YPF SA (YPF) 2014 Q4 法說會逐字稿

Hello and welcome to the YPF Sociedad Anonima Q4 2014 earnings conference call.

My name is Tiffany 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.

Thank you, Tiffany.

Good morning, ladies and gentlemen.

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

I would like to thank you for joining us.

In this occasion, we will discuss YPF's results for full-year 2014 and the fourth quarter of 2014.

The presentation will be conducted by our CEO, Mr. Miguel Galuccio; and our CFO, Mr. Daniel Gonzalez.

During the presentation, we will go through the main aspects and events of the year 2014 and the fourth quarter results in detail.

Finally, we will open up the call for questions.

Thank you Diego and thank you everybody to join us.

2014 was another year for this turnaround of YPF that we started almost three years ago.

We delivered higher production, substantially increased our reserve and continue to show a strong number.

In the full year of 2014, revenues were up 6% in dollars driven by higher volume across all our products and improve in pricing.

EBITDA was up almost 17% in dollar taking our EBITDA margin to 29%.

We produced 560,000 barrels of oil equivalent per day which was 13.5% higher than the previous year.

And what is even more important, we increased our reserve for the second year on the row showing a reserve replacement ratio of 163%.

We execute a large acquisition and we can already show solid result from that.

And we are stuck with our commitment on maintaining a conservative balance sheet.

Our leverage is still below 1 times versus EBITDA.

I will cover the review of the year and then Daniel will share some details of our financial results.

Now let me start with the session by focusing our financial results which were in line with our expectations.

Although we formally report in Argentine pesos, we measure ourselves in dollars and we understand the oil and gas business that way.

That is why we also show our more relevant income statement figures in dollars.

We are happy to see our revenue growing by 6%, but more so when we see that our margin expectation resulted in EBITDA and operating income growing at much higher rate.

Three years ago we received the Company with an EBITDA in the order of $3.6 billion and we are now at $5.1 billion despite of some one-time hits.

Production wise, in 2014 we consolidated positive trend.

We begin to experience during 2013 and this way we end in this year with a total hydrocarbon production growth of 13.5%, 560,000 barrel of equivalent oil per day compared with a 493,000 boe that we produced in 2013.

You can note on the graph that we are able to keep our legacy conventional production essentially flat.

And production growth come from both acquisition and shale and tight development.

Even without considering the Apache acquisition, our total production was up by 5.7%.

Regarding crude oil production, we were up by 5.3% producing 240,000 barrels of oil per day, being slightly above our 5% target despite the incident that we had in Mendoza early this year.

In term of natural gas, the increase in production was 25.1%, comfortably above our 18% guidance, producing 42.4 million cubic meter per day heavily impacted both by the ramp-up in the tight gas production and the incorporation of the formal Apache operation now renamed YSUR.

If we move to the slide 8 and moving into reserve, once again I think it was probably the most important achievement we had during 2014.

If you want to replicate our production growth, definitely we need to have our reserve in place.

We increased the total proved reserves by almost 12%, adding 333 million barrel of oil equivalent per day, of which 154 million barrel of oil equivalent per day corresponds to liquid and 179 million barrel of oil equivalent per day to natural gas.

The total proved reserves reached 1.2 billion boe.

The increase is a historical achievement for us since the Company has not record this type of increase since it was listed in the New York Stock Exchange.

Consequently, our reserve replacement ratio on 2014 was 163% from which a 184% come from natural gas and 144% for liquid.

This is the higher reserve replacement ratio in the last 15 years.

With an addition coming from different sources, one is from the acquisitions from Apache and Puesto Hernandez, net from the capital of this investment resulting in an addition of approximately 100 million boes.

Additionally, I would like to highlight the reserve additions in another areas.

First one, Aguada Toledo and Sierra Barrosa, with the development of our tight gas in the Lajas formation.

Rincon del Mangrullo also developed of tight gas and in the Golfo San Jorge and Neuquina basin due to the new oil and the gas development project as well as the extension of our secondary recovery projects.

And last, the extension of the concessions in the province of Rio Negro.

This slide shows our progress on shale oil and gas development, mainly in our Loma Campana and Orejano blocks in which we have as a partner Chevron and Dow Chemical respectively.

We have reached a total of 290 wells producing from Vaca Muerta formation.

284 of them with shale oil production and six of them with shale gas production.

During 2014, we drilled 182 shale wells including 173 in the shale oil wells and nine shale gas wells, more than the [total] that we have drilled in the previous year so far.

At January 15, the total gross shale production at Vaca Muerta was 14,200 barrels of oil equivalent per day in which we own 50%.

Regarding Loma Campana, in the past few months we have drilled four horizontal delineation wells targeting distinct horizons, one well land in the hot shale that we call [Vaca Siena], the interval with the best petrophysical characteristics of Vaca Muerta reaching a peak of oil production of 580 barrels of oil equivalent per day.

The number of hydraulic fracture per horizontal well, we have increased currently to 15 stages from an average of ten stages that you have seen in the previous year.

Our development plan will contemplate an acceleration of horizontal wells during the current 2015 year.

Regarding El Orejano, which we only start this year in a pilot form, the gas production went from 250,000 cubic meter per day to 650,000 cubic meter per day.

This increase is mainly due to the performance of two horizontal wells.

We were also completing two vertical wells and two additional horizontal wells, and we have another two vertical wells waiting for completion and two horizontal wells being drilled in [Zadaria].

All these wells are going to substantially increase the output from this field, thanks to the installation of additional separation capacity.

The current capacity to process wellhead gas has gone up from 250,000 cubic meter per day to 1.2 million cubic meter per day.

Currently, we are carrying now three initiatives on our shale development.

First is to increase the extension and number of fractures of horizontal wells.

As you are well aware, we have drilled probably in an area of 1,000 meter lex and probably an average of 10 stage fracs.

We believe we can go far beyond from that.

Second, to optimize the cost by using national funds including our own fund that will be mining and treating very soon, probably toward to the third or fourth quarter of this year.

Third, the new stimulation service contracts at a much more competitive rate and some of the rest of the service rate that we have managed to campaign and reduce.

Lastly, to test the low cost maneuver 3 1/2 horizontal wells for REF with low productivity.

We are learning fast but we are also facing some challenges for our share development that will be good part of our focus in 2015.

First the development of horizontal well in sweet spot in factory mode.

As you are aware, we have applied a factory mode in vertical wells but we get fracture-applied factory mode in horizontal wells to understand the subsurface a bit more to solve some interference problem that we have detected between wells and to enhance our supply chain with a vertical integration of services such as provision of sand distribution and another supply.

A key pillar of our growing in production is explained by our renewed focus on natural gas development.

The natural gas production performed an impressive 25% growth mainly due to the YSUR acquisition and our outstanding performance in the perforation at tight gas.

We have reached a total consolidation gas production of 42.4 million cubic meter per day during 2014, while in the fourth quarter we produced 43.4 million of cubic meter per day.

Our natural gas drilling activity has also increased in 2014.

We drill currency 110 natural gas wells, almost twice the drilling activity we had in 2013 and five times than the one that we had in 2012.

And you should expect that this continues to grow in 2015 as the average price for our natural gas is $4.4 per million BTU in this last quarter.

YSUR is currently contributing approximately 5.8 million cubic meter per day and our tight gas development in Lajas another 5.1 million cubic meter per day.

The small decrease that you might note in the graph for the fourth quarter of 2014 is due to preventive maintaining and the shutdown of El Porton field.

In this slide, we break down our crude oil production and you can see that the secondary recovery represent 40% of our total production.

We have increased this production by 10% this year by focusing on our (inaudible) and large experience that we have in secondary recovery development.

Bear in mind that our recovery factor are still relatively low and we are comfortable with the potential that secondary recovery and tertiary recovery represent for YPF in the future years to come.

Regarding our primary production, we have reversed the natural decline of the mature fields with an increase in new wells drilled and workover activity.

Shale oil production is a nice add-on but still only represents approximately 5% of our total crude oil production.

Now let me move into the downstream business.

In 2014, crude oil processed was 290,000 barrels per day, 4.3% higher than 2013.

A year which has specially be affected by the incident that we have in our La Plata refinery on the 2nd of April of 2013.

This way we were able to reach 91% utilization rate even without the coke unit as a consequence of the strong effort made by the downstream during these two years and the graded ability of light crude oil of the throughput mix due to the increase of shale oil production.

As a result, I am pleased to say that we have been able to certify an overall 6% increase in the demand compared with 2013.

Our gasoline sales were up by 3.9% this year and the diesel sale were also up by 0.8%.

However, the year was strong at the beginning but then were the volumes essentially flat.

If YPF did better than the market and therefore increased the market share to 57.7% and 60% in gasoline and diesel respectively, we performed especially well in the premium segment in the last quarter with the launch of Infinia who grow 13% in the last few months achieving a 63% of the total market share of Argentina for premium gasoline.

As I am sure you are aware, by the end of the last year the local producers, refinery and the government, reached an agreement designed to protect the local oil and gas industry while international prices remain low.

Aerosol, the price of the palm, were reduced by 5% in pesos.

The reduction was partially supported by the federal government with a cut on internal taxes including the prices of the palm.

Additionally, crude oil prices were reduced by $7 per barrel from $84 to $70 from a Medanito quality and $70 to $63 for Escalante quality that is our heavy oil.

These prices can be increased by $3 per barrel for those companies that are able to maintain production flat every quarter vis-a-vis the last quarter of 2014.

The last measure in this reduction of export taxes for all crude oil and refined products to 1%.

For YPF, all these measures we have a neutral or a slightly positive effect in 2015, but more importantly they provide us with a pricing disability needed to continue the development of our long-term projects.

I believe this agreement is a sign of alignment coming from both government and industry.

With this, I will turn over Daniel to go over the financial results and I will come back for the wrap-up.

Thank you, Miguel.

Good morning everybody.

I will go through the analysis of the result denominated in pesos as we do every quarter.

In line with the dollar numbers that Miguel discussed before, revenues in Argentine pesos increased by 57.5% in the year, EBITDA was up by 73% and operating income grew by 64%, providing a solid financial situation and a healthy EBITDA margin of 29%.

Operating income was ARS19.7 billion and was evenly distributed between our upstream and downstream businesses as they both grew, in this case, 72% and 63% respectively.

Revenues grew by ARS52 billion or 57% and the main drivers as usual were an ARS18 billion increase in the diesel sold to a local market with a 0.8% volume increase, ARS11.3 billion increase in the gasoline sold to a local market in this case with a 3.9% volume increase and ARS8.3 billion increase in sales of natural gas.

Then there was ARS3 billion increases in exports mainly due to higher prices denominated in pesos were offset lower exported volumes and ARS2.9 billion increases in fuel oils and to a less extent ARS1.5 billion increase in petrochemicals, both fuel oil and petro chemicals sold in the local market.

On the cost side, cost of sales for the year increased by 53.5%.

Within the cost basis, purchases increased principally due to the price increases for the crude oil purchase from third parties in the domestic market, this is in Argentine pesos, which more than offset the reduction in purchase volumes of approximately 20%.

We obviously purchased less crude oil because we have increased our own production for the period and we are also incorporating some of the production of YSUR.

At the end, the crude oil purchases were higher by ARS2.3 billion in the year.

The other component of the increase in purchases was gasoline and diesel imports.

In this case, the effect is ARS2.8 billion and this was again driven almost entirely by higher prices in peso terms as volumes were essentially flat.

Other cost of sales were up due to higher activity expressed in higher expenses for construction services contracts for ARS6.2 billion and greater royalties of ARS3.6 billion aligned with higher production and higher prices in pesos terms.

While again the largest single item contributing to the cost increase was of course depreciation which was up 77% or ARS8.7 billion on a higher fixed asset base, all of it denominated in US dollars.

During fiscal-year 2014, we accrued a recovery from the insurance on our La Plata refinery for ARS2 billion.

This we have been accruing on a monthly basis and is accounted for as less cost of sales.

This is for the business interruption coverage of our La Plata refinery fire.

SG&A was up 43% as a consequence of higher transportation expenses, salary increases, and marketing expenses resulting from the launch of our premium gasoline brand in the last quarter of 2014.

Exploration expenses were up by ARS1.2 billion as a consequence of the more active exploration activities, and actually exploration expense varied in the same proportion the exploration CapEx.

Other expenses include the impact of two one-time items that I will describe in more detail in a couple of slides as they affect the fourth quarter comparison.

Entering into the upstream business segment.

Operating income in 2014 grew by 72% to reach ARS12.4 billion.

Revenues increased by 65% to reach ARS70.7 billion, and was mainly driven by greater volumes of crude oil produced and transferred to our downstream business, and greater volumes of natural produce unsold to the local market, and in both cases with higher average prices in dollar terms.

The average price of crude oil in the domestic market reported an increase of 3.2%, to $73.7 per barrel.

While for natural gas, the average annual price was $4.29 per million BTU.

That's 13.2% higher than in the full-year 2013.

And these figures include the consolidation of the prices experienced by YSUR which were $79 per barrel in the case of crude and $3.32 per million BTU in the case of gas.

Upstream costs in 2014 were up ARS22.8 billion.

That's a 64% increase compared with 2013 and was mainly due to, again, higher depreciation of ARS7.6 billion, higher expenses for outsourced services due to activity for ARS5 billion, increased royalties for ARS3.6 billion, which is directly related again to higher production and higher prices, both in dollars and pesos.

And finally, higher exploration expenses for ARS1.2 billion.

However, during 2014 the lifting cost came down to $13.9 per boe from $15.1 a year ago.

And total cash costs, including taxes, came down to $26.4 per boe -- from $26.4 per boe in 2013 to $24.9 per boe in 2014.

With regards to downstream during the year 2014, operating income reached almost ARS11 billion showing an increase of 63%.

Revenues were up ARS47 billion or 54%, and mainly due to higher volumes of diesel and gasoline, as explained before, coupled with higher average prices in dollars of 2.1%, and 6.9% for diesel and gasoline respectively.

Sales of fuel oil in the domestic and international markets reached ARS7.7 billion, which was a significant increase of ARS3.8 billion versus a year ago, and this was due to higher volumes of products of approximately 33%, and again higher prices denominated in pesos.

Revenues of petrochemical products reached ARS5.9 billion.

That's a hike of ARS2 billion also driven by higher prices in pesos as well as greater marketed volumes.

In the export market, sales of jet fuel, flour and oils and grains reported an increase of ARS3 billion.

For the year 2014, costs increased by 53% compared with 2013, and we can highlight the increases in the crude oil purchases of ARS22.5 billion, which was mainly transferred from YPF's upstream business segment as purchases from third parties diminished by approximately 20% in volume.

Higher prices and volumes of purchases of biofuels accounted for an additional increase of ARS2.8 billion in the year.

And higher imports of diesel and gasoline for ARS2.7 billion, again mainly driven by higher prices in pesos that have offset the decrease in volumes of 1%.

Finally, depreciation was higher in almost ARS1 billion in the year.

Again, let me note that this year cost of sales includes the positive effect of the ARS2 billion accrual for the insurance compensation which was registered as less purchases in our downstream financial results.

This slide compares to the fourth quarter results and it's important to understand the one-time nature of certain items that provide some distortion to the quarter-on-quarter comparison.

The operating income for the fourth quarter of 2013 included a ARS1.5 billion positive effect from the one-time recovery from the insurance of a physical damage, not business interruption in this case, suffered by a refinery.

And the fourth quarter of 2014 was affected, again, by a one-time non-cash provision by our subsidiary Maxus of ARS1.2 billion, and was related to third-party claims alleging contractual indemnities provided by Maxus more than 30 years ago.

Without these effects, operating income would have increased by almost 11% in the fourth quarter of 2014, and EBITDA would have been up by 50% in the quarter.

Other than that revenues were up 49% on mostly flat volumes.

Other than natural gas, volumes which were up again, and in all cases had higher prices in pesos.

Cost of sales were up by a similar percentage.

SG&A was also up by a similar percentage of 50.8%.

And exploration expenses were up by 160%.

Exploration expenses are mostly non-cash as they derive from writing off wells that are determined to be non-productive.

These write-offs do not occur evenly throughout the year, and therefore we believe that you should track the evolution of the exploration expenses more on an annual basis as opposed to the quarterly basis in order to avoid distortions.

Following two charts you will be able to see that the fundamentals of the business remained very strong during the quarter.

Crude oil production was up 4.4%, producing almost 250,000 barrels of oil per day.

And it is important to remark here that we continue to work on the recovery of production in the Malargue area in Mendoza, which had been affected by a fire occurred in the Cerro Divisadero plant.

Then this quarter crude oil production in the Malargue area reached an average of 7.2 thousand barrels of oil per day, which was still 2,000 barrels below levels before the incident.

In terms of natural gas the increase in production was 23% during the quarter, producing 43.7 million cubic meters a day.

And this was heavily impacted both by the ramp-up in tight gas production previously mentioned and incorporation of the gas production of YSUR.

As a consequence, in the quarter the total hydrocarbon production was up by 12.7% to 583,000 boes per day.

Crude processing in our refineries was also up in the quarter, this time by 4.3%, and reaching a capacity utilization of 93%.

Total sales of refined products were up by 9%, but mostly driven by lower margin fuel oil volume increase as both diesel and gasoline were essentially flat.

Cash flow from operations was more than doubled, to reach ARS46 billion in the year, and this financed over 85% of the CapEx.

Therefore, the net financing was only ARS6.2 billion in the year, allowing us to maintain our net debt to EBITDA ratio at 0.9 times.

Operating cash flow was not strong because of the 73% EBITDA growth during the year, coupled by an improved working capital, which I don't necessarily expect to replicate in each quarter or each year in the future.

Our cash position pro forma for the recent new issues in the local and international markets stood at $1.6 billion, which is enough to cover all the debt maturities of the year.

However, we feel confident in our ability to roll over most of the 2015 debt maturities, and have the cash cushion ready to fund the negative free cash flow of the year.

We are very comfortable having proved very recently access to local and international markets and the very challenging market conditions, and again remain committed to staying within our 1.5 times net debt to EBITDA ratio limit.

With this I will turn it back to Miguel for final remarks.

Thank you.

Thank you, Daniel.

I am very proud of what we have achieved so far, but there is so much more to do on the time that we have ahead.

I believe now we have a Company that is totally prepared to face the challenges ahead of us.

We have the team, we have the resources, we have the access to capital and we have the government support.

Despite what we are seeing with the rest of the oil and gas companies around the world, we have decided not to cut our CapEx program and we will invest again in the ordering of $6 billion this year.

And we feel comfortable to do this because we have enough pricing visibility and because we have not over-leveraged our balance sheet.

We are not compromising our long-term growth plans.

However, we already started to focusing and reducing our cost base.

We feel this is the perfect timing to address core reduction initiative and we launch a program called YPF 2020 precisely to identify and execute many of these initiatives.

We have brought in partners to develop our shale resources and we intend to continue to execute this project.

I share with you today some of the challenges with regard to the shale development and we don't lose sight of that.

Although we have made a long progress, we are still scratching the surface in time of achieving an optimum level of cost efficiency and productivity.

By the end of this year, we expect to be completing our new coking unit in La Plata.

We will have invest close to $800 million in that project and we should be seeing a result of 10% increase of our gasoline and diesel production.

We will grow oil and gas production again this year, target between 3% to 5% increases.

This year also we will be not able to deliver the same kind of EBITDA growth that we did in the last three years as with the transition year in many aspect but certainly we believe we will deliver resource, we will be among the best of our peer group in the industry.

With this, I would like to conclude the presentation and open for questions.

Thank you very much.

Thank you.

(Operator Instructions)

Bruno Montanari, Morgan Stanley.

I have a couple of questions here.

First, the Company clearly came from quite difficult comps with very strong results in the prior quarter which was reflected in how your downstream margins have evolved.

So the question is, what can we expect to see in the coming quarter on the pricing front?

There were no hikes in Q4.

Then January started with a price decline offset by the tax breaks.

So how confident is the Company to cope with inflation and the devaluation in the pass-through strategy?

Second question is, if you could give us an update on the development pace at Loma Campana and other unconventional areas where you have joined venture partners.

So how many wells are you looking to drill this year and if you can comment on the performance and cost of the horizontal wells as well.

And if I may add the third one there, how are the negotiations with the unions going for the salary readjustment in 2015?

Those are my questions.

Thank you very much.

Bruno, thank you very much for the questions.

I mean for the first one, you know and you understand we don't give pricing guidance.

Nevertheless, I think you can expect if we manage to do what we have been doing in the past year that our pricing will be flat in dollars during this year.

In term of the evolution in Loma Campana and in other areas, let me give you probably a brief of how I see it.

First of all, the level of activity that we are going to have the year this year is going to be pretty much we believe in the similar range to the one that we have last year.

Nevertheless, we believe that the composition of vertical and horizontal wells is going to change.

We will drill more horizontal well this year than we drilled last year due to the success that we had in this east area with some of the horizontal wells that we have been placing.

In Loma Campana, we have two main initiatives or two main potentials that we believe we have to take this year.

One, is to increase the length of the [lateral] of horizontal wells, okay, because now we have that horizontal wells that are performing well in that area and we believe we can reach probably the double or the triple of the length that we have today and placed more fractures in that particular area.

Also for the area that is working well with vertical wells, we are drilling two link holes.

We are probably cool if we are successful and we don't know if you will be so far, if you were successful that would mean a very step change in the cost of the vertical wells that we have been managed to decrease, as you know, from ARS11 million to close to ARS7 million today.

The other area on unconventional shale, not oil but gas that is working very well or has given us a very good surprise are the two horizontal wells in Orejano.

The two horizontal wells in Orejano that also have not reached a very long leg and that we have placed 10 stage fracs is producing 250,000 meter cubics per day of production, what is very good, and also the pressure is maintaining quite well.

So we believe our fair attempt to develop a shale gas play is showing a very promised result.

You have a third question I think?

Or that's --

Unions.

Yes, unions.

As I mentioned before, this is the perfect moment for us to push for cost reduction and cost reduction not only comes from service.

You know that a big percentage of our cost comes from manpower and manpower is not only wages, it is also mainly productivity.

We have started an initiative with all the unions that will start with a meeting that we have not only with the union leaders, also with the minister of the government and also with the governor of the provinces.

So basically in this is the new market condition for the oil and gas industry.

We need to change some practice to increase productivity.

It has been very well take by the union leaders.

We have been working on that for the last two weeks.

We have made very good progress on the list that we have of things to achieve fracturing in the night, move and de-move of the rigs, extra hour costs and I can't list a whole list of initiatives that we have with them.

So I believe in term of productivity we will see a reassessment of the condition that we have from the past years.

Perfect.

Thank you so much.

Frank McGann, BofA Merrill Lynch.

The world has changed a lot obviously over the last six months and you are in a somewhat favored position given your lack of direct exposure to international prices.

And that's obviously been key in the performance so far and probably will continue through this year.

But I was just wondering, obviously there are still effects that can be seen in your results and in terms of thinking about the business as we go forward the willingness of your partners, for example, to invest in shale projects or the profitability of the shale projects in a less favorite global environment, if that should continue for extended period of time, I am just wondering if you could talk about maybe how much you really think you can reduce your cost further to deal with that and to keep the business on a solid footing, particularly how much can you get form the efforts to do your own shale sands production in Argentina, perhaps what type of infrastructure changes are being done, working with suppliers to reduce contract cost and that sort of thing.

How much can we expect and how much would that bring your project cost down as you look forward?

So Frank, thank you for the question.

And you are right, the world and the industry have changed a lot and believe me it will change again.

So I think first of all I would like to comment that we should not lose sight of the big picture and the big picture for me for YPF is that we continue increasing production 13% last year.

We continue increasing reserves and we continue increasing EBITDA close to 20% probably this year.

And we brought the Company for a generation of EBITDA of $3.6 billion to $5.3 billion today.

Clearly, probably we will not be able to maintain the increase on EBITDA this year at the rate that we have seen in the last two years because, as you well pointed out, the border condition have changed.

Now coming back to your question of how much we can reduce cost, I cannot give you a figure, but I can give you an indication that we just scratching the surface, even though we have done a lot.

At the same moment that we were increasing activity, we can do a lot on continue reducing our cost, and also to continue increasing our productivity per well.

So on this one, as you probably well know, it go hand by hand when come to unconventional development.

One initiative that I think in that balance will add a lot now that we have a place where the horizontal wells are performing is increasing the length of the laterals.

As you know in US today, I am not sure with all the right technology, but they are drilling 3,000 meters laterals and placing between 30 and 40 stage fracs.

We are at 1,010.

And if we can increase the lateral and show increase in productivity, that immediately will reduce our development cost.

The link hole vertical -- I mean, on vertical wells, we have done a lot.

I mean we drill in those well under balance, we are using casing drilling, and we have managed to reduce from 11 to 7 million the cost of those wells.

So I think we have done a lot.

And our learning curve start to get flat even though we continue -- we have some wells that are below 7 today, we are not seeing the same trend of reduction that we experienced the last two year.

Nevertheless, the link hole, we are drilling two link hole could mean a major set change in the cost of those vertical well.

And then probably the third item and not less important of the others is solely logistic.

On horizontal wells, the factored drilling approach could be completely different.

The way that we utilize our frac set that today is probably at a higher level than you see in US, but still probably 35% of the time of demand that the frac fleet is being completely used.

So changing the way that we factor the drilling on the horizontal wells will bring a lot of logistic savings around what we do.

And there is a huge focus that we have with a huge initiative with third party resources are helping us to review how we can reduce the amount of cost that we put in logistics, how we can optimize it.

And one main item that will create immediately cost saving the day that it is up and running is the local sand supply.

As you know, 18 months ago we started an initiative to look for local sand within Argentina.

We bought a mining in Patagonia six months ago, and we are going to be producing our own sand close to the third quarter of this year.

This will create an immediately and a major cost reduction on the sand supply that we are today bringing from Brazil, China and US.

Okay.

Can I ask how much of your sand you'll be able to supply locally, at least over a one- to two-year period or five-year period, how much do you think you can produce?

This year we will just kick off in the third quarter, but you could expect that for 2016 more than 50% of the sand will be supplied locally.

Okay.

And then one last follow-up if I could.

Just in terms of rail infrastructure to bring equipment to the region more cost effectively, is that something that can help anytime in the near future or is that not expected?

Yes, Frank, it's a good question.

And together with the sand mining there is an initiative together with the government to upgrade two of the main railways that we need.

One is how we bring the sand from Patagonia toward Bahia Blanca, and then it's the connectivity between Bahia Blanca and Neuquen where is the main port where we receive some of the items that we bring from abroad.

One of those projects have already started and the other one is in planning phase.

Okay, thank you very much.

You're welcome.

Ricardo Cavanagh, Itau.

I have two questions.

Well, you referred on your expectations to sustain dollar prices constant and my question would be how do you got governmental support to sustain these prices for a long time and these events that international crude prices remain unchanged or even fall further?

And the second one is how do you imagine your business plans to adjust to the event that Argentina reopens to the capital markets next year?

Okay, thank you Ricardo for your question.

Sustainability of crude prices I think is part of making sense of the whole equation of not disrupting what we have start, but definitely at the end we have a very positive effect for the country.

The government understand if we are looking to oil prices that will continue being under $50 or $40 range in all the years to come in the long term, probably what we are doing doesn't make any sense.

Nevertheless, we don't believe if that's the case.

The government doesn't believe if that's the case.

And therefore Argentina cannot afford to interrupt what was started because at the end of the day, the long-term solution for the country is to produce and to learn to produce their own resources.

Therefore, discontinue what we are starting is going to have a huge cost for the country and definitely for YPF as well.

And this is well understood.

So I think the government wisely have find an equation where basically the industry -- they've been decoupled on the past from the international prices, and if they couple now for the international prices and they coupled in the past, and that was an advantage for the consumers in Argentina.

If they coupled today to protect what is a long-term view about what the country should do in terms of developing their resources.

So answering your question, in the medium term the crude oil price get adjust to the levels that we believe are normal and probably close to the level that we have before, I think what we have done is a good initiative, and you will not see an impact.

If this continue to be in the long term the level of crude oil that they will have, then we will have an issue for sure.

Probably we will not be able to sustain the initiatives that the government put in place.

To your second question, Ricardo, we believe that a potential reopening of markets for Argentina will have a positive effect on us on the cost of funding, okay.

We haven't had an issue so far in terms of accessing the market.

I think all the capital that we have needed, both debt and equity on a project level, we have been able to raise without much difficulty.

I do think that what we will experience as a significant reduction in the cost of debt capital.

Okay, thank you both very much.

Gustavo Gattass, BTG Pactual.

I had three quick questions as well.

The first one is more of an accounting question but if you guys can get us at some moment later, it's not that much of an issue.

The two other are a little bit more strategic.

But just to give them in order, we saw in the press release that you guys were able to get YSUR into the gas incentive program, but we also saw that it was included in a retroactive manner.

And I was just trying to understand how much of a retroactive contribution we may have seen from the implementation of the program in the fourth quarter results.

So I am a little bit more interested in just to say if there was anything extraordinary supporting them or not.

The two other questions, Miguel, you mentioned that you are going to go ahead with the $6 billion program.

I was wondering if you could give us an idea of what kind of growth rate you would be aiming for, you would be expecting to be able to deliver on the production in light of that commitment to spend $6 billion under this new cost environment.

And the third question, I have to admit we were a little bit surprised about the drop in profitability seen in the Company from one quarter to the other and scratching our heads here we were wondering if this was really the impact of inflation catching up on the Company.

And I just wanted to have this last question which was, let's assume that YPF is really able to keep the prices flat in dollars as you have been saying.

Should we be working under the assumption that we may be seeing a lower level of profitability of the downstream in the event that the currency does not devalue much more?

Those would be my three.

Thank you guys.

Let me address some of the issues and Miguel can wrap it up.

First on YSUR, the total that was accounted for out of our Plan Gas II in the year was $30 million.

So part of that belonged to the fourth quarter and part of that was retracted.

But again in a consolidated figures, YPF is not really significant.

In terms of the drop of profitability that you referred to, I think that it's referred to the third quarter and hopefully you remember when we discussed the third quarter results I did tell everybody that was especially strong quarter and that you should not necessarily multiply that by four.

The way we look at our profitability is vis-a-vis the same quarter last year and in that case we don't feel that we have lost any profitability because the evolution of the revenues of the cost of sales and of SG&A were exactly of the same percentage which is 50%.

However, you are raising a very good point which is we do believe that we will be able to keep our prices flat in dollars.

We don't know and everybody will have it's own assumption in terms of what the inflation and what the evolution of the FX will be in Argentina for this year if the situation where the one that you are describing in which inflation outpaces de-evaluation.

Therefore there is a possibility that you could see a slightly lower profitability, a slightly lower margin in our downstream business as our revenues grow in the medium term with a dollar not necessarily with some of our inflation component.

However, in the downstream you need to bear in mind that the biggest cost component by far is the crude oil which is transferred from the upstream and to a lesser extent purchased from third parties.

And that crude oil is dollar denominated also, right.

So if you assume that crude oil prices do not grow in dollar terms, the fact that we are passing through the FX effect of that dollar price to prices is actually a good thing for significant majority of our downstream cost base.

So the last question on production guidance, look I think we will be able to be in the same area of growth that we were probably around 5% with that more or less.

Really our guys have done an excellent job so far increasing production and I don't see why this year is going to be different.

Of course, we will need to continue looking at the development of the unconventional but still being a very small portion of our total production today is 4% to 5% of our total production.

But I think what I said to Frank that applied to the cost also apply to the productivity.

I am inclined to think that now that we will have an area where we are going to massify the development of horizontal wells, we should see more production coming for that.

And of course you will have to [held] that we continue performing the same way that we performed in gas that so far has been excellent.

So if I have to give you a number, I would say on the range of 5% growth.

Perfect guys.

Thank you.

You're welcome.

Andre Sobreira, Credit Suisse.

I have a couple of questions, some for Daniel maybe and some for Miguel.

First one, if I can get back to the issue of how stronger Q3 was versus Q4, is your perception that the stronger Q3 was mainly due to the timing of the price hikes or are we seeing any sort of unexpected cost hikes in Q4 that we probably couldn't have foreseen or couldn't model here?

So that would be the first question.

The second one, Daniel, if you could just briefly explain, just working capital, in Q4 you had quite a strong release in working capital.

So I would just like to understand that and see how I think about it going forward.

And more on finance as well, any debt covenants that we should be reminded of on the operational side of the businesses?

Miguel, with all your efforts to decrease cost and raise efficiencies how is this supply chain receiving that?

Are they receptive, do you have to negotiate quite hard?

I just wanted to understand the dynamics a little bit.

And if we could also have an update on that medium and longer term downstream plan, I remember you had a plan to increase capacity not only from the coke unit but further on down the line to keep appraising La Plata and (inaudible) capacity.

If we could just get a refresher on that please.

Thank you.

Well, let's go to why Q3 had been much stronger.

You are exactly right, a good part of it had to do with the price increases which we didn't have any in the fourth quarter and of course the evolution of our cost base continued in the fourth quarter.

So you had not necessarily cost pressure, I wouldn't call it cost pressure but the normal evolution in an inflationary environment of costs and we didn't have any new price increase, okay.

So that was the main reason of why one quarter was stronger than the other.

Another reason which is smaller but still important has to do with the exploration expenses which I made reference to during my presentation.

We are not necessarily linear and actually in the fourth quarter, they were, if I don't recall wrong, like two or three times higher than what we had recorded in the third quarter.

Another difference between the two quarters had to do with the global oil prices.

As much as we have been saying that it has a limited effect on us, we have also been providing guidance that every $10 of Brent oil price fluctuation we have an annual impact in our EBITDA of $100 million to $150 million.

So the fourth quarter was very weak in terms of crude oil prices and that had an effect on the fourth quarter vis-a-vis the third quarter.

So that I think explains most of the difference between the two quarters.

Going to your working capital question, we look at it again on an annual basis and clearly the working capital evolved very favorably in 2014 vis-a-vis 2013 not only because of the better EBITDA, let's say, the better behavior of business in itself, but also helped by a couple of other factors.

One is the insurers, okay.

In the fourth quarter of 2013, we had recorded the gain but we had not collected that indemnification, we collected it during 2014.

And we also collected during 2014 a good part of the accruals of the business interruption of the insurers during the year.

So that accounts for a big difference.

And the other one has to do with income tax because the behavior of the business in 2014 was much better than the previous year with, as we said, net income up more than 50% but we didn't pay income tax on that.

We did accrue it, but we didn't pay it, we are going to be paying it in May.

So those are the main reasons why the working capital evolved in that way.

Then to the question regarding covenants, no, there is nothing that we don't feel pressed by financial covenants in any way.

The leverage ratios that we have in most of our debt facilities are 3:1 and, as you know, we are less than 1:1.

So we have plenty of room.

The same thing in terms of interest coverage.

So there is nothing that we worry about in that regard.

And Andre, to your other question, we have very good reception so far on the cost reduction of the main service provider that we have.

Of course we have all the [names], many of the reductions already are in place.

They have been very receptive we also have been very hard.

Most of our service contracts have cancellation clause.

So it is not that we were asking much, we want these and we need to get it because I think it was the way to keep the whole thing rolling.

So, very good reception so far.

I think the other part of the question as I mentioned before is the manpower.

This is the one that we are addressing now.

It of course is going to take a bit more time for implementation.

It is not something that you do immediately.

But I have to say that we have very good reception from the union.

And of course, this will have a long impact in the industry.

So it is very important.

Regarding downstream business, I think you shouldn't expect that we could increase the amount of the efficiency of the refinery much more than we have done so far.

I think they are completely matched up.

Probably the main thing we are working on is the coke, A, and this one should come into place probably beginning of July 2016 and, of course, it will create an immediately and a big financial impact on YPF because it will increase our output in 10%.

So this is we should expect.

The rest of the refinery, we have invested a lot.

They are reaching the maximum level of complexity and probably the maximum level of capacity.

As you said that in the long term the industry in Argentina will need a new refinery probably for 2025 or 2026 but there is no much more that we can do in the one that we have.

Perfect, thank you very much guys, appreciate it.

And with that I am not saying that we are going to be the refinery shutting case.

Good.

[Filipe Santos].

Just a few quick questions.

First, have you seen (inaudible) cost reduction on this higher rig viability in this low-Brent environment scenario?

The second question is what is the Company's expectation for production increase on this increasing and lengthier horizontal wells?

How much this is longer wells could increase the increase the [COGS] and the CapEx for the development and how much do you effect this increasing CapEx which the higher production, how you think about that?

And the last third question, how do you see 2016 investments possible with the government changing and there is also low-Brent scenario?

Those would be my questions, thank you.

Thanks Filipe for your question.

So I will try to give you a flavor on some of the question that you have that probably you will not be able to be as precise as probably you want me to be.

On the cost risk of reduction yes we have cost reductions already in place.

So four different providers have different rigs, different rates but we have achieved that.

On expectation on the laterals, I cannot give you a figure and I will be probably not professionally say if I give you one because we don't really know and we are simulating and of course we have ideas of what we could achieve.

One thing I will tell you is we will try.

We have some limitation and we have some limitation on the equipment to go as long as we want to go in some of the laterals but that limitation now is much more easy to resolve because of the [low pair] equipment in the US that we can get hold of.

But again one thing you have to bear in mind is I mean the cost of development, when you reach the bottom, is really where the main cost is then increasing few meters or thousand meter the length of the lateral will really have a very low incremental impact on the cost.

There are four, if we get, the increase on productivity for the development cost equation that will be a huge win.

We have to demonstrate that we can do that and the reservoir basically responds well to that.

And also we need to have the equipment in order to be able to perform those operations.

We are already on the way to do that.

And the other one is the link hole I mentioned to you that is much more easy we are drilling two link-hole wells as we speak.

So we will have an indication on that probably soon.

On 2016, prices, I mean 2016 for us is like is talking futuristic since I don't think I can tell you what it is going to be since pricing and government and so on.

Okay.

Okay, thanks so much.

[Ravi Gamboa].

I have just two quick one please.

One on the exploration expense, so we saw a 1.2 billion peso exploration expense this year obviously on the back of higher activity.

I saw you guys mention that you maintain the overall rate of success there.

I just wanted to know if you can give me a sense of what's the weight on the 1.2 billion.

How much of that or just a percentage of how much of that in unconventional and how much of that is conventional?

I am just trying to try and get what's going to happen this year if you maintain the same level of activity.

The second one is just going back on the horizontal wells, are we going to see the program of increasing lateral lengths and increasing frac stages this year in the horizontal wells that you have planned this year.

And I am not sure if you can, but if you could give us some estimate on an average of how much does horizontal well cost currently under the 1000 meter and 10 stage scenario?

Thank you.

Ravi, thank you for your question.

In term of the ratio between unconventional and conventional development for exploration, I would say probably 50-50.

Now you need to take in consideration that what we call unconventional also include tight gas, and in tight gas is where we have a huge effort in exploration or we have a fantastic resource for us, because we open new fields and new horizontal all the time.

So, probably 50-50 even though I don't have the precise number here with me, it would be a fair assumption.

Horizontal wells, we don't give guidance.

I will say on Horizontal wells today also still immature in term of efficiency, even though if you compare with our competitors here we're probably drilling horizontal wells at half of the price that they are drilling but today I cannot give you an indication of the prices.

We are not giving that.

And what was the other question on Horizontal wells?

Yes.

On the horizontal well that you are going to drill this year, are you going to start to implement the extend laterals is that something you are going to plan to implement this year?

Yes, we will start this year; for sure we will start this year.

We are planning it.

We don't have all the equipment in place; we are lacking on some pieces and [continuing] particularly and we are basically we have companies today coming through because we're planning to do it this year.

How many of the horizontal wells when we will be able to go with the long length, I cannot tell you, and it will depend on the equipment and the result of the test.

Thank you very much.

You're welcome.

We have no further questions at this time.

So gentlemen thank you very much for all the questions and for the support so far.

I encourage you to keep looking the big picture.

I think the big picture as I said before is we continue growing production, we continue growing reserve and we continue delivering growing EBITDA.

And therefore yes, we will have our up and downs and we are one off short on the balance sheet.

But we continue with the performance that we have so far I think we will continue delivering.

Thank you very much.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.