Vista Energy SAB de CV (VIST) 2019 Q1 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standby.

Welcome to Vista's First Quarter 2019 Earnings Webcast.

(Operator Instructions) Now it's my pleasure turn the call to Alejandro Cherñacov.

Thanks.

Good morning, everyone.

This is Alejandro Cherñacov.

We are happy to welcome you to Vista's first quarter 2019 results call.

I am here with Miguel Galuccio, Vista's Chairman and CEO; and with Pablo Vera Pinto, Vista's CFO.

Before we begin, I would like to draw your attention to our cautionary statement on Slide 2.

Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements.

These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from expectations contemplated by these remarks.

Our financial figures are stated in U.S. dollars and in accordance with International Financial Reporting Standards, IFRS.

However, during this conference call, we may discuss certain non-IFRS financial measures such as adjusted EBITDA.

Reconciliations of these measures to the closest IFRS measure can be found in the earnings release that we issued yesterday.

Please check our website for further information.

Our company Vista Oil & Gas (foreign language) Miguel Galuccio will now present our first quarter 2019 results.

Hi and thank you, everybody, for joining this call, in which I will present our first quarter 2019 results.

This was a very important quarter for us.

I'm really excited to share with you the results of our first shale oil development pad targeting the Vaca Muerta formation in Bajada del Palo Oeste block.

We completed our first pad achieving best-in-basin completion performance.

With an average of 5 frac stages per day totaling 136 stages in 4 wells.

Initial production price from this pad in Bajada del Palo Oeste came in very strong, having pitched in more than 6,500 barrels of oil equivalent per day.

We will deep dive down into our Vaca Muerta development at the end of the presentation.

Let me now walk you through the main consolidated figures of our quarter.

In the first quarter of 2019, our production reached 25,700 in barrels of oil equivalent per day, 4% above the previous quarter.

Such increase reflects mainly our focus on maintaining conventional production.

We ramped up our unconventional wells production in Bajada del Palo Oeste, which allowed us to deliver more than 29,000 barrels of oil equivalent per day by the end of March.

Net revenue in the first quarter were $93.7 million.

If compared against previous quarter, net revenues were impacted by lower sales prices of oil and natural gas, we will explain later.

Adjusted EBITDA totaled $37.1 million and despite lower oil and gas prices, we managed to maintain a solid 40% adjusted EBITDA margin by continuing to drive cost reductions.

In a quarter in which we continue ramping up investing in our Vaca Muerta development, we closed the period with a robust financial position, with a cash balance of $87.5 million and net debt of $247.7 million, resulting in a net debt leverage ratio of 1.3x LTM adjusted EBITDA.

I will go into more details regarding the above-mentioned metrics in the following slides.

As shown in the first chart of the Slide 4, we increased our net production to 25,700 barrels of oil equivalent per day implying a 4% growth quarter-over-quarter.

Our production growth pad is accelerating, driven by our unconventional development in Bajada del Palo Oeste.

As shown in the chart at the top right corner, the average daily production in March totaled 27,000 barrels of oil equivalent per day, reflecting an increase of 8% from January to March, which have an exit rate of more than 29,000 barrels of oil equivalent per day.

The latter ramp up being exclusively driven by our first pad in Bajada del Palo Oeste.

As stated above, during Q1, we tied-in the first 4-well pad in Bajada del Palo Oeste.

In terms of unconventional activity, we tied-in 11 new wells in Medanito, Jagüel de los Machos and Entre Lomas, of which 9 wells target oil formation and 2 wells targeted gas formation.

The first chart of Slide 5 shows the 4% quarter-on-quarter production growth explained earlier.

The breakdown by group shows that crude oil production in the quarter was 15,100 barrels of oil equivalent per day, 4.1% above Q4 2018 and natural gas production was 1.59 million cubic liter per day, 4.6% above Q4 2018.

We also produced 623 barrels per day of natural gas liquid.

And as shown on the Slide 6, our first quarter revenue totaled $93.7 million, 10% below the previous quarter driven by lower sales price.

Crude oil sales represented 78% of our total sales.

With steady sales volumes, the reduction in revenue was driven by a quarter-on-quarter reduction on -- of 13.4% of the average wholesales price, which was $56.7 per barrel.

This drop is a consequence of the competition of Argentinian domestic market to export parity pricing as a consequence of supply growth driven by Vaca Muerta production and lower international commodity prices.

The prevailing export parity pricing formula reflects the export parity duty estimated at [polycystic] cost are used with previous [mono invested] Brent prices are the applicable benchmark.

Therefore, Q1 2019 crude oil sales were realized based on December 2018 to February 2019 Brent prices, which are $60.8 per barrel, 19% below Q4 2018 were marked benchmark prices and late-April 2019 Brent levels.

All our crude oil volumes, which is entirely Medanito-type light crude oil, was sold to domestic refineries, with Trafigura and Shell being the main of takers.

Natural gas revenues, which represent 20% of our total sales, were 7.5% below Q4 2018 mainly due to the decrease of spot sales prices to the power generation segment from $3.3 per million BTU in Q4 2018 to $2.7 per million BTU in Q1 2019, will result from an auction conducting by the state agency, CAMMESA, in [a novel] supply summer market.

Moving on, on to Slide 7. The total operating expenses for the quarter were $27.8 million, 2.8% below Q4 2018.

OpEx per barrel of oil equivalent was $12, 4.8% below Q4 2018.

This is a very positive trend given that we achieved a lifting cost reduction in a quarter with a flat real terms exchange rate.

This puts us in a very good position to continue reducing lifting cost by absorbing the ramp up in shale oil production with minimal incremental cost.

Moving on to Slide 8. Q1 2019 adjusted EBITDA was $37.1 million, mainly impacted by lower revenues.

Our adjusted EBITDA margin increased 1 percentage point with respect to previous quarter to 40%.

It is important to highlight that this EBITDA margin was achieved despite lower Brent prices showing the impact of our focus on cost efficiency.

As shown on Slide 9, we maintained a solid cash position and ended the first quarter of 2019 with $87.5 million coming from $80.9 million at the end of 2018.

The increase in activity, which drove higher working capital needs, our lower revenues, impacted cash from operations, which was $20 million in the quarter.

Cash from financing activities reached $79.1 million, including the closing of $54.4 million capitalization plus short-term borrowing of $35 million with interest payment of $10.3 million.

Finally, we allocated $92.6 million to investing activities, mainly the completion of our first pad and the drilling of our second pad of Bajada del Palo Oeste.

As of March 31, 2019, our net leverage ratio was a healthy 1.3x LTM adjusted EBITDA.

We will now deep dive into the most exciting chapter of this call.

As you know, the key driver behind the efficiencies in Argentina was the exposure to core shale oil package in Vaca Muerta, where we stated will be our key growth driver.

The result of our first pad confirm my confidence in the quality of the asset we acquired and the strength of the team we have put together.

In our very first pad and after a record [time of effort], we are delivering resource that are among best in basin, both in term of development cost and production rate.

We are doing this with a factory-mode development approach that is sustainable and represented solely the starting base from which we will continue improving.

Moving on to Slide 11.

I'm thrilled to share with you the performance achieved during the completion of first pad in Bajada del Palo Oeste.

We landed 2 wells in La Cocina and 2 in lower organic, with an average lateral length of 2,550 meters and 34 frac stages per well.

The drilling and completion cost of these wells was an average of $13.8 million, implying a cost of $1,600 per lateral foot.

Implementation of the 1 team contracting model, which aligned the key contractor of Vista we had in [Saint Bowls], sharing performance metrics in a conjunction with the best practice in terms of logistics, enable us to achieve outstanding completion results.

As an example, we laid 22 kilometers of flat hose from our water source to a temporary extract points and used 100% sandboxes to transport and store sand on location, which warrant clean water and sand supply throughout the completion of the first pad.

This, combined with the focus and expertise of our team, allowed us to achieve best-in-basin performance with an average of 5 frac stages per day and a record of 19.3 hours of pumping time in a single day in which we complete 8 frac stages.

Vista's sustainable development approach in both long-term solutions that are key to minimizing impact of our operation on the environment.

With the flat hose mentioned previously, we avoided approximately 7,500 truck trips.

The use of sandboxes provide for the safer environment for our crews through a significant reduction of silica gas in the air.

We also contracted our first Early Production Facilities in record time in order to minimize gas flaring and trucking.

As shown in the bottom-left chart, our first 4-wells pad to Bajada del Palo Oeste shale production from 0 to peak of 6,500 barrels of oil equivalent per day in mid-April 2019, boosted by individual work performance of our type curve, as I will explain further in the following slides.

In our second pad, we have already drilled all surface and intermediate sections with a spudder rig and also the horizontal sections of 3 wells.

We expect to tie-in the second pad during Q3.

The chart on the left side of the Slide 12 shows the outstanding production performance of our first pad.

Each of the 4 wells of the pad are shown in color, and we are clearly above Vista P50 Type curve, drawn in black.

The comparison against Vista-type curve is also shown individually on the right side of the slide on a cumulative basis.

As I mentioned earlier, we are very excited about this performance, believing that it [should shed] our average in Bajada del Palo Oeste is even better than we initially expected.

This reconfirms our growth plans and our production guidance for 2019.

The previous slide compare our first pad production in Vista-type curve.

In this slide, we compare it against other Vaca Muerta wells.

As you can see, all 4 wells are showing strong performance, in line with top-tier wells of the basin.

We are applying strictly drawdown management policy to preserve frac integrity.

As shown in the bottom-left corner, current bottom-hole pressure is still over 7,000-psi, with wells flowing naturally through a 6.35-millimeter choke.

To conclude the first part of this call and before opening the line for questions, I want to thank the entire team at Vista for their hard work and their commitment.

I think this quarter marks an inflection point for us, as we ignited the Vaca Muerta profitable production growth engine.

The result we obtained [to share the] quality of average in Bajada del Palo Oeste is even better than we initially expected.

I am very excited with the drilling and completion performance.

This [to me] an important bet on innovation, technology and a sustainable development approach, and we have seen best-in-basin results in our first pad.

Our first pad in Vaca Muerta has also showing, as wells are producing above type curve as well as making a significant contribution to our production, reaching mid-April 6,500 barrels of oil equivalent per day.

Our exit rate for the first quarter was above 29,000 barrels of oil equivalent per day, setting the stage for growth acceleration in the coming quarters.

Our success in cost reduction initiative place us in a very good position to continue reducing the existing cost as shale production increases.

That's creating a solid foundation for EBITDA margin growth.

Q1 results and a stronger commodity price environment allow me to confirm that Vista is on track to achieve 2019 guidance.

Thank you for allowing me to share Vista's first quarter 2019 results with you.

We'll now continue this call with a Q&A session.

(Operator Instructions) And our first question is from Bruno Montanari with Morgan Stanley.

Very interesting to see all those colors on the chart above the type curve.

So really excited to see the performance from the first pad.

So a few questions from me.

If the productivity of the coming pads is the same, what type of upside could we expect for both the near and long term in terms of production for Vista?

Second question is about costs.

How do you think the first pad cost of $13.8 million per well compares with the company's target for the upcoming pads once the ramp-up activity picks up?

And then finally, maybe something more related to Argentina, I think the pricing system with the export tax was working pretty well or is working pretty well, but with Brent probably at the low to mid-60s.

So looking at the screen now, Brent is now low to mid-70s, what do you think happens with the export tax and with the realization of oil prices in Argentina in the coming months?

Bruno, thank you for your question.

So the first part of your question was related to productivity.

Clearly, we're looking at wells that are much better than the one that we were expecting and you can see it in the operations that we have with our type curve.

Now the question is how these wells are going to evolve.

We are more working under pressure than anything else, pressure is behaving extremely well.

And therefore, we -- I think this pad is the one that is going to tell us what we need to do next.

At the moment, we are not changing our type curve for the pad that are coming forward, the pad 2. We're still forecasting that pad with the same type curve.

But if you will see that the result is really -- it is what it is and the pressure show a steady and very low decline as it is showing before, at some point of time we will restate our type curves.

So that's for the productivity part.

On the cost side, of course, we see a side.

I believe, we still a long way to go in term of performance in order -- I mean we have a super start.

I mean we started slowly with average cost of the basin.

But we have a lot of ideas of things that we can do in order to reduce cost of the wells and cost of the products that is whether [rather] consuming, for example, sand.

So I cannot give you much more of that information.

I wish -- you should expect our cost, it will come down with scale and will come down with implementation of the processes that we are putting in place on technology.

Related to prices, in Argentina.

Well, you're right, I mean the formula is what it is.

I mean we've been affected for the 4 pesos per dollar import tax, okay?

That continues to be there.

We expect that it's going to dilute more so with inflation that we have in Argentina at the moment, and plus the penalty that the refineries are charging to us related, basically, to transportation and logistic, okay?

Of course, we are in a very rich scenario in Q2 because of what you said, I mean we have better Brent prices.

I think the only dynamic that I will add to your question going forward is, clearly, Argentina is moving to a market where we are going to start to have supply of light crude oil, okay?

So the question will be, how that is going to accelerate and when Argentina become a net exporter.

Being a net exporter help the equation change in term of pricing, for the price of the crude oil.

We will export for the local crude oil, okay?

And I think we should expect to see that dynamics in the next year or so.

And our next question is from Regis Cardoso with Credit Suisse.

Miguel, Alejandro, Pablo.

Congratulations on the very impressive results, especially on the unconventional front.

The few topics I wanted to touch.

First one regarding CapEx.

Can you provide us with some CapEx breakdown in regards to the $300 million CapEx guidance that you have provided for this year?

And I am trying to understand whether you have flexibility to work around the CapEx if necessary?

And also, how do you plan to fund the still $210 million-or-so that you should still invest throughout this year?

Next topic would be in regards to prices.

I mean if you're pricing at export parity, so -- I mean that's as much penalized as E&P companies can get?

And let's say, if you were to actually export the crude, the government would actually collect these export tariffs that is already minoring your prices.

But on the other hand, this could also actually be an important milestone to boost Vaca Muerta production growth, right, because if you are actually allowed to export, then that also allows for production and it allows for reserve-based lending and many other advantages that would allow not only Vista, but other players to ramp up production.

So I mean how do you see evolution in terms of actually allowing producers to export crude?

And then finally, how do you compare the type well economics now that you have observed the first few days of the first pad?

I mean when we run our models, if we just assume the IP rates we have observed and the CapEx we have put in place, it does look like you'd have much improved IRRs over the ones you have initially guided.

Is this correct?

And is this a sweet spot that you've drilled so far?

And -- or should we continue to expect wells of this quality?

Thank you, Regis, all good questions.

So look at the first one, very briefly, the CapEx of $300 million is $50 million conventional and $250 million are non-conventional -- unconventional CapEx, okay?

This for 2019 and it's already fully funded.

So we have not -- we will run this year as it is.

The fundings from 2020 gap for '20 -- from now to 2020, and I say 2020, 2021, is probably around $200 million.

So we are, at the moment, already exploring different avenues of prefunding that gap.

To be honest, we feel very comfortable that we will have that funding available, okay?

And I think today, we have pretty much, I will say, advanced in some of those options.

In term of pricing, you mentioned the export.

So export is something that we are discussing.

As you said, that will be a big milestone for the government.

So we see the government today align with idea, it will be good for them.

I think it will help to accelerate the development of Vaca Muerta, similar to what happened in U.S. in 2015, when Obama renewed the ban for exportation.

So the discussions are there.

The question is what it takes to be implemented and so on and there's been a lot of it put into it to understand what it will take and how it can we implement it.

I don't want to give you any guidance on that.

But I think it's good to know that discussion is on the table.

And philosophically, we see the government aligned with idea of doing it.

And also, we need to take in consideration that, again, as I said before, we will start to have full capacity in term of light crude oil.

In term of the results of the wells of the first pad, let me probably -- I believe the result of this first pad is not only the result of the fact that we are in a very good geological position.

In order to get a result, we have to take many things, we managed to drill those wells and achieve the 2,550 meter.

We managed to put [directly after] the stage.

We manage to pump all the sand and the water, 1,550 cubic meter per stage, 0.5 million pound of sand in each stage.

We managed to put it on production to clean up the sand.

We managed to manage the drawdown in a very good way.

So there's been a lot of things that came in place in order to have the performance that we are having, neither to say the whole water we have done subsurface to understand how to pave those wells and this can be done between those wells, the fact that we'll probably pump more water than we thought.

So what we've seen in this first pad is that we have contact more reservoir that we thought we were be going to contact, okay?

So the result of this pad is not only the fact that we are in a good position, is the result of the subsurface and execution team that helped managed fantastic result putting this in place.

The question to me, how the pressure has gone up and far, okay?

And it's performing extremely well.

Those well still producing with 30% of water today, okay?

So we have seen a different behavior from the wells and we are seeing a very good pressure performance.

Again, if we manage to see the same, and we are basically putting all the planning and subsurface efforts for the second pad, if we see the same performance in the second pad and we manage to perform the same, definitely, at some point of time, we will have to adjust our type curve.

And you are going to be looking at wells and pads, they'll have a different IRR than the one that we planned.

And one more comment on that, it's not only that you have good wells, you have a very good pad.

So the 4 wells are performing well, that means in a pad, you have a lot of consistency.

This is something also I have not seen much within Vaca Muerta.

Miguel, very complete answers.

If I may -- just follow-up on the well performance.

It seems, at least from this first pad, that the 2 wells in La Cocina are performing better than the 2 others in the organic.

Does it make sense?

Do you think that you -- I mean the different landing zones could have different tiers of wells productivity?

Yes.

I mean your assumption looking at the crude, it is correct.

I mean this has been always the case.

Now if I show you a picture of what happened with the frac down hole and how this frac should grow vertically and so on, I mean, there's a lot other things that play into the result.

Nevertheless, I think your assumption is correct.

I think we can see different performance in different horizons.

You saw that we are actually referring from the hydrogen test and we plan to test those too.

And our next question is from Pedro Medeiros with Citigroup.

And I wanted to congratulate you, Miguel, and the whole Vista for the results so far.

I have a couple of questions.

Some of them, it's really targeting to understand a bit on how to read those results and draft some scenarios going forward.

So the first one, and maybe this is a very tough question, but do you mind to give some color on how your current resource size distribution is split up between La Cocina and lower organic or any color on how the number of identified drilling locations for the business plan split up between both of them?

And the second question is, do you -- considering these results, do you mind to comment on whether your upcoming drilling pads will be of greater than 4 wells and if you have any intention to test even longer laterals on the coming pads?

And my last question is, if you can discuss, a little bit more on -- and I apologize if you have already presented on this in the early part of the presentation, but if you can discuss the drilling activities planned for your conventional assets.

Will you see an important increase in production there and I just wanted to understand how far can that production grow throughout 2019?

Thank you, Pedro, for your questions.

So very interesting questions.

The first question related to lower organic and La Cocina.

Today, we are having an approach that we call a cube approach, something that is very well known in U.S., where we develop -- we plan to develop our average based on that cube.

If we look at the cube or the series of cubes that we have today, I think at the moment, until we have tested the rest of the horizon, you can assume that we will have 50-50.

So the dynamic that you saw in the first pad and the configuration that you saw in the first pad, you can assume that, that will repeat, okay?

Related to drilling pad numbers, so that will depend of 2 things.

One is the shareholder fee, okay?

So we are blessed that the fact that our block is a square.

So we don't have a triangle.

So we have a square.

This is the best case scenario that you could have in order to have a rational development of a block.

That is playing in our favor.

As already mentioned that you have to consider is the fact that we have not drilled any oil in this block.

So basically, we don't have pipes and we will not have [chance], okay?

We will create the pattern of chance, but if you go to, I don't know, I don't want to mention it, look, but if you go to any block that's in pilot or delineated in Vaca Muerta, those companies have to deal with a lot provincial issues.

We don't.

Why?

Because we didn't pilot.

We didn't delineate.

We went to full development from day 1. So this 2 thing play in our favor.

Nevertheless, we will be signing a strategy of development, with the size and space in between the wells.

And that doesn't mean that we will have few interference between the cube, but we will have approval in Vaca Muerta because of the approach that we have.

It's super rational approach to the development of Bajada Palo Oeste from day 1, okay?

So another 2 things that you have to keep in mind and I think it's important, there could be some packed out rig wells, okay?

If you -- we look at the development today, if we look at the cubes today, we will find cube of 6 well.

The length of the well is something that is under discussion.

I will not, basically, say that we could not deliver 3,000-meter wells.

It's under discussion.

It's possible, also depend on geometry.

Sometimes you need to cover certain geometry and this 3,000 meter give you a better coverage.

And a 2,500 meter or 2Q for 6,000 meter give you a very coverage for the areas you have that, whatever, cube of 2,500 meter.

I will say from the economical point of view on -- I'm looking at what's happening in U.S. At the moment, and this is a personal opinion, I'm not completely convinced that a 3,000 meter will give you an economic of 2,500-meter well, as per today, okay, as a result of what I have seen in U.S. So can we go to 3,000?

It's going to depend more on the geometry that we are convinced today that the 3,000 meter well will give us a better economical result.

And the last question is related to the conventional production.

So you have to just think that we would move in convention as how we move today.

I mean the idea is to continue maintaining a solid base of conventional, keeping the focus in conventional, independently of the growth on conventional, and we make a lot of effort with our people on that, and for that, we need to continue drilling sand-free wells, sand delineation wells and continue looking for opportunities in the conventional arena.

There are 2 areas where we -- you can't expect anything tomorrow, but we are studying, one is Lotena, okay?

The development of Lotena as the next play that could bring new life to conventional.

And the other thing that we are looking, and we are studying and we are putting quite a bit of effort is on water flat to see if we can have a different strategy for water flat or some [fleet] that are today are not under water flat, but they could be good opportunities to be -- to have secondary recovery, okay?

But I will say, for this year, you should expect that we would try maintain conventional flat.

(Operator Instructions) And our next question is from Frank McGann with Bank of America.

And thanks for the complete presentation and clear presentation.

Most of the operating key issues have been earlier discussed.

Just kind of given your experience and having operated in many different environments, given the current volatility that we're seeing in the market in general, but particularly in Argentina and the uncertainty from an economic standpoint particularly that Argentina is facing right now, I was just wondering does that have any effect in how you allocate capital or how quickly perhaps you put capital to work?

Or is that -- you don't see that as a major impediment at this point?

Thank you, Frank, for your question.

Look at -- I mean for the -- we all know what we have seen in Argentina today.

And I think for the short-term volatility of Argentina that -- it will not change our plan.

I mean we have this year is completely funded and the results they were coming better than we expected.

And with this Brent prices, we don't foresee any change.

Of course, moving forward, it will depend on where we see the Brent -- how the Brent behave.

And also, it will depend on the discount that we have in the local market.

And if you -- we need to assess -- remember, we plan to grow all the way up to 4 rigs, okay?

But that's not written in the stone.

And definitely, we want to show the growth that we expect.

And today, we have the economic basis to relive in that plan.

Now if your Brent go to 50 or whatever, of course, we will assess CapEx as is required.

And also, we will watch clearly today we are working with a set of economic type curve that is not the one that we are repeating in the first pad, but I think it's a bit soon to change it.

But we will assess numbers on activity fees required due to the conditions of the market, international market or the local market.

At the moment, we don't see any reason to change our plan.

And sir, I'm not showing any further questions in the queue.

All right, thank you, [Marge].

Look, thank you very much for joining us.

Thank you for the questions.

We always learn something from your questions.

And looking forward talk to you again next quarter.

Have a good day.

And with that, ladies and gentlemen, we thank you for participating in today's conference.

Please, have a great day.