YPF SA (NYSE:YPF) Q2 2022 Earnings Conference Call August 11, 2022 9:00 AM ET
Company Participants
Pablo Calderone – IR Officer
Pablo Iuliano – GM, CEO & Director
Alejandro Lew – CFO
Conference Call Participants
Frank McGann – Bank of America Merrill Lynch
Bruno Montanari – Morgan Stanley
Luiz Carvalho – UBS
Ezequiel Fernández – Balanz
Marcelo Gumiero – Crédit Suisse
Andres Cardona – Citigroup
Operator
Hello, and thank you for standing by. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the YPF Second Quarter 2022 Earnings Webcast Presentation. .
I would now like to turn the conference over to Pablo Calderone, YPF IR Manager. Please go ahead.
Pablo Calderone
Good morning, ladies and gentlemen. This is Pablo Calderone, YPF IR Manager. Thank you for joining us today in our Second Quarter 2022 Earnings Call. Today, we will have some introductory remarks from our new CEO, Pablo Iuliano; and then our CFO, Alejandro Lew, will go through the main aspects of our second quarter results.
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 question may include forward-looking statements, which are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these remarks.
Also, note the exchange rate used in calculations to reach our main financial figures in U.S. dollars. Our financial figures are stated in accordance with IFRS, but during the call, we may discuss some non-IFRS measures such as adjusted EBITDA.
Now let me turn the call to Pablo Iuliano.
Pablo Iuliano
Thank you, Pablo. Good morning, and thanks, everyone, for joining today. I am delighted to be with you for the first time to report our second quarter results. And before getting into specific, I would like to begin my remarks by thanking our now former CEO, Sergio Affronti, who 2 years ago, trusted me to rejoin YPF to lead our unconventional operations. Sergio took the hand of the company at an extremely difficult time, not only for YPF and Argentina, but for all the economies worldwide and navigated through the strong with affirmed determination, successfully putting the company back on the path of profitable growth. Therefore, the positive results that we are presenting today are the outcome of Sergio’s strong leadership and the outstanding job performance by the more than 20,000 employees and more than 40,000 people that indirectly contributed with us, with whom, we will continue working to deliver on our ambitious target.
I would like to also express how proud and honored I am to assume the responsibilities to lead the largest integrated energy company in the country, with my firm commitment and that of the entire Board of Directors and of the executive team of taking YPF to the next level, by growing consistently in a profitable way to become an exporter of energy within the next 2 years. All the while, we maintain our proven and healthy financial strategy and having safety and sustainability of our operation at the forefront of our day-to-day decisions.
Now moving into the very purpose of this call, let me start highlighting that this was a very robust quarter, in which we continued delivering solid operational and financial results. We continued expanding our profitability, gaining for the operating efficiency and consolidating the production growth that we have been delivering for over a year leveraging, amongst others, on the tremendous progress that has been gained in our Vaca Muerta operations in the post-pandemic.
We, therefore, feel very comfortable with our ability to deliver on our ambitious guidance established at the beginning of the year and further adjustment them to establish more challenging goals, as Alejandro will go through by the end of his remarks.
I now turn the call to Alejandro to go through our results for the second quarter.
Alejandro Lew
Thank you, Pablo, and good morning to you all. During the quarter, our total hydrocarbon production averaged 504,000 barrels of oil equivalent per day, remaining essentially flat vis-à-vis the previous quarter, but consolidating a 9% growth when compared to the previous year, primarily leveraging on the very positive performance of our shale operations.
Adjusted EBITDA reached a strong quarterly mark of $1.5 billion, expanding 54% from the previous quarter and 38% on a year-over-year basis. This outstanding increase in adjusted EBITDA was primarily the result of higher prices across the board, including those of fuels sold in the local market, other refined products sold locally and abroad and the seasonal increase in the average realization price for our natural gas production. In addition, the sustained oil and gas production and the increased refining processing levels also contributed to the interannual improvement in adjusted EBITDA.
On the negative side, however, total OpEx jumped 34% when compared to the same quarter of last year, primarily as a result of the overall accelerated inflationary environment, the wage agreements negotiated with the unions and incremental transportation and energy costs given the increased activity levels. In turn, the strong operating results translated into the highest quarterly bottom line in the company’s history, with net income reaching $798 million, accumulating over $1 billion in net income during the first 6 months of the year.
In terms of our investment activities, CapEx totaled $932 million in Q2, representing an increase of 25% on a sequential basis and 61% on a year-over-year basis, accumulating almost $1.7 billion in the first half of the year. After a slower start in the first quarter, during the second quarter, we have gained momentum and are now expecting not only to meet, but even probably surpass our initial investment plan for the year, given some additional activity we are planning for the second half.
Finally, on the financial side, free cash flow was positive for the ninth consecutive quarter at $310 million, accumulating over $700 million during the first half of the year. This, in turn, translated into further strengthening of our balance sheet as our net debt declined to $5.8 billion, pushing our net leverage ratio down to 1.3x.
Focusing on the evolution of our oil and gas production during the quarter, although total production was relatively flat versus the previous quarter, we have continued expanding our crude oil production, which averaged 225,000 barrels per day in the quarter. On the other side, natural gas production declined slightly, while NGLs had a 5.7% contraction, primarily as a result of transportation constraints in our nonoperated area, La Calera, that should be completely lifted during the course of August.
Nevertheless, our investment plan for the year is allowing us to keep interannual production growth at a healthy pace, with total hydrocarbon production standing 9% above the same quarter in 2021 and more recently, resuming sequential growth with preliminary production figures for July, increasing to 512,000 barrels of oil equivalent per day.
Moving to costs. Lifting averaged $13.3 per barrel of oil equivalent across our upstream operations, an increase of 14% versus the previous quarter, primarily on the back of wage increases that impacted during this quarter. Higher pulling activity and increased energy costs combined with an overall accelerated inflationary environment and the slower-than-expected pace of the currency depreciation.
However, when we segregate lifting costs for our shale oil core hub operations, we managed to achieve a 5% sequential reduction to $3.50 per barrel as efficiencies implemented during the quarter, combined with higher levels of production, more than compensated the general cost pressures.
Regarding prices within the upstream segment, average crude oil realization price increased by over 10% on a sequential basis to $65 per barrel as price increases in local fuels during the quarter made it possible to improve prices of local crude, although still price at the discount to export parity.
And on the natural gas side, prices increased by almost 30% to an average of $3.9 per million Btu on the back of the seasonal adjustments within the Plan Gas contracts. More specifically, with regards to our shale operations, both shale oil and shale gas continue showing remarkable growth compared to the previous year, while also marking fresh new quarterly production records. Total shale oil production averaged 74,000 barrels per day in Q2, while shale gas averaged 15.5 million cubic meters per day, increasing by 5% and 1.2%, respectively. And when compared to the previous year, shale oil production expanded by almost 50%, while shale gas increased by over 80%.
In terms of activity, during the quarter, we completed a total of 29 new horizontal wells in our operated blocks, reaching a total of 67 completed wells during the first half of the year. Furthermore, during this quarter, we increased the [indiscernible] of filling activity beyond completion activity to enlarge our inventory of drilled but uncompleted wells in order to recover operating flexibility in line with what we have anticipated during the last earnings calls. In that sense, during Q2, we drilled a total of 38 new horizontal wells, 34 of which were in oil-producing blocks, representing the second highest quarterly mark in terms of drilling activity.
During Q2, we also established new records in terms of horizontal length, drilling a 4-well PAD in Loma Campana, which contains the 3 largest wells in all of Vaca Muerta at over 4,400 meters of horizontal length. And it is also worth highlighting that during the quarter, we drilled the second part in the Aguada del Chañar block, which is our newest development within our shale oil core hub, fully owned by YPF.
In terms of efficiencies within our shale operations, during the quarter, we achieved further significant improvements in drilling and fracking performance, averaging 248 meters per day in drilling and over 200 stages per set per month on fracking, increasing by 13% and 23%, respectively, when compared to the previous quarter and setting new quarterly records for both metrics. This came as a result of the continued efforts of our technical teams in collaboration with our key contractors that keep working relentlessly to introduce further operating improvements to counteract the effects of rising costs in the context of accelerating inflation. Consequently, average development cost within our core hub operations decreased by almost 20% when compared to the same quarter last year, reaching a new record low of $7.1 per barrel.
Switching to our downstream operations. Domestic sales of diesel and gasoline increased by 6% when compared to the previous quarter, driven by record high diesel demand, which led to the highest level ever dispatched of diesel in any given quarter, jumping over 12% versus the previous quarter and standing 15% above pre-pandemic levels of the same second quarter of 2019. This historical diesel demand was mainly the result of high seasonality in the agribusiness sector, which, combined with increased demand from certain industrial segments such as mining and transportation and higher-than-usual demand in provinces that border with some of our neighboring countries.
It is fair to comment that this historical high-diesel demand stressed our supply logistics in certain regions of the country, particularly in late May and early June, causing some disruptions in the normal supply to consumers. However, at YPF, we led a broad sector effort to face this exceptional high demand through increased processing levels, higher than historical imports, a greater portion of biofuels in the blend and drawing on inventories, thus managing to gradually restore the normal supply of diesel. On top of that, it is worth noting that during the first half of the year, we achieved a record high production of gasoline and middle distillates through maximizing our refinery conversion levels in order to partially reduce dependence on imports.
In terms of prices, during the quarter, we continued with our strategy to gradually reduce the gap of local fuels to international parties, maintaining a dedicated approach to avoid stressing affordability of our products by our local clients. Average prices for gasoline increased by 11% in Q2 versus the previous quarter when measured in dollars, while average diesel prices advanced 24%, combining higher increases, both on retail and wholesale segments. And diesel price increases were more pronounced in premium diesel when compared to regular quality, aiming at aligning the former with import parity prices. Therefore, and in conjunction with the government policies that introduced temporary tax refunds on imported diesel, we managed to mitigate, to a large extent, the economic impact of imported volumes running above normal levels.
In addition, during the second quarter, we have continued benefiting from a high pricing environment on the basket of refined products other than gasoline and diesel that have high correlation with international prices, which represent close to 20% of our total revenues and increased about 25% versus the previous quarter. Further on this topic, it is worth highlighting that during the quarter, we continued strengthening our commercial relations in the Asian market, further enhancing international demand for our nonfuel refined products.
Cash flow from operations in the second quarter amounted to $1.3 billion, 33% higher than the same quarter last year, but slightly below the $1.4 billion recorded in the previous quarter. Despite the higher adjusted EBITDA level for this quarter, lower cash flow from operations compared to the previous quarter was the result of a positive noncash inventory adjustment recorded in the quarter as well as a negative working capital variation, primarily based on seasonal factors in the natural gas segment. Nevertheless, free cash flow came in positive territory for the ninth consecutive accumulating almost $2 billion even after the ramp-up activity in the deployment of our investment plan for the year.
On the liquidity front, our cash and short-term investments position declined slightly to $1.2 billion as of June 30 compared to the $1.3 billion as of March 31. Part of this decline resulted from the heightened volatility in the local financial market in June, which affected the market value of a portion of our investment portfolio particularly sovereign bonds and treasury notes, resulting in a 3.5% loss over our total liquidity when marking to market our entire financial investment position. However, this impact was not fully reflected in our since a portion of our position in sovereign bonds are booked on an accrual basis as they are expected to be held to maturity. Therefore, the net impact recorded in our consolidated liquidity was less than 2%. Nevertheless, market performance after June 30, thus improved further leading to an almost fully recovered market value of our entire investment portfolio compared to the situation before the market volatility started.
Turning to our debt profile, positive free cash flow in the second quarter led to a further reduction in net debt to $5.8 billion taking the net leverage ratio further down to 1.3x. Part of the gross debt reduction in the quarter came from the prepayment of a peso-denominated syndicated loan for the equivalent of about $82 million as part of a proactive strategy to minimize the cost of carry of our global financial position.
Therefore, as our financial situation continues improving, I would like to highlight, as in the previous quarter, that our healthy liquidity position comfortably covers our short-term financial maturities almost doubling the amount of debt coming due within the next 12 months, as we have less than $150 million coming due until the end of this year. And just north of $900 coming due all along 2023. It is also worth mentioning that during this quarter, we entered into an interest rate swap to hedge our exposure in relation to the to the software-based cash loan that was fully disbursed by the end of March, thus leaving us with no relevant exposure to global interest rate movements.
Finally, before going into the Q&A, I would like to provide an updated guidance for the rest of the year. Better-than-expected economic performance so far in 2022, enhanced our cash flow generation and also left us with a more constructive outlook for the rest of the year. In this context, we have reviewed our investment plan, expanding among others, our budget for the upstream segment adding to our drilling and completion campaign in Vaca Muerta as well as incorporating incremental activity in the Golfo San Jorge basin. We are, therefore, anticipating an increase of full year CapEx budget by about 10% to above $4 billion.
This expanded CapEx activity should in turn allow us to achieve further oil and gas production growth, raising our year-over-year target for hydrocarbon production growth by about 1 percentage point and even more relevant, increasing our end of year oil production target by about 6%, now estimating an average of about 230,000 to 235,000 barrels per day in the fourth quarter, leveraging on an estimate of 85,000 to 90,000 barrels per day in shale oil production in that period.
In addition, we are introducing guidance for full year adjusted EBITDA which we expect to land in the area of $5 billion, assuming no major macroeconomic distortions affect our operations in coming months.
Finally, even though we are adjusting our CapEx plan outwards, we feel confident in our ability to maintain net leverage within current levels, estimating to end the year with a net leverage ratio not higher than its current level of 1.3x compared with our previous commitment to stay below 2x.
With this, I conclude our presentation for today and open the call for your questions.
Question-and-Answer Session
Operator
[Operator Instructions]. Our first question will come from the line of Frank McGann with Bank of America.
Frank McGann
A couple of questions, if I could. One, just in terms of the second half, I’m just wondering what price increases have been put in place so far? And what you’re seeing in terms of the environment given inflation pressure, international prices coming down a little bit, how you see the need for price increases?
And then secondly, could you comment on the benefits of the additional transportation capacity that you’re seeing, particularly on the oil side over the next couple of years, how much incremental production you will be able to bring on stream in order to fill your share of that capacity?
Alejandro Lew
Thank you, Frank, for your questions. Well, to start commenting on our views for the second half, so far, in terms of prices, our average prices as of today are a little bit higher than the ones that we averaged in the second quarter. Primarily on in the case of diesel, we are running about 10% higher, while on gasoline we are just slightly below. That basically is the result primarily of the final adjustment or the most recent adjustment that we performed in the month of June, in which we only adjusted prices for diesel and not for gasoline.
Going forward, we expect to continue with the strategy that we have been deploying — in — during most of this year. Basically trying to — for the — at the minimum adjust prices in a way to compensate for the evolution of the currency depreciation and for as long as possible to continue reducing the gap with international parties.
So far, we see ourselves in a much comfortable situation in diesel, where the combination of the reduction in international Brent prices has translated into a lower import parity for diesel. And also for gasoline and combining that with the increases in diesel we are significantly closer to international parities on average, primarily being aligned and fully aligned on our premium quality diesel products, both on retail, where we are practically aligned and wholesale segments where we are slightly above import imparity.
In the case of gasoline, we are having higher distortion or a higher gap. We expect to be able in the near future to probably introduce price adjustments at the pump in a way to not only compensate for the currency evolution, but also to reduce at least partially the current gap that we are having with international parities on gasoline.
So all in all, we would expect, as I said, to continue with adjustments for as long as possible, but keeping clearly a constant look and looking into how the overall macroeconomic environment evolves. And clearly, as mentioned during the presentation, making sure that our price adjustments don’t interfere with the possibility and the affordability of our products by our local clients.
So clearly, and as also mentioned, cost pressures related to the your — the second leg of your first question, inflationary pressures we are seeing a global inflation environment in Argentina running higher than the devaluation of the currency. We have recently closed the wage agreements with the unions for the period that goes from April ’22 to March ’23. That was negotiated at a nominal level of 79% for the entire period. It’s still to be seen how that ends up landing vis-à-vis inflation.
But at least for the next few months we expect wage increases to have — to be already fixed based on those negotiations. And beyond that, we will continue to analyze how the rest of the inflationary environment affects our cost structure. And in that sense, also that we’ll also be taking into consideration to — for our strategy in terms of prices for local fuels.
And in terms of your second question, the — our views for the midstream projects that will continue to bring further evacuation or the transportation capacity online. What we have already achieved at least for the YPF side, we — since the beginning of 2021, we have seen an increase in about 50% of our total evacuation capacity out of Vaca Muerta that is a combination of the project that was already put online by Oldelval in terms of the 4 pump stations that have been idle for many years and they were back in operation since April. That increased total evacuation capacity for Oldelval — of Oldelval by about 25%.
And then on top of that, we have benefited from some additional evacuation capacity related to the oil transportation to our refinery in Mendoza in Lujan de Cuyo through a reversion of some oil pipeline flows that goes from Vaca Muerta and also through some virtual transportation basically through swaps of oil with some other players. So based on all of that, we have already seen an incremental capacity of about 50% in the last 18 months.
And going forward, what we see is that the combination of the Oldelval expansion through about 300 kilometers of loops and also the upgrade of the other 4 pump stations that Oldelval has connecting Neuquén to the Atlantic to Puerto Rosales. That should be gradually bringing further capacity online, probably the first leg that we are going to see early next year by the end of the first quarter by about 10% of incremental capacity by March of next year. Whereby, we also expect the final contribution of the total expansion of — through those loops, which should take current capacity of about 44,000 cubic meters per day of that pipeline to a total of about 72,000 cubic meters per day. And that should be gradually through the first — and part of that in the first quarter of 2024 and the final leg in the first quarter of 2025.
And in addition to that, has been mentioned in previous calls, we are also pulling back in operation, transforming the pipeline that we jointly own together with ENAP and with Chevron. We are currently undergoing a full analysis of the state of that pipeline. We expect to have, if no major situation is identified. We would expect that pipeline to be back in operation in early 2023. And then in combination with the new pipeline that we are starting to build before the end of this year, that should be already in operations in the second half of next year. That should probably add a total of about 70,000 to 100,000 barrels a day in additional transportation capacity out of Vaca Muerta by the end of next year. So that’s basically for the — at least for the near term and the next couple of years, the projects that we are identifying to be able to grow our total oil production.
Operator
Our next question will come from Bruno Montanari from Morgan Stanley.
Bruno Montanari
I have three, if I may? The first one, talking a little bit about conventional fields. You have been mentioning for a while now the progress at Manantiales Behr. So just wondering if you could give us an idea of how much more production you can extract from that area? And then if you can apply similar techniques to other areas, and again, what type of production could come from there, which would be a nice complement to what you’re doing on unconventional?
The second question is about diesel, so just to confirm, is the situation now with the logistics and demand normalized? Or are you still running the refineries a little bit harder and importing? And then the third question, curious about your comment on the newer longer wells that you recently drilled. Are you in a position to talk about differentials for those super long wells versus the more normal type wells you were running now?
Alejandro Lew
Bruno, thanks for your questions. In terms of tertiary production, it’s hard to say how further production growth we are going to see in Manantiales Behr. So far, it continues providing very positive results. We have already started to redeploy some of the existing injection units to rotating them into new areas in Manantiales Behr, and all of that is producing very positive results. So we would expect that trend to continue, but it’s hard to predict exactly how further production growth we are going to see there.
In terms of further opportunities, we are deploying new pilots in other areas such as Los Perales and El Trébol, for example. So far they are rendering initial positive results. And so we would expect to start probably a process of massification on some of those projects by the end of this year and early next year.
The — if we talk about the total potential that we see in EOR, given all these projects, we can probably see an increase in total tertiary production of about 50% clearly coming from still a low number, but probably seeing something over 50% between now and next year, generally speaking.
In terms of your second question about logistics on our downstream operations. Clearly, the supply constraints that we faced in the peak of late May and early June already subside. That was through a combination of things, as we have mentioned in the call. But clearly, we are now running on higher levels of imports compared to the second quarter. Clearly, that’s been managed also in a positive economic way given the adjustments on premium grade diesel to international parties to import parity. And so now the — clearly, the problem is the last-mile transportation logistics, which is running at practically full capacity given our increased market share as well.
So it’s a combination of record high diesel volumes dispatched, which is part of the total increase in overall demand and also our higher market share on diesel. So we are doing our best in expanding our last mile transportation capacity basically to adjust our logistics. But generally speaking, the supply constraints have been reduced in a very significant way, whereby, we have seen some constraint both on regular quality and premium quality in late May and early June in terms of supply disruptions at our gas stations.
And now all of that has declined very significantly, where we are not having any relevant disruption in premium quality and also having reduced disruption by about 40% in regular diesel. So all in all, we are in a much more comfortable situation today, but still facing the potential risk given the overall heightened demand environment and running our capital logistics or last mile transportation logistics at full capacity and trying to, as I mentioned before, incorporate more trucks into our fleet to be able to further expand our logistics capacity.
And finally, on our longer wells, it’s still early to say. We are clearly pushing our boundaries forward. That’s also possible given the — some technology that was acquired in late 2019 and early 2020, it’s a new equipment, which is called snubbing, which is the only equipment that is available here in the Argentine market and is owned by our wholly owned subsidiary, AESA, Alfredo Evangelista.
I actually mentioned that because I was yesterday at the local event, oil and gas event here in Neuquén — in the province of Neuquén, where our company has a simulator of that system, which is pretty impressive that can work on — with light pressure on the wells and also has the ability to rotate stoppers on horizontal legs of over 3,000 meters without any major issues in one run. So clearly, that is a differentiation factor for YPF, having that equipment which is allowing us to grow and expand the boundaries of total horizontal legs in our wells. In terms of EOR, as I said, we should probably — a way to have further response from these high longer wells to be able to come up with an estimate that we feel confident and comfortable in sharing with you.
Operator
Your next question will come from the line of Luiz Carvalho with UBS.
Luiz Carvalho
Two questions here. The first one is follow-up the cost. I mean we saw some power increases over the past let’s say, over the past year and sequentially quarter-over-quarter. So just trying to — center page of your trend as in the past, the lifting cost was somehow stable/dropping. The second question is about the debt maturity now and congrats on managing that over the past couple of quarters. But still looking to 2022 to ’25, you still have some increase of $3.5 billion on debt, that is expiring. So I’m just trying to understand I think better what will be the , management here in terms of expanding or extending — sorry the maturity of the debt in order to try to distribute better the cash flow for the coming years.
Alejandro Lew
Thank you, Luiz, for your questions. In terms of lifting, clearly, what we are seeing is a different trend in conventional versus unconventional, whereby, the production growth in our shale operations in unconventional is allowing us to continue reducing the overall lifting cost of our operations there. And of course, as we continue to see a higher proportion of shale within our total production mix, we would expect that to continue helping the average lifting cost down the road.
Clearly, on the opposite side, the combination of the inflationary pressures in pesos and with a slower devaluation of the currency, clearly translating into dollar denominated cost pressures. And the decline in production although clearly at significantly lower pace than the natural decline that we would see in our conventional operations, should we not had the contribution of tertiary and also the further efforts that we are putting on secondary production. Clearly, the impact in our lifting costs for conventional would be even worse.
But — so combining those 2 factors and given the continuous expectation for inflation running above the valuation of the currency during the rest of the year, combining all of that, we would expect the overall lifting cost to remain relatively flat in the second half compared to the second quarter that we are just releasing. So basically, we will be — we should be able to counteract the effects of higher inflation through the high proportion of shale and the stabilization of our production in conventional and the higher production in our shale operations.
And going to your second question in terms of our debt maturity profile, we clearly see a jump in maturities in 2025. Of course — and this is mostly related to international bonds. While on the other hand, in 2023, 2024, we have only a portion about 60% of the maturities are based on international bond amortizations and the remainder being local bonds and bank financing. So we clearly see a better ability or an easier situation in refinancing, rolling over local bonds and bank financing.
Further to that, we — and as mentioned in previous calls, as of today, we are sitting on the lowest level of exposure to the local capital markets and to — our counter — the major financial institutions that are our main relationship bank. So we see ample capacity to raise the financing there and probably that should allow us to rollover the debt that is coming due from international bonds in 2023, 2024, basically replacing exposure to the international capital markets through new exposure in the local capital markets and through our relationship banks.
So for the most part, we would expect that. We — even if we consider clearly, we don’t have a budget for 2023, yet. But even if we assume that we could potentially move into an even more ambitious CapEx plan next year, we believe that if we continue to manage to grow our production in the way that we have so far been doing and probably project for next year and the years to come.
As mentioned in the previous call, we are expecting to double our oil production by 2026, so that clearly implies that we continue to expect to grow our production gradually along the years. So given that, and which should allow us to continue to have a healthy cash flow generation, cash flow from operations, so the combination of that, increased cash flow generation should allow us to be somewhere in the cash flow neutral stance when taking into consideration CapEx and interest expenses. But we clearly — it’s still too early to say.
We would say that the rolling or the maturities coming due should be easy to be rolled over given the ample capacity that we have in our local market exposure in our relationship banks. And then if we were to have a negative free cash flow, well, either it would be because we have the capacity to raise that additional debt or otherwise we would adjust our CapEx plan to in line with our cash flow generation.
So all in all, what I would say that, we remain very optimistic in terms of being able to manage along the lines of growing our production through ambitious or to further increase in our CapEx plan. That should be tackled through operating cash flow in the next coming years and maintaining a prudent financial approach, as we committed in previous calls, of staying below 2x in terms of net leverage.
Clearly, given the current level of 1.3 and the expectations to remain within 1.3x for this year, that provides us further room in case we need to increase our leverage next year. Clearly, if we see that opportunity in the different markets.
Luiz Carvalho
Okay. And if I may just do a follow-up here. In terms of cost of debt, I mean, maybe the company situation is getting, of course, better from a balance sheet perspective. But still the country situation and somehow, I would say, a bit more challenge, right? So how do you see not the capacity to finance if may see — if I’m persuaded by the cost of gas of this potential refinancing of your debt structure?
Alejandro Lew
Well, clearly, it’s a moving target. Of course, so far, the local market continues to provide a very nice, a very attractive arbitrage in terms of cost of debt. So any debt that you replace from the international markets with the local market, given current conditions, it would imply a cost — a total cost reduction in overall cost of financing.
On the other hand, when you look at bank financing, the most recent experience that we had was with the CAF led transaction which clearly was slightly above our average cost of debt, but not significantly higher. So all in all, I would say that we are constructing in terms of being able to maintain our average cost of debt in the range of 7.5% to 8%, but that will also depend on the overall interest rate environment globally, of course.
As of today, we have no relevant exposure, as mentioned in the presentation, no relevant exposure to value or to interest rates. The key — or the largest loan that we have on variable rates, which was the CAF loan, has already been hedged, fully hedged. So we have no exposure to variable interest rates. And in terms of the refinancing, it will depend on how the local market continues to perform and whether it continues to provide a potential arbitrage vis-a-vis international financing.
Operator
Your next question will come from the line of Marcelo Gumiero with Credit Suisse.
Marcelo Gumiero
Most of my questions were actually already answered. I have just one follow-up, maybe on the CapEX side. So you have updated the guidance for the year for 2022. And it seems at least for me that we should expect CapEx to accelerate in the second half of the year, right? I — just — I was just wondering I mean, what drives that acceleration. If you could provide some additional color on what — do you need to meet these prospects. If there is any effect of maybe CapEx inflation there? So I mean an overall comments on what you expect in terms of CapEx for the second half of this year?
Alejandro Lew
Marcelo, thanks for your question. Clearly, an unfortunate portion of the CapEx increase is related to inflation pressures. But to the largest extent is related to increased activity that we are projecting for the second half. This is clearly the result of better performance than anticipated in the first half, that is allowing us to anticipate some activity that was expected for next year. And that is a combination of increased drilling and completion activity in our shale operations, primarily in oil in our core hub, whereby, we are expecting to drill over 2 — drill and complete about 20 additional wells. When we provided guidance for the year, we anticipated about 100 of completing or tying in about 100 wells in our fourth half. We are moving now to probably over 120. So that is increasing our total activity there by about 20%, which also correlates with the comments that we made in terms of increased oil production expected for the fourth quarter of this year in our shale operations. So probably we are raising.
Even though we have not provided guidance specifically before on what we had expected in terms of shale oil production, today, we introduced the number of 85,000 to 90,000 in terms of net production for YPF, 85,000 to 90,000 barrels per day in our core hub. And I would — sorry, in our total net shale production, which is clearly a significant increase versus our previous estimate, and that is related to this increased activity in drilling and completion. So that is on the one hand, we are also expecting some incremental drilling activity in some of our shale gas blocks primarily in La Calera.
And then finally, we are also moving forward or anticipating the construction of some facilities in — primarily in the Aguada de la Arena block. There, we were projecting for the next couple of years to build 2 new gas processing plants. One was expected for the first half of 2024, and that was related to our commitments to continue deliver on our planned gas commitments.
And then we also have a second plan — a second solid processing plant projected for 2025. That second plan, we are probably anticipating that, and we now expect to start the construction of that second plant this year. That’s why we are part of the incremental CapEx is related to that facility. And the idea for that is to be ready to supply further production — further gas production for the — for when the new evacuation capacity coming in line through the pipeline, be available hopefully next year. So we want to be ready to be able to supply part of that incremental capacity as well.
So I would say it’s mostly drilling and completion and some facilities in the — in our shale operations, primarily oil, but also some in gas. And then also, we are accelerating the construction of the oil pipeline that I mentioned before, the oil pipeline that connects our shale oil core hub operations to the northern part of Neuquén to be able to supply both our refinery in Lujan de Cuyo also to connect with the Trans-Andean pipeline to export to Chile.
So we are also bringing some of the CapEx that was originally projected for next year for that pipeline forward to this year. So that’s basically the main aspects of the CapEx increase. And as I mentioned at the beginning, unfortunately, a portion of that also relates to inflationary pressures, cost pressures.
Operator
Your next question comes from the line of [indiscernible].
Unidentified Analyst
Congratulations on your results. I’d like to pose a question on your refinery diet. You are focusing CapEx in Panama, which produces light sweet Medanito oil. Now does that mean that you will need to purchase proportionally more oil from producers with heavier blends?
And another question. Since a significant portion of YPF’s revenues are denominated in pesos. Could you give us your view of the impact of a steep devaluation on the company’s financials, let’s say, what could we expect if the peso fell by 30% overnight?
Alejandro Lew
Constantino, first of all, thanks for your congratulations. In terms of the refinery diet, clearly, the evolution of the portfolio of lighter crudes versus heavier crudes evolves over time. I would say that in the long run, we are preparing for that higher proportion of lighter crude through the revamping of our refineries, the topping B that will allow us to improve or modify the diet to be able to process a higher proportion of lighter crudes, clearly the Medanito crude vis-à-vis heavier crude.
So in the short run, we have been managing efficiently to work on that. And as I mentioned, as was mentioned in the presentation, we even have the highest refinery margins in terms of production margins or efficiency in the history of our refineries during the second quarter. So we’ve been through I would say, through smaller adjustments of our refining processes, we’ve been able to manage these higher proportion of lighter crudes.
And in the long run, we are — the part of the major multi-annual investments that we are doing in our refineries, both in the Lujan de Cuyo and the La Plata, that would allow us to process the higher proportion of lighter crudes in the mix in coming years.
And then on your second question, well, let me just say that, yes, clearly, as you have mentioned, is our revenues — a good portion of our revenues, I would say, roughly 60% of our revenues are peso-denominated in the short-term peso denominated. Those are clearly the revenues that come from the sale of fuels in the local market.
On top of that, roughly 35% to 40% is dollar denominated, which is a combination of the market of further refined products that do follow international prices. And then also our natural gas sales which are dollar denominated. So when you look specifically into the peso-denominated revenues, it will also depend on the ability that we will have to adjust prices accordingly. So doing sensitivity analysis there, it’s pretty complex because it depends on that ability to translate any significant devaluation into pump prices and into local fuel prices.
And then also an important portion of our costs, both OpEx and CapEx is also peso-denominated. So the revenues are partially hedged through the impact — the positive impact that devaluation — a steep devaluation we have in our cost structure, which is roughly about 60%, roughly speaking, combining OpEx and CapEx, roughly 60% to 70% peso-denominated, depending on whether you look more into CapEx or into OpEx.
So Clearly, for as long as the — a steep devaluation is not passed through immediately to fuel prices. It will have a negative impact, but then the full impact will depend on the velocity, the speed in which we managed to adjust prices accordingly. And then how much that is compensated with the savings or the reductions in our total costs are denominated in dollars.
And finally, on our liquidity, I would say that our net exposure is roughly — it has increased, by the end of the second quarter was slightly below 30%. And of course, clearly, there, we will also have some impact in terms of a deterioration in our liquidity position…
Operator
Our next question will come from the line of Andres Cardona with Citi.
Andres Cardona
You have one question about your EBITDA guidance, $5 billion. If you can share with us what are the key assumptions for crude realization prices and the adjusted EBITDA for downstream, it was $21.1 per barrel as per your press release. So I would like to understand what are your assumptions for the second half of the year for this key variable realization price of crude and downstream — adjusted downstream margin — EBITDA margin?
Alejandro Lew
Andres, generally speaking, what we would expect — or is assumed in our guidance is to have relatively stable prices and margins in dollar terms for the second half. What we are seeing is, as I mentioned, in terms of pricing strategy, we would expect to be able to continue adjusting prices in a way to compensate for the devaluation of the currency. And further to that, expecting to and primarily in the near term to really use at least partially the gap that we have today in gasoline.
So based on that we would assume a fairly stable pricing of crude in the local market. And that’s why probably maintaining margins both on the upstream and downstream segments relatively stable in the second half to what we have seen in the second quarter.
But again, that it all depends on how the different variables continue to evolve in coming months, both in terms of international prices and in terms of the key local macroeconomic dynamics such as inflation and devaluation. But generally speaking, that is what has been assumed.
Andres Cardona
Congratulations for the very strong second quarter and the guidance, which is also very strong.
Alejandro Lew
Thank you very much, Andres.
Operator
Your next question will come from the line of Ezequiel Fernández with Balanz.
Ezequiel Fernández
This is Ezequiel Fernández from Balanz. So it was great to see such results. I joined — indeed congratulations. And thanks to the Investor Relations team for the very complete material portfolio.
Sorry to take up some more of your time after an extended call. My questions should be quick. I have 3 of them. If we could go one by one, that would be great.
The first one is a follow-up on the — or related to Trans-Andean. If I understood correctly, you need to build another pipe that connects back more to that pipe that goes through [indiscernible]. Is that correct?
And then would that export capacity would be available to other players in Argentina? Or it would be dedicated just to exports from maybe YPF and Chevron?
Alejandro Lew
First of all, thank you, Ezequiel, for your congratulations and for recognizing the work of our IR team, which constantly looks into ways to provide the information in the best possible way to help our jobs. So thanks for recognizing that.
In terms of your question, once the Trans-Andean pipeline is put in service, which we expect that to happen unless some surprise takes place once we finish the passing of the intelligent equipment that is undergoing the inspection of the pipe, and that is going to take place in the coming weeks. And it’s been — going to be finalized relatively soon.
Assuming that is as expected. We should be able to have that pipeline back in operation by the end of this year, early next year. So the first volumes that will be able to be exported or transported through the pipeline are going to be the result of the reversion in the existing pipelines that are already taking place and that we are finally putting in service through new pumping equipment, and that should be available in the first quarter of next year. That will probably allow for total export capacity of about 5,000 cubic meters a day as early as the first quarter of next year.
Beyond that, and clearly, the total capacity of the of the Trans-Andean pipeline is significantly higher than that at 18,000 barrels — sorry, at 18,000 cubic meters per day, about 110,000 barrels a day of total capacity for the OTA — Trans-Andean pipeline.
The way to achieve the total capacity or in a way to get to that total capacity, we see the need to have this new oil pipeline that we have already started to move forward with and that construction should start in the next couple of months. And that is a pipeline that will also not only serve to connect to Trans-Andean but also to supply with larger proportion of oil from Vaca Muerta, our refinery in Lujan de Cuyo.
So we — therefore, we — to go beyond this initial 30,000 barrels that we expect to be available for export capacity in early next year through the Trans-Andean, we do see the need for this new oil pipeline, which we call Vaca Muerta Norte, not very creative. We do need that additional pipeline to be online to be able to expand beyond the initial 5,000 cubic meters a day to probably a level of around the 11,000 cubic meters a day by the end of next year in terms of export capacity to Chile.
And basically, that’s not going to be or our understanding is that’s not going to be available only for YPF, but also likely for other producers that might join also — might join us in the effort of putting together, finally putting together this new pipeline, which goes up north. So far, this is a project that is being 100% led by YPF.
Ezequiel Fernández
Okay. That’s great. That’s very clear. And my second question is related to — you talked about a little bit before local debt in the second half, how much do you think you might need to raise?
Alejandro Lew
Clearly, our plans as of today is not to tap the markets in the second half at all.
Ezequiel Fernández
Okay. Perfect. And my final question is related to, if you have any updates on potential farm-outs or selling of noncore areas through mature concessions?
Alejandro Lew
Okay. Yes, in terms of M&A activity, on the one hand, in terms of Vaca Muerta, we are not planning any major transactions. Clearly, we do analyze opportunities, and we do analyze with some of our partners’ ideas and explore opportunities for joint ventures such as the one that was published with ENAP, for example, that clearly is something that we constantly explore opportunities, but not in a way to allow us to move forward. With the development of Vaca Muerta, we feel that today, our capital structure and our financial condition allows us to move forward with our projects without the need to divest or to farm out any significant area in Vaca Muerta, but we definitely constantly look into opportunities to have further partnerships with our key relationships.
In terms of the noncore mature assets, we continue to look into that. It’s something that it’s an efficient portfolio management that allows us to also focus our attention in the key — in our key operations, that are both Vaca Muerta and then also in conventionals in those areas where we see potential for tertiary production for EOR. So beyond that, we are constantly looking into the possibility of divest or disinvest in some of the other mature areas that are nonkey, noncore for us. But there is no specific schedule, no timeframe to move forward with any particular transaction.
We, at some point, we were looking into some portfolio that was considered to be put up for potential disinvestment. And it’s a moving target. It’s a dynamic, and it also depends on the general market environment and our need to release cash flow for other operations.
Today, clearly, we are in a more comfortable situation. So there is no need to urgently move forward. But there’s always opportunities, there are always opportunities to have an efficient management of the portfolio. And so we will constantly look into that and move forward, if we see any specific opportunity to disinvest in a particular area that makes sense, not only for us, for the potential acquirer and for the problems as well, right? If there is a way for some niche operator, to make or to perform a more efficient operation of some mature area, we will definitely look into moving forward with that.
Operator
We have no further questions at this time. I’ll turn the conference back over for any closing remarks.
Alejandro Lew
Well, thank you very much, everyone, for joining us today. Thanks for your congratulations. We are very proud of the results that we have achieved. And we hope to continue having you on board following our names in — our name in the future. Thank you very much, and have a great day.
Operator
Ladies and gentlemen, this concludes today’s call. Thank you all for joining. You may now disconnect.
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