YPF Sociedad Anónima (YPF) Q4 2021 Earnings Report, Transcript and Summary

Good morning. My name is Rob, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the YPF Fourth Quarter 2021 Earnings Webcast Presentation and Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Pablo Calderone, 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 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 using calculations to reach our main financial figures in U.S. dollars. Our financial figures are stated in accordance with IFRS, but during the call, we may discuss some non-IFRS measures such as adjusted EBITDA. I will now turn the call to Sergio. Please, Sergio, go ahead.

Thank you, Pablo. Good morning, ladies and gentlemen. Thank you for joining us on the call today. One 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 rejoined YPF with the firm determination to restore the company through the storm. And now one year later, we are proud to present a fully recovered reality, delivering exceptional results on all fronts in light with guidance that we have 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 $3.8 billion, exceeding pre-pandemic levels of 2019 by about 6%, and the positive cash flow generation achieved along seven consecutive quarters allowed for an aggregated reduction in net debt of around 17% or $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 five 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 strategy that combined financial prudence 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 shale blocks. And while we continued prioritizing oil over gas, the 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, withstanding 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 costs in our hub core on the back of new well designs that resulted in lower average well costs and higher average estimated ultimate recovery. We have recently revisited the EUR for a tied well of 2,500 meters of horizontal leg 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 systems through third-party financing for our franchisee network, 68 locations revamped the 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 Echeverria 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 convictions, 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 sustainabilities 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 worked, although higher than in 2020, even the low activity performed that year on the back of the pandemic. The result for 2021 continued delivering on the same ambitious lines established five 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 $465 million, this budget more than doubled the figure for 2020 and resulted more than 30% above the average for the last five years. Among other initiatives, this has allowed us to implement a spill prevention and control system, a program to automate detection, maintenance and requirement 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 direct employees and contractors focused on what we refine at the 10 golden rules to save lives, which looks to encourage and promote a safety culture within the entire organization. We also maintain the safe driving program put in place in previous years, which has resulted in relevant reduction in the frequency rate of vehicle 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 lives. 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 on 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 the further 10% reduction in 2022, averaging less than 41 kilograms of CO2 equivalent per barrel produced. This is then seen in the over accomplishments of the targets put forward back in 2017 accounting for over 14% in cumulative net debt reduction and targeting a further decrease of 6.5% in 2022. Our commitment towards this reduction continues foreseen more than 30 initiatives for the decarbonization of our activities, as well as having an all time high share of renewable sources in our energy purchases for the last quarter. To outline our energy transitioning 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 two 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 $64 million long-term green bond recently issued in the local market. Finally, it's worth noting that we are also analyzing future projects to improve fuel quality, enter [indiscernible] value chain and deploy blue and green hydrogen pilots through the H2Ar consortium all led by YPF technology, our research and development company 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 sustain our levels, but also managing to stabilize our oil and gas production after five years of continuous decline. Our revenues increased over 41% year-over-year reaching a total of $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 lease back 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 the savings ended slightly below our expectations with respect to pre-pandemic levels, we are still satisfied with our performance as cost efficiencies secure within the program launched in 2020, continue 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 $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 five years. It is worth highlighting that the year-on-year improvement in adjusted EBITDA was achieved across all our business segments on the lack of 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 are 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 $2.7 billion announced at the beginning of the year, that was initially considered very ambitious and difficult to achieve. However, after 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 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 of 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 $882 million, allowing for a significant reduction in our net debt that closed the year at $6.3 billion, reaching the lowest levels in 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 earning 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 remain flat sequentially at $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, totaled $834 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 inputs and higher prices on crude purchases among others. On the CapEx front, in Q4, we executed the highest activity of the year, deploying over $900 million with increases across all business segments, but maintaining our focus in upstream activities, which represented 77% of total investments. Finally, this results translated into yet another quarter delivering positive free cash flow before debt financing, the seventh in a row totaling $143 million in the quarter, and leading to a decline by another $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 five 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 containment 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 2021 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 $3.1 per million BTU. On the crude oil side, our average realization price increased by 4.4% on a sequential basis to about $58 per barrel, only partially benefiting from the rallying 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 pump 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 seven 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 2019 wells. As stated in previous calls, in setting this record, we took advantage of the above average backlog of drilled and completed 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 the DUC inventory slightly below our target. In terms of efficiencies, during the fourth quarter, we continue 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 are having a multi-year evolution of our key operational metrics becomes easier to understand the impressive reduction in development cost at our shale oil core hub. When comparing to five years ago, our shale oil development cost declined by more than 50% to an estimated average of $7.2 per barrel in Q4 2021, resulting in a full-year estimated average of $8.2, well below the guidance provided a year ago of $9.2 per barrel. Our operating improvements and development plans for our shale resources also contributed significantly to the evolution of reserves. Total proved reserves expanding 24% year-over-year to over 1.1 billion barrels of oil equivalent, recording the highest metric in five years. Most specifically, proved 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 equivalent 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 barrel of oil equivalent resulted in a reserve replacement ratio of 2.3x in 2021, the highest for the last 20 years. Furthermore, net shale 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 Rincón del Mangrullo among others having the largest contributors to these results. On the other hand, on the conventional side, reserve editions were supported by the positive results achieved in the Golfo San Jorge basin with the expansion of tertiary recovery projects in Manantiales Behr and the acceleration of derisking on Los Perales, El Trebol and Cañadon 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 process crude from third parties in the middle of the 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 locally demand within our retail network. Moving into fuel 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 evaluation 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 measuring dollars, while average diesel prices remain flat benefiting from the continuation of our strategy to reduce discounts to the wholesale segment but 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 quality 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, but 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 2021, 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 transaction 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 continue delivering very healthy operating cash flow on the back of positive working capital variation, staying above the $1 billion mark and accumulating $4.2 billion for the 12 months as of December 2021. The strong generation of operating cash flow combined with a significant reduction in cash interest expense that reached the lowest levels 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 commended. In terms of cash management, during the fourth quarter, we have continued with an active asset management approach to minimize FX exposure in a 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-à-vis the previous quarter. Finally, we ended the year with a total liquidity of $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 $700 million as of December of last year. The first time in many years, the liquidity comfortably exceeded short-term maturities. Furthermore, the recent $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 Bank has extended regulations that limit the ability of Fortune 9 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 capital transaction was fully reversed at the end of March will certainly comply with such restriction, 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 tap 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 potency in a challenging macro environment. Uncertainties related to the future evolution of the global economy together with geopolitical tensions and/or 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 through an enlarged CapEx program in great measure financed through operating cash flow. We are therefore committed to maintain our proven 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 of the pump in a proven and sustainable way to counteract the FX 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 running international prices. Nevertheless, we feel confident in our ability to fully execute our CapEx program of $3.7 billion, which represent an increase of more than 40% when compared with the amount deployed in 2021. These investments will once again be concentrated in our option activities where we plan to deploy $2.8 billion, $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 shale oil operations encompassing the Loma Campana, La Amarga Chica and Bandurria Sur blocks. And from now on, including also our Aguada del Chañar block constituting the first shale oil block within our core hub to be 100% owned by us and where we have just connected to us during December with early promising results. YPF net investments in the core hub operations shall include about $100 million in facilities, including the third train within the oil treatment facility at La Amarga Chica and a new oil treatment facility at Bandurria Sur, with the reminder being devoted to drilling and competition activities. In that sense, we expect to tie-in close to 100 new wells during 2022, while drilling activities should be somewhat higher to build back a slightly larger deck 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 the Bajo del Toro Norte with an area of 114 square kilometers, where we plan to tie-in six new wells in 2022. As a result of this 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 Neuquén Basin and taking into consideration future growth plans, we have decided to emphasize our focus in coordinating midstream initiatives to the bottleneck, the future of equation of oil and gas production out of Vaca Muerta. In that sense, we have created two new business units within our organization to lead the efforts on both the midstream oil and midstream gas plants. 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 investment required on the midstream oil side to enable further export opportunities to Chile, as well as through the Atlantic. Finally, on the downstream segment, we will continue with the multi-year investment plan to revamp our La Plata and Luján de Cuyo refineries, to adapt to new fuel specifications resulting in lower sulphur fuels that will help to reduce our Scope 3 GHG emissions. During 2022 estimated CapEx for this project will around the $150 million to $200 million range out of estimated CapEx of $800 million for the next four years. With a reminder investments within the segment for 2022, been deployed to finalize the adaptation of our refineries to process lighter crudes, regular maintenance of our facilities, the continuation of the new branding image 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 am 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 the continued support. We are now open for your questions.

[Operator Instructions] Your first question comes from the line of Bruno Montanari from Morgan Stanley. Your line is open.

Hi, good morning. Thanks for taking my questions. I have three questions. First, your budget for CapEx this year is increasing $1 billion. So I'm curious to what you are assuming on the budget happens with oil price in Argentina. So do you expect oil to remain at this $57, $60 per barrel level? Or do you plan to increase crude oil practice 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 still invest a size of 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? Thank you very much.

Thank you, Bruno, for your questions. I'm going to take the question about on prices and local prices of oil and let me answer in a broader sense. As already commented during the presentation, we will continue monitoring evaluation of key variables, such as the depreciation of the currency and international oil crisis 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 quality in every December when Brent prices moved around $70 per barrel, the rise during the last couple of months, particularly spike on the back of the last couple of weeks has to spread higher. Consequently, after bottoming at about 10% an average of all fuels by early December, the discount to import quality has been increasing since then finish in January at about 30%. And by the end of February remaining close to that level, as the price adjustment performing early February compensated to further appreciations international prices up to that point. However, the most recent rally in international crisis that took Brent above $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 quality. 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, why don’t you take the second question on 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 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 putting 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 crude and pump prices, and in that sense affect our budget for the year. Then into the maturities, as you were asking debt maturities for 2023 to 2025, what we see is that the shorter-term, mostly 2023 and 2024 maturities are within levels that we feel very manageable for - basically for historical standards for YPF, and what we expect for our ability to manage them in the future there in the order of $800 million to $850 million 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, there was actually net leverage allowed us to reduce very significantly, the balances that we have outstanding with 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 reminder of 2022 is very well taken care for because, as you know, we - A/B loan already secured, the rest of the maturities in 2022 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 bond 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 pre-finance or take that maturity ahead of time as soon as a possibility arrives or materialize. And then finally on your question about opportunities for joint ventures or divestments in Vaca Muerta as well as commented in previous calls, we still see that devaluation distortion that we have this least potential interesting 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 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 will come significantly closer, we will definitely entertain this conversation would be 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 Papalios from Plenti. Your line is open.

Hi. Good morning, and congratulations on your results. I'd like to ask two questions today, more related to your income statement. There's $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 their impact on downstream EBITDA in this fourth water? I'm referring to diesel, ultra-low- sulfur diesel and gasoline imports for the local market? Thank you very much.

Hi, Konstantinos. Thank you for your questions. As it relates to your income statement question and the line of other income or expenses, it mostly relates as you will find out going deeper into financial segments 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 that generating other income in the third quarter. But then when you look at specifically the charge in the fourth quarter, as I said, is 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 the printing, 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 Sergio 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 90% in the quarter, part of that was sourced through higher processing levels, which increased by 6% but then the reminder, was taken care through fuel imports. Mostly as – clearly as you know, we keep on acquiring about 20% of our crude purchases of our – the total crude process from third parties and so also given the discounts international prices versus local crude prices. It became a little tougher to source local crude to further improve processing levels at our refineries, so the reminder was sourced from imports, and in that regard also the increased volume of imports, which, mostly for diesel which is a largest portion of our fuel imports ended up representing 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 imports, that amount also – that volume also included specific build up 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 build up of inventories, and looking into the evolution of local demand in the first quarter of this year, going forward, we would expect 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 contracts 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 regulations. So also that is another source of demand for imports, which need to compensate that lower proportion of biofuels in our overall fuel mix.

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

Hi, good morning, everyone. Thanks for the presentation. Congratulations on the financial results and also – very solid start for the quarter. I have three questions. I'm not going at the very beginning of the question you said that you were revising [indiscernible] EUR estimate 1.5 million barrels of oil equivalent for some projects. Can you say what type of projects are these? I imagine it's 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 upstream segment in particular? And the last one is if you can remind us how much is the receivables of our Plan Gas as of the end of last year? Thanks.

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 [indiscernible] segment of that Loma Campana block and in that specific area we adjusted our type well, and in the context of our type well for the well in the leg of 2,500 meter of horizontal drilling, basically 2,500 meters horizontal leg. We have adjusted the average EUR by 17% higher to 1.5 million barrels. So it is very specific to that block, and to that segment, but clearly we are seeing the new engineering that we are putting together and the extension in the average horizontal leg on our tied wells that overall EURs are trending upwards. And so clearly that helps also our improved development costs. On our upstream costs, yes, definitely, we are seeing inflation pressures both from service inflation and particularly wage pressures and salary pressures, mostly given that those levels inflation and salaries are running faster than deprecation of currency. So in dollar terms, we are seeing pressure on our lifting costs 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 the different of the composition of that average lifting cost, we can point out that our overall lifting costs on conventional blocks went up clearly on a unit basis, right? 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, 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 on a unit basis, it went up. But again, less than the reaction on the overall production, and the opposite happened with our unconventional where we are significantly lower than a per unit basis when comparing to 2019, of course helped by the increased production out of those blocks, where our overall average lifting cost in fourth quarter was below $4 per barrel in unconventional, which is a decline of about 25% when compared to the 2019 field. 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 this inflationary pressures in dollar terms continue, it will be partially mitigated by the further increase in the overall proportion of shale on the total production portfolio, but definitely, cost pressures will likely be there. And finally, there was a question on the [indiscernible] from the Plan Gas, I would say as of today, payments are very regular – for the most part regularized. As you probably remember, payments in the new Plan Gas are divided in two 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 reminder 25%, that is already scheduled to be paid with some delays from the specific regulation, another 30 days, basically giving 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 payments on the initial 75% - pretty much regularized and we have a very minor delays of about not more than one month there, but then, yes, on the remainder 25% will do have some receivables that are [indiscernible] related as we only collected the 25% portions of the invoices from January and April of last year of 2021 with the reminder pending payments. That amounts to about $30 million asset to…

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

Hi guys. Sergio, Alejandro, Pablo, thanks for taking my questions. Couple of follow-up questions of 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 whether you already embedded in that guidance sort of the expectation that you would have declining margins on the back of that inflation, right? And then still on the topic of the price adjustments, of course, now oil prices trending significantly higher at $110 per 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 the gasoline, assuming that the country might become net imported throughout 2022? And then just finally, if I may, one question regarding the number of drilled and then completed wells. The number of wells has declined from 76 in 2020 to 47 now. I just wanted to get a sense of how should we interpret this? Is this because we'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 slow down in the fourth quarter? Thanks.

Hi, Regis. Good morning, and thank you for your questions. In terms of your first question about cost inflation and how we treated it 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 fuels and crude, and it's hard to say at this point, how both things will end up playing out, but at least started trying to answer your question. At least we can say that we will take into consideration the impact of inflation and how it plays out with our view on the evaluation 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 will increase our cost base generally speaking. And again, that is considered in our assumptions for EBITDA generation and free cash flow for the year. Then on your question of price adjustments and the evolution within 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 is that, again, repeating what Sergio was saying, we need to remain cautious and prudent in figuring out how the different bios play out. 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 do that? It's still a question mark. And again, then not only depends on our wheel, but also on the general context of the macroeconomic situation in the country and the potential demand FX that that could have. Of course, this is also related and caused 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 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 that was the consensus and the reasonability among all parties to re-sustain and to be able to continue sourcing the local demand in a fair way with logical profitability for all different segments along the value chain. And finally, on your question about DUCs, yes, as mentioned during 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 the result of the mostly coming out of the pandemic to accelerate production growth and through further tie-ins and drilling activity. However, we get drilling activity high, and that's how we still manage 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 are 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 operated shale blocks.

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

Good morning, everybody. Thank you very much for the materials and the time on the call. I have three 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 80%, 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 on the country as oil crude exports?

Hi, Ezequiel. To start with that question, yes, as mentioned utilization at our refineries recovered in the fourth quarter. Part of that has to do with the increasing demand. Part of that also has to do with lower utilization in the third quarter, given some program maintenance work that we were executing during the quarter, primarily between, July and August. So that pushed our utilization rate and 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 the utilization rate on the refineries. So based on that and given the spread of local crude prices to export parity, we probably don't – 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 bounce back a little bit in February, but of it all 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 allow the same level of utilization rate at our refinery so potentially slightly higher during the year, what we are likely going to see is that total imported volumes are going to remain high probably 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 on average quarters probably below what's happened in the fourth quarter because as we commented before the fourth quarter was also initially high because of the build-up in inventories. So most likely on average, we are going to see lower level of inputs compared to fourth quarter, but on a year-over-year basis our total volumes likely to be higher than 2021.

Okay. Thank you. And I don't know if you can touch a little bit on what might happen with some other refiners in Argentina, could go online this year 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, I particularly don't know of any specific issues on the refinery system overall during the year. So unfortunately, 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. Your line is open.

Hi, everyone. Thanks for taking the question. I believe you want to come back to me. One on the cash flow and [indiscernible] slides 12 and 13 of the presentation, they're really helpful. But 2022, when we tried to reconcile the cash flow for the current year, I know even considering significant increase on the EBITDA level, we still see like a lower, I would say cash position than the 1.1 that you ended the year. I mean, you still have some debt to be paid and $3.7 billion on CapEx and we are consigning to the cash flow in 2022 with I don't know, $0.4 billion, $0.5 billion in cash. So just trying to understand first, if that makes sense considering no debt roll over and in that prompt how you guys are now planning to renegotiate with $700 million that you have that expiring in 2022. And the second question is with regard to the IMF agreement with Argentina, I mean, there are lots of moving bars, but lots of parts that touching about the energy sector and the government subsidies in that front. So just trying to understand also how these agreement might impact, if point to, or negatively the company and the sector with regards to the freedom to price to follow the international markets, pricing looking forward? Thank you.

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

Sorry, operator, can you hold on one second because we need to answer Luiz’s question. Sorry, Ezequiel hold on a minute, please.

Yes.

Luiz, good morning. 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 as you 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 that has trended downwards compared to the average of 2021. And then we also say that we do have some positive working capital variation 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 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 not to exceed a net leverage ratio of 2x during 2022. And clearly, on that regard, as I said before, given that the nominal maturity 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 upstanding facilities with relationship banks, as well as our exposure to the local market, it’s at the minimum in many years, we do feel that we have ample room to tap on those sources to fund those net needs that we might have. And as I said, of course, maintaining and keeping that 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 $3.7 billion CapEx program with 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 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 the 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 area, which, Sergio tackled away 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 in global business.

Ezequiel Fernandez, your line is now open.

Thank you. Hi, again. So basically I had two questions, 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 sent for approval in a couple of months. I don’t know if you have any updates on that front?

Sorry, Ezequiel. Can you repeat your first question because the line was little cut off and we couldn’t really 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. And 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 proven that 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 will expect some positive impact not huge, not major, but we will see some positive impact on the working capital contribution.

Great.

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

Great. That's all from my side. Thank you very much.

Sure. Thank you.

And your next follow-up question is from Konstantinos Papalios from Plenti. Your line is open.

Thank you very much. Just to follow-up on Cardoso question on refinery utilization, we are forecasting higher, fewer needs for the power duration sector in Argentina during the prices – the international price for LNG. So why you forecasting a positive impact on the power sector gas oil needs? And does it perhaps mean that you could score higher crack spread on eventual additional volumes for diesel and fuel oil towards the power generation sector? And just one quick one, you mentioned the bottlenecking infrastructure for evacuating volumes from black and white of course, could you share with us ballpark estimate on the CapEx required to fulfill this goal and how much evacuation capacity would it add? Thank you very much. And again, congratulations on your results.

Thank you, Konstantinos for your comments. [Indiscernible] to the second question. As you know, total production from all producers out of the Neuquén Basin down 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's a level not seen since [indiscernible] and this incremental production, with an excellent news was a result of example oil production, led by our company, increasing production by 62% over a year, and reaching almost $140,000 barrels per day loss in last December. This ramp-up in production was more pronounced than previously expected by the industry, and that resulted in – to anticipate investment in midstream or into the bottleneck and enable the continuous expansion of Vaca Muerta. And this investment large portion of which is – and will be carried out through our midstream subsidiaries total value, which we have 37% and 10%, which we have a 30% participation include different initiatives. In the future of the value under go into revamping of four compression stations that have been ideal for over 10 years, which will add about 25,000 barrels or about 10% of allocation capacity to [indiscernible] in the second quarter of this year, and for investment is around $50 million. And revamping of the other four pump stations currently in operation, and more than 500 kilometers of new loops are expected to further up about 200,000 barrels per day of additional capacity during 2023, CapEx estimates by around $400 million to $450 million. On this note, investment plans also contemplate the expansion of a storage capacity at Puerto Rosales by our subsidiary – to provide further export flexibility through advantage. In Paraguay works are also being performed, current facilities on the Trans Am oil pipeline, OTA OTC, which we have also participation to put them back online, expecting to have the pipe running by the end of the year or beginning of next year, we ran an initial export capacity of about 35,000 barrels per day. And with the final target after putting together a new oil pipeline of about 150 kilometers from the core of Vaca Muerta to Puesto Hernández 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 that expected equation of the production of oil in Vaca Muerta. And as it relates to your other question, in terms of sourcing extra demand from the power sector, as commented before, right, even without direct extra demand, we are seeing, probably a higher volume of imports during the year compared to last year and that relates to I would say, our utilization rates at the refineries being limited given the negotiations of the sourcing of local group. So in that context, I would say that any incremental demand from the power sector will likely resourced to further imports that meaning if the system needs or required to switch a portion of natural gas or LNG with extra liquids, that is likely to further increase the volume of inputs. And of course, historically, those that segment goes at import quality. Any fuels, any liquids, sold to power system to the power generators are priced at import quality. So in that regard, there are no distortions, but we don't particularly see a further business opportunity for 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 comment and reports, and have a good day.

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