full convergence, there's less need for a formula going forward. But again, it's too soon. we're still in early August. I think that we cannot predict what will happen January 1. What we can say is that we're clearly trending towards normalization of prices and that, at some point, normalization of prices will imply that fuel prices at a bump are absolutely free.

Our next question comes from Santiago Wesenack from AR Partners.

And how much do you see the local price falling this year provided that international prices don't go up? And is the -- the second one, is the government paying on time, the gas [indiscernible] program? And -- or do you believe you need to take some debt in the market in this -- for the rest of this year?

Okay. Well, on local crude oil prices, the agreement was that if Brent stayed at $55, prices would basically converge there. We're a few dollars away from that. So I don't expect any meaningful changes in crude oil prices in the next few months or for the remainder of the year as long as, as you very well said, the international crude oil prices stay in the, I don't know, $50 to $55 range, where we have seen it in the last 5 months or so. In terms of your second question regarding the collections of the subsidy of the gas plan, no, the government has not been paying regularly. The last month that we have actually collected is September of last year which we collected approximately a month ago. And we're in constant conversations with the government -- the appropriate government officials to try to shorten this period. I think there is goodwill, positive goodwill in trying to accomplish that. But unfortunately, we're still working with, in average, 10 months in arrears, right? I don't think that is going to change in a very short term. And actually, one of the reasons why we have increased -- or that we have issued new debt is precisely assuming that this is not improving. So to your question, will this imply the need to raise for debt? The answer is absolutely no. Of course, if -- we always plan for worse. If things improve in terms of those collections, that would probably mean that we have excess cash that we will use to pay down debt, right? So I think one of the questions I was asked at the beginning of the call, we're very comfortable with our cash position and with our balance sheet. And that comfort comes from planning for the worse and being prepared for some of these collections not to improve over the short term. Now at the same time, I have to say that because of the increase in well head prices of gas for residential customers, the subsidy has come down significantly. So it's less of a burden for the government to pay the subsidy now than what it was a year ago.

Our next question comes from Francisco [indiscernible] from PointState.

Just a quick follow-up on the Resolution 46. You mentioned you're working on getting the approvals. And my question specifically is on the announcements you've made in late July on the Aguada de Castro and Aguada Pichana areas and the announcement that Pampa made last week on Rincon del Mangrullo. In terms of these areas and the Nuequen basin being reclassified as unconventional, should we take these as concrete evidence that you are making progress on achieving the Resolution 46 on some of your unconventional areas? And if so, what are the following steps, so that these areas eventually get the -- are extended the benefits of the plan?

Both cases, the Aguada Pichana West and East and Aguada de Castro transaction which was a reshifting of stakes between the Total, Pan American, Wintershall and YPF and this in this case of Rincon del Mangrullo, where it is not Pampa, it's actually us. Pampa is a 50% nonoperating partner there. In both cases, what we announced is the shift of conventional concessions to unconventional concessions for 35 years. And that is something between the operators or the producers and the province. Resolution 46 comes from a federal government. So we need to come up with specific concrete plans for each of those areas, where we will set for each concession areas, concentrated with the partners, bring it forward to the province and then being approved by the state in order to get the full benefit of the plan. Now you should not assume that because we have extended that we already have the full effect of Resolution 46. What you can assume, of course, is that all of us -- all of those companies that we have just mentioned, we're all very optimistic regarding our chances of being approved. Otherwise, we wouldn't have made the commitments that we made.

Okay. So you're making progress, but it hasn't been formalized yet is the way we should read it.

Okay. I don't disagree with your way of reading it, yes.

Our final question comes from Walter Chiarvesio from Santander.

In your series, you talked about this, I couldn't hear it probably, but assuming that most of the variables remain constant in terms of the crude price, the amount of crude that you need to buy to third parties and the level of the effects for the third quarter, given the pricing mechanism that you have for the bump price, should we expect a reduction of margins and EBITDA for the third quarter given that?

No, absolutely not. The formula assumes a full passthrough of crude oil prices and biofuels, plus a fixed percentage increase. That actually works the opposite. That should protect our margins. So no, we're not assuming any margin deterioration at all for the second half.

Even despite the devaluation of the currency, does that impact anything? I mean, you are buying crude during the quarter, but you chart the price based on the end of the last week of the quarter or something like that, if I'm not wrong.

Well, that is true. Of course, we -- prices are determined on those variables. I think it's for the last week or last week of the quarter. But I cannot speak about temporary changes or effects. But conceptually, we're fully protected. So there's no reason to think that our margins are going to be deteriorated for that. Quite the opposite, we're assuming a slight expansion in margins.

We have no further questions at this time.

Okay. Well, thank you, Julia. Thank you, everybody, for taking the time. And as always, Paulo, Diego and myself are available for any follow-ups. Have a good day.