YPF SA (YPF) 2021 Q3 法說會逐字稿

Good morning. My name is Chris, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the YPF Q3 2021 Earnings Webcast Presentation. (Operator Instructions) Thank you. Santiago Wesenack, IR monitor for YPF, you may begin.

Good morning, ladies and gentlemen. This is Santiago Wesenack, YPF's IR Manager. Thank you for joining us today in our third quarter 2021 earnings call. I hope you all continue to be safe. This presentation will be conducted by our CEO, Sergio Affronti; our CFO, Alejandro Lew; and myself. During the presentation, we will go through the main aspects and events that explain our third quarter results. And finally, we will open up for questions. Before we begin, I would like to draw your attention to our cautionary 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 may discuss some non-IFRS measures, such as adjusted EBITDA. I will now turn the call to Sergio.

Thank you, Santiago. Good morning, ladies and gentlemen. Thank you for joining us on the call today. The 3 months ended last September constituted yet another quarter with strong financial and operational results, all the while our operations and businesses continue to move into the post-pandemic new norm. As we move forward with our focused approach towards delivering sustainable recovery, adjusted EBITDA was above the $1 billion mark for the second consecutive quarter. This results came on the back of a benign pricing environment, primarily on brand-related products and natural gas.

While we managed to continue recovering our oil and gas production increasing 7% since the last quarter and 17% year-to-date, while containing cost pressures. CapEx activity continued to be primarily concentrated in developing our unconventional resources, reaching a historic record in terms of completed horizontal shale wells in any given quarter since the beginning of Vaca Muerta's development.

At the same time, we maintain our focus on achieving further operational efficiencies and pushing our technical boundaries to the next level, securing further gains in drilling and fracking speeds, while also recording the longest well ever drilled in Vaca Muerta with a horizontal leg of over 4,100 meters at our Loma Campana block. In terms of sale production, growth came mainly from the natural gas side based on the tie-ins encompassed during the previous quarter and early on in the third quarter, increasing shale gas operated production by 166% year-to-date.

This temporary prioritization of natural gas was tactically aimed and upped complying with our seasonal commitments within the Plan Gas program and allowing for further long-term contracting outside of it, generating a significant recovery in stable and predictable revenues for this segment. On the other hand, while shale oil production grew by 5% during the quarter, recent tie-ins have permitted to resume growth momentum with preliminary data for October presented growth of 17% versus the average in Q3, reaching a new record high in shale oil production of 61,000 barrels a day.

In addition, domestic demand for gasoline and diesel continued the recovery trend after mobility restrictions were fully lifted by the end of the second quarter with preliminary data for October showing demand for both fuels being at or slightly above recovery levels of 2019. During the quarter, we kept moving forward with our sustainability and energy transition agenda. We are making progress in concrete actions to reduce emissions and improve efficiency in our oil and gas business, such as the startup of a new ETBE unit in Lujan de Cuyo refinery and the beginning of works to revamp gas processing plants in Loma La Lata.

Additionally, we are also advancing our new energies portfolio. Our power subsidiary, YPF Luz made very good progress on the final stages of the new 120 megawatts wind farm at Canadon Leon, expecting COD before the end of this month. Thus, we will finish the year with almost 400 megawatts of renewable generation capacity, positioning YPF Luz as the second largest renewable generator in Argentina. Besides, the company already delivered growth of 114% on its renewable generation when comparing to cumulative 9 months of 2021 with the same period of last year and still have -- we have new projects in pipeline, plus YPF is one of the largest buyers of renewable energy with about 30% of our power purchases coming from renewable sources, showcasing our clear commitment towards reducing our carbon footprint.

We have also decided to gradually increase our participation in a local distributed solar company to enlarge the offering of renewable energy solutions to our clients. And we are putting forwards nature-based solutions like for station projects as the one we have in new (inaudible) province. On this topic, I have recently the honor to co-chair the energy and resource efficiency task force within the B20, which presented policy recommendations to the G20 heads of state, aiming at accelerating orderly and just energy transitions. In that sense, we highlighted the role of low carbon in addition to renewables, which will be crucial for some countries in their net 0 journey. And in our case, the strategic potential that our [bus] shale gas resources have to contribute to the process of regional and carbonization.

As a final comment on my introduction to our third quarter results, it's also worth highlighting that despite moving forward with our CapEx plan, we managed to deliver positive free cash flow before debt repayment for the sixth consecutive quarter. This, in turn, allowed us to continue reducing our net debt resulting in a steep reduction in our net leverage ratio returning to historical healthy levels. And finally, looking forward, although we remain cautious on the back of local macroeconomic uncertainties that could test our ability to adjust fuel prices in the near term, the robust results achieved so far permit us to revise our adjusted EBITDA guidance for the year upwards to a range of $3.8 billion to $3.9 billion.

We also reaffirm our guidance for full year CapEx of $2.7 billion. And our oil and gas production targets for the second half, the latter with some upside, particularly include, where shale oil production could end the year above previous expectations, providing for a better entry point in 2022. Before leaving you with Alejandro, I would like to once again tell you that I am especially proud of the YPF team of their commitment, their efforts. I also want to thank our clients for their fidelity and our investors, partners and suppliers for their continuous support.

Good morning to you all. As briefly anticipated by Sergio, our third quarter results came very strong on the back of a benign pricing environment, coupled with higher natural gas output and the continued recovery in local fuel demand. Adjusted EBITDA reached over $1.1 billion, 6% higher than the previous quarter. When compared to pre-pandemic levels, this quarter's results were 18% higher than Q3 2019 or 11% higher than the average of the third quarter of 2017, 2018 and 2019.

On a cumulative basis, for the 9 months ended September, adjusted EBITDA reached $3 billion, resulting in an EBITDA margin of 31%, which was lower on a sequential basis, but mostly in line with the historical average at about $11 per barrel during Q3. Further supported by positive results on the petrochemical segment that added an extra $2 per barrel when looking into the full adjusted EBITDA generated by our Downstream operations. However, the future evolution of margins for the Downstream segment, not only for YPF, but for the industry as a whole, represents one of the risks for our sector going forward.

Pressure is mounting from local independent producers to reduce the discount of local crude prices with respect to export parity, while Downstreamer's ability to pass on price increases to the pump could be challenging, considering recent actions taken by the government to contain inflation. Nevertheless, we will continue to monitor key variables such as FX valuation and global and local crude prices closely to define new adjustments at the pump. However, should FX depreciation rates in coming months, we shall carefully address the pace of any adjustments of our pricing in pesos, given the overall macroeconomic environment that could result in high demand elasticity in such a context.

Moving into revenues. Results showed an increase of 8% sequentially reaching $3.6 billion in the quarter, mainly supported by a 31% jump in natural gas revenues and 15% in domestic sales of gasoline and diesel. When comparing these figures with pre-pandemic levels of the same quarter in 2019, revenues were 9% higher. On the cost side, OpEx expanded 6% quarter-on-quarter in dollars on the back of increased activity and the recent evolution of macro variables. However, on a cumulative basis for the 9 months ended in September, total OpEx remains well below pre-pandemic levels at minus 15% when compared to the same period of 2019 as cost efficiencies secured last year continued to be well in effect despite mounting inflationary and salary pressures, while the currency depreciation has slowed down.

As regards CapEx. During Q3, we managed to accelerate the implementation of our investment program after a somewhat slower than projected pace in the first half of the year. CapEx expanded by 20% when compared to the previous quarter, accumulating $1 billion during the 9 months ended in September, 83% of which was deployed into our Upstream operations. Finally, these results translated into yet another quarter delivering positive free cash flow before debt financing, totaling $144 million, allowing for our net debt to decline by another $44 million or by a large $150 million when considering liquidity invested in financial assets accounted as noncurrent given their maturity being a few months longer than 1 year and were not for trading accounting treatment.

In addition, when considering the evolution during the last 12 months, net debt was reduced by about $750 million or a larger $890 million when including the noncurrent liquidity. Focusing on our Upstream activities. Total hydrocarbon production expanded by 7% on a sequential basis, accumulating a 17% increase when compared with average production in Q4 of last year. The quarter-over-quarter improvement was primarily concentrated on natural gas, which grew by 14% versus the previous quarter as we focused our Upstream activity on gas in our commitments as part of the new Plan Gas.

More specifically, we managed to grow our shale gas production by 64% when compared to the previous quarter, with an even more pronounced jump of 74% when looking specifically at our operated shale gas production, mostly led by the productivity of the new wells tied in the Rincon del Mangrullo and Aguada de la Arena blocks. On the crude oil side, production remained stable versus the previous quarter given the temporary redirection of efforts towards gas, as previously mentioned.

Nevertheless, it is worth highlighting the 5% growth in shale oil during Q3 and a further 17% in October versus the average of Q3, with our core hub reaching a new record at over 50,000 barrels per day of net oil. Regarding prices, during the quarter, we benefited from a 10% increase in natural gas prices, averaging $4.2 per million BTU, primarily on the back of seasonal adjustments within PG4 contracts.

Separately, on the crude oil front, our average realization price increased by 7% to $55 per barrel, only partially reflecting the rally in international prices as local crude continued being negotiated between local producers and refiners in a way to smooth out the impact on local fuel prices from the volatility in international markets. Moving into the operational highlights of our Upstream operations. During the third quarter, we marked a new record in terms of horizontal wells completions with 44 total new wells, 37 shale long wells and 7 shale gas wells, totaling 99 wells during the 9 months ended in September.

In setting these new records, we took advantage of the relatively large backlog of [TAC] wells that were accumulated last year during the anemic. But we also managed to keep drilling activity high as well, stabilizing our drilling and uncompleted inventory at about 60 wells, which we consider fairly reasonable to provide enough flexibility to our operations. This positive evolution in completed wells comes not only as a result of our resumed CapEx activity, but even more importantly, on the back of the continuous operational improvements that we continue to achieve.

Our drilling time on the unconventional side improved by almost 20% when compared to the normalized levels of Q2 or an even higher 35% versus the average of 2019. This was mainly the result of a reduction in nonperforming times and standardization of certain activities such as tool maneuvering, cementation, casing tuning and open hole registry, among others. In addition, on frac speed, our operations improved to an average of 188 stages per -- set per month during Q3, a 27% improvement compared to the previous quarter or an impressive 81% when compared to the average achieved in 2019.

Let me now go into our Downstream business. During the quarter, domestic fuels demand resume its recovering towards normalized pre-pandemic levels as mobility restrictions were relaxed after the setback in Q2. Sales of our main refined products increased 13% when compared to the previous quarter primarily driven by gasoline, which jumped 22%, ending September above pre-COVID levels of 2019. In the case of (inaudible), domestic sales increased 8% on a sequential basis averaging 3% above Q3 2019.

In terms of refinery utilization, our processing levels during Q3 remained almost unchanged on a sequential basis, averaging 263,000 barrels per day. This represented an increase of 13% versus the same period of last year, but about 9% below the pre-pandemic level of Q3 '19. Processing levels during the quarter were negatively affected by the scheduled maintenance works performed at one of the catalytic converters at the La Plata refinery, which was finalized in August within the planned schedule.

In addition, processing levels during the quarter were also affected by complex negotiations with local independent oil producers, who changed to maximize their export volumes on the back of better realized prices. On this issue, it is worth highlighting that during the quarter, we still acquired 19% of the crude processed at our refineries from third-party producers. However, going forward, we expect crude purchases from third parties to decline as we continue to make progress in growing our oil production, particularly light crudes coming from our Vaca Muerta operations. With regards to prices for gasoline and diesel, average net prices measured in dollars remained stable during Q3 when compared to the previous quarter, standing at similar levels to those registered on average in 2019.

Although retail prices remained stable in pesos, the evolution resulted from a relatively low currency devaluation that was compensated with some adjustments at the wholesale segments. Switching to the evolution of our cash flow during the quarter. I would like to highlight the positive trend in our cash flow from operations, which once again stood above $1 billion, comfortably covering our fully deployed investment plan and interest payments, allowing for further net debt reduction. This has marked the sixth consecutive quarter in positive free cash flow before debt repayment, resulting in a total net debt reduction of about $1.2 billion since March of 2020.

In terms of debt financing activity, in mid-July, we successfully tapped the local capital market with $384 million, 11-year dollar linked bond with a coupon of 5.75% that was priced at par, taking advantage of a unique opportunity to prefund our needs for the remainder of the year. To minimize cost of carry, the transaction was structured to be disbursed in 3 installments, [213] of which were actually cashed in during Q3, with the balance settled later in October. On the other hand, during the quarter, we repaid about $190 million in outstanding YPF debt, about half of which came from trade financing and other bank facilities, $55 million from local bonds and $43 million from the semiannual amortization on our March 2025 international bond.

By September 30, total and consolidated borrowings from bank and multis reached the lowest level in many years at around $55 million, expecting this figure to be even lower by year-end compared to an average of $1.5 billion in the last 5 years, leaving significant room within credit lines to handle next year's needs. In terms of liquidity, our cash and short-term investments totaled just over $1 billion by the end of September, an increase of $99 million when compared to the previous quarter. In addition, by the end of the quarter, we had $144 million booked as noncurrent investments, which could be considered as a good proxy to liquidity as they are held in local dollar-linked securities with maturities longer than 12 months, but shorter than 24 months.

Although these securities have decent liquidity in the secondary market, given that we do not hold them for trading based on our accounting policies, we are not marking these instruments to market and hence, not accounting them as part of current assets. Finally, we continue to manage our liquidity position with the objective of minimizing FX exposure. To that end, we have an active cash management approach to achieve the difficult task of building another great portfolio in the context of limited available instruments in the local market, particularly considering our self-imposed credit concentration limits.

Consequently, and given the increase in net liquidity during Q3 on the back of the opportunistic prefunding exercise, our net FX exposure increased from 6% at the end of June to about 14% by September 30. Before finishing our presentation, let me briefly go through our maturity profile. But before doing so, let me highlight the significant reduction in net leverage that was achieved during Q3, reaching 2x net debt to 12 months adjusted EBITDA by the end of September, showcasing the tremendous recovery in our operating and financial performance after peaking at a net leverage ratio of 4.9x only 6 months ago.

In addition, for the first time in many years, our liquidity position exceeds our short-term debt, having less than $1 billion coming due within the next 12 months. In terms of 2022 debt maturities, we have just north of $800 million on a consolidated basis, with a particular concentration in Q2, including the $260 million amortization on our 2024 international bond. With that in mind, we have been working for several months now on a cross-border multilateral lead financing, which is at the final stages of being signed.

Should that deal finally gets confirmed in coming weeks, we shall be able to closely match amortizations on our international bonds, both the 2025 in March and the '24 in April with disbursements from that facility. This should, therefore, minimize our net demand of FX reserves from the Central Bank that's further mitigating potential risks to comply with our obligations even if current FX restrictions are extended into next year. That finishes our presentation for today. We are now open for your questions.

(Operator Instructions) Our first question is from Frank McGann with Bank of America.

Okay. I was just wondering how you're thinking about growth from here. You mentioned that oil production could continue to rise and could be a little bit higher levels perhaps than you had originally expected at the end of the year. I was just wondering in terms of looking forward, how much upside do you see over the next couple of years potentially? And how are you seeing that relative to gas upside?

With gas I'm just wondering what the transportation limitations are. And now that you've ramped up the production pretty aggressively to take advantage of the Plan Gas prices, do you see further upside in natural gas ARPU?

Well, clearly, when looking at growth potential, as we have been saying, we see that mostly related to all, to crude oil. As you have just said, we had a very impressive ramp up in natural gas activity in the last few months, particularly in line with our commitments within the new Plan Gas program. And going forward on that particular segment on natural gas, we are not expecting in the short term significant further growth on natural gas.

We do see evacuation limitations out of Vaca Muerta for natural gas. And as you probably know, the government authorities have been commenting publicly about their intentions to put forward a new gas pipeline to further increase the evacuation possibilities of natural gas out of the Neuquina basin. So clearly, for as long as that -- those projects do materialize in coming years, we clearly are very likely to join in the effort of putting forward further growth in natural gas, of course, always assuming and preserving profitability on that front.

But for as long as those new pipelines are not in place, we see current natural gas production as being relatively stable in the near future. On the other side, in terms of oil, as you said, we will continue to see significant potential there. We are focusing our CapEx efforts on front. As you have seen during the last quarter, the growth in oil was not relevant, was relatively stable. Clearly, as we manage or as we focus our activity in natural gas, in line with our seasonal commitments.

But now as we have expressed already in October, we are already ramping up activity and production in crude oil. And we expect that to continue going forward. We do see our CapEx plans to -- probably to increase for next year, particularly in Upstream, and we have already commented in the previous call our ambitions to move forward with -- on the Downstream segment with ramp and an upgrade of our refineries, which will take a significant amount of CapEx in the next 3 years.

But besides that, we are also expecting to increase our Upstream CapEx, particularly next year. And with that, hopefully and probably bringing a significant improvement and growth in our crude oil production.

Okay. Great. Very interesting. If I could just follow up with a second question. In terms of hydrogen, there's announcements over the last couple of weeks about a large development being done in Rio Negro. I was just wondering, are you participating in that? Or do you have any other projects perhaps that you might be looking at to do green hydrogen?

Yes. Well, particularly on that project that was announced, we have nothing to do with it. We are not part of it. We do -- although actually are part of a big consortium of Argentine companies from different segments, doing R&D on green hydrogen. So mostly, we are participating on that consortium through our Y-TEC R&D subsidiary, which is a joint venture together with (inaudible). So we are, I would say, initial steps of doing research and development on hydrogen, but not being part of that announcement that was -- that came on the media in recent weeks.

Our next question is from Guilherme Levy with Morgan Stanley.

So I have 2 questions. Just wondering on the shale production ramp-up. There has been a marked increase in drilling and tie-in in the recent past. So I just wanted to get a second view of how much more efficient that we could get. And if the bulk of the efficiencies are already achieved, so we should assume that the current levels are a sustainable run rate going forward?

And then the second question is on lifting costs. Costs have been well under control this quarter. And so I wanted to understand what should we expect going forward from this line, considering both the high inflation rates in Argentina and also the inflation we are seeing in the global oil industry. Those were my questions.

Thank you, Guilherme, for your questions. In terms of operating efficiencies within our shale activity, I would say that yes, we definitely have an impressive improvement, particularly in frac speed, but also most recently in the last quarter in drilling. We are optimistic that we should continue seeing further improvements, I would say that more on the drilling side line on fracking, but still, we would expect also some improvements in fracking as well.

So clearly, the numbers for the third quarter should be used as a basis for future performance. But we expect along the next few months, particularly as I said, in drilling, but then also some further improvements in fracking as well. And in terms of lifting costs, well, as you said, they've been relatively stable, managing to compensate the evolution of macro variables, clearly, as inflation has been running higher than devaluation. Our dollar denominated -- I would say, dollar equivalent costs clearly are having some pressure there.

But still, we've managed to improve -- compensate the evolution of those macro variables through efficiencies and through a higher proportion of unconventional shale within our total portfolio, total production. So going forward, as we expect that proportion to continue increasing, meaning the proportion of shale on the total hydrocarbon production, we would expect the average lifting cost to go down probably below $10 on average for both segments, conventional and unconventional.

Our next question is from Regis Cardoso with Credit Suisse.

Congratulations on the results. The topics I wanted to touch on. One of them is the guidance for this year. It seems to imply a big CapEx increase in the fourth quarter, assuming that you've done so far $1.7 billion and your guidance is $2.7 billion. I just wanted to make sure if I'm understanding this correctly, there would be a big CapEx concentration of about $1 billion in the fourth quarter?

Likewise still in the guidance discussion, EBITDA guidance for 2021 implies fourth quarter around $800 million to $900 million, which is a sequential decrease relative to the third quarter. Is this -- am I reading it correctly? Would that decrease be related to a lower gas price in the Plan Gas or seasonality? So that's the topic on the guidance and financial metrics.

Two other topics I wanted to touch on. One of them is looking beyond this year and into 2022, how do you balance CapEx with deleveraging, if any? I mean would you maintain 2x net debt to EBITDA and growing EBITDA, you could actually increase your absolute net debt. Or do you see it differently? And ultimately, I mean, YPF has been in this position where it has struggled to grow production without leveraging any further, right?

So whether you see 2022 as a more benign environment where you could actually either deleverage or grow production more materially? So that's it for '22. If I may, a third one, just on the fuel prices. It appears to us that domestic prices are still below international parity at the refinery gate in Argentina. So I wonder if that entails that you still have some upside, let's say, in the EBITDA front for catching up with import parity or if I'm seeing it wrong?

Thank you, Regis, for your questions. I'm going to start with the prices. I'm going to -- let me give you a broader answer. As you probably recall, between August of last year and May this year, we made several adjustments at the pump with the objective of compensating for fuel tax hikes, not previously translated into retail prices as well as a recovery in dollar margins. Based on those adjustments, we managed to strengthen our operating cash flow and by that time, align net prices in dollar terms with the average for 2019 when Brent prices were at similar levels, trading in the mid-60s providing for reasonable margins along the sector's value chain.

Since that moment, we have expressed our decision to monitor the evolution of key variables such as the evolution of the FX as well as international and local oil prices to determine the convenience and timing of any further adjustments, while considering the general macroeconomic environment with particular emphasis on the inflationary context. Consequently, on the back of the lower anticipated evolution of the FX in recent months, we have taken a conservative approach to address the volatility in international prices, avoiding unnecessary pressure on consumers while we waited to -- for the global market to settle down.

And we managed to maintain this conservative approach on the back of our active effort from most actors within our sector that collectively understood the convenience to smooth out the full effect of the rally in international prices to local consumers. In any case, it would be fair to highlight that pump-related revenues, although very relevant for our company, will present less than 50% of our total revenues between 40% and 55% of our revenues. Going forward, given that market, the consensus is building up around the notion of international crude prices settling down around mid-70s at minimum, we will probably consider introducing further adjustments at the pump in coming months to close that gap, reducing the price distortions currently embedded in the local prices when compared to international ones.

However, at the same time, we will have to consider the evolution of the FX and adjust prices in pesos in a manageable and sustainable way. We are convinced that besides short-term fluctuations and distortions, having local prices adequately reference to international parties is the way to ensure the healthy and sustainable development of our sector, enabling the true potential of our world-class hydrocarbon assets.

Thank you, Sergio. And Regis, in terms of your other questions, I will try to tackle them as best as possible. If I recall correctly, you asked about the CapEx in fourth quarter of this year. And yes, the actual number is an expectation of about $900 million. So the aggregate for the 9 months, it's a little bit over [1.7], rounded at 1.8. And so we are expecting a CapEx level to increase to about $900 million, particularly led by Upstream operations, where we see further drilling activity including, on average, 3 more weeks, 2 in our unconventional areas and 1 in conventional.

We also expect some further investment in facilities, in ground facilities, particularly in our unconventional blocks. And then also, we expect the ramp-up in activity in our Downstream operations as well, where we are seeing more activity on the next project. Basically, the projects, as I mentioned before, the multi-annual project that goes for revamping and improving the quality of our fuels. So that's in general for the fourth quarter in terms of CapEx. In terms of EBITDA expectations for the fourth quarter, you are looking at it correctly.

We do see a sequential decrease in EBITDA generation. That is mostly related to the seasonality of the natural gas segment, where we expect there a significant decline mostly on prices. As you know, there are seasonal adjustments under the Plan Gas program and also in volumes as well, but mostly on prices. So that is the main impact of the main aspect that will -- that make us project a lower EBITDA for the fourth quarter, together with the continuous evolution of micro variables, as we mentioned before, right, the inflation running higher than devaluation.

That also affects somehow our cost structure. And finally, when looking into 2022, we would expect not to reduce -- to further reduce leverage, but take advantage of the very attractive opportunities that we have to accelerate the development of our share resources, particularly the crude resources. So -- and we mentioned this in the previous call as well, we would expect long-term leverage to be in the order of 2x or to max out at 2x in the future, provide for any cash flow generation to go into CapEx to foster or to accelerate the development of our shale resources. So not expecting any further deleveraging, but rather further CapEx activity.

Our next question is from Bruno Amorim with Goldman Sachs.

My question has actually been answered, but just to make sure I got it correctly. It's a follow-up on Regis' question on deleveraging going forward. So providing that EBITDA would be in line with this year or even above next year, if you are not assuming a lower leverage, this means that in absolute terms, you do expect for net debt should be either stable or higher next year vis-a-vis the current level? So is that understanding correct?

Bruno, yes, the understanding is fairly correct. We don't expect net debt to go down next year. Of course, depending on what the cash flow generation will end up being next year, which will also depend on many variables. But for as long as we continue to generate similar levels of cash, we would expect to ramp up CapEx activity, not reducing absolute net debt nor leverage.

Our next question is from [Konstantinos Papalios] with (inaudible) Argentina.

Congratulations on your results. My question for you today is with respect to price adjustments at the pump. Now could you share your view for the next month? I mean, these prices are frozen in pesos, pinching your Downstream margins. Can you maintain your CapEx schedule? And if so, for how long? Additionally, we know that Mega facility has been processing less NGLs in the month of October. So you do have some losses there or some revenues that won't come in through the door.

So how does this -- how do you balance all this with prices frozen in pesos in Downstream and then less money entering through the other business segments of the company? And if I might just add one more question regarding cross-border financing. Could you give us some detail on amount the maturity? And what is -- what happens if this cross-border financing does not materialize?

Sure, Konstantinos. In terms of your question about prices at the pump, I think Sergio went in some detail on our expectations. We do not expect prices to be frozen, but rather we expect to carefully monitor the evolution of different variables, right? As we've been saying, we now believe that international prices have established some certain floor that probably it would be a healthy decision for the sector as a whole to try to reduce the spread to international parties.

And of course, that will also depend on the evolution of the FX, and we will have to carefully address any potential adjustments of the pump to figure out the potential impact in demand that such decisions could have. So we are not assuring by no means that prices are not going to move, nor the opposite. We continue to carefully monitor the different variables. And in the context of the macroeconomic environment that we are all living on.

So that's why I would not definitely say that Downstream margins are going to be significantly down. If you look at how local crude prices have been negotiated locally, we are above the average of the last quarter. So in the third quarter, we had an average on the Upstream side in Argentina, $55, mostly on -- related to Medanito oil, lightweight Medanito oil. Those prices have been trending upwards. As of now, the prices that are being negotiated among producers and Downstream is closer to $60. So already in there, you are seeing an evolution in Upstream. So because of that, we are already having a reduction in Downstream margins.

Going forward, of course, that is -- to be able to continue with that process, we will definitely need to address prices at the pump. But again, that will be carefully monitored in coming weeks and months. In terms of Mega, it's related to seasonality that I mentioned. And also, as you correctly say, Mega has been processing less amount of natural gas and producing less amount of NGLs. That is related to scheduled maintenance at Mega, which was performed in the month of October.

It is already back in full operation. And so yes, that is part of the estimate that we are putting forward to the market on our EBITDA generation for the fourth quarter. So nothing beyond the impact that we are already forecasting when putting forward a full $3.8 million to $3.9 million EBITDA for the full year. And finally, on the cross-border financing, let me -- given the fact that it's not closed yet, let me just keep for ourselves the specific tenor and interest rate.

Although I can mention that it's not short term, it's a medium-term facility and at very competitive levels. If the deal doesn't materialize, of course, we will have other opportunities or other alternatives. Clearly not cross-border and still consider that our ability to own our payments, our commitments on our maturities on international bonds next year, should be granted even if current FX restrictions are extended, given the way those FX restrictions currently in place are written or the way they work today because the amortizations that we have next year are related to bonds that have been part of previous liability management exercises.

And so we understand that current FX restrictions, if at all extended, should not impair our ability to comply with our commitments. But again, if this transaction moves forward, which we are very optimistic that it will, we will further provide for an alleviation for a relief in FX reserves from the Central Bank when related to the amortizations that we have to honor next year by having relatively matched those payments with the disbursements from this cross-border multilateral facility.

Our next question is from Ezequiel Fernandez with Balanz.

Thanks for the very complete materials as always. I have 3 questions. I would like to go one by one, if you do not mind. Last year, the company launched an operational expense savings program that we -- also bring in efficiencies in the last quarters. Congratulations on that. Do you think you're mostly done with these efforts? Are you already satisfied with what you've done?

Ezequiel, not sure whether you were going to ask 3 questions at once. But yes, let me quickly answer that. We are happy -- we are -- we feel okay with the results achieved so far. Clearly, the evolution of macro variables in the last few months have reduced somehow the full effect of our cost-cutting exercise executed last year. By the end of last year, we had expressed that we have achieved a structural cost reduction of 20% when compared to pre-pandemic levels. That was sustained for the first 6 months of this year.

Now we're looking at the third quarter and we're looking at the full 9 months, that amount of savings was reduced to about 15% when compared to the previous year -- sorry, with pre-pandemic. Actually, if you take out some standby costs related to the blockade in (inaudible) in April of this year, that would be 17% on a fully standardized basis. And we are expecting that to be maintained roughly in the 15% cost reduction or savings by the end of the year.

So we are okay with that. We definitely have expected to sustain further savings. But we -- this is a new cultural thing within YPF to continuously look for efficiencies. The same way that we are doing in our shale operations, as discussed before, we continue to look for further savings across the company as a new cultural way of doing and moving forward with other business.

Okay. Great. My second question is also, during the pandemic YPF entertained the idea of looking for asset sales. Is the company continuing to look for interested parties in noncore assets? And if there has been any progress on specific assets like Metrogas or mature concessions lately?

Thank you, Ezequiel, for your question. And with respect to M&A and I'm going to cover the sale activity and also the mature fields. Let me start with shales. We mentioned as you said in previous calls and in line with the financial deleveraging that the company has already been achieved. We continue to see potential M&A activity as a way to optimize our portfolio rather than as a critical funding source.

In that sense, when looking at our unconventional acreage and given prevailing market conditions, in the near future, we shall only see, if any at all, some small-scale divestment in blocks that are outside our core development strategy. We expect to mature fields. We continue moving forward, analyzing potential opportunities in our mature conventional areas.

And this analysis focuses into assets or blocks that have some further development upside, but require a niche player to extract full potential. And given the positive feedback gathered through an initial round of conversation with potential interested parties, we have entered into preliminary conversations with provincial authorities where these assets are located to establish a basic framework of understanding in the case this potential disinvestment opportunity ends up materializing. And these are the 2 areas that we are analyzing with respect to M&A.

Okay. Great. And my final question is related to the last maybe 2 or 3 weeks toward some press articles in which the idea of a $3.5 billion CapEx for next year was a sort of a target. I don't know if this is a formal target already? Or does it still need to be confirmed on the guidance or budget exercise that you're probably working on?

Yes. Basically, that is not a formal target yet, of course, as we commented earlier, we do expect CapEx to be higher next year than this year, not only because of the Downstream projects. That was already commented in the previous call, but also as we expect to continue increasing activity in our Upstream operations with a specific focus in oil. So as of today, we have not gone through a formal budget approval for next year. We should be doing so in the next few weeks.

And once we have that, then we're in a situation or in a position to formalize the CapEx guidance for next year. But for now, it's -- I would say it's informal intentions and in line with what we have been commenting in the previous call and during this call as well.

Our next question is from Luiz Carvalho with UBS.

I'd like to maybe come back on the free cash flow for 2022. And you just mentioned about the (inaudible) inform and intentions about a $3.5 billion CapEx. You also mentioned during the call that you do not have the intention to potentially reduce further deleverage of the company. But assume due to the $800 million debt that you have for next year and around, let's say, $600 million on that interest plus this CapEx. If you do not roll over any debt for next year, you're probably going to consume a significant amount of your cash considering, let's call close to $4 billion EBITDA as you're probably going to deliver this year, right?

So trying to actually reconcile here, how do you think the CapEx even can, I don't know, potentially go up? And what are your expectations in terms of EBITDA for 2022? I know that you cannot provide any guidance, but considering this, I would say, baseline as $4 billion, what is the likelihood that you see a higher EBITDA with the current oil prices that we have? And the current conditions that we have 2022 in order to try to reconcile to the free cash flow for next year and forward?

The second question, I think that you also touched base on the previous question. It's more related to the fuel imports, right? So YPF did import gasoline at and apparent that's where shale is, at a higher price versus the average of domestic prices, right? So even if you consider the difference between the premium and the regular gasoline, I'd like to see if you can provide a bit more details or update in terms of import conditions and import needs as we head towards the fourth quarter in 2022.

Thank you for your questions. In terms of how we intend to balance our informal expectations for next year so far, as I said before, we still have to go through a full revision of our CapEx plan for next year and our EBITDA generation estimates for next year. What I can guarantee you is that we plan on maintaining a healthy financial approach, both in the sense of net leverage, as said, with net leverage being maxed out at 2x. And cash balance where we expect to continue having -- working with a minimum cash balance in the order of $800 million to $1 billion.

You know that temporarily, we've been above that level. In some cases, and -- but roughly speaking, in the past, we have been saying that we will be -- we targeted $1 billion plus or minus 10%. Right now, we have reduced that target a little bit probably to a range of $800 million to $1 billion. That is related also to our short-term maturities, as we commented during the presentation. For the first time in many, many years, our net cash position is higher than our short-term maturities, and we expect that to remain the case for the next few months, and I would say a couple of years, given that maturities will continue to be relatively low.

So because of that, of course, we -- when you look and when you try to estimate what the EBITDA number has to be to get to that level of CapEx that was informally mentioned in the media, then definitely, we need to finalize our budget for next year and come up with the final numbers for CapEx. But again, as previously said, we expect to increase our CapEx level. And probably for that, we will come with still strong EBITDA generation as well as working capital contributions that we would have.

We have been -- we have a few fiscal credits that we can cash in. And we also have some other account receivables that we have been making very good progress in collecting. So when you combine all of that is that we feel pretty comfortable with our ability to increase our cash -- sorry, our CapEx next year without jeopardizing the financial health, both in terms of leverage and in terms of liquidity.

And in terms of...

Yes. Sorry, if I may challenge, let's just pretend that oil prices come down to, let's say, $50 next year, right? I don't know something happened on OPEC level. I just want to try to understand what will be the flexibility on the CapEx because, of course, the cash generation for 2022 will be negatively impacted because of the, say, lower oil price in that scenario. And as a consequence, do you say with the debt profile that you guys have and the commitments, what will be the flexibility in order to try to reduce the CapEx for -- in order to cope or to keep you to the net leverage at 2x?

I understand that the -- around 2x net debt to EBITDA would be the main target or production growth or CapEx would be the main target for the company.

Yes. No. Thank you for asking for the clarification. Yes, it's completely clear for us that the main target is the financial health. So I would say that the main target would be to be within that 2x net leverage. And based on that, we will have to flexibilize our CapEx in line with the cash flow generation to maintain those financial targets. So clearly, the answer to that would be flexibilizing CapEx and accommodating our CapEx target to whatever cash flow generation capacity we will end up having.

Even though we still believe that there is a tremendous opportunity to add value and to generate value for all of our stakeholders by accelerating the development of our shale resources, but I think -- primarily the shale resources. But we do believe, and we are very serious about that, that the only way to seriously or sustainably do that is by maintaining a prudent financial framework. So that will be the main driver.

Okay. Sorry. And I (inaudible) to you about the fuel imports.

Sure. In terms of fuel imports, yes, as you said, we -- most recent data, given the rally primarily since October, the massive rally in international prices. Our prices at the pump today are below import parity levels. That's why we have to bear in mind the full equilibrium of the market as a whole. And in that sense, we try to balance the relatively small amount of our imports in the context of the general business that we have undergoing.

So in that sense, yes, the ramp-up in demand both in gasoline and diesel is creating the need to increase our imports in the fourth quarter, primarily of gas and oil. As you know, we are structurally -- for the last few years, we've been structurally a net importer of diesel, not that much of gasoline. And so on average, in the fourth quarter, we will be probably imported what was the average for the last few years, which is in the order of 20% of our diesel sales.

That could be challenging in the context of the current relationship between local fuel prices and import parities, yes. And definitely, that is a challenge. And that's why as Sergio commented in his -- when talking about pump prices and the future evolution of pump prices, we do have -- we do carefully monitor those variables to basically make the right decision in terms of the future evolution of prices.

Our next question is from Walter Chiarvesio with Santander.

Actually, all my questions have been answered.

And with that, I'm showing no further questions. I'll turn the call back over to the presenters.

Thank you very much, guys, for your interest, for following YPF, for your comments and reports and have a good day.

Ladies and gentlemen, this concludes today's conference call and webcast. You may now disconnect. Thank you.