YPF SA (YPF) 2018 Q2 法說會逐字稿

Welcome to the Q2 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.

Great.

Thank you, Richard.

Good morning, ladies and gentlemen.

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

I would like to thank you for joining the YPF Second Quarter 2018 Earning Webcast.

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

During the presentation, we will walk through the main aspects and events that explained our second quarter results.

And finally, we will up -- we'll open up the call for questions.

We will be making forward-looking statements.

So we ask you to carefully review the cautionary statement on Slide 2. Also, our financial statement figures are stated in Argentine pesos and in accordance with International Financial Reporting Standards, IFRS.

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

Please, Daniel, go ahead.

Well, good morning.

And before Sergio and Diego go through the details of the quarter, I would like to provide some context.

This was a difficult quarter for Argentina, where the currency devalued by more than 40%, interest rates skyrocketed, and the economy started to soften.

Under these conditions and acknowledging that we were kind of slow in passing through to prices the effects of devaluation, results were again strong and our growth plans for the future remain essentially unchanged.

Revenues were up by 55% in pesos and EBITDA by 53%, both also up in dollar terms despite the devaluation.

Total hydrocarbon production was 1% below last year, very strong in unconventionals but mixed in conventional, especially natural gas.

And again, we were free cash flow positive as operating cash flow more than doubled to ARS 27.6 billion, while CapEx amounted to ARS 19.3 billion.

So with that, please, Diego, go ahead.

Okay.

Thanks, Daniel.

Moving now into our main financial figures measured in U.S. dollars.

In the second quarter, the local currency depreciated by almost 50% when compared with the same quarter of 2017.

However, revenues were up by 3.3%, driven by a strong demand of our main products, gasoline and diesel.

The increase was enough to offset the lower prices in dollars for both products.

Exports increased due to a combination of higher international prices and higher exported volumes.

On the other hand, price of natural gas was down, average 1.9%, as a former play in gas expired December 2017, and less volumes are now eligible for the new incentive plan for unconventional new gas.

Cash cost, expressed in U.S. dollars, remained essentially flat, lifting our refining cost in dollars, decreased by 14% and 22.8% in absolute terms, respectively.

Royalties, which is the only cost component fully denominated in dollars, were up close to 26%, in line with increasing domestic crude oil prices.

Crude oil purchases were down 9.7% in dollar as our crude oil production increased 3.6% while we processed in our refineries lower levels of crude oil than a year ago.

As a result, adjusted EBITDA was up by 2.3% in dollars.

Finally, total CapEx for the company amounted $824 million, almost 1% lower compared to Q2 2017.

Upstream CapEx in the quarter amounted $686 million, 8.6% higher than Q2 2017.

Our activity was mainly focused in drilling and workover, which represented 70% of the Upstream CapEx; followed by a buildup of facilities with a 19% share of the total; and exploration and other activities, 11%.

During the quarter, we drilled and put into production a total of 96 new wells, including 14 new shale wells and another 12 wells in the tight gas formations.

In Downstream, CapEx was $114 million.

Activity was focused in refining, which represented 38% of the Downstream CapEx; followed by logistics with a 26% share of the total; then marketing representing 20%; and finally, chemicals were at 16%.

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

As you can see in this slide, this time, we decided to focus the analysis in adjusted EBITDA of our business segment instead of operating income to provide a better understanding on how each business segment contributes with the cash generation of the company, putting aside the FX impact on depreciation and amortization, which are, in fact, a noncash effect.

This way, adjusted EBITDA has come up by 53.2% compared with the second quarter 2017.

This was mainly driven by the better operating results obtained in the -- in our Upstream business segment, which show an increase of almost ARS 13 billion vis-à-vis a year ago.

Revenues of this segment increased by 74% mainly as a result of higher crude oil and natural gas prices in pesos, while on the other hand, cash costs of this segment increased by 41%, below revenue increase as lifting cost and other OpEx were partially diluted by the devaluation.

The Downstream segment results show a decrease of almost ARS 1.8 billion pesos.

This is basically explained by a gasoline and diesel price increase in pesos of only 8% and 9%, respectively, in the quarter being not enough to offset the increase in crude oil and biofuel purchases, which are denominated in dollars.

However, revenues of this business segment managed to increase by 54%, driven by actually demand of our main products, coupled with higher price in pesos although lower in dollar for gasoline and diesel, as explained before, higher sales of petrochemical products, and higher exports on higher volumes and international price.

It is worth mentioning that refining costs show an increase of only 15.5% compared to the same quarter 2017 as the currency depreciation played a beneficial role as well.

The power -- the Gas & Power segment also show a reduction of ARS 177 million.

Although it's worth highlighting that from Q1 2018, YPF Energía Eléctrica is no longer consolidating in the business segment results.

And in the second quarter of 2017, this company had contributed with ARS 299 million of EBITDA.

So if we do normalize this effect, adjusted EBITDA of the segment would have been -- would have grown by ARS 122 million.

Corporate expenses increased by ARS 864 million mainly due to higher salaries, IT and advertising costs.

Also, there was a lower EBITDA contribution for our controlled company, [Ayesa].

Finally, those results created in the different business segments that are not backed to third parties are eliminated in the column of eliminations basically due to the difference in valuation of inventories between transfer price and replacement cost.

The cash generated in the second quarter of the year reached a total of 26 -- ARS 27.6 billion, more than doubling the operating cash flow of a year ago.

This increase of ARS 14.6 billion was mainly due to an increase in adjusted EBITDA of ARS 8.6 billion and a reduction in working capital on higher accounts payable as a result of the higher purchases of the period and the partial collection for the assignment of the Aguada Pichana Este and Aguada de Castro areas, among others.

This operating cash flow more than exceeded the ARS 18 billion CapEx of the period and contributed to the [deleverage] process that is part of our 5-year plan.

Finally, this cash generation, including the dollar-denominating sovereign bonds still held in treasury, results in a strong cash position of ARS 57.6 billion at the end of the second quarter 2018.

As we can see in the graph on the right, we are fully funding our CapEx program with our own cash generation.

We explained cash position is enough to cover our debt maturities of the year and most of the first half of 2019.

Our leverage ratio came down to 1.8x net debt to EBITDA, bringing our 2x target for the year, while the average life of the debt remains in the 6-year area.

The average interest rate in pesos increased to 31.7%, while the average cost of our debt in dollars remained stable at 7.4%.

With this, I would like to turn the presentation to Sergio, who will better explain our operational results.

Well, thank you, Diego.

Good morning, everyone.

Let me start by sharing with you this slide as safety is a core value for YPF.

Our daily work is done in places with flammable liquids, high pressure and confined spaces.

So we need to be very vigilant and ensure that all the safety measures are taken so I can produce, treat, transport and sell our products without harming our workers, the environment or the community.

As you can see in the chart, the currently, injury frequency rate indicate that the measure of the number of people injured every million hours worked is the lowest of the last 10 years, proving that the actions that we have been taking over the last few years regarding safety measures are paying off.

Despite this figure, it is important to remain vigilant as we are reminded from time to time that we work in potentially dangerous environments.

We have been focusing in formalizing as well the efforts and initiatives that we have been doing in terms of environmental, social and corporate governance, also known as ESG, in order to position YPF in the first quarter compared to peers.

We are finalizing our 2017 ESG Report under the global report initiative standards.

So shortly, it would be available in our website.

Now let's move to the analysis of the second quarter production.

Total production in the second quarter increased 3.6% to 226,000 barrels of oil per day.

Whereas in the comparison with the second quarter of last year, we need to integrate the consequence of the severe weather conditions that [hampered] production in the Golfo San Jorge Basin.

It is also worth mentioning, on the positive side, that we saw an increase in oil production from our Chachahuen field in Mendoza province; an increase in liquids produced in our tight gas field, Estación Fernandez Oro in Rio Negro province.

We also sold our Cerro Bandera mature field, which production is not considered anymore.

Natural gas production reached 44 million cubic meters per day, a 1.3% decrease compared to the same quarter last year mainly due to the lower demand observed for this product during the quarter and some delay in the first gas of the Magallanes field, a non-operated offshore JV.

NGLs production decreased 19% due to the scale of maintenance in our affiliated company, Mega, producing a total of 41,600 barrels per day in the quarter.

As a result, total hydrocarbon production dropped 1% vis-à-vis the same quarter of 2017 to 544,500 barrels of oil equivalent per day.

This production level is somehow similar to fourth quarter 2017 and first quarter of 2018.

So we'll start seeing a kind of stabilization.

When we break down the sources of our production, we can observe that shale production contributed with 19,300 additional BOEs per day in the quarter, while tight production show a slight decrease of 2,200 BOEs per day mainly related to a lower production of natural gas liquids as a consequence of the stoppage in Mega, as explained before.

As you can observe, growth is coming from our unconventional fields and clearly, most of the decline from our conventional fields.

So we would like to do a deeper analysis on this in our next slide.

In this slide, you can see that our conventional production decreased by 5.5% vis-à-vis a year ago.

First of all, it is worth mentioning that crude oil production in the second quarter of 2017 was affected by the weather contingencies that we already mentioned, while in this quarter, natural gas production was affected by lower demand of this product, as explained before.

Having said that, due to the second quarter, we have been focusing in the following aspects: first, managing the decline of our conventional fields by launching a series of initiatives in terms of primary, secondary and tertiary recovery as well as natural gas compression in order to extract the maximum value while remaining profitable.

While primary recovery initiatives are the main contributor to improve the recovery factor of our conventional fields, we are also working to improve the process facilities and the quality of the water to accelerate our secondary recovery project.

At the same time, we are currently developing 3 tertiary recovery projects, 2 in San Jorge basin and 1 in Neuquina basin.

And in the short term, we will be adding 5 more pilot projects with the purchase of 10 additional facilities for that purpose.

We had also continued with our strategy of disposing high-cost, noncore assets in order to focus on what is core.

In that respect, we found out 4 additional mature blocks in the Neuquina Basin, which, by the way, we are contributing with 2,200 BOEs per day in the second quarter of last year.

And we will continue with this portfolio management activity.

We have also incorporated good, quality blocks in our portfolio, such as Cerro Manrique, a tight gas block just beside Estación Fernández Oro, one of our best tight gas fields.

Moving now to unconventionals.

Net shale production of the quarter reached 56,000 BOE per day, showing an increase of almost 53% compared to a year ago.

If we add to our net shale production the 96,000 BOEs of tight gas and liquid, our total unconventional production of 152,000 BOE represent now almost 28% of our total production.

In terms of our activity as operator, during the second quarter, we produced 97,000 BOEs per day, and we connected a total of 18 new shale horizontal wells.

In relation to cost in our shale operations, the development cost in Loma Campana continues in the good trend, staying in the first half of the year in the $12 per BOE area.

Operating expenses show a similar improvement, coming down to the $7 per BOE area from more than $16 only 3 years ago.

Although the peso depreciation effects are rapidly seen in lifting costs, it takes a longer period to impact in the CapEx as the average drilling and completion time is close to 180 days because we drill and complete in batches of 4 wells.

Therefore, we expect to see further reductions in the development cost in the following quarters.

Now let me provide a general update on our shale projects.

Continuing with our main shale development, Loma Campana, the operated JV we have with Chevron, it is important mentioning that we have successfully drilled, completed and put into production the first 10,000-feet long lateral well with 40 fracks and a total well cost of approximately $40 million.

Although it is yet early days as the well has been put into production for 1 week and we are still choking it up, it is already producing an interesting amount of oil, and expectation is to reach an EUR in the order of magnitude of 1.5 million BOE.

Based on the good results we are having in this field, we are now planning to increase the activity level next year, adding one more drilling rig to the already 3 rigs that are working there.

For this reason and to ensure that we have the treatment and evacuation capacity for the additional production, we are launching an expansion in the midstream capacity.

These works include a Phase 1 expansion of the Loma Campana treatment facilities as well as the construction of a new 88-kilometer oil pipeline.

These facilities will allow treating and transporting oil production not only for Loma Campana but also other adjacent blocks in Vaca Muerta.

The pipeline is already being constructed, and expectation is to finish it by year-end.

In addition to Loma Campana, while we plan a growth production plateau reaching 100,000 barrels of oil equivalent per day in 2024 from the current level of 44,000 BOEs, as we mentioned in previous calls, we are currently derisking our Vaca Muerta acreage through 17 operated and non-operated pilots.

The result we have seen so far are promising.

And therefore, we expect 2 new FIDs by the last quarter of this year.

One of them is La Amarga Chica, a shale oil JV with Petronas; and the second is Bandurria Sur, a JV with Schlumberger.

We currently have 1 rig on each 1 of these blocks, and we will have up to 2 rigs on each block next year.

In line with these results, we are also analyzing launching additional pilots to derisk more acreage, and the challenge will be then being able to achieve the same development metrics that we have in Loma Campana on those new fields.

A series of initiatives have been launched in the Upstream segment to ensure those results, among them, incorporating technology.

For instance, do we know that just [steering] from a control room using data analytics and powerful databases to predict failures to optimize frack plans and to prioritize the development that looks more attractive; also ensuring our people work in collaborative mode so that useful information is exchanged and stabilizing as well our facility design to reduce cost and lead time.

We are also focusing in reducing the derisking to development cycle by having teams organized by projects and a central group that ensures best practices from one project are applied on the other project.

YPF is very active and well positioned in Vaca Muerta with good quality acreage both in shale gas and shale oil areas.

We are operators and 100% share or in JVs in some of these acreage, and in others, we are not operators or within JVs with international, renowned partners.

This situation, combined with a short-term cycle investment like Shell, is providing us one interesting optionality, allowing us to redirect, up to a certain extent, our CapEx to the most profitable fluids and projects.

Moving now to our Downstream business segment.

During the quarter, the volume of crude oil processed in our refineries was 275,000 barrels of oil per day, 6.6% lower than the second quarter 2017, mainly as a result of scheduled maintenance in our La Plata refinery.

Regarding sales, total volumes were essentially flat, with reduction in domestic volumes almost offset by exports.

Although demand for our main product, diesel and gasoline, increased, total volumes in the local market were down mainly to a significant reduction in fuel oil demand from power generation plant as there was more availability of natural gas.

Now to provide more detail about fuel 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.

Gasoline demand in the first half of the year is showing the same trend in 2017 and 2016 with a total 5.6% increase.

Diesel demand also show a good performance, increasing 3.5% in the quarter despite the severe drought that affected agricultural sector this year, being this one a very great source of demand for this product.

Market share for both products continued to be strong and above 2017, with 55.7% in gasoline and 58.2% in diesel.

Market share for our premium products, Infinia gasoline and Infinia diesel, were 61.5% and 59.1%, respectively.

As we explained at the beginning of the presentation, the spiking effect, coupled with an increase in international price that happened in April, put an increased pressure to our Downstream margins as prices for gasoline and diesel were reduced in dollar terms.

At that time, the government requested the industry to help curb inflation.

And in May, an agreement was signed with refiners, by which prices at the pump would not increase for 60 days.

This agreement was amended in June to have some increase in fuel prices and to include producers that agreed to negotiate lower price for local crude oil and to work closely with refiners to face operational difficulties that the macro situation was presenting.

However, as the oil price kept on increasing and the peso continued devaluating, in conjunction with the government and the other industry players, we decided to terminate the agreement.

As we always do and to avoid the sharp negative effect in our client base and the overall economic activity, we decided to adjust our prices gradually in order to make up for these lower prices, and this is what we have been doing and we will be showing later in the next slide.

Having said that, in this scenario, our Downstream EBITDA per refined barrel, and without considering the revaluation of inventories, decreased by $4 in the quarter, whereas our fuel prices declined by the [barrel].

Finally, in this slide, we are showing the evolution in the price of our main product, diesel grade 2, versus the evolution of the import parity price in pesos.

As you can see, since April, we have been adjusting gradually in order to start reducing the gap.

This same analysis also applies for our regular gasoline, which has a very similar evolution to the one for diesel shown in this chart.

Now I would like to offer Daniel the opportunity of giving us the final remarks, and then we will open the Q&A session.

Thank you, Sergio.

Well, in summary, we are again reaffirming our guidance for 2018 of 10% growth in EBITDA in dollar terms, with production down in the 2% area.

Leverage should stand comfortably below our 2x previous expectation, as CapEx should be around $3.5 billion in the year.

Shale oil and gas production continues to provide great result, above budget by the way, and positions us to be able to double the number of drilling rigs dedicated to shale oil next year as La Amarga Chica and Bandurria Sur move to full development and will be joining Loma Campana.

We are still slightly below budget in conventional production in a couple of areas, and the reasons behind such shortfall have been identified and are being dealt with.

We should start seeing crude oil production growth next year, as it was envisioned in the 5-year plan.

In terms of prices, we have made substantial catch-up in fuel prices in the last month or so, with average increases well above 10% and are on track to full convergence before year-end.

Non-premium products still have another 10%, give or take, to catch up, and premium products are almost there.

The situation with crude oil prices is similar as we are only 5% to 10% below export parity and should also converge with international prices before year-end.

The government has publicly and repeatedly made it clear that they do believe in market prices and that we are going in that direction.

Natural gas prices are still not that clear as the regulator yet needs to determine how the devaluation effect will be passed through to consumers.

In any event, it is likely that the local gas prices will trend towards the $4.50 to $5 per million BTU range, which is below what some people had been expecting but consistent with our $4.50 number used in our 5-year plan.

We will be making investment decisions with regards to natural gas depending on where the average price finally lands.

Access to financing remains open to us, especially in the bank market, where our lines of credit are virtually unused and liquidity is extremely strong.

Therefore, there is no need to change any of the growth targets that we have established in our 5-year plan.

So YPF has proved again its resiliency to macroeconomic volatility and has also proved the value of our integrated business model approach.

We will be conducting our annual Investor Day in New York on October 26 and hope to see many of you there in person.

But with that, I would like to address your questions.

So thank you, and let's start the Q&A session.

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

The first one is about pricing policy.

First, wanted to get some more color on natural gas.

I understand that the situation is not very clear yet, but we read that the intention is you have a free market with tenders and bilateral agreements but also read about this resolution fixing the prices for thermo power plants at least in the near term and gas distributors also pushing for a lower price.

So in the company, what is the optimum policy?

How should natural gas prices work in the country?

Trying to think here about the framework and not necessarily about the actual price level, which you mentioned, $4.50 to $5 per million BTU.

That's quite clear.

But the framework to me is not very transparent yet.

And on refining, it seems that June was the month with a wider gap versus the international parity, looking at the chart in the presentation, followed by the gradual improvement.

Does that mean your refining margin should already improve in Q3 relative to Q2?

Or should we think of stable margins on other quarter until the gap fully closes?

And also, I have a question about cash flows.

We have now seen 3 quarters or so of positive free cash flow after interest payment with a strong [print] now in the second quarter, nearly $200 million.

Do you think this trend will be sustained for the coming quarters especially now with the lower level of CapEx?

Thank you, Bruno.

Well, let me address those questions.

On pricing for natural gas, your question regarding the framework, I think that what we would like as a company -- and I believe the government is also going in that direction, is a free market with a possibility of contracting with the distribution companies, with the independent power producers or initially with CAMMESA or ENARSA consolidating the natural gas for the power producers.

I think we are going in that direction.

The mention or mention that you made to the price, which is actually around $4.20, what is being paid by CAMMESA for the power generation gas is only for the remainder of the year.

We believe the intention of the government is to move to auctions next year.

And as long as those auctions are for the medium term and have the ability of having low -- maybe lower gas prices during the summer and higher gas prices during the winter, I think we should be fine.

And if we arrive in terms of prices converging in the $4.50 to $5 per million BTU range, I can say that that doesn't jeopardize any of our shale gas projects going forward.

But as I said, we need to understand that better before making investment decisions because some projects may work with the prices in the $4.50 range.

Others may need higher prices, and others can survive with lower prices.

So depending on what the average wellhead price of gas is, that will determine what is the size of our natural gas investment for the future.

In terms of our...

Sorry to interrupt.

Do you still have anything under the prior incentive plan, any of the assets still getting the higher price?

Oh, yes.

When we talk about $4.50 to $5, that also includes, in the weighted average, a small percentage of a subsidy under the new plan.

The old plan is gone.

We have a few projects, some of which have already been approved and others that are in the process of being approved that should benefit from the pricing incentive that starts at $7.50 and goes all the way down to $6 per million BTU in the next 4 years.

Still, that's a very small amount in the total scheme of things in terms of natural gas for us, okay.

But it is definitely part of the weighted average price for us.

In terms of refining margins, yes, you're right.

June was the one -- the month with the widest gap.

We can say that both refining and commercial margins should go up on the third quarter especially after the price increases that we effected in July and August, which were more than 10% in average, and with the FX and the crude oil prices and, I would say, import parity of refined products remaining essentially flat during this period.

So you should definitely expect that the refining margin of the second quarter should be kind of slower, and we should start recurring refining margins again.

And in terms of cash flows, the answer to your question is yes.

We will continue to see positive free cash flow going forward.

You know, Bruno, that this is something that we've been guiding on for quite some time that in 2019, we would have positive free cash flow.

So that shouldn't surprise anybody, and that should be the trend, as I said, for the remainder of this year but for next year and going forward also.

Our next question online comes from Frank McGann from Bank of America.

Just on the JVs that could be moving towards the development phase as of the end of this year and into the next year, what -- I was just wondering what -- how you see those relative to Loma Campana in terms of potential production.

You indicated Loma Campana would be close to 100,000 barrels a day by 2024.

Do these other areas have similar potential?

And beyond the 2 that you talked about that could go into development by the end of this year, do you see more coming in 2019?

So as you know, both blocks, La Amarga Chica and Bandurria are not that far from Loma Campana.

And we are both having good results in pilots on both blocks.

So as we say, well, Loma Campana, it's already more advanced, but we are going to increase activities on both blocks.

We expect the same level of productivities that we are having in Loma Campana, sometimes better.

And so we are still early days to define a production plateau.

But probably in La Amarga Chica, where we are a little bit more advanced, it could be around 75,000 BOE, the plateau; and in Bandurria Sur, probably 50,000 or more but it's still early days to confirm.

And in terms of other blocks, as I say before, we are performing 17 pilots, operated and non-operated.

We are having good results in all of them.

As an example, a non-operated pilot that is operated by Total in Aguada Pichana Este, we just finished a pilot of 20 wells with very good results.

Productivities are very good.

And we are going to start discussions now on a plan, on a multiyear plan to add probably 40 more wells there.

And I could go on, on every block but just to say that we have a good portfolio that we will be maturing and going to FIDs as soon as we are ready.

And I would say, complementing what Sergio has very well explained, in these 2 additional shale oil blocks plus Loma Campana, I'd say by the end of next year, approximately 20% of YPF's crude oil production will come from shale oil, just from these 3 blocks, 20%, give or take.

So -- and that is obviously well below those plateau figures that are going to be reached in some place in the next 5 to 7 years.

But only by 1 year ahead of us, they are already going to representing 20% of our total production.

And if I could just follow up.

As you look -- go forward with more infrastructure now being put in place and already in place and a lot more experience, do you think the ramp-up towards plateau will gradually come quicker as a result of being further along the learning curve?

I'd say it will depend on what we negotiate with our partners.

In all these cases, we are 50-50 JVs, and the pace of a ramp-up is directly proportional to the level of investments.

And we will have to sit down with each of our partners and decide what is the ideal level of investments that we are willing to make and that will result in what is the pace of acceleration.

But in terms of cost, in terms of know-how and so on, we haven't found any reason why they should be different to Loma Campana.

Our next question online comes from Regis Cardoso from Credit Suisse.

A few questions on my side.

One is regarding the accrual of the receivables for natural gas prices.

I understand that during the second quarter, you booked as revenues the full price for natural gas, but you cannot collect the prices in full because of the depreciation in peso that still needs to be passed through tariffs so that the distribution companies can effectively pay producers.

So is this diagnostic correct?

And if this is the case, how much have you accrued?

And what is your expectation going forward?

Second question is regarding CapEx efficiency because you've effectively reduced the CapEx forecast for the year while you've maintained production growth for the years ahead.

So I just wanted to understand if you are indeed seeing a more efficient CapEx.

And if that's the case, how would you explain this in terms of maybe FX devaluation, maybe more productive wells with lower development cost?

And I mean, how representative are each of these factors?

And still on the CapEx efficiency side, I wanted to get a sense, if you can share with us, what should we consider to be the type well curves, I mean, typical parameters, right?

If you can provide EUR, lateral length, IP rates in both oil and gas windows.

And finally, if we can do just a quick follow-up.

The Downstream margins presented in Slide 15, I assume those also include the commercial distribution margins, right?

Regis, Diego Celaá.

Let me address the first question.

In terms of the trade receivables, yes, you're right.

We haven't been -- collected the full sales of gas not only to Metrogas but to all the other distribution companies.

The total amount that we have accrued is around $350 million.

And the reason why is just because those tariffs that were specified in April at an exchange rate of ARS 20.5, actually, the [government] has been paying the [first] price using those -- that same exchange rate.

And now we are discussing.

We are negotiating also with [another] gas to see how we can end up trying to passing -- pass through these into consumers.

So we don't have a lot of clarity yet.

We are under negotiations.

But I would say that this would be clarified in the next couple of months.

Now regarding CapEx, the reduction in CapEx is mostly related to currency depreciation.

I would say that most of the reduction is there.

Maybe some slight or maybe some small CapEx in some facilities are being postponed to next year.

But again, most of the reductions are in -- is coming from currency depreciation, and we are not cutting activity in terms of drilling activity.

So that reduction is not going to affect the production.

In terms of type well, I don't know.

Maybe Sergio can address that part for you.

Okay.

So in terms of type well -- type curves, first of all, we have different type curves in one field and not only, I would say, geographically but also by depth because we're on different landing points.

And we have several fields.

So it is very difficult to provide one type curve for gas and one type curve for oil.

However, we understand that question, and we probably will try to show something in our Investor Day in October.

But there's no one, I would say, type curve for oil and one type curve for gas.

Let me complement, Regis, what Sergio is saying because he did mention 0.5 million barrels of EUR for our extended reach well.

It's just one well.

We do believe that if that exercise is successful, could be a total game-changer for us.

Let's put things in context.

For those of you that have been following us for 5 years or so, we started with the vertical wells that were expected to accumulate 300,000 barrels of oil during the life of the well.

And initially, they were also costing us $40 million, as Sergio said, this well cost, right.

So again, it's just one well, but it could represent a significant change.

And in terms of the -- what, up to recently, we called extended wells, which were those with 2,500 meters of lateral length, those, as Sergio said, vary from area to area.

But just to give you a range, we're talking about 750,000 to 1 million barrels of EUR depending on the area.

Even within concession areas, there is this variation.

And in natural gas, it's much more difficult for us to provide a meaningful number given that the experience is somehow more limited.

But the initial wells are giving us results that they should accumulate 10 Bcf in the life of the well, okay.

But again, let's take these numbers with a grain of salt because they are very initial results.

So they are expectations on a low number of wells, I should put it that way.

We still have the last question pending.

Yes, the Downstream margins actually are including the marketing margins.

Our next question online comes from Luiz Carvalho from UBS.

Just 2 questions from my end here.

The first one, back to the pricing policy, first, looking to the Slide 16, where you mention about -- you said the 53% increase since the beginning of -- or late 2017.

My question is, why do you not give a bit more visibility about what is the gap in terms of parity for each product?

I mean, not on a daily basis, maybe -- I don't know, on a monthly basis or a quarterly basis, and really show how much below parity and what's the plan in order to close the gap looking forward?

I think that would give more visibility on how to -- actually to look this, how can I say, topic in a bit more specific numbers.

That's the first one.

And the second, back to the divestments and farm-outs, you mentioned about some divestments that were in the pipeline and also did say some updates on the current JVs, but I'm more looking forward here.

And how should we see further divestments over the next, let's say, 6 to 9 months?

And also potential JVs being signed, is there something in the pipeline that we expect?

Or -- I mean, for now, with the -- let's say, with the crude oil capped in the country, it's somehow more difficult.

Luiz, thank you for the questions.

Well, regarding pricing, the thing here is that this is a competitive market.

We do have more than 50% share, but we do not set prices for anybody.

And actually, if you look at how our competition has raised prices the last month, some of our competitors have raised prices well ahead of us, and some of our competitors have raised prices in line with us.

And then our pricing policy is that -- takes into account a lot of different things, and it's not the same price in different parts of the country.

It's not the same price in different channels.

So when I talk about the catch-up that we still need to make, that is on average, right, but the reality is that prices vary from region to region and from channel to channel and from product to product.

We made a decision of increasing premium product prices well ahead of non-premium prices in early July.

And we made a decision not to do the same in this last price hike a few days ago during the last weekend, and the increase in premium products was only 1 percentage point higher than non-premium products.

So what I'm trying to say with this is we don't want to hint competitors of exactly what our pricing policy is.

What I can tell you with as much visibility as I can is that nonpremium products still have a 10% catch-up to make, 10% to our objective prices, meaning where the margins that we have never disclosed but that we have put in our budget that we're trying to accomplish and the costs that we already know.

And premium products, we're almost there.

We have our positive margins, not the margins that we expect to have.

So we still need to do some catch-up but not a lot.

And as I said during the presentation, you should assume that we will continue with this gradual catch-up the next few months, and this catch-up should be completed before the end of the year.

And in terms of our divestments, we are not working in any meaningful divestment in terms of Vaca Muerta.

What we have disclosed some time ago is that we are close to finalizing a very small sell-side process of mature fields in the Neuquina basin.

It's 4 fields.

And once that transaction is over, we will probably start with a new one.

Actually, we are in the process of starting with a new process again to sell out another few fields that we believe there are other people that can be more efficient than we are because of the size and the marginality of those fields.

This is in line with the strategy that we have laid out last year to, over the long term, operate a lower number of fields and concentrate in larger opportunities.

But in terms -- again, going back to Vaca Muerta, we believe that we have all the capital and the know-how needed in order to develop those fields that are under pilot mode today.

So we don't envision any need for additional farm-outs over the short term.

Depending on where natural gas prices land, we will make decisions in terms of developing some of those natural gas fields.

And maybe part of those decisions have -- or result in teaming up with other partners to develop some of those gas projects.

But the reality is that of those pilot projects, there are a lot that we are operating with partners, and there are many which we are not even operating and that we have partners that operate for us.

So there's very few acreage or very few areas under which we are already working at 100%.

Actually, in crude oil, there is none; so no need for divestment over the short term.

Okay.

Just one last follow-up here.

On the Slide 16, just to clarify, you mentioned the green line about import parity and the blue line, the retail price, right.

But in the comment one you made that this does not include internalization costs.

Just to clarify, this internalization cost is -- you mean from the port internal to the country.

Is that correct?

I just want to understand what the import parity means here.

Is it including the cost?

You said the cost, the freight cost, I don't know, from U.S. Gulf Coast, Gulf of Mexico to Argentina.

Or is it just the export parity?

I mean, comparing prices, screen prices from Argentina to -- I don't know, to any other region.

Thank you, Luiz.

Sorry for the confusion here, but internalization costs are included in the import parity.

Oh, are included, right?

Yes.

Because you said does not include internalization cost.

So I just want to be clear that we're...

No, no.

What we are comparing is the increases in retail prices with the increase in import parity with all costs included, including internalization.

And I understand there's a confusion in the slide.

So sorry for that.

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

In January of 2017, the Macri administration announced Plan Gas, which targeted reaching self-sufficiency in natural gas by the year 2022.

And I'm curious, with the changed approach to gas pricing, is it still realistic for Argentina as a whole to reach gas self-sufficiency within the next 4 years?

Thank you, Pavel.

I think it is.

I don't see any reason why it isn't.

As I said, it will depend a lot on where natural gas prices, in average, end up landing.

Meaning if it's $4.50 to $5, which is our base case, I think there are substantial projects that can continue to be developed and, therefore, provide for all that additional production growth needed in order to reach self-sufficiency.

In any event, I think what you need to differentiate is winter from summer because self-sufficiency doesn't mean that Argentina will not be continuing to import some LNG during the peak days of winter and maybe exporting natural gas in some form during the summer.

But in all, what I would say is that developments should continue if prices are attractive.

And we still believe that we are trending towards prices which continue to be attractive, maybe not as attractive to the expectations that some people had 6 months to a year ago but again, $4.50 to $5 per million BTU should be good enough prices.

Okay.

At Loma Campana, last October, as I recall, there was a third rig being added.

Can you give an update on how many rigs are currently running?

And are there any plans to increase the rig count from current levels?

Yes, you're right.

There are 3 rigs today.

There is a plan to increase an additional rig next year.

That's just Loma Campana.

But as I said, we still -- or we need to start thinking of La Amarga Chica and Bandurria also, which will become very significant next year and in years beyond.

And we do expect we have one rig in each of those areas.

We do expect to add another 2 rigs by the end of next year in each of those areas.

That's why I said during the call that we were expecting to double the number of rigs going after unconventional crude oil by the end of next year from 5 today to 10 by the end of next year.

Our next question on the line comes from Santiago Biagini from AR Partners.

Actually, I have a couple of questions.

First, we have seen lifting costs decreasing this quarter, 15% year-over-year in dollar terms, around that.

Could you give us any color on this?

And shall we expect this to be sustainable going forward?

The second question is regarding the incentive plan for unconventional gas.

And I'd like to know which projects were already approved by the government and which ones are still waiting for the final approval considering that the government [Mr.

Iguacel] has said that going forward, projects will be suspending this incentive plan.

And taking this into consideration, which could be the implications going forward of this change in the Gas Plan?

Thank you, Santiago.

On the lifting cost question, well, clearly, the second quarter had the full benefit of the devaluation without the effect of the inflation that follows -- typically follows a devaluation of this size.

So I'd say we will be giving back some of that during the remainder of the year.

However, directionally, the trend is that we will continue to lower lifting cost, among other reasons for 2, I'd say, main drivers: one, the increase in the mix coming from shale oil, which, as you know, has a much lower lifting cost that are conventional production and Sergio showed in the presentation, a number of -- I think it was $7 of lifting -- $7 per barrel of lifting cost, okay.

And the other reason is that as we do expect not -- or the remainder of this year.

But yes, for '19, 2019 and going forward, an increase in production and given that some of our costs are fixed, we will start diluting some of those fixed costs and, therefore, reduce the lifting cost going forward.

So short answer to your question is over the short term, we will be giving back some of the benefits from the deval.

Over the long term, we will continue to see additional reductions in lifting cost.

And in terms of your question regarding incentive plan for natural gas and which projects have and have not been approved yet, we will not get into detail, which -- because it's confidential and in many cases, most cases, these are projects that we have jointly with partners.

But what I can say is that approximately half of the projects that we have filed have been fully approved, and the other half have a -- are still in process of being approved.

But all of them have been appropriately filed.

Our next question online comes from Lilyanna Yang from HSBC.

I have one question.

Could you give me more details on the cost side of El Orejano?

And another thing is when I see the Loma Campana, the well cost, why would this be much lower than the well cost for other shale players, right?

And is this more on accounting side?

You kind of showed maybe the $8 million per well.

And while others indicated that it could be $12 million.

Maybe it's accounting or indeed maybe it's indeed better productivity.

Lilyanna, before we answer the first question, can you clarify a little bit further the second question?

That -- it's not fully clear to us.

Yes.

In Loma Campana, right, you show that the well cost was about $8 million.

Now you kind of show in the slides more on the development cost is about $12 million, right.

Maybe we can clarify what else is there to make the gap?

And how can I compare the Loma Campana well cost versus the well cost of other players that indicate higher costs maybe.

Or maybe I'm wrong on that.

So if you could maybe compare well cost of Loma Campana versus other projects.

I'm not sure that the $8 million per well is comparable to the development cost.

What we -- the reason why we have moved from the cost per well to the development cost concept is that we have been changing the mix of wells.

We went from the 1,500 long laterals to 2,500.

And hopefully, we are going to go longer in the future.

So it will basically be comparing -- in order to compare apples-to-apples, we talk about development cost, and that is why we are sharing with you what our development cost is instead of focusing on the cost per well.

Now why is it that one of our wells is cheaper than some of our -- the other players in the basin?

I cannot say.

We have drilled, how many wells, in Loma Campana already?

(foreign language) More than 500 wells in Loma Campana already, well above 500 wells, and we are probably comparing with people that have only drilled a handful of wells.

So it'd be logical to assume that we are further down the curve and, therefore, are more efficient than others.

Yes.

To complement on El Orejano, so we have a development cost in El Orejano, which is around $1 per million BTU.

We are now moving into a new zone.

So this is why we are not disclosing the development cost because it's still new and we still need to have production from this zone.

Our next question comes from Javier Zorrilla from JPMorgan.

I had just one follow-up on the accrual of receivables from the gas distribution companies.

I don't know if -- from the Metrogas side, do you know the amount of accrued gross account payables from Metrogas to gas producers that you can disclose?

Also, can you please talk a little bit about refinancing plans?

I know you mentioned that you have almost $2 billion on the cash balance to, I guess, pertain the amortizations in 2018.

But I don't know if you can explain a little bit on the refinancing plans there.

And we have also heard about financing plans and YPF Energía.

If you can comment on that as well.

Thanks, Javier.

Regarding the first question, unfortunately, we don't break down the receivables by different companies.

Again, the total amount that we have accrued is -- so far, is $350 million.

Yes.

And we treat Metrogas as any other distribution company on an arm's length basis.

So there is no substantial difference in terms of what Metrogas owes to us vis-à-vis what the rest of the system owes.

To the second part of your question, we do not have any financing plans for YPF S.A. because we have positive free cash flow and significant liquidity cushion and not any important debt maturities other than $400-and-something million coming due by the end of this year of the first bond that we issued back in 2013.

There are absolutely no plans for us to issue in the debt markets soon.

What I did say during the presentation is that we've seen the bank market wide open to us and willing to lend money to us on medium-term tenors, which is good news.

And that's a market that we haven't tapped in quite some time.

So that means that any refinancing that we might have to do in the next few months is more likely than not to go through that part of the market as opposed to the bond market.

And in terms of YPF Energía Eléctrica, that's a company with substantial projects going forward, substantial growth.

And definitely, they will need to raise some debt in order to cope with all the CapEx with each of those projects.

Some of the financing will come from ECAs.

Some might be done as a project finance basis, as it has been done in the past.

And that's all we have to say for now.

We are not working -- now I'm talking for YPF EE, which, by the way, we have renamed YPF Luz.

We are not working in any bond offering as we speak.

Of course, with the markets reopen before the end of this year or next year, it is possible that YPF Luz will decide to tap those markets.

Our final question comes from Vicente Falanga from Bradesco.

I had just one question here.

When you see that prices of $4.50 to $5 are good enough to support gas production, what sort of IRRs are we looking at?

And can we assume that $4.50 is for tight and $5 is more for shale?

Thank you, Vicente.

No, you should not assume that $4.50 is for one type of gas and $5 for the other.

As I said, the way we look at it is weighted average price of gas for the company.

So if it's going to be shale or is it going to be tight or it's going to be associated gas, it will all depend on the returns on a project-by-project basis.

We do prioritize projects based on expected returns.

And if shale projects are more or less attractive than tight projects, those are the ones that will or will not get a sanction, okay.

But I don't think that we are going to a pricing scheme in Argentina where there's going to be a difference in terms of the type of development, if it's tight or if it's shale or conventional.

And unfortunately, to the other part of your question regarding IRRs, we do not disclose what are the expected IRRs.

What we have always said is that 13% on a dollar unlevered basis is our cut-off rate and that we do not sanction projects where the expected returns below that return or that level, I should say, but from there upwards.

It varies a lot from project to project, and we have never disclosed the IRRs on any given project.

And we have no further questions at this time, I would now like to turn the call over to Daniel for closing comments.

Well, thank you very much, everybody.

Thank you, Sergio and Diego, to organize -- for organizing the call.

And as always, if there are any follow-up questions, please feel free to e-mail or to call any of us here today.

So have a great day.

Bye.

Thank you.

Ladies and gentlemen, this concludes today's conference.

Thank you for participating.

You may now disconnect.