(Seeking Alpha, 10.Nov.2022) — Executives with Argentina’s state oil giant YPF Sociedad Anónima (NYSE:YPF) held a third quarter of 2022 earnings conference call with analysts. What follows is a transcript of the call.
Company Participants
Pablo Calderone – Investor Relations
Pablo Iuliano – Chief Executive Officer
Alejandro Lew – Chief Financial Officer
Conference Call Participants
Walter Chiarvesio – Santander
Frank McGann – Bank of America
Marcelo Gumiero – Credit Suisse
Daniel Guardiola – BTG
Ezequiel Fernandez – Balanz
Operator
Ladies and gentlemen, good morning. My name is Abby and I will be your conference operator today. I would like to welcome everyone to the YPF Third Quarter 2022 Earnings Call.
[Operator Instructions] And I will now turn the conference over to Pablo Calderone. You may begin your conference.
Pablo Calderone
Good morning, ladies and gentlemen. This is Pablo Calderone, YPF IR Manager. Thank you for joining us today in our Third Quarter 2022 Earnings Call. This presentation will be conducted by our CEO, Pablo Iuliano; and our CFO, Alejandro Lew. During the presentation, we will go through the main aspects and events that explain our third quarter results. And finally, we will open up the call for questions.
Before we begin, I would like to draw your attention to our cash flow statement on Slide 2. Please take into consideration that our remarks today and answer to your questions, may include forward-looking statements which are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these remarks. Also, note the exchange rate using calculations to reach our main financial figures in U.S. dollars. Our financial figures are stated in accordance with IFRS but during the call, we might discuss some non-IFRS measures such as adjusted EBITDA.
I will now turn the call to Pablo. Please go ahead.
Pablo Iuliano
Thank you, Pablo and good morning to you all. Let me start highlighting that this was another robust quarter in which we continue delivering solid operational and financial results, remaining on track to meet our ambitious target for the year. We maintained healthy profitability levels, gaining further operating efficiency and consolidating the tremendous progress that has been achieved in our unconventional operations.
During the third quarter, total hydrocarbon production remained stable when compared to the previous quarter but has accumulated a very healthy growth of about 9% comparing the first 9 months of 2022 with the same period of last year. primarily as a result of very positive performance in our shale operations. Adjusted EBITDA remained strong, reaching the $1.5 billion quarterly mark for the second quarter in a row, representing an increase of 50% on a year-over-year basis. interannual improvement continues being the result of the increased hydrocarbon production levels, coupled with improving pricing across our business segments and partially offset by an increase in total OpEx, mostly driven by cost pressure in local currency that continue to run higher than the FX depreciation.
The solid operating results permitted our bottom line to come in positive territory once again, with net income reaching $678 million, accumulating over $1.7 billion during the first 9 months of the year. In terms of our investment activities, we continue ramping up our CapEx, expanding 27% on a sequential basis and 71% when compared with the same quarter of the last year, totaling close to $1.2 billion in the quarter and accumulating $2.9 billion as of September, being on track to fully deploy our updated target for the year.
On the financial side, free cash flow was positive once again for tenth consecutive quarter, up $262 million, accumulating close to EUR 1 billion year-to-date. This translated into further strengthening of our balance sheet as our net debt declined to $5.7 billion, pushing our net leverage ratio down below 1.2x, the lowest mark since the second quarter of 2015.
On a final note, let me briefly comment on the recent presidential decree in relation to the expansion of Plan Gas 4 and a potential new Plan Gas 5. We expect that this important step towards who will produce the country needs to import LNG income in years based on the availability of a new evacuation capacity once Nestor Kirchner pipeline is up and running. Also provides further stability and price signaling to continue incentivizing the profitable development of our vast natural gas reserves.
In summary, we have continued advancing powers achieving the targets that we set for this year, delivering on financial and operating results while we continue to strengthen and prepare YPF for new and even more challenging goals for the future.
I now turn to Alejandro to go through same details of our operating and financial results for the quarter.
Alejandro Lew
Thank you, Pablo. Let me begin by expanding on Pablo’s comments about the evolution of our oil and gas production. During the quarter, total production remained essentially flat when compared with the previous quarter, though recording a 2% increase year-over-year, boosted by a strong 7% expansion in our crude oil production which averaged 225,000 barrels per day in the third quarter. And more recently, in October, we have resumed sequential growth as preliminary production figures came at 232,000 barrels per day.
Beyond crude, natural gas production increased 2% on a sequential basis, while NGLs were down by about 9%, negatively affected by program maintenance activities at MEGA during the months of August and September. The positive evolution in oil and gas production on a year-over-year basis came once again and as expected, on the back of the very solid increase in our shared production, both crude and natural gas. On the other hand, on the conventional side, we have continued advancing our strategy of extending tertiary recovery techniques.
In that sense, it is worth noting the progress achieved so far in the Manantiales Behr block, currently operating 8 Polymer Injection Units, leading into new production records achieved every quarter as well as the promising results from the key 3 pilots beyond Manantiales Behr being deployed at Chachahuen in Mendoza, El Trebol in Chubut and Los Perales in Santa Cruz.
Moving to costs. Lifting averaged $13.60 per barrel of oil equivalent across our upstream operations, remaining virtually stable versus the previous quarter. However, when we segregate lifting costs for our shale oil core hub operations, although remaining at a very low level of $3.7 per barrel, it recorded a 5% sequential increase, primarily due to the combination of higher maintenance activities and general cost pressures. Regarding prices within the upstream segment, crude oil realization price averaged $67.5 per barrel in Q3, increasing by about 4% on a sequential basis, thus reducing the gap to Brent prices which declined by about 13% in the same period, although still priced at a discount to export parity.
On the natural gas side, prices increased by 13% quarter-over-quarter to an average of $4.4 per million BTU, supported by the seasonality factor included in the Plan Gas 4 between the months of May and September. Zooming into the evolution of our shale operations, during the quarter, we completed 36 new horizontal wells in our operated blocks, reaching a total of 112 completed wells year-to-date. During the quarter, we also continued increasing the rest of drilling activity to enlarge our inventory of drilled and completed wells.
In that connection, during Q3, we drilled a total of 47 new horizontal wells, 38 of which were in oil producing blocks and 9 targeting shale gas, representing a new quarterly mark in terms of drilling activity. It is also worth highlighting that during the quarter, we continued with the strategy of developing Vaca Muerta beyond our core hub blocks. In that regard, during the months of September and October, we tied in 2 wells at our fully owned Lajas Este block and we have just finished drilling the first delineation well at the Loma Amarilla block, also 100% owned, targeting to fracture it before the end of this year.
Overall, new tie-ins during the quarter led our shale production into further expansion, delivering healthy growth rates and making fresh new quarterly production records. On a quarterly basis, our shale production increased by 4% and 11% for oil and gas, respectively, averaging 77,000 barrels a day in shale oil and 17.1 million cubic meters a day in shale gas. And when compared to the previous year, shale oil production expanded by almost 50%, while shale gas increased by 22%. The latter being less impressive as last year’s third quarter shale gas production has already experienced a significant ramp-up that was required to deliver on our challenging commitments under Plan Gas 4.
In terms of efficiencies within our shale operations, during the third quarter, we continued setting new records on drilling and fracking performance, averaging 259 meters per day in drilling and over 210 stages per set per month on fracking, increasing by 29% and 13%, respectively, when compared to the same quarter in 2021. As we have been flagging in previous calls, this constant improvement in operating metrics is a result of the joint efforts of our technical teams and key contractors that work relentlessly to introduce further efficiencies to our operations.
As a result, average development cost within our core hub oil operations decreased by 15% on a year-over-year basis to $8.1 per barrel with a marginal sequential increase driven by reigning cost pressures. It is also fair to highlight that the development cost of our shale core hub operations from previous quarters was revised slightly upwards as a result of some retractive tariff adjustments as well as updated UR estimates of some specific wells based on actual productivity recorded in recent months.
Finally, as an example of the productivity improvements that we have been achieving over the last quarters, during Q3, we drilled the first slim design wells with over 4,000 meters of lateral length in our gas field Rincon del Mangrullo, setting a new record in terms of horizontal length for a well with slim design. All the while, we have continued extending the use of simul-frac technology.
Switching to our downstream business. Domestic sales of diesel and gasoline remained strong in the quarter as dispatch volumes increased by 1.7% when compared to the previous quarter and stood 11% above a year ago and pre-pandemic levels of 2019. Diesel sales recorded a marginal sequential increase, setting a new quarterly record, driven by higher retail and industrial demand, partially compensated by lower seasonal sales within the agribusiness sector.
In terms of refinery utilization, despite the lower crude oil process compared to the previous quarter due to a scheduled maintenance stoppage at our Plaza Huincul refinery. During the quarter, we achieved a production record of gasoline and middle distillates through maximizing our refinery conversion levels. However, in spite of the higher refinery output, total fuel imports increased during the quarter, representing 13% of total fuels sold in Q3 in order to meet the very strong demand levels as well as to rebuild our inventories that were drawn down in the preceding quarter on the back of some disruptions in the normal supply of diesel primarily during May and early June.
In terms of prices, during the third quarter, we continued with our strategy of adjusting prices of local fuels in a way to gradually reduce or at the minimum avoid extending the gap between the pricing of local fuels vis-a-vis international parties. Average prices for local fuels measured in dollars increased by 5% in Q3 versus the previous quarter. And after September 30, we have continued with this strategy while remaining very conscious of the impact that our pricing policy has on the affordability of our products by our clients and the effects on the broader inflationary context.
We, therefore, introduced 2 additional price adjustments at the pump, one in early October, primarily aiming at compensating an increase in fuel taxes and more recently last week by an average of 6%, managing to maintain average prices fairly stable in dollar terms despite the faster devaluation of the FX. Furthermore, when we compare the evolution of local fuel prices with [indiscernible] parity over the last 12 months, both measured in dollar terms, we concluded that local prices have tracked import parity references fairly well during that time frame, albeit recording some periods with delayed response given the heightened volatility in global prices, not only in crude but also in the spreads of refined products, particularly heating oil.
Moreover, during the third quarter, we have continued benefiting from a high pricing environment on the basket of refined products other than gasoline and diesel which represents between 15% and 20% of our total revenues, while the average price for this basket declined by about 2% versus the previous quarter amidst the decline of 13% in Brent, it remained about 45% above the average for the third quarter of 2021.
On the financial front, the third quarter resulted in another quarter delivering sound operating cash flow which increased by almost 19% sequentially to about $1.6 billion on the back of positive working capital valuations besides similar adjusted EBITDA levels. This strong cash generation permitted to not only fully fund the ramp-up activity in our investment plan but also led free cash flow into positive territory for the 10th consecutive quarter, totaling $262 million and accumulating $2.2 billion since the second quarter of 2022.
In turn, this serves to further strengthen our balance sheet and provide us with the financial flexibility needed to continue tackling our ambition growth opportunities. On the liquidity front, our cash and short-term investments increased to $1.3 billion as of September 30 compared to $1.2 billion as of the end of June. And in terms of cash management, we have continued with an active asset management approach to minimize FX exposure considering the prevailing regulations that restrict our ability to hold assets abroad.
In that sense, in the context of limited available dollar-ized instruments in the local market and given our increased liquidity, we ended with a consolidated net FX exposure of 31% of total liquidity. Nevertheless, if we consider the liquidity invested in inflation indexed instruments as a proxy hedged to currency exposure, the net exposure falls to 22%.
Looking into our debt profile. The positive free cash flow generated in the quarter led to a further reduction in net debt to $5.7 billion, taking the net leverage ratio further down to less than 1.2x which as already mentioned by Pablo is the lowest mark registered in the last 7 years. Therefore, as our financial situation has continued improving, I would like to highlight, as in the previous quarter, that our healthy liquidity position comfortably covers our debt amortizations for the next 18 months, given a very manageable debt profile with just $50 million coming due before year-end and another $941 million coming due in 2023.
And before ending our presentation, let me mention the recent upgrade to our local ratings communicated by fixed which increased our local issuer rating by 2 notches to AAA as well as the change in outlook of our local ratings from [indiscernible] to positive from stable. In both cases, highlighting the continuous improvement in operating and financial performance as well as the tremendous growth opportunities ahead of us.
And with this, I conclude our presentation for today and open the call for your questions.
Question-and-Answer Session
Operator
[Operator Instructions] We will take our first question from Walter Chiarvesio with Santander.
Walter Chiarvesio
Congratulations for the results. I have 2 questions, if I may. The first one, if you can update on the CapEx plan for the next couple of years on the [indiscernible] you made. My particular interest is the acceleration that we are seeing in refinery marketing, how should we see that looking forward? That is on one side. And the other question is related to the drilling speed in the shale blocks, there is an acceleration of wells. I see 47 new drilled wells more in natural gas, probably deceleration. And if this could be considered as a new normal like nearing 50 wells per quarter or 200 wells per year. If that is a new normal for the upcoming future. That’s from my side.
Alejandro Lew
Walter, thanks for your question and for your congratulations. Let me start by quickly addressing CapEx for the next few years. As we commented, I think, in the previous call as well, we do believe at this point, even though we are still undergoing the budget process for next year. We do believe that the improvements in our Vaca Muerta operations primarily present us with a very attractive opportunity to ramp up our CapEx activity and probably have an even more ambitious CapEx plan for next year and the years after that. And of course, there is also, we believe, possible given the further flexibility that we have in our capital structure, given the significant reduction in the net leverage that we have experienced in the last few quarters. So all in all, we believe that the capital efficiency gain along the learning curve in Vaca Muerta in the last few years, position us at a very attractive point to accelerate the development of that operation, particularly the Vaca Muerta blocks.
All the while, we also continue advancing with our CapEx plan in developing the opportunities in tertiary production in our conventional fields. And all the while also we are undergoing the increased multiyear CapEx on our downstream operations given the revamping of our refineries to reduce the sulfur content of our fuels. And if you add to that also the investments that will probably be needed to be deployed in the midstream area to further debottleneck Vaca Muerta. So all in all, we do expect CapEx for the next few years to be somewhat more ambitious than the level that we have seen in 2022 and the one that we are expecting to fully deploy in 2022 of just over $4 billion. So unfortunately, I cannot comment any further than that at this point, given that we are going — undergoing our budget process for next year. But generally speaking, as I said, we will probably expect to have a larger plan for next year and the years after that.
And then in terms of the new norm for drilling activity, well, clearly, it is related to this expansion plan or acceleration in our CapEx plans in 2 ways, right. On the one hand, we expect to deploy further capital into our upstream operations and primarily into our unconventional operations. All the while, we are also improving the overall drilling speed of our operations through operating efficiencies. So all of that combined will probably imply that yes, I would not be able to tell you a specific number. But most likely, we are going to get closer to the level that we have seen in this quarter in terms of new well activity and probably also incorporating another drilling rig in the first quarter of next year, probably for a total of 15 drilling rigs in our Vaca Muerta operations. So I would say that including all of that, you would probably see similar to slightly higher drilling activity in coming quarters.
Walter Chiarvesio
Perfect. One follow-up question is, given the increasing CapEx plan it would imply also that the leverage level of the company would increase as well to the historical number of 2x or so or you should keep the — or you expect to keep the leverage level that we are seeing now?
Alejandro Lew
Well, part of the process that we are undergoing is, as I mentioned before, the budget for next year and we have to present that to our Board. But most likely, we would expect, even though we have a more ambitious plan probably for next year, we would probably expect to reduce the maximum leverage that we should be willing to accept to fully deploy that CapEx plan. But I would say it’s a little early to finally comment that. But most likely, we would expect to the same way at the beginning of this year when we announced our CapEx plan for 2022, we had expressed that we were going to look for that to push for that for as long as we remain below 2x net leverage. Most likely that cap level will be reduced for next year given the levels of net leverage that we have already achieved. But I will not be able to comment yet on that final number but most likely, it’s going to be lower than the 2x.
Operator
We will take our next question from Frank McGann with Bank of America.
Frank McGann
Two questions, if I could. One, just on costs and cost pressures. You obviously have the issue with Argentine inflation but you also have, at least globally, oil service cost inflation. I was wondering if you could comment on what you’re seeing and how you see that developing over the next 12 months? Also, if you could bring into that the issue that was mentioned in the press release related to the negative effect — net effect you have because of the difference between the official exchange rate and other exchange rates?
And then secondly, just thinking a little bit longer term. Obviously, over the next 2 to 3 years with the new pipeline capacity coming on stream, both on the oil side and on the gas side, that should provide the basis for some pretty meaningful growth. I’m just — I was wondering, longer term, your resources seem to have significantly more potential. I was just wondering, are there already discussions going on for further increases in capacity over time? And how would your discussions related to a potential LNG projects play into that? And how are those advancing?
Alejandro Lew
Okay. In terms of cost pressures, yes, definitely, we are seeing coming from both sides, from the real appreciation of the FX basically given the local inflation running higher than the evolution of the FX in that way, we get, I would say, the macroeconomic inflation pressure in our dollar based or the equivalent of dollar costs. So that is on the one hand. And then second to that, we are also experiencing some pressure from our international service providers and clearly also from some imported goods, primarily some raw materials related to both maintenance and CapEx activity that we also see some pressure there. So, all in all, what we have seen is in the case of our OpEx which has increased about 34%. That’s a combination of increased activity but also both local inflation as well as international cost pressures. And that number was similar to — on an interim basis, was similar to the result of the second quarter, right, about 34% higher than the same quarter on the year before. So we do see that those 2 sides of cost pressures. We are working on that.
Of course, depending on the future evolution of the local inflation versus the FX that will — probably the way we have been seeing in the last few weeks, the currency has evolved in a similar fashion than the inflation, the recent inflation figures. So in that sense, we might not see — or at least we are not seeing further acceleration in the cost pressures from local inflation and higher than the devaluation but we are still experiencing inflation coming from imported goods and services. So all in all, we expect to partially at least partially mitigate those cost pressures through further operating efficiencies, although clearly, that is becoming harder as we get to closer to a plateau in terms of how further we can get in operating efficiencies. But so far, we have continued making good progress on that front, both on our CapEx activity as well as in some of our operating costs as well.
And in terms of your second question about future capacity. Yes, definitely. We have commented in the past that we do see the opportunity to fully deploy our Vaca Muerta resources given the capital efficiency that we have already achieved. And for that, we will need further debottlenecking of Vaca Muerta, both in gas and in oil. Clearly, the government and through the Nestor Kirchner pipeline is taking care of the debottlenecking of Vaca Muerta to fully supply local consumption needs. But then if we manage to move forward with the project, the LNG project that we have commented — that we have announced a few weeks ago or a couple of months ago, together with our partner, PETRONAS but which is still at an analysis stage, definitely, that will require a further pipeline capacity to be able to further evaluate the increased natural gas production to supply a potential LNG plant. So that would definitely probably require a dedicated gas pipeline in case we move forward with such a project in coming years.
And in case of crude, we do believe that even though we — the industry is undergoing through Oldelval, the expansion of the current system as well as the restating of the trans-Andean pipeline into Chile probably in early 2023. On top of all of that, we believe that the industry will require further evacuation capacity and for that, we have — for some time, been working on a whole new project, midstream project which we call Vaca Muerta Sur which will probably imply a whole new oil pipeline connecting Vaca Muerta to the Atlantic and probably a new port terminal to manage the export capacity. So we would expect to have news on that project relatively soon and that’s a project that we believe that should be up and running by late 2025 or early 2026. So we need to start moving on that ASAP.
Frank McGann
And then in terms of LNG, any thoughts on — or discussions going on that — is that really could become something that’s viable?
Alejandro Lew
Yes. We — we have announced together with PETRONAS a joint agreement or an MOU to jointly study the true potential of such a project and the true merits of such a project, we believe that clearly, we have already demonstrated the productivity of Vaca Muerta and the economically viable exploitation of the natural gas resources. But clearly putting together an LNG plant, a large-scale LNG plant, the way that we are thinking of takes many engineering as well as economic and financial analysis to come up to final investment decision. So we would expect — we are undergoing that process in a joint effort together with our main partner with PETRONAS and we would expect to have some type of FID decision before the — hopefully before the end of next year, that will be the time frame for coming up with a final decision there.
Frank McGann
Okay. End of 2023?
Alejandro Lew
End of 2023, yes, that’s our expectation.
Operator
We will take our next question from Marcelo Gumiero with Credit Suisse.
Marcelo Gumiero
Good morning, everyone. Congratulations on the results and thank you for taking my questions. Many of them were already answered but I might have one here. In terms of EBITDA guidance for the year, I mean, we saw that you have been posting really good results so far, almost $4 billion EBITDA so far in 2022. How does that compare with the guidance of $5 billion for this year? Do you believe you could surpass or exceed the guidance? And the other question is on fuel imports. I mean we saw a higher mix of imports to supply the strong demand in the third quarter. I wonder, I mean what should we expect in terms of debt going forward into the fourth quarter results? I mean, is demand still at a strong level. And I mean, how does the return of Plaza Huincul affect, I mean, YPF capacity to produce fuels? So that were my questions.
Alejandro Lew
Marcelo, thanks for your question and for your congratulations. On your first question, the guidance for the remainder of the year, we clearly — we stick with the guidance of $1 billion which was an area, $5 billion area in terms of full year EBITDA. We do believe that the cumulative 9-month EBITDA so far $4 billion, position us very well to fulfill that guidance. And most likely, the area concept of the $5 billion is probably over $5 billion and not below $5 billion. So we are very confident that we should be able to be somewhere above $1 billion but still within the area of that number.
We expect the fourth quarter to be relatively similar in terms of the general business concept than in the third quarter and the second quarter. But then you definitely need to take into consideration the seasonality of our natural gas business. Clearly, the seasonality factor on our long-term plan gas contracts which reduces in a significant way, prices of our natural gas sales during the summertime and that is from October onwards until April or May I don’t recall exactly, I think until April. So clearly, the fourth quarter has a lower seasonality factor on our plant gas contracts. And then also, as we mentioned before, we do expect to see some further cost pressures in the fourth quarter. So that also should reduce probably our EBITDA numbers for the fourth quarter comparing to the third quarter.
So all in all, I would say that the general — our general business view is similar with those 2 main aspects affecting probably the EBITDA figure for the fourth quarter but then sticking with the general guidance for the full year. And in terms of your second question about fuel inputs, we do expect fourth quarter numbers to come a little below the ones that we saw in the third quarter, primarily from a reduction in diesel inputs. Now, we will probably see total fuel imports to be below 10%, once again in the fourth quarter, particularly given that in part, the imports of diesel in the third quarter were related to building back inventories that we had to draw back — drawdown, sorry, in the second quarter — at the end of the second quarter.
And also, what we are seeing is some slowdown in the total demand for diesel primarily coming from the agribusiness sector, both on seasonality factors and also mostly related to the lack of humidity in the soil which is affecting the regular activity in the agribusiness sector as we speak. So when combining those factors where we see most likely diesel imports, total volume in sports of diesel coming down in the fourth quarter compared to the third quarter, taking our total fuel imports, as I said, below 10%.
Operator
We will take our next question from [indiscernible].
Unidentified Analyst
Thank you. Congratulations on your results. I’d like to address some questions regarding your view for the medium and long term. So regarding 2023, could you share with us your view on YPS fuel sales in case there is a macroeconomic recession, how resilient are your local market sales to a decrease in industrial activity? And what would such a scenario alter your production plants? And a second question, looking ahead, when do you expect to reach full sales supply in your refining needs? And how do you expect to finance the upstream growth necessary to reach that point? Are production facilities prepared to handle production growth?
Alejandro Lew
Well, to address your questions. The first one, in terms of our outlook for 2023 and sensibility in case of macroeconomic recession or a slowdown in activity, what I would say is that, of course, mostly on the diesel side, you see diesel volumes or diesel demand with a significant correlation with economic activity, with an elasticity that is above 1. So clearly, economic activity has a relevant impact on total diesel demand. So in that front, if we were — and less so in the demand for gasoline. So if under your scenario of a slowdown in economic activity or even a recession scenario, where we would see most likely is diesel demand being affected. And in that regard, probably reducing the total needs for imported fuels, mostly diesel, imported diesel. As you probably know, the country is a net importer of diesel on average by about 20% and about 10% on gasoline. So a reduction in economic activity will probably reduce the total country needs for imported diesel and to a lesser extent of imported gasoline.
If you were to have a very severe and remember given that the country imports about 20% and elasticity is slightly above 1 in terms of diesel demand versus economic activity, you could absorb all the reduced economic activity just by reducing the amount of imports. If you want to have a very severe economic crisis or recession which we don’t have at this point in our view for 2023 then even you will still have some cushion in our refining capacity, utilization capacity to still not have a significant impact on our whole efficiency. As you probably know, at this point, right now, we are running a very high utility capacity utilization levels of close to 90%. And in the past, that number averaged between 80% and 90$ having significant or average cost efficiency. So we would say that we still have some flexibility even beyond carrying back on inputs and still not have a significant impact in overall efficiency.
And in terms of your second question about how we expect to be self-sufficient in terms of our needs for crude oil. We have commented on that in the past and we still believe that we should be able to given our expectations on crude production growth in the next few years, we would expect to be self-sufficient sometime between late 2023 or early 2024. So generally speaking, we still believe that, that is the case. And we are clearly working and investing on all the facilities that we need to have in place to be able to actually deliver on that type of ramping up production or production growth. So that’s part of the — as I commented at the beginning of the Q&A session of the ambitious plan that we have ahead of us which basically encompasses not only the well activity but also all the infrastructure that is needed to accommodate that increased production. So we believe that all of that is manageable and within our ability.
Operator
[Operator Instructions] We will take our next question from Daniel Guardiola with BTG.
Daniel Guardiola
Have a couple of questions. My first question is related to the Nestor Kirchner pipeline. And I wanted to know if you could share with us how the progress of this project? And when is it expected — when are you expecting guys for this play to come online? And what are the opportunities for YPF from the conclusion of these projects? And my second question is regarding capital allocation. We have seen very strong FCF generation during the last 10 quarters, actually positive in all of them. And I wanted to know if you have considered maybe for next year to start implementing shareholder remuneration program, either distributing dividends or putting in place a buyback program? Those are my 2 questions.
Alejandro Lew
Thank you, Daniel. Well, in terms of the Nestor Kirchner pipeline, as you know, YPF is not involved in the construction of the pipeline. But of course, we do have — we do follow very closely the evolution of it and we will talk to the different companies involved in that. So we — at this point, we believe that even though it is challenging but we still believe that they have the ability to have the pipeline up and running for the winter of next year, sometime around June. And as I said, we — the likelihood of the actual chances we cannot actually comment on that but we believe that technically speaking, — it is doable. There are not many — there is not much flexibility for anything to go wrong. That’s our view. But if everything goes as planned, we believe that technically speaking, they have the ability to have the pipeline, as I said, up and running by early — the early stage of the winter of 2023.
And in terms of your second question, the capital allocation and of course, sorry, related to that, clearly, as Pablo mentioned in his introductory remarks, last week, we saw the enactment of the decree that proposes or comments on the extension of the existing Plan Gas and probably a new Plan Gas to filling up that pipeline. So we believe that, that’s definitely good news. And that should also imply that there is confidence in getting the pipeline up and running for the next winter. And of course, we would look into any formal announcement of such a new Plan Gas, or either the extension of the existing Plan Gas to definitely consider our participation in such opportunities.
And then on your second question about the capital allocation for next year, I think it — first of all, it will depend on how our final budget is built up and approved by our Board. As I mentioned before, we do have probably a more ambitious capital expenditures planned for next year which might result in a slightly negative free cash flow for next year, of course, will depend on how we continue developing our capacity to generate operating cash flow. But all in all, we do believe that next year could end up being a negative free cash flow year. But still, that would not imply that we — the company may not consider any form of distribution, as you said, in any form, most likely potentially to our equity holders.
But I would say that, that’s not up for management to decide. At the end of the day, management may make a recommendation but it will be something that our Board of Directors will have to consider and design. And so again, I think it’s a little bit early to comment on that, given that we have not had a final budget approved for next year. But then I would say that given the significantly improved our capital structure, that should be something that the company could consider for next year.
Operator
We will take our next question from Ezequiel Fernandez with Balanz.
Ezequiel Fernández
I have 3 questions. I would like to go one by one, if you do not mind. So my first one, during the last 5 years and of course, excluding 2020, investment in facilities has oscillated between $500 million and $700 million per year. And beyond big projects like Oldelval or [indiscernible] coming along, would you expect the pace of this investment in more specific or area specific facilities to progressively come down in the medium term, let’s say, 5 years? Or should it continue at similar levels or maybe even higher?
Alejandro Lew
Well, when you talk about facilities, it’s a combination of different things, right? On the one hand, you have the maintenance CapEx and integrity CapEx related to our mature conventional fields. And on the other hand, you have the buildup of new facilities related to our Vaca Muerta operations. So when you combine the 2, I would say that most likely, total investment in facilities on our upstream operations will likely remain strong and probably continue to increase in nominal tonnes as we continue to progress in building up our total production capacity in Vaca Muerta, all the while, we continue having integrity and sustainability of our mature operations in — at the top of our agenda as well.
So when you combine all of that, I would say that most likely, you will see total facilities investments in next — in the coming years, nominally increasing. And at the same time, then you have some infrastructure investment in downstream and midstream. That should be more of a specific allocation of capital, most likely within the next 3 years as we finish the multiyear investment in the revamping of our both the La Plata and the Lujan de Cuyo refineries. And all the while, we also deploy the midstream investments but mostly not done on YPF’s balance sheet in itself. So a good portion of the midstream investments in terms of pipelines do not go into our balance sheet directly but rather in the balance sheets of the different vehicles that basically deploy or actually perform the capital investments on those projects.
Ezequiel Fernández
Great. That was very clear. My second question is related to some comments included in the press release, precisely regarding upgrades at La Plata, Lujan de Cuyo which could lead to expected higher production fuel, if I’m not mistaken. I don’t know if you could share with us how much additional volumes this program could bring on the refining side.
Alejandro Lew
Sure. The multiyear investment in the refineries, it’s mostly related not to increase the total production capacity but rather mostly at improving the quality of our fuels but reducing their sulfur content. And at the same time, managing a different mix in terms of crudes that that are — that are capable of processing, basically, to contemplate the increased proportion of lighter crudes coming from Vaca Muerta into the general mix of crudes being processed. So those are the main aspects of the investment. However, given particularly the latter part that I mentioned, the different mix in fuels — sorry, in crudes that will end up resulting in somewhat expanded total capacity in terms of gasoline and middle distillates production.
So all in all, we would expect that by the time that we finish with this multiyear investment program which is probably going to be by the end of 2025, we should see total production capacity of gasoline and middle distillates to go up by about 10% to 15%.
Ezequiel Fernández
That’s very helpful. And my final question is, sorry, if I go back to the LNG topic and I know this is still in preliminary stages. But do you think that unrestricted export permits which, of course, would allow an eventual LNG export facility to operate year-round is an absolute prerequisite to go forward with such a project?
Alejandro Lew
Well, definitely, for a large-scale LNG facility, the types that we are considering, you would definitely mean to have the ability to run on a 365-day basis. which, at the same time and I think I briefly mentioned at the beginning of the Q&A session which probably require a dedicated gas pipeline to supply the natural gas to feed the LNG plant. So in that case, even that we see ample resources in Vaca Muerta to further expand in a significant way, the total natural gas production for the country. for as long as you have a dedicated midstream facilities, such as a dedicated gas pipeline, we would not envision any meaningful problems to actually have the ability to run a 365-day basis. But the quick answer to your question would be that definitely a large-scale LNG plan will require to have the ability to run on a year-on basis.
Operator
And with no further questions, I will now turn the call back to Mr. Alejandro Lew for closing remarks.
Alejandro Lew
Well, thank you very much all for joining in and for continuing to track the evolution of our results and we hope to see you or to hear you the next time. Have a great day.
Operator
Ladies and gentlemen, this concludes today’s call. We thank you for your participation. You may now disconnect.
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