YPF SA (YPF) 2017 Q4 法說會逐字稿

Welcome to the Fourth Quarter 2017 YPF Sociedad Anónima Earnings Conference Call.

My name is Sophia, and I'll be your operator for today's call.

(Operator Instructions) I will now turn the call over to Diego Cela.

Mr. Cela, you may begin.

Thank you, Sophia.

Good morning, ladies and gentlemen.

My name is Diego Cela, Head of Investor Relations at YPF.

I would like to thank you for joining us, at this occasion we will discuss YPF 2017 full results.

We will be making forward-looking statements, so I ask you to carefully review a cautionary statement on Slide 2. In addition, our financial statement figures are stated in Argentine pesos and in accordance with International Financial Reporting Standards, IFRS.

However, certain financial figures have been adjusted to reflect additional information to let you better understand our key financial and operating results.

I will be providing an overview of the year end and quarter results, then our CFO, Daniel Gonzalez, will be explaining in more details those results, and finally, the Chairman of our Board of Directors, Miguel Gutierrez, will share his conclusions for the year and perspective for the year ahead, before we start taking questions.

As you are all aware, 2017 was a special year for the industry in Argentina.

After a decade and a half of local crude oil prices being dissociated from international prices in the last quarter of the year, local prices finally converged with international benchmarks.

In line with this, local fuel prices are now aligned with import parity, and we are now in a free market for determining fuel prices.

Consequently, our upstream business continued to adapt to this new reality, and we are now at a level of activity which is sustainable in a low crude price environment and can be grown in line with our business plan.

The results for the year showed that YPF performed well in this new scenario.

Revenues of ARS 253 billion were up by 20% in the year and adjusted EBITDA reached ARS 67 billion, which represented a 15% increase when compared with full year 2016.

This, together with the onetime gain derived from the reduction of the corporate tax rate in Argentina, and another partial reversal of impairment charge that had been originally recorded in 2016, resulted in a net income of ARS 12.7 billion in fiscal year 2017.

We will later explain in more detail these 2 effects.

Operating cash flow was up by 21.8%, reaching ARS 72 billion.

This number is well above the capital expenditures of the year, and therefore, allow the company to finalize the year with a leverage ratio inside the 2x area.

Total hydrocarbon production in 2017 was down by 3.9% with 555,000 barrels oil equivalent per day, which was somehow, below our expectations.

On the other hand, demand for our product was strong in the year, with an increase in the volume of gasoline sold almost 7% and a slight reduction in diesel sales of less than 1 percentage point, driven by lower sales to power generation companies.

The fourth quarter was especially strong as revenues increased 12.2%, reaching ARS 4 billion, and EBITDA was up 5.7%, reaching ARS 956 million.

Total production was down 5.3%, reaching a total of 543.6 thousand BOE per day with a 3.8% reduction in crude oil, and a 5% in natural gas.

Demand was strong in the quarter, with an increase in diesel sales volumes of 3.6% and 8.8% increase in gas.

With this, I will ask Daniel to continue with the presentation.

Thank you, Diego, and good morning, everybody.

Let me start this section by focusing briefly on our financial results for the full year, expressed in U.S. dollars.

Revenues in dollars increased 7% in the year, as average gasoline and diesel prices were higher in dollar terms by 6% and 3%, respectively.

Export prices were also up, in line with the recovery of international prices, and the price for natural gas was also up, in average, 3.7%.

In addition, demand was strong in the year, and therefore, we benefited from an increasing volumes sold for most of our products, especially those with higher value-added.

Cash costs expressed in U.S. dollars increased by approximately 8.7%, but heavily impacted by an increase in purchases.

Lifting cost, on the other hand, increased only 2% in dollars in absolute terms, although, it was 6.7% up on a BOE basis due to the reduction in total production.

Royalties, which is the only cost component fully denominated in dollars, were down close to 9% as domestic crude oil prices and production declined more than the growth in natural gas sales.

The reason for the increase in purchases had to do with higher crude oil purchases, up 30% in dollars as our own production was down while we processed in our refineries similar levels of crude than the previous year.

EBITDA was then up by 2.3% in dollars, and it's worth highlighting here that 2016 EBITDA included some onetime gains, which makes the comparison a little bit unfair.

Again, we will be explaining those effects later through the presentation.

Finally, higher depreciation expense contributed to the 6.4% reduction in operating income before impairment charges.

During the last quarter of the year, we had a better performance in terms of revenues and EBITDA, up 12% and 6%, respectively, in dollar terms, reflecting a solid demand for refined products at higher prices.

On the other hand, operating income was wiped out by the increase in depreciation rate of our Upstream assets due to the decrease in reserves that we will be explaining later.

In terms of production, in the Upstream segment, we ended the year with a total hydrocarbon production of 555,000 barrels of oil equivalent per day, representing 3.9% lower production than the previous year.

This was below our expectations, especially in the crude oil side, as we had provided a revised guidance of minus 3.5%.

Crude oil production in 2017 decreased by more than 7% to 227,000 barrels of oil per day.

As explained in previous quarters, part of the decline was already expected and reflects the reduction in activity that had started in 2016 and the natural decline of our mature fields.

But the balance was mostly a consequence of the heavy rains and snowstorms that had affected the south of the country in the second quarter and other factors affecting production like labor conflicts.

Natural gas productions showed a decrease of 1.1%.

We produced 44.1 million cubic meters per day, while natural gas liquids production decreased by 4%, producing 50,000 barrels per day.

Mild weather during the late spring resulted in a reduction of gas demand that forced us to cut production during a few days, and that is the only reason behind the 1.1% decrease in natural gas production.

Production stabilized through the end of the year and the first months of 2018, and although we still expect a small decrease in production this year.

Moving on to reserves.

This year shows a 16.5% reduction in proved reserves, reaching a total of 929 million barrels of oil equivalent and a replacement ratio of only 9%.

The reduction in reserves was mainly due to the reduction in domestic crude oil prices as a result of the process of converging local prices to international prices.

It is counter-intuitive as 2017 was a year of increase in international oil prices, while in Argentina, these were down.

Fortunately, these inconsistencies are behind us, and in a few slides, I will show a graph to further illustrate this.

The performance of our fields, which is one of the most relevant aspects to certify reserves, was positive, which is evidenced by the incorporation of 112 million barrels of oil equivalent due to the drilling and enhanced recovery activities carried out during the year.

Let me try to put this discussion of our reserves in perspective.

As the graph shows, during the last 10 years, our P1 reserves fluctuated around the 1 billion barrel mark.

We had years above such level when prices were higher or concessions had been extended, and years in which these were lower, based on the same factors.

We all know that the bulk of our reserve growth will come from the shale and we have resources of 5 billion barrels only in Vaca Muerta.

This is 5x our total reserves coming only from Vaca Muerta.

However, the strict rules that apply to book unconventional reserves under SEC rules with such a short history of production prevents us from certifying those Vaca Muerta resources.

With more history in production and additional new activity, which will derisk new areas, we should be able to transform those resources and reserves.

Therefore, our target of increasing reserves by 50% in 5 years is not affected by the fact that lower local crude oil prices has forced us to cut reserves this year.

Now let me provide an update on our shale and -- shale gas and shale oil activity.

Net shale production of the year reached 42,100 BOEs per day, and gross operated production was 81,300 BOEs per day.

In terms of our activity as an operator, in 2017, we connected a total of 64 new wells, taking the total to 607 shale wells in production.

In relation to the well cost, as we mentioned in our last conference call, during 2017, we started to test longer lateral wells, so the cost per well does not help to understand the cost improvement trend.

As you can see in the chart at the top right part of the slide, we are measuring the well cost in terms of dollars per lateral foot.

Having said that, in 2017, our well cost in Loma Campana was reduced to $1,600 per lateral foot, which represents a decline of 28% compared to the previous year.

Even more promising during the fourth quarter of 2017, the well cost was reduced even more to reach $1,400 per lateral foot, proving that our efforts extending the well lengths and improving operational performance are paying off.

Finally, as a result of a shift to longer laterals wells, in the last chart of the page we see that the increase in the average length in the fourth quarter is 1,900 meters with 21 frac stages per well in average.

In addition to what we have just described, we have some other positive news that we want to share with you regarding Vaca Muerta.

In Loma Campana, our main development in Vaca Muerta, we have successfully finished the drilling of the first 3,200 meter long lateral well, which we are expecting to complete this well soon and has proved very efficient drilling with less than 40 days of total drilling.

In El Orejano, the shale gas development we have jointly with Dow, we continue to see the development cost below $1 per million BTU.

Another very good news that we recently have is that, in February, 2018, we reached an all-time production record in El Orejano of 5 million cubic meters a day.

It is important to highlight that this level of production was reached in an area of less than 10,000 acres, whereas YPF has a total acreage of close to 5.5 million acres, reaffirming the potential in Vaca Muerta is actually huge.

In the case of La Amarga Chica, we have recently announced that Petronas confirmed their intention to enter the last phase of the pilot, which is expected to be finalized in the second half of this year, where it should be reasonable to expect that we move jointly to full development.

We have also announced that we closed the $300 million JV with Statoil in order to develop Bajo del Toro area.

By the way, this is an area which we acquired from EOG a couple of years ago for virtually nothing.

We have put this map in a presentation to show all the different Vaca Muerta activity that we are doing.

In green, the only 2 projects under full development, which are Vaca Muerta and El Orejano.

In light blue -- sorry, Loma Campana and El Orejano.

In light blue, the 5 pilots which are ongoing, including the partnerships with Shell, Petronas and Schlumberger.

And in dark blue, the 5 new pilots that we are launching this year, including the partnership with Statoil.

Not marked on this map are several other Vaca Muerta projects, where we have a minority stake, and it's actually 8 or 9 additional projects to these 12 that I have highlighted between development and pilots, like, (inaudible) for instance, where Total operates or La Calera, where Pluspetrol is the operator.

And a good number of these pilots are in the gas window at the west of Vaca Muerta.

During this year, we're expecting to drill more than 100 wells in Vaca Muerta in 12 different areas.

Two years ago, all the activity was concentrated in just 3 areas.

Now let me move on to the Downstream business segment.

In 2017, crude oil processed in our 3 refineries was 293,000 barrels per day, essentially flat compared with the previous year.

Regarding the domestic market, although total volumes decreased by 0.5%, this was only a consequence of the 50% reduction in fuel oil sales, because volumes sold of gasoline showed an increase of almost 7% and diesel showed a slight reduction in comparison with the previous year, while asphalt also showed a remarkable increase of 104%.

The rest of the products, including oil petrochemicals, were also very strong during the year.

On this slide, we can see on the left-hand side how gasoline sales evolved every month compared with the previous 2 years, and on the right-hand side, the same for diesel oil.

Gasoline demand was consistently strong all year long, while diesel oil started soft and recovered in the second half of the year.

With respect to diesel, we should differentiate the demand from power generators from the rest of the market because CAMMESA had more availability of natural gas, and therefore, demanded less diesel.

Demand for the rest of the diesel market was actually up 3.7% during this year.

Market share for both products continued to be strong and slightly above that of 2016, at 55% in gasoline and 56.7% in diesel.

Market share for our premium products, Infinia and Infinia Diesel, was actually higher at 61% and 58%, respectively, as they continue to grow at much higher rates than the regular products.

With regards to our gas and power business, the highlight is the recently announced agreement with General Electric to capitalize YPF Energía Eléctrica, our power generation subsidiary, in order to fund the future growth of this company.

YPF would get diluted to 75% and GE will be acquiring a 25% participation in that business for a total cash contribution of $275 million, plus a contingent payment of $35 million.

We are also in advanced negotiations with a third party to subscribe an additional 24.5% of YPF Energía Eléctrica under similar terms.

In the Investor Day we held last year in New York, we mentioned that YPF has a lot of unlocked value and part of this value is what is within some of our businesses that we think is not reflected in the price of our stock.

With this transaction, now we do have a market reference with an implied value for our power generation business in the $1.2 billion area, of which we own 75% and might finalize owning 50% if the third investor comes in.

Now we would like to talk about prices.

Let us start over on this slide with crude oil prices and fuels.

The key message here is that local prices are aligned with international prices, both in crude oil as well as in fuels.

On the left side of the page, we can see, for gasoline at the top, and for diesel at the bottom, how our prices compared with import parity.

The solid lines show our prices with the different increases, effective since prices were fully liberalized on September 30, and the dotted lines show the daily evolution of import parities with, of course, the volatility provided by Brent prices and the local FX in the last few months.

This proves that our prices are very aligned with the international references and we have seen and we'll continue to see short-term periods in which our prices are slightly higher or slightly lower than those references.

Our pricing policy also takes in consideration other market dynamics as we operate in a competitive environment.

We currently have the prices that we need to have, as all the catch up is now over.

And this catch up was done in the last couple of months with demand growing at very strong pace, therefore, without any negative impact from the market.

We have also included, in the upper right side of the page, a pie chart that breaks down prices at the pump and shows how relevant taxes are in the composition of pump prices.

A posted recent development has to do with one of these taxes, which represents 20% to 25% of the pump price.

And that has been changed from a percentage basis to a fixed peso number that will be adjusted on a quarterly basis by inflation, and that the government can increase or reduce by approximately 10% to act as a buffer of final prices.

The last graph of the page shows the gap between local crude oil prices, which are the green and purple lines, vis-à-vis, Brent.

It is important to understand where we're coming from as the local oil industry experienced low oil prices in Argentina for many years, and gave back a portion of that in the last couple of years as it adapted to a lower crude oil price environment.

Now prices are freely negotiated between refiners and producers with reference to import and export parities and without any export or import duties.

We believe this slide is important to understand a significant breaking point from the contradictions of the previous decade -- or decade and a half actually and will provide investors with the opportunity to compare YPF with any other Upstream and Downstream player in other parts of the world.

In this next slide, we'll continue discussion of prices, but with natural gas.

The good news here is that we are expecting to have, in 2018, almost the same average realization price than 2017, in the order of $4.9 per million BTU, as you can see that at the right side of the page.

But a much higher portion of our realization price will come from the market and less in the form of subsidies.

This is shown in the chart, also, on the right of the page, where you can see that, in 2017, close to 2/3 of the price was coming from the market, and in 2018, we are expecting that percentage to be around 90%.

On the other chart, on the left side, we are explaining the reason for the increase of the market price, the segment that will bear the increase is a residential, that is coming from a very low base.

Gas starts will increase in April and October, and we are not seeing the pushback that we experienced in 2016.

In addition, the government is focusing the reduced subsidies in those residential clients that might find it difficult to cope with such increases.

Industrial clients and power producers are already paying prices in the $4 to $5 per million BTU range.

We continue to see a wellhead price in the $5 to $6 per million BTU as a market clearing price over the long term.

However, we should note that the last LNG cargoes have arrived at prices closer to $7 per million BTU, before regasification costs.

Now I'll go through the analysis of the annual results denominated in pesos, as we always do.

Revenues in Argentine pesos increased by 20%, adjusted EBITDA was up by 14.7% and operating income before impairment charges report an increase of 3.2%.

Operating income went from a negative of ARS 24.2 billion in 2016, heavily impacted by the ARS 35 billion net impairment charge registered in the third quarter of that year, to a positive of ARS 16.1 billion in 2017, which was also impacted by the partial reversal of that impairment charge for an amount of ARS 5 billion this year.

Excluding those effects, operating income, in 2017, came up by 3.2%, reaching ARS 11 billion.

This increase was mainly driven by the strong operating results obtained in our Downstream business segment, which showed an increase of ARS 12.7 billion, vis-à-vis, a year ago on higher fuel prices and strong gasoline demand, as explained before.

The Gas and Power segment also showed better results due to better tariffs in our subsidiary Metrogas and also an increase of 75% in the Power Generation business.

Now on the other hand, the Upstream segment results before the impairment charge and reversal, showed a decrease of ARS 9.3 billion.

This was mainly driven by the combination of lower production in the period and higher depreciation.

In order to better understand the reasons behind the increase of ARS 344 million in operating income, we've broken it down into more detail.

The ARS 42.7 billion or 20% increase in revenues was a result from an increase of ARS 13 billion in gasoline sales, with higher prices 20% and higher volumes 7%, an increase of ARS 10.7 billion in diesel sales due to higher prices in pesos of 16%, partially offset by a decrease in sales of 0.7%.

Third, ARS 6.2 billion increase in natural gas sales due to prices which were 14% higher in pesos, an increase in sales volumes of 1.1%, ARS 3.8 billion increase in natural gas sales in the retail segment, which was mainly explained by the consolidation of our subsidiary Metrogas.

Then, other products sold in the domestic market, which recorded an increase of ARS 8.9 billion, highlighting all-time record sales of asphalt and also strong performance in LPG, jet fuel and petrochemical products, all of them also with higher prices in pesos.

Then, we had higher exports of ARS 5.7 billion on higher volumes and prices.

And on the other hand, we had a reduction in fuel oil sales of ARS 5.5 billion on lower volumes of approximately 49.5%, and prices which are also lower in 15%, as the power generation sector had more gas available to displace fuel oil.

Cost of sales other than depreciation increased ARS 8.4 billion.

The only cost component which is fully dollarized is the royalties.

The factors explaining the increasing costs were the lifting cost, which was up by ARS 5.4 billion or 14%, which was well below inflation levels, transportation expenses, which increased 25%, refining cost, which was 20% higher, and royalties, which I already explained before.

In addition to that, we had higher environmental charges during the last quarter that impacted the full year.

Depreciation was up by almost 20% or ARS 8.8 billion, due to an increase in the value of our assets, which are carried in dollars, and the increase in the rate of depreciation due to the decrease in the net reserves of crude oil as a result of a reduction in prices in domestic market.

These effects, which were partially offset by the net reduction of the carrying value of these assets as a result of the impairment charge that had been recorded in 2016.

Purchases of crude oil and other products for sale increased by ARS 17 billion, and this increase was mainly concentrated in crude oil purchases from third parties, which increased by ARS 6.3 billion on 49% higher volumes, driven by the lower production of the year.

Also, purchases of biofuels increased by ARS 4.8 billion as a result of higher prices in pesos and higher volumes to be blended.

Purchases of natural gas from other producers for our Retail segment increased by ARS 1.1 billion, again, this is Metrogas, as well as purchases of grains that result of the bartering in our Agro business that had a similar increase.

Imports were up by ARS 1 billion through a combination of higher imported products or volumes of premium gasoline and lower imported volumes of diesel and jet fuel.

SG&A was up by 19.5%, below 2017 inflation rate and below the revenue increase, as a consequence of higher transportation expenses and salary increases.

In turn, exploration expenses decreased by almost ARS 700 million or 22% on lower, unproductive exploratory wells.

Other operating results in 2017 was a loss of ARS 800 million compared with a gain of ARS 3.4 billion last year.

Note that the 2016 number included certain positive onetime gains, which were the gain of ARS 1.5 billion from the deconsolidation of Maxus in the second quarter of 2016, the gain of ARS 1.4 billion that was related to the expansion project in the Magallanes area that was funded by our 50% partner, and finally, the temporary financial assistance received by our subsidiary Metrogas of ARS 759 million in 2016.

Entering now to our Upstream business segment.

Our analysis of the operating income, excluding the effects of the impairment previously discussed, shows that the segment reported an operating loss of ARS 1.2 billion compared to an operating income of ARS 8.1 billion last year.

Revenues reported a slight increase of 2.2%, reaching ARS 116.7 billion, driven by the following combination of factors: first, higher natural gas revenues of ARS 6.8 billion or 18% on higher prices in pesos and a 1% increase in volumes; second, lower crude oil sales by ARS 3.8 billion or 5% due to the 7% reduction in volumes transferred from our Downstream business segment.

In line with the terms of the agreement between refiners and producers signed in January of 2017, the average realization price in dollar terms for crude oil decreased to $53.90 per barrel.

For natural gas, the average price was $4.92 which was 3.7% higher than previous year.

On the cost side, these were up by ARS 11 billion, which is an 11% increase compared with 2016, mainly due to the increasing items related to lifting cost.

Lifting cost on a per-barrel equivalent basis increased by 6.7% compared with the previous year to $12.80, mainly because of the production decline.

Total cash cost per BOE reached $21.10, including royalties and other costs -- or other taxes, actually, of $5.70 per BOE.

The Downstream segment reported a strong operating income of ARS 15.8 billion, which was 5x higher than the ARS 3.1 billion operating profit of the previous year.

Revenues were up by ARS 32.8 billion or 20% on higher sales of gasoline, diesel and most other refined products with the exception of fuel oil, all this was explained before.

And finally, as sales in the export market increased by 36% also.

Costs of the Downstream segment increased by only 11%, well below inflation.

And there, we can highlight higher purchases of biofuels of ARS 4.8 billion, with higher prices for both biodiesel and ethanol of 22% and 20%, respectively.

Now ethanol volumes increased by 17% and biodiesel volumes increased by 8.7%.

During 2017, total CapEx for the company amounted to ARS 58 billion, 7.6% below the level of 2016, showing a further reduction of 17.8%, if we measure it in dollars.

Upstream CapEx amounted to ARS 44.3 billion, which represented a decrease of 9.8% compared to 2016.

Our activity was mainly focused in drilling and workover, which represented 70% of the Upstream CapEx, followed by a buildup of our facilities with a 24% share and exploration and other activities representing 6% of Upstream CapEx.

During the year, we drilled and put in production a total of 467 new wells, including 94 new wells in shale and tight gas formations.

Most meaningful investments have taken place in the Neuquén basin, more specifically, in unconventional and other shale and tight gas blocks where we have activity.

And then in conventional areas, Chachahuen in Mendoza, was the most relevant of the Neuquén basin.

We continued our drilling activity in all other producing basins, Golfo San Jorge, Cuyana and Austral.

With regards to exploration, in the fourth quarter we completed 3 exploratory wells, 2 of them looking for oil and 1 with natural gas objective, reaching a total of 24 new exploratory wells in the year.

In Downstream, CapEx was ARS 8.2 billion, which is 17% lower compared to the previous year.

Activity was focused in refining, which represented 53% of Downstream CapEx, followed by Logistics with a 23% share, chemicals representing 14% of CapEx, and finally, marketing with only 10% of total refining CapEx.

To highlight during the year, we finalized the revamping of the topping 3 unit in our Mendoza refinery, and we began the pumping tests in the Señal Cerro Bayo-Puesto Hernández crude oil pipeline reversal that will allow our Mendoza refinery to work at full capacity.

In our Gas and Power segment, CapEx reached ARS 3.9 billion, and this is a result of the construction of the power plants, which we discussed earlier.

As we guided in our Investor Day, we are committed to align our cash generation with our capital expenditures as the financial discipline is one of the key priorities for the following years.

This way, operating cash flow reached or increased by almost 22% compared to the cash generation in 2016, which included the collections of the Plan Gas receivables of 2015, which we had collected in bonds.

And this number of operating cash flow for 2017 more than exceeded the CapEx for the year, starting the deleveraging process that is part of our 5-year plan.

This cash generation including the dollar-denominated bonds still held in treasury, results in a strong cash position of ARS 41 billion at the end of year 2017.

The previously explained cash position is enough to cover our debt maturities of the next 12 months.

It is worth to mention that, in December, we issued a new 30-year bond and reopened the notes maturing 2027, for a total amount of $1 billion.

This way, our next important debt maturity of December 2018 has been reduced by the repurchase of $400 million of those bonds coming due.

Our leverage ratio came down to 1.98x net debt-to-EBITDA, in line with our 2x target for the year.

And the average life of our debt has been extended to 6.4 years.

The average interest rate in pesos was 23%, while the average cost of our debt in dollars was 7.4%.

With this, I would like to ask Miguel to make our final remarks before opening up for questions.

Thank you, Daniel.

Good morning and thank you for your participation on this call.

Daniel just reviewed our results for the fourth quarter and the full year for 2017.

No doubt we consider this result as very good and especially when we put them in the context of the year 2017.

Some points I would like to highlight.

The year 2017 was a year of growth for Argentina.

GDP grew 2.8%, following a decline of 2.2% in 2016, was also a year where the government normalized the energy sector by liberalizing the oil and gasoline and diesel markets in October, after [grower] convergence between the price of the domestic oil barrel and the international markets that Daniel has explained.

Remember that, in the year 2015, the domestic barrel price was around $75 and we came down to levels of $55 per barrel last year, a decline of 36%.

In other sectors of the energy markets, it was a year in which the natural gas markets were regularized as well and a clear price path was introduced, paving the way to restructure the debt between producers, transportation and distribution companies.

It was also a year where the government consolidated an aggressive push and incentives for investments in the thermal generation sector as well as the development of the renewable energy sector, among other initiatives.

No doubt, the energy sector is a critical driver for investments in the country.

Testimony of that was a nonconventional new labor contract that led by YPF the industry signed with the unions in January 2017.

That agreement that was developed with the leadership of President Macri and Ministry of Energy Aranguren, with an active participation by the province of Neuquén, where a significant productivity and efficiency gains were achieved.

But we also promised in the conventional areas, where we concluded similar agreements with other labor unions and governments like the Province of Chubut in February 2017, and during the year with the unions of the Province of Santa Cruz.

We are very thankful for the close working relation and collaboration with the unions, the provisional governments and the federal government.

This initiative was very important to position the company at an efficiency level that permits operating at a price range of $50 to $50 (sic) per barrel.

That continues to be our medium-term forecast and the base for our long-term plan.

Additionally, we have continued to put in place our supply chain plan unveiled at the end of 2016 to reduce our cost by 20% in dollar terms within the next 3 years.

In fact, our relentless focus on cost management contributed to whether a year where inflation was higher than the peso depreciation by between 5 to 10 points, adding a significant challenge to our nevertheless successful cost reduction results.

YPF had leveraged the positive macro and regulatory environment by increasing our gasoline and diesel sales in 2017, already in a much competitive market, by maintaining and increasing our market share and leading a market transformation that is expected to have new entrants that will change the incumbent landscape and also will feature the active participation of trading competitors.

We are preparing ourselves for a very interesting competitive market where YPF has all the necessary assets to compete and win in that environment.

We are defining our pricing policy as explained with a clear focus on protecting our margins.

We have a clear, thorough and disciplined investment process with implementation of the investment committee, where every investment is analyzed in detail, not only in relation to our portfolio, but also making sure that every dollar invested contributes to our bottom line.

Some resulting delays in CapEx investment during 2017 were the result of this scrupulous analysis.

In that context, I would also like to highlight that our aggressive decision to invest in shale pilots to accelerate our nonconventional derisking, with 10 pilots to re-execute it in 2018, as discussed, for more than $600 million, in addition of the development of tight gas in new areas like Rio Neuquén.

We have not forgotten our significant conventional activities, that despite of being mature in nature, we still believe the significant value in executing what must to be done in those areas as the best-in-class.

We're already focused on ensuring that our secondary stimulation is optimized, and that our [tertiary] activities are expanded in a very disciplined and aggressive manner.

We're keenly focused on our production for 2018, that was affected by some severe climate events, labor strikes and a few disputes with indigenous communities during 2017.

We do not anticipate a similar combination of events for 2018.

As we move into the year, we have taken a conservative outlook and we prefer to guide on a 2% to 3% reduction in the production for the year.

We conducted all of our activities with excellent safety results and ensuring that we have a clear plan and commitment to reduce our emissions in accordance with the Paris Accord and other related industry and government agreements.

We have also implemented an energy efficiency plan to reduce our consumption of energy in our operations, that is an integral part of our long-term transformation program.

We are very proud of our transformation towards an integrated energy company, where our leading position in hydrocarbons business is combined with our efforts to lead the power generation business and renewables.

To that end, the recently announced agreement with GE Capital for YPF EE is a great step towards achieving a top 3 position in the Argentine marketplace by 2022, as our strategic plan states.

Our focus on the power generation business and on the growth and expansion of our petrochemical business positions YPF for the growth expected in natural gas production in the next 5 years and this [distratation] that will enhance the value of that production.

We have also launched a transformation program across the firm that will help us to achieve the productivity and efficiency goals indicated in our long-term plan.

We have identified over 150 projects, of which, 65 are critical.

And we've already entered into the implementation phase of those projects, all of which we expect to implement within the next 4 years.

It should be noted that, during 2017, the management team and the board devoted significant time and resources to the preparation of a long-term plan that was presented back in October and that we ratify completely today.

Our financial situation is quite solid with significant cash generation and reduction of our debt-to-EBITDA ratio below 2x despite that the planned gas subsidy for 2017 was not paid during the year, a situation for which we anticipated resolution during the next few weeks.

In addition, during 2017, we continued to optimize our management team with our Downstream, Upstream human resources and safety and sustainability units under new leadership.

We also created and incorporated a CTO position and more recently also a CIO to lead our digital and IT transformation.

We are committed to driving a cultural change in the company to best leverage the opportunities and manage the challenges that lie ahead for YPF.

For example, we launched a gender equality program in 2017 and we will focus on a broader diversity program for 2018.

As announced, we created an executive committee in August following the departure of our CEO that has worked very well together during these past months.

However, as I indicated previously, and in keeping with our corporate governance values and principles, the board is working to name a CEO before our next shareholders meeting.

A word on reserves.

As you can see from the presentation, we continue to be in a very narrow range of reserves over the last 10 years, around 1 billion barrels of oil equivalent, despite our significant declines in our conventional activities.

While we are very focused in achieving our reserve replacement targets indicated in our long-term plan, we take comfort from our resources of over 5 billion barrels of oil equivalent only in Vaca Muerta.

Our targets for 2018 are -- for the company are the following: an increase of 10% in EBITDA; CapEx around a $4 billion range; and as discussed before, a reduction of around 2% to 3% in production growth.

We also are committed to keep debt-to-EBITDA within the 2x.

In summary, we are pleased with the quarterly and annual results, and we are very focused to improve the areas that we highlighted during the call, while we are very optimistic about our future.

Finally, I would like to take this opportunity to thank the executive committee and the extended management team for their efforts and contributions during 2017.

And especially thank all of our YPF employees for their hard work and commitment.

We'll now go for the questions.

(Operator Instructions) And our first question comes from Bruno Montanari from Morgan Stanley.

First question is about production.

I understand the targets implying 2% to 3% production decline in a year.

But when can we expect an inflection point in the curve?

Because it's been a few quarters now, the production continues to decline.

So just wondering if we should see things getting better in the first, second quarter of the year or if this is more towards the second half of 2018?

My second question is on Downstream.

Margins were very resilient in Q4, despite all the noise with inflation and the price liberalization.

So should we expect margins to remain sustainable at current levels?

And also, following the removal of all the trade restrictions, has the company seen movements that imply fewer imports could start to come more aggressively into Argentina?

And if I could ask a third one, just following up on Mr. Gutierrez's comments, just to get an update on Plan Gas, especially now that the new rules seems to be defined.

If I remember correctly, the last payment the company received from the government was still related to Q4, 2016.

So just wondering when we should actually see the 2017 receivables to be paid, and in that regard also, what exchange rate does the company believe will be used for those?

Bruno, thank you for the questions.

In terms of production, what we can say is that the first quarter seems to be aligned with the fourth quarter, so the decline in production in absolute terms is kind of behind us.

Still a comparison of the first quarter, vis-à-vis, the first quarter of last year is going to be negative, right, and that's why Miguel guided on this minus 2, minus 3 for the full year.

But in absolute terms, as I said, I think that the worst is behind us and we should not expect additional declines in production.

Now the turning point will be towards the second half of the year.

It will come from different sources, it will come, clearly, from the shale.

We are expecting growth in shale oil and gas production of 35% plus this year, vis-à-vis, the previous year.

It will also come from the Province of Santa Cruz, where we didn't have any drilling activity last year, and we started the drilling in the last couple of months, and we'll have a two dedicated rigs for the full year.

And it will also come from Magallanes where we have this project jointly with ENAP that will only come in stream at some point during the second quarter of the year.

So definitely, the second half of the year should be better.

In terms of our Downstream margins, yes, they have been resilient, we don't see any reason why they would be different going forward than where they are today.

We continue to have a very strong competitive position, a unique brand and footprint.

So as Miguel said, we have -- we are establishing or we are putting in place a pricing policy based, obviously, on import parities and based also on other market dynamics, including competition.

We haven't seen yet that increasing competition that you outlined in the questions but that doesn't mean that we will not see it in the future, that's why we are preparing the company for that.

And finally, regarding Plan Gas, we are owed approximately $780 million that was accrued last year of subsidies.

We didn't get paid anything of the subsidies of 2017.

And also as mentioned by Miguel, we will have news about this, hopefully, very, very soon.

I think I would rather not comment at this point of what kind of payment tenor we are anticipating or what kind of interest rates we have in mind, but as I said, in the next few weeks, we will be able to provide more detail.

Our following question come from Frank McGann from Bank Of America.

Just a couple of questions.

One, just in terms of asset sales and the sale of your stake in Metrogas, any thoughts on that at this stage where we are in that process?

And then I missed -- the line cut out, I missed the percentage increase you said you're expecting shale to show for 2018.

If you could repeat that, that would be helpful.

Frank, yes, the percentage increase was 35% for shale production in 2018, vis-à-vis 2017.

In terms of asset sales and specifically, Metrogas, all we can say is that we have hired an investment bank that has very recently started the process to review what the strategic options we have.

You should not expect any news in the short term.

And hopefully, it is -- it will definitely be a second half of the year event.

And as I said, it's all very confidential and very difficult for us to provide any kind of color before we are very close to having some kind of transaction in the future.

But first, we need to define what kind of interest is out there, what kind of percentage of stake we should sell in order to maximize valuation.

Luckily, we are in a very comfortable position from a liquidity perspective, and we're just being proactive in terms of trying to realize value of certain assets, including Metrogas, that we think might be worth more for other people than for ourselves.

But other than that, Frank, there isn't any process ongoing.

There is no significant process ongoing.

Let me make a clarification there.

We are in the process of selling a few small marginal oilfields in the Neuquén Basin.

It's a very small transaction, but I just didn't want to confuse by saying that there is nothing else.

This is something that, hopefully, will be announced in the next couple of months.

On our next question comes from Juan Vazquez from Puente.

The first question is related to the seasonality problem that exists in the natural gas market in Argentina.

If increasing production to cover the demand peak in the winter is unrealistic, we'd like to have your thoughts on what sources of demand you see materializing in the short term.

And especially, in the summer months, to incentivize additional gas production and, therefore, the development of Vaca Muerta and other unconventional assets.

And the second question, in the presentation you showed that your 2018 expected average realization price from natural gas still includes subsidies.

So are these expected subsidies coming from your unconventional pilots to be launched?

Juan, thank you for the questions.

Let me start with the second one.

Yes, we are including in our realization price expectations for natural gas for 2018, the subsidies of the new gas plan for unconventionals.

We have -- let me count on, like, 7 or 8 different projects that we actually filed for the benefit of the subsidy, and we have all the expectation that all of them will get it.

So we will have some positive effect this year coming from those subsidies.

As I said during the presentation, the good news is that subsidies, as a whole, will only represent approximately 10% of that weighted average price.

Regarding -- the first very good question regarding seasonality of natural gas demand, we are clearly working for the short but, especially, for the long term in order to find and secure different alternatives of gas demand.

Miguel mentioned that the petrochemicals, where Argentina has competitive advantages, is definitely a place where we want to grow, and we will grow with partners there.

That is long term, because it takes a while to build petrochemical facilities.

But that will definitely take care of a good part of the -- of gas demand.

Gas fire generation, all the projects that were sanctioned and that obtained contracts from CAMMESA for new power to be generated using natural gas, will also be an important driver, and that is short- to medium term.

And then there's the exports, and there you also have short-term exports, like, with -- what we are doing with Methanex and other potential short-term exports to Chile.

And on the medium term, I think even more exports.

Now it is not unthinkable to assume that, a few years down the road, Argentina will continue to have LNG coming in regasified to fill the peaks of the winter.

And maybe natural gas being liquefied out of Argentina with the excess production of the summer.

And also, if that occurs, we would be thinking about seasonal pricing, which is not what we have today.

So today, we're talking about $5, give or take, per million BTU as an annual price.

But it is reasonable to assume that we might have a lower price during the summer and a substantially higher price during the winter.

All of that is in the process of -- the whole gas industry is being redefined in Argentina.

But we continue to be very optimistic regarding the prospects for natural gas.

The last thing I should mention is import substitution, right?

Not just LNG, but also demand -- or gas coming from Bolivia.

After Argentina continues to grow its home production, we should also expect, over the medium term, that gas coming from Bolivia should tend to come down.

Okay.

Just a quick follow-up.

So that would imply your renegotiation of the take-or-pay contract with Bolivia, so you think that's -- that could be a reality?

No, we are not a party to that agreement, that is the federal government.

And we are not implying, in any way, that, that contract is going to be renegotiated.

All we are saying is gas production for Argentina is important.

Good news is, it is growing.

The government is paying -- or is helping the industry in the form of subsidies.

So over the medium, long term, you should assume that volumes coming from Bolivia should tend to come down.

If that implies or not redefinition of the agreement, we have nothing to do with that.

And I will add to that -- this is Miguel, that also regional integration with other countries in the region, like, the Chile agreement is going forward as well as some agreements with Brazil to sell electricity in the summer time are also in the agenda for us to really work with the government, really to execute those agreements.

And that, obviously, will entitle gas consumption for the summer.

That's very clear.

And a quick follow-up to the first question.

Some investors are worried about the entry, the potential entry of traders.

Assuming that traders may have distribution capacity, and this is a big assumption, isn't the lack of storage facility in the country a huge entry barrier for traders?

I mean, if they wanted to compete in Argentina, what are your thoughts on that?

Clearly, logistics is an very important part of the equation, and both tanking and pipelines are a restriction.

Distribution, in itself, is also a restriction on us.

You said, your -- it's a very huge assumption, believing that, that distribution is available to anybody.

So I think that the market is open, anybody can come in.

Prices are international prices, so based on international prices.

There are no import duties at all.

But the incumbents, and we think YPF at the top of the incumbents have all the elements to compete favorably.

So we're not saying that this is not going to happen.

We're just saying that if it does, we are in a very, very strong position to defend our portion of the market.

Our following question comes from Alejandra Aranda from Itaú BBA.

This is actually Ricardo Cavanagh.

Well, first of all, I would like to ask like an holistic view on the industry.

I see the impressive improvement that you have achieved over the past few years, well, in Vaca Muerta and honestly, I think you're doing all of the right things.

Now yet when I look at the outlook for production and YPF and the industry as a whole, the trend is definitely downward for crude has been, well, for more than 20 years and for gas it's very hard to pick it up.

So conceptually, what do you think could make the trick for industry fundamentals to revert, given that extrapolating the situation would mean that crude production will continue going down, industry as a whole, no?

So is it cost, is it productivity, is it new fields?

What do you think?

Well, thank you, Ricardo, for the question.

I think what we are seeing, and we're only seeing the tip of the iceberg here is a huge replacement of, let's call it, legacy production for shale production, okay?

Up to what extent the shale production, in case of oil, we'll be able to offset the decline of the mature fields, difficult to say, especially if you're talking about the whole industry, not just YPF.

In natural gas, it's very, very clear that shale and tight production, not only will offset the decline of the existing production but will also provide significant growth in order to take natural gas production in Argentina back to where it was 10 years ago, which was substantially higher level than where we stand today.

How we get there?

Clearly, it's about continuing this derisking of unconventionals and making sure that the results, very positive results, I have to say that we are seeing in the only 2 development projects that we have in Vaca Muerta can be replicated in the rest of the acreage.

That's why I made reference to the presentation of 20 different Vaca Muerta areas where we have participation and our projects are ongoing.

18 of those 20 are pilot projects, okay?

So only 2 are in development mode, okay?

Between our own pilots, which, as we said, are 10 of them plus pilots being conducted by some of our partners where we have a minority stake, there is plenty of activity going on to make sure that we can replicate this success of Loma Campana and El Orejano.

And the great news is that different to what it was 3, 5 years ago, where it was only YPF, the one that was doing this.

Now there's a bunch of other very big players also making significant investments here.

You can see that with those names that have teamed up with us and have signed agreements, especially, in last 12 months, we've been extremely active with that.

But also in other areas, where the likes of Total or XTO or Shell and so on are investing heavily, same thing with Tecpetrol in natural gas.

So I -- we believe that this is kind of a rebirth of the Argentine oil and gas industry.

We will continue to fight the decline of the mature fields.

We will put a lot of emphasis in massification of secondary recovery and starting tertiary recovery seriously to fight decline.

But the bulk of the growth will come from the unconventionals.

Our next question comes from Regis Cardoso from Crédit Suisse.

Two questions.

First one in regards to Downstream market.

You mentioned you are working on a pricing policy, right?

And I guess that's a key point on YPF investment case going forward with increasing competition from trading companies.

So last time we talked, one of the key question marks is whether you would pass through volatility or not to domestic markets?

So I wanted to get a sense of how are your latest thoughts in regards to your pricing policy, eventually having daily volatility or not?

And then second question in regards to the Plan Gas.

I wanted to touch base on the implications of the change, because I understand from when you presented the business plan, the interpretation of Plan Gas was different, right?

I wanted to understand what does that change in terms of both short-term EBITDA, and I see you're looking at similar gas prices.

But also on terms of longer term, how has it changed your 5-year plan in terms of which investments you're making and whether that's impacting or not the 5-year production growth target?

Okay.

Thank you, Regis.

First on Downstream pricing policy, we included a graph on that -- on today's presentation, I think, was Slide 15 that pretty much shows how we're looking at this.

We are definitely incorporating the effects of that volatility.

We just are not doing it on a daily basis, okay?

We have been increasing prices as needed, taking into account what was going on with international markets and also what is going on with the market dynamics in Argentina.

As you can see on that graph, at this point in time, we are exactly converged.

At some point in December, we had local prices which were above parities, and in January, we were below parities.

So you should continue to see that, because the way that we planned is with a quarterly and an annual margin as a target.

Both for refining margin as well as our commercial margin, right?

And we are pricing our products always with an eye in protecting and enhancing those margins.

We are not saying that we will never have our daily pricing policy.

We don't know, but we have our pricing policy today that we think it's a good one and has allowed us to catch up with prices.

It has allowed us to maintain or even slightly increase market share.

And lot of this with -- without any pushback from the market, which is also very, very positive.

The demand in Argentina continues to be very, very strong.

So you should rest assured that in determining prices, protecting our always-healthy margins in downstream will continue to be a priority going forward.

With respect to our Plan Gas, it is true that when we laid out the plan in October, the details of the plan had not been ironed out and that it came out different than what we expected.

And basically, a few areas, tight gas areas, which is nonconventional but that were already in production are not getting the benefit of the subsidized plan.

And that's why we actually tweaked the CapEx for the year and stopped drilling in some tight gas areas where we just didn't think the economics were there.

That doesn't mean that you're stopping all investment in the area, but we basically cherry-picked the wells that made sense and decided not to engage in the additional drilling activities that would have made sense with the full subsidy and that probably didn't make sense without that subsidy.

Did it have a negative impact in 2018 EBITDA?

Yes, some, but that's already embedded in the 10% growth in EBITDA that Miguel provided as a guidance for this year 2018.

So now for the long term, it doesn't have any negative impacts because first, all those shale oil pilots that we or shale gas pilots, sorry, that we are addressing this year all, we believe, will have the full benefit of the subsidy because they're all new.

It's going to be new production.

And in any way, all of the projects that we are considering have breakeven prices, well above the prices that we have with the first few years with some subsidies and then no subsidies at all after year 4. So we just adapted our plan to the new reality of that Plan Gas.

As I said, it has -- it had some negative impact on what we were planning for 2018.

It does not have any negative impact of what we are planning for the full 5-year timing of the plan.

If I can make just 2 quick follow-up questions.

One is regarding the charts you mentioned in Slide 15.

Are those charts, in any way, accounting for freight?

Is this a clear representation of the import parity?

Or is it simply [arball] and ethanol costs?

And also a second follow-up question, tight gas production seems to be down in fourth quarter, last year, right, in '17.

Is it, in any way, related to what you've just mentioned about the change in which projects you will carry out?

I didn't hear the last question, Regis.

But the first question regarding the import parities, yes, absolutely, it's not just [arball] plus bios.

It's a full import parity, including freights.

So the answer is yes.

I didn't get the second part of your question.

The second question was about tight gas production in the fourth quarter.

It seems that it was down on a quarter-on-quarter basis.

It is, in any way, related to the change in investments as a follow-up of the Plan Gas?

Or is it something else?

Soft demand?

No, it's not related to the change in the Gas Plan.

It's related to the restrictions to demand of the -- that we experienced in the last quarter, that I made reference to, which actually -- the areas that were most affected or the area that was most affected is our largest tight gas area, which is the Lajas formation.

And that's why we lost production out of Lajas basically because we had to cut because of a lack of demand.

But no, it has nothing to do with Gas Plan.

Our next question comes from Pavel Molchanov from Raymond James.

This is Muhammed on behalf of Pavel.

So you guys added a third rig to your acreage with Chevron in October.

Have you already begun to see the impact from the rig, if not, when do you begin -- when do you expect to see the rise in production as a result of the rig?

Muhammed, no, we have not yet seen the additional production out of that rig, because it's only came in operation, I think it was in October, November of last year.

And the full cycle of a full part coming into production takes, give or take, 150 days between drilling, completion and putting in production.

So that is embedded in that 35% increase in shale production for the year that we are estimating.

Okay.

And can you talk a bit about your plans for Santa Cruz?

How many wells do you plan to drill in 2018?

And what areas are you targeting?

No, Muhammed, we never disclose in that kind of detail how many wells in each of the areas or each area, specifically, that we are going to be investing.

Now because I mentioned that we will have 2 dedicated drilling rigs, we should assume it's going to be around 30 new wells during the year.

And the next question comes from [Valencia Torres] from [TPCC].

Our next question comes from Santiago Biagini from AR Partners.

Just a couple of questions.

The first question, just a quick follow-up on the price of gas that you mentioned before.

Where should we expect to see the price in the first quarter of 2018, once we factor in the amendment to a Plan Gas?

I mean, how much could it fall versus the figure reported in 4Q?

Two questions, and could I get a breakdown of the reserves at the end of 2017 between conventional and shale for oil and conventional tight and shale for gas?

And the last question, if I may, I wanted to get a sense on your financing needs for this year, considering the CapEx plan.

Okay.

Santiago, thank you.

Your first question regarding expected price of gas for the first quarter, we usually say, we don't usually give those kind of projections.

But you should assume it's going to be around the same level that we have today.

We have -- we are projecting a similar price for the year as a whole, we are not breaking it down on a per quarter basis.

Maybe it's a couple of cents below the $4.90, but in that range, okay?

Regarding breakdown of reserves, I don't have here a full breakdown.

What I can tell you, it's a shale oil and gas reserves represent, give or take, 80 million barrels of oil equivalent out of almost 1 billion for total P1 reserve, so it's 8% or 9% of our total reserves, still small.

I don't have the numbers for tight gas, they are quite significant.

But we can follow-up with that -- providing that.

In terms of financing, as we said, we are in a very liquid situation.

We anticipated the financing needs for the year in December.

So we started the year with strong cash position.

We don't have any intention in addressing the capital markets for now.

And at the same time, we have entered a new cycle in which we start having positive free cash flow before interest.

So whatever we fund or finance is basically to replace or refinance debt coming due.

And we don't have any significant debt coming due this year.

We have approximately $400 million or $450 million of bonds maturing in December of 2018, end of December.

That is our first sizable maturity this year.

So no significant financing needs for the year.

And clearly, no new issue, no debt new issue activity in the coming months.

Our next question comes from Pedro Medeiros, Citigroup.

I have a couple of questions.

First one is, you guys can provide any extra color on the contribution for any shale resources you updated resource figure for this year?

And on that same line of thought, do you mind commenting on the results for drilling the first 3,000-meter plus lateral wells in Loma Campana in terms of cost and initial productivity or the recover for well targets that you have for these wells.

And if the plan is that these will become the norm, the new norm to be pursued in Loma Campana?

Thank you, Pedro.

We don't have any results for the 3,200-meter long lateral well, basically, because it has been drilled, but that's not yet been completed.

And we expect it to be completed in April of this year.

So hopefully -- sorry, not for the first quarter results.

But definitely at some point after that, we will be able to start providing with some details, some color in terms of the cost and in terms of the IPs.

If it's the way to go or not, it will depend on these results.

We're still trying to find what is the sweet spot in terms of length of laterals.

But you should assume because of the significant increase in the number of frac stages that we can put in those longer wells, the cost of development of those wells should be much lower than the 1,500-meter wells that we have been drilling in the past.

So we will see there for us for -- with us for a couple of months while we give you -- or while we have our own results in order to share with the rest of the market.

Your first question was regarding additional color on those 5 billion barrels of oil equivalent of resources.

There's very little we can say about this, other than saying that we have just huge resources in Vaca Muerta.

That's why the discussion regarding reserves we try to put in context so that nobody thinks that we don't have the ability of replacing production every year, as we have been doing, right, because we produce 200 million barrels of oil equivalent per year.

We have been producing that for the last few years and always the reserves seem to be around that 1 billion barrel mark.

We will have the ability of transforming these resources in reserves over time, okay?

But there are very strict rules in terms of what kind of reserves or how to certify reserves coming from unconventional.

And we have very little history, again, to my point of 20 pilots ongoing, only 2 of them, which are in production or in full development, I must say.

I said that, that we have 80 million barrels of oil equivalent of P1 reserves coming from the shale, while 80% of that is just coming from one area, which is Loma Campana.

So clearly, what we are saying with this is, as we grow in the number of pilots, those reserves will start coming in.

Don't ask me, please, for a specific projection of what reserves are going to look like this year.

But we stick to our objective of increasing reserves by around 50% over 5 years.

Just if you don't mind, a follow-up on that.

And based on the map shown in the presentation and the comments you have made, and recently we have had the renewal in the budget approved for La Amarga Chica for 2018.

Like, how many of your pilot projects are expected to potentially have a decision on a commercial development sanctioning in 2018?

And if you don't mind, like, conceptually, that commercial development approval would mean typically, what, like, adding 3, 4 rigs on each of these projects?

Okay.

Pedro, that project that you mentioned, La Amarga Chica with Petronas, is the first one of those pilots ongoing that we expect to be converted into full development this year.

But we also expect Bandurria, which is JV that we have with Schlumberger, also to be transformed from a pilot to full development at some point very late this year.

And generally, like, if we take the Loma Campana as an example, it will mean like targeting somehow between 3 or 4 rigs per year, right?

Just so I can try to figure out scenarios for your production growth from shale over time?

We still have not discussed, in detail, the development plan with our partner here.

So we should not get into any specific details regarding La Amarga Chica.

But generally speaking, any of these areas can easily support 2 to 3 drilling rigs when moving to full development.

At the end of the day, it will depend on the pace of investment that the partners intend to engage in.

What we can tell you is, we don't see ourselves going back to the early Loma Campana days in which we had 20 rigs in one area.

That, I don't think, will happen.

Will it be 2 or 3, will it be 5, it will depend.

And again, this comment is not just about La Amarga Chica, it's about all of the developments in Vaca Muerta.

And, Daniel, just as the last follow-up on that theme, is there any project that is fully owned by YPF and could face a decision on commercial development this year?

And I mean, regarding shale, specifically then in the Vaca Muerta resource development?

Not from those that are going to full development.

As I said, it's only La Amarga Chica and Bandurria, also then we have partners.

But in terms of the pilots that we showed in the presentation, yes, definitely yes.

We have many of those pilots like Rincon del Mangrullo for Vaca Muerta, La Ribera I and II, Aguada de la Arena and a few others that we're engaging in this year that are all fully owned by YPF, yes.

My last question is regarding the deal with GE.

It's just to understand one very simple and objective point.

Is there any take or pay for your natural gas regarding this project?

And do you mind sharing, if so, like, how does the price compare with your current natural gas price sale?

I don't recall exactly if there are take-or-pay agreements, I think there are -- clearly, there are preferential sale gas agreements as they are preferential equivalent agreements with GE.

In all cases, what is very clear is that it should be on an arm's-length basis, okay?

And always in the best interest of YPF EE, meaning YPF EE will not be subsidizing any of YPF OG.

Our next question comes from [Valencia Torres] from [TPCC].

I would like to ask you a follow-up regarding the reserves, which is a strategy that the company has to improve the reserved based on ratio currently at 9%?

Thank you, Valencia.

The strategy the company has is engaging in the best projects that we have for oil and gas development.

Meaning, we have very thorough prioritization of projects and not just managing according to research.

What I'm trying to say with this is, if we are successful with all these projects, reserves will clearly increase.

And that's why we have set up this target of increasing reserves by 50% in 5 years.

The one thing that we are not doing, and we will not be doing is just doing CapEx that might have a short-term positive effect in reserves, if that CapEx cannot prove that should return or should provide returns above our threshold, 13% rate, okay?

That's, I think, that's the best way to elaborate how we are seeing reserves.

Our final question comes from Luiz Carvalho from UBS.

Just 2 quick questions.

The first one is the -- regarding the reserves, if I may come back to this point.

I just would like to understand how you'd see the change of the pricing policy or you'd say the change of the crude policy affected your reserves this year?

Because for the past -- couple of past years, I mean the reserves were, somehow, close to 1.2 million, 1.1 million, and now basically dropped a bit, I don't know, 16%.

I just would like to understand the impact of the change of the pricing policy itself on the reserves?

And second, that's kind of a recurrent question from my end in the conference calls, but I'd like to understand a bit more, is there any update on the potential additional JVs for any unconventional areas, I mean, where we are on top of this?

Luiz, well, the first thing regarding reserves, as specifically, crude oil reserves that we all need to understand is that the price, the crude oil price used to determine those reserves decreased by 11% in dollars from '16 to '17, okay?

And that is, by far, I would say almost, not the only, but by far the most important contributor to reduction in reserves.

We actually lost, like, 70 million or 80 million barrels of oil equivalent just because of the price reduction, okay?

Of course, we should assume that prices will or are recurring this year, the average price that we used for reserves in 2017 was $57 per barrel, sorry, I'm asking the rest of the team here.

And we have enjoyed a price in the $65 range in the first couple of months of this year.

So if prices remain flat in 2018, we will be making calculation with prices just $7 or $8 above those used in 2017.

That -- should that have a positive effect on reserves?

Yes, but very difficult to predict today what the effect will be.

In terms of additional JVs, as we -- you always ask a question and we always provide a similar answer, which is we are talking with a number of different interested parties.

There is one thing that we have to say is the interest from different parties within Argentina and outside of Argentina regarding Vaca Muerta is stronger than it has ever been, clearly, based on the very positive results of the pilots and the developments of Vaca Muerta so far, and also because of improvements in Argentina as a whole.

I really think, we really think that this convergence of prices will be a major contributor to increasing that interest even further, okay?

Because people like to have a possibility of having their oil produced in Argentina being benchmarked against their oil produced and sold in other places of the world.

We didn't have that luxury before.

We will have it going forward, so that should be a positive also.

Now we are not expecting an imminent announcement of any additional JVs.

We like the idea of doing a good part of that derisking in areas where we own 100%.

And eventually, moving to JVs once we have been able to realize additional value in all those areas.

Because as opposed to a couple of years ago, where we didn't have the financial resources, we do have the financial resources today to do all these derisking by ourselves.

So we continue to be -- to like JVs.

We are associative as a company.

We have very good partners, and we put a lot of value in the relationship with those partners.

So you will continue to see us doing JVs.

It's just not a need of doing them too early on and diluting our property at low value.

The only think I would add to that is that, as we have said in our long-term plan, we will be very active in managing our portfolio and that means not only doing JVs with existing assets that we have, but also looking for new assets.

So will be very active in the marketplace one way or the other.

Okay.

If I may just come back to the first question, Daniel, who is the certification company that certify your reserves?

Because -- but at some times you mentioned that you're going to use this type of oil or that type.

I just would like to understand what was the approach for this year?

Who is the certification company certifying the reserves?

This year, it was Gaffney and Cline the one that certified 1/3 of our reserves.

We have a protocol of certifying 1/3 of our reserves every year, so every 3 years, we have 100% of our reserves certified.

And we -- this year, as I said, it was Gaffney, the previous year was also Gaffney.

I'm not sure who is going to be doing at this year.

We put that for bids from time to time but it always the usual suspects, the big companies that certify reserves to the majors and all the relevant E&P companies globally.

At this time, we have no further questions.

I will now turn the call over to our host for final remarks.

Okay.

So on behalf of all of us here at YPF, thank you very much for bearing for -- with us for what a little over an hour and a half.

And of course, if there are follow-up questions, you can call me, Diego, Pablo or rest of the team at any time.

Have a good day.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.