YPF SA (YPF) 2021 Q4 法說會逐字稿

Good morning. My name is Rob, and I will be your conference operator today. At this time, I would like to welcome everyone to the YPF Fourth Quarter 2021 Earnings Webcast Presentation and Conference Call. (Operator Instructions) Pablo Caldera, YPF Investor Relations Manager. You may begin your conference.

Good morning, ladies and gentlemen. This is Pablo Calderone, YPF Investor Relations Manager. Thank you for joining us on the call today in our full year and fourth quarter 2021 earnings call. I hope you all continue to be safe. This presentation will be conducted by our CEO, Sergio Affronti; our CFO, Alejandro Lew and myself. During the presentation, we will go through the main aspects and events that explain our fiscal year and fourth quarter results. And finally, we will open up the call for questions.

Before we begin, I would like to draw your attention to our cautionary statement on Slide 2. Please take into consideration that our remarks today and answer to your questions may include forward-looking statements, which are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these remarks. 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 the IFRS, but during the call, we might discuss some non-IFRS measures such as adjusted EBITDA.

I will now turn the call to Sergio. Please, Sergio, go ahead.

Thank you, Pablo. Good morning, ladies and gentlemen. Thank you for joining us on the call today. 1 year has passed since we were announcing the worst annual results for this company in its recorded history. And at that time, I said that I had to rejoin YPF with a firm determination to steer the company through the storm. Now only a year later, we are proud to present a fully recovered reality, delivering exceptional results on all fronts in line with guidance that we had provided.

In 2021, we managed to restore profitability that resulted in solid positive free cash flow that in turn translated into healthy reduction of our net leverage. Adjusted EBITDA for the year ended in line with guidance at USD 3.8 billion, exceeding pre-pandemic levels of 2019 by about 6%. And the positive cash flow generation achieved along 7 consecutive quarters, allowed for an aggregate reduction in net debt of around 17% or USD 1.3 billion when compared to December 2019 levels.

We have also accomplished a much needed recovery in our oil and gas production, managing to grow it sequentially along the year after 5 years of continuous decline, delivering over 14% growth in the fourth quarter compared to the same period in 2020. This was particularly possible on the back of a strategy that combined financial prudency, together with company effort to become more efficient across our operations, allowing us to fully execute our targeted CapEx program.

And at the same time, these efforts permitted us to restore a positive path in terms of proved hydrocarbon reserves, reaching remarkable growth in our reserves of around 24% and historical high reserve replacement ratio of 2.3x. Our production achievements were the result of a conscious effort to simultaneously tackle the natural decline in our conventional fields and the unparalleled opportunities to accelerate the development of our sale blocks. And while we continue prioritizing oil over gas, materialization of Plan GasAR at the beginning of the year created a renewed opportunity that we managed to successfully exploit acting as the largest bidder on the public tender and delivering on the challenging production commitments.

During the year, with outstanding progress in our operations, particularly in Vaca Muerta. Our focused approach towards revisiting our processes and engineering models permit us to continue improving our efficiency. In that regard, we achieved a tremendous improvement in our frac speed and more recently in our drilling speed, and we are capable to continue reducing the development cost in our Hub Core on the back of new well designs that resulted in lower average well cost and higher average estimated ultimate recovery.

We have recently revisited the EUR for a tight well of 2,500 meters of horizontal length at some areas of the Loma Campana block to almost 1.5 million barrels, a jump of 17% compared to previous estimates. Along the year, we have also experienced a significant recovery in the local demand for both diesel and gasoline, with particular ramp-up in the fourth quarter. This recovery permitted further improvement in our refiners runs, reaching an average utilization rate of 85% in the fourth quarter, while also leading to incremental volumes of imported fuels, particularly diesel to maintain the market fully supplied.

And to maintain our brand visibility in 2021, we launched a program to update the image of our gas stations across the country. As part of this program, which includes the system through third-party financing for our franchisee network, 68 locations revamped their infrastructure during 2021. In addition, during the year, we inaugurated the first gas station of the future in La Plata City and started works at the Chacarita gas station in the city of Buenos Aires, which will become our flagship location in coming months.

Moreover, along the year, we incorporated 30 new locations to our network to over 1,600 stations across the country, including 20 newbuilds. Customers' loyalty through innovation remains a key priority to upsell in complex market conditions, as well as following YPF on the edge of the energy transition. And this was not only a year of positive economic and operating results. We have also maintained our sustainability agenda at the forefront of our strategic decisions.

As we always remark, sustainability is at the core of everything we do and therefore, safety of our people is a top priority. In 2021, we continued showing improvements in the safety of our operations, as shown in the evolution of the index that measures the frequency of accidents per million hours of work, although higher than in 2020, given the low activity performed that year on the back of the pandemic, the results for 2021 continue delivering on the same ambitious lines established 5 years ago.

To deliver on our safety and environmental goals, during 2021, we significantly increased the budget deployed towards keeping integrity and safety of our facilities. At about USD 465 million, this budget more than doubled the figure for 2020 and resulted more than 30% above the average for the last 5 years. Among other initiatives, this has allowed us to implement a spill prevention and control system, a program to automate detection, maintenance and repairmen with focus on hazardous liquids and natural gas pipelines, as well as a strong line of action to reduce the inventory of tanks in high-risk status.

Along the same line, in 2021, we carried out almost 500,000 hours of training for directing projects and contractors focused on what we define as the 10 golden rules to save lives, which looks to encourage and promote a safety culture within the entire organization. We also maintained a safe driving program put in place in previous years, which has resulted in a relevant reduction in the frequency rate of leak or accidents that compares positively with global oil and gas industry standards.

It's also worth highlighting that our salary policy for variable bonus of executives and direct employees is based on a holistic assessment that includes not only financial and operating metrics of the company, but also sustainability goals in all its dimensions, which for the first time in 2022, will include diversity goals. Integration of a more plural and equitable workforce is not only a responsibility we have as a company throughout our diversity committee and new protocol sanctions during the year, but also because we truly believe it has immediate and long-term benefits on our day-to-day job.

Further focusing on sustainability and in line with our policy to promote cleaner and more efficient energy solutions, during 2021, we have been working hard and making good progress on the path of reducing our direct greenhouse gas emissions. Within our upstream operations, which represent half of our total emissions, we have made meaningful progress so far and much more should be achieved in the future.

Given the significantly lower emissions intensity of our shale operations, we expect to continue reducing our carbon footprint intensively in coming years and have established a target for a further 10% reduction in 2022, averaging less than 41 kilograms of CO2 equivalent per barrel produced. This is then seen in the over accomplishment of the targets put forward back in 2017, accounting for over 14% in cumulative GHG reduction and targeting a further decrease of 6.5% in 2022.

Our commitment towards this reduction continues foreseeing more than 30 initiatives for the re-carbonization of our activities, as well as having an all-time high share of renewable sources in our energy purchases for the last quarter. Outlying our energy transition initiatives, YPF lose our strategic arm to continue expanding our renewable energy matrix, has become the second largest renewable energy generator in the country after reaching COD on 2 new wind farms that added 175 megawatts to reach a total renewable portfolio of almost 400 megawatts in installed capacity.

Moreover, the company has recently announced the construction of a new 100 megawatts solar PV project in the province of San Juan, financed by a USD 64 million long-term bond recently issued in the local market. Finally, it's worth noting that we are also analyzing future projects to improve fill quality, entirely to value chain and deploy blue and green hydrogen pilots through the H2ar consortium all led by YPF technology, our research and development company in association with concept.

I will now turn to Alejandro to go further in detail into our financial and operating results. And before the Q&A section, I will share our view of the 2022 outlook.

Thank you, Sergio, and good morning to you all. As already commented by Sergio, 2021 marked a significant turning point for our company, not only recovering historical profitability levels and reducing our net leverage to sustainable levels, but also managing to stabilize our oil and gas production after 5 years of continuous decline. Our revenues increased over 41% year-over-year, reaching a total of USD 13.2 billion and standing only 4% below pre-pandemic levels of 2019. This increase was mainly supported by the recovery in fuel sales, both on higher volumes dispatched, as well as higher average prices in dollar terms.

In addition, our revenues in 2021 were also positively affected by higher prices on those products that correlate with international prices, such as lubricants, propane, petrochemicals and virgin naphtha that represent close to 20% of our total revenues, as well as higher natural gas sales, which represented about 15% of our total revenues, primarily on the back of our participation in the new Plan Gas. On the cost side, total OpEx in 2021 expanded by 1% compared to the previous year, while declining by 13% compared to 2019.

Although these savings ended slightly below our expectations with respect to pre-pandemic levels, we are still satisfied with our performance as cost efficiencies secured within the program launched in 2020, continued to be well in effect in 2021. And these savings were achieved despite mounting inflationary and salary pressures that pushed our cost structure higher in dollar terms given the context of a slow pace of currency devaluation.

Adjusted EBITDA closed at USD 3.8 billion, in line with guidance and consolidating a remarkable recovery year-over-year, even exceeding the pre-pandemic results of 2019 by 6%. Furthermore, our adjusted EBITDA margin reached 29%, standing at the high end of our metrics for the last 5 years. It is worth highlighting that the year-on-year improvement in adjusted EBITDA was achieved across all our business segments on the back of a normalization in volumes produced, processed and dispatched and an overall improved pricing environment. In addition, certain operating extraordinary items that negatively affected last year's adjusted EBITDA that were not present this year also contributed to the outstanding year-on-year improvement.

On the CapEx front, we managed to fully execute our program of USD 2.7 billion announced at the beginning of the year that was initially considered very ambitious and difficult to achieve. However, after a somewhat slower than projected pace in the first half of the year, we managed to accelerate in the second half and executing full and without jeopardizing efficiency, as demonstrated by the evolution of the development cost at our shale oil for half core hub that I will comment later on in the presentation.

And as projected, about 80% of total investments were concentrated in our upstream operations with the aim at recovering oil and gas production growth and meet our Plan Gas commitments for the year. Finally, based on the solid recovery in adjusted EBITDA, our free cash flow before debt financing totaled USD 882 million, allowing for a significant reduction in our net debt, but closed the year at USD 6.3 billion, reaching the lowest level since the second quarter of 2015 and pushing our net leverage ratio down to 1.6x, well below the threshold of 2x that we have announced as our financial guide during our last earnings call.

Our fourth quarter results also came in line with guidance, although below previous quarters given the impact of the seasonal dynamics in natural gas prices on the back of the new Plan Gas, as well as higher OpEx expenses in the context of inflationary pressures on our cost base. Revenues remained flat sequentially at USD 3.6 billion with higher fuel sales and higher prices on products that correlate with Brent being fully offset by a reduction in natural gas revenues due to the impact of lower seasonal prices.

Total OpEx increased 12% sequentially, mostly driven by the impact of the evolution of the macroeconomic environment on our cost structure as general inflation and wage increases significantly outpaced the evolution of the currency. In terms of adjusted EBITDA, it totaled USD 634 million, 28% below the previous quarter, but standing 26% above the same quarter of 2019.

Within business segments, higher OpEx impacted across the board, while upstream was particularly affected by seasonality in natural gas and downstream benefited from higher process volumes and better pricing on products with high correlation to international prices, but was negatively affected by higher fuel imports and higher prices on crude purchases among others.

On the CapEx front, in Q4, we executed the highest activity of the year, deploying over USD 900 million with increases across all business segments, but maintaining our focus in upstream activities, which represented 77% of total investments. Finally, these results translated into yet another quarter delivering positive free cash flow before debt financing, the seventh in a row, totaling USD 143 million in the quarter and leading to a decline by another USD 184 million in our net debt.

Focusing on our upstream business, we are proud to have achieved our key goal of stabilizing our total hydrocarbon production after 5 years of continuous decline. And on a sequential basis, we managed to continue expanding our oil production by 3.2%, although total production was down by 2.3% due to program maintenance works at our subsidiary MEGA and certain gas pipelines that led to the curtailment of some gas production and negatively impacted NGLs.

Furthermore, looking into the evolution of total production along the year, we have achieved remarkable growth of 14.5% when comparing the 4Q '21 with the same period in 2020. The sustained recovery in production along the year was driven by the impressive expansion coming from our shale blocks with shale oil increasing by 62%, all the while shale gas almost doubled in the year. As a result, shale accounted for 35% of our total consolidated production in Q4, growing from 21% only a year ago.

And we are also proud to mention that net production in the fourth quarter out of our shale oil core hub came above guidance provided during our 2020 earnings call a year ago at 53,000 barrels per day. Regarding prices within the Upstream segment, during the quarter, natural gas prices were negatively impacted by the seasonal adjustments stipulated within the new Plan Gas, reducing natural gas prices to an average of USD 3.1 per million Btu. On the crude oil side, our average realization price increased by 4.4% on a sequential basis to about USD 58 per barrel, only partially benefiting from the rally in international prices, as local crude continued being negotiated between local producers and refiners in a way to smooth out the impact of the volatility in international prices into local pulp prices.

In terms of activity within our unconventional upstream operations, in the fourth quarter, we completed a total of 36 new horizontal wells in our operated blocks, 29 shale oil and 7 shale gas wells. Although slightly below the activity performed in the previous quarter, in which we have completed a record high of 44 new wells, the fourth quarter results rounded an impressive annual campaign as we have completed an all-time record of 138 horizontal wells in the year. Our previous record registered back in 2018 was at a significantly lower level of 91 wells.

As stated in previous calls, in setting this record, we took advantage of the above average backlog of drilled but uncompleted wells that accumulated in 2020 on the back of the pandemic. But we have also kept drilling activity high as well, although closing the year with (inaudible) inventory slightly below our target. In terms of efficiencies, during the fourth quarter, we continued achieving steady improvements in our performance on fracking and drilling speed, averaging over 230 meters per day in drilling and over 180 stages per set per month on fracking.

And we're adding a multiyear evolution of our key operational metrics, it becomes easier to understand the impressive reduction in development costs at our shale oil core hub. When comparing to 5 years ago, our shale oil development cost declined by more than 50% to an estimated average of USD 7.2 per barrel in Q4 2021, resulting in a full year estimated average of USD 8.2, well below the guidance provided a year ago of USD 9.2 per barrel. Our operating improvements and development plans for our shale resources also contributed significantly to the evolution of reserves.

Total group reserves expanded 24% year-over-year to over 1.1 billion barrels of oil equivalent, recording the highest metric in 5 years. More specifically, crude oil reserves increased by 33%, while natural gas P1 reserves expanded by 16%. The addition of proved developed and undeveloped reserves totaled 393 million barrels of oil equivalents in 2021, mainly driven by the progressive developments and expansion of our unconventional operations, coupled with the effects of variations in prices and costs. The addition of P1 reserves during the year in relation to the total hydrocarbon production of 171 million barrels of oil equivalent, resulted in a reserve replacement ratio of 2.3x in 2021, the highest for the last 20 years.

Furthermore, net sales P1 reserves increased by 57% in the year, achieving a remarkable reserve replacement ratio of over 4x, now representing almost 50% of our total reserves. Our developments within our shale oil core hub and shale gas blocks, such as El Orejano and Rincon del Mangrullo, among others, having the largest contributors to these results. On the other hand, on the conventional side, reserves additions were supported by the positive results achieved in the Gulf of San Jorge basin with the expansion of tertiary recovery projects in Manantiales Behr and the acceleration of de-risking of Los Perales, El Trebol; and Canadon Leon.

Looking into our downstream operations, domestic fuels demand was especially strong in the last quarter of the year. increasing 9% compared to the previous quarter and even surpassing by 7% pre-pandemic levels of 2019. The increase was primarily driven by gasoline demand, which jumped 15% on a sequential basis, while domestic diesel demand increased by 5%.

In terms of refinery utilization, our processing levels have further recovered in the fourth quarter, resulting in a sequential increase of almost 6%, reaching an average utilization of 85%. Even though this average is in line with 2019 levels, we are still well below historical averages of around 90%. The reason for this being our need to still source about 20% of total processed crude from third parties in the middle of a complex negotiations with local producers, given the discount of local crude prices to rallying international prices. As a result, during the quarter, we increased imports of premium diesel and to a lesser extent, premium gasoline to fulfill local demand within our retail network.

Moving into fuels pricing in the local market. During the fourth quarter, we maintained a prudent approach in the context of high volatility in international prices. The slow pace of the currency devaluation and the overall economic environment in the country. Retail pump prices, which affect about 50% of our total revenues were almost flat in the quarter. This resulted in a 3% quarter-on-quarter deterioration in average gasoline prices measured in dollars, while average diesel prices remained flat, benefiting from the continuation of our strategy to reduce discounts to the wholesale segments that permitted to mitigate the effects of the currency devaluation.

And more recently, in early February, we introduced a 9% price hike to regular fuels with an additional 2 percentage points on premium qualities to catch up with the depreciation of the currency and on the back of the consolidation of the rally in Brent prices. Separately, during Q4, we continued benefiting from high prices on our products that correlate with international prices, which represent about 20% of our total revenues. These products include petrochemicals as well as lubricants, propane and virgin naphtha among others.

During '21, we also managed to further increase the penetration of our app reaching over 2.7 million active users by the end of December, an increase of 75% compared to the previous year and generating over 4 million transactions in December alone, representing 18% of total transactions compared to about 12% at the beginning of the year.

Switching to cash flow. Despite the reduction in adjusted EBITDA in the fourth quarter, we continued delivering very healthy operating cash flow on the back of positive working capital valuation, staying above the USD 1 billion mark and accumulating USD 4.2 billion for the 12 months as of December '21. The strong generation of operating cash flow, combined with a significant reduction in cash interest expense that reached the lowest level since 2013, permitting not only to cover the investment program for the year, but also resulted in a significant reduction in net debt, as previously commented.

In terms of cash management, during the fourth quarter, we have continued with an active asset management approach to minimize FX exposure in the context of still limited available instruments in the local market, ending the year with a consolidated net FX exposure of around 16% of total liquidity, stable vis-a-vis the previous quarter.

Finally, we ended the year with a total liquidity of USD 1.1 billion, in line with our target, although currently assessing whether we should operate with less average liquidity in the future given that short-term financial obligations have decreased significantly. On that note, our total consolidated financial maturities for 2022 amounted to less than USD 700 million as of December of last year, the first time in many years that liquidity comfortably exceeded short-term maturities.

Furthermore, the recent USD 300 million cross-border A/B loan obtained by a group of financial institutions led by CAF, further reduces our short-term financing needs. This transaction was possible after several months of work, showcasing YPF's ability to access cross-border funding even in the middle of the undergoing negotiations between the sovereign and the IMF.

In addition, even though the central line has extended regulations that limit the ability of Arginine companies such as YPF to fully repay cross-border financings that come due until June of this year, it is our understanding of such regulations that the CAF led transaction once fully disbursed at the end of March, will serve to comply with such restrictions, granting us access to the official FX market to proceed with our international bond amortizations in coming months.

Finally, it is worth noting that the significant reduction in net debt that took place during 2021, particularly reduced our exposure with relationship banks and the local market, providing us with ample room to adapt those sources if needed in the future.

I will now switch back to Sergio to go through our outlook for 2022.

Thank you, Alejandro. Before moving into the Q&A section, I would like to provide you with a quick glance at our 2022 outlook. First and foremost, we shall continue prioritizing profitability and financial prudency in a challenging macro environment. Uncertainties related to the future evolution of the global economy, together with geopolitical tensions and our impact on international oil prices, will probably add to local volatility. In such a context, we shall maintain our focused effort to deliver profitable production growth, so an enlarged CapEx program in great measure financed through operating cash flow.

We are, therefore, committed to maintain our prudent financial approach establishing a maximum net leverage ratio target of 2x, in line with what we have commented in previous calls. To that end, we expect to continue adjusting prices at the pump in a prudent and sustainable way to counteract the effects of the depreciation of the currency, while also aiming to reduce at least partially the spread between local and international prices. However, we shall remain conscious of the Argentine economy reality that will probably make it difficult for our sector to fully track rising international prices.

Nevertheless, we feel confident in our ability to fully execute our CapEx program of USD 3.7 billion, which represents an increase of more than 40% when compared with the amount deployed in 2021. These investments will once again be concentrated in our upstream activities, where we plan to deploy USD 2.8 billion, USD 1.6 billion of which going into our conventional operations. Within the investments in unconventionals, we shall invest more than 50% on a net basis in our core hub sale oil operations, encompassing the Loma Campana, La Amarga Chica and Bandurria Sur blocks.

And from now on, including also a Aguada del Chanar block, constituting the first shale oil block within our core hub to be 100% owned by us and where we have just connected 2 wells during December with early promising results. YPF net investments in the core hub operations shall include about USD 100 million in facilities, including the third train within the oil treatment facility at La Marca Chica and a new oil treatment facility at Bandurria Sur, with the remainder being devoted to drilling and completion activities. In that sense, we expect to tie in close to 100 new wells during 2022 while drilling activity should be somewhat higher to build back a slightly larger debt portfolio to prepare for further growth in 2023.

And we are also expanding our shale oil development beyond the core hub. In 2021, we signed together with our partner, Equinor, a new unconventional exploitation permit in the north portion of the Vaca Muerta oil window, forming a new concession called Bajo del Toro Norte with an area of 114 square kilometers, where we plan to tie in 6 new wells in 2022.

As a result of these investments and on the back of the significant ramp-up in production along 2021, we expect our total hydrocarbon production to increase by about 8% year-over-year, representing the largest organic production growth for our company in the last 25 years, including an estimated 50% jump in shale oil production coming from our core hub. Given the current state of production out of the Neuquina Basin and taking into consideration future growth plans, we have decided to emphasize our focus in coordinating midstream initiatives to bottleneck the future evacuation of oil and gas production out of Vaca Muerta.

In that sense, we have created 2 new business units within our organization to lead the efforts on both the midstream oil and midstream gas fronts. These teams have the critical task of identifying and executing all necessary plan to enlarge processing and transportation capacity, including the interconnection to the recently announced new gas pipeline put forward by the federal government as well as investments required on the midstream oil side to enable further opportunities to Chile as well as through the Atlantic.

Finally, on the downstream segment, we will continue with the multiyear investment plan to revamp our La Plata and Lujan de Cuyo refineries to adapt to new field specifications, resulting in lower sulfur fuels that will help to reduce our Scope 3 GHG emissions. During 2022, estimated CapEx for this project was around the USD 150 million to USD 200 million range out of estimated CapEx of USD 800 million for the next 4 years, with the reminder investments within the segment for 2022 being deployed to finalize the adaptation of our refineries to process lighter crudes, regular maintenance of our facilities, the continuation of the new branding initiative within our retail gas stations and efficiencies and sustainability initiatives, among others.

Before turning into the Q&A section, I would like to once again tell you that I'm especially proud of the YPF team of their commitment and their efforts without whom the remarkable results achieved in 2021 would not have been possible. And as always, I also want to thank our clients for their fidelity and our investors, partners and suppliers for their continued support. We are now open for your questions.

(Operator Instructions) Your first question comes from the line of Bruno Montanari from Morgan Stanley.

I have 3 questions. First, your budget for CapEx this year is increasing USD 1 billion. So I'm curious to what you're assuming on the budget happens with the oil price in Argentina. So do you expect oil to remain at USD 57, USD 60 per barrel level? Or do you plan to increase crude oil prices as well? The second question is about mid to long-term debt maturity. There is quite a bit of debt coming due in 2023, 2025. So, today, what is the strategy of the company to cover those maturities. I imagine you'll invest a sizeable amount in CapEx to recover production. And third, taking into consideration the very high level of oil prices today, has the company been approached by interested parties to acquire acreage in Vaca Muerta and would you be willing to monetize a portion of the excess acreage to help bridge the funding requirements in the coming years?

I'm going to take the question about oil prices and local pricings of oil. And let me answer in a broader sense. As already commented during the presentation, we will continue monitoring evolution of key variables, such as the depreciation of the currency and international oil prices to determine the merits of further adjustments of the plan. However, given the increased volatility that international markets have experienced in recent weeks, we do not expect to fully track international prices, but rather accept some alignments, particularly as we shall remain very conscious of the undergoing economic situation in the country.

With respect to the discount versus import quality and after a significant reduction in the spread to import parity in early December when Brent prices moved around USD 70 per barrel, the rise during the last couple of months, particular spike on the back of the last couple of weeks, has pushed the spread higher. Consequently, after bottoming at about 10% on average of all fields by early December, the discount to import quality has been increasing since then, finishing January at about 30% and by the end of February, remaining close to that level as the price adjustment performed in early February compensated to further appreciation to international prices up to that point.

However, the most recent rally in international prices that took Brent above USD 110 generated further distortion. We would expect to remain active to maintain our dollar margins at least stable. This year, while at the same time, evaluating the convenience to reduce the gap to international parities. All in all, we expect to continue working in a collaborative effort with most factors in our sector to continue moving out the full effect of this volatility to local consumers.

Alejandro, you want to take the second question to maturities.

And just to complement that as well on the general context on our view on pricing, as it relates to budgetary purposes, we -- basically, we run our budget at the beginning of the fourth quarter. So, the assumptions on crude oil prices and pump prices was taken at that time. So clearly, when put in the context of current prices, our budget would be conservative in the sense of the prices that were assumed, both in terms of crude and pump prices.

So, clearly, we could have some upside there. But of course, as Sergio was saying, we will need to be very prudent in monitoring the evolution of the volatility to see how that -- the rally in international prices and the volatility brought by the evolution of prices globally will end up impacting both local food and pulp prices, and in that sense, affect our budget for the year.

Then into the maturities, as you were asking, debt maturities for '23 to '25, what we see is that the shorter term, mostly 2023 and 2024 maturities are being leveled that we feel are very manageable for -- basically for historical standards for YPF was and what we expect for our ability to manage them in the future. They are in the order of USD 850 million in each year, mostly composed of international bond maturities. And of course, we cannot say or predict what availability we will have in terms of access to funding in international markets.

But what we do have is, as was mentioned in the presentation, during 2021, the reduction in net leverage allowed us to reduce very significantly the balances that we have outstanding with our financial institutions, mostly our most relevant relationship banks, as well as the local market. So, in that sense, we see that we have ample room. Of course, the remainder of 2022 is very well taken care for because as you know, we -- A/B loan already secured. The rest of the maturities in '22 are very manageable.

And then for 2023 and 2024, we feel that the availability of lands that we will have in financial institutions, both local and global, as well as the capacity that we have to tap on the local market. should enable us to manage those maturities fairly well. Then going into 2025, of course, we do have about maturity on our 2025 bullet bond, international bond. So by that time, we would expect to be proactive in managing those maturities well ahead of time. Of course, that will depend on the evolution of the international market as it relates to appetite for Argentina and YPF in particular. But we believe that we have time for that. But of course, we monitor those opportunities very regularly and we will access the market whenever we feel that is the right time to proactively refinance or take that maturity ahead of time as soon as a possibility arise or materializes.

And then finally, on your question about opportunities for joint ventures or divestments in Vaca Muerta, as was commented in previous calls, we still see that devaluation distortion that we have vis-a-vis potential interested parties and I think that mostly relates to the overall risk of entering new investments into the country is very well apart. So, at this point, we still sense that relevant transactions are probably not going to take place in the near future. And so, we are not taking that into consideration to -- as part of the financing sources for our CapEx plans for 2022 nor the following years in any material way.

Of course, if anything actually comes up and valuations do come significantly closer, we will definitely entertain those conversations. We believe that anything that could potentially accelerate the development of the Vaca Muerta exploitation, it's positive. But again, at this point, we are not seriously considering any such alternative.

Your next question comes from the line of [Konstantinos Papalos] from Plenti.

Congratulations on your results. I'd like to ask 2 questions today, more related to your income statement. There's a USD 338 million other cost figure on your upstream income statement. What cost does it entail? And why did it increase so fast on a quarterly basis? And also regarding downstream financials, could you shed some light on your margins on fuel imports? Are they positive or negative? And what was the impact on downstream EBITDA in this fourth quarter? I'm referring to diesel, ultra-low sulfur diesel and gasoline imports for the local market?

I think relates to your income statement question and the other -- the line of other income or expenses. It mostly relates, as you will find out going deeper into the financial statements with some adjustments on the provisions for legal contingencies during the quarter. So, when you will go into that specific line, it mostly relates to that.

Of course, also when comparing to the previous quarter, also has some positive results in the third quarter that are not present this quarter related to the divestment of some real estate assets, but generating other income in the third quarter. But then when you look at specifically the charge in the fourth quarter, as I said, it's mostly related to -- with the evolution of that specific account on provisions for legal contingencies in general. Of course, that evolution has a mix of different things. But generally speaking, it's the best assessment in terms of provisioning our contingencies by the end of the year.

And then on your question of fuel imports. Clearly, during the quarter and as was mentioned during the presentation, we have increased the amount and the volume of fuel imports, primarily related with the significant growth in demand that we experienced in the quarter. As was mentioned already in the presentation, total demand for fuels in the local market increased by 9% in the quarter. Part of that sourced through higher processing levels which increased by 6%. But then the remainder was taken care through clearly imports.

Mostly, as clearly as you know, we keep on acquiring about 20% of our crude purchases of our -- the total crude profits from third parties. And so, also given the discount international prices versus local crude prices, it became a little tougher to source local crude to further improve our processing levels at our refineries. So the remainder was sourced from imports. And in that regard, also the increased volume of imports which mostly for diesel, which is the largest portion of our fuel imports ended up with the same thing about 20% of our total diesel sales in the quarter. That is significantly higher than the historical average of around 10% of total diesel sales sourced through import -- imports.

That amount also -- that volume also included specific buildup in inventories that we adjusted in the fourth quarter, given the larger or higher average daily demand. So, when taking out that specific consideration for the buildup of inventories and looking into the evolution of local demand in the first quarter of this year, going forward, we would expect the -- that figure, the average of imports versus total diesel demand to go down to about 15%.

And also, take into consideration that that number also basically counteracts the effect of smaller portion of biofuels, biodiesel, particularly in our diesel mix, which went down from over 10% in the past to 5%, given the adjustment in regulation. So, also that is another source of demand for imports, which need to compensate that lower proportion of biofuels in our overall fuel mix.

Your next question comes from the line of Andres Cardona from Citigroup.

Congratulations on the financial results and also because of the very solid result report. I guess I have 2 questions. I'm now going at the very beginning of the question, you said that you were revising upward you estimate to 1.5 million barrels of oil equivalent for some projects. Can you say what type of projects are these? I imagine its La Amarga Chica, Bandurria Sur and Loma Campana among right here. The second question is if you are seeing a relevant inflation cost pressure in the absent segment in particular? And the last one is if you can remind us how much is the receivable about Plan Gas as of the end of last year?

Thank you, Andres. On the EUR question, it is very specific on Loma Campana, on the Loma Campana block that is we are targeting activity specifically related to the La Cocina segment of the Loma Campana block, and in that specific area we adjusted our tight well. And in the context of that tight well for well we lay of 2,500 meter of horizontal drilling, basically 2,500 meters horizontal length, we have adjusted the average EUR by 17% higher to 1.5 million barrels.

So it is very specific to that well and also to that block and to that segment. But clearly we are seeing, given the new engineering that we have put in together and the extension in the average horizontal length on our tight wells that overall EURs are trending upwards. And so, clearly, that helps also our improved development costs. On our upstream costs, yes, definitely on our upstream costs, yes, definitely. We are seeing inflation pressures both from service inflation and particularly wage pressures, salary pressures, mostly given that those levels, inflation and salaries are running faster than the depreciation of the currency. So in dollar terms, we are seeing pressure on our lifting cost both in the conventional and the unconventional segments.

However, it would be interesting to say that when you look at the average lifting cost for the year, we were still about 8% below 2019. When looking specifically at the fourth quarter, on average we were relatively in line with 2019. But then on that -- on the different -- on the composition of that average lifting cost, we can point out that our overall lifting cost on conventional blocks went up clearly on a yearly basis, right, I'm saying, it went up. But that is primarily as a result of the significantly lower production coming out of our conventional activities.

Just to put it in context, our production when comparing the fourth quarter of 2021 with the average of 2019, our production on those fields came down by 25%, of course, more than or compensated to a large extent with our increase in unconventionals. But then at the same time, our overall lifting cost went up in a lower proportion. So basically the unit -- on a unit basis it went up, but again, on less than that the reduction on the overall production.

And the opposite happened with our unconventionals where we had significantly lowered on a per unit basis when compared to 2019, of course, helped by the increased production out of those logs where our overall average lifting cost in the fourth quarter was below USD 4 per barrel in unconventionals, which is a decline of about 25% when compared to the 2019 season. So, all in all, we do see pressures, but we are managing to keep our costs under control. But of course, going down the road, if these inflationary pressures in dollar terms continue, we -- it will be partially mitigated by the further increase in the proportion of shale on the total production portfolio, but definitely, cost pressures will likely be there.

No, sorry. And finally, there was a question on receivables from the Plan Gas. I would say as of today, payments are very regular -- for the most part regularized. As you probably remember, payments on the new Plan Gas are divided in 2 parts. First, there is the first installment for 75% of your invoice, which has to happen within 30 days of invoicing. And then there is the remainder 25% that is already scheduled to be paid with some delays from with some delays from the specific regulation another 30 days, basically leaving extra time for the authorities to come up with the final figures and confirm the final figures provided by each producer.

On that regard, what we are seeing is that the payments on the initial 75% are pretty much regularized and we have a very minor delays of about another 1 month there. But then, yes, on the remaining 25%, we do have some receivables that have accumulated as we only collected there the 25% portions of the invoices from January and April of last year of 2021, with the remainder pending payments. That amounts to about USD 30 million as of today.

Your next question comes from the line of Regis Cardoso from Credit Suisse.

Couple of follow-ups questions on topics we've already sort of glanced on or touched on. First is considering the cost inflation, I wanted to get a sense if you believe you need price adjustments to make up for the cost inflation in order to achieve your EBITDA expectations or, I mean, or whether you already embedded in that guidance sort of the expectation that you would have declining margins on the back of that inflation rate?

And then still on the topic of the price adjustments, of course, now with oil prices trending significantly higher at USD 110 oil prices trading significantly higher at USD 110 barrel Brent, how do you see this play out in Argentina? Do you think you would be able to pass through these higher prices or, instead, would you expect the government to fund the importation of diesel gasoline, assuming that the country might become net importer throughout 2022?

And then just finally, if I may, one question regarding the number of drilled and uncompleted wells. The number of wells has declined from 76 in 2020 to 47 now. Just wanted to get a sense of how should we interpret this. Is it because you're being more efficient in tying up the wells or is it, in any way, something that you have less wells to put on stream now or that your activity has slowed down in the fourth quarter?

In terms of your first question about cost inflation and how we treated for budgetary purposes, of course, when putting together our budget, we put together our own assumptions in terms of macroeconomic variables and how they will translate into our cost base. And so, when we put out our guidance in terms of CapEx and the potential free cash flow effect of that CapEx, saying that we might be in the neutral to slightly negative territory, we do have contemplated our assumptions on inflationary pressures.

As I said, that also contemplated conservative prices in terms of U.S. in crude. And it's hard to say at this point how both things will end up playing out. But at least, to trying to answer your question, at least, we can say that we really take into consideration the impact of inflation and how it plays out with our view on the devaluation of the currency during the year in terms of their impact on our cost structure. What I can say is that, clearly, that generates an increase based on our budget assumption that would increase our cost base, generally speaking. And again, that is considered in our assumptions for free cash flow, EBITDA generation, and free cash flow for the year.

Then on your question of price adjustments and the evolution given the current context, clearly, Sergio has already touched upon that issue in terms of our view very specifically related to the current situation of prices above 110%. What we can say that, again, repeating what Sergio was saying, we need to remain cautious and prudent in figuring out how the different variables play out. We definitely -- and also, as mentioned in the presentation, we are very focused on at least maintaining our dollar margins.

And by that, meaning that we should at least adjust prices to absorb the evolution of the currency and, of course, also aim at reducing at least partially the spread to international prices. How successful we are going to be on that, it's still a question mark. And again, that not only depends on our wheel, but also on the general context of the macroeconomic situation in the country and the potential demand effects that that could have. Of course, this is also related and casts an important correlation to the price of crude locally. At the end of the day, both variables go together. And, of course, as long as we cannot fully translate international policies to the pump, that unfortunately also affects the pricing for local crude.

But, again, that has been a constant negotiation between upstreamers and downstreamers. Clearly, we are mostly integrated but still, on a net basis, are a downstreamer because we still acquire about 20% of our crude -- of total crude from third parties. But that's a constant negotiation for the last few months between upstreamers as and downstreamers. It has become a little more tense, of course, given the current situation in international prices. But we are still hopeful and expect those -- the consensus and the reasonability among all parties to be sustained and to be able to continue sourcing the local demand in a fair way with logical profitability for different segments along the value chain.

And finally, on your question about DUCs, yes, as mentioned within the presentation, the total balance for DUCs has declined over the year. And particularly in the fourth quarter, we took advantage of the -- and we explained that at the beginning of the year, we took advantage of the larger than usual DUC inventory that was a result of the mostly coming out of the pandemic to accelerate production growth through further timings and drilling activity. However, we kept drilling activity high and that's how we still managed to keep a healthy level of DUCs.

Going forward, we are probably likely going to see some increase in this inventory of DUCs, but marginally down the road because we feel that we have roughly speaking, on a level that provides enough flexibility to our operations. When looking at the number of drilling rigs and frac sets that we should have in operation during the year. So most likely you are going to be somewhere between this number and the figure of published in the previous quarter, somewhere in that range we will manage our DUC inventory on our shale, operated shale blocks.

Your next question comes from the line of Ezequiel Fernandez from Balanz.

I have 3 questions I would like to go one by one, if you don't mind. My first question is related to the refineries utilization. YPF is near 90%, if I'm not mistaken on this last quarter, and this is important not only for the company but also for the country from an FX reserves perspective. How high you think you can go in 2022 in terms of utilization? And would you expect perhaps older refineries that have been inactive during 2020 and 2021 not owned by YPF, other refineries in Argentina, to go online this year and if this higher utilization is going to translate into lower exports as a -- on the country as a whole crude exports.

Hi, Ezequiel. Okay. To start with that question, yes, as mentioned, utilization at our refinery has recovered in the fourth quarter. Part of that has to do with the -- with an increase in demand. Part of that also has to do with lower utilization in the third quarter given some maintenance work program, maintenance work that we were executing during the quarter primarily between July and August. So that pushed our utilization rate in average to 85%. And although improved from the previous quarters and coming out of the pandemic that is still below the average of 90% that we used to have in the past.

And now how we expect that down the road, it has to do with I was just commenting before in terms of the negotiations between downstreamers and upstreamers in terms of sourcing local crude to further increase utilization rate on the refineries. So based on that and given the spread of local crude prices to export priorities, we probably have done -- we would like to see, but we probably are not going to see a significant further increase on the overall utilization rate of the refineries.

Of course, we also don't expect local demand to continue increasing at the levels that we experienced in the fourth quarter. Actually, for the first quarter, we are already seeing demand being stabilized and potentially even a little bit lower than the fourth quarter, particularly in January local demand decelerated and then it bounced back a little bit in February. But overall, in the first quarter, we are likely to see a little bit of a lower demand compared to the fourth quarter.

And then given that and of the same level of utilization rate that our refineries are potentially slightly higher during the year. What we are likely going to see is that the imported volumes are going to remain high throughout the -- on a year to year basis higher than 2021 because the ramp-up in imports last year took place mostly in the fourth quarter. So, when average quarter is probably below what happened in the fourth quarter because as we commented before the fourth quarter was also unusually high because of the buildup in inventories. So, most likely on average, we are going to see lower level of imports compared to the fourth quarter, but on a year-over-year basis, our total volume is likely to be higher than 2021.Hi, Ezequiel. Okay. To start with that question, yes, as mentioned, utilization at our refinery has recovered in the fourth quarter. Part of that has to do with the -- with an increase in demand. Part of that also has to do with lower utilization in the third quarter given some maintenance work program, maintenance work that we were executing during the quarter primarily between July and August. So that pushed our utilization rate in average to 85%. And although improved from the previous quarters and coming out of the pandemic that is still below the average of 90% that we used to have in the past.

And now how we expect that down the road, it has to do with I was just commenting before in terms of the negotiations between downstreamers and upstreamers in terms of sourcing local crude to further increase utilization rate on the refineries. So based on that and given the spread of local crude prices to export priorities, we probably have done -- we would like to see, but we probably are not going to see a significant further increase on the overall utilization rate of the refineries.

Of course, we also don't expect local demand to continue increasing at the levels that we experienced in the fourth quarter. Actually, for the first quarter, we are already seeing demand being stabilized and potentially even a little bit lower than the fourth quarter, particularly in January local demand decelerated and then it bounced back a little bit in February. But overall, in the first quarter, we are likely to see a little bit of a lower demand compared to the fourth quarter.

And then given that and of the same level of utilization rate that our refineries are potentially slightly higher during the year. What we are likely going to see is that the imported volumes are going to remain high throughout the -- on a year to year basis higher than 2021 because the ramp-up in imports last year took place mostly in the fourth quarter. So, when average quarter is probably below what happened in the fourth quarter because as we commented before the fourth quarter was also unusually high because of the buildup in inventories. So, most likely on average, we are going to see lower level of imports compared to the fourth quarter, but on a year-over-year basis, our total volume is likely to be higher than 2021.

And I don't know if you can touch a little bit on what might happen with some other refineries in Argentina that could go online for you or not?

Well, generally speaking, we do know that some of our competitors are having some major maintenance as we speak, so that can also generate some extra imported volumes. Beyond that, we -- I particularly don't know of any I particularly don't know of any specific issues on the refinery system overall during the year. So, unfortunate -- no more color that I can share at this point. I will definitely talk to our downstream experts and if we have any particular additional color, we will definitely revert to you.

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

I definitely want to come back in -- I don't know, one on the cash flow, and I would like the slides 12 and 13 of the presentation. They are really helpful. But looking to 2022 when we try to reconcile the cash flow for the current year, I don't know, even considering significant increase on the EBITDA level -- we still see like a lower, I would say, cash position than the USD 1.1 billion that you ended the year. I mean, you still have some debt to be paid and the USD 3.7 billion on CapEx and reconciling near to the cash flow, we end 2022 with, I don't know, USD 0.4 billion, USD 0.5 billion in cash. So just trying to understand first, if that makes sense considering no debt roll over. And in that front, how you guys are planning to renegotiate the USD 700 million that you have that expiring in 2022?

And the second question it's with regard to the IMF agreement with Argentina, I mean, there are lots of, I don't know, moving parts that -- with lots of parts touching about the energy sector and the government subsidies in that front. So just trying to understand also how this agreement might impact if positively or negatively the company and sector with regards to the freedom to price to follow the international markets pricing looking forward.

And we do have a follow-up question from the line of Ezequiel Fernandez from Balanz.

Sorry. Operator, can you hold 1 second because we need to answer Luiz' question? Sorry, Ezequiel. Follow on a minute, please.

Luiz, okay, let me address your questions. Clearly on the cash flow issue, of course we are not yet disclosing our budget in terms of adjusted EBITDA for the year. I will do say that we are not expecting any significant increase compared to the results on 2021. And I should clearly say we do have an ambitious CapEx plan that has to be financed.

But then, also, we need to bear in mind that, well, on the one hand, our total cash expense for the year is expected to decline as the average amount of debt has trended downwards compared to the average of 2021. And then, we also say that we do have some positive working capital variations expecting in expecting in 2022, mostly related with the collection of some receivables that we still have in our balance sheet by December. Part of that related to gas distribution; for example, clients that we are collecting during the year and some other working capital adjustments that we are forecasting.

And then, of course, we are also saying that we might end up having a relatively small negative free cash flow during the year that which -- it might require some incremental debt, although we are saying also that incremental debt will be capped at -- not to exceed a net leverage ratio of 2x during 2022. And, clearly, on that regard, we -- as I said before, given that the nominal maturities that we have during the year are mostly taken care for already and the receivable maturities are very small and given that the total balance in outstanding facilities with relationship banks, as well as our exposure to the local market, it's a minimum in for many years.

We do feel that we have ample room to tap on those sources to fund those net needs that we may have and as I said, of course, maintaining and keeping the maximum leverage ratio of 2x. And if anything, if for any reason, our operating cash flow is not enough to do that and as we said last year, that might affect our total CapEx plan for the year. But at this point, we feel confident that we should be able to fully fund the USD 3.7 billion CapEx program within the assumptions that I have just laid out.

And regarding the potential impacts on the IMF negotiations, well, clearly it's hard to say. Generally speaking, we don't see a direct impact on our particular business. As you know both on the side of crude oil, local crude oil and pump prices, there are no subsidies to be eliminated or to be reduced by the government. And on this side of potentially reducing subsidies on other segments, well, that could have potentially an impact on some of our subsidiaries like Metrogas.

But I would say that it would be only marginal for us. Clearly, the overall context of inflationary pressures will play out on the ability to adjust prices at the pump. But that also relates to the questions asked before in terms of our vision or views in terms of how we see prices evolving along the year, which Sergio tackled already and I commented also briefly before. So unfortunately, not much to say. We don't expect to see any significant impact deriving specifically from the IMF negotiation into our business.

Ezequiel Fernandez, your line is now open.

So basically, I had 2 questions. This should be quick. The first one is related to -- in your budget for 2022 or your guidance. How much are you contemplating to get us inflows from working capital management? And my other question is related to the -- well, the new hydrocarbons law is probably not moving forward or at least is stalled in Congress, but it seems that the chapter on fuel tax offset could be set for approval in a couple of months. I don't know if you have any updates on that front.

Sorry, can you repeat your first question because we -- the line was a little bit cut off and we couldn't fully grasp it?

Sure. In your guidance, in your budget for 2022, how much are you considering -- how much money is coming in due to working capital management?

Okay. Again, as we are not -- because if we specifically talk about working capital, we are putting together full assumptions on adjusted EBITDA, et cetera, right? Unfortunately, let me, at this point in time, not be so specific, because clearly, we see some volatility, and that's why we prefer to be prudent at this time and not fully disclosing our specific budgets in terms of adjusted EBITDA and specific working capital. What I do can say is that, as I mentioned on Luiz's question, we do expect some positive impacts, not huge, not major, but we do see some positive impact on the working capital contribution.

And in terms of the hydrocarbon law, yes, clearly, as we speak, we don't have too much clarity on what will end up happening with it. Clearly, given general views, we would tend to say that it might -- the actual project that was presented to congress might not actually be approved. Basically, we understand that there are some concerns about the complexity and the technicalities incorporated into that loan, into that project.

But we do see or we do expect to see maybe a shorter, a more specific project or law that would touch upon certain aspects that need to be addressed in the near future. Part of that is the fuel tax that you were asking about. So, we do expect that to be clarified and put forward in the near future to provide more stability and clarity in the way of anticipating the evolution of that component.

And your next follow up question is from [Konstantinos Papalos] from Plenti.

Just a follow-up on Ezequiel's question on refinery utilization. We are forecasting higher fuel needs for the power generation sector in Argentina viewing the price -- the international prices for LNG. So are you forecasting a positive impact on the power sector gas oil needs and does it perhaps mean that you could score higher crack spreads on eventual additions and volumes for diesel and fuel oil towards the power generation sector? And just one quick one, you mentioned debottlenecking infrastructure for evacuating volumes from Vaca Muerta, of course, could you share with us a ballpark estimate on the CapEx required to fulfill this goal and how much evacuation capacity would it add?

Thank you, [Konstantinos] for that comment. I'm going to take your second question. As you know, total production from all producers out of the (inaudible) very significantly in 2021 from about 250,000 barrels per day in December 2020 to an average of about 320,000 barrels in December 2021. It is not a -- it's a level not seen since 2003. And this incremental production is an excellent news -- was the result of a jump in shale oil production led by our company increasing production by 62% over a year, and reaching almost 140,000 barrels per day gross in December.

This ramp-up in production was more pronounced than previously expected by the industry, and that resulted in the need to anticipate investments in midstream oil to the bottleneck and enable the continuous expansion of Vaca Muerta. And these investments, a large portion of which is will ease and will be carried out through our midstream subsidiaries, Silvina del Valle in which we have 37%, and (inaudible) in which we have a 30% participation include different initiatives.

In the eminent, in the future of the del Valle's and they're going to revamping of 4 compression stations that have been idle for over 10 years, which will add about 25,000 barrels or about 10% of evacuation capacity to Puerto Rosales and in the second quarter of this year. And for this, the investment is around USD 50 million. And in addition, the revamping of the other 4 pumps and stations currently in operation and more than 500 kilometers of new loops are expected to further run about 200,000 barrels per day of additional capacity during 2023 with a CapEx estimated by O del Valle in around USD 400 million to USD 450 million.

On this note, the investment plans also contemplate the expansion of a storage capacity at Puerto Rosales by our subsidiary, OTA, to provide further export flexibility through Atlantic. (inaudible) works are also being performed at the current facilities on the Trans-Andean oil pipeline with (inaudible) OTC which we have also participation to put them back on line expecting to have the pipe up and running by the end of the year or beginning of next year with an initial export capacity of about 35,000 barrels per day with a final target after putting together a new oil pipe of about 150 kilometers from the core of Vaca Muerta to Fernandez of over 100,000 barrels per day in the second half of 2023.

This is more or less the strategy that the industry is following with respect to the acquisition of the production of oil in Vaca Muerta. And yes, as it relates to your other question in terms of sourcing extra demand from the power sector as commented before, right, we -- even without that extra demand, we are seeing probably a higher volume of imports during the year compared to last year imports during the year compared to last year.

And that relates to, I would say, average utilization rates at the refineries being limited given the negotiations of the sourcing of local crude. So in that context, I would say that any incrementally demand from the power sector will likely be sourced for further imports. That meaning if the system needs or requires to switch a portion of natural gas or LNG with extra liquids, that is likely to further increase the volume of imports. And, of course, historically those -- that segment goes at import parity. So any fuels, any liquids sold to the power system, to the power generators are priced at import parity. So in that regard, there are no distortions. But we don't particularly see a further business opportunity coming out of that.

And there are no further questions at this time. I turn the call back over to Sergio for some closing remarks.

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

This concludes today's conference call. Thank you for your participation. You may now disconnect.