YPF SA (YPF) 2016 Q4 法說會逐字稿

Welcome to the YPF full-year 2016 earnings webcast. My name is Richard, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. I will now turn the call over to Mr. Diego Celaa, IR Manager. You may begin.

Great, thank you, Richard. Good morning, ladies and gentlemen. My name Diego Celaa, Head of Investor Relations at YPF. I would like to thank you for joining us in this occasion, we will discuss YPF 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 various forward-looking statements. So, I ask you to carefully review the cautionary statement on slide two. Our agenda today will include a review of the key issues and achievements of the year, a review of our operations, a detailed explanation of our full-year results, an update of our financial situation and finally the conclusion. Also, our financial statement figures are stated in Argentine pesos in accordance with International Financial Reporting Standards, IFRS. In addition, certain financial figures have been adjusted to reflect additional information to let you better understand our key financial/operating results.

Please, Ricardo, go ahead.

Thank you, Diego, and thanks everyone for joining us this morning to review our full-year 2016 results. This past year was a 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 costs.

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%, as the growth in adjusted EBITDA was more than offset by the increase in 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 the previous 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 players in the industry, our proven reserves were negatively affected by lower crude oil and were therefore down by 9%. Overall, prices affected negatively our base of proven reserves in mature fields, taking a drop, concentrated mainly in the province of Santa Cruz. This drop could not be compensated by the activity in Vaca Muerta, since the SCC rules for reserve calculations required consideration of a 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.

If we move to review of operations, let me start this section by focusing briefly on our financial results, expressed in US dollars, since it will allow me to provide you a better understanding of the evolution of the business during 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 fuel 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 33% to $4 billion, as our 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 these effects in more detail in a few minutes.

When we analyze these dollar figures for the last quarter of the year, we see a slightly milder behavior, as the average devaluation was lower than that of 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 a flat hydrocarbon production of 577.4 Kbped. Breakdown between oil and gas, so crude oil production down by 2% to 244.7 Kbped; natural gas production up by almost 1% to 44.6 million cubic meters per day; and natural gas liquids production up by almost 7%, reaching 52.5 Kbped. This growth in NGL offset some of the decline in crude oil production and was the result of a business decision to save some production to be processed for extraction of liquids. Additionally, the production of the year was affected in approximately 1.2 million barrels of oil equivalent, or over 3,000 barrels a day, due to different labor conflicts we suffered that affected our operations. We would like to highlight that the gross production derived from those fields in Argentina, where 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 reserves, YPF is not an exception to the industry and after three straight years of increasing reserves, we have reduced our proved reserves by 9.2% to slightly above 1.1 billion barrels of oil equivalent, with a reserve replacement ratio of only 46%, despite incorporating 98 million barrels of oil equivalent of new reserves, most of it in natural gas. This reduction 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 that should gradually be incorporated into our reserve base and that should allow us to replace and grow reserves on a sustainable basis.

The reserve booking coming from the shale is slow by definition, and still represents only a fraction of our total proved reserves. Reserve additions, on the other side, came from a variety of fields, but mostly in the Neuquina basin, our shale project in Loma Campana and El Orejano, tight developments in Lajas formation, both in Aguada Toledo, Sierra Barrosa and Estacion Fernandez Oro, and also in the Mulichinco formation in Rincon del Mangrullo. We also incorporated some reserve from the acquisition of participation in Rio Neuquen and Aguada de la Arena. Additionally, we also increased reserves in the Golfo San Jorge basin from the expansion of secondary recovery projects.

Now, I would like to provide some highlight on our gas and shale oil activity, as 2016 was a turnaround year for us. We achieved an important [well] production 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 62.3 Kboed in the last quarter. On the top right graph of this slide, we can see the evolution of well cost in Loma Campana, and there are two important take-outs 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. With some additional savings, this year we are already below this number in the first quarter of 2017. And second, we have reached and 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 that what it was two years ago. Our type well curve gives today an expected (inaudible) recover an EUR of [550,000] barrels of liquids, plus gas, and we are seeing even better results in 2017. With this productivity and a new cost trajectory, we calculate a breakeven price with a 13% rate of return, IRR, of less than $40 per barrel.

With this performance in hand, we feel very comfortable in pursuing an expansion of our activity in Vaca Muerta, are 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 contiguous to those already under development, and second, areas where we are moving farther into the dry gas window.

In the case of [Vaca Muerta's El Orejano], 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 a pilot project.

We are also witnessing a substantial increase in the interest from different players to join us in the development of Vaca Muerta, so we're comfortable with our strategy to increase the value of the asset. Significant part of the future of Vaca Muerta relies on the infrastructure for development. As many of the analysts 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, and other shale oil areas; sand washing, drying and classification plant with a capacity to provide the necessary proppant for several years; the control room's [monitoring] and production; the pipelines necessary to provide the water, etc.

On this slide, we wanted to show a chart from a joint study done between YPF and with Mckinsey, comparing the productivity of our Loma Campana wells in 2015 and 2016, shown in red, in comparison with analog wells in the main shale oil plays in the US. Benchmark shows the EUR, expected ultimate recovery, for typical wells, divided by the lateral length of the well. As we can see on the graph, we've 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 this ratio as we move to longer laterals. Clearly, the quality of the rock is second to none and we are proving our ability to successfully develop them.

With regards to our tight gas project, in 2016, we have put in production 41 wells, targeting the Lajas formation in Aguada Toledo, Sierra Barrosa, where we have a 100% share; 28 wells targeting the Mulichinco Formation in Rincon 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 Rincon del Mangrullo, and 2.1 million cubic meters per day in EFO. Today, tight gas represents roughly 22% of our natural gas yearly production. Also, in the near future, we will be showing the production of the Rio Neuquen and Aguada de la Arena blocks, a more recent acquisitions, 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 processed 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 utilization rate of our refining capacity during the year was 92%. For this year and with the incorporation of the new delayed coking unit in La Plata refinery, we expect a higher proportion of higher value products.

Regarding the domestic market, total sales of fuel decreased by 3%, mainly driven by a 4.1% decline in diesel, and an 11.6% decline in crude oil. This decline was basically due to economic activity and a small market share reduction in fuel oil decline with 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 preserving our prices 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 declined, and recovered again towards the end of the year. In term of diesel sales, at the right of the screen, the whole year was soft. We saw some recovery towards the end of the year. Market share for both products saw a little decline against record high levels of 2014 and early 2015. Today, we feel comfortable 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 product, Infinia and Infinia diesel, 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 now 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 Uno, Loma Campana 2, and the first phase of Manantiales Behr wind farm are expected to start up operations in the second half of this year, while for the project in Tucuman, we expect it to be on operations in the first quarter of 2018. All these projects are fully funded. We will consider the cooperation of one or more equity partners to fund additional projects, as we believe there is substantial additional growth and we are not planning to allocate more equity in this segment for the time being.

Finally, despite the many challenges, we were able to deliver in line with guidance. We ended the year with a total CapEx of $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 we're reducing 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 2016.

Now I'll pass over to Daniel for the financials.

Thank you Ricardo. Now, I'll go through the analysis of the annual results denominated in pesos, as we always do. Revenues in Argentine pesos increased by almost 35%, adjusted EBITDA was up by 22% and operating income before impairment charges decreased by 44%. We will get in more detail in the following slides about the reasons behind these changes.

Operating income before impairment charges went from a positive of ARS16.6 billion in 2015, to a negative of ARS24.2 billion, heavily impacted by the ARS35 billion 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% decrease 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 volumes 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 increase in natural gas sales in the retail segment that comes from our subsidiary, Metrogas, due to a 60% increase in prices, and an 11% increase in volumes. And finally, we had ARS2.6 billion increase in fuel oil sold in the local market on 54% higher prices in pesos, as most of our fuel oil is sold locally on dollar based prices. And an 11.6% reduction in volumes, as Ricardo explained earlier.

Cost of sales, other than depreciation, increased ARS24.8 billion. The only cash cost component which is fully dollarized are the royalties, 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 by 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 ARS17 billion, fueled by the 60% currency devaluation and the capital expenditures, which have been made in previous 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 prices 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 a 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 a charge of ARS2.5 billion in 2015. The impairment charges of the third quarter of 2016 have been ARS36.2 billion. So in the fourth quarter, we actually recorded a recovery, a gain of ARS1.2 billion. The rationale for the 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 gas generating unit, as all the rest of our asset base, including the gas generating units and the 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 39%, also, with stable volumes, which were all transferred to our Downstream business segment and there was a slight reduction of 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 US dollars, and also a slight decrease in volumes. It is worth mentioning that during 2015, we had accrued ARS2 billion of revenues derived from the $3 a barrel incentive in effect at that time, 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 ARS15 billion as explained before. Second, ARS8.4 billion increase in items related to lifting costs, which are included in the graph under the production costs. Third, ARS5.2 billion on higher royalties, because of higher 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 billion, which was 55% below the operating profit of the previous year. Revenues were up by almost ARS38 billion or 30%. That ARS38 billion increase in revenues was already 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 [fair] 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 biodiesel and bioethanol, of 76% and 46%, respectively. Bioethanol volumes, on the other hand, increased by 11%, due to increase in the blend. And biodiesel volumes showed a very slight increase of 1.4%, although there was no change in blend at all. 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 have had a negative ruling and we are in the process of 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 ARS49 billion, which was a decrease of 1.5%. Our PBT was mainly focused in drilling and workover, which represented almost 70% of the Upstream CapEx, followed by buildup of facilities with 19% share of the total and exploration and other activities representing slightly over 10% of total Upstream CapEx.

During the year, we put in production a total of 642 new wells, 184 of which were targeting non-conventional formations. Most meaningful investments in the upstream have taken place in the Neuquina basin, most specifically in the blocks Loma Campana, Aguada Toledo, Rincon del Mangrullo, El Orejano, La Amarga Chica and Chachahuen; and then in 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 5 for natural gas. In terms of the rig count, we ended the year with a total of 44 active drilling rigs, after reducing a total of 18 rigs during the year. In Downstream, CapEx was slightly below ARS10 billion, highlighting the finalization and the startup 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 programs and we collected those in the form of sovereign bonds, denominated in dollars for a total of ARS9.9 billion or $642 million. These were the amounts due from 2015. And we have decided to keep in treasury these bonds, as we believe it constitutes a good dollar-based investment.

We also collected close to ARS2 billion during the year of the crude subsidy, which will also owed to the 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 than the previous year. This is one of the most important highlights of the year, in my opinion.

The previously discussed cash flow generation, together with a 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 a ARS26 billion cash and cash equivalent position as of the end of 2016.

In this next slide, the figures are expressed in US dollars and are shown on an unconsolidated basis. But what we can see, our cash position in green is enough to [cater] all of our debt maturities 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 roll over without any difficulties.

Our leverage ratio is now two times net debt to EBITDA and we expect it to stay flat in the 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.

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 the improvement on safety performance. YPF measures its safety performance using a number of indicators, the main one being the LTIF, Lost Time Incident Frequency, which is the number of lost-time incidents per million man-hours worked. This applies to the staff of YPF, plus its contractors when working at YPF facilities.

For 2016, we finished the year 2015 with an LTIF of 0.91 lost-time incidents of a million man hours, and in 2016 we dropped this LTIF to 0.74. This is the lowest LTIF since 2010 and is very close to the best performance ever of YPF 16 years ago, when the LTIF was of 0.72. As you probably know, in the oil and gas business, safety performance tends to mirror 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 three refineries in Plaza Huincul, Lujan de Cuyo and La Plata have reached outstanding levels of 92% of utilization rate 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 over 2.5 million cubic meters of gasoline produced at La Plata. This number should improve further with the completion of construction work in our delayed coker 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 specialties like aromatics, maleics, PIB and surfactants. However, we are really excited with the improvements in Vaca Muerta. Increased productivity and reduced cost, like those obtained 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 actions to opportunistically make additions to our asset base and restructure holdings and commitments to better align our asset base to our investment priorities and possibilities.

We took the decision to reduce non-strategic activities and executed on this decision. We have taken safety as the top value of YPF and we will make all necessary efforts to continue to improve our safety and reliability performance. We are also setting exploration as a priority, because it assures the sustainability of our reserve base in the long term. We will be investing approximately $450 million this year in exploration, including the pilot projects in Vaca Muerta that were presented earlier.

Our vision continues to be focused in creating value for our shareholders. To that end, our strategy is directed to; one, increase the efficiency and productivity of our operations. We made significant progress this year and we expect to continue this trend in 2017. Two, increase production over the long term, with the focus on our two major plays, unconventionals and mature fields. Three, focus on exploration to replace and expand our reserve base. Fourth, permanently evaluate our asset base to determine opportunities to maximize value through acquisitions and divestitures. Five, protect and maximize the value of our brand. And six, maintain a sound capital structure.

Having said all this, we believe that in 2017 we will see a slight reduction of around 10% in hydrocarbon production, capital expenditure in the area of $4 billion, a flat leverage ratio with that of year end 2016 and adjusted EBITDA growth up to 5%.

So this ends our formal presentation. We will be answering questions now. Thank you.

(Operator Instructions) Bruno Montanari, Morgan Stanley.

First on pricing. I understand that 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 the beginning of the year. Is that correct?

And then on fuels, is everything on track to implement this new agreement which allows refiners to increase 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 this 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 SCC methodology mentioned on the beginning of the call, but how much reserves are actually booked as 1P coming from unconventional and when would you be in a position to book more reserves of Vaca Muerta on a perspective of this production history as defined by the SCC? Thank you very much.

Well, let me address your questions. First on 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 takes me 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 crude oil local production and how we will effect pricing changes at the pump and that will depend on the evolution of the FX and the evolution of the prices on the biofuels, basically. So, no changes at all, and we're 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 they tend 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 this year is a significant increase in exploration CapEx, more than expenses. Okay? When we add up all the pilot projects that we are going to be taking on to expand our knowledge of Vaca Muerta the limits for YPF of Vaca Muerta, 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 a lot of guidance in terms of the composition of our reserve base, but I can tell you that unconventionals are defined as a combination of tight and oil should represent approximately 15% of our total P1, and specifically the shale out of the total represents less than 7%.

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

Yes. 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 the crude oil production.

Luiz Carvalho, UBS.

I have basically two questions here, which I think I would take the opportunity, as Ricardo is on the call. So to approach more to -- I'm going to say, top-down themes. The first one is related to the JV that you're just signing with Shell. And you mentioned during the call that you expect actually to sign new agreements over the next -- I'd say, couple -- in the future. I would like to understand a bit of the strategy of the Company during this JV, is if it's a shared 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, it 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 (technical difficulty)l.

So this is Ricardo, I will address your first question regarding the strategic partnerships we are searching for in the Vaca Muerta area. We have been seeing for last two years, let's say, after the grade oil price declined that the industry have gone through levels of production of capital expenditure that were enormous. And that in the end would impact the reserve base of the majors in the industry. So, we are forecasting that there would be an interest coming up sometime soon within our date, 2017, 2018 from major companies and independent players to fish for reserves and production in different areas. This has happened, I would say -- or we have seen materialized in the very last few weeks, if not to say months. You have probably read in the press the reduction of reserves declared by Exxon and another majors that are extremely significant. So, Vaca Muerta has become magnetic for oil producers and gas producers searching to renew their reserve base and find sources for production.

This venture we started with Shell, or we are going to start with Shell, I think is just first one of -- the first step on a number of ventures that we trust 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 with us the geological risk and the business risk globally to be able to develop Vaca Muerta in its full potential.

Now, for the timing on cashing, as you said, of these investments, the shale plays traditionally require some time for investigate via pilot projects, pilot a number of -- limited number of wells, three, four wells [a year] or three, 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 extract the most reserves and production from it. If you want me to set a guideline on a time planning for development project in the shale, I would say that it's the first step of one or two pilots that may go over one year or 18 months and then eventually a second pilot phase, depending on the complexity and the extent of the area. And then take the decision to go into massive development, I would say you will see from the first meter you drill in a shale project to the first oil you can count on four years, from first meter drilled to first development oil.

Luiz, the second part of your question regarding divestures, I think nothing has changed from what we have last discussed, which is we have a clear indication from our Board, just to review our strategic -- or to conduct a strategic review of all of our asset base, not with the intention of selling any assets, but just to determine which assets are worth more in our hands and other people's hands. We are not in the process of divesting any asset at all. I know there have been some things that went out on the papers a few weeks ago, that is not true. The only M&A process, which we will be launching very soon is, and 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 are fully funded. We believe that there is additional growth that we would like to monetize, and to that end, we would not like to have to allocate more of our own capital there. So we are 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 if 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 imminently.

Frank McGann, Bank of America Merrill Lynch.

Just two questions, if I could. One is just taking a little bit longer-term view in terms of production and your expectation -- I know you won't give specific numbers, surely, but as you look out into 2018, 2019 and 2020 with the potential of more aggressive development of some of the Vaca Muerta areas, some of the tight gas you obviously have, what your overall expectation is for production of both crude oil and natural gas 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 or 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 a floor at least over the short term for crude oil. And then with products, I would assume, tell me what you think, we will be moving into a fully competitive market at that point, where each of the players will define prices and 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?

Hi Frank, it's Daniel. Well, our long-term view of hydrocarbon production growth is that we should be in a position to grow production of at least 5% per year on a sustainable basis. And we are making all the investments. and as you know, a good part of the investments made in the last year have been to build up -- the last years, I have to say, have been directed to build a base in order to be in a position to grow production along those lines.

The recent improvements, in this case in productivity, coming out of the Vaca Muerta wells support our vision that we really believe that we have the resources in order to grow long-term at or around that rate, that has not changed. What has been changing in the last 12 months, 18 months is that we've been investing more towards natural gas and towards crude oil and actually 2016 is going to be the first year in history of this Company, in which the total CapEx going to gas is going to be higher than that going to crude oil.

Now, to the second part of your question, so your second question regarding downstream prices is, we are all targeting to maybe a convergence of prices for crude oil for our products. There is a fully competitive market in Argentina today in the downstream sector, that's a reality. There is guidance in terms of prices that was agreed between all the producers and refiners and the government, but there is no regulation at all. So everybody is 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 a 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 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 as it has always been and we actually don't see any reason when we look forward a few years, why our refining margins or our cracking margin should come down.

Ricardo Cavanagh, Itau.

I want also making a question on growth, it was already raised, but how I see YPF that it's making huge progress on multiplicity of fronts. 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, no? In order to think about the growth, Daniel, that you mentioned as 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 where Argentina will much likely go to emerging market category. And there's going to be huge appetite, in my view, to buy Argentine equity.

No, we don't have any plans to issue equity in the short-term, clearly not at these stock prices. So that is not in the works for now. Of course, in the long term, if there are projects that warrant it, 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 where it is today. The way that we have decided to raise capital is on a project basis, and that is in the Upstream sector, the farm-outs that we have been doing in the 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 business in the future, is through partnerships at the asset level and not a corporate level -- equity at the asset level and not a 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 of production that I have described early on. I think that the CapEx in the $5 million to $6 million range that we have been making the last few years included a lot of infrastructure CapEx that is not necessarily regarding the future, it also included a lot of the learning curve, let's put like that, in the shale that clearly 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 of CapEx, especially in the shale from now on. 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, in terms of the proppant out of 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 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 on a 5% rate. That's not going to happen in 2017, granted, but we have not 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.

Anish Kapadia, TPH .

I had a few questions around the tight gas development. Just wondering if we could get a bit more information and an update, especially given 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 play 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 the Vaca Muerta shale? Thank you.

As you know, we've never provided and we're not making difference today, EURs or IPs for the wells. The only EURs that we've always given is the well type curve for the shale. But basically for oil -- for shale oil and coming out of one area, which is Loma Campana, the tight is very diverse. Okay. We have tight out of -- going down to Lajas formation, which are deep expensive wells and we have tight production going to the Mulichinco Formation in Rincon del Mangrullo, and those are less deep wells (technical difficulty) wells with a completely 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-a-vis the previous year, but remember that we are going to be increasing this year the number of shale gas wells. So it's going to be, in 2016, more of a combination of shale gas and tight gas, whereas in 2016 and earlier, it was more about tight and less about shale.

And to the second part of your question, no, we haven't found any constraints, or at least constraints that we cannot overcome in terms of continue our development of the tight.

Just a follow-up. Can you give some idea of how the economics compare in the different plays, as well as which one is kind of the most economic and maybe why you're shifting more towards shale gas away from tight gas this year?

No, the economics of the tight work very, very nicely with current average prices in Argentina. Of course, we will all need to understand 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 is a good thing. We have visibility towards 2021 in terms of prices, so that's good. So there is no economic reason that has caused us diverting from tight to shale. Most of the shale gas wells that we are going to be drilling this year have to do with the pilots. We mentioned that we are going to be conducting around 10 new pilot projects in shale. Most of them are in the gas window -- the dry gas window. So a lot of that has to do with booting the shale gas in value and not necessarily to switch from tight to 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 very profitable and we have not encountered a single tight gas project that we have decided not to sanction, because of economic reasons.

[Richard Cardoso], Credit Suisse.

The first one relates to the shale 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 translate into similar economics in other 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 the Gas and Power segment is not fully perceived -- the failure of Gas and Power is not purely perceived by the market? Thanks.

This is Ricardo. For your first question, how to unlock the shale potential, well, I would say the factory model that we are putting into place for our activity in shale can be linearly extrapolated to oil fields beyond Loma Campana. The cost for the wells should remain similar, the number of meters of horizontals drains we drill, and the number of frac stages we do on each field depends on the specifics of that field. Those are driven by the pilots that we're currently doing now. In fact, I don't see any constraint for the wells on fields other than Loma Campana to have higher drilling cost than what we see in Loma Campana, unless there are -- I don't know -- some technical or operational issues like (inaudible) pressurized, having to add one more casing, whatever. These are, let's say, uncertainties we should lift by doing the pilots, is the whole sense of doing the pilots themselves.

And I'll pass to Daniel for the second question.

Richard, you know that we have created this new VP for Gas and Power exactly one year ago. So, 2016 was the 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 were just making a definition on what exactly would be the internal reach of that new VP. So given that we have the organization in place, the accounting rule that prevails is disclosing the 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's plenty of growth and there's plenty of value in having a dedicated view towards commercialization, the marketing of natural gas, on the one hand, and on the other hand, as everybody knows, there's a need for new power in Argentina. And as we have proven, we want to be part of that -- of satisfying that need, being part of that growth. So we decided to put those things into a new VP. Having that in the very senior, or top organization of the Company, it was logical for us to disclose it as a new business segment.

If I may, a follow-up, there was a recent decision by ENARGAS concerning Metrogas. Do you have any updates regarding this?

There haven't been any developments there. I think what ENARGAS 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 with laws and regulations. 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 tariffs in place and everything that as 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 will consider eventually if it's worth keeping or not keeping, but there is actually no development at all in terms of the communication that you made reference to, and we don't expect any development in the short term there.

Pavel Molchanov, Raymond James.

On the 2017 budget, you mentioned that it will be down slightly year-over-year. Can you provide any additional detail on the amount of the reduction and what segments in particular that reduction is going to come from?

Sorry, Pavel, what reduction are you referring to?

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

Well, the CapEx is actually going to be more visible, Pavel, is in the Downstream, sector because the last couple of years included the investment in the new coking unit in the La Plata refinery. So that took approximately a full $1 billion of CapEx out of the last couple of years and we are not going to be having that this year. The Upstream, we'll see a very minor reduction in CapEx, an increase in exploration and a small reduction in development, but not very different to the levels that we experienced this year. And where we will have another increase is in Gas and Power, because of the projects that were already disclosed and that are ongoing. Most of those projects will come on stream this year, next year, and therefore, most of the CapEx is being invested in 2017 and 2016.

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?

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% what we had last year as an average. So there're further reductions below $8 million mark that we have already achieved.

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

And one additional thing, complementing Ricardo's comments, a good part of what we're going to be doing this year if -- entails going longer in terms of lateral. So there is not going to be an exact comparison, because the $8 million market for wells for 1,500 meters of laterals. 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 shale is something achievable.

Anne Milne, Merrill Lynch.

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?

For the first part of your question is, yes, there is a big change vis-a-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 (technical difficulty) markets at all. We can say that if we decide to access markets, first it's going to be less frequent, and second, it will probably be more of decision of extending tenures than having to fund needs or to refinance maturities. What comes due this year in terms of debt, is mostly short-term debt, is mostly trade financed, which is efficient for us to maintain and actually I'd say, easy for us to roll over. So we haven't made any decisions. You should expect us to be an active player over the long term, but not as a frequent as an issuer as 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 unit would actually increase our capacity to produce additional diesel oil, so the need for imports will come down. At the end of the day, 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 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.

Frank McGann, Bank of America Merrill Lynch.

Just in looking at your supplier negotiations, I was just wondering what trends you're seeing in terms of competitiveness amongst suppliers, has 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 are they staying the same, or what are the general trends?

Frank, it depends on what kind of suppliers you refer to. But, for instance, if we are talking about drilling rigs, there is spare capacity, idle capacity, in Argentina again, okay, after having a need or deficit of drilling rigs 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 the rig count. So we are not necessarily going to be benefiting dramatically out of additional competition there.

In terms of the 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, and 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 a CapEx level, as well as an 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 to reduce costs and that reduction in cost has to do with doing the things differently, it 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.

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

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

Good morning. Thank you.

Thank you, ladies and gentlemen. This concludes today's webcast. Thank you for participating. You may now disconnect.