Vista Energy SAB de CV

BMV:VISTAA

Earnings Call Analysis

Vista's Q3 2024 Growth and Updated Forecast Highlight Strong Production

In Q3 2024, Vista experienced robust growth, with total production reaching 72,800 BOE per day, a 47% year-over-year increase. Revenues surged to $462 million, up 53% from the previous year. Looking ahead, Q4 production is forecasted to hit 85,000 BOE per day, with 2025 expectations set between 95,000 and 100,000 BOE daily. Margins remain healthy, with adjusted EBITDA climbing to $310 million, reflecting a 37% rise year-over-year. Notably, the company has implemented a significant capital expenditure program, expected to total $1.1 to $1.3 billion in 2025 to support this growth trajectory.

A Strong Third Quarter Performance

In the third quarter of 2024, Vista experienced a robust operational performance driven by new well activity at its Vaca Muerta development hub. The company achieved its highest quarterly production ever, with total output of 72,800 BOEs per day, a remarkable increase of 47% year-over-year and a 12% rise from the previous quarter. Oil production alone soared to 63,500 barrels per day, representing a 53% increase from the same period last year.

Remarkable Revenue Growth

Total revenues in Q3 reached $462 million, marking a staggering 53% increase compared to the prior year's $302 million revenue. This growth is attributed primarily to the enhanced production levels, which are expected to drive future earnings as well. The lifting cost per BOE was effectively managed at $4.70, down 2% from the previous year, showcasing Vista's operational efficiency during this period.

Capital Expenditures and Future Expectations

Vista's capital expenditure for the quarter was $369 million, which primarily supported drilling 12 new wells and completing 15 more. This expenditure indicates the company's commitment to maintaining production growth. For Q4, Vista forecasts a considerable production boost to 85,000 BOEs per day, reinforcing investor confidence in its growth trajectory.

EBITDA and Shareholder Returns

The adjusted EBITDA reached $310 million, reflecting a 37% year-over-year increase, with an impressive EBITDA margin of 65%. Despite a negative free cash flow of $74 million due to increased investment activities, Vista has prioritized shareholder returns, executing a $50 million share buyback plan, contributing to a total of $100 million in repurchases this year.

Strategic Outlook for 2025

Looking ahead to 2025, Vista has updated its production guidance to between 95,000 and 100,000 barrels of oil per day, forecasting over 40% growth from 2024 levels. This forecast is based on continued drilling activity, with expectations of tying in 52 to 60 new wells and capital expenditures between $1.1 billion and $1.3 billion. Adjusted EBITDA is projected to fall between $1.5 billion and $1.65 billion, emphasizing robust growth potential moving forward.

Operational Flexibility and Infrastructure Development

Vista secured additional midstream capacity to handle 124,000 barrels of oil per day by the end of 2025, enhancing its operational flexibility. With already established partnerships for infrastructure expansion, Vista aims to capitalize on this capacity as production increases. The operational enhancements reflect strategic foresight in scaling production, with the company demonstrating viable plans for incremental growth.

Navigating Market Conditions

In facing market price volatility, Vista remains a low-cost operator with no major debt maturing soon. The company does not currently engage in hedging due to regulatory constraints, suggesting it allows investors to manage their exposure directly. Nonetheless, management expressed optimism about oil price stability and potential median pricing dynamics between local and international markets.

Final Thoughts

Vista's strong Q3 performance, combined with its strategic plans for growth and shareholder value enhancement, positions the company favorably in the evolving energy market. Investors should note the company's operational discipline, particularly in managing costs while scaling production, which bodes well for the company's profitability and further investments in infrastructure.

Earnings Call Transcript 2024-Q3

[Operator]

Good day, and thank you for standing by. Welcome to Vista's Third Quarter 2024 Earnings Webcast and Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Alejandro Cherñacov. Please go ahead.

[Alejandro Cherñacov, executive]

Thanks. Good morning, everyone. We are happy to welcome you to Vista's Third Quarter of 2024 Results Conference Call. I am here with Miguel Galuccio, Vista's Chairman and CEO; Pablo Vera Pinto, Vista's CFO; and Juan Garoby, Vista's COO.

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 call, we may discuss certain non-IFRS financial measures such as adjusted EBITDA and adjusted net income. 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 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. Our tickers are VISTA in the Bolsa Mexicana de Valores and VIST in the New York Stock Exchange. I will now turn the call over to Miguel.

[Miguel Galuccio, executive]

Thanks, Ale. Good morning, everyone, and welcome to this earnings call. The third quarter of 2024 was marked by strong operational and financial performance, driven by new well activity in our development hub in Vaca Muerta. Total production was 72,800 BOEs per day, an increase of 47% year-over-year and 12% quarter-over-quarter. Oil production was 63,500 barrels per day, 53% above the same quarter of last year and 11% up compared to the previous quarter.

Total revenues during the quarter were $462 million, a 53% increase compared to the same quarter of last year. Lifting cost was $4.70 per BOE, 2% down year-over-year. Capital expenditure was $369 million, mainly driven by 12 new wells drilled and 15 wells completed during the quarter, plus $63 million in development facilities. Adjusted EBITDA was $310 million, 37% above year-over-year, driven by robust revenue growth and lower lifting cost per BOE. Adjusted net income was $53 million, implying a quarterly adjusted EPS of $0.60 per share. Free cash flow was $74 million negative during the quarter, driven by higher cash in investing activities as we ramp up capital expenditure in our development to drive growth. Net leverage ratio at quarter end was a solid 0.65x adjusted EBITDA.

I will now deep dive into our main operational and financial metrics of the quarter. Total production during the quarter was 72,800 BOE per day, our highest quarter ever. On a sequential basis, production growth was 12%, driven by the connection of 23 new wells between May and September. We continue to see solid productivity with new wells performing in line with our type curve. Total production was 47% higher on an interannual basis, reflecting the ramp-up of our new well activity as we tie-in 51 new wells during the last 12 months compared to the 31 during 2023.

Oil production was 63,500 barrels per day, implying an interannual growth of 53% and a sequential growth of 11%. Natural gas production increased 16% year-over-year and 12% quarter-over-quarter. Growth was driven by associated gas stream coming from our Vaca Muerta shale oil wells.

During the third quarter of 2024, we continued to make solid progress in the execution of our annual work program. We connected 3 pads during Q3, 2 in Bajada del Palo Este and 1 in Bajada del Palo Oeste for the total of 12 new wells. We completed an additional pad in Bajada del Palo Oeste in late September, which led to the tie-in of 3 wells earlier this month. We therefore connected 40 new wells year-to-date, leaving us on track to deliver on our activity guidance, which is between 50 and 54 new wells for the year. Based on the execution of our new well activity plan, our model shows that production is forecast to expand again by double digit in Q4 to 85,000 BOEs per day. We also reiterate our guidance of 68,000 to 70,000 BOEs per day on average for the full year, noting that we will likely be on the upper end of this range.

In Q3 2024, total revenues were boosted to $462 million, a 53% increase year-over-year and 70% above the previous quarter, driven by strong production growth. Realized oil prices were $68.40 per barrel on average, up 1% on interannual basis. And on a sequential basis, oil prices were 5% lower, driven by softer international prices. Domestic realization prices were $67.80 per barrel, net of trucking costs and including volumes sold at export parity.[indiscernible] realization prices were $68.90 per barrel.

During Q3, we continued to execute our export-oriented strategy with an increase in amount of oil sold in the international market driven by the production growth. We exported 3.5 million barrels of oil during the quarter, 57% above the previous year. Additionally, 1 million barrels of oil were sold in the domestic market at export parity prices. Therefore, combining the sales to international buyers and domestic buyers paying export parity, 72% of our total oil sales were sold at export parity prices.

Lifting cost was $31.6 million during the quarter, implying a lifting cost per BOE of $4.70. On a unit cost basis, our lifting costs were down 2% interannually, reflecting dilution of fixed costs as we continue to ramp up production. This effect was partially offset by the inflation in U.S. dollars. In a sequential basis, lifting cost per BOE increased 5%. This was driven by higher costs in gathering, processing, gas compression, and power generation to accommodate current production and future growth. Based on our annual work program, our model shows we are on track to deliver on our guidance of $4.50 per barrel for the year.

Adjusted EBITDA during the quarter was $310 million, a solid increase of 37% year-over-year, mainly driven by strong production growth amid stable oil prices and lifting cost per BOE. On a sequential basis, adjusted EBITDA increased by 8%. Noteworthy is the fact that on LTM basis, adjusted EBITDA has surpassed $1.1 billion.

Adjusted EBITDA margin was 65% during the quarter. The softer interannual print reflects a temporary increase in trucking expenses. During Q3, we tracked 12,000 barrels of oil per day for a total cost of $23 million, of which $16 million were allocated to selling expenses in our income statement, and $7 million were deducted from our revenue line. During the third quarter, we continued with CapEx acceleration to support production ramp-up. Operating activities cash flow was $255 million, reflecting an increase in working capital of $52 million and advanced payments for the midstream expansion of $20 million.

Cash flow used in investing activities was $329 million, reflecting accrued CapEx of $369 million, partially offset by a $42 million decrease in CapEx-related working capital. Cash flow from financing activities reflect proceeds from borrowing of $143 million, the repurchase of share for $50 million, and the repayment of borrowings for $74 million. As a result, free cash flow during the quarter was $74 million negative and cash at period end was $256 million. Net leverage ratio stood at a very healthy 0.65x adjusted EBITDA at quarter end.

During 2024, we have achieved three very significant milestones to deliver on our profitable growth plan. Firstly, we have accelerated growth in 2024, ramping up new well activities and leading to a forecast of 85,000 BOEs per day on average in Q4. This will imply more than a 50% increase year-over-year in that quarter. Additionally, we secured oil midstream capacity of 124,000 barrels of oil per day by year-end in 2025. And finally, we secured a third drilling rig and a second frac set under term contracts, which give us capacity to grow further during 2025.

Based on these milestones, we are updating our 2025 guidance. We forecast total production between 95,000 and 100,000 barrels oil per day, implying an interannual production growth of more than 40%. This plan is based on 52 to 60 new wells during the year and $1.1 billion to $1.3 billion of CapEx. This excludes potential investment in Vaca Muerta Sul oil pipeline and export terminal. We forecast an adjusted EBITDA of between $1.5 billion and $1.65 billion, also implying an interannual growth of more than 40%. Our realized oil price assumption is between $67 and $72 per barrel, implying a Brent of $75 to $80 per barrel. This plan is in line with capital allocation priorities disclosed in our last Investor Day.

Based on the depth of our short-cycle, high-return well inventory, we are accelerating our profitable growth plan. We continue to assess the impact that this updated guidance will have on our 2026 forecast. As a result, we are withdrawing our 2026 guidance, and we are working on a new long-term plan to be presented to our investors during 2025.

I will now summarize the key takeaways of today's presentation. During Q3 2024, we recorded strong operational and financial performance. We continue to deliver growth with industry-leading return on capital. Growth was driven by the sharp execution of our annual work program. We have connected 12 wells in the quarter and 40 wells year-to-date. Alongside with solid well productivity, this has boosted production, revenues and net profit.

Based on solid progress during the quarter, I can confirm we are well on track to deliver on our 2024 guidance [ for activity ], production, lifting costs, and adjusted EBITDA. During Q3, we have also made focus on return to shareholders. We executed the second tranche of our share buyback plan for $50 million. This adds up to $100 million of buybacks during the year.

Finally, based on our CapEx acceleration during the year and having secured additional capacity in drilling, completion, and oil export infrastructure to continue our growth, we have updated our 2025 guidance. Our plan is forecast to yield more than 40% growth in production and adjusted EBITDA compared to 2024.

Before we move to Q&A, I would like to thank our shareholders for their continued support and congratulate the entire Vista team for their outstanding performance.

Operator, please open the line for Q&A.

[Operator]

[Operator Instructions] Our first question comes from the line of Vicente Falanga from Bradesco BBI.

[Vicente Falanga Neto, analyst]

My question is the following. Vista had a similar level of well drillings and completions in the third quarter versus the second quarter of 2024, but we saw quite a sharp rise in the CapEx. Can we assume that you're drilling longer laterals with more frac stages? And if yes, what is the expected peak production for these kind of wells that you drilled in the third quarter versus the ones that you were drilling before?

[Miguel Galuccio, executive]

All right. So yes, you're right. I mean, when you look at the total CapEx in Q3 was $369 million compared with $346 million in Q2 with similar numbers of well tie-in. When you look at the breakdown, $280 million were drilling and completion in Q3 compared with Q2 of $267 million. And as you pointed out, the main difference in CapEx came from the lateral length of our horizontal wells. So we drill, yes, longer laterals between 3,200 meters compared with 2,800 meters.

Cost of those wells go from [ 14.5 ] in the 2,800 to a range of [ 16 to 17 ] and dependent of the length, it is 3,000, 3,200 meters. And the main difference doesn't come from the drilling itself. It comes from the number of stages of completion. We usually move from 47 in the 2,000 to 50 to 55 in a 3,000 or 3,000-plus lateral length.

The decision of this is super based on subsurface so it's subsurface-driven. And of course, EURs of these wells are different. We move from 1.5 million barrels of total EUR to around probably 1.8 million, so that is the main difference. And yes, I mean, when you look at NPV-wise, every time that we have a chance to go a bit longer on the lateral, NPV-wise pay off. So that's the main reason of why you have seen the $20 million or $23 million of CapEx difference between drilling and completion between Q3 and Q2.

[Operator]

Our next question comes from the line of Tasso Vasconcellos with UBS.

[Tasso Vasconcellos, analyst]

Miguel, you said that the company delivered 51 new wells in the past 12 months, and that's actually prior to the full usage of the new equipment set. And the guidance ahead is a little bit above that figures. But I think the question is, what would be the full potential looking ahead in terms of how many wells can the company deliver maybe on a best case scenario? And what would be the main bottlenecks and the main risks for such accelerated development plan? That's my question.

[Miguel Galuccio, executive]

Thanks, Tasso, for your question. It's a very good question. So maybe the best way to look at this is if we look at 2024. When you look at 2024, we will end up tie-in in between 50 and 54 wells. And that execution will be done with 3 drilling rigs for the full year, independently that we are replacing 1 rig with now a rig that have arrived that is a new drilling rig. When you look at -- we have been drilling with 3 drilling rigs full year and 1 frac set full year. And then we use a spot frac set, I believe, twice a year. So with that, yes, we will achieve between 50, maybe 54 tie-ins.

When you look at what we guide for 2025, we guide between 52 and 60 new tie-ins, 3 drilling rigs. And the main difference is that we will have access to a full frac set for the full year. So when you talk about potential, really what this frac set give us is the full potential to go beyond this 52 or 60 well tie-ins.

It's well to notice here that if you want to add another drilling rig, a fourth drilling rig because the conditions are there, the context allow us to do so, getting a new rig in the country or getting access to a rig within the country is not difficult. Getting a new frac fleet, having that optionality ready in the country at any moment, that is what is difficult and is what we will have in hand in case we want to go further to the 60 or 52 wells that we have guided. So that frac set, back to your question, is really what give us flexibility, optionality and potential.

[Operator]

Our next question comes from the line of Bruno Montanari from Morgan Stanley.

[Bruno Montanari, analyst]

So when we think about your secured evacuation capacity, which I believe you mentioned 124,000 barrels per day into next year, can you give us a sense of how we should expect your production to evolve quarterly into 2025 and perhaps getting closer to that level of around 120,000 barrels per day?

[Miguel Galuccio, executive]

Bruno, thanks for your question. Yes, we will finish this year with an average of 85,000 barrels per day in Q4. And we are guiding, for 2025, 95,000 to 100,000, so I mean, it's a super incremental increase as we outlined in our presentation, 40% increase in production, 40% increase in EBITDA. When you -- if we want to basically finish between 95,000 and 100,000 for next year, that means that we will have an exit rate in 2025 above 100,000 barrels oil per day for sure.

We will have evacuation capacity in 2025 for 124,000 barrels of oil per day. That will be composed of 75,000 in Oldelval, 44,000 that we already have plus the 31,000 that we will add. Vaca Muerta Norte in Chile and Otasa, it will be 12,000 so that gives you 87,000. And we have big capacity -- trucking capacity for 30,000 barrels oil per day. So that makes our 124,000 total capacity that we have in hand for 2025.

The reality, I believe there's going to be a spare capacity in Oldelval, I mean, beyond the 31,000 that we have -- that we will use and we have access to. For me, when you look at the capacity that's going to be put in place in Q1, they most likely will be [ spare ] capacity. So even though we talk about 35,000, 37,000 barrels per day in trucking, I think it's unlikely that we will use that full capacity in 2025.

[Operator]

Our next question comes from the line of Marina Mertens from Latin Securities.

[Marina Mertens, analyst]

So in the third quarter, Brent prices declined and local prices remained quite stable so the gap between domestic and international prices narrowed significantly. How do you foresee these dynamics evolving? And in particular, what is your outlook for the price of the local barrel compared to export parities in the upcoming quarters?

[Miguel Galuccio, executive]

Yes, you're right. I mean, when you look at Brent prices, Q2 was around $85, Q3, $78, and we are thinking that Q4 would be in similar range to what we have in Q3. When you do the realized price of our export with $78 per barrel, it was $60.8. And when you look at -- when you see the prices of local in Q3 was $68, so very similar. We feel that we should see -- we should not see a change in that dynamic going forward.

Now we will look at the same dynamic and that is based in the new law that calls for no pricing intervention. So we are optimistic that the implementation of this new law will support that conversion between local prices to international prices. So we believe that same dynamic will continue in Q4. We don't see a major change.

[Operator]

Our next question comes from the line of Daniel Guardiola from BTG Pactual.

[Daniel Guardiola, analyst]

First of all, congrats for the results. I would like to touch on inorganic growth. And in that sense, I wanted to know if you could share with us an update on the sale process of Exxon. My understanding according to local media is that this process is now a 3-horse race. And I wanted to know if you are in this race or if you decided to opt out. And if you're still in this race, Miguel, I would like to know if you can share with us what are the main merits you have identified from Exxon's assets in Argentina.

[Miguel Galuccio, executive]

Daniel, thank you for the question that I cannot answer but I will try to do my best to give you some color. So first of all, yes, we continue to engage in Exxon that, as I said, the previous quarter was a competitive process that we were keen to participate and we continue to be in the race. And of course, as I said also in the last quarter, we will do whatever makes business sense. And if it comes to us, I mean, it will be welcome.

If not, life will move on and we have enough acreage in our hands to continue with the development of our plans, our future plan. Exxon assets are good assets. I mean, that's why we are there. It gives us probably beyond -- I mean, we have today 200,000 acreage. As you know, we have around 1,300 well locations from which we have drilled 120, 130 of those. But also we have assets in the north, and that will probably allow us to create a new development hub in the north with more materiality to the one that we have today. So that is probably the strategic view behind that.

Now again, I mean, it's building optionality for the future is we have enough upside in our own portfolio today to continue with our growth plan. Having a development hub in the north will add something to Vista. Hope I give you some color and I cannot say much more than that.

[Daniel Guardiola, analyst]

No, that's very good.

[Operator]

Our next question comes from the line of Leonardo Marcondes from Bank of America.

[Leonardo Marcondes, analyst]

Well, there is a very interesting exhibit in your corporate presentation that I would like to explore a little more, corporate presentation, okay, not the one from this quarter. On the Slide 11, there's an exhibit showcasing potential upside for different landing zones in different blocks, right? The message I get from this exhibit is that there could be an upside in terms of well inventory, right? So my question is, when do you guys expect to explore or try to develop the middle carbonate land zone of BPO, the lower carbonate of BPO and Aguada Federal and also the organic land zone of BPE? Any color here on your expectation would be great.

[Miguel Galuccio, executive]

Leonardo, thank you for the technical question. I would love to have my chief geologist next to me now to answer properly, but I will do my best. So yes, as you pointed out, we have been testing different zones in different fields. So in BPO, for example, we test the lower carbonate. We have not tested yet the middle carbonate. In Aguada Federal, we take the middle carbonate. In BPE, we have presence of organic so also, I mean, it's something that we will test so we have some upside for the future.

What this slide in the corporate presentation doesn't show is the area distribution of all those zones. For example, when you look at BPE, the organic is not present in the full block. So they are -- besides testing the productivity of the zone in some of those fields, we need to test where those zones are really are and where are the borders. And as you -- as we see in the corporate presentation, we have started to test those zones little by little.

And this, what you just pointed out, I mean, when you talk to independents, American companies and very technical people that compare the rock of Vaca Muerta with Permian, this is one of the main things that set us apart. And for many of them, it's one of the things that may think that Vaca Muerta, even though today have better productivity than Permian, have even more upside potential.

Now saying all that, 2025 for us continue to be a year of full development. So you will see that we will test when we have an opportunity, some of those zones but we will not come with a plan of how to develop those zones in a different way in the next year. But yes, as you pointed out, we will continue assessing those zones because we believe that, that will add future reserve to our future development.

[Operator]

Our next question comes from the line of Ignacio Sabelle from Itau BBA.

[Ignacio Sabelle Ramirez, analyst]

Congratulations on the results and the updates. My question was about midstream capacity. But maybe could you give us any color on the long-term contracted capacity? I mean, 2030 goals are above the current capacity and I would like to understand a bit better this.

[Miguel Galuccio, executive]

Okay. Ignacio, thank you for your question. So when it comes to additional capacity, I mean, the first thing that we are working on, and we expect to have is Oldelval expansion. So we expect that full capacity of the Vista share to be in place between February and April of 2025. These will be additional 31,000 barrels of oil per day. More long term is Vaca Muerta Sur. This is a process with YPF and other upstream producing of the basin, where we are actively participating with equity in that concept in the building of that pipeline.

Today, we are working in the commercial financing, shareholders' agreement of how that will come into place. I think a lot of work has been done in that front and we are confident that this project will take place. We have not yet defined our working interest on that one. But I think -- I mean, I can probably say that it will not be less than 10% for the stage 1. And the stage 1 full capacity, you have to think is around 400,000 barrels oil per day. So that is what we are working and we are looking and we are engaging in long-term capacity. But for now, of course, our eyes are in the ball and the ball is Oldelval expansion that we expect to have in Q1 next year.

[Operator]

Our next question comes from the line of Andres Cardona from Citi.

[Andres Cardona, analyst]

Congratulations on the results. I have a more short-term question about the trucking activity for the fourth quarter, if you have any estimate guidance that you can provide, it would be very helpful.

[Miguel Galuccio, executive]

Andres, trucking, so yes, let me look at the number. So in terms of volume trucking, we will finish Q3 with a total volume of around 12,300 barrel oil per day. When you look at going forward, what we are forecasting for Q4, of course, is an increase but we will increase volumes but Oldelval will not be online. So we are thinking that we will be trucking around 23,000 barrel oil per day average in Q4. Of course, that number will come down in Q1 2025, depending on when exactly Oldelval come into line. But I mean, you could expect that Q1 will be between the middle of what we did in Q3 and Q4 in terms of trucking.

[Operator]

Our next question comes from the line of Henrique da Cunha from JPMorgan.

[Henrique da Cunha, analyst]

A lot of my questions were already asked so a more basic one here. Lifting costs increased in the quarter despite the relevant production ramp-up. So what is the expectations like and drivers going forward? How should the company manage this increase?

[Miguel Galuccio, executive]

Yes. Thank you, Henrique, for your question. Yes, I mean, lifting costs increased a few cents during Q3. And that basically increase is the continued investment that we are doing in gathering and processing, in compression, in power generation to accommodate the production growth and the future production growth. So when it comes to accommodate production growth and future production growth, even though the main [indiscernible] is CapEx, we also have to accommodate OpEx somehow.

So we continue with our guidance of $4.50 per barrel for the year in terms of the average lifting cost for 2024. And going forward, with the increase of production and having lifting costs a main component of fixed cost, I mean, we are very positive with that number going forward, and we see room for even improving that $4.50 that we have. So no concern on the lifting cost front.

[Operator]

Our next question comes from the line of Matías Cattaruzzi from Adcap Securities.

[Matías Cattaruzzi, analyst]

Congratulations on Q3 numbers and the updated guidance. My question goes in the line of the recent oil price volatility. Is the company considering implementing a hedging strategy for realized oil prices if regulation allows it or how will you manage this in the future?

[Miguel Galuccio, executive]

Matías, thanks for the question. Yes, first of all, as you know, I mean, regulation does not allow today to have a hedging policy or hedging program since we cannot access to dollar for hedging. We see ourselves as a low-cost operator, and we are very unleveraged with no major debt maturity in front of us.

So we like to think that our investors today can hedge themselves more efficiently than we can do in the current conditions. So again, I mean, we don't have a hedging program. It's very unlikely that we will have in the next few years a hedging program. If the conditions change at some point of time and that makes sense, I mean, we will do something, but it's not something that we have today in our plan and we are looking at.

[Operator]

Our next question comes from the line of Alejandro Demichelis from Jefferies.

[Alejandro Anibal Demichelis, analyst]

Actually, I would like to understand a bit better your guidance for 2025 and how much flexibility you have in that. So you said, Miguel, that you should have the Oldelval expansion there by April. So that means you should have like 124,000 barrels a day of capacity for at least half of the year. So if there is any spare capacity in the pipeline, how quickly can you access that? And do you have enough flexibility in your work program to further expand your production?

[Miguel Galuccio, executive]

Well, thanks, Ale. I mean, yes, definitely, I mean, as you pointed out, we will have -- different to what we experienced in 2023, we will go to 2025 most likely having -- most likely, we will have spare capacity, even striking spare capacity in Oldelval expansion, the capacity will be there.

The other thing that we have and that we have proved this year and we will continue growing, I think going into Q4 is the ability that we have to ramp up and execute. I mean, we are today quietly discussing the increase of production that we just have in Q3, but that has been an amazing achievement and something that we have proved to ourselves that we are capable to do. And I think that is another very important point.

Going forward also, we will have a second frac set in hand. And as I said before, that gives us optionality to grow because when the opportunity comes, you have to have the tools to make it happen, and this second frac set is very important. If we want to go beyond what we have guided in 2025, we will need probably an additional drilling rig, a fourth drilling rig.

Now saying all that, that will all depend on the context that 2025 bring, particularly pricing of oil internationally. So if the price is better or equal to the one that we plan, yes, we have flexibility to grow. We said that in the next 3 years, we will have generated around $1 billion of cash. We are using this cash this year partially to boost that growth. And 2025, we will do exactly the same thing. But of course, the context has to be there. So price of oil will play a role, and for that, we have the rest.

[Operator]

I would now like to turn the conference back to Miguel Galuccio for closing remarks.

[Miguel Galuccio, executive]

Well, thank you very much, guys, for the support, for the question, for the continuous interest in Vista. And again, I would like to thank you, the people in the field, that have made that quarter possible. This plan, internally called Moonshot for us, reflects or shows how difficult we saw was to go through this ramp-up of production. So all credit to them. Thank you very much, and have a very good day.

[Operator]

This concludes today's conference call. Thank you for participating. You may now disconnect.