Vista Energy - Earnings Call - Q3 2020

Transcript

Speaker 0

Ladies and gentlemen, thank you for standing by and welcome to Vista's Third Quarter twenty twenty Earnings Webcast. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. Please be advised that today's conference may be recorded. I will now hand the conference over to the Strategic Planning and Investor Relations Officer, Mr.

Alejandro Chernikov.

Speaker 1

Thanks. Good morning, everyone. We are happy to welcome you to Vista's third quarter twenty twenty results call. I am here with Miguel Gallucho, Vista's Chairman and CEO and with Paolo Ella Pinto, Vista's CFO. Before we begin, I would like you to draw your attention to our cautionary statement on Slide two.

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 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 Vilan Gas, is associated with an anonimagustatile capital variably, organized under the laws of Mexico, registered in the Volta Mexicana de Valores and the New York Stock Exchange. The figures of our common stock are Vista in the Bolsa Mexicana de Valores and BIST in the New York Stock Exchange.

The ticker of our warrants is VTW408A. I will now turn the call over to Miguel.

Speaker 2

Thanks, Alejandro. Good morning, everyone, and thank you for joining this earnings call. The 2020 was marked by a solid recovery of our key operational and financial metrics. We have seen a robust improvement in crude oil demand, especially in the international market, where we have refocused our commercial efforts. This shift has allowed us to increase our production back to 25,400 BOEs per day, a recovery driven by an oil production growth of 12% quarter on quarter.

Revenue for the quarter improved to $70,000,000 while lifting costs remained in a single digit arena at $9.9 per BOE. Revenue growth, coupled with control lifting costs, contributed to a solid recovery in adjusted EBITDA, which reached $24,000,000 more than doubling quarter on quarter. Cash at the end of the period stood at $225,000,000 and net debt was $297,000,000 The recovery in prices with Brent consistently between $40 and $45 per barrel through the quarter, along with the successful rebasing of our development costs in Bajada Del Palo Este, have enabled us to restart drilling and completion activities in Vaca Muerta. In August, we finished drilling Part number four, which we completed and tying late in September. As I will show later in this presentation, we achieved robust drilling and completion metric with solid improvement vis a vis previous parts.

We also finished drilling pad number five, and we have recently begun the completion of this pad, which we expect to tie in during December. As I mentioned, our total production for the quarter was 25,400 BOEs per day, reflecting a 7% quarter on quarter growth after the reopening of Vaca Muerta Way in June and a marginal impact of the Part four, which was connected late in September. Oil production, which represent approximately 70% of our total production, was 17,500 BOE per day, a 12% increase quarter on quarter. Natural gas production will represent the remaining 30% of total production, was 31% down year on year as we have fully focused our development activities on oil. We forecasted oil production to continue growing in Q4 as it will fully reflect the incremental production of part number four.

Our third quarter revenues totaled $70,000,000 a 30% improvement quarter on quarter driven by higher oil production and stronger prices. Brent was about $43 for the quarter on average and has stayed relatively stable in the $40 to $45 per barrel range. In addition, demand recovery has helped stabilize Medanito crude discounts to Brent at around $4 per barrel. As a result, average oil realization prices were $39.1 per barrel for the quarter, a 48% increase compared to Q2. Average natural gas prices was down 37% vis a vis the 2019, mainly due to the weaker industrial demand affected by COVID-nineteen and softer prices in the regulated distribution segment.

As part of our effort to reduce our exposure to short term volatility in general market conditions, we have already secured oil sales at a fixed price of about $40 per barrel for more than 80% of our Q4 forecasted production volumes in a combination of sales to domestic refineries and international oil traders. Moving on to Slide six. Total lifting cost for the quarter was 19% lower than Q3 twenty nineteen. The revising of our operating cost structure allow us to offset lower production levels with cost savings resulting in a lifting cost per BOE that was flat year on year. Lifting cost reduction year on year was driven by the renegotiation of most of our OPEC contracts and a 32% improvement in the failure index of our mature field, which allowed for 36% reduction in the number of well interventions year on year.

The quarter on quarter increase in total costs were driven by having restored oil well maintenance and other oil field services to pre COVID activity levels. We expect most of the savings to remain in our cost base going forward. Therefore, as production volumes pick up, we should see a continuous decrease in lifting cost per barrel. Our adjusted EBITDA for the quarter was $24,200,000 a 138% increase quarter on quarter on the back of higher revenues, driven by an increase in both oil production volumes and oil realization prices, as shown to the right of the slide, coupled with controlled costs. Adjusted EBITDA margin was 35%, jumping 15% points vis a vis Q2 twenty twenty.

Moving to Slide eight. Our cash during the period increased from $220,700,000 to $225,000,000 maintaining a solid cash position amid capital expenditure increase. Cash flow from operation activities was $19,100,000 while cash used for investment activities was $23,300,000 driven by the ramp up in Vaca Muerta activity. Additionally, we generated cash from financing activities of $8,500,000 reflecting new bond issuance in the Argentine capital market of $30,000,000 at very competitive terms. 10,000,000 in pesos, eighteen months bullet at a variable rate with an spread of 137 basis points and $20,000,000 in a dollar linked bond, thirty six months bullet with zero coupon.

I will now give you an update of our Vaca Muerta project in Baja del Palo Verde. As I mentioned earlier, we have restarted drilling and completion activities on the back of lower development costs and stronger realization prices. As a recap, in part number four, we have drilled three wells before stopping operations due to the COVID pandemic. In August, we drilled the final well and completed the entire four well pad. Two wells were landed in La Cosina and completed with forty four and fifty one frac stages, respectively.

The two other wells were landed in the Caguenay section of Vaca Muerta, a third landing zone we are testing and were completed with twenty six and thirty one stages, respectively. The result in drilling and completion metrics we have achieved are impressive, as we continue to improve KPI across the board. Drilling speed was eight fifty four feet per day on average for part number 81% above the first pad. Drilling cost per lateral foot was $592 21% down from our first pad. Such improvements were driven by productivity gains and successful renegotiation of our drilling service rates.

Completion costs for the part number four came very solid at $133,000 per stage, a massive saving vis a vis all previous parts, driven by saving in proppant costs and a reduction in frac set rates. Finally, total drilling and completion cost per well for part number four was $11,400,000 34% below our first pad on normalized basis, 20% below our previous pad and in line with the new well cost I shared with you in our previous call. The four words of the part number four were tied in between late September and early October. So we will keep you posted on productivity results in further update. In the meantime, we share an update view of the productivity result of the first three paths to the right of the slide.

Each well is marked in gray with the average well shown in light blue for the first one hundred and eighty days of cumulative production. As shown, the average well is 13% above the 1,500,000.0 disclosed in our previous earnings call. I cannot stress enough how excited I am by the progress of our development economics and the understanding delivery of our operations team. Before we move to Q and A, I will summarize today's highlights. As I said, during Q3 twenty twenty, the main topic has been recovery.

We have seen solid sequential growth in all key operational and financial metrics, including production, revenues and adjusted EBITDA. We have restarted drilling and completion activities in Bajada Del Palo Verde, leveraging our low development costs and stronger realization prices. We completed path number four, which achieved outstanding KPI for all drilling and completion metrics, allowing us to achieve a total normalized drilling and completion cost of $11,400,000 per well, 20% below our previous path. We are currently completing part number five, which we expect to tie in before year end. With our Baja Del Palo Oeste development plan back on track, we expect to deliver a strong production growth in early twenty twenty one.

To close the presentation, I would certainly like to thank all Vista employees for their outstanding job in creating a better company in these challenging times and delivering improved results quarter on quarter. I also would like to thank our investors for their continued support and interest in our company. Thank you for listening. I will now move to Q and A.

Speaker 0

Thank you. Our first question is from Bruno Montanari with Morgan Stanley. Please go ahead.

Speaker 3

Good morning, Miguel, Alejandro. Thanks for taking my questions. Two questions here. First, can you share a little bit more color on the expectations and perhaps early results of the new lending zones, especially in the Carbonite? And also, what are you targeting in terms of lending zones for Plat number five?

And second question is more about macro. I think all the operating figures you report here are going pretty much in

Speaker 2

the

Speaker 3

right direction, strong figures. But the exchange rate in particular seems to be a challenge. So how is the company dealing with the complexity of FX conversion, being able to keep U. S. Dollars outside of Argentina?

So how are you dealing with that? Thank you very much.

Speaker 2

Thank you, Bruno. Thank you very much for your question. Well, starting with the carbonate wells that we drilled in mid October, we are very excited with them. They have less than twenty days of production at the moment. One of the well increasing around 700 barrels of oil per day and the other one increasing around 1,000 barrels of oil per day.

The water cut actually is around 60% decreasing and the pressure is something that we really follow close and give you a fair indication of the quality of the well is around three twenty kilos. So all in all, it's very good starting condition. One of the well is two fifty meter lateral length. But and the other well that was drilled by the South for the limitation that we have over a concession is 2,200 meter lateral length, it's a bit shorter. The two wells are landing in the carbonate section.

For that for the carbonate, we are using a different technique that we use for the normal wells. So in terms of going with Black and Per, we go full with light lift. It's something that we learned in our past experience. So we believe this is the way to complete those wells. And now we are very excited that clearly, with that reserve, if it works, it looks like it's going to work and it's going to make our portfolio more richer in terms of options to land wells.

When it comes to Pipe five, Pipe 5 is going to take the north area of our concession. So new completion design, we're going to choose 2,500 meter lateral lengthways, 50 meter space between stages. So it's going to be a high density path. So I mean, it should be a very good path. We know what is happening at the north of our concession.

So we know that area is a pretty good one. And then after that, we will go to a path six is going to be testing the east side of our concession. So no, it should be path five should be a good a very good path. Regardless, your last question that is comment on FX restriction and so on. But as you know, in mid September, the Central Bank of Argentina announced a new capital control that require entities with hard currency international debt and hard currency local bonds over $1,000,000 basically pushing to refinance those plans as far as between 10/15/2020 and 03/31/2021.

The refinancing plan will require that companies settle only up to 40% of the principal in cash, accessing official exchange rate market in Argentina and refinancing the remaining 60%. We have, as you know, 45,000,000 January installment of the syndicated loan that have a cross border impact to us. So that basically will impact us in '20 I mean, 50% or 60% is $22,500,000 with 13% is the 60% of the 22,500,000.0 that are to be renegotiated in January. So we have already started contracting discussion with the banks. Dollars 13,000,000 is not a big issue for us.

So I think it's going to have in specifically for our operation and for our financing a very mild impact. Of course, there's a second impact that is effect control in Argentina going forward and perception of when this is going to come to an end and if it's anything that is going to it's not a good perception in the fact that we have effect control to us. And of course, that affects probably our perception in terms of future.

Speaker 3

Perfect. Thank you so much, Miguel.

Speaker 0

Thank you. Our next question comes from Andres Cardona with Citigroup. Please go ahead.

Speaker 4

Hey everybody. I just wanted to ask two questions. The first one may have to do with the first question of Bruno and is if the carbonate section proves to be successful, will Elon lock incremental drilling location over the 400 wells that you have already mentioned in the past? And the second is if the $9.9 per barrel lifting cost does already reflect the full effect of the new contract terms? Thank you.

Speaker 2

Hi, Andres, and thank you very much for your question. So yes, definitely, the carbonate is something that we have not considered in our 400 West portfolio. So I think it will have two effects on the portfolio. First of all, clearly more locations. And second, the fact that we manage our we do reservoir management and we use a queue technique, that will allow us also to plan better and to probably have an effect in any kind of potential foreign China issue.

So I think it has two dimension effect. One, for sure, more reserves, more locations second, allow us to have more freedom in term of how we do reservoir management for Vajada Del Palo Este. So it's a really good it will be a very good news that those wells performed well. And every sign that we are getting now is pretty encouraging. In terms of lifting costs, yes, the lifting cost of $9,900,000 that you see, it has the new prices of the renegotiation that we have done in every single contract.

Has the effect that we pick up three pulling units during this quarter. So therefore, you have the full cost base. What you don't have is the full production base. Production, as we go forward with the plan, is going to increase. Therefore, lifting cost should come down.

The other thing I think will affect lifting cost going forward is the fact that our lift our gas lift initiative is looking pretty good for unconventional. I'm sure that we have an impact not only on the productivity of the wells because we managed to manage those wells, we artificially lift in early stage, but also in terms of lifting costs since we're not requiring pooling units in order to service those wells.

Speaker 4

Thank you.

Speaker 0

Thank you. Our next question is from Marcelo Gemiero with Credit Suisse. Please go ahead.

Speaker 5

Good morning, everyone. Thank you for taking the questions. Congratulations on the results. Just a few quick questions here. First one is production.

So we saw production at 32,000 barrels per day in June and 3Q numbers were lower at 25. So I mean is it fully explained by the higher pressure in the unconventional when they were reopened in June? And if I may, the second question, CapEx going forward, I mean should we expect the same level of CapEx going forward? Or I mean, or a higher number given the number five? And also should we expect a similar cost per well in the pad number five?

Thank you for taking the questions.

Speaker 2

Thank you, Marcelo, for your question. So, regarding production, basically, what you have seen is, well, as you know, I mean, with the COVID, we stopped drilling and then we start drilling again. But also we have the effect of the flash production when we stop drilling, and we have these three parts well shut in. There you have a combination of two effects. One effect that is the buildup of pressure that give us a flash production when we opened up.

And then you have a second effect that was the fact that we shut in our third part before that part peak on production. So when you look at what's happened since, I will say, March, where we have around 32,000 barrels per day. Until June, when we really start to reopen, you will see two effects. One is the peak oil of Part three and the other effect that you see there is the flush oil coming from the buildup of production on Wichita. The effect that happened then, you have both the declination or the disappearance of that buildup pressure that is basically flushed and this is a short one.

And then you see the decline of the Fab three that have the accumulation or the fact that didn't peak. And second, that you have the flash production of the Fab three as well. So that effect is around 4,500 barrels of oil per day. And then after that, you will see another effect on production that is the fact that we shut in Part one, Part two and Part three when we were completing the Part four, okay? And that is to avoid basically what we call a frac heat in order to be able to have a very good completion.

And this is a technique that we use. We shut in the wells for a few days and then we reopen then and we go back to normal production. So all that dynamic is happened at the same time. Saying that, now we are going to be tying in one part every quarter. So we will not have the effect of the pandemic.

So you should see, first of all, an overlap in declining and the new part coming in and a solid profile of growing production going forward, okay? So we are planning to exceed with a very good rate at the December. In terms of CapEx, well, we finished the year with around $200,000,000 or EBITDA about $200,000,000 We believe that we will tie in one part of every quarter going forward for 2021. So I think you should assume that CapEx will be around the same level. In terms of cost per well, I mean, the reduction of development costs in particular of the cost per well has been incredible.

We as I mentioned in the presentation and as you have seen on the numbers, we have managed to reduce the cost of the well in normalized basis of around of more than 30%. And that creates a completely different development cost going forward. So we are looking today at the development cost of around 8.4%. So completely different cost base to the one that we have when we start development. Just to mention, if you look at from the EBITDA margin point of view and you go back to two years ago and you look at we were generated around 40% EBITDA margin with prices of oil of $60 So today, probably, we will generate similar or above EBITDA margins in the current environment where we are talking about between $40 and $45 per barrel.

Speaker 5

All right. Thank you very much guys. Very clear.

Speaker 0

Thank you. Our next question is from Alex Demichelis with NAU Securities. Please go ahead.

Speaker 6

Good morning, A couple of questions, if I may. First one is on your conventional production, how we should be assuming decline rates for 2021? And then the second question is on the wells that you're landing on the carbonate. Maybe you can give us some kind of indication of your expectation for EURs. And obviously, you mentioned the IPs that look a little bit lower than what we have seen in Lagosina.

But just trying to understand the difference in economics between Lagosina and carbonates, please.

Speaker 2

Hi, Alejandro, and thank you for your question. So regardless decline rates on conventional, we will continue putting some small CapEx in conventional next year. I feel that we managed quite well when we mentioned the reduction on indices of failure rates of pump, this is mainly conventional, and that is basically managing not only the lifting cost, but also managing properly the decline of those fields. So this is something that we muster. So I would say you can assume that decline for conventional next year could be between five percent and ten percent.

Regarding carbonate, I think it's too soon to give any kind of indications in terms of EUR. The economics is going to have a different mix to the one that we have today Wilapocina with and organic because we will be aiming, due to the technique that I mentioned, to shorter wells, different kind of technician complete, more space between cluster and less CapEx, I will say, and less EUR because somehow we will connect less reservoir. Now the economics, it will look what it look depending on the production. I cannot give you an estimation today. What I can tell you is pressure is good, and they are cleaning up very well.

So it looks very encouraging to us.

Speaker 6

So from what you were saying, we can still see drilling and completion costs on a per well basis coming lower than the 11.4% that you put for Part four?

Speaker 2

Yes. I think you can count on that. Of course, we as you continue I mean, as our team continue doing the job that they are doing, I would say there's less opportunities now. I believe we are still having more opportunities to start a particular area. We are, for example, working in a new initiative for Sun, where basically, we are aiming to come partially in partnership with somebody our own San Mali.

So that will reduce further down the cost that is we have already reduced a lot of some in terms of dollar per ton. So I don't have on the top of my head, but let me look at I think we start operation in terms of sand dollars per ton of probably about $200 per ton. And today, we are around $80 So it's already a super reduction. And I think we can take it further down.

Speaker 6

Because you are importing less than what you were before?

Speaker 2

No, we are not importing. Today, we are sourcing from suppliers. And the next step I mean, basically, what happened with sand is there'll be more sun more local sun available, more competition and better handling in terms of many things, the way that we dry the sun, the way that the different different hydro sand that we use. So that shows the reduction that we have so far. What I'm saying is the next step for us is we have our own sand mining.

We have that sand mining very close to the trade we operate, and we are developing that. When our own sand mining came into place, we will have further reduction. I will tell you at least 3% lower than we are paying today in terms of dollar per ton. And sand is a big it's a very important component of our cost structure for completions.

Speaker 6

Okay. That's very clear. I'm sorry, just I have a small follow-up. So then the overall CapEx that you were saying we should assume kind of similar to the third quarter going forward, we should also assume some additional CapEx for facilities or your own mine or something like that, yes?

Speaker 2

Really, we have today facilities to allocate probably a bit more than 40,000 barrels per day, okay? That without saying too much is in line with what we are planning to produce in 2021. So we said that you will not see a big CapEx expenditure in next year. We continue spending CapEx on facilities, but there are no big CapEx items in terms of facilities for 2021. And you can count that we will continue reducing price of cost of well as we move forward with the development.

Speaker 6

Okay. That's fantastic. Thank you, Miguel.

Speaker 2

You're welcome.

Speaker 0

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

Speaker 2

Well, gentlemen, thank you very much. Appreciate your support and interest on VITTA. I'm looking forward to see you in the next quarter. Thanks.

Speaker 0

And with that, ladies and gentlemen, we thank you for participating in today's program. You may now disconnect. Have a wonderful day.