YPF Sociedad Anónima (YPF) Q3 2016 Earnings Report, Transcript and Summary

Welcome to the Third Quarter 2016 YPF Sociedad Anonima Earnings Conference Call. My name is Sylvia, 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, Sylvia. Good morning, ladies and gentlemen. My name is Diego Celaa, head of Investor Relations at YPF. I would like to thank you for joining the YPF third quarter 2016 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 third quarter results, and finally, we will open up the call for questions. We will be making forward-looking statements. So, I ask you to carefully review the cautionary statement on slide 2. Our agenda today will include a review of the third quarter results, including an update of our shale and tight development projects; a brief description of our financial situation; and a brief summary, to conclude. Please, Daniel, go ahead.

Thank you, Diego, and thanks, everybody, for joining us this morning for a review of our third quarter 2016 results. I had mentioned the last few quarters that we were facing a challenging environment. But this quarter was especially difficult, as the slow economy resulted in lower volumes of fuels sold in the local market and, therefore, made it impossible for us to increase prices. But at the same time, our cost structure is fully loaded with a combined effect of a 60% plus devaluation which happened a year ago and the wage increases that kicked in the second half of this year. Consequently, revenues were up by 39% in the quarter when compared to the same period of 2015, and adjusted EBITDA reached ARS14.6 billion, which represents only a 9% increase. In line with what the rest of the industry has been doing during the last several quarters, we recorded an impairment charge of ARS36.2 billion to our fixed assets, as we will explain in more detail in a few minutes. Without considering that effect, operating income would have reached ARS1.6 billion, showing a 71.4% decrease vis-a-vis the third quarter of 2015. Total CapEx was down in this third quarter by 4.7% in pesos, reaching a total of ARS15 billion, mostly as a result of our scheduled reduction in drilling activity. However, despite this reduction of activity, total hydrocarbon production showed an increase of 1.3% vis-a-vis a year ago due to an increase of 14.8% in NGL production, with 0.9% decrease in crude, and 1.1% increase in natural gas production. Similarly to what we went through in the first half of the year, the local currency devaluation of December 2015 had a negative impact in our most relevant income statement figures when expressed in U.S. dollars. Revenues were down by 14%, as diesel and gasoline prices dropped by 18% and 15%, respectively, in dollar terms, while exports were down 24% on lower international prices and also lower volumes. Additionally, as I just mentioned, volumes of products sold were also lower. Cash costs were lower than expressed in U.S. dollars, but not enough to fully offset the revenue decline. And therefore, EBITDA was down 32% in dollars and EBITDA margin contracted to 26%. Lifting cost, on the other hand, was down in dollar terms, but royalties, purchases of biofuels, and refining costs were all up. Operating income was further affected by an increase in DD&A and was, therefore, almost wiped out even before the effect of the impairment charge. Let's switch back to Argentine pesos to go over the more detailed analysis of the quarter. Operating income before the impairment was down 71%, and both business segments presented lower operating income. Our downstream sector is suffering the impact of a severe devaluation we experienced at the end of last year, which has eroded our prices in dollars, as price increases year to date were a little over half of the effect of the devaluation. In the upstream segment, the revenue increase resulting from higher prices in pesos for both crude oil and natural gas was not enough to offset the effect of higher depreciation, but also higher royalties and other expenses. I will explain this in more detail in the following slides. Finally, the decrease in operating income of ARS500 million in corporate and other was driven primarily by higher personnel expenses, higher IP costs, and lower receipts of construction incentives granted by the government to our subsidiary, IASA, last year. We have not included in the comparison the effect of the ARS36 billion impairment charge, which net of taxes is actually ARS23.5 billion. That would fall into the upstream column. The rationale for the impairment has to do with a faster convergence of local prices with international prices, combined with a lower and flatter oil price curve for the outer years. This impairment only affects our oil cash generating unit, as all the rest of our asset base including the gas cash generating units and the downstream clearly passed the ceiling test. When broken down in more detail, we can better understand the reasons behind the reduction of ARS4 billion in operating income. Revenues grew by ARS15.8 billion, or 39%, resulting from the following factors. First, ARS4.2 billion increase in natural gas sales due to both prices, which were 76% higher in pesos, and volumes, which were 1.1% higher than last year. Second, ARS3.8 billion increase in diesel sales due to 31% higher prices in pesos, partially offset by a 4.2% reduction in sales volumes. Third, an increase of ARS2.9 billion in gasoline sales, with higher prices also in pesos of 36% and lower sales volumes of 2.5%. Fourth, ARS1.2 billion increase in natural gas sales in the retail segment from our subsidiary Metrogas, which we are consolidating, due to a 70% increase in prices in pesos and a 20% increase in volumes. And finally, ARS1 billion increase in fuel oil sold on 56% higher prices in pesos, as most of our fuels sold is done on dollar-based prices, and a 7.7% reduction in volumes. Cost of sales other than depreciation increased by ARS7.5 billion, the only cost component which is fully dollarized are the royalties, which are paid to the provinces on wellhead prices which are set in dollars, and they were up ARS1.6 billion, or 56%. The other factors explaining the increase were the lifting cost, which was up by ARS2.5 billion, or only 33%, which translates into an approximately 20% reduction in the lifting cost in dollar terms; second, refining costs, which were up ARS750 million, or 47%; and finally, transportation expenses, which increased slightly over ARS500 million, or 43%. Depreciation was up by 82%, or ARS5.5 billion, fueled by the 62% currency devaluation and the capital expenditures made in previous periods. Purchases of raw material and other products for sale increased by ARS4.9 billion, mainly as a consequence of higher purchases of biofuels, for ARS1.6 billion, driven by significantly higher prices in pesos and a slightly higher blend in the case of the ethanol. Imports were up for ARS500 million due to higher volumes of jet fuel and lower volumes of diesel, but both at higher prices in pesos. SG&A was up by 51% as a consequence of higher transportation expenses and salary increases. Additionally, in the third quarter of 2015, we had recorded a reversion of bad debt allowance in the natural gas segment. Finally, exploration expenses decreased by ARS870 million, in part as a consequence of lower expenditures on geological and geophysical studies, but mostly because of a lower number of unproductive exploratory wells. Entering now to our upstream business segment, the operating income decreased by 51% against last year, to reach approximately ARS1.1 billion. Revenues in the upstream increased by 37%, to reach ARS28 billion, driven by higher crude oil sales of ARS4.1 billion, or 27%, due to 4.9% lower volumes transferred to our downstream business segment but at 41% higher prices in pesos; and second, higher natural gas revenues of ARS4.2 billion on higher prices in pesos and higher in dollars, also, and a slight increase in volumes, as well. It is worth mentioning that during the third quarter of last year we had accrued ARS540 million of revenues derived from a $3 per-barrel incentive which was in effect at that time to promote the crude oil production, and that subsidy is not in effect this year. Therefore, we are not accruing those revenues any more. The average realization price in dollar terms for crude oil decreased to $59.90 per barrel, as a result of the negotiations between local producers and refiners that resulted in a 2% price reduction per month starting in August and ending in October. For natural gas, on the other hand, the average price was $4.80 per million BTU, which was almost 7% higher than the third quarter of 2015. On the cost side, these were up by ARS9.6 billion, which is a 56% increase mainly due to four factors. First, the depreciation increase of ARS4.9 billion, which I already explained; second, ARS2.5 billion increase in items related to the lifting costs, which, as I explained, were actually down in dollar terms; third, higher royalties because of the higher prices in pesos at the wellhead; and lastly, the partial offset by the reduction in exploration expenses, also as I explained in the previous slide. The lifting cost on a per-barrel equivalent basis was down 20% in dollars, to $12 per BOE. And the total cash cost per BOE reached $20.80, including royalties and taxes of approximately $6.10 per BOE. Crude oil production in third quarter decreased by 0.9% to 247,000 barrels of oil a day while natural gas production was up by 1.1% producing almost 45 million cubic meters per day. NGL production, which is not in the graph, increased by 14.8% producing 50,000 barrels a day and as a result, and despite the significant reduction in activity this year, total hydrocarbon production was up vis-à-vis the same quarter of 2015, with 579,000 barrels of oil equivalent per day. Now, let me provide an update of our shale gas and shale oil activity. During the third quarter of this year, we connected a total of 24 wells, taking the total to 522 shale wells in production. Total shale production of the quarter was above the previous quarter, reaching a new high and a quarterly average of 58,200 BOE a day. This increase is basically explained by, first, the good productivity of the horizontal wells in Loma Campana and also in the La Amarga Chica that pushed up oil production, and second, the increase in the total treatment capacity in El Orejano up to 2.5 million cubic meters per day that enabled shale gas production increase coming from that area. We continue to see improvement in the cost per well in Loma Campana. We're currently at $9.5 million, which is now ahead of the reduction trend that we were expecting for the year. We had a target of $10 million per well. Moreover, substantially all of the new wells were completed with 18 frac stages per well, which is in line with our type wells, and the initial production points to EURs which are also in line with our well type curve. Finally, we completed and tested an extended well in El Orejano, with 2,000 meters of lateral length and 27 frac stages, which showed peak production rate of 400,000 cubic meters a day. And we expect to see more of this coming next year. In connection with Vaca Muerta, it is important to comment on the recent agreement we reached with the province of Neuquen and its provincial company Gas y Petroleo de Neuquen. By this agreement, we have been able to extend for a couple of more years $1.2 billion of short-term commitments in the three largest pilot programs. We have also been able to shift 11 contracts that we had with G&P to two new development concessions and nine new exploratory permits without participation of G&P. All this, in Vaca Muerta core areas. Simultaneously, we will return our participation interest in 14 areas with contracts that were supposed to expire between 2016 and '17, and in which YPF did not have any exploration plans. Some of these areas are actually even outside of the Vaca Muerta limits. Finally, in consideration for this exchange of areas and extension of commitments, we are granting the province a $30 million payment which will be made by us but also shared by the partners that we have in some of these areas. With regards with our tight gas projects, in this third quarter we had put in production 10 additional wells starting in the Lajas formation, which we own 100% of; three additional wells targeting the Mulichinco formation, in the area called Rincon del Mangrullo, where we own 50%; and six additional wells in EFO, where we also own 100%. As a consequence of this, gross production continued to show encouraging results, reaching 5.3 million cubic meters per day in Lajas, 2.1 million cubic meters per day net to YPF in Rincon del Mangrullo, and 2.2 million cubic meters per day in EFO. And now, tight gas represents 20% plus of our natural gas production. Regarding the Rincon del Mangrullo, during the quarter we completed the first horizontal well with five frac stages targeting Mulichinco, with a promising peak production of 290,000 cubic meters a day. The downstream segment reported an operating income of ARS1.1 billion, which was 68% below the ARS3.5 billion operating profit of the third quarter of 2015. The reasons for that are the following. Revenues were up by ARS14.7 billion, or 41%, based on diesel sales which were up ARS3.8 billion, on prices which were 31.7% higher and volumes which were 4.2% lower. However, in the case of diesel, it is worth highlighting an increase of 2.9% in sales volumes of our premium product. And by the way, last week we launched a new premium product for diesel. If it turns out to be as successful as the gasoline premium which we launched three years ago, we can expect a significant further improvement in the sales mix. Gasoline sales were up by ARS2.9 billion, due to a combination of an increase of almost 37% in the average prices and a decrease of 2.5% in the volumes sold in the local market. Fuel oil sales in the domestic markets totaled ARS2.8 billion, representing ARS1 billion of increase driven by higher prices in pesos of 52% and a 0.5% reduction in volumes sold locally. In the export market, we noticed an increase of sales of 39% or ARS1.3 billion, due to higher prices in pesos, although lower in dollars, and despite the Brent price having decreased by approximately 9% vis-a-vis the third quarter of 2015. Cost increases of 53% compared with last year, and we highlight the following. First, greater crude oil purchases of ARS5.2 billion on higher prices and lower volumes, as discussed before. And remember that most of these are purchases from our own upstream segment. Second, higher purchases of biofuels, with higher prices for both biodiesel and bioethanol of 93% and 57%, respectively. Ethanol volumes also increased, by 13%, due to the increase in the blend rate for gasoline that went from 10% to 12%, while biodiesel volumes decreased by 7%, in line with the lower diesel production. And finally, the last explanation of our cost increases has to do with higher fuel imports, by a net amount of ARS500 million .Other than purchases, refining cost was also up, by ARS750 million, and depreciation was up, by almost ARS600 million. During the quarter, the volume of crude oil processed in our refineries was 292,000 barrels of oil a day, which was 1.7% lower than the third quarter of 2015, mainly due to maintenance activity at the Lujan de Cuyo refinery in Mendoza. Therefore, utilization rate of our refining capacity during the quarter was 91%. Regarding the domestic market, total sales decreased by 1.1%, mainly driven by the already explained 4.2% decline in diesel and 2.5% decline in gasoline, but both offset by an improvement of other refined products such as the LPG and the fuel oil. Monthly sales of diesel, at the right hand side of the screen that had already been weak in the first half of the year were also lackluster during this third quarter, showing this 4.2% decrease compared with the same quarter of last year. This was a quarter with different behavior in the different months. We had a very soft July; a good August, compared with the previous year; but unfortunately, again, a soft September. With respect to gasoline, the past was somehow different as this third quarter showed a slight recovery compared with the previous quarter. However, monthly sales during the quarter were consistently below last year and in line with two years ago. This reflects both a reduction in the whole market because of the soft economic activity and also a small reduction in market share as the market has become more competitive. On the other hand, market share for the premium products, Infinia and Eurodiesel, were 61.2% and 58.5%, respectively. So, we continue to show very good market share in our premium products. During the third quarter of 2016, total CapEx for the Company amounted to ARS15 billion, or 4.7% lower than the third quarter of 2015, which was actually 41% lower if we measure it in dollar terms. Upstream CapEx amounted to ARS11.7 billion, a decrease of 5%, and our activities mainly focused in drilling and workover, which represented close to 70% of the total upstream CapEx; followed by the build up of our facilities, with almost a 20% share of the total; and finally, exploration and other activities, representing slightly over 10% of upstream CapEx. During the quarter, we drilled and put in production a total of 140 wells, which together with those drilled and completed during the first half of the year reached a total of 512 new wells year to date. Most meaningful investments have taken place in the Neuquina Basin, most specifically in blocks Loma Campana, Aguada Toledo, Rincon del Mangrullo, El Orejano, La Amarga Chica, and Chachahuen in the province of Mendoza; and in the Golfo San Jorge Basin, in Manantiales Behr, El Trebol, Los Perales, and others. With regards to exploration, in this quarter we completed four exploratory wells. And in the downstream, CapEx was ARS2.9 billion, highlighting the finalization and startup of the coke unit in our La Plata refinery that resulted in a total investment during three years of close to $1 billion. Now, let's speak about our financial situation. As we anticipated in our last earnings call, during this third quarter of 2016 we collected the receivables owed to the Company by the Gas Plan program for 2015, and we collected that in the form of sovereign bonds in dollar terms for a total of ARS9.9 billion, or $642 million, which we are keeping those bonds in Treasury for now. We also collected close to ARS2 billion of the crude subsidy also from 2015. When we add these extraordinary collections to the rest of the recurring operating cash flow, we show ARS26.6 billion of operating cash flow in the quarter, which was 172% higher than the same quarter last year. The main effects contributing to this strong operating cash flow are the reduction of working capital, driven by the collection of the receivables we just discussed, and, in addition to that, ARS1.2 billion increase in EBITDA and lower income taxes payments. The previously discussed cash flow generation together with an active quarter in terms of debt new issue allowed us to finance our ARS16.7 billion capital expenditures and also resulted in ARS32 billion of cash and cash equivalents as of September 30, 2016. This cash position, including the bonds previously mentioned, is enough to cover our debt maturities of almost the next two years, as our most important debt maturities only come in late 2018. Using this same criteria of adding to our cash our short term investments, our leverage ratio is now at 1.86 net debt to EBITDA. And we expected to continue to stand above our target ratio of 1.5 times and to peak by yearend as we transition to positive free cash flow in 2017. The average interest rate in pesos was 30%, while the average cost of our debt in dollars was 7.75%. Actually, we also need to add up our debt in Swiss francs, at 3.75%. In summary, we are adapting to this difficult business environment, and we are sticking to our objective of having an upstream segment which is valuable with oil prices at $50. We continue to expect production at least flat for the year. The reductions in lifting costs that we have already realized are a good sign the discussions underway with the unions to discuss productivity measures for the development of the unconventionals could be a starting point to a completely reshaping of this industry for the future. Natural gas continues to be a priority and will be even more so in 2017. Although we have collected a good part of the subsidies that were owed to us, we still have a lot to work with the government in this respect, as we are collecting these subsidies after eight or nine months of accrual. And in the case of gas sold to distribution companies, we have more than one year in arrears. We recorded this $1.5 billion net impairment charge in our oil E&P unit, as price expectations are lower than before, and we will use those same assumptions to analyze and decide the projects that we take on for next year. 2016 has been a transformational year for our Vaca Muerta efforts as we have simultaneously significantly reduced costs and also increased productivity. So, we will continue with our pilots to put this resource in value, but we will do this at a slower pace. In this respect, the recent agreement with the province of Neuquen was an important milestone in order to assure that our investment plans are consistent with our regulatory commitments. In the next months, we will have finalized our 2017 budget in which we expect to be at least free cash flow neutral for next year, and we are entering the year 2017 with a very comfortable liquidity position. So, with this, I would like to stop here and answer your questions. Thank you.

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

I have a few questions. First question is about impairment. I just want to explore some details. What level of oil prices did you use in this flatter curve you mentioned? And then can you share with us how much of the charge was driven by the vertical wells at Vaca Muerta? Still on the impairment theme, with the current cost of the horizontals today and the spot oil price, is it safe to assume that those horizontals were not affected by this impairment test? My second question is on costs. If we assume a stable FX rate, what can we expect for lifting and refining costs in the coming few quarters? In other words, is there still much impact from the new labor contract to flow through the cost line in the P&L? And if I can ask a final one, just to confirm it seems you received the $645 million past due from the government in a dollar-denominated bond. Is that correct? So the FX risk that was discussed last quarter was mitigated? Just wanted to check if my interpretation is correct.

Let's start out the impairment charge for a second. In terms of prices, we considered different scenarios and awarded different probabilities to each of those scenarios for 2017. Those scenarios go from going straight to import parity to keeping prices pretty much where they are, and a middle ground scenario in which prices evolve in a sort of soft landing. In average, we are talking for 2017 prices of $52, $53 for our products. For 2018 and onwards, we're using the consensus of analysts from Bloomberg, which is what we have traditionally used for our ceiling tests. And those actually result in prices which are in the low 60s for the next few years I mean 2018 and beyond, and only reach $70, I think, in eight years from today. So, I believe very conservative prices for the long end of the curve, difficult to say for next year, but clearly adapting our prices to what we are hearing in the local market. On the one hand, prices have already come down by 6%. On the other hand, what we are hearing from different government officials is that eventually, which we always expected it would occur eventually we will end up in convergence. In terms of the verticals and the horizontals and the composition of this impairment charge, this impairment charge is performed on the full oil E&P unit. So, it's a combination of I think, over 70 different fields. There is a portion that comes from Loma Campana, and there is a portion that comes from other fields, very mature fields that we have been operating, in some cases, for almost 100 years. So, it's a combination of different factors. Yes, it is true that the very positive results that we are seeing from the horizontals and the costs associated with those, or at least in the recent wells, lead us to believe that all of these wells are economic, and that is the only reason why we will be engaging in more horizontal drilling next year. So, if anything, the impairment reflects for Loma Campana some of the learning of the first couple of years. Clearly, it doesn't imply negatively anything about the new wells, because the economics of those wells is very attractive. In terms of our costs, going forward, and the relationship with the last labor agreement, yes, there is two more wage increases which were part of the agreement that we signed half of this year. One is coming by the end of this month, and the other one is coming in January. So, those are the only additional kick-ins from that agreement. Now, conceptually, we are planning, and definitely next year, our budget with the objective of not seeing any increase in our lifting cost and in our OpEx in dollar terms. Actually, the only way to do that is by putting in place efficiency initiatives that we started this year. In the case of CapEx, that is even hopefully, that's going to be even more telling because of a lot of reductions that we have been realizing in new agreements, new backs for many of the services that imply in CapEx and not so much in OpEx. Finally, regarding the question of what we collected from the state for the subsidies for the Gas Plan of 2015, yes, we collected bonds denominated in dollars, with a yield that we actually like. And therefore, we are keeping those in Treasury for now. However, we collected the equivalent in dollars of the peso amounts accrued in 2015. So, what is still to be disputed is that we understand that those numbers, or that those accruals, in 2015 were dollar amounts. And we were paid in pesos. Yes, the consideration that we received is a dollar consideration, but we ended up receiving less dollars than what we expected. So, this is in line with what I had said in previous quarters, and we are still analyzing our different options in order to try to collect this difference, although none of this has been accounted for in our books.

Our following question comes from Frank McGann with Bank of America.

Two questions. One, just in terms of CapEx plans for next year and your plans to achieve free cash flow, I was wondering if that was likely to come more as a result of reductions, I would assume, in both expected cash flow as well as lower CapEx? But how do you see the balance there over time with still some concerns on the pricing front? Secondly, with the write-off and with some expectation for lower prices nearer term, does that affect your production plans for 2017? I was wondering how you're seeing the potential for growth there? And then, lastly, if I might, just looking at the overall cost structure in terms of the well costs that you've brought down fairly significantly, you mentioned the labor union agreement that you're working on, I was wondering how you see the potential for further material cost reductions for non-conventional?

Well, it is a little bit early for me to give you precise guidance for 2017 CapEx. What I can tell you, Frank, is that we are working the budget of 2017 bottoms up; meaning, we are coming up with what we believe is the operating cash flow that we can actually generate next year, and that's the maximum that we will have available for CapEx. Because again, the objective is not to increase leverage beyond where we're going to be by the end of this year. That means that more likely than not there is going to be an additional reduction in CapEx vis-a-vis this year. I think this year we had a target of $4.5 billion. We're going to be short of that. I think we're going to be in the $4.2 billion to $4.3 billion range. And we expect a further reduction next year, not of the size of the reduction of this year that we went from $6 billion to $4.2 billion, but some additional reduction next year, for sure. Let me go to your second question regarding affecting production. I think that reduction in activity may have some effect on production. It might have a more meaningful effect in following years, not necessarily in 2017. It is likely that production next year is going to be slightly below this year. I don't think it's that related with the write off. I think the write off, if anything, has an effect on future CapEx and not necessarily in production, at least not in the short term. And as I mentioned in the presentation, we are using the same, in my opinion, conservative price assumptions that we used for the impairment test for all of our project evaluation for next year. So, the projects that we will sanction next year are those that even with these assumptions that resulted in an impairment, even with those assumptions, those projects still throw IRRs in the 13% and higher range in dollar terms, of course which has traditionally been our cutoff rate for E&P projects. Finally, in terms of cost structure, we are very optimistic regarding the outcome of these discussions that have been taking place and have been all over in the papers during the last several weeks between us and a couple of other producing companies in Argentina with the unions, with different government officials, with the province of Neuquen to try to come up with some changes to the labor agreements that apply to the unconventional's. We are working towards that. It is, in my opinion, a landmark thing. It is a first time that we are actually all of us, all of these stakeholders, getting together to find a way to make sure that all these resources can actually be put in value. And the only way to do that is if the costs are in line with the new price assumptions that we all have in mind. So, hopefully, before the end of year you will all have news regarding that discussion. Now, that's not the only measure that will result in additional cost reductions in the development of the shale. As I was mentioning, the significant reduction this year in a way is also a result of renegotiation of different contracts, contracts that have to do with the hydraulic fracturing, with the directional drilling, with the pumps. A lot of new contracts that came due were replaced by contracts which implied significant savings vis-a-vis the previous contracts that we had been carrying. We haven't seen this in drilling, not yet. Hopefully, that will start kicking in, in the next couple of years. But all these measures, plus those that we had mentioned in previous quarters and previous years, like the replacement of the imported sand with our own sand, and so on, clearly are resulting in lower costs per well. So, I think what we can expect for next year is that we will be able to do longer laterals for the wells; we will be able to do more number of frac stages per well; and hopefully significantly increase the production out of those wells without increasing the costs.

Our following question comes from Ricardo Cavanagh from Itau.

My questions would be, the first one is if you see which would be the conditions that you would imagine would be able to take EBITDA of CapEx under the current oil price scenario? And related to this -- two separate questions -- if you see the government can launch additional investment incentives to upturn a trend that seems to be for the entire Argentine sector too tight in terms of economics to reverse the energy deficit of the country? That is the first one, fiscal incentives, if you see that Argentina might be able to attract partners that will commit money for YPF? Also pushing that EBITDA [floor above] CapEx under the existing oil price scenario, that's the first one. And the second one is if it might be disclosed how much CapEx has YPF deployed at Vaca Muerta and tight gas, in general, over the past few years? That will be it.

Well, regarding last part of your question, we have invested close to $5 billion. That's at our own working interest in Vaca Muerta plus tight, in the last several years. That's probably in the last four years -- four or five years, give or take. Regarding fiscal incentives, well, obviously, it's a question more for government officials than for ourselves. I think that the government is committed to making sure that the shale is developed and that, especially in the case of natural gas, that natural gas production continues to go up. And as you know, if that is an objective, that can only come from the shale and the tight. So, if as a consequence of these discussions that the government is a party of we all conclude that, in addition to the efforts that the companies are making and the provinces are making, that the unions are going to be making, the government needs to pitch in, I think that they will be open to hearing something like that. I cannot talk of specific measures because I don't know of any. But from our conversations with government officials, it is very clear that they know that the price of gas will continue to go up, with the current Gas Plan program being extended or with some other form of regulation, but that results in prices, which in the case of oil is a negative, the convergence with import parity. In the case of natural gas, it's a positive. So, prices will continue to go up. If there is a need for some kind of fiscal relief, I think that they will be open to considering. We are not discussing any specific measures as we speak now. In terms of your first part of the question, as I said, the objective is making sure that CapEx is not higher than -- I don't look it on an EBITDA basis. I look it on operating cash flow basis. So, cash on cash right. And we will continue to reduce costs. We will be increasing prices. Now, we are in a period in which we have not increased prices over the last six months. And the reason for that is basically because the economy is in the middle of a recession and we have still not seen significant growth that would allow us to increase prices again. When and if that occurs, of course we will increase prices as needed in order to cope with a cost structure and making sure that our margins do not contract. This is the first quarter in quite some time in which we have EBITDA margins below 30%, and I don't see any reason why we should not go back to the 30% plus area.

Okay. Thanks. And would you consider that, under the scenario that prices are extended for gas and you might even have some additional fiscal situations, that more partners might be attracted to the shale and tight in terms of geological potential of Argentina? Or, you would consider that under the current cash flow generation for companies around the world this is unlikely to escalate, in the near future at least?

It's a great question. I think that we are starting to see a turnaround in the industry, globally. Actually, the earnings released by most of the industry players have been on a more positive tone than before. So, I think that from that end things are going to be changing for the better. We haven't sensed a lack of interest in Vaca Muerta, at all. We've seen and we are in conversations with different players, as we have been in the past. It is true though that with a reduction in prices, generally, and nothing going on, the prices at which we could have closed transactions are not closed, but at least engage in more meaningful discussions on potential transactions, were prices at which we were just not willing to dilute our asset base. So, for instance, in 2017 we are going to be investing probably close to $200 million in pilot programs in Vaca Muerta. And in most of those cases, as opposed of the previous years, we're going to be funding most of it because we have not closed partnerships. Now, that doesn't mean by any means that we are closed to doing more partnerships. Quite the opposite. What it means is that we will enter into those partnerships after those pilots have been completed or will advance, and therefore, we will be in a position to extract a better valuation out of those assets. So, nothing has changed in terms of our strategy of developing Vaca Muerta with partners. We are just looking for the best moment to bring those partners in.

Next following question comes from Walter Chiarvesio from South American.

Well, my questions were partially answered already, but if you could be more accurate in terms of numbers? For example, with the crude oil price that makes or assumptions in terms of rate of return that makes the shale projects profitable? I remember that in the past the number was around $80. Now, with these horizontal wells and higher productivity lower costs, clearly it could be much lower. Also, cost of risk could help. If you could give us some numbers around that? And also, in terms of the guidance for the next, I don't know, two, three years in terms of production? Because what I see is CapEx going down, probably, and a large part of that depends on the [outcome] of expenses reduction and available free cash flows, operating cash flow to invest. But assuming that CapEx will go down, probably production will go down or be stable, as well. Is it safe to assume that production, all in, will be stable for the next three years? So, this is the kind of questions that I want to have more accurate outlooks, if you will.

In terms of production guidance, as I said, I think next year production will be flat or a small reduction, with a very different behavior between natural gas, that I expect production to go up again, and crude oil, in which we expect production to come down. For the following years, I cannot give you a specific guidance. Clearly, the reduction in CapEx has some negative effect, but also the significant CapEx that we have been putting in the unconventional in the last few years will start kicking in, as well. So, we have always said that the run rate of our production growth should be between 3% and 5% per year. We are clearly not there this year and will not be there next year. But we are not changing our objective, going forward. In terms of crude oil prices for the shale, we've always stayed away from the concept of the breakeven price. We don't believe in that concept. What I can tell you is that with current prices in Argentina, including this scenario of reduction in prices for next year that has caused the impairment, all of our Vaca Muerta projects have, or throw out, IRRs above the 13% target. So, what I'm trying to say with this is it's not just about price. Clearly, price has been coming down. But costs have come down significantly, and productivity per well has come up significantly, as well. So, I don't know where you took the number of $80. Clearly, it didn't come from us. But I'm not saying it's not accurate. Maybe that was a number a few years ago. That number is clearly in the $50 range. I will not get into more detail on that, but I think that that should be accurate enough.

Okay. Perfect. Thank you very much. One more question is the impairment has any impact on cash tax payments in the future due to the tax loss carry forward, or so? I don't know if you mentioned that during the presentation.

It doesn't have any effect in current taxes for two reasons. First, the impairment is just an accounting impairment; it's not a fiscal impairment. And second, we already have a tax loss carryforward. So, we are not paying taxes this year, and likely we are not going to be paying taxes next year, either.

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

Just a quick question. In terms of diesel demand, which was pretty weak, I was just wondering did you notice any difference in where that weakness was coming? Was it across the board? Or, was the agricultural and industrial sectors perhaps more affected than other retail customers?

Well, Frank, it's very diverse. Clearly, the borders and dollar demand coming from the borders is a place where we have lost we, the industry, not just we, YPF we have lost a lot of demand, basically, because prices locally were above prices in some of the bordering countries. The agri sector has behaved well. We don't see any weakness there, at all. We've seen some weakness in transportation. We've seen some weakness in some industries. For instance, the oil and gas industry, which is a heavy user of diesel oil, clearly has been reducing activity. So, there was a reduction of demand coming from that segment. So, it really varies. All in all, it has a pretty high correlation with economic activity, and I think economic activity has clearly not picked up in the third quarter. We continue to be optimistic regarding next year, but we have not seen that improvement as of today, not yet.

We have no further questions at this time.

Okay. Well, thank you very much, everybody, for the call. Diego and Pablo are available to follow up on any further questions. Have a great day.