YPF Sociedad Anonima

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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star one. Thank you. Pablo Calderon, YPF Investor Relations Manager. You may begin your conference.

Good morning, ladies and gentlemen. This is Pablo Calderon, YPF Investor Relations Manager. Thank you for joining us on the call today in our full year and full quarter 2021 earnings call. I hope you all continue to be safe. This presentation will be conducted by our CEO, Sergio Franti, our CFO, Alejandro Leo, and myself. During the presentation, we will go through the main aspects and events that explain our fiscal year and forecast the results. And finally, we will open up the call for questions. Before we begin, I would like to draw your attention to our questionnaire statement on slide two. Please take into consideration that what are remarks today and answer to your question may include forward-looking statements, which are subject to risk 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 calculation 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 new 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. Only a 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 steer the company through the storm. And now, only a 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 aggregate 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 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 approved hydrocarbon reserves, reaching remarkable growth in our reserves of around 24% and historical high reserve replacement ratio of 2.3 times. 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 CAS4 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, we saw 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 fracking speed and more recently in our drilling speed. And we were capable to continue reducing the development cost in our half 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 wall 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 refiner's 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 assistance 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 Echevarria 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 new builds. 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 continue 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, given 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 discussed allowed us to implement a spill prevention and control system, a program to automate detection, maintenance, and repairment 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 define as 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 a 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 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 seeing 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 decarbonization of our activities, as well as having an all-time high share of renewable sources in our energy purchases for the last quarter. Outlining our energy transition initiatives, YPF LUS, 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 MW 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 a lithium value chain, and deploy blue and green hydrogen pilots through the H2R consortium, all led by YPF Technology, our research and development company association with CONICET. 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 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 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 nafta, 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 plant 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 efficiency 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 $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 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, our 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 a somewhat slower than projected pace in the first half of the year, we managed to accelerate in the second half and execute in 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 planned gas commitments for the year. Finally, based on the solid recovery in adjusted EBITDA, our free crash 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 level since the second quarter of 2015 and pushing our net leverage ratio down to 1.6 times, well below the threshold of two times 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 planned 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 rent 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 $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 fuels 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 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 $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 4Q21 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 plant 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 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 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 7 shale gas wells. Although slightly below the activity performed in the previous quarter, in which we had 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 the DAC 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 when adding a multi-year evolution of our key operational metrics, it 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 crude reserves expanded 24% year-over-year to over 1.1 billion barrels of oil equivalent, recording the highest metric in five years. More specifically, crude oil reserves increased by 33%, while natural gas P1 reserves expanded by 16%. The addition of approved 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 barrels of oil equivalent resulted in a reserve replacement ratio of 2.3 times 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 four times, 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 Mangrucho, among others, have been 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 the San Jorge Basin, with the expansion of tertiary recovery projects in Manantiales Verde and the acceleration of the risking on Los Perales, El Trébol and Cañadón León. 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 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 continue delivering very healthy operating cash flow on the back of positive working capital variations. staying above the $1 billion mark and accumulating $4.2 billion for the 12 months as of December 21. This strong generation of operating cash flow, combined with a significant reduction in cash interest expense that reached the lowest level since 2013, permitted 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 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-a-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 that liquidity comfortably exceeded short-term maturities. Furthermore, the recent $300 million cross-border ABI 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 Argentine 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 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 the hour 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 their 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 two times 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 rallying international prices. Nevertheless, we feel confident in our ability to fully execute our CAPEX program of $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 absent activities, where we plan to deploy $2.8 billion 1.6 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 half-shale oil operations, encompassing the Loma Campana, La Marga Chica and Bandurria Sur blocks, and from now on, including also Aguada del Chaniar block. constituting the first shale oil block within our core hub to be 100% owned by us and where we have just connected two walls 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 Marga Chica and a new oil treatment facility at Banduria Sur. with the reminder being devoted to drilling and completion 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 DAC 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 Baca 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 six 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 Neuquena 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 two 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 plans 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 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 Lujan de Cuyo refineries to adapt to new fuel specifications, resulting in lower sulfur fuels that will help to reduce our scope 3 GHG emissions. During 2022, Estimated capex for this project will round the $150 to $200 million range out of estimated capex of $800 million for the next four 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 image initiative within our retail gas stations, and efficiency and sustainability initiatives, among others. Before turning to 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 their continued support. We are now open for your questions.

At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Your first question comes from a 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're assuming on the budget happens with the oil price in Argentina. So do you expect oil to remain at its $57, $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 while I imagine you'll still invest a sizable 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 pump prices and local prices of oil, and let me answer in a broader sense. I've 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 at the time.

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 countries. With respect to the discount versus import parity, and after a significant reduction in the spread to import parity in early December, when brand prices moved around $70 per barrel, the rise during the last couple of months, particularly a spike on the back of the last couple of weeks, has pushed the spread higher. Consequently, after bottoming at about 10% on average for all fuels by early December, the discount to import parity has been increasing since then, finishing in January at about 30%. By the end of February, remaining close to that level, as the price adjustment performed in early February compensated, the further appreciation of international prices up to that point. However, the most recent rally in international prices that took a brand 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 priorities.

All in all, we expect to continue working in a collaborative effort with most actors in our sector to continue moving out the full effect of this volatility to local consumers.

And just to complement that as well on the general context on our view on pricing as relates to budgetary purposes. We basically ran 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 ton 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 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 are very manageable for basically for historical standards for YPF and what we expect for our ability to manage them in the future. They are in the order of $800 to $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 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 of because, as you know, we have a 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 land 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 a bad 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 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-à-vis potential interested parties, and I think that mostly relates to 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 do come up, significantly closer, we will definitely entertain those conversations. We believe that anything that could potentially accelerate the development of the vacuum work 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 Papalas from Puente. 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 a $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 quarter? I'm referring to diesel, ultra-low sulfur diesel and gasoline imports for the local market. Thank you very much.

Hi, Constantino. 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 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. of 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 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 inputs, clearly during the course and as was mentioned during the presentation, we have increased the the amount and the volume of fuel inputs, 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 was sourced through higher processing levels, which increased by 6 percent, but then the remainder was taken care through fuel inputs. Mostly, as clearly as you know, we keep on acquiring about 20 percent of our crude purchases of the total crude process 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 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 the largest portion of our fuel inputs, 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 phase source through inputs. 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 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 inputs, which need to compensate that lower proportion of biofuels in our overall fuel mix.

Our next question comes from the line of Andrea Sardona from Citigroup. Your line is open.

Hi. Good morning, everyone. Thanks for the presentation. Congratulations on the financial results and also because of the very solid research report. I have a few questions. I'm not wrong at the very beginning of the question. You said that you were revising Upward. You are estimate to 1.5 million barrels of oil equivalent for some projects. Can you say what type of projects are these? I imagine it's La Marca Chica, Bandurria Sur, and Loma Campana. Am I right here? The second question is, if you are seeing a relevant inflation cost pressured in the absent segment in particular. And the last one is, if you can remind us, how much is there we hear about planned gas as of the end of last year? Thanks.

Thank you, Andrés. 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 type well. And in the context of that type well, for a well with a length of 2,500 meters of horizontal drilling, basically 1,500 meters horizontal length, we have adjusted the average EUR by 17% higher to 1.5 million barrels. So it is very specific to that block and to that segment. But clearly, we are seeing, given the new engineering that we are putting together and the extension in the average a horizontal leg on our pipe wells that overall URs 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, 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 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 composition of that average lifting cost, we can point out that our overall lifting cost on conventional blocks went up clearly on a unit basis, right? I'm saying it went up, but that is primarily as a result of 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 compensated to a large extent with our increase in unconventionals. But then, at the same time, our own lifting costs went up in a lower proportion. So, basically, the unit on a unit basis it went up um but uh but again on a on less than that the reduction on on the overall production and the opposite happened with our unconventionals where we are significantly lowered on a per unit basis when comparing to 2019 uh of course helped by the increased production out of those blocks, where our overall or average lifting cost in the fourth quarter was below $4 per barrel in unconventionals, which is a decline of about 25% when compared to the 2019 figure. uh so what you know we do see pressures but we are managing to to to keep our costs under control uh but of course going down the road if these inflationary pressures in dollar terms continue um 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... No, sorry. And finally, there was a question on receivables from the plant gas. I would say as of today, payments are very regular, for the most part regularized. As you probably remember, payments from 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 the payments on the initial 75% are pretty much regularized, and we have very minor delays of about no more than one month there. But then, yes, on the remainder 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 a reminder pending payments. That amounts to about $30 million as of today.

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

Hi, guys. Sergio, Alejandro, Pablo, thanks for taking my questions. A couple of follow-ups, questions of topics we've already sort of glanced on or touched on. The first is considering the cost of 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 expectations 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 $110 per barrel Brent, how do you see this play out in Argentina? Do you think you would be able to pass through this? these higher prices? Or instead, would you expect the government to fund the importation of diesel gasoline, assuming that the country might become, you know, net importer throughout 2022? And then just finally, if I may, one question regarding the number of drilled and uncompleted wells. That number of wells has declined from 70%. in 2020 to 40 soon. I just wanted to get a sense of, you know, how should we interpret this? Is it because we're being more efficient in tying up the wells? Or is it in any way, you know, something that you have less wells to put on stream now or that your activity has slowed 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 yields and crude. And it's hard to say at this point how both things will end up playing out. But at least 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 valuation 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, everyday generation and free cash flow for the year. Then on the question of price adjustments and devolution 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 is 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 in that, it's still a question mark. And, again, that not only depends – on our will, 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 cast 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 um fully uh translate uh international politics to the pump uh that unfortunately also affects uh the pricing for local crew uh but again that 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 total group 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 crisis. 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, you know, logical profitability for all different segments along the value chain. And finally, on your question about DAX, yes, as mentioned during the presentation, the total balance for DAX 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 DAC inventory that was the result of the mostly coming out of the pandemic to accelerate production growth through further tie-ins and drilling activity. However, we kept drilling activity high, and that's how we still manage to keep a healthy level of ducts. Going forward, we are probably likely going to see some increase in this inventory of ducts, but marginally, down the road, because we feel that we are roughly speaking on a level that provides enough flexibility to our operations. We're looking at the number of drilling rigs and that we should have in operation during the year. So most likely you are going to be somewhere between this number and the figure published in the previous quarter. Somewhere in that range we will manage our DAC inventory on our operated shale blocks.

Your next question comes from the line of Esquil Fernandez from Belance. 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 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 do 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 21, 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 all crude exports?

Hi, Ezequiel. To start with your question, yes, as mentioned, utilization at our time is recovered in the fourth quarter. Part of that It has to do with an increase in 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 that quarter, primarily between July and August. So that pushed our utilization rate on 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, you know, how we expect that down the road, it has to do with what 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 parties, 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 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 about the same level of utilization rate that I will find, and it's 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, in all quarters, 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. 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 that 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 requirements 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 Luis Carvalho from UBS. Your line is open.

Hi, everyone. Thanks for taking the question. I think we want to come back in, you know, on the cash flow. And I really like this slide, 12 and 13 of the presentation. They're really helpful. But looking to 2022, when we try to reconcile the cash flow for the, you know, the current year, even considering significant increase in the EBITDA level, you know, we still see like a lower, I would say, cash position than the 1.1 that you end of the year. I mean, we still have some, you know, debt to be paid and, you know, $3.7 billion in cutbacks. And we're consigning it to the cash flow. We end 2022 with, I don't know, $0.4, $0.5 billion in cash. So just trying to understand first if that makes sense considering that rollover and in that front, how you guys are planning to renegotiate the $700 million that you have that expiring in 2022. And the second question is with regards to the IMF agreement with Argentina. There are lots of moving parts, but lots of parts are touching about the energy sector and the government subsidies in that front. So just trying to understand also how these agreements might impact, if positively or negatively, the company and the sector with regards to the the freedom to price, to follow the international market pricing looking forward. Thank you.

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

Sorry, Alberto, can you hold on one second? Because we need to answer Luis's question. Sorry, Ezequiel. Hold on one minute, please. 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 debt has trended downwards. compared to the average of 2021. And then we also say that we do have some positive working capital variations expected 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, It might require some incremental debt, although we are saying also that that incremental debt will be cut. not to exceed a net leverage ratio of two times 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 residual 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 at its minimum for 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 two times. 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 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 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, you know, vision or 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 INF negotiation into our business.

Esquil Fernandez, your line is now open.

Thank you. Hi again. So basically I had two questions. It 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 offsets could be sent for approval in a couple of months. I don't know if you have any updates on that front.

Can you repeat your first question? Because the line was a little cut off and we couldn't 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? Yeah. 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 such as the EBITDA and specific working capital, what I do can say. is that, as I mentioned on Lucy'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, yeah, clearly, as we speak, we don't have too much clarity on what will end up happening with it, clearly, given general views. we tend to say that 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 do see or we do expect to see maybe a shorter and more specific project or law that will 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 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.

Thank you. And your next follow-up question is from Constantinos Papalios from Quente. Your line is open.

Thank you, thank you very much. Just to 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 of 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 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 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 very much. And again, congratulations on your results.

Thank you, Constantino, for your comment. I'm going to take the second question.

As you know, total production from all producers out of the Neuquena basin jumped 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 2003. And this incremental production is an excellent news.

It 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 per day gross in last December. Distributing production was more pronounced than previously expected by the industry, and that resulted in a need to anticipate investments in midstream oil to the bottleneck and enable the continuous expansion of Vaca Muerta. And this investment, a large portion of which is and will be carried out through our mid-frame subsidiary, such as Oldelval, in which we have 37%, and Olitankina Returns, in which we have 30% participation, include different initiatives.

In the imminent future, Oldelval is undergoing to revamping

of four 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 in the second quarter of this year.

And for this, the investment is around $50 million.

In addition, the revamping of the other four PAM stations currently in operation and more than 500 kilometers of new loops are expected to further add about 200,000 barrels per day of additional capacity during 2023, with a capex estimated by Oldelvale in around $450 million. On this note, investment plans also contemplate the expansion of storage capacity at Puerto Rosales by our subsidiary OCHE to provide further export flexibility through Atlantic.

In the current way, works are also being performed at current facilities

on the Trans-Saharan oil pipeline, OTA, OTC, which we have also participation, to put them back online, expecting to have the pipe up and 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. with a final target after putting together a new oil pint of about 150 kilometers from the core of Baca Muerta to Puerto Hernandez of over 100,000 barrels per day in the second half of 2023.

This is more or less the

the strategy that the industry is following with respect to the acquisition of the production of oil in Guatemala.

Yeah, and as it relates to your other question in terms of sourcing extra demand from the power sector, as commented before, right? Even without that 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, 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 an incremental demand from the power sector will likely be sourced through further inputs. That means 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 inputs. And of course, historically, that segment goes at impropriety. So any fuels, any liquids sold to the power system, to the power generators, are priced at impropriety. So in that regard, there are no distortions. But we don't particularly see 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.