YPF Sociedad Anónima
Q4 2016 Earnings Call Transcript

Published: 10 Mar 2017

[Operator:]

Welcome to the YPF Full Year 2016 Earnings Webcast. My name is Richard, and I will be your operator for today's call. [Operator Instructions] I will now turn the call over to Mr. Diego Celaa, IR Manager. You may begin.

[Diego Celaa:]

Great. Thank you, Richard. Good morning, ladies and gentlemen. My name is Diego Celaa, Head of Investor Relations at YPF. I would like to thank you for joining us. In this occasion we will discuss YPF's 2016 full year results. The presentation will be conducted by our CEO, Mr. Ricardo Darre and our CFO, Daniel Gonzalez. During the presentation, we will go through the main aspects and events of the year 2016. Finally, we will open up the call for questions. I need to let you know that we will be making by forward-looking statements so we ask to carefully review the cautionary statement on Slide 2. Our agenda today will include a review of the key issues and achievements of the year, review of our operations, a detailed explanation of our full year results and update of our financial situation and finally the conclusions. Also our financial statements figures are stated in Argentine Pesos and in accordance with International Financial Reporting Standard ,IFRS. In addition certain financial figures have been attested to reflect additional information to let you better understand our key financial operating results. Mr. Ricardo, go ahead.

[Ricardo Darre:]

Thank you, Diego and thanks everyone for joining us this morning to review our full year 2016 results. This first year was the year in which local crude oil prices continued to drop, a year in which relative prices in the Argentine economy tended to be readjusted after the devaluation of late 2015 and a year in which the industry struggled to move products around as demand was really soft. However, we managed again to deliver results in line with guidance but we made significant progress to adjust our activity to a new industry reality and also to improve productivity and reduce cost. In this scenario, revenues of ARS210 billion were up by 35% year-on-year and adjusted EBITDA reached ARS58.2 billion which represented a 22% increase over 2015. However the operating income before impairment was down by almost 44% of the growth and adjusted EBITDA was more than offset by the increasing depreciation expenses caused by the 60% peso devaluation. Operating cash flow was up by 42.7%. The impairment charge registered in the third quarter of 2016 was by far the most important contributor to the net loss of ARS28.4 billion in the fiscal year 2016. However in the fourth quarter of the year, we reverted to a positive net income of ARS1.8 billion. In 2016 we produced 537,000 barrels of oil equivalent per day which was essentially flat compared with a review year with a slight increase in the production of natural gas and a slight decrease in the production of crude oil. In line with most other place in the industry our proven reserves were negatively affected by lower crude oil and well therefore down by 9%. Lower oil prices affected negatively our base of proven results in mature fields taking a drop of concentrated mainly in the Province of Santa Cruz. This drop could not be compensated by the activity in Vaca Muerta since the SEC rules for reserve calculations required consideration of the history of production that we don’t have yet. Total CapEx was slightly up in pesos but approximately 36% lower in real terms. Without any doubt, one of the highlights of the year was the substantial improvement in the economics of shale drilling and completion that has pushed down breakeven prices to levels comparable to most other shale plays in the world. We will spend some time discussing this during the presentation. Let me move to Review of Operations. Let me start this section by focusing briefly on our financial results expressed in U.S. dollars. Since it will allow me to provide you a better understanding of the evolution of the business within the year in real terms. Revenues in dollar terms were down by 16% as diesel and gasoline prices dropped by 18% and 16% respectively. Additionally demand dropped with respect to 2015 and we also sold less fuels than last year. On the positive side, natural gas experienced solid demand and prices were up almost 6% in dollar terms. Adjusted EBITDA was down 23% to $4 billion, other margins were compressed a couple of points due to cost of sales dropping only 7% in dollar terms as purchases of crude oil and biofuels are denominated in dollars as are the royalties. In addition, higher depreciation expenses contributed to the 65% reduction in operating income before impairment charges. Daniel will explain this effect in more detail in a few minutes. When we analyze these all figures for the last quarter of the year, we see slightly milder behavior as the EBITDA's valuation was lower than that over the full year. The other big difference is that the impairment charge of the last quarter of 2016 had a gain of $79 million compared with a loss of $195 million for the last quarter of 2015. Slide 8, in terms of production realized by our upstream business unit, we ended the year with flat hydrocarbon production of 577.4000 barrels of oil equivalent per day. Breakdown between oil and gas crude oil production down by 2% to 244.7000 barrels per day, natural gas production up by almost 1% to 44.6 million cubic meters per day and natural gas liquids production up almost 7% reaching 52.5000 barrels per day. This growth in NGL offset some of the decline in crude oil production and with the reservoir business decision to save some production to be processed for extraction of liquids. Additionally the production of the yield was affected in approximately 1.2 million barrels of oil equivalent or 3,000 barrels a day due to different label conflicts with sulfur that affected our operations. We would like to highlight that the gross production derived from this field - those fields in Argentina were YPF is the operator was up by 4% in 2016 while on the other hand the non operated production was down by 2.2%. Moving on to the reserve YPF is not an exception to the industry and after three straight years of increasing reserves, we have reduced our proven reserves by 9.2% to slightly above 1.1 billion barrels of oil equivalent. The reserve replacement rate of only 46% despite incorporating 98 million barrels of oil equivalent of new reserves most of it in natural gas. This transaction affected mainly our crude oil reserves, principally due to the 13% reduction in local prices throughout the year. We believe we still have substantial resources especially those in shale, oil and gas areas. It should gradually be incorporated into a process space and that should allow us to replace and grow reserves on a sustainable basis. The reserve booking coming from the Shell has slowed by definition until the percents only a fraction of our total proven reserves. Reserve additions, on the other side, came from a variety of fields but mostly in the Neuquina Basin, our shared project in Loma Campana, El Orejano, high developments in Lajas formation both in Aguada Toledo, Sierra Barrosa and Estacion Fernandez Oro and also in the Mulichinco formation in Rincón del Mangrullo. We also incorporated some reserves from the acquisition of participation in Rio Neuquen and Aguada de la Arena. Additionally we also include reserves in the Golfo San Jorge basin from the expansion of secondary recovery projects. Now I would like to provide some highlight on our shale gas and shale oil activity as 2016 was a turnaround year for us. We achieved an important oil cost reduction and a significant improvement in oil productivity which exceeded even our own expectations. We drilled and completed 19 wells in the last quarter and now we have 541 producing wells at an average gross production of 62.3000 barrels of oil equivalent per day in the last quarter. On the top right graph of this slide, we can see the evolution of oil cost in Loma Campana and there are two important takeouts of this graph. First, that we have drilled all of our horizontal wells during this last quarter at an average cost of $8.2 million per well and with some additional savings this year we had already below this number in the first quarter of 2017. And second we have reached an optimized the number of fracs at 18 stages per well with an average of 17 frac stages for the well completed this year. As we can see on the graph at the lower right, the production per well in Loma Campana is 25% higher than what it was two years ago. Our tight well curve gives today expected yields we had recovered an EUR of 550,000 barrels of liquid plus gas and we're seeing even better results in 2017. With this productivity and the new cost trajectory we calculated breakeven price with 13% rate of return IRR of less $40 per barrels. With this performance in hand, we feel very comfortable in foreseeing an expansion of productivity in Vaca Muerta by engaging in a number of new pilot projects in 2017. As you can see on the map on your left, the location of most of this project is concentrated in two distinct areas. First areas complete was to those already under the development and second areas where we’re moving further into the dry gas window. In the case of Vaca Muerta, we have recently announced a joint venture with Shell in which Shell will carry us with $300 million of investment in the first two years of our pilot project. We are also witnessing a substantial increase in the interest from different players to join us into the development of Vaca Muerta so we are comfortable with our strategy to increase the value of the assets. Significant part of the future Vaca Muerta relies on the infrastructure for development, as many of the analyst on the call have witnessed in the field trip organized last December. Most of the infrastructure is already in place. The oil treatment facility for Loma Campana another shale oil areas washing, drying and classification plant with a capacity to provide the necessary proppant for several years. The control room is monitoring bringing on production. The pipeline is necessary to provide the water et cetera. On this slide we wanted to show a chart from a joint study down between YPF and WoodMackenzie comparing the productivity of our Loma Campana wells in 2015 and 2016 showing great in compression with NOL wells in the main sale oil place in the U.S. Benchmark shows that EUR expected that we're going to make recovery for typical wells divided by the lateral length of the well. As we can see on the graph with significantly improved from 2015 to 2016 but more importantly we compare favorably with most other shale plays. Our challenge now is to preserve or increase these rates as we move to longer lateral. Clearly the quality of the rock is second to none and we are proving our availability to successfully develop it. With regards to our tight gas projects, in 2016 we have put in production 41 wells targeting the Lajas formation in Aguada Toledo Sierra Barrosa, where we have 100% share. 28 wells targeting the Mulichinco formation Rincón del Mangrullo where we have 50% share and 21 wells in EFO Estacion Fernandez Oro where we also own 100%. As a consequence gross production continued to show encouraging results reaching in 2016 levels of 4.9 million cubic meters per day in our Lajas project, 2 million cubic meters per day net for YPF in Rincón del Mangrullo and 2.1 million cubic meters per day in EFO. Today tight gas represents partly 22% of our natural gas yearly production. Also in the near future we will be showing the production of the Río Neuquén and Aguada de la Arena blocks a more recent acquisition which we expect will further accelerate our tight gas production. Moving on to our downstream business segment on this next slide we show that in 2016 the crude oil process in our three refineries was 294,000 barrels per day 2% lower than in 2015 this is due mainly to the scheduled maintenance activities in our refineries during the year. Still the utility section rate of our refining capacity during the year was 92%. For this year and with the corporation of the new delayed coke unit and La Plata refinery we expect a higher proportion of higher value products. Regarding the domestic market total sales fuel increased by 3% mainly driven by a 4.1 decline in diesel and 11.6% decline in fuel oil. This is a decline was basically due to economic activity and a small market share reduction and fuel oil decline was consequence of more availability of natural gas to feed power plants. Gasoline demand also showed a reduction of 1.3% as we traded market share against by serving our prizes in a competitive market as we will see in the next slide. On the graph on the left we can see the monthly sales of gasoline for this year in green compared with the previous two years. The year started strong then decline and recovered again towards the end of the year. In term of diesel sales at right of the screen the whole year was soft we saw some recovery towards the end of the year. Market share for both products show a little decline against record high levels of 2014 and early 2015 today we feel confident so that we can maintain our share in this 55% range for both products with some additional share in diesel than in gasoline. In term of the premium products premium products Infinia and Eurodiesel market share was 60.7% and 58.1% respectively, comfortably above the levels for ordinary products. With regards to our gas and power activity which for the first time we are breaking down as a new segment in our financial presentation we continue to move forward with the new projects of power generation that will add 535 megawatts project Loma Campana I Loma Campana II those and first phase of Manantiales windfarm and expected to start up operation in the second half of this year while for the project in Tucuman we expected to be on operations in the first quarter of 2018 all this projects are fully funded we’ll consider the corporation of one or more equity partners to fund additional project as we believe there is substantial additional growth and we are now planning to allocate more equity in this segment for the time being. Finally despite the many challenge we were able to deliver in line with guidance. We ended the year with a total CapEx $4.3 billion which is below our target range of $4.5 billion to $5 billion. The adjusted EBITDA was $4 billion in line with our estimate for the year. The lifting costs were reduced in 20% in real terms also we were able to achieve flat production of hydrocarbons despite the social and labor conflict. For our shale cost per well we overachieved our target of $10 million by reaching 8.2 million by the end of the year. And finally the delayed coking unit commenced operation in September of 2016. Now I’ll pass over to Daniel for the financials.

[Daniel Gonzalez:]

Thank you, Ricardo. Now I will go to the analysis of the annual results denominated in peso as we always do. Revenues in our Argentine pesos increased by almost 35% adjusted EBITDA was up by 22% and operating income before impairment charges decreased by 44%. We’ll get in more detail in following slides about it reasons behind these changes. Operating income before impairment charges went from a positive ARS16.60 billion in 2015 to a negative of ARS24.2 billion heavily impacted by the ARS35 billion and net impairment charge which had been registered in the third quarter of 2016. Revenues grew by ARS54 billion or 35% resulting from several factors first a ARS14.4 billion increase in natural gas sales due to prices which were 68% higher in pesos with a 1.4% increase in volumes. Second ARS14.3 billion increase in diesel sales due to 30.5% higher prices in pesos partially offset by a 4% reduction in sales volumes. Third, an increase of ARS11.3 billion in gasoline sales with higher prices in pesos of 34% in the year and lower sales volume of 1.3%. Exports were up by ARS4.1 billion of higher prices in pesos partially offset by lower volumes. Then we had an effect of ARS2.9 billion pesos increase in natural gas sales in the retail segment that comes from our subsidiary Metrogas due to a 60% increase in prices and 11% increase in volume. And finally we had ARS2.6 billion increase in fuel oil sold in the local market on 54% higher prices in pesos of most of our fuel oil sold locally on dollar based prices and a 11.6% reduction in volumes as Ricardo explained earlier. Cost of sales other than depreciation increased ARS24.8 billion pesos the only cash cost component which is fully dollarized are the royalties to which are paid to the provinces on wellhead prices for both oil and natural gas and they are set in dollars and these were up ARS5.2 billion or 46%. The other factors explaining the increase were the lifting cost which was up by ARS8.4 billion only 29% which translates into an approximately 20% reduction in dollar terms. Second the refining cost which was up by ARS2.5 billion or 42% and the transportation expenses which increased by ARS2.2 billion or 45%. Depreciation on the other hand was up by 68% or ARS70 billion fueled by the 60% currency devaluation and the capital expenditures which had been made in previously periods. Purchases of raw material and other products for sale increased by ARS14.9 billion mainly as a consequence of higher purchases of biofuels for ARS5.5 billion which were driven by significantly higher price in pesos as they are all dollar denominated. And in the case of ethanol, also by a higher blend. Imports were down by ARS620 million or 10% due to our 38% decrease in volumes of diesel imports which were partially offset by higher jet fuel volumes both at higher prices. SG&A was up by 34% in the year as a consequence of higher transportation expenses and salary increases. Additionally, in 2015 we had recorded a reversion of other allowance in the natural gas segment which was not present in this year. Exploration expenses increased by only ARS0.6 billion due to higher number of unproductive exploratory wells. During the year, the Company reflected a charge of impairment of property plant and equipment and intangible assets for a net value of ARS34.9 billion in comparison with our charge of ARS2.5 billion in 2015. The impairment charges of the third quarter of 2016 had been ARS36.2 billion. During the fourth quarter, we actually recorded a recovery a gain of ARS1.2 billion. The rationale for impairment had 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 of the curve. The impairment only affected actually our oil cash generating unit as on the rest of our asset base including the cash, cash generating unit and downstream units clearly passed the ceiling test. The upstream business segment suffered a 51% decline in its operating income before impairment charge. Revenues increased by 42% driven by two factors. First, higher crude oil sales by almost ARS22 billion or 39% due to higher prices in pesos of 39% also with stable volumes which were all transferred to out downstream business segment and there was a slight reduction of a very small volumes sold to third parties. And second, higher natural gas revenues of ARS14.4 billion on higher prices, in pesos but also in U.S. dollars and also slight decrease in volumes. And it is worth mentioning that during 2015, we had accrued ARS2 billion of revenues derived from a $3 a barrel incentive in affect of that which subsidy was not present this year and therefore we did not accrue those revenues in 2016 anymore. The average realization price in dollar terms for crude oil decreased to $58.9 per barrel and for natural gas the average price was $4.76 per million BTU which was 5.8% higher than in the previous year. On the cost side, these were up by ARS35 billion or 52% compared with 2015 mainly due to, first, higher depreciation of ARS50 billion as explained before. Second, ARS8.4 billion increase in items related to lifting cost which are included in a graph under the production costs. Third, 5.2 billion on higher royalties because of the high prices in pesos and lastly, higher exploration expenses as I explained before. Lifting cost on a per barrel equivalent basis was down 19.7% in the year to $12 per barrel of oil equivalent and total cash cost per BOE reached $20.7 including royalties and other taxes of approximately $6 per BOE. The downstream segment reported an operating income of ARS3.1 million which was 55% below the operating profit of the previous year. Revenues were up by almost ARS38 billion or 30% but the ARS8 billion increasing revenues was explained a few slides ago, so I will not get into that detail again. The increase in purchases, we highlight the following, first, greater crude oil purchases of ARS23.8 billion on higher prices but stable volumes for upstream segment and then 11% reduction of volumes purchased from third parties. Second, the higher purchase of biofuels of ARS5.5 billion with higher prices for both the biodiesel and the bioethanol of 76% and 46% respectively. Bioethanol volumes on the other hand increased by 11% due to increase in the blend and biodiesel volumes show that very slight increase of 1.4% although that was changed in blend oil. And finally lower fuel imports by a net amount of ARS620 million. Also in 2015 we had made a reserve of approximately ARS600 million for a 20-year-old lawsuit where we had a negative ruling and we had a positive appealing and this was already recorded and explained in the fourth quarter of 2015. During 2016 total CapEx for the Company amounted to ARS62.8 billion which was 2.7% higher compared to 2015 but 35% lower if we measure it in real terms. Upstream CapEx amounted to the ARS49 billion which was a decrease of 1.5%. Our activity was mainly focused in drilling and work over which represented almost 70% of the upstream CapEx followed by buildup of facilities with 19% share of the total and exploration in our activities representing slightly over 10% of the total upstream CapEx. During the year we put in production a total of 642 new wells, 184 of which were targeting nonconventional formations. Most meaningful investments in the upstream have taken place in the Neuquina basin, most specifically in blocks Loma Campana, Aguada Toledo, Rincón del Mangrullo, El Orejano, La Amarga Chica and Chachahuen and then in the Golfo San Jorge Basin in Manantiales Behr, El Trebol, Los Perales, Canadon de la Escondida, El Guadal, Seco Leon and Barranca Baya. With respect to exploration, in this year we completed 15 exploratory wells, 10 for crude oil and five for natural gas. In terms of the rig count, we ended the year with the total of 44 active drilling rigs after reducing a total of 18 rigs during the year. In upstream, CapEx was slightly below ARS10 billion highlighting the finalization on this product of the coke unit in the La Plata refinery. Let us use the next two slides to go through our financial situation. As we explained in our last earnings call, during 2016 we collected the receivables owed to the company from the gas plant program and we collected those in the form of sovereign bonds denominated in dollars for a total of ARS9.9 billion or $642 million. This was the amounts due from 2015. And we have decided to keeping treasury these bonds as we believe it constitute a good dollar base investment. We also collected close to ARS2 billion during the year of the crude subsidy which was also owed to a company from 2015. When we add these collections to the rest of the recurring operating cash flow, we show ARS59 billion of adjusted operating cash flow in the year and this represents almost 43% higher operating cash flow that previous year, this is one of the most important highlights of the year in my opinion. As previously discussed, cash flow generation together with our very active year in terms of financing with seven new bonds issued allowed us to finance our ARS64 billion capital expenditure and also resulted in ARS26 billion cash and cash equivalents position as of the end of 2016. In this next slide, the figures are expressed in U.S. dollars and are shown on a unconsolidated basis but what we can see our cash position in green is enough to tell all our debt but for the following year. However, most of these debt maturities are either short-term bank financing or trade finance which we believe we will continue well over without any difficulty. Our leverage ratio is now two times net debt-to-EBITDA and we expect it to stay flat in a medium term as we are targeting for this year to be breakeven in terms of free cash flow. The average interest rate in pesos was slightly over 27% while the average cost of our debt in foreign currency was 7.75%. With this, I will turn it back to Ricardo for final remarks.

[Ricardo Darre:]

Thank you, Daniel. Firstly I'd like to draw your attention to one of the major highlights of YPF during the year 2016 which is to implement on safety performance. YPF measures its safety performance using a number of indicators, the main one being the LTIF, loss time incidence frequency which is the number of loss time incidents per million man-hours worked. This applies to the top of YPF, this is contractors when working at YPF facilities. For 2016, we finished the year 2015 with an LTIF of 0.91 loss time incidents per million man-hours and in 2016 we dropped this LTIF to 0.74. This is the longest LTIF since 2010 and it is very close to the best performance ever for YPF 16 years ago when the LTIF was 0.72. As you probably know in the oil and gas business, safety performance tends to measure operational performance and YPF is no exception to this. In 2016, YPF has achieved several high-performance milestones that are key to our business. On the downstream side, our clear refineries in Plaza Huincul, Lujan de Cuyo and La Plata have reached outstanding levels of 92% of utilization rates and 97.8% of mechanical availability. The levels of fuels produced have reached a number of records including premium diesel at 730,000 cubic meters for the year and are over 2.5 million cubic meters of gasoline produced at La Plata. This number should improve further with the completion of construction work now the late coking unit in La Plata refinery, which will allow for larger production of diesel. On the same side petrochemical facilities have also broken a number of records of production on facilities like Aromatics, Maleic, PIB and something like that. However we are really excited with the improvements in Vaca Muerta. Increased productivity and reduced cost like those obtain this past year should result in raising highly the value of these resources. The recent JV with Shell is a perfect example of this and we expect more companies wanting to join YPF soon in this adventure. We took some action to opportunistically make additions to our asset base and structure holdings and commitments to better align our asset base to our investment priorities and possibilities. We took the decision to reduce nonstrategic activities and execute on this decision. We have taken safety as a top value of YPF and we would make all necessary of force to continue to improve our safety and reliability performance. They are also setting exploration as a priority because it shows the sustainability of our reserve base in the long term. We will be investing approximately $450 million this year in exploration including the pilot project in Vaca Muerta area. Our vision continues to be focused in creating value for our shareholders. To that end our strategy is directed to one, include the efficiency of productivity of operations. We made significant progress this year and we expect to continue this trend in 2017. Two, increase production over the long-term with a focus on our two major plays unconventionals and matured fields. Three, focus on exploration to replace and expand our reserve base. Four, permanently evaluate our asset base to determine opportunities to maximize value through acquisitions and divestures. Five, protect and maximize the value of our land and six maintain a sound capital structure. Having said all this, we believe that in 2017 we will see the slight reduction of around 30% and hit hydrocarbon production, capital expenditure in the area of $4 billion, flat leverage ratio with data of year end 2016 and adjusted EBITDA growth up to 5%. This ends our formal presentation. We will be asking questions now. Thank you.

[Operator:]

[Operator Instructions] Our first question on line comes from Mr. Bruno Montanari from Morgan Stanley. Please go ahead.

[Bruno Montanari:]

Good morning everyone, thanks for taking my questions. First on pricing, I understand it late 2016 was volatile because of the ongoing discussion of oil prices with the refiners and the smaller producers. But based on the new agreement, it seems that the 53 level you report now should be the price for now the beginning of the year, is that correct. And then on fuels is everything on track to implement this new agreement which allows refineries for increased prices on a monthly basis, starting in April. The second question is about exploration expenses, we have seen a sizable increase now in the fourth quarter and I was wondering if this is a new level of expenses, given the profile of the drilling campaign or if we should see these as a one-off and think of the past few quarters as the more sustainable level. And finally, if I may, on the reserve base I understood the comments on the SEC methodology, mentioned in the beginning of the call, but how much reserves are actually booked as one peak coming from unconventional and when would you be in a position to book more reserves of Vaca Muerta on a perspective of these production history as defined by the SEC. Thank you very much.

[Ricardo Darre:]

Good morning, Bruno. Well, let me address your questions. First on the pricing, yes, $53 per barrel as an average between the light crude and heavy crude is what we are still expecting for the first quarter. And that’s actually to the second part of your first question which is nothing has changed in terms of the agreement between producers, refiners, and the government in terms of what prices we will all have for the crude oil local production and how we will affect pricing changes at the fund and that will depend on the evolution of the effects and the evolution of the prices of the biofuels basically. So, no changes at all, and we are still at least a month or approximately a month away from any potential new price increases. Second on exploration expenses. Yes, you should definitely look at the exploration expenses on an annual basis, not on a quarterly basis because a trend to be choppy from one quarter to the next but we don't see any reason to factor in larger exploration expenses for this year as opposed to last year. What we will have year is a significant increase in exploration CapEx more than expense. Okay, when we are up on the pilot projects that we are going to be at taking on to expand our knowledge of Vaca Muerta and the limits for YPF of Vaca Muarta plus the ordinary exploration that we always incur, we are talking about investing in the order of $450 million this year there. And to your third question regarding reserves, we usually don't give cover guidance in terms of composition of our reserve base. But I can tell you that unconventionals defined as a combination of tight and oil should represent approximately 15% of 31, and specifically the shale out of the total represents less than 7%.

[Bruno Montanari:]

Great, thank you very much. And may I just ask you to repeat the very last comment from Ricardo about production in 2017 because I didn't quite understand.

[Ricardo Darre:]

The guidance for production for 2017 is flat to minus 2% production for the year where we see some growth in natural gas production and a decline in crude oil production.

[Operator:]

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

[Luiz Carvalho:]

Hi, Ricardo, hi Daniel. Thank you. I have basically two questions here, which I would think the opportunity that Ricardo is on the call. So to approach more to how going to talk down themes. The first one is related to the JV that you just signed with Shale. And you mentioned during the call that you expect actually to sign your agreements over the next, let's say - in the future. I would like to understand a bit of its strategy of the company during this JVs, if it's share technology, and how quickly do you think that you'll be able to actually to monetize and book reserves from the potential JVs and looking forward. And the second question and might go to Daniel, which I think that, I mean the last time that we met during the Investor Day in Argentina, you mentioned about divestments throughout 2017.

[Ricardo Darre:]

Okay, so this is Ricardo. I will address your first question regarding the strategic partnerships with [indiscernible] in the Vaca Muerta area. We have been seeing for last two years let's say after the great oil play decline at the industry have gone through levels of production of capital expenditure that were enormous and that in the end would impact reserve base of the majors in the industry. So what we're forecasting is that, there would be an interest coming up sometime soon, we do know the date 2017, 2018 from major companies and independent players to fish for reserves and production and different ideas. This has happened - I would say we're seeing materialize that in the very last few weeks if not to say months, probably it was the press, the reduction of reserves declared by Exxon and another majors that had extremely significant. So Vaca Muerta has become magnetic for oil producers and gas producers searching through renew the reserve base and find sources for production. This venture we started with Shell - or we’re going to start which Shell. I think it's just first one of step, the first step on a number of ventures that we thought we will be able to establish in the next few months. The strategy in fact is that Vaca Muerta is so large, requires so much capital that we won't be able to do it alone. We need to find strategic partners that accept to share without the geological risk, and the business risk globally to be able to develop Vaca Muerta in its put potential. Now for the timing on caching as you said of these investment, to the shale place traditionally require sometime for investigate and be a pilot project, pilot a number of limited number of wells three, four wells here three or four wells depending on the size of the permit to actually investigate what is the best way for developing the field and the best way to access the most reserve and production from it. If you want to need to set a guideline on the time planning for development project in the shale I would say that it’s the first step of one or two pilots that might go over one year or 18 months and then eventually second pilot phase depending on the complexity and the extent of the area and then to take the message - the efficient go into massive development I would say you’ll see from the first meter you drill in the shale project to the first oil you can count on for years from first the drill two - first development on.

[Daniel Gonzalez:]

Luiz, the second part of your question regarding divestitures. I think nothing has changed from what we have last discussed which is we have a clear indication from our Board just to review a strategic model - conduct a strategic review of all of our asset base not been intention of selling any assets but just to determine which assets are worthwhile in our hand - other people's hand. We’re not in the process of divesting any assets at all I know there's been some things that went out in the papers a few weeks ago that is not true the only M&A process which we will be launching very soon is in line with what Ricardo mentioned is looking for partners in order to accelerate the growth of our power segment. We have a lot of growth already in the projects that our fully funded we believe that there is additional growth that that we would like to monetize and that to that end we would not like to have to allocate more of our own capital there. So we’re going to be looking for partners there other than that I think that we will be reviewing as I said each of the asset base and that we find that there is any asset which doesn’t make strategic sense or is worth more in the hands of others than our own we might decide to do something but nothing eminently.

[Operator:]

Thank you. Our next question online comes from Frank McGann from Bank of America, Merrill Lynch.

[Frank McGann:]

Just two questions, I could, one is just take a little bit longer-term view in terms of production and your expectation that you won't give specific numbers, surely, but as you look out into 2018, 2019 and 2020 with the potential more aggressive development of some of Vaca Muerta areas, some of the tight gas developments you have what your overall expectation is for production of both crude oil and natural gas and as you go out a little bit in time. And then secondly, just looking at the Downstream business, obviously, we've gone through a long period of distorted prices are managed prices that we're now moving into an environment that should be somewhat more of a truly competitive environment with the expectation that by mid-year prices will essentially be moving in line with international prices with floor at least over the short term for crude oil and then with products, I would assume, tell me what you think will be moving into a fully competitive market at that point were each of the players will define prices and how -- if that's the case and not the case, how do you think about margins as you're looking out in time in terms of refining margins?

[Daniel Gonzalez:]

Hi Frank well our long-term view of hydrocarbon production growth is that we should be position to global action of at least 5% per year on a sustainable basis okay. And we are making all the investments and you know a good part of the investments made in the last year have been to build in the last years I have to say been directed to build a base in order to be a position to grow production along those line. The recent improvement in this case in productivity coming out of the Vaca Muerta wells support a vision that we really believe that we have the resources in order to grow long-term at or around that way that has not changed. What has been changed in the last 12 to 18 months is that we have been investing more towards natural gas and towards crude oil and actually 2016 is going to be the first year in the history of this company which a total CapEx going to gas is got to be higher than that going to crude oil, okay. Now to the second part of your questions or to the second question regarding downstream prices yes we are all targeting to a midyear conversion of prices both for crude oil as for products. There is a fully competitive market in Argentina today in downstream sector that’s a reality there is a guidance in terms of prices that that was agreed between other producers and refiners and the government but there is no regulation at all. So everybody free to establishing prices the way they see fit and actually you can see how our market share evolves from one quarter to the next. And that is the consequence of our really competitive market in the downstream sector in Argentina. We are the largest refiner we have 55% give or take share, but we have at least four refiners with their own network of service stations with their own distribution network and we have the competition from imports also which has actually become more or heavier during the last year. So we do have a fully competitive market but however we do expect to be able to preserve our downstream margins as we have always done the power of the YPF brand continues to be strong asset as always been and we actually don't see any reason when we look forward a few years why our refining margins or cracking margin should come down.

[Frank McGann:]

Thank you very much very helpful.

[Operator:]

Thank you. Our next question online comes from Ricardo Cavanagh from Itau. Please go ahead.

[Ricardo Cavanagh:]

Good morning all and thanks for the call. I would also making a question on growth, it was already raised, but how I see, YPF that it's making huge-progress on multiplicity of France. But yes, there is a limited capacity to augment CapEx as you mentioned beyond cash flow in terms of leverage. So you mentioned the possibility of attaining growth via partnerships and the expectation that this is going to be substantially Vaca Muerta. You also need to struggle with conventional production trends that are tougher now. In order to think about the growth Daniel that you mentioned being 5% per year. Is it too crazy to consider down the road that you might consider raising equity to deploy capital faster at the best projects that you find at Vaca Muerta. And I'm thinking this in a context Argentina will much likely go through emerging market category. And that's going to be huge appetite in my view to Argentina equity.

[Daniel Gonzalez:]

Well thank you Ricardo no we don’t have any plans to issue equity in a short-term clearly not at these stock prices so that is not in the work for now of course in the long-term if there are projects that are warranted we would consider it. But it would require the stock to be valued where we believe it should and I can tell you it’s very far from what is today. That the way that we have decided to raise capital is at our project basis and that is in the upstream sector the far amounts that we have been doing in shale which is where most capital is required it’s similar to what I have just described regarding our intentions to raise the size of our power basis in the future. As - through partnerships are the asset level are not at corporate level equity at the asset level and not at corporate level. Now we believe that this company that has recorded EBITDA of $5.2 billion only a year ago has the ability to go back to cash generating levels in line with those very soon. Therefore that means that we should be having more cash flow available to increase CapEx going forward out of this $4 billion guidance that we are providing today and therefore that CapEx resulting in the growth or production that I have described earlier on. Think that the CapEx in the $5 billion to $6 billion range that we have been making in the last few years included are a lot of infrastructure CapEx that is not necessarily recurring in the future you’ll also included a lot of on the learning curve let’s put it like that in the shale that clearly for the numbers that we have - out of the numbers that we have just laid out for you the investments to require the same production are significantly lower than before. So there is a lot of leverage in terms of what we can do with a dollar especially in the shale from now. Remember again horizontal shale well costing us $13 million a year, a year and a half ago $8 million today, and actually we have another 10% reduction of costs for this year there out of the new conditions for the labor for unconventionals out of new savings with terms of a propane out new savings in terms of the rates that we pay for some of the equipment. So again don't just look at how much we invested in the last previous years and how much growth came out of that investment. I think that that we have built a platform in order to be able to grow with less so I don't believe that we need to raise equity initially in order to get the company growing again at 5% rate. That’s not going to happen in 2017 granted but we have now changed our view that we have the resources and we have the capital necessary to have this company growing at a 5% rate without necessarily raising equity in the short-term.

[Ricardo Cavanagh:]

Okay Daniel, thank you very much.

[Operator:]

Thank you. Our next question online comes from Anish Kapadia from TPH. Please go ahead.

[Anish Kapadia:]

Hi, I had few questions around the tight gas development. Just wondering if we could get a bit more information and an update, especially given that the higher investment you're putting into the gas this year over oil. I was just wondering if you could give an update in terms of what you're seeing in terms of the initial production rates from the wells, the expected ultimate recoveries from each well and also in terms of the outlook how many wells do you expect to drill in the place this year, some update on the production profile you expect where well costs and designs are. And then just kind of finally, how much kind of resource do you see are you in anyway resource constrained in terms of tight gas or in terms of when you compare it to Loma Campana shale. Thank you.

[Daniel Gonzalez:]

Hi Anish as you know we've never provided and not making difference today at EURs or IP for the wells. The only EURs that we've always given is the well type curve for shale business basically for oil shale oil and coming out of one area which is Loma Campana. The tight is not yet diverse okay we have tight out of volume down to Lajas formation which are deep expensive wells and we have tight production going to the Mulichinco formation and the Rincon del Mangrullo and those are lesser deep wells flow wells with a complete different curve right. So I'm not sure that – it's really indicative of the tight potential to provide one EURs and unfortunately we are not breaking down EUR for fields or IPs for that matter. What we can share with you is that we are going to be drilling at least another 100 tight wells this year maybe a slight decrease vis-à-vis the previous year but remember that we are going to be increasing this year the number of shale gas well right. So it's going to be in 2016 more of a combination of shale gas and tight gas well as 2016 an earlier it was more about tight and less about shale. And to the second part of your questions no we haven’t found any constraints or at least constraints that we cannot overcome in terms of continue our development of tight.

[Anish Kapadia:]

And just follow-up can you give some idea of how the economics compare in the different place I suppose which ones kind of most economic and may be why you’re shifting more towards shale gas away from tight gas this year?

[Daniel Gonzalez:]

No economics of the tight work very nicely with current average prices in Argentina of course we will all need to understand that better what is the effect of a new gas plant that has been announced this week but our initial reaction is that this is a step in the right direction it’s a good thing we have visibility towards 2021 in terms of prices so that’s good. So there is no economic reason that cost us diverting from tight to shale okay. Most of the shale gas wells that we are drilling this year have to do with the pilots. We mentioned that we are going to be conducting around 10 new pilot project in the shale most of them are in the gas window in the dry gas window okay. So a lot of that has to do with putting shale gas in value and not necessarily to switch from tight and shale gas. And again just to repeat with the current and expected average price of gas in Argentina and the current is $4.70 and going up all of the tight projects that we are considering for this year are profitable or very profitable okay and that we have not encountered a single tight gas project that we have decided not sanction because of economic reasons.

[Anish Kapadia:]

Thanks very much.

[Operator:]

Thank you. Our next question comes from [Richard Cardoso] from Credit Suisse. Please go ahead.

[Unidentified Analyst:]

Good morning Ricardo, Daniel, Diego, thanks for taking my questions. The first one relates to the share potential YPF holds. YPF has made impressive progress in the horizontal wells in Loma Campana, so my question would be how do you unlock value from other blocks within Vaca Muerta, does the learning curve from Loma Campana translating to similar economic, fix similar economic similar blocks. The second question would be in relation to the new disclosure format, I wanted to know the rationale behind this change, is this because you think that you have some follower segment is not fully perceived the value of gas and power is fully perceived by the market? Thanks.

[Ricardo Darre:]

Yes Richard, this is Ricardo. For your first question the shale potential well, I would say the factoring model that we are putting into place for all that our activity on shale can be linearly extrapolated to or it is beyond Loma Campana, the cost for the wells should remain similar then the number of meters of horizontal drain we drill and the number of frac stages we do on each field it is on the specifics of that field. Those are proven by the pilot equivalency doing now. In fact I don’t see any constraint for the wells on fields other than Loma Campana to have higher drilling cost that what we see in Loma Campana unless there are I don't know some technical or operational leases like they can took in our prejudice having to add more location rather, these are let's say uncertainties we should look by doing the pilot, the whole sense of doing the pilots themselves and I will pass to Daniel for the second question.

[Daniel Gonzalez:]

Richard, you know that we have created this new VP for gas and power exactly one year ago. So 2016 was a first year in which we had this new VP ongoing, we did not open it up as a new business segment in the previous quarters, last year because we are just making definitions or what exactly would be the internal reach of that new VP. So given that we have our organization in place, whereas the accounting rule that prevails is disclosing information in line with the organization that we have in place. So we didn’t have a lot of room to maneuver there. In any event the reason why we created that VP was precisely because we believe that there is plenty of growth and there is plenty of value in having a dedicated view towards commercialization and marketing of natural gas on the one hand and on the other hand as everybody knows there's a need for power in Argentina and as we have proven we want to be part of that - satisfying that need being part of that growth. So we decided to put those things into new VP having that in the very senior or top organization of a Company, it was logical for us to disclose it as a new business segment.

[Unidentified Analyst:]

Very clear. If I may a follow-up there was a recent decision by Energas concerning Metrogas do you have any, do you have any updates regarding this?

[Daniel Gonzalez:]

There haven't been any relevance there, I think what Energas made is just a formal communication to Metrogas and Metrogas just transferred that communication to us. Of course as we said in our filing recently, we are always in compliance and with laws and regulation, so what we hold is because we have the proper authorizations to hold that equity stake but we have also said publicly that when Metrogas has new in place and everything that many other assets that we are going to be reviewing from a strategic perspective, Metrogas is just another asset an important one for us that we can - we will consider eventually if it's worth keeping or not keeping. Okay, but those actually no development at all in terms of the communication that you made reference to and we don't expect any development in short term there.

[Unidentified Analyst:]

All right, very clear. Thank you very much.

[Operator:]

Thank you. Our next question comes on line comes from Pavel Molchanov from Raymond James. Please go ahead.

[Pavel Molchanov:]

Yes, thank you for taking the question. On the 2017 budget you mentioned that will be down slightly year-over-year can you provide any additional detail on the amount of the reduction and where that, what segment in particular that reduction is going to come from?

[Ricardo Darre:]

Sorry Pavel, what reduction are you referring too?

[Pavel Molchanov:]

You stated that the capital program in 2017 will be down - CapEx will be down slightly from last year's level and my question is can you be a little more specific on how much lower the CapEx will be and in what segments the reduction will be visible?

[Daniel Gonzalez:]

Yes, well the CapEx reduction is going to be more visible Pavel is in the downstream sector because of the last couple of years included the investment in the new coking unit in the La Plata refinery so that took approximately $4 million of CapEx out of the last couple of years and we are not going to be having that this year. The upstream will see a very minor reduction in CapEx and increasing exploration on a small reduction in development but not very different to other levels that we experienced this year and where we will have another increases is in gas and power because of the projects that we're already disclosed and that are ongoing. Most of those projects will come on stream this year and next year and therefore most of the CapEx is being invested in 2017 and 2016.

[Pavel Molchanov:]

Okay. And a year ago you specified a target for the shale well costs $10 million and as you mentioned you achieved $8 million in actuality, what is your target for shale costs this year? How much lower will they be?

[Daniel Gonzalez:]

Well, we are not going to get very specific, we would like to over achieve but we believe that we can reduce the CapEx per well around 5% to 10% to what we had last year is an average. So there are further reductions below the $8 million mark that we have already achieved.

[Pavel Molchanov:]

Okay, that’s helpful.

[Ricardo Darre:]

I can compliment to that in fact the large part of the drilling program on shale this year is going to be on pilot, pilots and sales we do a lot of that acquisition which is at a level that you don’t do a development wells like Loma Campana. So the overall cost of the wells that you’ll see in Vaca Muerta it’s a whole might actually increase of it due to the, drilling of pilots which again we do a more extensive that acquisition program. The drilling itself is well maintained cost. Today we are finishing two wells - two pilot wells one on Rincón del Mangrullo and one on in La Ribera and in fact the drilling speed on the cost is very similar to the very last well - development well on Loma Campana its mainly the data acquisition that might bring extra expenses.

[Daniel Gonzalez:]

Yes and one additional saying complimenting Ricardo's comments, a good part of what we’re going to be doing this year is entails going longer in terms of natural. So there is not going to be an exact comparison because the $8 million mark is for wells for1500 meters of laterals. So if we go longer and if we put more frac stages per well, the cost of our well will be higher of course the EURs should also be higher right, but conceptually we believe that 5% to 10% additional savings for the year in the Shell is something achievable.

[Operator:]

Thank you. Our next question on line comes from Anne Milne from Merrill Lynch. Please go ahead.

[Anne Milne:]

Thank you, Ricardo, Daniel and Diego for the call today. So just changing gears a little bit, I believe you mentioned during the call that you expect the free cash flow for 2017 to be about breakeven. Does that mean that you will not be involved in the capital markets or are there still some maturities or other payments or refinancings or activities that you will do, that will be my first question. And then the second question is, do you have a level of what your exports and imports of different products were for 2016 and will that change in 2017? Thank you.

[Ricardo Darre:]

For the first part of your question is yes. There's a big change vis-à-vis the last couple of years in terms of being free cash flow neutral and therefore implying that we are not going to be increasing our net debt. Definitely should result in us being less active in the capital market especially international capital markets. We cannot say that we will access markets at all. We can say that if we decide to access markets, first it's going to be less frequent, and second, it’s it will probably more of the season of extending tenure than having to fund needs or to refinance maturities. What comes too this year in terms of there, it’s mostly shortened there, that’s mostly trade finance which is efficient for us to maintain and actually I'd say easy for us to roll over. So we have made a decisions, you should expect us to be an active player over the long term but not as frequent as an issuer we've been in the past. Regarding the second part of your question, imports and exports have been coming down. One of our main imports is imports of diesel oil. The new coke units will actually increase our capacity to produce additional diesel oil. So the need for imports will come down. At the end of the date, it will depend on economic activity, it will depend on how strong diesel demand is in Argentina. That will determine if we need to increase imports or not but initially we are not anticipating any big increase in imports actually - as I said, the most likely scenario is that we will actually be reducing the imports. In terms of exports, it will depend on prices mostly because of course most of the products that we export are on international prices. We don’t expect any significant increase in the volumes of exported products. If prices go up, then you might see at the end of the day some increase in exports but nothing meaningfully.

[Anne Milne:]

Thanks very much.

[Operator:]

And our last question comes from Frank McGann from Bank of America Merrill Lynch. Please go ahead.

[Frank McGann:]

Yes, thank you again. I'm just, in looking at your supplier negotiations, are just wondering what trends you're seeing in terms of competitiveness amongst suppliers, is there been any increasing activity by suppliers that would lead to a little bit more competition. Are you seeing generally that your prices when you renegotiate, contracts are coming down or they staying the same or what are the general trends?

[Ricardo Darre:]

Frank, it depends on what kind of suppliers you refer to, but for instance, if we are talking about drilling rigs, there is an ideal capacity in Argentina again after having a need or deficit of drilling rig in 2013 through 2015 because we and others have reduced activity. I can tell you that there is more availability of drilling rigs in the country than before. That should translate into more competitive rates. Yes, we believe so. But at the same time, we are not increasing rig count. So we are not necessarily going to be benefitting dramatically out of additional competition there. In terms of rest of the services that we contract, what we have been seeing is a reduction in the rates of the services that we pay. That has to do with the reduction in cost of capital in Argentina. That is one of the drivers that we expect to see continuing in the future in order to continue to reduce the costs for us both at CapEx level as well as on OpEx level. So if your question is, are we feeling the inflation pressure that the industry is starting to see in other parts of the world, no. I think that we still have plenty of room to continue reduce cost. And that reduction cost has to do with doing things differently, has to do with efficiency, and that’s on us. But it also has to do with reducing some of the services that we contract from third parties.

[Frank McGann:]

Thank you very much.

[Operator:]

And we have no further questions at this time. I’d like to turn the call over to our presenters for closing remarks.

[Ricardo Darre:]

Okay, thank you very much for participating in the call.

[Daniel Gonzalez:]

Good morning. Thank you.

[Operator:]

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