YPF SA (YPF) 2020 Q3 法說會逐字稿

Good morning, and thank you for standing by, and welcome to the YPF Third Quarter 2020 Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your host, Santiago Wesenack, Investor Relations Manager. Please go ahead.

Good morning, ladies and gentlemen. This is Santiago Wesenack, YPF's IR Manager. Thank you for joining us today in our third quarter 2020 earnings call. I hope you are all safe.

The 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 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 reducing the calculations to reach our main financial figures in dollar terms. 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 Sergio.

Thank you, Santiago. Ladies and gentlemen, good morning. Thank you for joining us on the call today. Let me start by saying that after the severe economic slowdown that took place after the eruption of COVID-19, the worst now seems to be behind us, and the performance of the company has started to show signs of recovery. We are far from being back to normal levels, but the disruptions that critically affected our activity and prices have started to subside. First and foremost, safety of our people is our top priority.

As we have gradually started to resume activity, the index that measures the frequency of accidents per million hours at work stood at 0.19 during the first 9 months of 2020, representing an improvement of over 50% when compared to the 2019 average of 0.43.

Our COVID Committee continue overseeing that critical services and operations are maintained with the utmost care for our employees, suppliers and customers. Over 90% of our people, whose positions do not require face-to-face interactions, are still working remotely. Our success in adapting to the realities imposed by the pandemic was clearly showcased during the major maintenance works done at our La Plata refinery through September and October.

A total of less than 900 people who work on the task, way below the pre-pandemic estimate of 1,300, thanks to a fully revised strategy, including the special night shifts, bubble type working groups and introduction of innovative technological solutions that play a central role in optimizing resources and assuring health conditions.

And now that it has concluded, I am proud to say that we successfully achieved this work in a safety environment and at a lower overall cost when compared to original estimates. Along the same line, our subsidiary, YPF Luz, resumed full activity at their construction sites and managed to reach COD on several projects between September and October, for an aggregate of 411 megawatts of both thermal and renewable installed capacity.

When including these projects now in commercial operation, YPF Luz accounts for total installed capacity of over 2.2 gigawatts, with an additional 230 megawatts underway.

Moving into our economic performance for the quarter. Since the worst monthly record of April, when gasoline and diesel volumes contracted by 69% and 34%, respectively, on a year-over-year basis, we have seen a gradual recovery in volumes as the lockdown has been flexibilized. Fuel sales had a positive sequential evolution in the third quarter and further out in October, we have seen demand recovery continuing with gasoline contraction being close to 30% and diesel around 18% when compared to the previous year.

Taking into consideration the positive demand trend, coupled with the agreement reached with unions and contractors, we were able to gradually start resuming upstream activity, which allowed for production stabilization on a sequential basis.

During the third quarter, we rigged up 37 rigs, including drilling, oil cover and pulling and reopened oil shale wells. As a whole, production was flat quarter-over-quarter, which sailed back at pre-COVID levels, offsetting the contraction in conventional production. As I've just mentioned, the resumption in activity was supported by initial results of our cost-cutting effort.

We have already reviewed 65% of all vendor contracts and revisited a good portion of our internal operating processes, achieving important savings in key activities. For instance, total cost for shale well is estimated to be 15% lower on aggregate, excluding potential additional savings for contracts still under review and further efficiency gains that we are working on.

Another example can be found in our pulling intervention in conventional fields, where we have achieved significant reductions in the number of hours per intervention in addition to tariff renegotiations, bringing pulling total costs down by over 30%. Additionally, the voluntary retirement program executed in the third quarter, reaching all non unionized workers, resulted in a 12% headcount reduction in that labor segment, representing savings around $50 million per year.

During the quarter, we have also pursued periodic price increases at the pump, raising by a cumulative 12% in Argentine pesos as of today. Our profitability improved sequentially with adjusted EBITDA totaling $392 million during the quarter, a significant recovery compared to the $28 million of the previous quarter. Despite this partial recovery in profitability, we have continued prioritizing financial prudency.

As a result, although higher compared to the previous quarter, CapEx remained at low levels and net debt decreased further. We have also taken an active liquidity management approach to mitigate currency exposure, while minimizing cost of carry.

Looking forward, we estimate full year EBITDA to end up around $1.5 billion with a similar figure for CapEx. As production is expected to contract in the fourth quarter due to preventive shutdown of wells surrounding fracking activity and program pipeline maintenance, average production for the entire year continues to be estimated at minus 10% in comparison to 2019.

In terms of capital allocation and portfolio optimization, we continue having active conversations with strategic partners about potential farmings in Vaca Muerta, while also analyzing some potential divestment opportunities in the mature conventional blocks.

Finally, as we devise our plan going into 2021, we anticipate a more ambitious CapEx program to turn around the production decline trend seen during the last 5 years. This will likely result in a need for net new funding that should stabilize and subsequently deliver in following years, as cash flow generation capacity recovers on higher production and normalized demand environment.

Furthermore, the new plan gas, which was announced a few weeks ago by President Fernandez, should be formalized shortly and is expected to provide stability and incentives to develop our vast natural gas reserves.

In summary, while the pandemic triggered unprecedented negative conditions, we did not stand still and have been working very hard to reemerge much stronger with a leaner and more efficient operation and expect to show the full-scale benefits of these initiatives in the short term.

Once again, thank you, everyone, for joining us today. And now I leave the floor to Alejandro.

Thank you, Sergio, and good morning to you all. With regards to this quarter's main financial figures, as mentioned by Sergio, our operating margins experienced a sequential recovery as the worst effects of the preventive lockdown measures seem to be behind us. Along this line, our revenues increased by 20% from the previous quarter, primarily as a result of a 27% increase in diesel and gasoline volumes dispatched.

On the other hand, our efficiency program has started delivering first encouraging signs as total operating cost remained relatively unchanged, increasing by only 1% from the previous quarter, particularly benefiting from a 19% reduction in OpEx. While purchases of crude from third-parties, biofuels and other purchases increased on higher volumes.

From a different perspective, when compared to the same quarter last year, total operating costs were down 20% and an even larger 26% when excluding nonrecurring items such as the cost of the voluntary retirement program and upstream standby costs.

Now combining the evolution of both revenues and costs, adjusted EBITDA improved significantly in Q3 versus the previous quarter, as I will go through in more detail in a few moments. Also, as part of our cost-cutting plan and our clear prioritization of financial sustainability, we continue administering CapEx activity and further reducing our net financial debt. Total investments during the quarter reached $257 million, representing a 70% year-over-year contraction, but increasing 59% from the second quarter on the back of a gradual resumption in activity. The decision to do this was only taken once we have managed to verify some initial progress from our efficiency program, which also led us to move along carrying a major maintenance at the La Plata refinery that had been postponed back in April.

Last but not least, as a result of the increased cash flow generated in our operations, not applied to CapEx, we continued reducing net indebtedness. Consequently, by the end of September, our net debt stood at $7.2 billion, resulting in a reduction of over $500 million when compared to September of last year.

Going into a breakdown of the evolution of adjusted EBITDA during the quarter, which totaled $392 million, I should first make a reminder that this figure differs from reported EBITDA due to some adjustments that we understand better reflect our actual operations, primarily related to reclassification of leasing costs, otherwise recognized as assets and liabilities. As a comparison, reported EBITDA was slightly higher and stood at $472 million for the quarter.

Now I will go briefly through the main drivers of each segment. Upstream showed the highest recovery from the previous quarter. Its adjusted EBITDA increased by 130% quarter-over-quarter, reaching $358 million, although still down 44% versus the same period of last year. This segment benefited from higher transfer and realization prices for both crude oil and natural gas, stable production and lower lifting costs. All these factors largely outpacing higher royalties.

In contrast, adjusted EBITDA for our downstream segment declined by 68% sequentially, contributing with only $40 million in the quarter. The recovery in demand, particularly in gasoline and diesel, was not enough to offset the lower margins resulting from higher transfer prices of crude and lower net prices at the pump measured in dollars, which, despite the 2 increases of August and September, averaged a minus 4% when compared to the previous quarter.

In the case of gas and power, adjusted EBITDA reached $20 million compared to a $128 million loss in the previous quarter. It is worth highlighting that the figure for Q2 included a noncash accounting provision of about $120 million related to the potential enrollment of Decree 1053. Even excluding that extraordinary item, this quarter also showed an improvement compared to the previous one, driven by higher natural gas prices due to seasonality.

On the Corporate and Elimination segment, the negative contribution of $26 million for the quarter compares very favorably with a negative $123 million in the previous quarter. This evolution primarily results from a positive adjustment in the value of inventories of crude and products in Q3 in comparison with a large negative charge in the previous quarter.

Let me now go a little deeper into our upstream business. In the third quarter, we were able to stabilized production sequentially as we gradually started to resume well activity. Crude oil production averaged 202,000 barrels of oil per day, with shale production increasing 14% compared to the previous quarter and representing 20% of total oil production. The recovery in shale, which offsets the decline in conventional fields, was mainly driven by Loma Campana as we finalized the reopening of all the wells that were temporarily closed in April, taking output for the quarter back at pre-COVID levels.

On the natural gas front, production averaged 35 million cubic meters per day, almost unchanged sequentially as a slight growth in conventional and tight, which increased 1%, compensated the contraction in shale.

It is worth noting that during the quarter, our crude oil realization price averaged $40 per barrel, up 39% sequentially, while on the natural gas side, our selling price averaged $2.7 per million BTU, slightly up from the $2.5 per million BTU in Q2.

Moving in to the right side of the slide. As mentioned before, during the third quarter, we have gradually started to resume activity after having gone into a full stop at some point in the second quarter. By the end of the quarter, we have mobilized over 35 rigs, most of them in September, including 3 drilling rigs in conventional fields in the South region, 1 of them in August and the other 2 in September, and another 3 drilling rigs in Vaca Muerta by the end of the quarter.

With regards to our backlog of drilled but uncompleted oil and gas shale wells, we have started to fracture in late September as we mobilized 1 frac set, while 1 more should come online between now and the end of the year. This should allow us to have a total of about 25 of those wells fractured by the end of the year, all of which should be connected and fully operational by March of next year.

Let me now say that not only we are resuming activity, but we are doing so in a more efficient way. Taking examples from a couple of relevant performance indicators, such as average hours required per pulling intervention in conventionals and number of frac stages per day in shale, we can show very promising improvements. When compared to average parameters for 2019, pulling interventions are taking less than 80% of the time they used to require, while frac stages per day have improved to over 18 in October in comparison with an average of less than 5 in 2019.

Finally, our average lifting cost for the quarter stood at $7.6 per barrel of oil equivalent, down from 11.6% a year ago and 9.4% last quarter, with both conventional and nonconventional segments contributing to the decline. It is fair to note that the low levels reached in the quarter are exceptional as they are in part the result from limited pulling and workover activity. However, as we resume activity in a more efficient way, while lifting costs are expected to increase in coming quarters, primarily in the conventional segment, they should still come in well below the levels seen in 2019 as key well services are already showing total cost reductions between 15% and 30%, combining both operational efficiencies and lower tariffs.

Switching to our downstream business. In the third quarter, we have seen a significant recovery in volumes of our main products following some flexibilization of the strict lockdown. Volumes sold for gasoline and diesel, although still well below the level seen pre-COVID, increased by 41% and 22%, respectively, compared to the previous quarter. It is worth noting that diesel sales in the third quarter included large volumes sold to CAMMESA for deliveries to thermal generation plants in the months of July and August. Excluding this effect, diesel volumes in the quarter would have increased by a lower 10%.

Furthermore, our preliminary data for October is showing additional recovery with gasoline and diesel volumes expanding by 11% and 3%, respectively, compared to September, further reducing the decline compared to the same period of last year to 32% for gasoline and 19% for diesel.

Moving to the chart on the bottom left, we show the evolution of the average price of our fuels, measured in dollars against import parity. As international prices recovered from May onwards and the peso depreciated against the dollar, our net prices went below import parity for sometime until -- since August, we have managed to start with periodic increases at the pump. By this, we have so far accumulated a 12% increase in pesos, which permitted to stabilize our net prices in dollars and vis-à-vis import parity. However, it is worth noting that even after the cumulative increase since August, our net prices measured in dollars currently stand around 20% below the levels of last year.

In terms of capacity utilization at our refineries, it has improved significantly in line with the evolution of demand. Crude oil volumes processed averaged 232,000 barrels per day in the third quarter, 21% higher than the second quarter, resulting in an average capacity utilization rate of 73%, up from 60% in the previous quarter, but still down from an average of 90% during the third quarter of last year.

Within the quarter, capacity utilization fluctuated as we embarked on major maintenance works at our La Plata refinery in September. Thus, utilization averaged 80% in July and August, while it dropped to 60% in September. Excluding this effect, utilization for the quarter would have averaged an estimated 78%.

Finally, also worth mentioning as the utilization of our refineries recover in the third quarter, we increased crude oil purchases from third parties to an average of 11% of oil crude processed in comparison with the 6% of the previous quarter, an historical average of around 20%.

Turning to cash flow. Let me start by reiterating something that was already mentioned last quarter about the impact of Central Bank Communication #7030 on our liquidity position. The regulation established by that communication, which restricts corporates in Argentina from holding liquid assets abroad, if they want to continue being granted access to the official FX market, has led us to hold most of our liquidity locally. Therefore, the peso proportion of our cash and cash equivalents has increased to 61%, which compares to 22% a year ago. Given the situation and our decision to minimize FX exposure by hedging our peso liquidity with peso-denominated debt and local FX features, the cost of carrying our liquidity increased significantly, leading us to voluntarily reduce our liquidity position, although establishing a minimum level that is consistent with a prudent cash management strategy.

Along this line, financial discipline continues to be a key priority for us, particularly during these uncertain times. During the third quarter, cash generation from our operations reached a total of $666 million, after netting the effects of all noncash items that were deducted from EBITDA and including, among others, collections from legacy planned gas programs.

As we have already mentioned, during the quarter, we have started to gradually resume activity, but that process only took relevant speed in September. Consequently, cash used in connection with investment activities contracted by 33% on a sequential basis to $191 million as we usually pay vendors with a 1 month lag.

With regards to our financing activities, as we already commented during the last quarter's webcast, we successfully managed to refinance 58.7% of our 2021 bonds through a market friendly liability management exercise back in July. Based on these results, we retired all notes for a total of $587 million and issued new 2025 amortizing notes for $543 million, while also paid $90 million in cash, including the upfront incentive payment and accrued interest.

In addition to this, we have used excess cash to pay down other debt maturities during the quarter, including over $150 million of an international peso linked bond that matured in July, about $100 million of maturing local bonds and about $80 million of trade facilities.

In summary, by the end of the quarter, our consolidated cash position stood at $1 billion or about $300 million below the level at the end of June. At the same time, our gross debt shrunk even further, including the impact of FX devaluation, our peso-denominated debt, resulting in a reduction in net debt of $184 million during the quarter.

Moving into our debt profile. Although we have managed to successfully secure a significant short-term debt relief through the market friendly liability management exercise executed back in July, recent regulations introduced by the Central Bank through Communication 7106 have significantly affected investor's perception of our financial risk, which have translated into a negative performance of our international bonds in the secondary markets since mid-September. The new regulation establishes that corporates with debt denominated in foreign currency other than trade related, with maturities falling between October 15 of this year to March 31 of next year, shall be able to access the official FX market for up to 40% of the maturing amount as long as they present the refinancing plan for the remainder, 60%, with a minimum average life extension of 2 years. In this regard, the residual amount of $413 million of our March 2021 bond could be affected by this regulation.

Nevertheless, although our exchange was performed ahead of the enactment of the new regulation, we still believe there is a chance for such exercise to be considered as part of the refinancing effort. And in such case, we should be granted access to the official FX market for up to $400 million as long as we present the refinancing plan for the remainder, $13 million. However, as of today, we don't have a formal confirmation from the Central Bank about this, and therefore, cannot provide any certainties to the market.

Beyond this particular issue, while current market volatility requires a methodic, proactive and cautious approach, we believe that the rest of our short-term maturities are fairly manageable as they are mostly trade-related or in the hands of local financial institutions. We, therefore, do not foresee a major short-term refinancing risk as we should be able to roll over most of our maturing facilities, while also take advantage of the ample liquidity currently available in the local market, to raise the remainder of our financing needs.

Separately, it is fair to note that, although we have continued reducing our net indebtedness in the third quarter, our leverage ratio, calculated as the net debt balance over the last 12 months EBITDA, has jumped to 3.7x on the back of the contraction in EBITDA during the last 2 quarters. This takes on further relevance as it has surpassed the incurrence covenant on some of our financial instruments that limits our ability to take on new debt when the ratio is over 3x. However, we do not foresee a material negative impact as the covenant provides for specific exceptions for debt refinancing as well as a general basket for new debt, which should provide us ample maneuvering room for the foreseeable future.

Finally, before we move into the Q&A section, allow me to go into more detail on what Sergio mentioned during his opening remarks related to the outlook for the rest of the year and how we are preliminary thinking about next year.

Looking into the fourth quarter, although fuel volume sales are expected to improve further, and we shall continue with our efforts to secure more cost efficiencies, we estimate a sequential contraction in EBITDA as total oil and gas production is forecasted to go down in Q4 and as we recognize the extraordinary loss related to the early termination of the floating LNG contract with Exmar, which was already announced back in October.

To provide more clarity on the forecasted decline in production in Q4, it will be related to temporary shutdown of wells to avoid interference with fracking activity as well as planned pipeline maintenance and integrity works. This should result in full year 2020 oil and gas production about 10% below 2019 levels, as already anticipated last quarter.

Combining all these effects, we estimate full year 2020 adjusted EBITDA to end at around $1.5 billion, while total CapEx for the year will likely reach a similar amount.

Now moving into a preliminary guideline for next year. Profitability is expected to continue improving as oil and gas production reacts positively to the resumed activity of the fourth quarter of this year, fuel demand continues a gradual normalization path, net prices remain stable in dollar terms and cost efficiencies are consolidated. In that context and with the intention to start turning around the production decline trend over the last 5 years, we expect to continue ramping up activity, thus pushing total CapEx higher.

Just in the first quarter, we expect to connect close to 50 new shale wells, about 75% of them for crude oil production. This expanded CapEx plan could potentially result in total investments that go beyond our cash flow from operations, net of interest payments, that's probably requiring us to take on net new funding along the year.

With this, I reached the end of our presentation and now open the floor for your questions.

(Operator Instructions) Our first question comes from the line of Frank McGann with Bank of America.

Okay. Two questions, if I might. One is just in terms of the comments you made on the fourth quarter. I was wondering if you exclude the payments for the FLNG facility that you're letting go the contract. How you would see EBITDA perhaps, comparing to the third quarter? How much of any decline that might still be there would be related to weaker pricing in dollars versus the third quarter? And then secondly, perhaps if you could just provide a little bit of more guidance in terms of the growth you see in nonconventional in 2021 and '22? I know it's far away perhaps for now. But -- and just in terms of the activity you're seeing, with the joint venture partners and your -- like you said, your planned expansion and CapEx, how -- what type of growth could we expect to be able to achieve over the next several years?

Okay. Frank, thank you for your questions. Going into the first one for Q4. Even beyond the nonrecurring expense that we are going to register on the back of the cancellation or early termination of the floating LNG contracts, we do still expect a contraction in EBITDA, which is product -- the product of the combination of 2 effects. On the one hand, the lower production that we are estimating, as was mentioned during the presentation, we estimate lower oil and gas production on the back of -- well, first of all, closing down some shale wells to avoid interference with the resumed activity on fracking. And then also some pipeline maintenance mostly related to natural gas. So all in all, we see production going down. And at the same time, we do see operating expenses, also primarily on the upstream side, we see OpEx going up, particularly as we were ramping up activity, both on pulling and workover. So clearly, what we see is it's a temporary trend where production is going to go down and OpEx is going to go up. But that clearly is going to -- is expected to reverse as we move into the following year.

On the downstream side and just tackling briefly on your question on prices, we do see relatively stable prices. We expect to see relatively stable prices. And we don't see a deterioration in dollar terms there. So all in all, mostly the evolution of EBITDA in the next quarter, in the last quarter of this year, as I was mentioning, is going mostly related to lower production in the upstream side and higher OpEx in that same segment.

Into your second question, and clearly, as you are saying, it's hard to predict for the long term. But we do see an increase in activity in our non-conventionals, particularly in Vaca Muerta shale, mostly focused in oil in the long run, but clearly, on the back of what we are expecting to be announced shortly, the formalization of the planned gas. Also, in the first part of next year, and clearly, in the fourth quarter with some increased activity in natural gas as well. But all in all, we do see the proportion of non-conventionals going up in coming years, probably looking if -- for the third quarter, we were at 20% in the case of oil production, shale oil production, as a percentage of total oil production for the company, we do see that number going closer to 25% or a little bit more into 2021. And probably, as we look into the long run, 2022 or 2023, we do expect that to go closer to 45% or 50%. And that is a combination of clearly our higher activity in nonconventionals as well as the natural decline in conventions, which is going to -- which is expected to be only partially offset with CapEx activity in coming years.

Our next question comes from the line of Marcelo Gumiero with Crédit Suisse.

Congratulations on the results. Just a couple of questions here, guys. So continuing on the CapEx side. I mean, CapEx is at a very low level, we should expect that as you provide the guidance. And I mean, how we should see CapEx going forward? I mean, for 2021 or even in the long run? And how do you plan to match CapEx commitment to the debt amortization schedule for next year? And if I may, another question, regarding listing costs, I mean, you saw listing costs going down. You said there is no recurring, of course, but how much -- if you can provide, how much you offset those cost savings would be reversed if we go back to normality?

Thank you, Marcelo. On your first question, in terms of CapEx activity, clearly, we are coming from very low levels in the second quarter. And activity started to be resumed primarily by the end of August and then a little bit more in September. And as we move along, we are further improving or further increasing activity, both in conventional and in nonconventional.

Just as an example, and as was mentioned in the presentation, we (inaudible) about 35 towers during the third quarter. And we expect to continue -- we are actually continuing with that activity and expect to activate another roughly 30 equipments or rigs by the end of the year. So all in all, we will probably end up with a little bit over 80 rigs by December comparing to less than 20 before June.

So when comparing that to pre-COVID levels, clearly, we are still well below the roughly 120 rigs that we used to have before this crisis erupted. And we don't expect to go back to those levels anytime soon. And so probably, this is about 65% of activity, or rigs in operation is probably going to be here to stay.

Nevertheless, as we mentioned also during the presentation, we have increased efficiency very significantly, both examples that we put in the presentation or the times or the hours in operation per every intervention in conventions with pulling equipment, which has come down by about 20% from 2019 levels of fracking activity where stages per day have gone up very significantly to above 8 as we resumed activity -- fracking activity now in October versus the averages for 2019. So we, therefore, can be more efficient and more productive with less equipment, and that also means that every dollar in CapEx should be more -- should have more power.

So going forward, we do expect an increase in the volume of CapEx overall in 2021. That was also mentioned as the guideline for 2021, we do expect those CapEx levels to go higher. Of course that will have an impact in our financial abilities, and that's why we are thinking or we are revising a short-term plan where we might need to take on some extra net new funding to be able to accommodate that more aggressive CapEx plan for next year, but that will definitely be needed to revert the production trend decline that we have been seeing in the last few years and particularly during 2020 on the back of COVID.

And into your second question about -- second question about lifting, yes, as was mentioned in the presentation, the number for the third quarter is exceptionally low. It's a combination of still reduced activity when compared to normal levels, mostly in well service activity in terms of pulling and workover services. We do see that those numbers going up already in the fourth quarter, and we do expect the stabilization as we move along into 2021.

Just to give you an idea, the more normalized, excluding some exceptional provisions that were reversed in the third quarter, which exceptionally lowered the overall lifting number for that quarter, a more normalized or taking aside those provisions during the third quarter, we will be closer to $9 per barrel of oil equivalent in the third quarter. And that number should probably stabilize as we go forward, and we normalize total activities, that number should probably go up to a level around $10 per BOE.

Our next question comes from the line of Barbara Halberstadt with JPMorgan.

So I know you mentioned about the refinancing options for the bonds, and there's still not a lot of clarity on what's going to be the decision from the government. But if you could just explore a little bit more how the local capital market is currently, and if that would be an option for the company to address some of the short-term financing needs? And then my second question is on the cash position. Also, as you mentioned, there's been a transition from the balance between dollars in local currency and your cash balance. And we do see a slight increase from last quarter. So I just wanted to understand a little bit better what the dynamic to build up the cash in dollars? Currently, should we continue to expect this new mix of 60%, 70% in local currency and the rest in dollars? Or should we be looking at more of a 100% in local currency going forward?

And also if you could comment on what's the minimum cash balance for the company?

Sure. Thank you, Barbara. In terms of our refinancing abilities, yes, as was mentioned during the presentation, we still cannot predict what the final decision from the Central Bank will be in terms of granting access to the official FX market, although we do still expect that our refinancing effort back in July should be taken into consideration to be able to comply with our commitments without major problems.

But in terms of achieving or raising new funding, yes, we do see significant liquidity in the local market. And we have been absent from that market in this quarter, primarily given our decision to reduce our overall cash position, liquidity position and hence, we were a net -- with net repaid local bonds, about $100 million -- as was mentioned in the presentation, about $100 million in local bonds were we paid during the quarter. And as we look into next year, we have about -- including an amortization that we have in December, we have about $350 million that mature in the local market. So when considering that, we do believe that we should be able to go into that market for amounts that are larger than that. So we do expect the local market to be a net provider of financing into -- from now and into the end of next year, which should be -- and through that, we should be able to largely compensate the probably -- what's going to probably be an availability of significant new cross-border funding. So clearly, we will probably rely more significantly on local opportunities, and we do see the liquidity there to do that.

In the -- into your second question about the cash position, yes, the regulations from the Central Bank basically preclude corporates from accessing the local -- the official FX market to increasing dollar reserves or dollar cash position. So basically, the only authorization to access the market is to pay imports and to servicing debt, of course, with the restrictions that were mentioned before. So the dollar position is not increasing, but rather the dollar amounts that we still have are the ones that were coming from the dollars that we used to have abroad. That after the liability management exercise that was executed in July, we brought back into the country. So you have -- on the YPF level, aside from our subsidiaries, we do have all of our liquidity locally. A portion of that is in dollar-denominated government bonds. And so that is also included in the dollar proportion or dollar portion of our liquidity. So in the roughly 40% that was mentioned by September, it includes the cash dollar position at YPF and its subsidiaries as well as the cash -- sorry, the dollar position in government bonds, which we consider as relative -- as a liquid financial investment.

If we look into the numbers, as of today, and excluding those dollar-denominated bonds, we would roughly be on -- YPF, allow stand-alone basis, we would probably be on a 10% dollar portion of our liquidity. And on a consolidated basis, probably closer to 20%.

Perfect. And I'm sorry, if you can just like follow-up on what's the minimum cash level that the company feels comfortable with operating?

Sure. That is on YPF on a -- we perform our analysis on the YPF on a stand-alone basis without the subsidiaries. And in that front, and excluding also the dollar-denominated bonds that we hold, we are -- we set a number that is not clearly written in stone, but we feel comfortable with a level of around $700 million equivalent in liquid cash position as a general rule.

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

A few follow-up questions. On refinancing, you have quite a substantial trade financing line maturing now in the fourth quarter. Have you already been able to roll that over? So what can we expect on that specific line?

And I had to get back to CapEx. We lost a little bit of the reference of what a more normal CapEx level is for YPF? I understand you are making plans for $1.5 billion this year. But should we think that the normal level is closer to $2 billion or $3 billion? So any ranges you could provide this would be very helpful?

And a quick third one. The results on gas and power in the third quarter were quite strong. Should we expect that level of results to be sustained? Or should it also decline into the fourth quarter now?

Bruno, thank you for highlighting the changes in the press release. It's good that the market takes it positively. Going into your questions, in terms of the refinancing of the trade facilities for the rest of this year, so basically, November and December, we have about $300 million in trade facilities that come due. I would say that for the most part, I cannot say that all of them are agreed upon to be rolled over, but we are in the process of doing that. For the most part, we see banks very constructive. And for the most part, we don't see any major risk in rolling those facilities over.

And also, we do have some room in some other bank facilities, both for financial instruments as well as trade that we could tap on to in case that we need to use that to compensate for any bank that might not be ready to roll over by now. But as a general comment, I would say that for the most part, we see banks very constructive. And clearly, taking advantage that the Central bank regulation has not affected trade facilities, they are in no obligation. Although they don't feel the constraint or the obligation to roll over 100% of that or 60% of that as is the case for cross-border financial lines, but still, for the most part, we see banks willing to roll over practically all that is coming due in the next couple of months.

In terms of CapEx, I would say that the new normal should probably be somewhere in between, what you used to have in the old days, up until 2019, and what you've seen in 2020. Clearly, the number for 2020 is not enough. That's why we are basically saying that we need to have a more aggressive plan. But clearly, that doesn't mean that we are going to go back to the $3 billion level of the past or more, right?

Also it's interesting or important to highlight and to bear in mind that as we are managing and seeing some encouraging signs from the steps that we took to improve our cost, in general, we do see that our cost structure is going to be more efficient, not only in OpEx but primarily in CapEx.

As was mentioned in the presentation, for example, the well cost in shale has come down already by about 15%, and we are seeing also new signs that would allow us to reduce that even further, probably getting closer to 25% as we move along in 2021. So that means that basically, we are going to be much more efficient and effective in -- when putting new dollars into CapEx. And so we feel comfortable that even not going back to the levels of the past, the company should be able to revert the production decline that we have seen in the last few years.

And sorry, Bruno, was there a third question?

Yes, about the results of gas and power, which seem to be very strong in the third quarter. And I was wondering if that level of profitability is sustainable now into the fourth quarter?

Okay. Yes. Clearly, there is a big difference when compared to the previous quarter. As was explained during the previous quarter, the number in the second quarter was affected by a specific provision on potential enrollment of Decree 1053, which basically is the recovery of FX losses on sales to distribution companies back in 2018. But so excluding that item, our adjusted EBITDA for this quarter is in the order of $20 million. And that is basically on the back of when taking aside that nonrecurring effect of the second quarter that is mostly related to higher seasonal prices. So of course, that will depend on seasonality. But also as the new planned gas come online, this should also somehow help the margins on this segment. But nothing major, we expect to change or no material changes we expect in coming quarters in this particular segment.

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

I mean looking to the presentation and maybe I'm coming from a different understanding. But in light of this year's 1.5, CapEx, 1.5. You have a debt interest in dollars of 7.5%, which, I mean, according to our numbers, close to $400 million per quarter. And this quarter, you basically had a cash burn of something close to $300 million per quarter, with a cash position of $1 billion, right? And as you pointed out, the leverage is close to 4x, and production is dropping close to 10% over the past years, right? So I do see some, I don't know, liquidity issues, potentially. I don't know, in the, let's say, the next 1 year, 1.5 years, if the oil price do not rebound, right? So -- and in the last slide, you mentioned about a potential, I would say, incremental CapEx or incremental net debt in order to cope with a bit more aggressive CapEx, right?

So just trying to understand how this scenario would consolidate with, let's say, with everything that you pointed out in, say, in the presentation in terms of the guidance for this year and potentially next year which, in my understanding, would not be too much different, right?

And the second question is that, I mean, I have been pointed this question in previously conference calls, would it be the time to be more aggressive on divestments instead of CapEx? I mean what the company can do in order actually to reduce the leverage and potentially even reduce EBITDA to the CapEx needs over the next couple of years? So that will be the second question.

And last question is about -- in the case that we see an oil price rebound, that, of course, would help, let's say, the Upstream business. But over the past couple of years, we saw prices being frozen in the in the, let's say, the Downstream. So what is your take if the oil price rebound, how we're going to be able to actually to follow the international parity in the Downstream business?

Luiz, thank you for your questions. On the first one, clearly, it's a delicate balance to move along with in -- as we move along in the coming months and years to address, on the one hand, the high leverage that we currently have. And with the more aggressive CapEx program that we need to put at work to revert the production decline. And that's why the main objective that we set ourselves on is the cost reduction and efficiency, because that's going to be the enabler, the lever that we have to trigger to be able to do this.

And so far, as was mentioned before, we are seeing some first encouraging signs. We have managed to reduce costs significantly in several fronts, as I mentioned before, well cost for shale, which already -- is down already by 15% and probably getting closer to minus 25% next year. But also pulling activity that when we combine efficiencies with tariff reductions, we had over 30% in terms of cost efficiency. And the same is happening in drilling and workover, for example.

So all in all, probably we are not -- it's going to be very hard for us to get to the 30% company-wide cost reduction that we set up as a target. But we definitely are doing and putting all our efforts towards that objective. And hopefully and probably, we will end up at least in the range of 20% or more in terms of cost reduction. So -- and that is both for OpEx and CapEx. So that should be the main enabler. We are not betting on higher prices to take us out of this situation. We are betting on efficiencies to do that job. And that's why we believe that in -- during 2021, of course, we will depend on availability of financing, and we will need to explain probably in even more detail these efficiencies to be able to get -- or to be joined by you guys by the market, in terms of providing the financing that we will need that will probably keep our leverage high at least for the next year. And as we manage to ramp up activity and production even with current prices, but as we are successful in our efficiencies, which provide us with, for example, breakevens in shale, which are well below current market prices. So we do expect that, as we combine all those efforts, by 2022, we should be able to once again reduce leverage and probably try to be closer or even below 3x. So that's our long-term trajectory expectation, I would say.

In terms of your second question of divestments, of course, and I will let Sergio talk a little bit about that.

Thank you, Alejandro, and thank you, Luiz, also for the question. I'm going to take the question about the divestments. As we commented on the second quarter results webcast, we are focused on our core oil and gas activities and in optimizing our portfolio. And in that regard, and taking into consideration current financial restrictions that our company has, cash generation through divestitures of non-core assets could provide us additional capital to permit a more rapid deployment of resources into oil and gas. We are maintaining an open dialogue with key international players for the possibility of entering into new farming agreements in Vaca Muerta. And we are also analyzing a group of mature conventional areas of both oil and gas that might be subject to potential disinvestment should we conclude that they could be operated more efficiently by a more flexible and focused niche operator, permitting us to allocate our resources to those assets where we can create the highest value for our stakeholders.

Also worth mentioning, YPF Board of Directors has approved recently sold a nonoperative office building for about $30 million. And along this line, we will continue analyzing our portfolio of nonoperating or nonstrategic assets and will likely move forward with the monetization should potential deal valuations result reasonable. And this is with respect to divestments.

Yes. So -- and thank you, Sergio and Luiz, on your third question, in terms of a potential rebound in oil prices. As was mentioned before, we are not putting or betting our future on that. Clearly, no one knows, and there is a complete lack of visibility of how the world and our sector, in particular, globally, will evolve. However, to your question about what happens to pump prices if oil rebounds? Of course, that will depend on how fragile or strong our macroeconomic viables will be. Hopefully, and as we have shown recently, we managed to align our prices to import parity. And -- but mostly, we are focused on at least maintaining current prices in dollar terms. So what happens if oil rebounds? We will see. Hopefully, we will be able to keep up aligning ourselves to import parity, but we cannot assure you that, that's actually going to be the case.

Okay. Just if I may come back to the first answer. So you saying that by mid-2022 year, the net debt-to-EBITDA leverage will be below 3x? But that also considers I mean a certain type of, I don't know, assumptions in terms of the oil price and production and so on. And I believe that liquidity issues might be faced, I mean, before that. Is there any discussion at the Board or within the management about a capital increase or something like this at this moment?

Tackling right, the last part of the question, the answer would be, no. Remember that this company is 51% owned by the Argentine government. And in that way, so far, we are not seeing the possibility of raising capital in -- through the market. And of course, the way for the government itself to increase capital in the company, it's a complicated, of course, a complicated solution.

So what I would say is that liquidity issues will probably need to be addressed by, first of all, performing or managing correctly our financial liabilities and our liquidity. And again, hopefully, not the case, if worse comes to reality, clearly, adjusting CapEx activity, which is not the best alternative because that has a long-term impact in our production. But once again, we don't want to bet our future on prices. And that's why all our efforts are putting into efficiencies. And we believe that through that, we can be much more efficient in reverting the production decline with much less CapEx than this company used to need up until last year. So that's basically what we can comment for now.

Our next question comes from the line of Anne Milne with Bank of America.

A few questions. One, I just wanted to follow-up on the -- on some pricing questions. If there were to be -- so both on upstream and downstream. On upstream, we know you're trying to keep import parity. If prices, though, were to decline again, would there be a possibility of reimplementing the Barril Criollo that went out, I guess, in August, when prices were about $45? And at what point would you talk to the government about that?

And then if inflation were to be higher-than-expected next year, how -- what is sort of the process for sitting down and negotiating or discussing price increases on the downstream side so that you can maintain import parity and not lose your value? That was the question on pricing.

Second, just wanted to know for 2020, what are your level of exports? And can you use any of those funds for helping to repay debt if you're repaid offshore?

And then my third question, it's one that you discussed several times. You have -- you're going to perhaps increase debt next year, yet you're already above your incurrence level covenants. Do you have baskets that allow you to increase your indebtedness next year to meet higher CapEx levels?

Thank you, Anne. On your first question about pricing, clearly, the Barril Criollo question is very difficult to answer. Of course, that's a regulatory decision, primarily needed or asked for previously by peer upstreamers and the provinces, of course, because royalties depend much on crude prices or local crude prices.

Clearly, for a company like ourselves, which we are practically fully integrated with minor purchases of crude from third-parties, in regular times, clearly, that went down in the second quarter to practically 0 and has increased to an average of 10% in the second -- third quarter. But for us, it's more the door-to-door pricing than the specific pricing of crude oil that affects our financials and our economic reality.

So we would not be the company most affected by Barril Criollo. And to be honest, it's hard to say whether if prices go down significantly from current levels, which clearly they have recovered significantly in the last 2 days to closer to the $45 per barrel that where Barril Criollo was dismantled back at the end of August. But if prices go back to lower levels, as we've seen in recent days, of course, there have been some rumors and some discussions as far as we understand, but nothing has really materialized. So it's hard to say whether -- if prices move significantly lower, whether that it's going to be reimplemented or not.

But again, as I said before, it's not something that affects our businesses that significantly because if anything, it changes the allocation between one segment and the other, between upstream and downstream, but the overall impact for our company is limited.

In terms of the adjustments in downstream or in pump prices, that is clearly related to the answer that I provided to the previous question. Basically, it's all going to depend on how the macroeconomic realities of Argentina evolve. As you probably understand, pump prices are not regulated. So it's not that you need to negotiate those. Of course, we do -- we are very, very realistic about macroeconomic realities and the impact that our fuel prices at the pump have on inflation, particularly. So of course, when considering adjustments, we look both on the impact that it's going to have on demand as well as the overall impact on inflation figures for the country.

So at the end of the day, it's being realistic and also being conservative in terms of understanding that adjustments of the pump have also a negative impact on demand. So at the end of the day, it's not a negotiation. But of course, we do have a very realistic approach on that front.

Going into your exports question, average numbers for exports in the past in the last few years were up about $1.5 billion. This year, it's probably going to be a little bit lower than that, closer to $1.1 billion or $1.2 billion, affected mostly by lower prices for some of our products, which are correlated to oil prices as well as collapse in the exports of shed fuel due to the -- clearly, collapsing the activity of the aviation sector worldwide.

So as we move forward, we would expect our export levels to go back to more average levels around the $1.5 billion or so. We are also putting a lot of focus into the business related to the agri sector. So we do expect to potentially have more exports of soybean flowers and oils also in coming years as we put a more commercial -- a more aggressive approach on that commercial side. But again, this is clearly something that will depend on how the realities of the market evolve.

In terms of being able to use those dollars to pay debt, that is only possible when you structure the debt as trade finance, of course, as a prefinancing of exports or as new Central Bank regulations permit. Once again, if you structure a new deal where you establish that, you will use those future export flows to repay the new debt. To do that, you have to bring the dollars that you raise through the new financing into the official FX market to then be able to use those flows to repay interest or principal on those on those instruments.

So on previously issued instruments that were not export-related, you cannot use future export flows to pay that. As you know that Central Bank regulations create the obligation for exporters to win all dollars from exports back into the country. And today, there is no basket of dollars that can be kept abroad, as it happened in the past, for example, in old days.

And then to your final question about the covenants, yes, as was briefly commented in the presentation, we do have, first of all, the possibility in the covenants -- first of all, on the instruments that do have these financial covenants. We do have the ability to freely refinance debt that comes due. And then also, we do have a basket, which, generally speaking, allows for new debt as long as it is within a range or within 5% of consolidated assets. So that should provide ample maneuvering rooms, as commented before, to tackle the needs in 2021.

Our next question comes from the line of Matias Wesenack with Partners.

I have 2 questions about the Downstream segment. Firstly, I see that gasoline sales are stalled at 30% year-on-year and diesel at around 20%, even with the lockdown easing. And what further explain this stagnation? Is this a new normal? And my second question is relating to the pricing policy you will follow. I understand that it's important to understand the impact that this has some macroeconomics. But what are you expecting to do with the prices? You mentioned that they are 20% below 2019 in dollar terms. And I want to know if you expect to recover those levels fully? Or -- and how long you expect to take to achieve them?

Thank you, Matias. Going to your last question first, pricing policy, as was commented before, yes, we've been adjusting several times since August, primarily trying to accommodate our prices to import parity, but primarily to recover some margins in dollar terms.

Going forward, and as was said before, we have to be very cognizant of the reality -- macroeconomic realities. But we would expect to at least keep track with the evolution of the FX to at least maintain the current margins that we have in dollar terms.

When comparing to the previous year, as you said, clearly, gasoline and diesel at about 20% to 25% down versus the same quarter last year in dollar terms. But you have to also bear in mind that international prices for crude, basically brand prices, went down in the same period by about 30%. So we are clearly not able to move too away from realities of our sector. So when you compare to that, you can see that actually from a spread point of view, we have improved vis-à-vis international crude prices. So I think this is a reality for the whole industry.

Oil and spread -- oil and refined product prices have come down very significantly. And as was mentioned before, we don't want to bet our future on expectations for future price increases. So we rather assume prices to be relatively stable in dollar terms. Of course, not assuming a significant reduction from current levels, which we don't see happening on a structural basis. And so we are doing our estimates in the best way possible, but basically taking on current dollar prices relatively constant in the near future.

And then -- sorry, I took down the note -- your downstream question, but can you repeat that? But -- because I didn't take note.

Yes. Yes. I was asking about the demand in the Downstream segment, that it seems to -- that is still down 30% for gasoline and 70% in October? And what explains this? And if this is the new normal?

Yes. Sorry, I didn't take note. No. Clearly, that is not the new normal. We do see a further gradual recovery after the end of September. So the numbers are shown there for the quarter. If we look into October, clearly, demand improved a little bit further. And as we moved along and now sitting in the first weeks of November, we are probably closer to minus 25% in gasoline and about minus 15% in diesel. So we expect to end the year roughly around these levels, probably a little bit better. Again, as the lockdown measures continue being flexibilized, we do see activity increasing. We don't see demand coming back to pre-COVID levels in the coming months. And as we move along in 2021, although it's hard to predict how the pandemic will evolve, and assuming there is no second outbreak, as the world is seeing in the north, in Europe primarily, assuming that there is no second outbreak, we do expect demand to continue normalizing along the year, probably reaching levels of 5% to 10% below pre-COVID by the end of the year. So basically, December '21 versus December 2019 both for gasoline and diesel will probably be in the order of -- or we are estimating, not probably. We are estimating to be between 5% and 10% below the previous normal.

And in terms of jet fuel, clearly, we don't see that significant improvement or improvement not to be that significant in that segment. And probably, we expect to end 2021 with demand for jet fuel closer to about 50% of what it used to be on pre-pandemic levels.

Our next question comes from the line of Andrew De Luca with Barclays.

Most of them have been asked, but I just wanted to follow up on the covenants on the 5% of total assets that you mentioned. I think that currently translates to about $1 billion of incremental debt above the incurrence. Is all of that available as of now? That would be my first question.

And the second question is, you answered it a bit in Barbara's question earlier, and it's about the possibility of local funding options. But you also mentioned that you could look to the international markets to help fund CapEx, if I understood correctly. Just given where your unsecured bonds are trading, it seems, obviously, quite challenging. So is it safe to say that when you mentioned that it's that you're looking or you're exploring the possibility of issuing some sort of secured funding?

Thank you, Andrew. Clearly, we are analyzing all possible options in terms of our funding -- to cover our funding needs. As mentioned before, and we are very, very realistic about where our secondary levels for our unsecured bonds are trading. That's why also we mentioned that we do see the ample liquidity currently available in the local market as probably being a relatively large source of funding next year and for the rest of this year as well.

So clearly, looking at potential secured financing -- cross-border financing could also be on the table. But there is -- no decision has been taken yet as of what the right next step should be. As you probably know, there is a very interesting arbitrage currently available in the local market where dollar-linked bonds have been issued at very low rates. So we do believe that we have the capacity to take advantage of that as well as also raising peso-denominated funding, which is very important to also maintain our hedging of our local liquidity as well. So I would say that we are primarily focused on the local market for now. We -- this company used to have significantly larger funding locally than what we currently have. So back in 2014, 2015, financing from the local market represented a significantly larger portion over total funding for this company. And we believe that probably we should move along in coming months with a strategy to get back to that situation, right? So relying more on the local market.

In terms of the covenant, your calculation is relatively correct. So it's a little bit over $1 billion, to be fair. But that is only related to new funding, right? So there is also the possibility all that, that comes due can be reissued without any restriction. So basically, refinancing is not precluded or restricted by the government. But only the new -- the incurrence of net new debt. And on that front, yes, the limitation would be on roughly about $1.2 billion as of now. Based on the latest consolidated asset figure, that will be the total available on net new funding based on the covenants.

Great. That's really helpful. And I just -- 2 very quick follow-ups. Just 1 on the local market funding. I mean we're hearing that a lot from a bunch of corporates in Argentina. There haven't been that many transactions over the last couple of months, obviously. But can you just help us understand how deep do you think the market is really right now?

And the second one is just going back to the secured capacity. Is there some update that you can provide us with in terms of how much secured capacity you had at the end of the third quarter?

Yes. And in terms of capacity from a negative pledge standpoint, we do have ample capacity. So there is -- I wouldn't say that there is any major restriction there, and we can have enough flexibility to move along there. And again, probably the restrictions are more related to our export flows. If that security comes from exports, which is probably the most reasonable way of putting up a secured financing. But again, as said before, as mentioned before, we don't have any final decision as to whether we want to actually move along in that front in the near future.

And again, as long as we do have -- as long as we end up having access to the official FX market to honor our commitment or honor our maturity of the March 21 bond, we do believe that the local market could still provide a very efficient funding source and very efficient funding alternative. Total capacity in that market or what the final depth of that market is -- it's hard to say for sure. It's not a market -- it's a market that has been increasing its liquidity very significantly and as you know, the FX restrictions for -- generally speaking, for corporates and for people, generally the common people. That means that both the population and companies have to retain liquidity on shore, and that means more liquidity available in the hands of institutional investors. So that happened in the past as well. And again, this is a mutual beneficial situation for both the local institutional investor audience and corporates like us to come up with new products to -- where that liquidity can be invested. That's why we believe that the arbitrage is coming from exactly that situation. And that's why we believe that there should be ample capacity to tap on that market in coming months. Much further beyond the debt that comes due for YPF in that market, which as I was saying, it's in the order of $350 million in bonds that come due between now and the end of 2021.

There are no further questions at this time. I would now like to turn the call back to Alejandro Lew for closing remarks.

Thank you very much. And well, thanks again to everyone that has joined the call this morning. We know that these are very volatile times. And taking the time to follow us is very appreciated by us. And so we keep open to having a continuous dialogue. And once again, thank you, all, and have a great day.

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