YPF SA (YPF) 2015 Q3 法說會逐字稿

Welcome to the third-quarter 2015 YPF Sociedad Anonima earnings conference call. My name is Sylvia and I will be your operator for today's call.

At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session.

Please note that this conference is being recorded. I would now turn the call over to Diego Cela. Diego, you may begin.

Great. Thank you, Sylvia. Good morning, ladies and gentlemen. My name is Diego Cela, Head of Investor Relations at YPF.

I would like to thank you for joining the YPF third-quarter 2015 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 statements on slide 2.

Our agenda today will include the 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. We are very pleased to report our third-quarter 2015 results. Financial performance in the quarter was totally aligned with our expectation and continues to prove the strength of the Company as we were able to successfully cope with an increasingly difficult operating environment.

EBITDA of ARS13.4 billion was just 1.8% shy of our best quarter ever, which was the third quarter of 2014. And year-to-date EBITDA was up 9%. Revenues were up by 7% in the quarter and 10.5% higher year-to-date. However, operating income was down by 30% as our price increases in local currency were not able to catch up with cost increases.

Total CapEx increased in the third quarter of 2015 by 14% in pesos, reaching a total of ARS15.7 billion, which is only 2% higher than last year in dollar terms.

In this third quarter, total hydrocarbon production was flat vis-a-vis a year ago with a 1.3% growth in crude oil and net increase of 1.4% in natural gas production, which was affected by a few factors that we will cover in a few minutes.

As every quarter, we also show our most relevant income statement figures in US dollars, since this is the functional currency of our Company and also helps to better understand the evolution of our business in real terms. In this opportunity, comparison may look difficult against an outstanding Q3 of 2014.

Revenues in dollar terms were down by 4% as diesel and gasoline prices dropped by 6% and 3% respectively in dollar terms and exports were down 17% on lower international prices.

EBITDA was down 11.9% in dollars, as cost of sales and operating expenses were up by 4% and 8% respectively. Additionally, higher depreciation resulted in a drop of 37% in operating income.

We added this slide with a quarterly evolution of revenues and EBITDA of the last three years to provide some context for the results of the present quarter. It is clear that revenues have been stable in the $4 million to $4.5 million range and this quarter is close to the top of that range.

With regards to EBITDA, we have seen it growing in the last four quarters in a row and as I mentioned before this was the second best quarter in the Company's history. Unfortunately, we are making the comparison against our best quarter ever which was the third quarter of 2014. We said at the beginning of this year that we expected to see our EBITDA essentially flat in dollar terms in 2015 and we are comfortably reassuring this guidance today.

Let's switch back to Argentine pesos to go over the more detailed analysis of the quarter. And when we break down by business segment the reduction in operating income, it is very clear that our upstream sector is the one that has been facing more challenging conditions with a combination of lower prices and higher costs.

The downstream segment, on the other hand, has been very resilient and only experienced a minor reduction vis-a-vis last year as lower crude prices provided a cushion against other cost increases.

Continuing with our operating income analysis, in this chart we can see the main changes from last year's to this quarter. Revenues grew by ARS2.7 billion or 7% resulting from an increase in local sales of gasoline due to higher volumes and higher prices in pesos, a decrease in diesel sales on lower volumes due to adverse weather conditions, partially offset with higher prices in pesos. An increase in fuel oil sold to the local market both volume and prices. An increase in natural gas sales due to 6% higher prices in dollars but on flat volumes. And finally, a ARS540 million accrued by the crude oil production incentive program put in place at the beginning of the year.

Cost of sales on the other hand grew by ARS4.3 billion or 16%. As in previous quarters, the largest single item contributing to the cost increase was again depreciation, which was up 29% or ARS1.6 billion. Other cost of sales were up with higher activity, ARS860 million increase in lifting cost, ARS313 million increase in refining costs, and ARS206 million increase in royalties.

Purchases increased by ARS1.3 billion mainly as a consequence of one, high volume of crude oil purchased from third parties in the domestic market for about 22% and slightly higher prices in pesos; and second, higher fuel imports of ARS240 million mostly diesel oil as a consequence of higher imported volumes but at lower prices.

Exploration expenses were up by ARS876 million in part as a consequence of higher exploratory activity carried out during the quarter, but also resulting from the write-off of 12 unproductive wells during the quarter, which is a process that it's usually not even throughout the year and was particularly high in this quarter, although year-to-date we are at levels consistent with last year.

Lifting cost on a per barrel equivalent basis was only up 1.8% in dollars to $14.7 compared with last year and total cash cost per BOE reached $24.2 including royalties and other taxes for $7.3 per BOE. This was slightly above the $24 per BOE number of the third quarter of 2014.

Entering now to our upstream business segment, operating income declined by 51% against the Q3 2014 to reach approximately ARS2.2 billion. Revenues were only up by 5.9% in the quarter as volume of crude sold was slightly down and prices were only slightly up in pesos. And actually prices were almost 10% lower in dollar terms as the average crude oil price was approximately $68 per barrel in the local market.

Sales of natural gas on the other hand were up on flat volumes but 6% higher dollar prices. As our upstream sector transfers substantially all its crude production to our downstream sector this negative price development does not have a negative effect on our overall results as a negative in the upstream is offset by the positive in the downstream.

Additionally, we also accrued another quarter of crude production incentive of $3 a barrel for close to ARS0.5 billion. And the last positive impact in upstream revenues was the ARS0.5 billion accrual for the insurance recovery of the business interruption policy from the Cerro Divisadero fire in 2014. This accrual, by the way, was in line with the advance payment already received by the insurers in October.

On the costs side, these were up by ARS2.6 billion or 17.5% increase compared with the third quarter of 2014 mainly due to higher depreciation of ARS1.4 billion, ARS0.9 billion increase in items related to lifting cost that we already went through, another 0.9% increase in exploration expenses, as also discussed before, and higher royalties because of higher prices in pesos.

Production wise, crude oil production in the third quarter increased 1.3% to 249,000 barrels of oil per day. Natural gas liquids production was also up by 1.1% producing 43.7 thousand barrels per day. And natural gas was down by 1.4%, producing 44.4 million cubic meters a day. As a result, in this quarter total hydrocarbon production was flat vis-a-vis the same quarter of 2014 with 571.9 thousand barrels of oil equivalent a day.

Crude oil production was pretty much in line with our expectations with some delay coming from our shale developments. But with respect to natural gas, the production during quarter was negatively affected by a couple of factors.

First, the swap of certain areas with production in the Neuquina Basin in December 2014 for stakes in other areas, which were not in production. And second, it was affected by certain technical contingencies in non-operated areas in Manantiales in the Austral basin and in Neuquina.

Actually, the gas production derived solely from YPF-operated areas was up 2.1% during the quarter. Additionally, the delay in the development of certain sites did not allow us to properly offset some of the natural decline.

Now, let's move to our shale gas and shale oil activity. During the second quarter, we connected a total of 43 wells, including 34 shale oil and 9 shale gas wells, taking the total to 388 shale wells in production.

Gross production from the shale areas reached an average of 46.2 thousand BOEs a day, primarily from Loma Campana field where we have a 50% working interest in a joint venture with Chevron. And in October, this production was already beyond the 50,000 BOEs a mark.

El Orejano is our second largest shale project and is producing an average of 750,000 cubic meters a day from 16 wells in production. Dow, our partner in Orejano, has injected an additional $60 million into the project a couple of weeks ago and should be making the final decision to convert it's participation to full equity before the end of the year. El Orejano will be a relevant source of additional gas for 2016.

We have also drilled two exploratory wells in a new gas field with target Vaca Muerta called La Rivera and then La Amarga Chica our joint venture with Petronas also has a couple of wells in production.

During the quarter, we continue developing the east area of Loma Campana with horizontal wells with positive results. So this will be the basis for our 2016 drilling campaign in Loma Campana.

We have developed, and that's the graph that you can see in the slide, a well-type curve for that area of the field that assumes a 1,500 length of the horizontal section and 18 frac stages per well. This well type should be able to accumulate an EUR of 560,000 barrels over -- of liquids with a GOR of 120.

The well-type curve is a black dotted line in the graph. We show the cumulative production of such well type against each horizontal well completed and connection 2015, those are all the different colored lines, but only those wells that have more than 60 days of production as of September 30, 2015.

And also we have compared it against the average of every horizontal well connected in 2015, which were 21 wells by the way, which is the green dotted line. It's very encouraging to see how the average replicates almost exactly the well-type curve, but it's even more encouraging how most wells have produced above type curve with an outstanding 28 frac well with substantially higher initial production, and that's the yellow curve of our well 992.

Those wells below the type curve were wells that presented different issues that prevented them from being completed, but that we expect to eventually complete them and improve their productivity.

Now besides productivity, it is also important to highlight that the average cost per well has been $40 million this year. This is just the horizontals by the away.

We are optimistic that this cost will come down next year once some of our efficiency initiatives are put in place like the usage of our own proppant that should gradually come on stream starting in February and the 15% reduction in drilling time that we believe is achievable now that we have more experience in our horizontal drilling.

Tight gas continues to be one of the drivers of our production growth and represents 12% of YPF's natural gas production. We have drilled seven wells starting the Lajas formation in Loma La Lata block where we own 100%. And we have drilled 12 wells starting in the Mulichinco formation in the Rincon del Mangrullo where we own 50%.

As a consequence of our drilling activity, gross production continued to show encouraging results reaching 4.4 million cubic meters a day in Lajas and 2.1 million cubic meters a day in Mulichinco.

Mulichinco and Lajas differ substantially in terms of the cost of the wells as Mulichinco is only 2,000 meters deep whereas Lajas formation is between 3,500 to 4,000 meters deep.

Moving now to our downstream business segment, this quarter's operating income was ARS3.5 billion showing a decrease of 9% compared with the third quarter of 2014. Revenues were up by almost ARS1 billion, so 2.5%. The main driver of the increase was gasoline sales, which were up by close to ARS1 billion on 4% higher volumes and 10% higher prices in pesos.

On the other hand, diesel sales were down ARS175 million due to 5.5% decrease in sale volumes driven by adverse weather conditions during the month of August that severely affected the agricultural and transportation sectors. Offsetting was an 8.8% increase in prices for diesel oil in pesos. Again, remember that both prices in dollars were down, diesel and gasoline.

It is also worth highlighting that in this quarter we have improved the mix of products sold increasing sales of premium products by 34% and 24% for gasoline and diesel, respectively.

In the export market, we noticed a decrease in sales of 17% or ARS587 million mainly due to the fall in international prices for those products tied to the Brent. However, these export declines were somehow mitigated with lower withholding taxes, which are accounted for in SG&A.

Fuel oil sales in the domestic and internal markets totaled ARS2.3 billion representing a significant increase of ARS519 million mainly due to higher volumes sold in the domestic market as well as higher prices in pesos and partially offset by the decrease in export sales due to lower international prices for fuel oil.

Costs increased by 4% compared with the same period in 2014. We can highlight first, greater imports of diesel and jet fuel for ARS240 million due to increased volumes imported but at lower international prices, higher depreciation for ARS144 million, and finally a small reduction of ARS72 million of crude oil purchases.

We increased the crude purchased from third parties, but we slightly decreased the crude transferred from our upstream segment. This was mainly driven by a scheduled maintenance halt in our La Plata refinery.

With regards to refining costs, this increased by ARS313 million primarily due to increases in general expenses and salaries and some additional costs associated with this maintenance of the catalytic cracking unit that we just made reference to.

Consequently and considering the low processing level on a per-barrel basis, the refining cost increased by 25% in pesos.

During the quarter, volumes of crude oil processed were 297,000 barrel of oil per day, which was 0.6% lower than the third quarter of 2014 mainly due to this 60-day scheduled halt of activities at the catalytic cracking units in our La Plata refinery, which affected the activities during September and October.

Year-to-date, however, volumes of crude processed were up by 4.1% reaching 300,000 barrels per day. The utilization rate of our refining capacity during the quarter was 93%. Regarding the domestic market, total sales was slightly decreased by 0.4% in volumes mainly driven by the 5.5% decline in diesel due to this excessive rainfall in August, which mostly affected the province of Buenos Aires and disrupted the transportation and agricultural businesses. Gasoline and fuel oil were strong but volumes were not enough to offset this decline in diesel.

On this slide, we have plotted YPF's monthly sales for the last two years and the first three quarters of this year. You can note that the green line in the gasoline chart in the left represents 2015 percent sales is consistently above 2014 and 2013 sales showing an increasing demand in the local market despite higher local prices, and the market share remains stable in gasoline around the 57% level.

In terms of diesel, which is the graph on the right-hand side of the screen, 2015 sales were flat against 2014 sales year-to-date and they were higher than 2013. But you can see the significant drop in August, which was recovered in September and in October, which is not part of the graph. Market share of 59% was slightly below last year but well above the previous year so in line with our expectations. Now market share of our premium products on the other hand is actually higher as both EuroDiesel and Infinia, which are our premium brands, enjoyed market shares comfortably above the 60% level.

During Q3 2015, the total CapEx for the Company amounted to ARS15.7 billion, which was 14% higher compared with the third quarter of 2014. Upstream CapEx amounted to ARS12.3 billion, which is 10% higher than the last year. And the most meaningful investments have taken place in the Neuquina basin most specifically in Loma Campana, in our Toledo-Sierra Barrosa, in Rincon del Mangrullo, Orejano and Chachahuen. And then to a lesser extent in the Golfo San Jorge basin in Manantiales Behr, El Trebol, Los Perales, and Canadon La Escondida.

With regards to exploration, in this quarter we completed eight exploratory wells and total exploration CapEx was 30% higher than last year. In downstream, CapEx was ARS2 billion where our largest ongoing projects it's a coking unit being built in the La Plata refinery and which is still scheduled to be completed in the first quarter of 2016 and commence operations in mid-2016.

We started the quarter with a high cash position that together with a ARS2.6 billion debt increase allowed us to fund our CapEx and still maintain a solid cash cushion at the end of the quarter. In Q3 2015, operating cash flow was ARS9.8 billion, almost identical to the previous two quarters but 46% lower than a year ago. The operating cash flow last year had been unique as it included the collection of a good part of the insurance from our La Plata incident and a much better evolution of working capital.

This quarter we have accrued higher revenues coming from natural gas and crude oil subsidies that have not yet been collected. During the quarter and also in October, we issued a total of over ARS5 billion in the local capital markets with average maturities close to five years. So we have increased the blue bar at the far right of the graph, therefore lengthening the average life of our debt to 4.7 years. This time the extension in tenure did not come with an increase in interest rates as most of the new issue came from the local markets at rates similar or lower than our average interest rate in pesos, which was 23.8%. The average cost of a dollar debt stands at 7.5%.

As usual for us cash position of around $1 billion is enough to fund the maturities over the next 12 months. We will probably do another local trade before the end of the year to fund the negative free cash flow or for the remainder of this quarter. Our leverage ratio of 1.4 times net debt tour EBITDA is getting closer to our target ratio of 1.5 times. We might temporarily go beyond that ratio during part of 2016, while we return to free cash flow breakeven.

In summary, results were solid in the quarter in line with our budget and in line with our guidance. We continue to face a substantial challenge with respect to our cost base and a good part is a result from the strong peso, but also derived from the substantial growth in activity in the last three years.

Production was somehow below our expectations especially in terms of natural gas but resulting from very identifiable situations and not from a change in fundamentals. We seem to have found a solid strategy to develop the shale in Loma Campana and should improve its results in 2016. And other Vaca Muerta projects continue to look promising also.

Our downstream business segment continues to prove its resilience and we are operating in a very healthy local market in terms of demand. So we look forward to having some additional clarity in the macro and political front in the next few weeks in order to finalize our 2016 budget process and only then we will be able to share some guidance in terms of EBITDA, in terms of CapEx and in terms of production as we always do.

So with this I would like to thank you and open it up for questions.

(Operator Instructions) Bruno Montanari, Morgan Stanley.

I have a few questions here. I know it's early to talk about the budget. But just trying to understand what the process will be, what you need to see from the new administration that will make you comfortable to outline a business plan. And then still on that topic, if you could elaborate on the Company's strategy in the context of lower oil prices, should we expect a deceleration in the investment phase of crude oil particularly shale and see the portfolio migrates to the gas opportunities? And how quickly would you be able to start developing the first shale gas prospect?

And the second question is, if you could comment a little bit on the working capital needs we observed in the quarter. You mentioned receivables building up from incentives for crude oil production. So when are those expected to be received and how have the payments from the higher gas price being done? Any delays from the government now that the country is in a kind of a transition phase. Thank you very much.

In terms of budget we are well advanced with our operating plan for next year. For obvious reasons we would like to review that with the new administration coming in that will be holding the 51% stake owned by the government. And then the other thing that we are waiting is to have more clarity on the macro situation, okay.

How the FX is going to evolve, what kind of inflation and price increases we can factor into our projections. And frankly, we are at a very unique timing right, just in the middle of the two elections, so it's probably a time where it's reasonable not to expect a lot of clarity. Fortunately, it's just a few weeks away, so I'd say, Bruno that we will wait to see, again, how the macro prospects evolve for next year, which are obviously the most important assumptions in our budgeting process.

And second, we would like to have the opportunity to discuss our plan our budget with the new administration before going public with it. So that's a process. In terms of strategy with the lower crude oil prices, we are of the opinion that international crude oil prices will not recover significantly at least next year. We do believe that local prices will continue to enjoy some kind of premium with international prices.

However you are right that we have been shifting and we will continue to shift as much as we can production from oil to natural gas as the fundamentals for natural gas are very strong in Argentina. This is a process that takes a lot of time in order to start -- to drill more aggressively for natural gas you need to have the projects in place in order not to take unnecessary risks and we will not take unnecessary risks. So when we have to prioritize a project a gas project vis-a-vis an oil project we will probably be more inclined towards oil -- gas projects, sorry. But again this is -- you will see some shift but it's not that you are going to be seeing a significant difference in terms of the mix between gas and oil in 2016 vis-a-vis 2015. More gas than oil? Absolutely.

And in terms of the shale gas specifically that you asked in that question, we are already producing there in El Orejano. I believe that we are going to be close to 1 million cubic meters a day by the end of the year. We have a budget in mind that we will need to discuss with our partner there for next year, but obviously that will be an important part of the CapEx coming forward at least in 2016 a good part of the growth in natural gas in 2016.

Now, we are also doing some exploration in other shale gas areas always with the same objective of formation Vaca Muerta but for instance this area La Riveira, which I mentioned, where we have drilled two wells and we have other areas that we might start doing some drilling next year.

Now to your final question regarding working capital, I think that with all the political changes in the fourth quarter it's difficult to assume a significant improvement in the working capital. We have seen some delays but not significant vis-a-vis what we have seen in the past. In terms of the natural gas subsidies we are collecting six months after the end of the month, we were collecting more like five months last year so there is some additional delay but not that significant.

And then the other thing that had an effect on the working capital is that we accrued two full quarters of $3 per barrel subsidy for crude oil production and we haven't collected that yet but it's not because it's delayed it's just in line with the process -- at least the second quarter it's in line with the process that we have in order to make our filings with the local authorities and get the approvals in order to get paid.

Now as I said, with a change occurring in the middle of the quarter I think it is probably safe for us to plan for a challenging working capital environment in this quarter and improvement happening next year.

Great, very clear. Thanks a lot Daniel.

Felipe Santos, JP Morgan.

Just a question. Actually, have you entered in contact with the two candidates to see what they had -- their thinking for the energy sector in Argentina going forward how has been the approach of them I mean or has their possible future ministers approached you in thinking of what going to be -- to expect in the future, how is this transition phase for you?

And you mentioned that you don't have yet the final plan but what is the time line that you think is to release the new CapEx plan and to put it on the market for the next year? Thank you.

I understand and I did expect a question regarding politics, of course, but we need to be patient. We are only two weeks away from a crucial election. And it's completely unnecessary for us to make any guesses at this point of who will do what. So the answer to your question is, no, we have not had any formal contact with any of the candidates regarding the energy policies. And it probably doesn't make a lot of sense to have that contact until we know who will be running the country for the next four years.

Obviously, we have a lot of ideas of what needs to be done and how and we will make sure to put forward those ideas to whomever comes as a winner on November 23rd and the next few days.

In terms of the time line for the budget, our idea is to have everything ready in order to present it as soon as possible to the -- whomever are the representatives of the new administration, as soon as they take office or a few days before they take office. We are going to be ready with our plan. But also remember what I just said, we also intend to factor into our plan for next year an update on the macro drivers, which are very significant for us and have to do with FX, they have to do the inflation, to our ability of transfer a potential effects of a devaluation to prices and so on.

And in that respect we might be able to use some help from whomever comes as a winner in the next elections in terms of what their plans are for the macro. I think we are very clear in terms of what our plans are from an operating perspective; of course, we need to run that by them but we are a little bit less clear in terms of what the macros variables will be for next year.

So summing up the answer to your question is, we will wait for both things, okay, a, to have more clarity on the macro and b, having them confirm our plan and only then we will go public. Hopefully, this should happen during December so at some point in December we should be in a position to start providing guidance.

Excellent, thank you.

Ricardo Cavanagh, Itau BBA.

Well, it's also politics and I know being the -- being sensitive and without mentioning anybody, do you think that the political establishment all along has a widespread perception or shared perception that national production needs to grow, are you still falling on a national level?

And in other words, do you think that there is a common ground within the political establishment to make a thinking that, well, this is going to be the conditions for YPF to grow independently of what happens on the macro (inaudible) fundamentally because I see that basically the main objective of nationalizing YPF was to recover self sufficiency and while YPF has been increasing production there is -- are still short of that objective, no? So Argentina needs to do something and well again do you see a common ground?

Yes, I do see a common ground. I do believe that production -- profitable production growth is something that people share okay and that YPF should be the engine of growth in Argentina. But followed by a rest is something that also politicians generally share so that I agree with you now.

We -- it's not just about growth for us, okay. Remember that we have a constraint in terms of our capital, so profitable growth and reasonable growth, and more reasonable cost structure are all significant priorities for us also. So I think it will not be difficult to align some of these priorities with what the country needs.

But that's exactly what we have done in the last three years; structurally align the need of the country for more hydrocarbons with our own need as a Company to increase value, to enhance value by growing profitably. So what I am trying to say is, yes there is common ground but we also need to incorporate it to that discussion what a company needs in order to be sustainable in the long term.

Perfect and thank you for that. And the last one is on in terms of CapEx (inaudible) has increased but at a pace that in the past quarter has been below inflation might be something -- what is -- how would be label that or in what context that relation has been given?

Well CapEx the guidance that we had provided for this year is that there would be close to $6 million. It will be close to $6 million. We have a range of $5 million to $6 million of CapEx which we believe are sustainable.

Today with what we know, if this year we are going to be closer to the top-end of that range I think probably next year we're going to be close to the low-end of the range but still directionally not changing to what we are focusing our objective to continue to grow and with profitably.

Okay. Thank you.

Walter Chiarvesio, Santander.

I have two questions exactly. The first one, if you could explain -- probably, you already did it -- but if you can explain a little bit more about the expiration costs that were a little bit high for me this quarter? And if you can give a guidance toward the future? That is my first question.

And the second one is, of course, I understand all the uncertainty regarding what is going to happen with the macro economy next year but to put it in a different way, probably the question would be how much do you need to translate into the pricing, the devaluation of the currency assuming that local costs grows with local inflation and the devaluation is higher than inflation. That is a possible scenario next year. So, the currency depreciate by 50% and the inflation is 20% and so salary cost. Do you have an idea of what could that be? That is my question. Thank you.

In terms of expiration costs, as I said, we had 12 wells, which were written off during this quarter just to give you a sense, we had around 5 wells per quarter the previous two quarters but last year in total we had 30 wells. So, we are totally in line with having similar number of wells being written off this year vis-a-vis last year.

What I am trying to say with this is, that this is not a negative trend by any means, despite the fact that we are obviously increasing our exploration CapEx at the same time, okay.

So it is usually a process which is not even throughout the year, okay. You have a quarter in which you make a decision, you have more information and you decide to write-off some number of wells and on the next quarter you don't have enough information so you delay the decision for the following quarters. So it's impossible to provide a guidance. What I can tell you is that year-to-date what we have an expiration expense is exactly in line with our budget. So we are not concerned with that.

Now to the second more difficult question regarding the macro. Yes, we believe that there will be some sort of real devaluation of the currency meaning that the currency will probably devalue beyond the inflation level next year. What are those levels? Frankly, we don't know and that goes to the previous questions of we will love to understand that a bit better, what, whomever comes as the winner of the election has in mind. So, that real devaluation will clearly mean that a good part of our cost base could be diluted in dollar terms because approximately 70% of our cost basis in the upstream is denominated in pesos.

So, this year on the other hand there was a real appreciation of the peso. What that meant is that because we have been trying to keep our prices pretty much flat in dollar terms, the increase in prices was not enough to offset the increase in costs. So, we hope to recover some of that margin that we lost this year in the future, in the near future.

But it's very difficult for me to go beyond what I am telling you which I understand it's very conceptual, it's very difficult to provide you with any precise numbers because frankly we don't know. So, depending on the extent of that real devaluation, we might need more or less pass through of our devaluation into prices. But clearly, if our costs go up in pesos, our prices need to go up in pesos. At least in line with the cost or higher in order to recover what we lost this year.

Okay. Thank you very much.

Anish Kapadia, Tudor, Pickering, Holt & Co. Securities

I just had three questions please. Just then going to some of the data you provided on the unconventional wells. I was just wondering for 2016 for the horizontal wells what kind of well costs do you expect because looking at the US we've some pretty dramatic falls in well costs not only because of the service environment but also higher efficiency going coming through. So, just wondering where that 14 could get to next year?

And then on the tight curve, thanks for providing that extra information. What I wanted to just understand there is what was the IP rate that you were assuming for those new horizontal wells and what kind of oil price breakeven do you see with that tight curve at the current well costs, so for a 10% return, what kind of oil price would you need?

And then just finally just trying to understand the impact of low oil prices. Just wondering if you could give some sensitivity of your cash flow next year to say $10 move down in oil prices? And in terms of how you're kind of looking at next year, with the aim next year to be balanced in terms of free cash flow or are you willing to kind of let that increase again in 2016? Thank you.

In terms of the costs for next year, obviously if we are not providing guidance on EBITDA and CapEx [less] so such a specific guidance on what the horizontal costs will look like in 2016.

What I can tell you is that it will definitely be lower than the 2015 numbers. We have a few initiatives, very clear initiatives in place, the most clear and I know that I used this example many times is the proppant as in the sand that we're going to be using, which is going to be our own sand, it's not just being our own sand it's also about using more of the natural sand and less of the resin sand. That in itself should reduce the cost of the sand per well by 50% and the sand is probably close to 10% of the cost of our shale well. So that's a significant reduction in itself.

We also expect to reduce the drilling times as we have more experience with the horizontal drilling, better equipment and so on in place. So clearly, we do target significant reductions in the cost per well. But a good part of the answer has to do with the previous questions that a colleague of yours asked regarding the macro variables okay, because the $40 million figure was achieved at a moment in which our costs in dollar terms were going up, right because inflation in Argentina was running at a higher pace than devaluation. So if that is reversed next year that in itself should have a very positive effect on the dollar cost per well.

We've never provided breakeven prices for any of our projects. What we can tell you is that the campaign that we are planning for next year of pure horizontal drilling with the prices that we enjoy locally and with a GOR cut in half with the added profitably coming from the associated gas. Those returns at or above are 15% IOR threshold. So we believe that with these prices we can successfully continue to develop the shale of course with our own assumptions that over time we continue to reduce costs -- to your first part of the questions which is a very meaningful one.

In terms of the impact of international low oil prices, the rule of thumb that we have been using in the past and has not changed is that for every $10 of Brent price fluctuation we have an impact of approximately between $100 to $150 million of EBITDA. So, if you assume another $10 of reduction that's $150 let's say to be on the safe side less EBITDA for next year.

Remember this is a Company that, I don't know, last 12 months EBITDA was around $5 billion last year was slightly above $5 billion. So if you use that as a run-rate, you conclude that we are not that sensitive to international oil prices in the short term of course in the long-term that means less investment less ability to bring in partners. So there might be a different effect in the long-term.

In terms of free cash flow, we do expect to become free cash flow neutral again at some point in 2016 clearly not 2016 as a fiscal year and probably not in the first half of 2016. So we will be getting there in the meantime we might see some additional increase indebtness. We have not changed our target ratio of 1.5 times as I said during the presentation, we might go a little bit beyond that ratio but only temporarily as we achieve free cash flow neutral status at some point hopefully next year.

Thank you. Just a quick follow up on my first question, I was just wondering, in terms of the well cost that you're seeing have you got the benefit of the fall in service cost that we're seeing in the US. So kind a much lower rig rates, completion costs. Or is that kind of some more of an isolated market in Argentina, so you don't see that coming through. So wondering how is that kind of that scope still to come through or has it come through already?

Sorry I didn't listen the first part of your question, Anish, I apologize.

Sure let me say again so in the US we've seen pretty dramatic falls in rig rates and completion costs given the over capacity. I was just wondering have we seen that come through in Argentina as yet or is Argentina somewhat of an isolated market and given kind of the labors you wouldn't expect that? Are those kind of reductions to translate through.

Well I don't expect the same kind of reductions in the short term. I think it's a more of a gradual process in Argentina and it's a little bit less flexible in terms our labor cost, which is what you were pointing out. However, I think in the long-term if you want the local shale to be competitive, you need to get closer to international costs, right.

So as I said repeatedly we do have significant cost initiatives so efficiency initiatives in place, but still I would not count with a 20% or 30% cost reduction per well as a some of the US producers have been experiencing or promising for the near future. I think it's going to more gradual our path to getting there.

Great, thank you very much.

Santiago Ruiz, TPCG Group.

I would like to know about the progress made in the (inaudible) by YPF with other corporates and if can expect another MoU in the next 12 months. Thank you.

We are not expecting any imminent announcement about our potential new JV. We have different people looking at couple of projects both in shale as well in the tight. We have a lot of food in our plate already with the JVs that we have in place, we have gone through some of that in the presentation.

I think there the strategy has not changed, the strategy will continue to be to develop the shale with partners on a 50-50 basis mostly. We hope to incorporate more partners coming in actually a few things that we are looking with the third parties are all new third parties to at least to conversations with us. Some of them are more advanced than others but again nothing imminent to expect.

And you should assume that what I have just said regarding this being an uncertain time in terms of politics and macro, it's probably the same thing from a people that are looking at our projects. I think from a geological and from an operating perspective the situation is very clear, from a macro it's probably less clear. And that's I think people are waiting to have that clarity before making any decisions.

And we don't have any rush. We always have said that we would be very disciplined in the way that we dilute our asset base. So in the mean time we continue to delineate, we continue to de-risk our properties. And hopefully, all of that will result in with high evaluations when and if we decide to do more JVs in the future.

Okay, thank you.

Bruno Montanari, Morgan Stanley.

I just have three follow-up questions. Just revising the gas production. When you mentioned the swap of areas in production, is this a recurring thing? So should we expect the current gas production should be the new base or the swap will already start to revert in the next few quarters? Thanks a lot.

Bruno this is the new base. These were areas that were in production in December of last year. And where we exchanged those for stakes in other areas, which were not in production. Obviously, we did that because we expect to extract more value over time for the new areas that we have gotten. But in the meantime it will suffer a little bit in terms of production.

In the first quarter of next year, when you compare whatever the gas production is during that first quarter with the first quarter of 2015, that difference will just go away because you will be comparing with a base that already didn't have those areas. But in the fourth quarter you should assume a similar situation than the third quarter.

Okay and just to give us an idea, can you disclose the volume of those areas so we can separate from that non-operated areas in that.

Bruno I don't have the exact figure but you should assume it's around 0.5 million cubic meters a day.

All right, thanks a lot.

We have no further questions at this time.

Okay, if there are no further questions, thank you very much everybody for the participation and thank you Sylvia for coordinating the call for us. Have a good day.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.