YPF SA (YPF) 2023 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. At this time, I would like to welcome everyone to the YPF First Quarter 2023 Earnings Webcast. (Operator Instructions)

It's now my pleasure to turn today's call over to Pablo Calderone, Investor Relations Manager. Sir, please go ahead.

Good morning, ladies and gentlemen. This is Pablo Calderone, YPF IR Manager. Thank you for joining us today in our first quarter 2023 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 first quarter results. And finally, we will open up the call 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. 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, Pablo, go ahead.

Thank you, Pablo, and good morning to you all. We are glad to report a solid beginning of the year across our operational and financial metrics, where our total hydrocarbon production continued with a positive trend, bringing to market over 511,000 barrels of oil equivalent per day, representing an increase of 2% on a sequential basis and 1% when compared with the same period of 2022. Moreover, I would like to highlight the evolution of our crude oil production we I commented during our strategic outlook presenting a few weeks ago, is the focus of our short-term growth strategy, recording a 3% sequential increase and a robust 7% interannual expansion.

Adjusted EBITDA remained strong in the quarter, surpassing once again the $1 billion mark, expanding 12% from the previous quarter and 5% on a year-over-year basis. Sequential improvements came as a result of higher hydrocarbon production and higher processing levels at our refineries, accompanied also by lower OpEx, partially offset by lower realization prices of our refinery products when comparing to the previous quarter. The solid operating results permit our bottom line to come in positive territory once again, with net income reaching $341 million in Q1.

In terms of our investment activities, we started the year investing $1.3 million, 78% higher than the first quarter of 2022, on track to meet our ambitious plan for the year, where the main focus was once again directed to shale operations, which concentrated more than 50% of the total investment.

On the financial side, free cash flow was almost flat during the first quarter at a negative $17 million, taking our net debt to $6 billion, resulting in a flat net leverage ratio at 1.2x.

On a final note, let me briefly comment on the positive recent development related to the international legal contingencies. In the Petersen and Eton Park case, on March 31, the New York court found that YPF has not contractual liability and always no damage to the claimants and according dismissed plaintiffs came against YPF. We believe this ruling to be of significant value to dissipate, to a large extent, our potential contingencies and should plaintiff sue to appeal the decision, YPF will continue to defend itself in accordance with applicable law.

In the Maxus case, on April 6, YPF and Repsol signed a settlement agreement with the Maxus Settlement Trust, providing for a full release and discharge of all claims in exchange for payment of $287.5 million each, subject to the satisfaction or waiver of certain conditions, including court approvals and other procedural events. We are convinced that this legal decision represents a fair and reasonable outcome for YPF and will allow the company to continue focusing on generating value for all our stakeholders.

In summary, we are pleased with the results achieved during first Q '23. And although we now -- it is a year full of challenges, we believe we have taken the initial step to deliver on the ambitious goals we set for the year.

I now turn to Alejandro to go through some further details of our operating and financial results for the quarter.

Thank you, Pablo. Let me begin by expanding on Pablo's comments about the evolution of our oil and gas production. During the quarter, our total hydrocarbon production delivered 511,000 barrels of oil equivalent per day, highlighting a strong interannual expansion in our crude production, reaching the highest quarterly mark since 2016 at 238,000 barrels per day.

And beyond crude, natural gas production increased 2% on a sequential basis, while NGLs remained essentially flat. The positive evolution in oil and gas production on a sequential basis came once again and as expected on the back of the solid increase of 6% in our total shale production.

Moreover, during this quarter, our total conventional production remained flat when compared to the previous quarter, mainly as a result of our continued strategy of extending tertiary production which recorded an expansion of 7% versus the previous quarter and almost 50% against the same quarter of 2022.

In that sense, in Manantiales Behr, our flagship project, tertiary production represents almost 1/3 of the total production of the block, and in the other 3 pilots being deployed at Chachahuen in Mendoza, El Trebol in Chubut and Los Perales in Santa Cruz, we have continued harvesting promising results.

Moving to costs. Lifting averaged $14.6 per barrel of oil equivalent across our upstream operations, representing a minor increase when compared to the $14.5 in the previous quarter, more particularly for our shale core hub operations, lifting costs increased by about 8% as higher activity and energy costs during the quarter overrun the expanded production, but still remaining at a very competitive level of $4 per barrel.

Regarding prices within the Upstream segment, crude oil realization prices averaged $67 per barrel in the first quarter, representing a minor increase compared to the previous quarter, but leading to a significant reduction in the discount to Brent prices, which declined by about 7% in the same period. On the natural gas side, prices remain sequentially flat, averaging $3.1 per million BTU, aligned with Plan Gas prices for the summer season.

Zooming into our shale operations, during the quarter, we completed 38 new horizontal wells in our operated blocks. We also continued increasing the return of drilling activity to enlarge our inventory of drilled and uncompleted wells.

In that sense, during the first quarter, we drilled a total of 48 new horizontal wells, 34 of which were in oil-producing blocks and 14 targeting shale gas, representing a new quarterly record mark in terms of drilling activity. It is also worth noting that during this quarter, we continued with the strategy of developing Vaca Muerta beyond our core hub blocks.

In that regard, during the first quarter, we tied in 4 oil wells at our fully owned Loma Amarilla block, and we have just finished drilling 1 well at Las Tacanas block, targeting natural gas production. The new tie-ins during the quarter led our shale production into further expansion. On a sequential basis, our shale oil production increased by 9% and our shale gas production expanded by 4%, averaging over 92,000 barrels of oil per day and about 17 million cubic meters per day of gas.

And when compared to the same period of 2022, shale oil production expanded by 31%, aligned with our strategy of accelerating the monetization of our shale oil operations. In terms of efficiencies within our shale operations, during the quarter, we lost some ground in terms of the development costs at our core hub operations, averaging $9.9 per barrel of oil equivalent, primarily on the back of continuous cost pressures, although operating metrics remain healthy. And it is also fair to highlight that the development cost for our core hub operations reported in previous quarters, was revised slightly upwards as a result of some retracted tariff adjustments as well as updated EUR estimates of some specific wells based on actual productivity recorded in recent months.

Finally, regarding our investment in facilities required to unlock our shale oil production, in January, we put in operations our third crude oil treatment facility in Vaca Muerta located at Bandurria Sur with an initial processing capacity of 4,000 cubic meters per day, which is targeted to be expanded to 12,000 cubic meters per day during the year.

Let me now briefly comment on the progress made in relation to the midstream oil projects aimed at unlocking the evacuation capacity of the Neuquina basin. First, regarding the expansion of the existing system to the Atlantic, Oldelval has made steady progress on its second stage of expansion, aiming at adding about 20,000 barrels per day of transportation capacity to the system, expected to reach commercial operation during the third quarter of this year. In addition, OTE has achieved solid progress in the critical path of its expansion project, having initiated the preliminary works for the construction of 2 new storage facilities of 50,000 cubic meters each and the offshore terminal at Puerto Rosales.

In terms of financing, on top of the large portion of the total CapEx to be funded through prepaid ship or pay contracts, both companies, Oldelval and OTE tapped the local capital markets with 3-year local notes of $50 million each, thus, securing a further portion of the funding required by the projects.

Moving to the Pacific route. The Transandino pipeline of the OTA-OTC system responded well to the in-line inspection test, resulting in only minor repairs that were already executed. Thus, the pipeline is now in operating conditions to resume exports to Chile in coming weeks after over 15 years of being idle.

In addition, we have continued making good progress in the construction of the Vaca Muerta Norte pipeline that will allow us and other producers of the basin to direct the crude oil produced in the core operations of Vaca Muerta to the Transandino pipeline and further north into our Luján de Cuyo refinery. The project is at about 60% completion and is expected to start operations between September and October of this year.

Finally, we have also achieved solid progress on the engineering design process for the Vaca Muerta Sur pipeline and export terminal, having achieved about 70% completion. In addition, we are progressing steadily with the environmental impact studies for the full project. It is important to highlight that even though the project is and will continue to be led by YPF, we have already initiated conversations with other major players of the Neuquina basin who already showed interest in participating in the project.

Switching to our downstream operations, let me start by highlighting that in 2023, the company has decided to reorganize the business segments considered for financial reporting by separating the downstream activities into those related to the midstream oil refining, transportation of oil and refined products and petrochemical production into a new segment called Industrialization, from the commercial activities of refined and petrochemical products, natural gas and trading activities that were grouped into another segment called Commercialization. This segment reclassification is aligned with the organizational change that separated this business under the leadership of 2 different vice presidents.

Now regarding our domestic sales of gasoline and diesel, total dispatch volumes decreased by 3% when compared to the previous quarter, driven by a contraction of 6% in diesel sales, mainly due to the lower seasonal demand in the agro business that was particularly affected by the severe drought that the country experienced in recent months and partially offset by a 2% increase in gasoline demand, which set a new quarterly record. In a year-over-year comparison, diesel demand remained almost flat, while gasoline sales stood 7% about a year ago.

In terms of refinery utilization, the revamping of a topping unit at the La Plata refinery that eliminated bottlenecks in the processing of light crude oil, accompanied by the revamping of the pump station Puesto Hernandez in the Neuquina basin, allowed us to increase processing levels to 307,000 barrels per day, 5% higher than the previous quarter and 9% above a year ago, achieving the highest quarterly mark in the last 13 years.

In addition, during the quarter, we managed to maximize our refinery conversion levels, reaching a record of gasoline and middle distillates production. However, in spite of the higher refinery output, total fuel imports increased during the quarter, representing 12% of total fuels sold in Q1 in order to build up inventories that remain below historical average levels in the preceding quarter.

In terms of prices, during the first quarter, we continued with our strategy of adjusting prices of local fuels in a way to mitigate, to the largest possible extent, the effect of the depreciation of the currency, while reducing, or at the minimum, avoid extending the gap between the pricing of local fuels vis-à-vis international parities.

Consequently, average fuel prices measured in U.S. dollars decreased 3% sequentially but stood 16% above Q1 2022. And the gap between local fuel prices versus import parity declined to an average of about 20% in the first quarter, while further declining to about 15% in April and more recently during the first days of May to a smaller discount of about 10% on the back of the continuous general downward trend in international prices.

Finally, on the financial front. The beginning of the year resulted in another quarter delivering sound operating cash flow, which increased 12% sequentially to about $1.5 billion on the back of the higher adjusted EBITDA coupled with positive working capital contributions.

This strong cash generation was almost enough to fully fund our investment plan, payments of interest and other expenses, resulting in a slight negative free cash flow of just $17 million. And despite this minor negative free cash flow that led to a marginal increase in our net debt to $6 billion, the higher 12-month rolling adjusted EBITDA permitted to maintain our net leverage ratio flat at 1.2x.

In terms of financing, during the first 4 months of the year, we have already raised over $1 billion through tapping the local capital markets in 2 occasions, in January and in April, and by securing several trade-related loans from relationship banks, obtaining net new funding of over $500 million, $294 million of which took place in Q1 and the balance during April.

It is worth highlighting that this funding took place at very attractive financing costs, benefiting from the average [price] in the local market as demonstrated by the negative funding cost of minus 5% achieved on our recent 2-year dollar-linked local notes.

Furthermore, during March, we entered into a fully committed short-term revolving credit facility denominated in pesos with 3 local financial institutions for an equivalent of $120 million. It is worth noting that this is a product that is not widely available in our local market but that we eagerly pursued as it provides us with flexibility to manage our liquidity more efficiently. All in all, these financings provide the right platform to secure our funding plan for the year including the liquidity required for the settlement of the Maxus legal case.

On the liquidity front, our cash and short-term investments increased to $1.3 billion as of March 31 compared to $1.1 billion as of the end of December of last year. And in terms of cash management, we have continued with an active asset management approach to minimize FX exposure, considering the prevailing regulations that restricts our ability to hold assets abroad. In that sense, in the context of limited available dollarized instruments in the local market and given our increased liquidity, we ended the quarter with a consolidated net FX exposure of 21% of total liquidity.

Finally, when looking into our debt profile, I would like to highlight that our healthy liquidity position comfortably covers our debt amortizations for the next 12 months, given a very manageable debt profile for the rest of the year.

And with this, I conclude our presentation for today and open the call for your questions.

(Operator Instructions) Your first question comes from the line of Walter Chiarvesio with Santander.

Congratulations for the results. I will have 2 questions. If you could first develop a little bit more on the export potential for the company. I understand that the company had crude oil deficits in the short term, but feel still there is some potential of exports given the connection to the trans-Andean pipeline. And if you can provide some details on the volumes you're seeing that you can deliver through this pipeline this year and the next one, for example? That is one thing.

And the other thing is, what do you see in the next 6 months regarding pump prices given that we are in an inventory year, inflation is running high [in quarry]. The company is receiving some pressure. This, the question, of course, for the government to try to keep pump prices stable.

Well, Walter, thanks a lot for your questions. Let me address first the question about the export potential. As was recently announced in the media, we have reached an agreement with ENAP to take advantage of the availability now of the Transandino pipeline that after several months of work and after performing in-line inspection should be back in operations in the coming weeks. This is a milestone -- a key milestone given the over 15 years that, that pipeline has been idle. And that clearly is on the back of the increased production, not only based on YPF's production, but also from all the other players in the Neuquina basin and in the country as a whole.

So we believe that, that will continue to expand the total export potential of the country and more specifically for YPF, that should allow us to become a structural exporter once again. So as mentioned, there is a short-term agreement to start with a volume of up to 40,000 barrels a day that should start to be pumped as early as the first days of June, so in a few weeks from now.

And out of that volume, YPF will probably have a share of about 40% to 45%. That total volume should increase over time, primarily on the back of the new pipeline that we are building, the Vaca Muerta Norte pipeline, that will connect the core hub with Puesto Hernandez. That should allow total pump volumes to increase.

And at the first stage, we believe that, that volume will probably be in the order of about 70,000 barrels a day or so before the end of this year. And hopefully, over time, that should continue to grow as we move along the following months until probably the end of 2024 to the total capacity that the Transandino pipeline has of about 110,000 barrels a day. So we believe that that's going to be a structural improvement and structural export potential, both for YPF and for other players in the Neuquina basin.

Given that, we so far continue to purchase about 20% of the total crude that we processed in our refineries. But clearly, as we continue to expect our oil production to increase in coming months and in coming years, as was also presented in our strategic outlook a few weeks ago in New York, we would expect total purchase volumes to decline over time, while at the same time, we increased our exports. And so over time, and as we said, probably in 5 years from now, we are expecting to reach a percentage of about 35% to 40% of our total production to target the export markets, while we reduce our net purchases to a level of about 5% to 10% of the total processing volumes. That -- as mentioned, just to be clear, that's over time within the next 5 years.

And moving to your second question, to prices. As was commented during the presentation, which so far, we managed to increase prices in several locations for the most part, once a month, we are trying to, at the minimum, keep track of the evolution of the currency and trying to maintain our prices in dollar terms, our net prices in dollar terms as stable as possible. So far, we have managed to achieve that. And as mentioned during the first quarter, the average of our dollar -- net dollar prices was just 3% below the average for the fourth quarter, even though international prices came down further than that.

And that continues to be the case so far. And for the following months, we expect to continue with that strategy of doing -- or moving or adjusting prices in a way to compensate for the evolution of the currency to the largest possible extent. Of course, being conscious of the global environment or the local environment in terms of macroeconomic reality and the inflationary pressures. So we will remain conscious of that, but still trying to adjust prices in accordance with the evolution of the currency and of course, maintaining a healthy relationship with international prices as well.

Your next question comes from the line of Carlos Moraes with Morgan Stanley.

I have 2 questions. The first question is about funding. Can you talk about your funding requirements and strategy for the 2023 and 2024? The second question is about FX devaluation. How is YPF preparing the company in the event of a sharp currency devaluation? How do you see fuel prices evolving in that scenario to ensure margins remain healthy?

Thank you, Carlos, for your questions. In terms of funding, as commented during the presentation, we have started the year on the right footage. We have already, in the first 4 months of the year, have already raised over $1 billion, tapping mostly the local capital markets and relationship banks, as expected and as commented as it was our funding plan for the year. With that -- with those exercises, we have already reached a net funding of about $500 million. And we expect to continue with a similar strategy for the remainder of the year. We clearly have tackled most -- the most relevant international amortizations that we had during the year. So we only have left a smaller amount of international cross-border amortizations for the following months.

And so in that regard, we expect to continue to mostly focus our exercises in the local market, where clearly, we see very competitive financing costs. As commented also, both in the January and the April local bonds that we issued, we achieved very interesting funding costs and also increasing our trade lines. On top of that, there is also a possibility -- a high probability of enlarging -- refinancing and enlarging the CAF [lev] A/B loan that was secured last year. We are working on potentially extending that loan, both in terms of tenor and in terms of size. And that we expect to be -- to finalize negotiations and documentation for that in coming weeks.

So all in all, clearly, mostly focused on the local market and in trade lines, but then also looking into other instruments, such as this enlargement of this A/B loan potentially.

For the next year, clearly, still too early to say, but most likely, we believe that there will still be room for us to continue to tap on these 2 main sources. And of course, we will keep an eye on the international markets as well. Depending on how our bonds -- our international bonds perform, we might definitely consider tapping the international markets at some point.

And in terms of the potential impact of significant FX devaluation, clearly, it's difficult to know whether that's going to be -- that's going to happen and when. But of course, we have our sensitivity analysis. What I can comment on that is that although the -- a steep devaluation of the currency will definitely erode our revenues as it impacts a large portion of our revenues, which are related to pump prices, roughly speaking, in the order of 55% to 60% of our total revenues come from the sale of local -- of fuels in the local market, which are priced in pesos.

But it's also fair to know that a large portion of our costs, both CapEx and OpEx is also denominated in pesos and should also, in that case, benefit from a potential devaluation of the currency. So all in all, we would say that the net -- there is a net impact, negative impact that the devaluation will have on the differential between revenues and costs. But that will also depend on our ability to pass that potential devaluation through to pump prices in a rapid way.

So we would expect -- and as commented on the pricing strategy, we would expect to be able to do that in an efficient and rapid way. But that, of course, will depend on the general environment that will prevail at the time. And of course, depending on our ability to actually do so that will result in the net impact that we will end up seeing in our cash flow generation.

(Operator Instructions) Your next question is from the line of Paula La Greca with TPCG.

I have a couple of questions. First, I would like to know how our (inaudible) doing? Could you tell us how much money they need to collect? And then as follow-up on this one is, if collections continue to deteriorate based on our earnings calls of peers and, let's say, to 115 days, how is it going to impact the plans in crude production?

Paula, thanks for your questions. Clearly, we have seen some deterioration in collections, particularly in -- related to the Plan Gas, where we have seen some further delays in collection. But from a net -- or from a nominal perspective, this amounts on the lower seasonality of the Plan Gas invoicing. So in terms of actual working capital during the first quarter, we had a positive effect because we've been collecting on high seasonal invoices and -- while the delays took place on lower seasonality invoicing.

So from a net working capital perspective, it was a positive variation in the first quarter. Down the road, we definitely expect, and we are doing our best to try to collect and to get the normalization of the collection on the Plan Gas.

In terms of CAMMESA's delays, we are not seeing any major impact there. But all in all, and as you probably recall, our focus is on crude oil production, which clearly has no relationship whatsoever to this collection timeframes because, of course, we monetize that through pump prices and there, we see no delays in collections.

And then also now, as we are going to move forward with a portion of our production being exported, also, it's completely separated from the realities of what is more a natural gas issue related to both CAMMESA and the government payment on the Plan Gas program.

So I would say that all in all, of course, it could potentially have an effect in future working capital balances. It does not affect our production growth plans or our investment plans as it has less of an impact on YPF than it might have in other companies that have a larger proportion of gas in their businesses or in their plans.

So I would say that so far, we are not seeing or expecting any relevant impact in our activities or in our investment decisions, and we continue to focus mostly on -- and assigning most of our capital investment to our crude oil opportunities.

Understood. And then I have another question that is regarding the contract with ENAP. If you could tell us what was the price agreed of crude oil and -- or in terms of revenue, how much is it going to represent in the second quarter?

Yes. Well, in terms of the commercial agreement, it's a formula that basically relates to export parity prices at Puerto Rosales. And on top of that, it adds some logistics premium, basically taking into consideration the -- to share the benefit of the improved logistics that both sites will have, both the suppliers, not just YPF, but the other producers as well versus ENAP that is substituting imported crude from sea imports to this inland imports through pipe. So basically, it's going to be an export parity plus pricing on this commercial agreement, at least for this initial agreement that is for the first 2 months.

In terms of impact for revenues during the second quarter, it's going to be very marginal because, as mentioned before, we are only going to start pumping in the first days of June. So it's going to be only less than a month of exports that will actually be recorded in the second quarter.

And even in the third quarter, it's going to be limited to this smaller amount -- or the smaller volume until the Vaca Muerta Norte pipeline is up and running, which is expected at some point in late September or early October. So we should start seeing the full benefit of this new exports into Chile by the fourth quarter of this year, where it should start representing around 10% of our total production.

Your next question comes from the line of Luiz Carvalho with UBS.

I have basically 2 here. The first one is about infrastructure bottlenecks. I mean there has been some discussions about the construction of pipelines and of course, how this will tie in terms of the production growth over the next couple of years. So you may, I don't know, give a bit more color in terms of what are the main challenges that you're seeing in terms of potentially, I don't know, suppliers or, I don't know, licenses and so on, will be great.

The second question, in the past, I mean, Argentina, announced some specific rules for the export on agri or soft commodities in terms of, I would say, accessing the FX rate, for example, right? And the company, YPF, has -- potentially becoming a larger exporter of oil. So it would be great to hear your views on the conditions that the company is seeing in terms of the rules to follow to match additional levels of oil exports and potential revenue dollars from now on?

Luiz, in terms of bottlenecks or pipeline expansion, again, as commented, we are seeing very good progress, and we are very comfortable with the progress that we are achieving directly and indirectly, right? Because some of these projects are being executed directly by YPF and some of them by third parties like our participating companies Oldelval and OTE.

In both those cases, we are making good progress. As expected, the Transandino pipeline should be up and running and in operations now in late May, early June. So that's a key milestone. We are making good progress on the construction of the Vaca Muerta Norte pipeline, which we are still seeing or expecting COD in early fourth quarter or late September, early October. So we are making good progress there.

Clearly, access to -- or the flow of imports is somewhat more troublesome these days, of course. But at the end of the day, the relevancy of these projects, finally get things moving and we are not expecting any major impact from this particular situation in the finalization of these projects.

And then in terms of Oldelval and OTE, again, we follow that from our side. But clearly, those projects are being run by those companies. And we are seeing good progress there, both in terms of the actual construction or the actual works that are being performed as well as the financing. As we mentioned, both companies tap the local market, and they are making good progress in terms of their financing as well. So at this point, we feel comfortable. We believe that the potential restrictions or noises related to imports, we so far don't expect them to have a significant impact in the evolution of these projects.

And then finally, on the Vaca Muerta South or Vaca Muerta Sur project, we are making good progress on the engineering. That's a project that should help or contribute to the debottlenecking of Vaca Muerta from '26 onwards. And so clearly, we do have time. But of course, that doesn't mean that we don't need to continue to making good progress and keeping a close eye to that project in the current -- right now, not just in the future.

So in that case, we are also making good progress. We are finalizing the environmental studies, and we expect the public hearings for environmental approvals to take place in coming months. So that should be a key milestone for that project that goes into a new territory and involves potentially a new port. So that will be a milestone to follow or to watch. And once that is done, then the rest of the project will be mostly related to construction. So in that -- on those fronts, we feel comfortable with the progresses that we are making.

And in terms of export regulations, well, the Secretary of Energy has already allowed for firm exports into Chile to -- clearly to make a -- or to take advantage of the Transandino pipeline. And then in terms of currency regulations, we, at this point, don't expect any specific regulation related to crude exports, but rather to be affected or to be within the current regulations that require exporters to bring dollars into the country and to sell those at the official FX. Although, and as you know, there is another regulation that was enacted last year, not yet fully implemented that provides for a specific benefit or access to the official FX to oil and gas companies for several uses related to our incremental production compared to our base year in 2021.

So that should provide for a specific benefit, not just related to exports, but mostly related to increased production. That should be a great tool to access and to manage FX access. And -- but yes, we are still waiting for the full implementation of that regulation, which is still lacking.

Your next question is from the line of Marcelo Gumiero with Credit Suisse.

I have 2 from my end. The first one is on costs. So we saw lifting costs almost flat sequentially, but I mean, coming from an increase compared to the last year. I would like to know, I mean, how do you see lifting cost evolution looking forward into 2023 or 2024? I mean as we advance and have more conventional production in the mix, should we expect lifting costs to reduce?

And the second question is on fuel imports. So we saw an increase of imports despite an increased refinery utilization rate. You explained that you were like building up inventories during the quarter. I mean I just wanted to understand what should we expect from that side going forward? I mean should imports go down? Or should YPF keep the current level?

Marcelo, thank you for your questions. In terms of costs, we are working hard in trying to contain cost pressures. And clearly, we've been mostly successful during the first quarter. However, we continue to see cost pressures affecting our overall performance. But as you have said, the higher proportion of shale or unconventional within our total portfolio, should allow us to, over time, decline the average cost -- the average lifting cost for our total Upstream operations.

All in all, even within both sides -- well, clearly on conventional, we've been -- we have seen our costs in previous quarters increasing, and that was mostly related to the decline that we were experiencing in production. As far as we managed to maintain production stable within crude -- conventional crude and mitigate to some extent, the decline in conventional natural gas, we should also see or be able to contain the increase in lifting costs there to a large extent. And so while we do that and we increased the share of total shale within our portfolio, then as you have said, even though we might continue to see some cost pressures, we would expect the average lifting to trend downwards over time.

And in terms of fuel imports, clearly, as you mentioned, the main reason for having -- continue to have a relatively large percentage of imports related to our total sales was mostly related to the buildup in inventories. We are now at average historical inventory levels. So we got to a point where we are comfortable with inventory levels. But for the following quarters, particularly the third quarter, we might also see import levels relatively high compared to historical averages mostly because of program maintenance on our refineries. So I would say on average for the year, we should be close to somewhat below the current level of imports, but with some potential reduction in the second quarter, but then probably some increase again in the third quarter.

But that's -- that will also depend on the overall level of demand and whether we -- beyond the program maintenance, how we continue to perform on our processing capacity, which as commented, will reach a historical high in the first quarter, and we will do our best outside or besides this program maintenance to maintain processing levels to the maximum possible extent.

Your next question is from the line of Ezequiel Fernández with Balanz.

This is Ezequiel Fernández from Balanz. I have 3 questions. I would like to run them one by one, if you do not mind. The first one is related to the Vaca Muerta South project that you mentioned. If you could provide us a little bit more details about potential pipe capacities or upgrades, if this is going to be geared toward Suezmax or VLLC -- VLCC exports, anything that might be worth mentioning.

Well, let me address it with information that we can comment at this point. This is a project that is still on a design stage, although we are moving fast with it. As we commented, we are well advanced with the engineering design process. And so far, we expect this project to be a project that could be expanded over time in a way to address the growing need for evacuating Vaca Muerta's production from '26 onwards.

And so far, we are looking at a project that could go from a minimum flow of about 30,000 cubic meters a day to be expanded to a total of about 120,000 barrels a day once it's fully expanded -- sorry, meters -- cubic meters per day. So from an initial of 30,000 cubic meters a day to a total of 120,000 cubic meters a day once it's fully expanded.

And that will be an efficient way from a capital perspective to handle that and move along with that project while we and the rest of the industry, will likely continue to see the expansion of Vaca Muerta's operations from '26 onwards.

In terms of the design of that project, we are seeing the pipeline that will, for the most part, go parallel to the existing Oldelval pipeline, but then connect to a new port further south. Location is still being fine-tuned but most likely, and as commented before, is going to be new ports in an area in the province of Rio Negro, where we can exploit or we can take advantage of natural deeper waters that should allow for the entrance of VLCCs and hence, making exports more efficient. So that's the general idea of that project.

That's great. Now -- sorry, but I would like to go into another question -- another project that you might not be able to fully comment on. But regarding the offshore initiatives in either the Austral basin or off the coast of the province of Buenos Aires, what else can you share about this initial maybe testing wells, and if they're going to be geared towards gas or oil? And anything on economics would be useful, too.

Yes. Economics is definitely still too early to comment. What we are seeing there is more clearly on the project outside of the coast of Buenos Aires of Mar del Plata, that's a key project that we are targeting to drill the first deepwater exploratory well in -- ever in Argentina. That's a project that is in the block CAN 100 and where we are partners with Equinor and Shell, and that's a project that is being -- or a block that is being operated by our partner, Equinor.

So as mentioned, we are expecting and working towards being able to drill or to start drilling before the end of the year or at the latest, early next year. And we -- well, we have high expectations for such a project, but there's still much work to be done to be able to comment on all the potential that we expect there.

Even though as we have already disclosed or mentioned, we are targeting resources in the order of 7 billion barrels of oil. So clearly, the focus there is oil. And so the expectations are very high for that project.

And in terms of the Austral basin, we are looking into some opportunities there to enter into some existing concessions that some other players have. We are looking into that and in that case, mostly for gas. But again, there, it's an analysis that we are performing. It's a little too early to comment.

Okay. Great. And I don't know if you have anything to add on Petronas and the LNG project?

Well, not much to add. We continue to work together with them in performing the -- both the technical and economic analysis to get us comfortable with a final investment decision. As previously commented, we are still away from that decision. There's still much work that has to be done. And at best, we would expect to have -- to enter into an FID not before the end of next year. So that's, as mentioned, still much work to be done there to be able to move on with the actual development of the project.

There are no further questions at this time. I will now turn the call back over to management for closing remarks.

Well, thank you very much, everyone, for joining this call and for your continued support. And we definitely remain open for any further questions that you may have, and have a great day.

Ladies and gentlemen, thank you for participating. This concludes today's conference call. You may now disconnect.