Ladies and gentlemen, thank you for standing by, and welcome to Vista's third quarter 2020 earnings webcast. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during that portion of the call, you will need to press star one on your telephone. Please be advised that today's conference may be recorded. If you require any further assistance, please press star and zero. I will now hand the conference over to the Strategic Planning and Investor Relations Officer, Mr. Alejandro Cherñacov.
Thanks. Good morning, everyone. We are happy to welcome you to Vista's third quarter 2020 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 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. 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 warrants is VTW408A. I will now turn the call over to Miguel.
Thanks, Alejandro. Good morning, everyone, and thank you for joining this earnings call. The third quarter of 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 25.4 thousand barrels per day, a recovery driven by an oil production growth of 12% quarter-on-quarter. Revenue for the quarter improved to $70 million, while lifting costs remained in a single-digit arena at $9.9 per BOE. Revenue growth, coupled with controlled lifting costs, contributed to a solid recovery in adjusted EBITDA, which 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 $40-$45 per barrel through the quarter, along with the successful rebasing of our development costs in Bajada del Palo Oeste, have enabled us to restart drilling and completion activities in Vaca Muerta. In August, we finished drill pad number four, which we completed and tied in late in September. As I will show later in this presentation, we'd achieved robust drilling and completion metrics with solid improvement vis-à-vis previous pads. 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 25.4 thousand barrels per day, reflecting a 7% quarter-over-quarter growth after the reopening of Vaca Muerta well in June, and matching an impact of the pad number four, which was connected late in September. Oil production, which represents approximately 70% of our total production, was 17.5 thousand BOE per day, a 12% increase quarter-over-quarter. Natural gas production, which represents a remaining 30% of total production, was 31% down year-over-year, as we have fully focused our development activities on oil. We forecast the total production to continue growing in Q4, as it will fully reflect the incremental production of pad number 4. Our third quarter revenues totaled $70 million, a 30% improvement quarter-over-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- $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-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 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 2019. The rebasing of our operating cost structure allow us to offset lower production levels with cost saving, 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 OPEX contracts and a 32% improvement in the failure index of our mature fields, 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 $24.2 million, 138% increase quarter-on-quarter on the back of higher revenues, driven by an increase in both oil production volumes and oil realization prices, and shown to the right of the slide, coupled with controlled costs. Adjusted EBITDA margin was 35%, jumping 50% points vis-a-vis Q2 2020. Moving to slide eight. Our cash during the period increased from $220.7 million to $225 million, maintaining a solid cash position amid capital expenditure increase. Cash from operation activities was $19.1 million, while cash use 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, 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 months bullet with zero coupon. I will now give you an update of our Vaca Muerta project in Bajada del Palo Oeste. As I mentioned earlier, we have restarted drilling and completion activities on the back of lower development costs and stronger realization prices. As recap, in pad number four, we have drilled three 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 fracked stages, respectively.
The two 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, as we continue to improve KPI across the board. Drilling speed was 864 ft per day on average for pad number four, 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 renegotiations of our drilling service rates. Completion cost for the pad number four came very solid at $133,000 per stage, a massive saving vis-a-vis all previous pads, driven by saving in proppant costs and a reduction in frac set rates.
Total drilling and completion cost per well for pad 4 was $11.4 million, 34% below our first pad or 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 wells of the pad 4 were tied in between late September and early October. 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 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 stress enough how excited I am by the progress of our development economics and the 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 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 Oeste, leveraging our low development costs and stronger realization prices. We completed pad number 4, which achieved outstanding KPI for all drilling and completion metrics, 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 number five, 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 finally 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&A.
Thank you. Ladies and gentlemen, as a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound or hash key. Please stand by while we compile the Q&A roster. Our first question is from Bruno Montanari with Morgan Stanley. Please go ahead.
Morning. Yeah, Alejandro, thanks for taking my questions. 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 Carbonate? Also, what are you targeting in terms of landing zones for pad number five? Second question is more about macro. I think all the operating figures you report here are going pretty much in the right direction, strong figures. The exchange rate, in particular, seems to be a challenge. How is the company dealing with the complexity of FX conversion, being able to keep the US dollars outside of Argentina? How are you dealing with that? Thank you very much.
Thank you, Bruno. Thank you very much for your question. Starting with the carbonate wells that we tied in mid-October, we are very excited with them. They have less than 20 days of production at the moment. One of the well is producing around 700 bbl per day, the other one is producing around 1,000 bbl per day. The water cut actually is around 60%, decreasing. The pressure is something that we really follow close and give you a fair indication of the quality of the well, is around 320 kg. All in all, a very good starting condition. One of the well is 250-meter lateral length. That and the other well that was drilled by the south, for the limitation that we have with our concession, is 2,200-meter lateral length. It's a bit shorter. The two wells are landing in the carbonate section.
For the carbonate, we are using a different technique that we use for the normal wells. In terms of going with plug and perf , we go full with slickwater. It's something that we learn in our past experience. We believe this is the way to complete those wells. Now we are very excited that clearly we have reserve. If it works, looks like it's going to work, and it's going to make our portfolio richer in terms of options to land wells. When it comes to pad 5, pad 5 is going to test the north area of our concession. New completion design, we want to choose 2,500 m lateral length wells, 50 m space between stages. It's going to be a high density pad. It should be a very good pad.
We know what is happening at the north of our concession. We know that area is a pretty good one. After that, we will go to a pad 6 is going to be testing the east side of our concession. Pad 5 should be a very good pad. Regardless, your last question that is comment on FX restriction and so on. 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 plans, as far as between October 15th, 2020, and March 31st, 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 Syndicated Loan that have a cross-border impact to us. That basically will impact us. It have 50% or 60% is $22.5 million, with 13% is the 60% of the $22.5 that are to be renegotiated in January. We have already started contracting discussion with the banks. $13 million is not a big issue for us, I think it's going to have, specifically for our operation and for our financing, a very mild impact. Of course, there's a second impact, that is capital controls in Argentina, and going forward and perception of when this is going to come to an end, and if it's anything that is not a good perception in the fact that we have capital controls to us, and of course, that affects probably our perception in terms of future.
Perfect. Thank you so much, Miguel.
Thank you. Our next question comes from Andres Cardona with Citigroup. Please go ahead.
Everybody, I just want 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 it unlock incremental drilling location over the 400 wells that you have already mentioned in the past? The second is, if the $9.9 per barrel lifting cost does already reflect the full effect of the new contract terms. Thank you.
Hi, Andres. Thank you very much for your question. Yes, definitely the carbonate is something that we have not considered in our 400 well portfolio. I think it will have two effects on the portfolio. First of all, clearly more locations. Second, the fact that we do reservoir management, and we use a cube technique, that will allow us also to plan better, and to probably have an effect in any kind of potential participation issue. I think it has two dimension effect. One, for sure, more reserve, more locations. Second, allow us to have more freedom in terms of how we do reservoir management for Vaca Muerta or for Bajada del Palo Oeste. It would be a very good news that those well perform well. Every sign that we are getting now is pretty encouraging.
In terms of lifting costs, yes, the lifting costs of 9.9 that you see, it has the new prices of the renegotiation that we have done in every single contract. Have the effect that we pick up three pulling units during this quarter. 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 costs should come down. The other thing I think will affect lifting costs 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 manage those well, we artificially lift in early stage, but also, in term of lifting costs, since we not require pulling units in order to service those well.
Thank you.
Thank you. Our next question is from Marcelo Gumiero with Credit Suisse. Please go ahead.
Good morning, everyone. Thank you for taking the questions. Congratulations on the results. Just two quick questions here. First one is production. We saw production at 32,000 bbl per day in June, and 3Q numbers were lower at 25. Is it fully explained by the higher pressure in the unconventional when they were reopened in June? If I may, the second question, CapEx going forward, should we expect the same level of CapEx going forward or a higher number given the pad number 5? Also, should we expect a similar cost per well in the pad number 5? Thank you for taking the questions.
Thank you, Marcelo, for your question. Regarding the production, basically, what you have seen is, as you know, with the COVID, we stopped drilling and then we start drilling again. Also we have the effect of the flush production when we stop drilling, and we have these three pads well shut in. There, you have a combination of two effects. One effect that is the buildup of pressure that give us a flush production when we open that. You have a second effect, that was the fact that we shut in our third pad before that pad peak on production. When you look at what's happened since, I will say, end of March, where we have around 32,000 bbl per day, until middle of June, when we really start to reopen, you will see two effects.
One is the peak oil of pad three, and the other effect that you see there is the flush oil coming from the buildup of production when we shut in. The effect that happened then, you have both the declination or the disappearance of that buildup pressure that is basically flush, and this is a short one. Then you see the decline of the pad three that had the accumulation of the fact that it didn't peak, and second, that you have the flush production of the pad three as well. That effect is around 4,500 bbl of oil per day. Then after that, you will see another effect on production. That is the fact that we shut in pad one, pad two, and pad three, when we were completing the pad 4. Okay?
That is to avoid, basically what we call a frac hit, and 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 them, and we go back to normal production. All that dynamic is happening at the same time. Saying that, now we are going to be tying in one pad every quarter. We will not have the effect of the pandemic. You should see, first of all, an overlap in declining and the new pad coming in, and a solid profile of growing production going forward. Okay? We are planning to exit with a very good rate at the end of December. In terms of CapEx, well, we will finish the year with around $200 million or a bit above $200 million.
We believe that we will tie in one pad every quarter, going forward for 2021. I think you should assume that CapEx will be around the same level. In terms of cost per well, the reduction of development costs, and particularly of the cost per well, has been incredible. As I mentioned in the presentation, and as you have seen on the numbers, we have managed to reduce the cost of the wells in normalized basis of more than 30%, and that creates a completely different development cost, going forward. We are looking today at the development cost of around 8.4%, a completely different cost base to the one that we had when we started development.
Just to mention, if you look at from the EBITDA margin point of view, you go back to two years ago, you look at we were generating around 40% EBITDA margin with prices of oil of $60. 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.
All right. Thank you very much, guys. Very clear.
Thank you. As a reminder, ladies and gentlemen, to ask a question, you will need to press star 1 on your telephone. Our next question is from Alex Demichelis with Nau Securities. Please go ahead.
Good morning, gentlemen. A couple of questions, if I may. First one is on your conventional production, how we should be assuming decline rates for 2021. The second question is on the wells that you're landing on the Carbonates. 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 you have seen in La Cocina. Just trying to understand the difference in economics between La Cocina and Carbonates, please.
Hi, Alejandro, thank you for your question. Regardless decline rates on conventional, we will continue putting some small CapEx in conventional next year. Our fields that we managed quite well, when we mention 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. This is something that we master. I will say you can assume that decline for conventional, next year could be between 5% and 10%. Regarding the 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 need 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 techn complete, more space between clusters, and less CapEx, I will say, and less EUR because somehow we will connect less reservoir. 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. It looks very encouraging to us.
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 Q4.
Yes, I think you can count on that. Of course, as our team continue doing the job that they are doing, I would say there's less opportunities now. I believe we still having more opportunities to 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 around sand mining. That will reduce further down the cost that we have already reduced a lot of sand, in terms of $ per ton. I don't have on the top of my head, but let me look at, I think we start operation in terms of sand $ per ton, of probably about $200 per ton, and today we are around $80. It's already a super reduction, and I think we can take it further down.
Because you are importing less than what you were before?
No, we are not importing. Today, we are sourcing from suppliers, the next step, basically what have happened with sand is, there's been more local sand available, more competition, and better handling in term of many things. The way that we dry the sand, the way that the different types of sand that we use. 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. Sand, it's a very important component of our cost structure for completions.
Okay, that's very clear. I'm sorry, just another small follow-up. 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, yeah?
We have today facilities to allocate, probably a bit more than 40,000 barrel per day. Okay? Without saying too much, is in line with what we are planning to produce in 2021. I will say that we will not see a big CapEx expenditure in next year. We'll continue spending CapEx on facilities, but there's no a big CapEx item in term of facilities for 2021. You can count that we will continue reducing price of, or cost of well as we move forward with the development.
Okay. That's fantastic. Thank you, Miguel.
You're welcome.
Thank you. Sir, I'm not showing any further questions in the queue.
Well, gentlemen, thank you very much. Appreciate your support and interest on Vista, and looking forward to see you in the next quarter. Thanks.
With that, ladies and gentlemen, we thank you for participating in today's program. You may now disconnect. Have a wonderful day.