Vista Energy SAB de CV

BMV:VISTAA

Earnings Call Transcript 2020-Q3

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to Vista's Third Quarter 2020 Earnings Webcast. [Operator Instructions] Please be advised that today's conference may be recorded. [Operator Instructions]

I will now hand the conference over to the Strategic Planning and Investor Relations Officer, Mr. Alejandro Cherñacov.

[Alejandro Cherñacov, executive]

Thanks. Good morning, everyone. We are happy to welcome you to Vista's Third Quarter 2020 Results Call. I'm here with Miguel Galuccio, Vista's Chairman and CEO; and with Pablo Vera Pinto, who's the CFO.

Before we begin, I would like you 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 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, is a sociedad anónima bursátil de capital variable organized under the laws of Mexico, registered in the Bolsa Mexicana de Valores and the New York Stock Exchange. The tickers of our common stock are VISTA in the Bolsa Mexicana de Valores and VIST in the New York Stock Exchange. The ticker of our warrant is VTW408A.

I will now turn the call over to Miguel.

[Miguel Galuccio, executive]

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

Revenue for the quarter improved to $70 million, while the lifting cost remained in a single-digit arena at $9.90 per BOE. Revenue growth compared with control lifting costs contributed to a solid recovery in adjusted EBITDA, we’ve reached $24 million more than doubling quarter-on-quarter. Cash at the end of the period stood at $225 million, and net debt was $297 million. The recovery in prices with Brent consistently between $40 and $45 per barrel through the quarter, along with the successful rebasing of our development cost in Bajada del Palo Oeste have enabled us to restart drilling and completion activities in Vaca Muerta.

In August, we finished drilling pad #4, which we completed and tied-in late in September. As I will show later in this presentation, we achieved robust drilling and completion metric with solid improvement vis-à-vis previous pads. We also finished drilling pad #5, 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 well in June and marginal impact of the pad #4, 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, which represent the remaining 30% of total production, was 31% down year-on-year as we have fully focused our development activities on oil. We forecast this oil production to continue growing in Q4. I think it will fully reflect the incremental production of pad #4.

Our third quarter revenues totaled $70 million, 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 held a stabilized into crude discounts to Brent at around $4 per barrel. As a result, average oil -- crude oil average prices were $39.1 per barrel for the quarter, a 48% increase compared to Q2.

Average natural gas prices was down 37% vis-à-vis the third quarter of 2019 mainly due to the weaker industrial demand affected by COVID-19 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 our oil sales at a fixed price is 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 6. Total lifting cost for the quarter was 19% lower than Q3 2019. 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 oilfield contract and 32% improvement in the failure index of our mature field, which allows 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 well maintenance and other oilfield 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 $24.2 million, 138% increase quarter-on-quarter on the back of higher revenues driven by an increase in both oil production volumes and other realization prices as shown to the right of the slide, capped with control costs. Adjusted EBITDA margin was 35%, jumping 15 percent point vis-à-vis Q2 2020.

Moving to Slide 8. Our cash during the period increased from $220.7 million to $225 million, maintaining a solid cash position amid capital expenditure increase. Cash and operation activities was $19.1 million, while cash used for investment activities was $23.3 million driven by the ramp-up in Vaca Muerta activity. Additionally, we generated cash from financing activities of $8.5 million (sic) [ $8.4 million ] reflecting new bond issuance in the Argentine capital market at $30 million at very competitive terms. $10 million in pesos, 18-month bullet, at a variable rate with a spread of 137 basis points and $20 million in a dollar-linked bond, 36-month bullet, with zero coupon.

I will now give you an update of what our Vaca Muerta in Bajada del Palo Oeste. As I mentioned earlier, we have started drilling and completion activities on the back of lower development costs and stronger realization prices. As recapped, in pad #4, we have built 3 wells before stopping operations due to the COVID-19 pandemic. In August, we drilled the final well and completed the entire 4-well pad. Two wells were landed in La Cocina, and completed with 44 and 51 frac stages, respectively. The 2 other wells were landed in the carbonate section of Vaca Muerta, a third landing zone we are testing, and were completed with 26 and 31 stages, respectively.

The result in drilling and completion metric we have achieved are impressive and will continue to improve KPI across the board. Drilling speed was 864 feet per day on average for pad #4, 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 the successful renegotiation of our drilling service rates. Completion cost for the pad #4 came very solid at $133,000 per stage, a massive saving vis-à-vis for previous pad driven by saving in propane cost and a reduction in frac set rate. Finally, total drilling and completion cost per well for pad #4 was $11.4 million, 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 4 wells of the pad #4 we are timing between late September and early October. So we will keep you posted on productivity results and further update. In the meantime, we share an update view of the productivity result of the first 3 pads to the right of the slide. Each well is marked in gray with the average well shown in light blue for the first 180 days of cumulative production. As shown, the average well is 13% above the 1.5 million BOE type curve disclosed in our previous earning call. I cannot express enough how excited I am by the progress of our development economics and outstanding delivery of our operations team.

Before we move to Q&A, I will summarize today's highlights. As I said during Q3 2020, the main topic has been recovered. 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 Oeste, leveraging our low development cost and stronger realization prices. We completed pad #4, which achieved outstanding KPI for oil drilling and completion metric, allowing us to achieve a total normalized drilling and completion cost of $11.4 million per well, 20% below our previous pad. We are currently completing pad #5, which we expect to tie-in before year-end. With our Bajada del Palo Oeste development plan back on track, we expect to deliver strong production growth in early 2021.

To close the presentation, I would certainly like to thank all these employees for their outstanding job in creating a better company in these challenging times and delivering improved result quarter-on-quarter. I also would like to thank our investor for their continued support and interest in our company. Thank you for listening.

I will now move to Q&A.

[Operator]

[Operator Instructions] Our first question is from Bruno Montanari with Morgan Stanley.

[Bruno Montanari, analyst]

Two questions here. First, can you shed a little bit more color on the expectations and perhaps early results of the new landing zones, especially in the carbonates? And also, what are you targeting in terms of landing zones for pad #5. And second question is more about macro. I think all the operating figures you report here are going pretty much in the right direction, strong years, 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 leading with that?

[Miguel Galuccio, executive]

Thank you, Bruno. Thank you very much for your question. Well, starting with the carbonated way -- wells that we gain in mid-October, but we are very excited with them, they have less than 20 day of production at the moment. One of the well increasing around 700 barrel oil per day and the other one is increasing around 1,000 barrel oil per day. The water cap 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 320 kilos. So all in all, a very good starting condition.

One of the well is 250-meter lateral length, but -- and the other well that was drilled by the south for limitation that we have or a concession is 2,200 meter lateral length. It's a bit shorter. The 2 wells aligning in the carbonate section for that -- for the carbonate, we are using a different need that we use for the normal well. So in terms of going with black and pale, we go full with light and lit. It's something that we learn 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, look like it's going to work, and it's going to make our portfolio more rich in term of options to land with.

We come to pad 5. Pad 5 is going to get the north area of our concession. So new completion design. We want to reduce 2,500 meter lateral anyways, a 50-meter space between spaces. So it's going to be a high-density side of the pad. So I mean, it should be a very good pad. We know what is happening at the north of our concession. So we know that the area is a pretty good one. And then after that, we will go to a pad. Pad 6 is going to be testing the east side of our concession. So no, it should be -- pad 5 should be a good -- a very good pad.

Regardless, your last question that is comment on FX restriction and so on. So 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 million, basically pushing to refinance those plan as far as between October 15, 2020 and March 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 million January installment of the [ CDK ] loan that have a cross-border impact to us. So that basically will impact us in 20 -- I mean 50% -- or 60% is $22.5 million, with 13% -- it's the 60% of the $22.5 million that are to be renegotiated in January. So we have already started contracting discussion with banks. $13 million 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 is FX 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 a fair control to us. And of course, that affect probably our perception in term of future.

[Operator]

Our next question comes from Andres Cardona with Citigroup.

[Andres Cardona, analyst]

I just want to ask 2 questions. The first one may have to do with the first question of Bruno is, if the carbonate section proves to be successful, will it unlock 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?

[Miguel Galuccio, executive]

Andres, and thank you very much for your question. So yes, definitely, the carbonate is something that we have not considered in our 400-well portfolio. So I think it will have 2 effects on the portfolio. First of all, clearly, more locations. And second, the fact that we manage our -- we do retro 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 pad issue. So I think these are 2, we mention, effect. One, for sure, more reserve, more location. Second, allow us to have more freedom in term of how we do rest of the management for Bajada del Palo Oeste oilfield. So it's really good -- it will be a very good news that those well perform well. And every sign that we are getting now is pretty encouraging.

In term of lifting cost, yes, the lifting cost of 9.9 that you see, we have the new prices of the renegotiation that we have done in every single contract from the fact that we pick up 3 pulling unit 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 go -- should come down.

The other thing, I think, will affect lifting cost going forward is the fact that our lift initiative is looking pretty good for unconventional. I'm sure that will have an impact, not only on the productivity of the well. Because we managed to manage those well, we are officially in early stage, but also in terms of lifting costs, since will not require pulling unit in order to service those well.

[Operator]

Our next question is from [ Marcelo Ramiro ] with Credit Suisse.

[Unknown Analyst]

Congratulations on the results. Just 2 quick questions here. First one is production. So we saw production at 32,000 of 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 pad #5? And also, should we expect a similar cost per well in the pad #5?

[Miguel Galuccio, executive]

Thank you, [ Marcelo ], for your question. So regarding the production, basically what you have seen is, 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 flat production when we stopped drilling, and we have these 3,000 wells shut in. There are -- you have a combination of 2 effect. One effect, that is the buildup of pressure that give us a flash production when we open that. And then you have the second effect. That was the fact that we shut in our first pad before that pad peaked on production. So when you look at what's happened since, I would say, end of March, where we have around 3,200 barrel oil per day until middle of June when we really start to reopen, you will see 2 effects. One is the peak oil of pad 3. And the other effect that you see there is the flash oil coming from the buildup of production when we shut in.

The fact that happened then, you have both the declination or the disappearance of that buildup pressure that is basically flash and is a short one. And then you see the decline of the pad 3 that have the accumulation or the fact that didn't peak. And second, then you have the flash production of the pad 3 as well. So that effect is around 4,500 barrels oil per day.

And then after that, you will see another effect on production. That is the fact that we shut in pad 1, pad 2 and pad 3 when we were completing the pad 4, okay? And that is to avoid, basically what we call a frac hit 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 few days and then we reopen them and we go back to normal production. So all that in that is stopping on the same time.

So in that, now we are going to be tying in one pad early quarter. So we will not have the effect of the pandemic. So you should see, first of all, a overlap in declining and the new pad coming in and a solid profile of growing production going forward, okay? So we are planning to exit with a very good rate at the end of December.

In term of CapEx, well, we finished the year with around $200 million or a bit about $210 million. We believe that we will tie-in one pad every quarter going forward for 2021. So I think you should assume that CapEx will be around the same level. In term 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 costs 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 2 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, we are talking about between $40 and $45 per barrel.

[Operator]

[Operator Instructions] Our next question is from Alex Demichelis with Nau Securities.

[Alejandro Demichelis, analyst]

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 EUR. And obviously, you mentioned the IPs that look a little bit lower than what we have seen in La Cocina. But just trying to understand the difference in economics between La Cocina and carbonate.

[Miguel Galuccio, executive]

Alejandro, thank you for your questions. So regardless, decline rates on conventional, we will continue putting some small CapEx in conventional next year. Our fees 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 field. So this is something that we master. So I would say you can assume that decline for conventional next year will be between 5% and 10%.

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 niche to the one that we have today with La Cocina 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 classes and less CapEx, I would say, unless you are because somehow we will connect the reservoir. Now the economics, you will look -- what it’ll 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 look very encouraging to us.

[Alejandro Demichelis, analyst]

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 pad 4.

[Miguel Galuccio, executive]

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 in start a particular area. We are, for example, working in a new initiative for sand, where basically we are aiming to come partially in partnership with somebody or our own some mining. So that will reduce further down the cost that you saw we’ve already reduced a lot of sand 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 dollar 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.

[Alejandro Demichelis, analyst]

Maybe because you are importing less than what you were before?

[Miguel Galuccio, executive]

No. We are not importing. Today, we are sourcing from suppliers. And the next step -- I mean, basically, what has happened with Chinese they've been more locals are available, more competition and better handling in term of many things the way that we dry the sand with the different kind of 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 place 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 term of dollar per ton. And sand, it's a very important component of our cost structure for completions.

[Alejandro Demichelis, analyst]

Okay. That's very clear. And 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 first quarter going forward. We should also assume some additional CapEx for facilities or your mine or something like that, yes?

[Miguel Galuccio, executive]

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

[Operator]

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

[Miguel Galuccio, executive]

Gentlemen, thank you very much. Appreciate your support and interest on Vista and looking forward to see you in the next quarter. Thanks.

[Operator]

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