YPF SA (YPF) 2018 Q4 法說會逐字稿

Welcome to the Q4 2018 YPF Sociedad Anónima Earnings Conference Call.

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

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

You may begin.

Right.

Thank you, Richard.

Good morning, ladies and gentlemen.

My name is Diego Celaá, IR Manager for YPF.

I would like to thank you for joining us today.

In this occasion, we will discuss YPF 2018 full year results.

The presentation will be conducted by our CEO, Mr. Daniel González, and our VP of Strategy and Business Development, Mr. Sergio Giorgi.

During the presentation, we will go through the main aspects and events that explain our yearly results and share our conclusions for the year and perspective for the year ahead before we start taking questions.

We will be making forward-looking statements, so we ask you to carefully review the cautionary statement on Slide 2. Also, our financial statements figures are stated in Argentine pesos, based on International Financial Reporting Standards.

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

With this, I'll ask Daniel to start with the presentation.

Please, Daniel, go ahead.

Thank you, Diego, and good morning, everybody.

Before we go through our operational and financial results for the year, I would like to provide some macro context to put things in perspective and better understand our performance.

Last year can be broken down in 2 very distinct realities.

The first few months of the year showed a strong economy with sales way above the previous year, the peso had devalued approximately 15% to ARS 20 per $1 and seemed stable back then, and local crude and fuel prices had converged with international prices.

Unfortunately, starting in May, the peso lost half its value and the local economy started to cool down and then rapidly fell into a deep recession.

In addition, export taxes were imposed in all products and services out of Argentina, and capital markets closed for remainder of the year.

To make things worse, international crude oil prices rallied all the way to $85 per barrel, which under normal circumstances would've been a good thing for us but, in this context, just made it tougher for local prices to keep up with international prices.

Local gas distribution companies were not able to pass through on to prices the effects of the devaluation creating a dispute with the producers regarding the wellhead price of gas.

And local supply of natural gas significantly increased during the year as a result of the incentive price program put in place but at a time when the local economy was not demanding more gas especially outside of the winter peak season.

This had a negative impact on our production figures of the last quarter and resulted in us rethinking our investments in natural gas development over the near future.

I believe the company performed well under these circumstances and was able to grow revenues, EBITDA, free cash flow and net income in dollar terms despite prices for all of our main products -- diesel oil, gasoline and natural gas -- being down in dollar terms.

Let me go through why I believe we did well and reach some of the main milestones of 2018.

In our Upstream business segment, I would say this year was one of the turnaround in Vaca Muerta.

As in previous years, shale production growth was strong, but the most relevant improvement had to do with the increasing productivity of the new wells and the simultaneous reduction in OpEx and CapEx per barrel taking our shale oil development cost to $11 per barrel and our OpEx to $6 per barrel.

And we sanctioned the next phase of the Loma Campana development, the full development of La Amarga Chica and the first phase of the Bandurria development, while we also complete the pilot in other parts of this area.

These sanctions are key because this will provide the basis for the oil production growth outlined in our 5-year business plan.

In addition, during 2018, we had an organic increasing reserves of 16%, provided by better economics and improvements in both unconventional and conventional fields, as we will explain in a few slides ahead.

We showed our highest organic reserve replacement ratio of last 20 years.

We rolled out an organization in the Upstream to improve the execution and conventional production, focusing on improving the performance of secondary recovery and made the investment decision to massively deploy tertiary recovery.

We started the year with lower investments in natural gas than what we had originally planned, and as the year unfolded, we started shifting more investments away from gas.

Needless to say, early this year, when the government announced the interpretation of Resolution 46, we scaled down a little bit further on natural gas projects.

Fortunately, the size and diversity of fluids of our shale acreage allows us to redeploy capital into other areas of Vaca Muerta.

In our Downstream segment, we recorded higher sales of gasoline and diesel of 3.7% and 4.5%, respectively, despite the economic downturn and the frequent price increases we performed along the year.

By November, we had already caught up with prices, and prices were in line with import parity.

In addition, we would like to highlight the acquisition of the assets of failed Oil Combustibles, especially the San Lorenzo terminal, which has the largest port in entire Paraná River, and significant storage capacity, which is already physically integrated with YPF.

In the Gas & Power segment, we acknowledged the significant natural gas glut and started working on a few short-term levers to create new demand for natural gas, including higher exports to neighboring countries and the chartering agreement for a small-scale floating LNG barge that will allow us to export up to 2.5 million cubic meters per day.

The barge has already arrived at Bahía Blanca, and we expect to start exporting LNG in the third quarter of this year.

With regards to power, in 2018, we closed the capitalization of our subsidiary, YPF Luz.

Today, YPF holds a 75% stake and GE holds the remaining 25%, resulting in a joint venture agreement and a deconsolidation of this company from YPF financial statements.

YPS Luz is executing its pipeline of new plants, combined cycle closures and cogeneration facilities, including its first wind park in the province of Chubut that started commercial operations back in October.

In 2018, we were able to deliver strong financial results despite the adverse market conditions.

We continued generating enough cash flow to invest in new developments and have a strong cash position that cover our short-term debt maturities.

And finally, the board yesterday recommended to the shareholders meeting to be held in April, the declaration of a cash dividend for this year of approximately $100 million, in line with our statement we announced our 5-year plan.

Now I would like to share with you our safety metrics and the impressive results achieved in terms of ESG.

As you can see in the chart in the left slide, the current injury frequency rate, an indicator that measures the number of people injured every 1 million hours worked, has been improving substantially and continuously in the last few years, proving that the actions that we have been taking over the last years regarding safety are paying off.

Having said that, we need to remain vigilant as we are reminded from time to time that we work in an industry with flammable liquids, high pressure and temperatures, and subject to the environment, and actually we had a few severe incidents in 2018 that we absolutely need to avoid in the future.

ESG is growing in importance globally, and we, in YPF, have always committed to sustainable practices.

However, we realized that many of our efforts were going unnoticed, and we were being penalized for our lack of proactiveness in communication.

Therefore, in 2018, we hired RobecoSAM to assist our sustainability practices and reporting.

And the Dow Jones Sustainability Index as a benchmark, YPF got a score of 44 in 2018, which was above the oil and gas upstream and integrated industry score average of 42, ranking 22nd among the 57 companies assessed in the index.

We have made significant progress from our 2017 score of only 9.

YPF has a social responsibility to contribute to the carbon dioxide emission reduction targets established in the Paris Agreements, and we are, therefore, targeting a 10% specific emission reduction over the next 5 years.

Besides, we are already IMO 2020 compliant, and more than 70% of the fuels produced at our refineries will be of low-sulfur content by 2023.

We will be one step away by then from reaching 100% compliance.

We will be investing around $1.3 billion during the next 5 years to reduce the sulfur content of our main fuels: gasoline and diesel.

As we presented in our last Investor Day in October, we have created a transformation office formed by 15 high-potential employees from different parts of the organization to lead the company into the objective of becoming more modern and agile, changing the way we do certain things, simplifying processes and preparing ourselves for a different energy industry in the future.

We started this effort more than a year ago and identified 130 concrete projects of which half were defined as critical.

We have projects within all our business units and others that touched the whole organization.

More than 1,000 employees in the company have specific compensation objectives tied with transformation projects.

Each project has concrete milestones.

The progress is reviewed by the executive committee on a monthly basis, and I personally do a deep dive on one project every week.

Some examples of initiatives of this year that we would like to point out are that we have extended real-time well data analysis from 35% to 50% of our total wells.

This way we can monitor wells in realtime from the control rooms and define interventions.

We have worked on improving the entire proppant value chain, expanding the total capacity of the plant and improving logistics, resulting in a 30% cost reduction of sand in dollar terms.

We have optimized our ground fleet by enhancing total transportation capacity and implementing a digital monitoring system.

We have continued to improve the customer journey platform out of retail network by incorporating technology to better satisfy client needs, including online payment methods and a dedicated app.

We're implementing Agile methodology in IT and supply chain.

So these 130 concrete projects for next year are going to be 65 concrete projects so we are refocusing our transformation efforts, what we have deemed as Transformation 2.0, and approximately half of those 65 projects are critical for us.

With that, I would like to pass the presentation on to Sergio to go through a deep explanation of the results of the year.

Thanks, Daniel.

Good morning, everybody.

Let me start with the 2018 financial results highlights.

Revenues reached ARS 435.8 billion, a 72.4% increase compared to 2017, while adjusted EBITDA increased by almost 100%.

However, our adjusted recurring EBITDA, which excludes the profit from the revaluation of our investment in YPS Luz, amounted to ARS 121.5 billion, expanding our recurrent EBITDA margin up to 28% versus 26% of 2017 despite the challenging scenario we just discussed.

Total CapEx of ARS 95.4 billion, resulting in an increase of 64.4% compared to 2017 but was lower in dollar terms as the devaluation of the local currency allotted some investments in pesos as we'll explain later on.

This CapEx amount was exceeded by cash flow from operations.

We reached a total of ARS 125 billion in 2018, consistently with our financial discipline commitment.

The good news of the year is that our P1 reserves increased by 16.2% in 2018, boosted mainly by our shale and [gas] recovery operations.

Our reserve replacement ratio for 2018 reached 178%.

Total hydrocarbon production was down 4.5%, and we'll be going into much more detail on this number.

We'll explain all these numbers in detail as we go through the presentation.

Moving on to reserves in 2018, we were able to achieve a 178% reserve replacement ratio, reaching almost 1.1 billion barrels of oil equivalent of crude reserves, which represent a 16.2% increase compared to 2017.

Net incorporation of reserves amounted to 344 million barrels of oil equivalent per day, of which 254 million came from liquids and 90 million came from natural gas.

This increase in reserves was obtained both in unconventional and conventional fields.

It is worth mentioning that our shale reserves already represent 19% of total reserves.

Let's move now to the analysis of the 2018 production.

Total hydrocarbon production dropped 4.5% vis-à-vis 2017 to 530,000 barrels of oil equivalent per day.

Let's look at this with more detail.

Crude oil production in 2018 remained stable compared to a year ago at 227,000 barrels of oil per day.

The good news here is that our unconventional production growth is now offsetting the conventional production decline, and we expect this trend to continue this year and beyond, providing the source for oil production growth.

Regarding gas, the story here is a little bit different.

As we discussed in previous quarters, during 2018, the good results obtained by YPF and by other operators developed in shale gas resulted in a situation where gas supply is above gas demand, and therefore, we face a situation where we had to curtail some gas production during certain times of the year mainly during the mild weather period.

This resulted in a 4.6% decrease in our natural gas production compared to last year, reaching 42 million cubic meters per day.

Now if we hadn't had to curtail our natural gas production, our total gas production would have been flat, and we would have produced approximately 2.5 million cubic meters per day of additional gas in the year.

This situation will undoubtedly result in the medium and long term as Argentina is gradually shifting from gas importer to gas exporter, but it poses a clear challenge for the short term.

However, we have already made our first step activating some short-term levers in terms of generating more demand, like exporting gas to Chile and installing a small-scale LNG barge that has already arrived at the port of Bahía Blanca, and we commence operations in the third quarter of this year, allowing us to export up to 2.5 million cubic meters per day.

In the meantime, we will focus more on oil production than on gas, and the optionality of our acreage position allow us to do so.

NGL production decreased 23% to a total of 38,800 barrels per day as a consequence of the scheduled maintenance stoppage in our affiliate company, Mega, and its main client, and of course, the lower natural gas production in the period as we just explained.

When we break down the sources of our production, we can observe that shale production contributed with 21,000 additional BOEs per day in the year while tight production showed a decrease of 6,200 BOEs per day mainly related to a lower production of natural gas as explained before.

Finally, it is worth mentioning that, by the end of 2017, we sold our participation in the Cerro Bandera conventional block, which represented an average of 2,300 BOE per day.

Moving now to unconventionals.

Net shale production of the year reached almost 58,000 BOE per day, showing an increase of 57% compared to a year ago.

But this upward trend continues, as by the end of the year, our net shale production increased up to 72,000 BOE per day, almost 25% above the average of the year, proving, once again, where the growth is coming from.

Now if we add to our net shale production the 88,000 BOE per day of tight gas and liquids of total -- our total unconventional production of 146,000 BOEs per day represent now almost 28% of our total production.

In terms of our activity as operator, during 2018, we produced 99,000 BOE per day, and we connected a total of 18 new shale horizontal wells, raising the total number to 676 producing shale wells.

In relation to cost in our shale operations, the development cost in Loma Campana continues in the good trend, reaching during 2018 an average of $11.40 per BOE, while operating expenses continued to improve, too, staying now at $6 per BOE area.

Based on these excellent results, we decided with our partner Chevron to launch what we call Loma Campana Phase 2 development, which includes more [of the] rigs, more wells and more infrastructure.

Now on the left-hand of this slide, we can see that, in addition to the continuous decrease in development cost and OpEx that we have already mentioned, every year, we have been consistently increasing well productivity as well as expected ultimate well recovery.

On the right-hand of the side -- of the slide, we are showing current Loma Campana type curve for 2,500 meter horizontal well length for different zones, and we can see that the actual wells are aligned with those type curves that have been upscaled from the 1,500 type curves, which in turn, are calibrated with the much larger number of existing wells.

We will continue looking at different ways of optimizing our operations, including increasing the length of our laterals, reducing the frac spacing, using high-density completion, increasing the number of wells per pad, using soluble plugs, testing new well designs, using a spudder rig combined with high-spec rig and increasing the proppant plant efficiency.

We are committed to replicate and multiply Loma Campana excellent results by expanding this oil development hub size, and we have taken very concrete actions to achieve that objective.

First, we launched what we call Loma Campana Development Phase 2. This Phase 2 includes increase in the drilling phase by adding new rigs, expanding the treatment facilities and ensuring we have the necessary evacuation route for this new oil.

Loma Campana will be progressively increasing the production level every year until reaching a production plateau of 100,000 barrels of oil per day and 6 million cubic meters per day of associated gas by 2023.

With the knowledge we have today, we expect maintaining this production plateau level for more than 10 years.

2019 activities in Loma Campana will consist in drilling with 4 dedicated rigs plus 1 spudder rig, completing around 40 new long horizontal wells and reaching a total gross production of around 48,000 BOE per day.

We have also launched the expansion of Loma Campana treatment facilities from the current level of 50,000 barrels per day to 100,000 barrels per day to much-expected production levels, and we will be -- soon put in service our new 88-kilometer oil pipeline going from Loma Campana towards the main oil evacuation pipeline.

The initial capacity of this pipeline is 157,000 barrels per day and can be upgraded to 220,000.

The structure is already finished, and we are currently filling it with oil.

2019 budget for Loma Campana will be approximately $670 million contributed half-and-half by partners.

The second step to expand this oil hub is coming from La Amarga Chica block, which is a joint venture 50-50 with Petronas.

During 2018, we finalized a successful 3-year production pilot, and based on the excellent results, we jointly decided to move ahead with the development.

During 2019, we will use their 4 dedicated rigs to drill 39 new long horizontal wells, and the goal is reaching a production of 20,000 BOE per day by the end of this year.

2019 CapEx is estimated at $550 million for this field, contributing half-and-half by partners.

Similarly to Loma Campana, La Amarga Chica will be progressively increasing the production level every year until reaching a plateau of 70,000 barrels of oil per day and 1.2 million cubic meters per day of associated gas by 2023.

With the knowledge we have today, we expect maintaining this production plateau level for approximately 10 years.

The first step in expanding this shale oil hub is coming from Bandurria Sur block, also very near to Loma Campana, where we have been doing the risk in activities with our partner Schlumberger.

Based on the good results and the knowledge we already have from neighboring blocks, also operated by us, we decided to move ahead and accelerate the development of the 1,000 part of the block, which is already the risk, adding 3 dedicated rigs this year to drill 8 new wells in the block while we continue, at the same time, piloting and the risk in the remaining parts of the block.

We will be co-investing $300 million during 2019 to increase production to 9,000 BOE per day.

Although at a much more easy stage of understanding of the area and without all of the risk in place, we believe this block has the potential to reach a production plateau around 60,000 barrels of oil per day and 2.4 million cubic meter of associated gas by 2023.

In the lower part of the slide, we can see the expected pace of drilling and production increase for this year in these 3 fields.

Now this hub expansion does not end up with these 3 blocks.

We have substantially high-quality acreage around them, and we are currently performing the risk in activities to select those that will be part of our next wave of development.

We will be mentioning them along this year, but to give an example, we are currently drilling and we'll be testing this year horizontal shale oil wells south of Loma La Lata.

Finally, we're also focusing in expanding Vaca Muerta boundaries by drilling and testing wells in other potential oil hubs.

We'll be expanding more about this activity throughout the year, but an example, we can mention that we will soon put into production 2 long horizontal and shale oil wells in Bajo del Toro block, a joint venture we have with Equinor.

As Daniel explained at the beginning of the presentation, 2018 was a disruptive year for the natural gas market in Argentina, so we wanted to take -- to talk more about it.

Resolution 46, as it was originally interpreted, resulted in the rapid growth of shale gas production, which helped the country reducing LNG imports during the winter but also resulted in a surplus of gas during the mild season, and as a consequence, we had to curtail production as explained before.

In the chart on the left side of the screen, we can see that our natural gas production, represented by the blue shallow, reached a peak in July and then declined abruptly due to a lack of demand.

These curtailments are represented in the green line of the chart.

The mild weather in May resulted in lower residential demand, forcing us to curtail some production during this period, too.

Moving to the chart of the right, you can see that the 2018 natural gas realization price was also lower than expected.

At the beginning of the year, we were expecting an average price of approximately $5 per 1 million btu, however, we ended the year with an average price $0.50 below our expectation.

This price decrease was mainly driven by lower market prices and lower subsidies.

Market prices were not only affected by the strong devaluation of the year as distribution companies were not able to pass through the full impact to the financial customers but also by the gas auctions launched by CAMMESA for power generation in the second half of the year, where the gas was abandoned.

Regarding subsidies, as we mentioned before, the government announced last month that it would be providing subsidies under Resolution 46 only to the production level that was included at the time the project was approved and will not consider production above this level.

In addition, we had some projects that already counted with the necessary provincial approval but lacked the final approval from the National Secretary of Energy.

Finally, the government also announced that those projects would not be included under Resolution 46, and this forced us to reverse some accruals with a hit in net income of approximately $60 million, which also reduced the total amount of subsidy for the year.

For 2019, we expect gas average prices of approximately $4 per 1 million btu.

In the recent auctions for distribution companies for the gas to be supplied from April '19 to March '20, we were able to contract good volumes at an average price of $4.06 per 1 million btu.

In summary, for the gas market, the negative side is that we have to curtail some production due to lack of demand that prices were lower than expected and that we, finally, got less subsidies than we were expecting.

The consequence of that is that we will be more selective now in terms of gas investment for growth moving forward until we will be able to generate more demand.

On the positive side, the production capacity of shale gas field from Vaca Muerta has been improved, and the government is actively working towards liberalizing this market.

The gas price indications we are seeing are along the lines with expectation we have for long-term shale gas developments.

Moving now to our Downstream business segment.

During 2018, the volume of crude oil processed in our refineries was 284,000 barrels of oil per day, 3.2% lower than 2017, mainly as a result of scheduled maintenance stoppages in our industrial complexes and lower demand of fuel oil from power generation plants as there was more of a liability of natural gas in the period.

Regarding sales, total volumes were slightly above the previous year.

Although demand for our main products, diesel and gasoline, increased, total volumes in the local market decreased by 1% as they were negatively affected by a significant reduction in fuel oil demand and, as we have just explained, well higher exported volumes of jet fuel and LPG drove total export up by 19%.

Now to provide more detail about fuel demands, 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 and diesel demand increased by 3.7% and 4.5%, respectively during the year.

However, as it can be observed, during the last quarter of the year, the market started to show some deterioration in response to the contraction of the economy and the slowdown in consumption with a slight recovery during December.

We also experienced some transfer in demand from premium products to regular, especially in the second half of the year with lower volumes of 7.6% and 4.5% for Infinia gasoline and Infinia diesel, respectively.

Market share for both products continued to be strong in 2018 and above 2017 with 56% in gasoline and 59% in diesel.

Market share for our premium products, Infinia gasoline and Infinia diesel, were 61.5% and 60%, respectively.

As we have been showing along the year, we would like to address one more time what we have been doing in terms of prices and where we are now.

The blue line in the graph represents the evolution of the blended price of our fuels in pesos since the beginning of the year 2019.

We used import parity as the reference where local prices do converge.

The dotted line shows the evolution of import parity, including demand that the blend of domestic biofuels, and the full line shows our average prices.

As it shows in the graph, from April to November and despite the periodic price adjustment that we put in place every month during that period to cope with the combined steep depreciation of the peso against the U.S. dollar and the increase in international prices, we were still below the import parity.

We converged by November and have remained at or slightly above import parity until the end of February.

As we have mentioned, the spike in FX, coupled with an increase in international prices that happened in April, put an increasing pressure to our Downstream margins as prices for gasoline and diesel were reduced in dollar terms.

Local crude oil prices averaged $63 per barrel along the year, almost 11% below brand price as a consequence of negotiations between producers and refiner that occurred in certain times of the year and the recent export tariffs implemented by the government that reduced local crude oil prices.

As a consequence, our Downstream EBITDA per refined barrel, and without considering the revaluation of inventories, decreased to $10.04 in the year, 14% below 2017 but still a healthy margin, given everything that we went through this year.

Now let me focus briefly on our financial results for the full year expressed in U.S. dollars.

Revenues showed a slight 1.7% increase in dollars, almost neutral in terms of fuel sales, impacted possibly by higher exports and negatively by natural gas sales.

Adjusted recurring EBITDA was up by 8.8% in dollars without considering the profit from the revaluation of YPF investment in YPF Luz.

Including this effect, EBITDA was $5 billion or 24% higher.

The total CapEx amounted $3.3 billion in 2018, which is 4.3% lower compared to 2017, reduction that is mainly explained by the dilution of some peso items entering into our CapEx, driven by the currency revaluation.

Upstream CapEx in the year amounted to $2.7 billion being essentially flat compared to 2017.

Drilling and workover represent 70% of the Upstream CapEx, facilities 20%, and exploration and other activities 10%.

During 2018, we drilled and put into production a total of 395 new wells, including 148 targeting shale and tight gas formations.

In Downstream, CapEx was $509 million, of which 59% was in refining, followed by logistics with a 23% share of the total, marketing 15% and, finally, chemicals with a 13%.

Now moving to the last quarter of the year.

Revenues showed a slight reduction of almost 1% in the quarter mainly due to lower prices for our main products, partially offset by higher exports.

Regarding operating costs, lifting our refining cost in dollars decreased by 70% and 26% in absolute terms, reflectively, and royalties were also down by 11%.

Total purchases were down by 0.2% in dollar with a combination of higher imports of fuels and lower crude oil purchases from third party.

As a result, the adjusted EBITDA remains flat in dollar.

It is important to note that this quarter's EBITDA figure was negatively affected by the valuation of inventories, whereas, last year had a positive effect.

The difference between quarters would have been a positive 17% if adjusted for this noncash effect.

Total CapEx for the company amounted to $916 million in the fourth quarter of 2017 (sic) [2018], 6.3% lower compared to the same quarter 2017.

Now let's switch back to Argentine pesos to go over a more detailed analysis of the year.

As we did in previous quarter, we are now focusing the analysis in adjusted EBITDA of our business segments instead of operated income to provide a better understanding on how each business segment contributes with a cash generation of the company, putting aside the FX impact on depreciation and amortization, which are in fact a noncash effect.

Moving on to adjusted EBITDA, it has come up by 82% vis-à-vis 2017.

This was mainly driven by better operating results obtained in our Upstream business segment, which showed an increase of ARS 19 billion compared to a year ago.

Revenues of the segment increased by 80.5% mainly as a result of higher crude oil and natural gas prices in pesos, while on the other hand, cash cost of this segment increased by 71.3%, well below revenue increase as lifting cost and other OpEx were partially diluted by the devaluation.

The Gas & Power segment also showed better operating results of ARS 13.5 billion.

Revenues increased by almost 63%, driven by higher natural gas prices in pesos of 50.7% partially offset by a 6.2% reduction in volumes due to lower production and demand of this product as we explained before and sales from our subsidiary, Metrogas, which also increased by ARS 14.5 billion, which are mainly explained by a 96% increase in prices and that, during 2018, this company recorded an inflation adjustment of ARS 4.2 billion in sales as the peso is the functional currency of this company.

On the other hand, it is worth remembering that, from first quarter 2018, YPF Energía Eléctrica is no longer consolidated in the business and the results, and in 2017, this company had contributed with ARS 1.2 billion EBITDA.

The Downstream segment result show a slight decrease of almost ARS 2.1 billion.

This is basically explained by higher crude oil and by fewer purchases, coupled with higher imports of fuels, which are denominated in dollar.

However, revenues of this business segment managed to increase by 73%, driven by a good demand of our products along the year, despite the weaker demand we started to see after September, coupled with higher prices in pesos, although lower in dollars for gasoline and diesel as explained before; then higher sales of LPG, jet fuel and petrochemical products and higher exports on higher volumes and higher international prices.

It is worth mentioning that the refining cost shows an increase of only 27.3% compared to the 12 months of 2017 as the currency depreciation play an efficient role as well.

In addition, during 2018 and as a consequence of lower depreciation due to higher reserves, the replacement cost came down, resulting in a negative inventory variation of ARS 1.8 billion compared to the positive ARS 3.7 billion of 2017.

The cash generation during 2018 reached a total of ARS 125.1 billion, 74% above the operating cash flow of 2017.

This increase of ARS 53.1 billion was mainly due to an increase in adjusted EBITDA of ARS 54.8 billion and some working capital variations that were almost offset by each other.

This operating cash flow more than exceeded the ARS 88.3 billion CapEx of the period and contributed with the deleverage process.

Finally, this cash generation included in the dollar-denominated sovereign bonds still held in treasury resulted in a strong cash position of ARS 57 billion at the and of 2018.

As we can see in the graph on the right, we managed to fully fund our CapEx program with our own cash generation, reaching a total of ARS 36.8 billion of cumulative free cash flow during the year, covering the ARS 26.3 billion of interest payments of the year.

The previous explained cash position is enough to cover our short-term debt maturities of next year.

It is important to highlight that approximately $900 million of short-term debt are related to trade facilities with an average maturity of 1 year, which we expect to renew during the year, while the only maturity in the capital markets are the CHF 300 million coming due in September this year.

Our leverage ratio stood at 1.7x net debt to recurring adjusted EBITDA, within our 2x target for the year, while the average life of the debt remains in the 6 years area.

The average interest rate in pesos increased to 44.7%, in line with the spike in rates occurred in the second half of the year, while the average cost of our debt in dollars remained stable at 7.4%.

With this, I would like to turn the presentation back to Daniel, who will provide some final remarks and guidance for the year ahead.

Thank you, Sergio.

In this final slide, I would like to address our outlook for 2019.

We have launched a policy for operational excellence last year, and I intend to deepen this effort in 2019 and beyond.

This should result in even better safety metrics in addition to a more efficient use of our assets.

Sustainability remains a core value, and we aim to improve every year our ESG ranking, reflecting the company we are and the one we intend to become.

In terms of production, we will continue focusing in accelerating our shale oil developments, following the outstanding results obtained during 2018.

This was the first year in which our shale oil production growth was enough to offset the decline in conventional fields, which proves this is a path that will lead us to reach a sustainable growth in production.

The strategy here in the shale is to accelerate Loma Campana, replicate its success in La Amarga Chica and Bandurria, which clearly, our first results in both areas point in that direction.

At the same time, we will derisk other clusters within our extensive shale oil acreage.

However, we are not going to neglect our conventional production, and we will continue with our commitment of reducing the natural decline of these fields.

In 2018, we initiated a turnaround of our secondary recovery production, and there is plenty more to improve this year.

An enhanced oil recovery will also be a vector of growth as we move from 2 projects today to over 20 projects in the next 12 months.

Of course, the results from secondary and tertiary are not immediate, but they will be an integral part of our oil production growth over the long term.

As we previously explained, it makes no sense accelerating shale gas production in a scenario of excess supply.

We made a decision this year to delay certain shale gas developments like Rincón del Mangrullo and Aguada de la Arena, where we have excellent wells already in production, others, which have been drilled and will await completion and many more to develop.

I expect that we will keep gas production essentially flat over the next couple of years, likely with some decline this year.

Growth over the next couple of years in natural gas will be coming from a few projects still under the subsidy program from nonoperating blocks and from associated gas in the oil developments, all of these at least offsetting national decline.

This is a diversion from what we were planning last year, but we believe it is the most efficient use of our capital.

In the meantime, we will focus in constructing as much gas locally as possible in order to avoid being cut off in off-peak seasons.

We will also focus on increasing our exports and putting in operation our floating LNG barge in the second half of the year.

However, the game changer here is a large-scale LNG terminal, which we're in the process of finalizing conceptual design and eventually move to front-end engineering this year as part of our consortium that yet needs to be put in place.

With regards to our Downstream segment, the good news is that we started the year without the need to catch up on pricing.

We know that in an inflationary scenario and with a volatile peso, the pass-through to pump prices is always difficult.

But we did it back in 2014, in 2016 and in 2018 after significant evaluations.

And there's no reason to think that we'll not do it again this year.

We have a unique brand and footprint that will allow us to keep our volumes evolving better than local economic activity.

Year-to-date, by the way, it's right in line with our budget for the year in terms of volumes sold.

Finally, let me address our 2019 targets.

At current Brent prices, we are aiming to keep our EBITDA as close to flat as possible.

It is a challenge as we will have lower revenues from natural gas sales.

We expect to invest between $3.5 billion to $4 billion in CapEx this year.

That will represent 10% to 15% higher than last year but is absolutely necessary not to affect the long-term growth that we have outlined in our plan and that we expect to maintain.

Overall production will decline by 2% to 3% this year mainly as a consequence of recent mature asset divestments in the order of 5,000 BOEs per day, lower gas production than what we expected before and a slow start in the Mendoza area.

However, we still believe we can grow production by 5% per year on a sustainable basis.

As we showed during the presentation, shale oil production significantly ramps up during this year and will represent approximately 20% of our total production by year-end, providing the basis for such growth.

Finally, we will maintain our leverage ratio at essentially flat this year as we plan to finance our CapEx program with our internally generated funds.

With that, I would like to address your questions.

Thank you.

(Operator Instructions) Our first question on the line comes from Bruno Montanari from Morgan Stanley.

First question, maybe to Daniel, is about the production target.

I think we were hoping to see an increase in production.

It's totally understandable what's happening with the natural gas industry in Argentina.

So just wondering were it not for the gas curtailment, would we have seen an increase in production?

So if you could mention what do you expect for oil specifically, what type of growth you're seeing this year would be great.

On natural gas, would you say now that the pricing scheme has stabilized in 2019; and if you see any risk of conversion to a local currency pricing instead of U.S. dollar happening at some point in time; and finally, field natural gas, if you could give us an update on the gas receivables you have from the government in terms of timing, what FX level is going to be used, whether the government has been paying in time or not would be great as well.

Well, thank you, Bruno.

Yes, I would say that if we didn't have restrictions on demand for natural gas production -- for natural gas, we'd be approximately 10% higher in 2019 than what we are now projecting.

So with that, clearly, overall production on a BOE basis would be higher in 2019 vis-à-vis 2018.

Regarding Metrogas, it's difficult to say if pricing has been stabilized or not.

I think, in a way, it will depend a lot on how the currency behaves.

There were changes imposed last year and this year in terms of setting the U.S. dollar wellhead prices into pesos at the beginning of each seasonal period.

So there's 2 seasonal periods per year.

So that, in a way, accounts for -- or I think it's a step in the right direction in terms of normalization, if you will.

But I would rather see another year of normalization before calling it a win already.

And in terms of receivables, what we can say is that as of December 31 this year, the receivables with the distribution companies was lower than the ones outstanding as of the end of September.

Half of those receivables have to do with the exchange rate differences generated last year with the devaluation.

And those, the government is going to be paying in 30 installments starting in October of this year.

They will be paying the distribution companies, and the distribution companies are going to be paying the producers like ourselves.

Finally, I don't know if it was part of your question or not, but the big receivable we have regarding natural gas is the subsidy of the plan for 2017.

And what we can say today is that the government has already issued the bonds that we are all going to be receiving.

And just as a reminder, it's also 30 installments starting in February of this year, fully dollarized, that's approximately $750 million for YPF that we are going to be collecting, as I said, on a monthly basis for 30 months.

Our next question online comes from Vicente Falanga from Bradesco.

I had 2 questions, if I may.

First of all, when you mentioned that on your guidance you expect your EBITDA to be close to flat, this is compared to the adjusted level of $4.4 billion in 2018, correct?

Or am I wrong?

And then my second question.

Today, on the paper, there was news saying that the government will subsidize a winter auction due to the lack of supply for a price of $8 to $9 per mcf.

On the other hand, the government will ask the companies that are being subsidized to build the gas pipeline in Vaca Muerta for $1.2 billion.

Just wondering if YPF is expected to participate on this.

Okay.

First, a clarification.

Yes, the EBITDA, flat for this year, is based on the $4.4 billion of EBITDA of last year.

I haven't read the news in detail, but what we knew the government was going to be saying is 2 different things, okay, which are connected but are not dependent, one on the other.

On the one hand, that they will invite people to bid for a new pipeline, which is something that we all know we need in order to satisfy the pent-up demand of gas during the winter season, okay?

And what we can say at this stage is that we are already in discussions with other parties in order to be -- if it's something that we want to be part of it.

But we are absolutely committed and playing a role in everything that allows us to monetize the significant gas resources that we have.

So if this is part of it, we will definitely take a serious look at it.

The second thing, which I don't know if it's what you're referring to, but the second thing that we know the government was going to be issuing is a bid to buy natural gas for the winter over a long-term period of 3 to 5 years, 4 years I think it is.

I don't know if that is what went out in the papers or not.

If they do that, that is absolutely great news for the industry.

It would provide us with additional clarity in terms of pricing going forward.

Having said that, we are working with an assumption of blended average price of natural gas not lower than $4, between $4 and $4.50, which is in line with last year, okay, but clearly below our previous expectations, which were around $5.

We don't have an issue of pricing, okay?

At those levels, what we can say is that all our significant shale gas projects work very nicely because they have breakevens below those levels, okay?

The issue that we have today is more an issue of demand of -- not during the winter, of course, but demand during the off-peak season.

Our next question in line comes from Regis Cardoso from Crédit Suisse.

First, I wanted to touch again on the guidances or outlook for the year of 2019.

If you could, Daniel, explore a little the relationship between CapEx increase or CapEx potentially going to $4 billion and at the same time, you have a production decline in the guidance, so whether this means that a $4 billion EBITDA is only sufficient to keep production flat.

Or is this something specific to 2019?

Then if you could also comment on -- in that case, how would you balance CapEx ramp-up, especially in the unconventional projects you have mentioned.

And how do you balance that with financial leverage and whether you would be expecting to increase financial leverage from the current 1.7x EBITDA, seeing, especially, as you don't forecast an EBITDA growth, right?

And finally, just a few follow-up -- really quick questions.

Is there any impact from hyperinflation accounting to fourth quarter results?

Also if you could clarify if there was any impact from inventory losses on lower international crude prices.

And also if you could explain the difference between Type Well A and Type Well B on Slide 12 of the presentation.

Regis, well that's a bunch of questions.

First, on guidance, what I would say is that production lacks CapEx.

It always does, okay?

So the fact that we are projecting CapEx of $3.4 billion to $4 billion basically provides the basis for production growth in 2020 and onwards.

Remember that we continue to target a 5% annual production growth on a sustainable basis, and there was a graph in the presentation that Sergio went through that clearly showed how, especially in the second half of this year, we connect, I think it's like 50, new horizontal wells in the 3 main Vaca Muerta oil developments.

And that, of course, takes CapEx -- significant CapEx.

But that is the growth in production for 2020 and onwards.

So the answer to your question is at these levels of CapEx, we can definitely grow production.

The thing is that production lacks the investments, comes after the investments.

In terms of that ramp-up and leverage, there's no concession there from our part.

We have always said that we feel comfortable in the 1.5x to 2x debt-to-EBITDA range, and we are staying within that range, okay?

If it's going to remain 1.70 or if it's going to be to 1.85 or 1.60, we don't know.

That's the flexibility that we will always keep as a management team, but the board has always been clear with us in terms of this range of 1.5 to 2x.

And the good news is that we believe that we can grow and that we can grow production 5% per year, staying within this leverage.

So the short answer is no, we don't expect to increase leverage beyond that.

The -- let me skip the 2 accounting questions, and maybe I will ask to repeat them for us and go to the last question.

The difference between the 2 type wells has to be the area of Loma Campana where we do the wells.

We have areas which are much more productive and where we believe that EURs can go to 1 million barrels in the life of the well and another area in which it's not as productive but still incredibly better than where we were coming from, right?

Remember that when we started a few years back, we were talking about, hopefully, accumulating 300,000 barrels of oil in vertical wells, most of which will never end up accumulating that.

And we started with the horizontals with the idea of doubling the amount of oil to be accumulated during the life of a well.

And now we are talking that we go from 750,000 barrels to 1 million barrels of oil.

So it's a big, big improvement.

And we still have not found out what is the sweet spot in terms of the lateral length of the wells.

You know that we drilled a 3,200-meter long lateral this year.

We have plans to go as long as 4,000 meters at some point next year.

But this -- again, it will depend what is the optimum balance between length and therefore, CapEx and productivity of the well.

With that, can you repeat the question regarding hyperinflation and losses, please?

Sure.

And just the 2 questions on accounting is whether fourth quarter results were impacted in any way by hyperinflation accounting?

And also if it was impacted by inventory holding losses, given that international crude prices declined during the quarter, particularly in the Downstream segment, right, which typically holds the crude oil inventories.

Regis, this is Diego.

Regarding your question on the hyperinflation effect, remember that YPF has its functional currencies in dollars, so we do not have an impact there.

Yes, we do have it in our subsidiaries where the functional currency is in pesos.

But when we consolidate all those figures into YPF numbers, it's really a nonmaterial effect.

Actually, we estimate approximately between $40 million to $50 million as a positive effect, but it's not really material for us.

Regarding the other question on holding losses, I think we mentioned during the presentation that the fourth quarter has a holding loss.

And the fourth quarter of the previous year had a holding gain.

And actually, if we were to adjust both quarters for this noncash item, the growth in EBITDA in dollar terms between one quarter and the other would've been 17%, right?

Now the holding gain loss this year doesn't have so much to do with a Brent price decline.

Accounted intuitively, it has to do with reserve growth.

Because with higher reserves, we have lower depreciation.

And depreciation is a big part of the cost of the products that we have in inventories, okay?

So with a lower cost, we had to revalue down those inventories.

And that is what had the effect on the quarter.

Our next question on the line come from Walter Chiarvesio from Santander.

The first one is if you could develop a little bit further on the cost -- OpEx cost decline in Loma Campana.

Is that -- it's just a matter of scale?

And is that -- could be extrapolated in the other blocks?

And how fast could that happen?

That is my first question.

The second one is related to the CapEx breakdown for 2019 because it's below the average guidance for the 5 years plan.

Is that -- has to do with the lower investment in natural gas?

Or probably you already mentioned what is the reason.

And the third question is broadly for the industry.

Because there are many -- or not many -- but some other companies announcing massive developments in some blocks in Vaca Muerta as well.

And I wanted to hear your views on whether there is any potential bottleneck.

Or what are challenges in terms of infrastructure either in the supply chains, for example, in the proppants' provisions -- one side, or on the pipes to evacuate crude oil, especially; and also related to that if there is any plan in YPF to export oil sometimes in the future if there were the case of an oversupply of crude oil for the company.

I understand that you have a deficit.

But probably in some years, that could be reverted.

That -- those are my questions.

Walter, thank you for the questions.

Yes, definitely, the OpEx decline in Loma Campana has to do with the scale.

It also was possibly affected by the evaluation, and there's absolutely no reason why we should not replicate that cost structure in the rest of the Vaca Muerta oil window.

Of course, we have several hundred wells in Loma Campana already and a few dozens and in the others, right?

But long term, the plan that we have as a company is to replicate the success of Loma Campana initially in La Amarga Chica and Bandurria, but as we said during the presentation, in other areas of Vaca Muerta oil -- of the oil window that we are derisking.

In terms of the CapEx for 2019, it is definitely below the guidance that we have provided in the 5-year plan, slightly below.

But the CapEx for this year, 2018, was also below our initial guidance.

So I think it's a combination of some gas projects that we have delayed, as we said during the presentation, and probably a more efficient buildup of infrastructure facilities than the one that we were envisioning 6 months ago.

In terms of Vaca Muerta and the potential massive developments from third parties, well, we cannot comment on third parties.

What we can tell you is that we believe that we are one step ahead of most of the others, and we have all the infrastructure in place.

We are probably the only company that has its own proppant facility with enough capacity to provide for all of our proppant needs even with the acceleration of Vaca Muerta for this year.

We have a very good water duct or aqueduct in place, so we have all the water that we need for the fracking also.

We have the rigs contracted.

We have the fracking bundles contracted.

So frankly, we are not seeing any bottleneck in our operations, at least not in the short term.

Actually, when we look at the midstream, which there are companies there like Oldelval or (inaudible), they are going to be making investments of hundreds of millions of dollars in the next few years that will allow all of us to be able to take all of our production from Neuquén to Bahia Blanca, Buenos Aires and where the refineries are.

Sergio mentioned that we are finalizing the construction of a 90-kilometer pipeline that will take all of the oil that we currently produce and that will be produced in the next several years from Loma Campana to the oil truck lines.

So I'd say the answer is no, we don't see any bottlenecks for us.

We would not be surprised if other people do have bottlenecks that at least result in much higher costs to them, not to us.

In terms of the plan to export oil, we actually did an exportation of oil this year of light crude oil out of Vaca Muerta.

That was because we had a shutdown in one of the plants in one of our refineries, and we had more crude oil inventories than the ones that we were able to process.

But in a way, this proved that we can go back to exporting oil out of Neuquén as the industry did decades ago.

We don't expect significant oil exports right away.

But clearly, the oil in Vaca Muerta or the Neuquén province generally is going from being scarce and therefore, being priced according to import parity to being abundant and therefore, being priced according to export parity.

So yes, if Vaca Muerta takes off, which we believe it will, you will start seeing exports out of Neuquén from us and from third parties.

Of course, as you very well said, Walter, we will first satisfy the needs of our refining complexes before exporting any oil.

Also a question is regarding the shale OpEx costs that we've seen in Loma Campana.

Is that $6 a reasonable reference in the long term?

Could be more decline?

How -- what is your view about it?

Well, the 5-year plan talked about $6 over the next 5 years.

So with -- I think the bar is already high enough.

We can definitely sustain that level.

It'll be a challenge to go way below that level.

Our next question online comes from Luiz Carvalho from UBS.

I have basically 2 questions here, trying to reconcile some data.

In the last slide, you basically mentioned that at current prices, the EBITDA is going to be close to flat while production is likely to drop 2% to 3%, right?

So the first question here is I mean, how can we expect -- and what are the sidelines behind the -- I mean, the assumptions that you're using to actually -- to have on EBITDA -- will affect EBITDA while production is dropping and you have a very challenging environment on the -- say, on natural gas price.

The second one is about production again.

I mean, production this year dropped at 4% to 5%.

Next year, it's likely to drop 2% to 3%.

And I remember I think at the Investor Day, your guidance was to have production over the last 2 years -- said 2018 and 2019, pretty much flat, right?

I mean, the long-term guidance is still unchanged even with a lower, how I can say, stock base, the baseline, if I can put it this way.

And third question, I know that 2019 might be a challenging one because of the macroenvironment in Argentina with the election you had.

But do you have any visibility when the potential JVs are likely to come back and now are potential negotiations on this front?

Luiz, thank you for the questions.

Well, one of the reasons why we believe that we can keep EBITDA close to flat in 2019 is that remember that in 2018, we had several months in which prices of our products were below import parity, below our own budget and therefore, it negatively affected margins, Downstream margins of course, okay?

And we -- luckily, we started this year without any catch-up to make in terms of prices.

So we do expect to expand our Downstream margin, more in line with what we had historically had and not with the $10 per barrel that we had last year.

And that should provide for the EBITDA being close to flat.

In terms of the production drop and how it compares with the numbers that we have discussed in the different Investor Days, yes, you're absolutely right.

We were not envisioning the cuts in gas production last year.

Remember what Sergio said, we had like 2.5 million cubic meters on natural gas ready to be produced but could not be produced and injected basically because of lack of demand.

You can call it that we misestimated demand, and you would be right.

But that is the reason why production was not flat in 2018 vis-à-vis 2017.

And for 2019, it's not that different in terms that we had several projects in our business plan, gas projects in our business plan for the next 5 years that we made a decision of delaying, okay?

They continue to make plenty of sense as long as you can sell the gas 360 days a year.

If you can only sell the gas 180 days or 120 days a year, some of these projects make a little bit less sense.

So what we have decided is that we will deploy capital into natural gas projects at a much lower pace than what we were envisioning when we last spoke like 6 months ago.

And that definitely has an effect in 2019.

Now 2020 and onwards, remember that our guidance was 5% to 7% production growth.

Today, I talked about 5%.

It doesn't mean that I don't feel comfortable that we can reach 7%, but I feel super comfortable that we should be in a position to deliver 5% with all the growth in oil that we're envisioning.

In terms of your last question and regardless of 2019 being a challenging year in Argentina or not, we are not envisioning any significant additional JVs now because we have the acreage that we want to have.

We have plans to derisk that acreage that's not ready to be developed, and we are in a financial position comfortable enough that we do not need third-party funds to accelerate growth.

Moreover, if we have -- we are redeploying capital from gas into oil, so that means that we have more capital available for our oily projects.

So you should not assume any short-term JVs in Vaca Muerta.

We are not working on new ones at this stage.

I would say we are more buyers of acreage than sellers of acreage for oil in Vaca Muerta today.

Our next question on the line comes from Lilyanna Yang from HSBC.

I actually have 2 questions.

One is on the LNG plant and the status.

Can you give a little bit more color about how you see plans evolving there on the LNG front?

And the other question is on the ESG and the good improvement.

That's great, but could you give us an updated status about the Maxus dispute?

Thank you, Lily.

Well, on the LNG plant, unfortunately, there's not much more that we can say.

We have done conceptual engineering already.

We believe we have a feasibility study that we are going to be sharing with other producers and other players in Argentina and globally that have already expressed interest in being part of our project.

We do not intend to have a controlling or a majority position in an LNG facility.

All we want is to make sure that, that project, if it makes sense, happens because that will be the only way that we can develop our Vaca Muerta shale gas acreage for the long term.

Of course, because of the size of something like this, as soon as we have any news, we'll make sure to share it with anyone.

But as of today, all we can say is that we have a pretty good idea of what is the project that should be done.

But we will share that with other potential investors before making it public.

Regarding the question on Maxus, all we can say and actually, it is part of the financial statement and was on the news a week or so ago, is that unfortunately, we have filed several motions to dismiss on the trial that were denied by the judge.

That doesn't change, in any way, the outcome of the trial because it has not even started.

But that's the only news in terms of litigation, in terms of the process so far.

We believe that we have a case.

In my opinion, it has absolutely nothing to do with the ESG because we were not part of that contamination.

YPF acquired that company, well, almost 30 years ago or 25 years ago.

And while we were at the helm, there was never any contamination at all.

The contamination goes all the way back like 50, 70 years ago.

But that's all the news that we have on Maxus.

Our next question on line comes from Pedro Medeiros from Citi.

Congratulations with the continuous progress in Vaca Muerta development in terms of costs and productivity.

So this is one of the calls I have actually many follow-ups to previous questions, okay?

And first, I wanted to come back to the guidance for 2019.

And then you talked about how refining profits should be the main source of recouping potential losses when you think on a year-on-year basis in terms of prices and then production decline.

But I also wanted to understand whether you're counting with improvements in your production cost to actually compose that guidance.

And for the guidance itself, you talked about declining production of 2% to 3%.

But would you mind sharing your view of exits, production growth rates?

There's a significant amount of new capacity and new wells being put out in production from Vaca Muerta in the second half of 2019 especially on the oil front.

So anything or any color you could give on fourth quarter 2019 over fourth quarter 2018 exit production growth rates would be very interesting to hear.

The second question is on Slide 12, you have outlined the evolution in type curves in Loma Campana.

And I know you already talked a bit about those type curves, but I was wondering whether you could share some of the early results from the 3,000-meter lateral wells that were drilled in Loma Campana and put in production in 2018.

My third question is coming back to the commercial LNG solution that you have just commented on how you already have a pretty good sense of the engineering and what the project could look like, but I just wanted to understand if there is any sort of like preliminary potential schedule of when a solution like that could come to the market and whether the kind of solution you guys are looking for would be an export hub through Bahia Blanca or from Chile into a commercial-sized facility.

And my last question, Daniel, is could you comment a bit on the progress made in plans to divest from assets in power and natural gas distribution?

Pedro, well, let me start from bottoms up, from the end.

In terms of progress on asset sales, you mentioned gas distribution.

We are not actively doing anything as we speak until the gas market generally and specifically for the LDCs clears and it's -- we have something more concrete eventually to offer to a potential investor.

So you should not expect anything right away there.

Obviously, the strategy continues to be the one of maximizing the value of the assets for YPF.

And those assets, which we believe can be worth more in the hands of someone else than in our own, we are willing to divest.

And that's where Metrogas eventually could fall into.

But you also mentioned power.

In power, we are not working and we have never been working on any divestment.

What we have been doing is the capitalization of our power generation subsidiary, of which we own 75%.

But we would be willing to be diluted -- but not to sell our shares, to be diluted if a third party comes in with more equity at the right valuation that would allow YPF Luz to accelerate its growth plan going forward.

Your previous question regarding the LNG unfortunately, I understand the question.

And I understand why you're asking the question.

But unfortunately, we are not in a position to share absolutely anything regarding this until we share it with people that are interested in eventually investing or co-investing in this project.

So when we have news, we'll let you know.

In the meantime, all we can say is that we are interested in finding the right project and making sure that the right project occurs and eventually, taking a small equity stake, if we have to, in that project.

And that's all we could say.

Regarding the 3,000-meter long well that we have drilled, we haven't disclosed any figures so far.

What we can tell you is that the results were good, were okay and pointing to similar development cost than the 2,500-meter-long lateral, so not evident, yet, the improvement of going to 3,000.

But again, it's just one well.

So it is likely that we will drill more of those that we -- as I said, that we have planned to drill even 4,000-meter-long laterals in order to find what is the sweet spot.

And the sweet spot is not necessarily the same in different concession areas or even different areas within one block, okay?

As we showed in our well type curve for Loma Campana, we might have -- we actually do have several well type curves in each of the blocks that we operate.

And there's -- unfortunately, there's nothing more that we can say about that.

And then you had a question regarding guidance.

What was that, Pedro?

Yes.

The guidance -- the question on guidance was whether you're counting with any improvement on production costs for 2019 and if you could share some color on your expectations for exit production growth rates.

You talked about average of the year of 2%, 3% decline.

But there is significant new amount of activity in the second half in terms of new wells being plugged from the new projects and from Loma Campana.

So I just wanted to understand if you're forecasting growth on a fourth-quarter-over-fourth-quarter basis?

Well, clearly, by the fourth quarter of this year, we will already be growing crude oil production.

That's all we can say.

We are not going to be providing any guidance.

We never do on a quarter-per-quarter basis.

The other thing that we said and we can repeat is that given all that activity that you referenced to in the shale, shale oil production is going to be approximately 20% of crude oil production by the end of the year.

So that's another relevant data point.

And in terms of OpEx for the year, we are not assuming any significant savings or cost reductions vis-à-vis last year.

Remember that last year, we had the positive impact of the devaluation.

And what we intend is to keep all of that -- all of those savings for the future, structurally, if I can say.

But we are not assuming a significant reduction in costs when we say that we expect to have our EBITDA approximately flat next year.

And our final question comes from Daniel Guardiola from BTG.

I have couple of quick ones here given the fact that this is the last question.

My first question is regarding reserves.

And I would like to know if you could please share with us part of the details with respect to the additional reserves.

And more specifically, I would like to understand the contribution from unconventional basins before the implementation of secondary recovery mix and the effect that higher prices had on the additional reserves.

So that's my first question.

And my second question is regarding the upcoming elections, governor elections in Neuquén.

And I would like to know your thoughts on potential implication for the development of Vaca Muerta coming from the outcome of these elections.

Well, on reserves, the breakdown that we can provide at this stage is that unconventionals or shale represents approximately 20% of our proven reserves and that the increase in reserves from last year to this year comes from both the good performance in unconventionals generally and in some conventional fields but also with the improved economics of all of the fields.

It's not just about price.

It's price and cost.

But clearly, improved economics played a role.

And regarding your second question on the elections, of course, we are not going to be commenting on elections, which are 48 hours away.

All we can say is that Vaca Muerta seems to be one of the few things in Argentina that everybody agrees on, that it's a good part of the future.

A good part of our future lies on developing Vaca Muerta, and that's widely understood at a national and provincial levels in all different parties.

Well, if there's nothing else, thank you, Daniel, for the last question and everybody else for all the questions and keeping up with us during this long call.

If there's any follow-up, please feel free to call either Sergio, Diego, Pablo or myself anytime.

Have a great day, a good weekend.

Bye.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.