YPF SA (YPF) 2019 Q1 法說會逐字稿

Welcome to the Q1 2019 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 Sergio Giorgi.

You may begin.

Great.

Thank you, Richard.

Good morning, ladies and gentlemen.

I'm Sergio Giorgi, Vice President of Strategy, Business Development and Investor Relations for YPF.

I would like to thank you for joining us today.

In this occasion, we'll present YPF's 2019 first quarter results.

Before starting the presentation, let me first give you an update on the recent changes in our Investor Relations' structure.

Diego Celaá, who has been our IR manager for more than 4 years, is moving to another position within the company, while Ignacio Rostagno has been designated as the new IR manager.

Ignacio has been working in the finance department for 5 years in YPF, and he will assume Diego's responsibilities from now on.

On this occasion, the 3 of us will be conducting the presentation.

I wish Diego and Ignacio the best of luck in their new positions.

Having said that, during the presentation, we will go through the main aspects and events that explain our first quarter results.

I will share -- and share our perspective for the year ahead before we start taking questions.

We will be making forward-looking statements, so I ask you to carefully review the cautionary statement on Slide 2. Also, our financial statement 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.

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

During the first quarter, the overall activity level in Argentina continued cooling down and the volatility in the peso combined with high inflation [derived] in a further deterioration of the economy.

International oil prices have gone up, which under normal conditions, would have been a good thing for us.

In this context, it made it tougher for our local prices to keep up with international prices.

Similar to what happened last year, we're adjusting prices gradually.

And our prices policy considers several factors like international prices, refining and distribution costs, biofuel costs, increasing local taxes, the premium blend, competition behavior and of course, what our customer can pay for the product we sell.

We will show later on where we are on this subject.

In regards to market, we continue seeing in this quarter the effect of the significant increase in the local gas supply as a result of the incentive price program.

This effect, combined with the mild weather and weaker demand, resulted in a negative impact in our production figures for the first quarter and as we said before, resulted in rethinking our investment level in natural gas development as well as activating short, medium and long-term levers to increased demand.

Despite the complex scenario, the company has managed maintaining positive cash flow without affecting our net debt [in our investment written] in unconventional oil production, while at the same time working on those levers to increase gas demand and positioning the company in other new potential growth areas like the deep offshore we will be showing you.

Before moving on to our financial results, as on every quarterly call, we would like to share with you our safety and ESG metrics and action plan.

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

These figures are currently the lowest of the last 10 years.

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 subject to the environment.

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

As we mentioned before, in 2018, we hired RobecoSAM to assess our sustainability practices and reporting.

Using 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.

And ranked 22nd among the 57 companies assessed in that index.

But this is a moving target so our teams are consistently working to identify improvement areas so we should [have] an internal objective for this year, which is improving 10% our 2018 scoring.

YPF has a social responsibility to contribute to the carbon dioxide emission reduction targets, establishing the parties' agreements.

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 fewer producers of our refineries will be low sulfur content by 2023, and we will be one step away from reaching 100% promptly thereafter.

Our 2018 sustainability report will be available in mid-August.

Now, Diego will walk you through our financial results.

Please, Diego, go ahead.

I will resume at the end of the presentation for conclusions and then we'll open the Q&A session.

Thank you, Sergio, and good morning, everybody.

Now let me start with our first quarter results highlights.

Revenues were up by 72.6% in pesos, and our adjusted EBITDA amounted ARS 39.9 billion or 62.6% reaching a margin of 30%.

Please remember that Q1 2018 adjusted EBITDA excludes the profit from the revaluation of our investment in YPF Luz.

Also, as of the effective date of January 1, 2019, the group has applied the guidelines of IFRS 16, which effects are not included in our adjusted EBITDA and financial debt.

Total CapEx of ARS 30.4 billion resulted in an increase of 104.2% compared to Q1 2018.

This CapEx amount was exceeded by the cash flow from operations, which reached a total of ARS 42.6 billion in Q1 2018, consistent with our financial discipline commitment.

Total hydrocarbon production was 11.5% below Q1 2018, and we'll go into much more detail on this number later on.

Net shale on production went up by 63.3%, reaching 30,500 barrels of oil per day.

We will explain all these figures -- all these numbers in detail as we go through the presentation.

Moving into our main financial figures measuring U.S. dollars.

In the first quarter, the FX variation was almost 99% when compared with the same quarter of 2018.

Revenues show a reduction of 14% mainly driven by lower prices in dollars for our main products, gasoline and diesel, and a 47% on our natural gas revenues as a result of lower volumes and a 20% price reduction.

In turn, exports show a slight increase on higher exported volumes.

Regarding operating costs, lifting and refining costs in dollars decreased by 10.3% and [32.3%] in absolute terms respectively as the devaluation played a beneficial role.

Royalties, which is the only cost component fully denominated in dollars were down by 28.4% driven by the lower natural gas and crude oil prices in dollars, coupled with the lower production of the period.

In turn, crude oil purchases were down 17.4% in dollars, as we processed in our refineries lower levels of crude than a year ago while our own crude oil production remained stable.

As a result, adjusted EBITDA was down by 18% in dollars, maintaining EBITDA margins in the 30% level.

Finally, total CapEx for the company was $779 million, almost 3% compared to the first quarter of 2018.

Upstream CapEx in Q1 2019 amounted to $636 million, 4.1% lower than Q1 2018, drilling [our cover] represented as 68% of the upstream CapEx followed by build up of facilities with a 23% share of the total; and exploration and other activities, 9%.

This quarter, we drilled and put into production a total of 99 new wells including 29 -- 21 new wells -- new shale wells, another 3 wells in tight gas formations.

In downstream, CapEx amounted $91 million, 43% higher than Q1 2018, of which 46% was in refining followed by logistics with a 39% share of the total, marketing representing 10%.

And finally, chemicals with 5%.

Now let me switch back to Argentine pesos to go over the more detailed analysis of the quarter.

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

Moving on to adjusted EBITDA, it has come up by 63% compared with the first quarter of 2018.

This was mainly driven by the better operating results obtained in our downstream business segment, which showed an increase in ARS 11 billion compared to a year ago.

Revenues of this segment increased by 80.5% driven by higher gasoline and diesel sales on higher prices in pesos although lower [in dollar] and a stable demand despite the local market contraction.

Also, higher sales of jet fuels, LPG, fertilizers, lubricants and petrochemical products and finally, higher exports on higher volumes and higher prices in pesos.

In turn, cost of this business segment reported a increase of 69%, basically explained by higher crude oil and by our fuel purchases, which are denominated in dollars and a 54% increase in refining cost.

The Upstream segment results showed an increase of ARS 3.7 billion in adjusted EBITDA with an increase of 43.5% in revenues driven by higher crude oil and natural gas prices in pesos while cash costs of this business segment increased by 65% above revenue increase resulting in margin erosion.

The Gas & Power segment show a decrease of ARS 0.4 billion mainly affected by lower revenues from the LNG regasification service as the contract with [a regasification vessel] operating at the Bahia Blanca terminal expired and was not renewed.

The cash generation in the first quarter of the year reached a total of ARS 42.6 billion, doubling the operating cash flow of a year ago.

This increase of ARS 21.2 billion was mainly due to an increase in EBITDA of ARS 17.7 billion on lower working capital needs.

The operating cash flow more than exceeded the ARS 30.5 billion CapEx of the period, supporting our financial discipline commitment.

Finally, this cash generation including short and medium-term liquid cash investments result in a strong cash position of ARS 68.2 billion at the end of March 2019.

In April, therefore, not included in these figures, we started collecting installments of the bond issued by the government for the 2017 [plan gas] accruals.

So far, we have received approximately USD 100 million of the total of $760 million including our working capital.

We'll collect an additional $200 million along the rest of year 2019.

As we can see in the graph on the right hand, we are fully funding our CapEx program with our own cash generation reaching a total of ARS 12.1 billion of cumulative free cash flow during the first 3 months of the year.

Also enough to afford the ARS 8.6 billion of interest payments.

The previously explained cash position is enough to cover our short-term maturities of the year.

As we mentioned in our previous earnings calls, significant amount of 2019 debt maturities are related to trade facilities, which we have been rolling over and expect to continue doing so every year.

In addition, this year, the relevant maturity in the capital market are the CHF 300 million coming due in September.

Looking forward, 2020 is a light year in terms of maturity and more than half of those maturities are denominated in pesos.

Our leverage ratio stood at 1.74x net debt to 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 decreased to 43.2%, while the average cost of our debt in dollars remained stable at 7.4%.

With this, I'd like to ask Ignacio to continue with the analysis of the quarter's production, and I also wish him good luck in his new role position.

Thank you, Diego.

Good morning, everybody, and thanks, Sergio.

I'm very happy to join the team, acting in this position.

I look forward to meeting you soon.

Now moving on to analysis of the quarter's production.

Total hydrocarbon production dropped 11.5% vis-à-vis a year ago to 486,500 barrels of oil equivalent per day.

Let's look at this with more detail.

Crude production in the quarter remained stable compared to a year ago at 226,000 barrels of oil per day.

It's worth mentioning that due to mature fields divestment performed at the end of 2018 in Neuquén, Río Negro provinces, we lost 2,100 barrels of oil, so if we correct for that, our oil production would have been slightly up.

The good news here is that our shale oil production growth is now offsetting, like I mentioned, our production decline and we expect this trend to continue along the year and beyond.

Procurements in natural gas production kept on appearing during this first quarter.

This resulted in a 20.6% decrease in our natural gas production compared to the first quarter of 2018, reaching 35 million cubic meters per day.

Now if we hadn't had to curtail our natural gas production for this quarter, it would have been only 1.3% below Q1 2018 figures.

As already mentioned by Sergio, considering this new reality for the gas market that we believe will be there for some time, we took a few years of mitigation measures.

As a first step from Q1 this year, we are limiting investments in natural gas to [shaft] those molecules that we are confident we would be able to sell in the market.

In addition, we're activating several short-term and medium long-term levers to increase gas demand.

For example, in Q1, we exported an average of 1.3 million cubic meters per day to Chile, while in April, the volume exported increased to 3.3 million cubic meters per day.

Moreover, we will be exporting LNG by the third quarter of this year.

Representing an additional 2.5 million cubic meters per day.

The Tango FLNG barge is already in place and being commissioned.

We have performed the cool down of the tanks, and we are already testing the liquefying process.

We're also working in increasing the underground gas storage to reduce the big [win] between winter and summer productions.

We also continue working towards a long-term solution to increase gas demand, which is a sizeable LNG terminal, for which we expect to give more details by the end of the year.

In line with the lower natural gas production, NGL production decreased 11.2% to a total of 41,700 barrels per day.

When we break down the sources of our total production, we can observe that shale production contributed with 22,000 additional BOEs per day, while tight production showed a decrease of 34,000 BOEs per day mainly related to a lower production of natural gas as explained before.

In the conventional side, we continue focusing in improvements in secondary recovery and expansion of EOR pilots to improve the recovery factor of our crude oil mature fields.

Moving now to unconventionals.

Net shale production in the first quarter of the year reached 71,000 BOEs per day, showing an increase of 45% compared to a year ago.

More important, in the current environment, net shale oil production showed an increase of 63.3% compared to Q1 2018.

Shale oil represents 13.5% of our total crude oil production.

I will give you some details on how we are performing in shale oil in a few minutes.

In terms of our activity as operator, during the quarter, we produced a total of 115,900 BOEs per day, and connected a total of 21 new shale horizontal wells, raising the total to 697 producing shale wells.

It is worth mentioning that if we [add those wells] and connected by our partners in fields, we are not operators, total producing wells increase to 747.

Now if we add to our net shale production, the 65,000 BOEs per day of tight gas and liquids, our total unconventional production of 136,000 BOEs per day represents almost 28% of our total production.

The development costs in our Loma Campana shale oil development continue coming down, being now in the $10 per BOE area, in line with the target for the year.

While operating expenses continued to improve to stay now at around $5.5 per BOE.

Now let's do a more general update concerning our shale oil activities in Vaca Muerta.

YPF owns 30%, Vaca Muerta's acreage and our activity represents around 40% of the total activity in the play.

We have a good split between shale gas and shale oil acreage, but also in terms of being at a 100% participation or in JV as well as being operators and not operators.

This situation, combined with a short-cycle type of investment that a shale play represents, provides us flexibility and optionality.

We currently have 14 active drilling rigs in Vaca Muerta and we expect to have 18 in operation by the end of 2019.

Our total gross investment in the play this year as operators will be around $2 billion, positioning YPF to there with its partner among the top 10 in the worldwide ranking of shale investors.

I'm very comfortable as #1 shale investor outside the USA.

We are planning to drill more than 100 horizontal wells this year, and as we mentioned before, our focus has shifted from gas to oil.

We have already shown our results in Loma Campana development.

During the last call, we said that the main challenge for a traditional shale oil development that is La Amarga Chica, the JV we have with Petronas, and Bandurria Sur, the JV we have with Schlumberger, was achieving there as quick as possible the same metrics that those we were having in the Loma Campana.

Whereas it is still too early to confirm the trend, we can affirm that just few months after starting those developments, we are already seeing a development cost level similar to the one we had in Loma Campana for 2018.

That is $11 per BOE.

But as we already showed, this happens to be a moving target as Loma Campana development cost keeps on reducing and is now around 10% per BOE -- $10 per BOE.

Setting breakeven practice for this field including a hurdle rate of 13% in the range of $40 to $35 per barrel.

We are well-oriented to achieve by year-end the targets in oil production we set at the beginning of the year for these 3 figures.

On the technical side, we continue drilling horizontal wells from multiple well paths with horizontal lengths, longer than 2,500 meters, there are 3,200 meters oil producing and we even have pilots for 4,000 meters.

We are using shales [during] control from our central control room.

We have reduced frac spacing to 60 meters and based on positive pilots, we are using more and more high density completion fracs, pumping more water and sand which result in higher productivities.

We are consistently performing more than 6 fractures per day.

From January to March this year, we pumped a similar quantity of sand that we pumped from January to June last year.

We will be investing around $48 million this year to expand our plant capacity from the current 360,000 tons per year to 1 million tons per year, and we are also using sandbox for the last mile logistics.

Our efforts do not stop there as we're also investing and working hard to prepare the next wave of shale oil development.

In fact, we are working with our partners, Shell in the Bajada de Añelo block and with our partners Total, Wintershall and PAE in San Roque block.

Performing pilots that is successful might lead to launch new shale oil developments by 2020 and 2021.

We are performing a shale oil pilot in Loma La Lata Oeste near Loma Campana, which we own 100%, for which we will start having results soon.

Finally, we continue pushing the boundaries of Vaca Muerta as we're also performing exploration in the north hub, particularly in 2 blocks: Bajo del Toro and Chihuido.

The first of these 2 blocks is a Chevy 50-50 with Equinor, while we drill and put into production 2 horizontal wells with very good results in terms of shale oil production, so the next step will be increasing the size of the pilot, and then we might be launching a new development there by 2021.

Similarly, if we have good results in Chihuido block, a same pattern will follow with the advantage that this is already an existing conventional field with declining production.

So the infrastructure for treating and exporting the hydrocarbon is already in place to be used.

Finally, we are also performing new exploration in our Vaca Muerta blocks, potentially expanding even more the boundaries and we will be detailing this during the year.

We are also ensuring that we will have the necessary infrastructure to guarantee we can treat and evacuate all the hydrocarbon being produced and yet to be produced.

Indeed, we have launched the Loma Campana treatment facility upgrades to increase the capacity from 75,000 to 113,000 barrels per day, which we expect to have it ready by the end of the year.

We have also launched the construction of the new La Amarga Chica treatment facility, that will be finished by the second quarter of 2020 and will have a capacity of 50,000 barrels per day.

And next year, we will launch the construction of Bandurria Sur treatment facility, which will have the same capacity.

But this does not stop here.

Because to evacuate all these hydrocarbons, we also constructed an 88 kilometer, 18 inches oil pipeline going from Loma Campana towards Oldelval export system.

This pipeline of which we have 55% ownership and it's already in service, increased the transportation capacity by 157,000 barrels per day.

Ensuring that every drop of oil we produce from Vaca Muerta can find its way here to our refineries or our -- or to exports.

Actually, last February and for the first time in 10 years, we exported [a full] oil cargo from Neuquina basin.

Now let's move for a while from our current Vaca Muerta growth area to have a different look at what could be another relevant potential new growth area for the future.

This is the offshore.

Currently, the offshore activity represents 17% and 2% of Argentina's gas and oil production, respectively, with the main activity situated in the south of the country.

YPF is present as a nonoperator producer, so the 50-50 JV we have with ENAP, a Chilean company, in the [Manantial-Espejo] in the south of Santa Cruz province.

And YPF believe that there are potential new growth areas in the offshore and therefore we have defined some time ago a strategy and a position in the company over those potential growth areas.

This anticipation lead us to obtain 100% of what we believe is a very promising block in the Argentine Atlantic basin.

The [CAN-10] block, which in our view could be the backbone of our position in the Atlantic [margin].

This deep offshore block has 15,000 square kilometer size and around 3 billion barrels of potential resources.

We have 2 exploration periods of 4 years each on this block.

With very low commitments in the first period, positioning work is around $50 million.

We already received expression of interest from some renowned international players that are interested in showing us to explore this prolific block.

Additionally, during the recent offshore round organized by the Secretary of Energy, we managed to get 2 additional blocks in the Atlantic basin, blocks [CAN-102 and CAN-100] both in partnerships with Equinor and with low commitments for the first 4 years around $21 million.

We also managed getting one more block in the Magallanes basin, block [MLO-123].

This time in partnership with Total and with Equinor, also with low commitments for the first 4 years at around $11 million.

It is important to point out that the bidding round organized by the Secretary of Energy, attracted a strong interest of global players and the total commitments were just below $1 billion.

More interesting, some of these international players position themselves besides our block [CAN-100] somehow valorizing our early positioning.

To summarize, we have achieved building a very attractive offshore portfolio in a potential new growth area with limited financial exposure and with first level partnerships.

We will keep on consolidating our offshore strategy based on these blocks.

Moving now to our Downstream business segment.

During the first quarter of 2019, we faced a minor incident in our La Plata refinery that disabled the topping unit for 40 days.

Decreasing its crude oil processing capacity.

As a result, the utilization rate of our refineries resulted 7.5% below of utilization capacity of the first quarter of 2018, reaching a total of 269,000 barrels of crude oil processed per day.

Regarding sales, total volumes were slightly below the same period a year ago.

Although demand for our main products, diesel and gasoline remain essentially flat, total volumes in the local market decreased by 1.2% driven by a significant reduction in LPG, coal and asphalt demand as a result of lower economic activity, while higher exported volumes of jet fuel and virgin naphtha drove total export up by 1.6%.

Now to provide more detail about U.S. demand.

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.

Beginning in the second half of 2018, the market started to show some deterioration in response to the contraction of the economy and the slowdown in consumption.

In this scenario, gasoline and diesel demand in the overall market declined by 5.6% and 3.7%, respectively, while our fuel sales remained almost flat, resulting in a higher market share of around 58% for both products.

In addition, market share for our premium products in premium gasoline and in premium diesel remained strong at 62.5% and 60.9%, respectively.

Going deeper in analysis, gasoline sales reported a slight decrease of 0.7% driven by a lower demand for our premium gasoline with a decline of 23% in volumes, partially offset by higher volumes of regular gasoline.

In turn, diesel demand remained flat in the quarter.

However, it is good to note that in this case, the sales of the premium products, Infinia Diesel, reported an increase of 2.5%.

Despite the lower prices in dollars for gasoline and diesel, our downstream adjusted EBITDA per refined barrel performed well, reaching $16.7 in this quarter.

This good metric derived from the impact of local crude oil prices as a consequence of a lower international Brent oil price and the current export tax applied to all products and services, which resulted in a lower export parity price for purchases of local crude oil.

We use import parity as a reference where local prices should converge.

The dotted line shows the evolution of import parity and the full line represents the evolution of the blended price of our fuels in pesos since the beginning of the year 2018.

But as Sergio mentioned, our pricing policy considers several other factors in addition to the import parity, like refining and distribution cost, the mandatory blend of domestic biofuels, the increase in local taxes, the premium blend, the competition behavior and of course, what our customers can pay for the products we sell.

Indeed, to avoid a sharp negative effect in our client base and the overall economic activity, we tend to adjust our prices gradually, similarly to what we have done last year.

We know we are going through our latest scenario with a soft demand where the pass-through to prices is not an easy task.

Despite the various price adjustments, we are still below the import parity.

As to date, we are 5% to 10% below and we feel confident we will keep on doing these gradual adjustments as we have done in the past.

With this, I would like to turn the presentation back to Sergio, who will provide some final remarks before opening up for questions.

Thanks very much, Ignacio.

In summary, this quarter, we continue improving our safety track record and describe sustainability as a core value for the company.

While at the same time we remain vigilant and willing to continue improving on both aspects.

In terms of production, we have shifted our focus to accelerating our shale oil development while at the same time, we keep on reducing the development on operational costs.

Early results in the 2 new development fields are showing that we might be able to replicate Loma Campana productivity and costs at a pace which might be faster than the one we originally expected.

We are confident that we can achieve the oil production targets we set for our 3 shale oil developments for this year.

We're also having very good results in our Vaca Muerta shale oil pilots and expanding the Vaca Muerta boundary, so the portfolio of future developments looks also in very good shape as well as infrastructure means to evacuate the production.

On the contrary, for the gas side, we will temporarily reduce in the investment level until we can increase the demand using all the short and medium-term levers we already mentioned.

And this will have a negative impact on the 5-year production plan we originally planned for this fluid.

We will give you more updates along the year.

We have also managed positioning YPF in a potential new growth area, which is the offshore, and we have done so with international renowned partners with low commitments.

The low unexpected natural gas production and revenues have affected our overall production and EBITDA figure for this quarter.

Margins in the Downstream sector were strong during the first quarter, but further looking for this year, we are seeing a contraction in this figure.

As similarly to what happened last year we are adjusting prices gradually to cope with international parity increase, but also with the macroeconomic situation, the softened demand and of course what our customer can pay for the products we sell.

We had a strong cash generation this quarter, exceeding our investments and we are in a good position to face CapEx commitments and to cover short-term debt.

We remain committed to keep a strict financial discipline and we'll be monitoring continuously the market to be able to react as soon as necessary.

Now considering all the elements we have already shared with you, we would like to make a final point on the 2019 guidance we said in our last webcast.

Basing our current prognosis, we expect to be in the lower end of the $3.5 billion to $4 billion CapEx that we already mentioned, and to remain in the minus 2%, minus 3% production range we set for this year.

It is challenging but doable.

Finally, we are modifying the EBITDA target to a level close to $4 billion.

With that, we would like to address your questions.

(Operator Instructions) Our first question online comes from Mr. Frank McGann from Bank of America.

Two questions if I could.

One is just in looking at the gas situation, the quarter was unusually negative and reflected both weak prices and weak volumes as you've highlighted.

As you look out over the next couple of quarters with the LNG exports that you'll have, even though they're limited, with the potential for expansion you indicated in storage -- and perhaps you could provide a little bit more detail on how big that would be.

But do you think that volumes relative to what you had in the first quarter can see some improvement, as we go through the rest of this year and perhaps into next year?

And secondly, how are you seeing prices behaving as you go through the next several quarters into the colder months and how do you think the average price will be then perhaps for the full year?

And then, one additional question if I might.

The tax line had some very large charges and I understand those are related to some provisions that were made for amounts related to changes in abandonment costs, taxation, et cetera.

I was wondering if you could provide a little bit more details on that and how that might affect -- or how those taxes would be paid over the next several years?

Thank you, Frank.

So considering the gas situation, yes, indeed the restrictions this quarter amounted 9.8 million cubic meters, which is much higher than we had last quarter -- this quarter last year.

Now we believe that the next 2 quarters will have much less impacts on restriction, probably next quarter reducing 30% to 40% this value.

And of course, reducing during the winter period.

We might have the restriction coming back by the end of the year, and as we said before, we are still exporting gas to Chile, and we are going to kick-in the LNG exports by the third quarter of this year and this will have additional volume.

Now the second question was related to average price.

So the average price for this quarter was around $3.72 per million BTU, and that includes $0.20 of subsidies with -- this value represents a 20% reduction from the $4.65 we had 1 year ago.

So subsidies are fading out.

Their impact on the gas price is coming lower.

And the current pricing is somehow aligned with the structural gas excess that we have.

Now moving forward, we expect that some operators restrict some investments in gas, as we are doing, and the market will find some new equilibrium, right?

And the third question was related to tax, so I will let Diego answer that.

Hello, Frank.

Well, this quarter remember that in periods where we have a high devaluation, first, we have these -- all these financial and currency issues on -- we have the dollar as a financial currency.

And all the assets and liabilities that we have there in our balance sheet when we convert that into pesos, that actually has a gain that doesn't go to the P&L.

But actually goes to -- we have to account a deferred tax for that.

So with devaluation being so high this period, we have a significant deferred tax in this period.

And particularly in this case, we have 2 effects, different effects.

One is the revaluation tax that we have actually [added] there.

In that case, we decided to [add it] on our assets -- part of our assets.

That means that we have -- we will be paying approximately $100 million on a down payment -- initial down payment.

But that will have a significant benefit for YPF because it will allow us to reduce in future exercises, at least in peso terms, ARS 32 billion with higher amortizations due to this asset revaluation.

And finally, then, yes, we have this also issue of the cost of well abandonment.

There we also enter it into our facility plan that the government actually offered and there we have decided to at least do that.

That will mean that we have to do a nonmaterial down payment now.

And then we will have to be paying within this facility plan this cost in [60] installments -- monthly installments, but starting in September.

And that will be in pesos, and with a floating rate -- quarterly floating interest rate in pesos.

But with a cap of 2.5%.

So within all these decisions that we took in this period, actually, we consider that was a very positive business case in terms of tax decisions, no?

Our next question online comes from Bruno Montanari from Morgan Stanley.

First one is on shale.

Looking at your asset base, you have now some projects under development, a few pilots as well.

So how would you rank them in terms of productivity?

Is there a particular area which is performing better in terms of potential EURs and returns?

Just curious to see if different [thermal] maturities are pointing to much different results based on your experience?

Second question is about the refining margins.

As you showed on the chart, they continue to be quite healthy, even that they were above or at import parity in the quarter.

But if we think about the level you are now, what type of contraction on a per barrel basis can we expect?

Again looking at the chart, in 2018, you started the year at $12 and finished at around $5.

So is this a similar progression we could perhaps expect for 2019?

And just a quick follow-up on Frank's question on the gas price.

Specifically as we move into winter and understanding that there might not be excess capacity.

In theory, LNG imports would be the benchmark, which is dramatically more expensive than the current price in Argentina.

So how can we bridge the prices between what we are seeing in the spot market now and the import parity with LNG?

So how does the company see that playing out?

Okay.

Thanks, Bruno.

So coming back to the gas price, difficult to say which will be the benchmark.

I forgot to say that we are targeting average gas price for the year between $3.8 to $4 per million BTU.

Concerning the shale, well, it's early to say which will be the best area in terms of productivity.

As we showed during our last call, even on the same field we have different type curves.

So as long as we learn more on the shale, we will be defining different type curves and probably having more visibility.

What we can say so far is that on the 3 developments we are doing, we're having very consistent results.

We're happy with what we are seeing.

And on the new pilots that we are doing as well we are having very good results.

So we will be giving much more detail about this Vaca Muerta activity during the field trip we are going to be perform in around 1 month, so some of you will be coming.

And we can get into much more detail.

But what I can say now, it is too early to define if there is one best spot.

There are probably plenty of them.

And we are happy with the results we're having both in the developments we are doing and in the pilots we are doing.

And the third one was?

Regarding downstream margins, Bruno.

It's Diego.

This particular quarter we have very good margins, similar margins to the fourth quarter of last year.

And compared to the first quarter, well, remember that in the first quarter of last year in 2018 regarding the evolution of prices and cost.

For the downstream, all the purchases that -- are doing on crude oil, prices went down close to 18% in dollar terms.

While in the line of revenues, the most important product that we have, prices came down only 9% -- or 8.5%, 9%.

That is diesel.

Now that we've seen that prices in dollar terms currently are slowly -- or have slowly came down, we don't expect to continue seeing the same margins for the future quarters.

They probably will be more in line with the average of last year.

Our next question online comes from Vicente Falanga from Bradesco.

I had a couple of questions.

First of all, it's a follow-up on Frank's question also.

How much of the $100 million down payment for the tax program did YPF already expend this quarter?

And how much can we expect looking forward?

And my second question, we understand your average cost of debt to be 7.5% based on your presentation.

What average cost of debt do you believe you can refinance the $1.5 billion maturing this year given a relatively more risky situation in Argentina?

Vicente, Diego again.

Well, regarding the tax, this payment of close to $100 million, as well in this first quarter, we only paid ARS 950 million of the first quarter.

And then we have to pay another 4 quarters -- 4 monthly installments of, again, ARS 950 million each one.

So we would have 3 installments in the second quarter and only 1 installment in the third quarter this year.

Then regarding the financial, I will let Ignacio to address that question.

So concerning the debt cost, as we mentioned, it's around 7.5%.

Nowadays, as you may know, the market is quite volatile.

So all these new maturities that we're renewing are in terms of [straight] facilities that -- as they are more short-term, they do not have the same cost as our long-term debt.

So it's difficult to say exactly, but the cost -- it's below the average of 7.5%.

Again our maturities, our long-term maturities, or bonds nowadays, are yielding around 10% but we do not foresee at least for now tapping the market.

We're just monitoring.

Your next question online comes from Luiz Carvalho from UBS.

First of all Diego, good luck, all the best and Ignacio, welcome -- [count on us].

I have basically 3 questions.

Looking to the downstream results probably the best came from the noncore [fuels].

So I would like to try to understand how recurrent the [yields] to their volumes versus margins are here?

And what will be the approach under the current environment, to try to call close to parity as you mentioned, [yields are now] 5% to 10% below?

And if there was any impact from the incident on La Plata refinery?

If you can try to help us quantify that would be useful.

Second question is about the shale OpEx.

It's reducing considerably over the past couple of quarters.

I know that you're probably going to have a bit more details during the Vaca Muerta trade coming.

But 5% -- $5 per barrel seems very competitive.

I just would like to try to understand, if there's any internal target for, I would say the year to the next 5-year plan as you have for production growth that we might use in terms of, you had said, the future cost looking forward?

And the last question is about the JVs.

Last call I asked to Daniel about potential JVs and apparently nothing has happened.

But at the end of the day, you signed an agreement recently.

So I just would like to understand about the limitations, talking about years of course.

But trying to understand, you had said the company strategy from now on, would you consider additional JVs and divestments?

So now or this is, I would say, out of the scenario now?

Okay.

Thank you, Luiz.

So concerning the shale OpEx, yes, it's very competitive.

What I can say is that when we constructed our 5-year plan, we based our assumptions on a $6 per barrel level, which is indeed already a challenging figure.

We are extremely happy that we see this quarter that we were able to reduce it, and it's mainly a scale effect combined with the devaluation.

Anyway, we are happy with the $6 per barrel figure and we still plan with that value, right?

Considering the JVs.

So as we already say a couple of times and regardless '19 being a challenging year I would say, we are not actively looking to perform new JVs, because we have the acreage we want to have with optionality we already mentioned.

We have the means to derisk this acreage, and we don't need now third-party funds to accelerate growth.

Now as we will be unlocking new developments based on the successful pilots we will have, maybe in the future we will reassess this, but it is not something we are working on at this time.

Hi, Luiz, Diego.

Let me address the first and the second question regarding downstream margins.

And the La Plata incident.

We are not seeing any change in terms of the volumes of our noncore products.

We continue seeing the same volumes as we have been selling in the last year and the quarter also.

In terms of the La Plata incident, there actually doesn't cost any significant or material effect to our -- or impact.

Basically, the main impact, if you want, was that we had -- we needed to do some additional imports of some products.

But those are -- were mostly the -- or the main consequence of that.

Yes, but can we try, sorry Diego, can we try to quantify in terms of the nonrecurrent impact from the La Plata incident?

And that would be helpful.

Could be something around let's say $30 million probably, but that is because we needed to do some imports that has a higher price than the cost of refining that or processing the crude, no?

Our next question online comes from Pavel Molchanov from Raymond James.

Can you give us more clarity on the timing of the Bandurria Sur JV entering into full-scale development?

Is that still planned for some time by the end of 2019?

In Bandurria Sur we currently have 2 rigs working there.

So we already started the development of the southern tip, which is the one that we already derisked.

While we continue piloting the rest of the pilots.

So the answer plainly, we are already in development mode on the southern part.

And when I think about the cost structure that you are currently reporting at Loma Campana.

So $10 for development and $5 roughly for operating costs.

Are those same numbers realistic targets for Amarga Chica and Bandurria Sur?

And if not, what are the differences?

Well, as we said before, it is early days to say that we will be able to replicate the same efficiency levels that we achieved in Loma Campana.

However, with information we have now we are in a good trend, right?

So we probably will give you more information along the year when we have more wells and more production.

But as we said before, in La Amarga Chica and in Bandurria just after a few months after starting the development, we achieved the development cost that we had in Loma Campana by the end of last year, so this is coming fast.

But it is still early to say how fast are we going to be able to replicate, right?

And then we need to consider other things like different productivity, the quality of the rock, et cetera.

So as we are in the same hub we have a lot of synergies and we -- and this will also help.

Okay.

Last question from me.

Can you give us an update on the wind power development and how much you plan to invest in that portion of your business in 2019?

Pavel, Diego here.

We continue, we do with a -- with our vehicle YPF Luz there, and 1 construction of a farm wind.

I don't have the amount to be expended this year in that project.

But it is not something that YPF would contribute to that CapEx.

And remember that now we have the consolidated business that is CapEx that is going to be carried out by YPF Luz, no?

Our next question comes from Lilyanna Yang from HBSC (sic) [HSBC].

I would like to ask about Mega.

Petrobras has indicated it's selling, if you have any plans to increase expect there.

Or what would happen with the asset?

Also very quickly would like to know if the federal government is paying on time, its $800 million in gas bills to you?

And if the government is still paying on time the gas subsidized payment for the unconventional producers for the new fields?

And lastly, could you give any updates, if any, on the Maxus legal dispute?

Thanks, Lily.

So, yes, Mega, for those that are not aware it's a joint venture between YPF, Dow Chemical and Petrobras.

It has a separation plant in Neuquén and which can go up to 40 million cubic meters per day and a fractionation unit in Bahía Blanca, produce around 5 million cubic meters per day of ethane.

And Petrobras have launched a divestment program, which includes this unit.

So we have been notified by them the process has already been launched.

And we are looking at it as we look at every opportunity that we have, knowing that we are partners there and we have a right of first refusal there.

So it's something that we follow, that we might participate or not, but we will certainly have a say.

Lily, this is Ignacio, I will take the question concerning the subsidies.

As we mentioned in the presentation, we have collected so far concerning the planned gas 2017, $100 million in cash.

The government has issued a bond for $650 million, so those are the installments.

It's $25 million per month because it's a monthly installment, and again as I mentioned it has been $100 million so far.

We expect to collect the $200 million for remaining 2019.

And in respect with following planned gas, as you may know, we do not have so much interest on that planned gas.

So far we have [exited] some part of 2018 but it's not material.

I think that -- Lily, Diego.

Your third question was regarding Maxus, we have any significant update there.

Remember that the supreme -- no the court has already dismissed -- sorry, denied the motion to dismiss.

So there we started answering the demand, and we are in the process of showing proof and starting the process.

We don't have any significant outcome yet.

And we don't expect to have it in the short-term.

Okay.

Great.

If I may ask one last quick question.

You had a softer EBITDA guidance now.

Are you also reducing your CapEx or they are going to be the same and you might increase leverage a little bit from current levels?

Yes.

As we said, Lilyanna, at the beginning of the year, we gave a target between $3.5 billion to $4 billion, CapEx.

And today, with the investments we are delaying for the gas, we believe we will be in the low range, so around the $3.5 billion.

You mentioned the leverage there, but we continue seeing the -- or we continue deciding very strictly on our finance discipline and we will keep a target -- a leverage target below 2x.

And our last question comes from Pedro Medeiros from Citigroup.

I just have 2 last questions.

The first one is if you could comment on the start of the smaller scale LNG barge project with EXMAR.

I think it was planned to start up in the second quarter of this year.

Would you mind commenting on, how does this contract works?

What's YPF's participation in the commercial part of the gas?

And I understand the facility has roughly around 500,000 tons of LNG capacity per annum.

But considering the demand seasonality in Argentina, how would you fit that capacity through the year?

Like, any guidance on prices and how seasonality for the plant will work out?

And my second question is -- well -- yes -- no, that's the only one.

I don't need a second question.

Thanks, Pedro.

The FLNG barge is already in Bahía Blanca, has been commissioned.

And we have performed the cool down of the tons.

And we are now testing the liquefying process.

So all is aligned to start liquefying and selling by the first quarter this year -- by the third quarter this year.

As we said, this will take up to 2.5 million cubic meters per day of gas, which is nice for us.

But when we see the output of what it's going to be in terms of LNG compared to the rest of the world, it's very low.

So we will be selling this at the spot market.

We already have conversations with potential off-takers.

But I understand you have signed a lease agreement with EXMAR for 10 years, right, for the facility.

That's correct.

And thank you, we have no further questions at this time.

I would like to turn the call over to Sergio Giorgi for closing comments.

Okay.

So thanks to all to bear with us during this results call.

And as always, if you have more questions, please do not hesitate to contact the team, now Ignacio and myself, and we will be eager to carry on the discussion.

And for those that will be able to come to the Vaca Muerta trip, we wait for you and we'll be able to show you much details about what we are doing.

Thank you very much, and have a good day.

And thank you, ladies and gentlemen, this concludes today's conference.

Thank you for participating.

You may now disconnect.