YPF SA (YPF) 2015 Q1 法說會逐字稿

Welcome to the YPF Sociedad Anonima first quarter 2015 earnings conference call.

My name is Lorrena and I will be your operator for today's call.

At this time all participants are in a listen-only mode.

Later we will conduct a question-and-answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr. Diego Cela.

Mr. Cela, you may begin.

Great.

Thank you, Lorrena.

Good morning, ladies and gentlemen.

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

I would like to thank you for joining the YPF first quarter 2015 earnings webcast.

The presentation will be conducted by our CFO, Mr. Daniel Gonzalez.

During the presentation we will go through the main aspects and events that explain our first quarter results.

And finally we will open up the call for questions.

We will be making forward-looking statements.

So I ask you to carefully review the cautionary statement on slide 2.

Our agenda today will include the review of the first quarter results, including an update of our shale and tight development projects, a brief description of our financial situation and a brief summary to conclude.

Please, Daniel, go ahead.

Thank you, Diego, and thanks everybody for joining us this morning.

We are very pleased to report our first quarter 2015 results, a quarter, as you know, in which the global oil and gas industry has suffered and is still dealing with a low international pricing environment with BRENT prices down 50% from a year ago.

In this context we believe it is remarkable to show our EBITDA in pesos up by 21%, with revenues also up by 13%.

However, operating income was only up by 2% and net income was actually down by 26% affected by higher depreciation and lower exchange gains.

Operating cash flow of ARS12 billion, up 78% from a year ago, allowed us to finance substantially all of our CapEx with our own cash generation, therefore keeping our leverage ratio virtually unchanged from the end of last year.

We produced 10% more hydrocarbons than a year ago and processed 9% more crude in our refineries.

As every quarter, we also show our most relevant income statement figures in US dollars to help explain the evolution of our business in real terms.

This is also how we, the management team, look at the Company in the long term as we do our planning and set our own annual objectives also in dollar terms.

Revenues were essentially flat in dollar terms as volume and price increases in the local market were offset by significantly lower international prices.

EBITDA was up 6.4% in dollars, despite the fact that we are comparing against a quarter in which the peso had suffered an important devaluation and therefore a good part of our cost basis had been diluted in dollar terms.

Operating income, however, dropped 10% in the quarter as higher depreciation expense more than offset the margin expansion at the EBITDA level.

Going back to the Argentine peso analysis on next page we can see that operating income for the first quarter of 2015 was approximately ARS4.5 billion, which was 1.9% higher than the first quarter of 2014.

Revenues grew by ARS4 billion, or 13%, resulting from ARS3.1 billion increase in the liquid fuels sold to the local market, on higher volumes of gasoline and lower volumes of diesel oil, but both at higher prices, a ARS1.5 billion increase in natural gas sold on higher volumes and higher prices both up 19%.

ARS450 million increase in fuel oil sold to the local market, although offset with a ARS300 million decrease in fuel oil exports.

And finally, a reduction of ARS1.1 billion in export sales, mostly as a consequence of lower international prices.

Cost of sales grew by ARS3.1 billion, or 13%, in line with revenue growth.

The largest single item contributing to the cost increase was again depreciation, which was up 43% or ARS1.7 billion.

Purchases were actually reduced by ARS1.3 billion, mainly as a consequence of both lower prices and lower volumes of imports of refined products.

This was partially offset by an increase in crude oil purchases from third parties in the domestic market due to 3% higher dollar prices but with lower volumes because of our increased crude production.

Other cost of sales were up with higher activity.

There was a ARS1.6 billion increase in lifting cost and a ARS500 million increase in royalties and ARS320 million increase in refining costs.

Lifting cost on a per barrel basis was up 8% to $14.4.

Now this is when we compared with the first quarter of 2014.

This number is in line with that of the last quarter of 2014.

The reason for this is that the devaluation of the peso in the first quarter of 2014 had had a dilutive effect in some of our costs.

As in previous quarters, we also accrue the recovery from the insurance in our La Plata refinery fire of 2013, this time for ARS511 million.

And this was accounted for as less cost of sales.

This was the last quarter in which we benefited from the insurance recovery as the business interruption coverage reached its contractual limit.

Entering now into our upstream business segment, operating income declined by 25% against the first quarter of last year to reach approximately ARS2.3 billion.

And this was mainly due to the reduction in crude oil prices of $7 per barrel.

Bear in mind that the Company transfers all of its crude production to its downstream business segment, therefore the crude price reduction does not have a negative effect in the Company as a whole.

The average crude oil price in the domestic market was approximately $69 a barrel; and gas prices, on the other hand, were up to $4.6 per million BTU.

Despite the dollar price decline in crude oil, both oil and gas prices were higher in peso terms.

And therefore revenues were up by 24.5%, primarily due to this peso price increase and also to production growth of both oil and natural gas.

Costs were up ARS4.4 billion, which was a 37% increase compared with the first quarter of 2014, mainly due to higher depreciation of ARS1.5 billion, ARS1.6 billion increase in terms of lifting costs, as explained before, and higher royalties also as I explained in the previous slide.

Production wise, we continue to perform very well with double-digit growth figures vis-a-vis the first quarter of last year and slightly above the total production of the last quarter of 2014.

Crude oil production in the first quarter was up 2.3%, producing 247,000 barrels of oil per day.

Unfortunately, this production was not enough to achieve the $3 per barrel incentive price put in place by the government this year.

The reason for this mainly has to do with the adverse weather conditions and the power outage.

In terms of natural gas, the increase in production was 18%, producing 43.9 million cubic meters a day, heavily impacted both by the ramp-up in tight gas production and also incorporation of the former Apache Argentina assets which we have renamed before.

NGL, finally, saw a production growth of 12% to reach 60,000 barrels a day.

As a result, in this quarter, total hydrocarbon production was up by 10% to 584,000 barrels of oil equivalent per day, comparing that to 530,000 barrels for the same period in 2014.

Now let's describe what we are doing with the shale oil and gas development.

We have connected 47 wells during the quarter, taking the total to 332 producing wells.

In terms of rig count, we peaked at 18 drilling and 7 workover rigs.

Gross production from shale areas reached 41.7 thousand boes a day in average in the quarter from which we consolidate approximately 50% as it is mainly coming from Loma Campana, our joint venture with Chevron, which has become, by the way, the second largest oil producing field in Argentina.

We said earlier this year that we would be accelerating our horizontal drilling.

And during this first quarter we have drilled five horizontal wells, three of them in Loma Campana, and two in Orejano, which is our joint venture with Dow Chemical.

Just to share a couple of data points, one of these horizontal wells in Loma Campana showed an outstanding initial production peak rate of almost 1,200 barrels a day.

Another Loma Campana horizontal well was drilled, cased and completed in a record time of 27 days.

The last wells are being completed at cost of around $15 million per well with approximately 15 frac stages per well.

Clearly the east part of Loma Campana, we will see more horizontal wells as the productivity is encouraging and we continue to make progress on the cost side.

And let's not lose focus on the fact that we only have 5% of our total Vaca Muerta wells being horizontal so far.

The sweet spot in the west area of Loma Campana continues to be developed with vertical wells with good productivity.

We continue to deal with interferences between wells, the production has been somehow slower as we close contiguous wells when we frac and then we open them again, so nothing that cannot be expected from a normal learning curve.

We have been ramping up our production engineering activity all over Loma Campana to optimize productivity.

Some of the actions include running tubing to most of the wells that had been producing tubing lifts, running pumps and plunger lifts and implementing debottlenecking of surface facilities.

We have even started drilling slim holes but it is still early to say if it is an efficient way to develop less productive areas of Loma Campana.

On the shale gas side, good progress has been made in the pilot in El Orejano.

We currently have nine producing wells, two of which are horizontals and another eight more wells will be in production soon.

We are already producing over half a million cubic meters a day from El Orejano.

Tight gas continues to be one of the drivers of our production growth and now represent 12% of YPF's natural gas production.

We have drilled nine wells targeting the Lajas formation in Loma La Lata block where we own 100% and ten wells targeting the Mulichinco formation in Rincon del Mangrullo block where we own 50%.

As a consequence of our drilling activity, production continued to grow reaching 4.3 million cubic meters a day in the Lajas project and 1.4 million cubic meters a day in the Mulichinco project.

Turning to our downstream business segment, this quarter's operating income was ARS1.5 billion, showing a decrease of 39% compared with the first quarter of 2014, mostly related to a 5% reduction in prices at the pump.

However, revenues were still up by ARS2.2 billion or 8%.

As previously explained, revenue growth mostly results from higher sales of diesel and gasoline.

Diesel sales were up ARS1.7 billion on higher prices which were approximately 1.5% higher in dollar terms but lower volumes, where in terms of gasoline sales these were up by ARS1.3 billion on higher prices, 5.5%, but also higher volumes.

It is also worth highlighting that in this quarter we have improved the mix of products sold, increasing sales of premium products which now represent 32% and 17% respectively of our total gasoline and diesel sales.

In the export market we noticed a decrease in sales of 31% or ARS1.1 billion mainly due to the recent fall in international prices for those products which prices are tied to the BRENT oil.

Also, in 2014, we had seen crude exports for ARS520 million that were not present this quarter.

However, these export declines were somehow mitigated with lower withholding taxes which were accounted for in less SG&A.

Fuel oil sales in the domestic and international markets totaled ARS2 billion, representing an increase of ARS150 million, mainly due to higher volumes sold in the domestic market as well as higher prices in pesos, but partially offset by the decrease in export volumes and lower international prices.

Costs increased by 12% compared with the same period of 2014 and there we highlight an increase in crude oil purchases of ARS2.9 billion mainly as a consequence of higher prices in peso terms for both volumes transferred from YPF upstream business segment as well as purchases from our producers; second, the higher prices and volumes of biofuel purchases accounting for an increase of ARS1 billion as the blend increased to 10%; third, higher depreciation of ARS150 million; and lastly, lower imports of diesel, gasoline and jet fuel for a net amount of ARS3.1 billion due to lower volumes purchased and at lower international prices.

This quarter, we booked ARS511 million in insurance compensation due to a loss of profits affecting the business after the damage suffered by our La Plata Refinery and this is netted in the bar named purchases.

Let me make a clarification with regards to the operating income breakdown by business segment.

When you are at the operating income for the upstream and the downstream and then you subtract the approximately ARS500 million loss derived from the corporate, you end up with a number which is lower than the Company's consolidating operating income.

The reason for this has to do with a negative charge of approximately ARS1.3 billion related to valuation of our inventories after the price declines of the quarter and which was fully allocated to the downstream business segment only for segment reporting purposes.

In other words, this charge is not a loss for YPF and is eliminated as part of our consolidation process.

During this quarter, volumes of crude oil processed were 300,000 barrels of oil per day, which was 9% higher than the first quarter of 2014.

In a way being this an unfair comparison because that first quarter of 2014 we had had a scheduled maintenance stoppage in our Lujan de Cuyo refinery, therefore reducing the processing capacity and leaving some excess heavy crude that was then exported.

Anyway, this way we were able to reach a 94% utilization rate as a consequence of having greater availability of light crude oil in the throughput mix due to the increase in shale oil production.

This refinery output allowed us to satisfy an overall 8% increase in demand with higher volumes of gasoline sold of 1.4% and a decline in diesel volumes sold of 0.7%.

On this slide, we have plotted YPF's monthly sales for the last two years and the first quarter of this year.

You can note that the green line represents 2015 sales and almost replicates the performance during the similar period of 2014.

Actually, April 2015 sales were significantly above last year.

So we are seeing a much stronger local market than expected.

Our market shares remain with little changes around 58% for both diesel and gasoline.

During the first quarter of 2015, total CapEx for the Company amounted to ARS12.4 billion, 27% higher to that of the first quarter of 2014 if we don't include in that quarter the additions related to the acquisitions of YSUR and additions taking Puesto Hernandez net of the sale of certain areas to Pluspetrol.

Actually, considering those acquisitions and divestitures, CapEx was approximately ARS16 billion in the first quarter of the previous year.

Upstream CapEx amounted to ARS10.7 billion, 24% higher than the first quarter of 2014.

Most meaningful investments have taken place in Loma Campana, Toledo-Sierra Barrosa, Rincon del Mangrullo and Chachahuen.

With regards to exploration, in this quarter, we completed 12 exploratory wells and three workovers.

We have stabilized our rig count in approximately 75 rigs from which 62 are drilling for oil and 13 for natural gas, maintaining a consistent level of activity and investment.

In downstream, CapEx was ARS1.4 billion where our largest ongoing project is a new coking unit being built in our La Plata refinery.

We are scheduling its completion in the first quarter of 2016 and commencement of operations in mid-2015.

Now let me get into the financial situation.

First quarter of 2015 was a very solid quarter in terms of operating cash flow reaching ARS12 billion which is 78% growth compared to the ARS6.7 billion in the first quarter of 2014.

First quarter does not include any extraordinary or non-recurring items, but the first quarter of last year had been particularly weak in terms of cash generation.

This higher cash generation allowed us to fund most of our CapEx with our own operating cash flow while maintaining our net debt to EBITDA ratio at 1 time.

We use this next slide to show how we have been lengthening the average life of our debt to almost five years.

Of course, this maturity extension comes with an increase in the average cost of our debt which now stands at 7.5% for the dollar-denominated debt and approximately 23% for our peso-denominated debt.

By the way, all the figures on this slide are pro forma for the debt issued in April, both the $1.5 billion, 10-year international bond as well as the ARS930 million local bond.

This strong cash generation of our -- this strong cash position of around $2.5 billion should allow us to fund all of the needs of the year without any need to access international markets again.

We are working on our capital bank facilities and local capital market street that should complete all of our needs for the year.

In summary, we believe this was just another quarter moving in the right direction.

We have been able to deliver very solid results despite a very challenging global oil price environment and these results compare favorably with almost anyone else in our space.

We continue focusing on cost reductions to offset the potential effects of our strong peso.

And we believe that these efficiencies should prove to be structural and not just help us weather this particularly difficult time for the industry.

We are keeping activity flat as we believe price visibility for the short term coupled with our medium- and long-term price expectations for the future, support our ongoing projects.

Of course, the more challenging projects especially those of shale, oil and gas need to prove over time that the assumptions that we are making with regards to cost and productivity as doable.

So far, our shale and tight development projects are progressing very well and we are addressing our learning curve challenges.

We continued to build a strong cash cushion (inaudible) no issues to prevent us from having to access markets at times of potential increased volatility.

And, finally, we continue committed with a 5% sustainable upstream production growth.

With this I would like to open it up for questions, and thank you very much for your attention.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions) Bruno Montanari, Morgan Stanley.

Thanks for taking the question.

I have a couple of questions.

First on shale.

What can we expect in terms of the ramp-up at Loma Campana in the coming quarters?

So, will this well interference team and the pace of new drilling allow a sustained increase of production going forward?

The second question is on the cost front, just wondering if the negotiation for the 2015 labor contract has been concluded and what was the wage hike agreed for the year?

And if I can throw in a third and last one, under the new structure of crude oil prices in Argentina what was the implication of this $15 rebound in oil since January?

Thank you very much.

Good morning, Bruno, thank you for the questions.

First on the shale, you should expect no changes in the drilling activity.

If there was some slowdown in production, a good part of that has been addressed in last couple of quarters.

We will continue to deal with these interferences with, as I mentioned, closing and opening the wells.

But again, I am not expecting any significant change from our own expectations, our own budget projections for shale production for the year.

So the ramp-up, we obviously never provide projections on annual production or a quarter-by-quarter production.

But in terms of drilling activity, we should be drilling not less than 150 wells in Loma Campana this year.

Okay.

Now, in terms of labor, we have extended the fixed amount being paid which was originally scheduled for the first quarter and we have extended that for the second quarter also.

So we have an agreement until the end of June.

We still have not had any meaningful negotiations concerning the second part of the year.

So it's still little bit early to say.

But, as we have always said, this is one of the most relevant challenges for us this year as it is likely that labor cost might increase at a higher pace than our price increases.

And third on crude price rebound, well, as much as we were not affected with the crude prices decline, we were not affected either by the rebound.

Okay, other than those products that we sell both locally and internationally at prices tied to the Brent and the effect there continues to be that of in the order of $100 billion to $150 billion of EBITDA impact every $10 of Brent price fluctuation; that has not actually changed.

Great, thanks.

So just to clarify, there shouldn't be any meaningful cost pressures coming from wages into the second quarter, right?

Second quarter, definitely not.

Going forward, I think more has to do with how the macro behaves, okay.

What I am trying to say is what is the pace of labor cost increases and what is the pace of devaluation and therefore price increases, okay.

But second quarter clearly you will not see any pressures coming from this side.

Got it.

Very clear, thank you very much.

Frank McGann, Bank of America Merrill Lynch.

Okay, thank you, good morning.

Two things maybe, one is just in terms of prices, do you still remain confident that as the peso devalues however slower -- slowly or quickly you will be able to adjust prices to maintain prices in dollar terms for 2015?

And then secondly in terms of the rate of growth of shale, oil and gas versus tight gas, I was wondering how, do you expect tight gas to grow faster than the other two and how do you see that over the next 12 to 24 months?

And then if I could just ask quickly on working capital, you had very good performance, it appears in the first quarter, how do you see working capital over the next couple of quarters?

Thank you, Frank.

In terms of prices, yes, our vision continues to be that we will be able to keep our prices essentially flat in dollar terms.

So hopefully, we will continue to adjust them as the currency devalues.

In terms of shale and tight growth, as I said, we will not provide a breakdown of the next few quarters or even what our expectations are for the year.

The only guidance that we have been providing in terms of our production growth is for total production and that continues to be a 5% per year growth, which in this quarter we were well ahead of that and in the next few quarters the comparison is going to be more difficult but we do expect to be able to achieve that.

Now, in terms of the pace of growth comparing shale to tight, that I don't think it's a fair comparison.

I think tight we've done a lot and therefore there is still a lot of growth but probably the pace of growth is lower than that of shale.

If you look at the slide that we presented on Loma Campana, you can see that we are now producing 41,000 barrels of oil equivalent a day.

And if you go two years back we were only producing 8,000.

So the pace of growth is that we have increased fivefold the production in two years.

Well, you do not necessarily see the same type of growth in the tight.

Actually if you look at the page in the presentation in which we presented the tight, we already have a very significant base.

And the production growth of course is much higher in Rincon del Mangrullo and we are coming from less than 1.5 million cubic meters a day than in the Lajas formation where we have already reached 4 million cubic meters a day.

In any event, both projects continue to perform well and tight continues to be an important driver of natural gas production.

In terms of working capital, as I said, this quarter does not include any one time or any nonrecurring items that has favored the number.

Having said that, in the next few quarters, we're going to be having to pay much higher income tax than before, and that's basically because the 2014 earnings were significantly higher than 2013 and therefore we have to pay income tax on that; and start paying under income tax regulations in Argentina the advances on 2015 income tax based on the 2014 number.

So therefore that's going to be eating part of the operating cash flow in next few quarters.

Other than that we are not seeing any substantial differences to what we experienced in the first quarter.

Okay.

Thank you very much.

Regis Cardoso, Credit Suisse.

Thanks for taking my questions.

I have two questions, one regarding costs and the other on CapEx.

So the first one on costs.

In the current environment it's of course harder for wet gas to increase prices as fast as you have done in the past.

So the question is, is there anything you can do on the OpEx front to prevent margins from being compressed as they have been the past two quarters?

It seems that costs have increased across the board in Q1 both for upstream and downstream.

So that would be the first question.

Second question on CapEx.

The CapEx for the quarter is at $1.8 billion, that's above the average range for the year, which is $5 billion to $6 billion.

So is there any seasonal effect or we should expect higher activity levels?

Thanks.

Okay.

Thank you Regis for the questions.

On the cost side, yes, we are clearly starting several initiatives.

One that we have mentioned, I think in the last call is that we have actually addressed all of our most significant service providers in the upstream and basically demanded an outright rate reduction, which we have actually obtained in most of them.

Actually part of that has a positive effect in OpEx and part of that has a positive effect in CapEx, okay.

Then how OpEx actually evolves for the remainder of the year, a good part of that, in dollar terms, will have to do with how the market evolves, okay, what are our assumptions in terms of inflation and in terms of the devaluation of the currency.

There is a general consensus that the currency will devalue during this year less than the inflation pace.

Okay.

If that were the case, without doing anything, your OpEx would actually go up in dollar terms.

So what I addressed in the presentation is that we are taking proactive measures in order to protect our margins and in order to prevent OpEx from going up if we have this environmental of a strong peso.

So that is clearly being targeted.

In the downstream that's less of an issue, because almost 80% of the cost base of the downstream is the crude oil purchases.

In our case, most of the oils are just transfers from our upstream segment.

But refining costs in itself are not really that significant and are mostly labor related.

In terms of the CapEx number, the $1.8 billion that you mentioned we are probably taking it from the cash flow statement that's actually ARS16 billion or ARS15 billion outlays, which were higher than the ARS12 billion actual CapEx or economic CapEx of the quarter.

And that only has to do with the fact that December or the fourth quarter in general is usually a stronger month in terms of CapEx and therefore in the first quarter you pay a lot of the bills of CapEx actually incurred in the fourth quarter of the previous year.

But to the fundamental of your question, no, we are not making any changes to our CapEx expectation for the year.

We are still targeting in the order of $6 billion of total CapEx.

Perfect.

Thank you.

Santiago Wesenack, Raymond James.

And thanks for taking my question.

Just one, actually two quick ones followed on the cost side.

The first one would be, we saw in the E&P segment this quarter a decline actually in cost increase year over year.

So I was wondering if we could assume that cost will grow at this new rate or will go back to higher rates like the ones they did in the fourth quarter.

And the second question it's related to if there is any update if you could give us in terms of bringing your own sand into a local market instead of importing from China and Brazil?

Thank you.

Hello, Santiago.

Thanks for your question.

On the cost side, I think what was tricky on this quarter is when we compared with the first quarter of last year, because last year we had had that relevant devaluation and therefore a good part of our cost basis had been dilutive.

When you actually compare with the fourth quarter and actually also with the third quarter of last year, you can see that lifting cost on a unit basis is virtually flat.

Okay.

So we do expect some of the measures that we mentioned before in terms of OpEx reduction to hopefully offset a potential negative affect coming from the strong peso as I said earlier.

But with this environment of a potential strong peso, [it beat us] to expect any significant reduction in OpEx or the lifting cost in a dollar basis, right.

Second, in terms of your request, it's going as planned, it's going very well.

We actually are already starting to mine our own sand.

We are going to be treating that sand close by to Anelo.

We are working in different logistics in order to reduce as much as we can the freight of that -- sand that will be transported from our mines in the province of Chubut to our treating facilities in Anelo and from there to, of course, to the field.

But, as we said earlier, when this project is up and running and we should expect that to occur by the end of this year, that should have an effect of a reduction of approximately 50% in the cost of the sand.

And that goes directly to CapEx, not to OpEx.

Great.

Thank you very much.

Gustavo Gattass, BTG Pactual.

We had two questions here as well.

The first one, now if I could I just wanted to touch on what you said about the refining adjustments during the call, the mention of the ARS1.3 billion.

If we really adjust for that, we would get EBITDA in the unit of about $350 million, which is fairly consistent with what you were having before oil prices started to fall.

And I remember last quarter, in the discussion, I got the impression at least that part of the drop in the profitability of the downstream business was those products that were not sold in Argentina.

So I just wanted to get a sense, is it correct to understand that even with these low oil prices, the prices that you were able to get in Argentina have allowed, say, profitability to be fairly similar to what you had in the past?

That's the first question.

The second question.

I just wanted to revisit the points made up until now on the shale and the pace of growth.

You guys are mentioning about 160 wells.

I just wanted to understand we are seeing a little bit of a slowdown in the amount of growth that you saw.

Does the company believe that you have, let's say, significant or enough locations around the sweet spots and the good areas to make those 160 wells be it as impactful as the last wells that we were seeing back in 2014 or should we believe that on the margin there will be some loss of productivity in terms of just rolling out more and more of the development plan.

Just wanted to understand that I do know that you're not going to give us a guidance specifically for it but just trends that's what I was looking for.

Thank you.

Thank you, Gustavo.

Well you were right, you're probably the only one that made that refining adjustment that has to do with the valuation of inventories.

The reality is that the crude oil price reduction which, as you very well said, has a positive effect on the downstream.

A good part of that is offset by the fact that we reduced prices in the downstream mainly on the [pump], by 5%, right.

So a part of that was financed with some tax relief provided by the federal government.

But the reality is that the prices at which we realize our products actually came down.

The most important raw material which is crude oil also came down.

So, I think that you can -- other than that adjustment that you made reference to there was nothing else in this quarter which is different to what we expect for the next few quarters, other than the fact that we don't know exactly at what pace we're going to be able to continue to increase prices.

All we can say in that respect is that our reason continues to be to keep prices at flat dollar terms.

But we continue to believe that our downstream business has very healthy margins and that we should be able to preserve those margins as much as possible.

If there is any cost pressure in the year, most on the upstream side, okay, where a good part of our upstream cost are related to the labor, okay, and that goes to a point I made earlier that it is likely that labor might go up at a pace which is somehow higher than the pace at which we will be able to increase our prices.

Now, on your second question regarding a slowdown, I don't think there is a slowdown, I think that we continue to target, as I said, 150 wells actually the budget of all like 170 but you should assume that that is a wide range and we are going to be moving within that range.

None of our partners or ourselves have made any decision in terms of slowing down any of the projects so far.

And in terms of locations, I think we do have all the locations for this year.

Bear in mind that the development is going to be much heavier on horizontal wells.

So, what you will see that the East part of Loma Campana will have a lot of horizontal drilling.

The West part will continue with the vertical drilling and the West part is what we call the sweet spot.

Then the center part of Loma Campana which has less productivity than the West, we are testing these slim holes also.

So in terms of locations, I don't think that that is an issue.

In terms of productivity, what we have said, it varies significantly even within the same concession area.

The same formations, same concession area but in different parts of that concession area the productivity varies significantly and also the GOR vary significantly, the gas to oil ratio varies significantly.

So in parts like the west we are having much higher GOR than the center.

So, I think that we continue to learn, we continue with our plans, we are not changing activity, we are not changing our own expectations in terms of production and we are dealing with some of the operating issues as we arrive to them.

I believe it's a normal learning curve situation.

Okay.

Thank you.

Alejandra Aranda, Itau BBA.

I know you touched upon the question of the labor negotiations.

I was wondering if you could tell us more about the mood of this negotiations.

I know you said you have an agreement till June.

But looking at it from a calendar perspective in Argentina it's going to be a very tricky month, especially looking at politics.

So I was wondering if you could tell us how the mood is developing in the south with the unions.

Hi, Alejandra.

Thank you for the questions.

Frankly, there is nothing that we can actually comment on, not because there is something going on that we don't want to tell you, it's because with the extension of the fixed amount, those discussions are actually being postponed, being pushed back, right.

So, what the mood will be in June, a month, a month and a half from now, I don't know.

I don't see why it will be different to what the rest of the unions across different industry sectors in Argentina are going to be facing.

This is a very relevant issue for many of the industries, it is for us.

But there is nothing leading us to believe that we will have a different tone in terms of the discussions which have always been very constructive with all of our unions.

Okay.

Thank you.

[David Dunbore, TPH].

Just a couple of questions regarding type curves in the shale.

When we look at the proved reserves that were added from Vaca Muerta of around 24 million boe, we saw that the split was around 50% oil, 24% NGLs and 26% gas.

I am just wondering if this is a good estimate going forward probably for the average split of hydrocarbons expected from wells in the Vaca Muerta.

And just if you could clarify if this gas component of the mix, is it not higher than initially expected?

On that same line, just can you give us an update on your EUR expectations from the vertical and horizontal wells if possible?

You gave some encouraging IP rates today during the call.

So just wondering if you have any thoughts or any updates on or guidance on that EURs for our type curve modeling.

Thank you.

Thank you, David.

No, unfortunately we cannot provide you with any projections or estimates of how reserves will behave in the future and what the component of oil, the heavy NGL and gas will be.

What we can tell you is that in the west side of Loma Campana we have found that the GOR is much higher than expected.

But in the center it was probably as expected and in the east might have been even lower than expected.

So that varies dramatically.

In terms of the EURs, in the sweet spot that's the only EUR that at some point we have commented.

We are assuming oil in the 250,000 barrel area and including adjusted with a GOR including liquids and gas we are in the 400,000 to 450,000 boes of cumulative production.

But that's just the west side.

And, as I said, it varies dramatically from different parts of Loma Campana.

If we are successful in the slim hole drilling, for instance, you might see much more cheaper wells, maybe with lower productivity but with economics on a per-well basis which could actually be better.

And again to the point or the question that was previously posted by Gustavo, a good part of wells, especially in the east, are horizontal wells.

In that case, we are not providing any EURs yet because we have drilled probably, what, 15, 20 horizontal wells so far.

So we have not enough critical mass in order to give a sense of what the EURs are going to look like.

But what we can tell you is that the economics of the last few wells, few horizontal wells look promising.

Taking into account initial production, of course, EURs and the cost basis of those wells is clearly coming down.

Very helpful.

Thank you.

Thank you.

We have no further questions at this time.

I would now turn the call over to Mr. Cela for closing remarks.

Okay.

Thank you very much for joining us today.

With this we conclude the presentation.

Good morning.

Thank you.

Thank you.

And thank you ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.