YPF SA (YPF) 2020 Q4 法說會逐字稿

Thank you for standing by, and welcome to the YPF Full Year and Fourth Quarter 2020 Earnings Call.

(Operator Instructions) Please be advised that today's conference is being recorded.

(Operator Instructions)

I'd now like to hand the conference over to Santiago Wesenack, Investor Relations Manager.

Mr. Wesenack, please go ahead.

Good morning, ladies and gentlemen.

This is Santiago Wesenack, YPF's IR Manager.

Thank you for joining us today in our fiscal year and fourth quarter 2020 earnings call.

I hope you're all safe.

The presentation will be conducted by our CEO, Sergio Affronti; our CFO, Alejandro Lew and myself.

During the presentation, we will go through the main aspects and events that explain our fiscal year and fourth quarter results.

And finally, we will open up for questions.

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

Also, note the exchange rate used in our calculations to reach our financial figures in dollar terms.

Our financial figures are stated in accordance with IFRS, but during the call, we might discuss some non-IFRS measures, such as adjusted EBITDA, normalized EBITDA and normalized OpEx.

I will now turn the call to Sergio.

Thank you, Santiago.

Good morning, ladies and gentlemen.

Thank you for joining us on the call.

In our remarks today, I will first introduce you the main highlights of YPF's 2020 performance.

And Alejandro will later give you further details on our main results.

Afterwards, I will share with you our view on the 2021 outlook.

And finally, we will open the floor for questions.

Let me start by saying that despite 2020 having been one of the toughest years for the oil and gas industry worldwide, we are quite satisfied about YPF's resilience and overall performance in this exceptional year.

As you know, we have witnessed how the COVID-19 pandemic impacted oil economies much harder than anyone could have ever imagined with the related lockdown measures, making consumption collapse, particularly having a negative impact in oil prices as never before.

Today, with the global progress achieved in understanding the situation, we are keeping close track on the vaccine rollout as it may hold the key to finally leave this challenging health situation behind.

I rejoined the company last May as its CEO with a firm determination of steering YPF through this storm and prepare it to get back to profitable growth.

I believe we took the right measures at the right time, acting swiftly to shield our finances while protecting the health and safety of our employees and contractors and that of the communities where we operate.

Despite the difficulties of the pandemic, critical activities continued with no interruptions following strict health protocols, which allowed us to keep providing energy to our clients in a safe way.

We then achieved the lowest IFR level in our history.

And by advancing new technology solutions and accelerating the digital transformation of our company, we were able to work remotely in an efficient and agile way.

Our digital agenda is aimed at generating and preserving value by deploying a wide range of world-class technologies and solutions.

Current priorities are to continue increasing efficiencies and achieving sustainable cost reductions over time.

Given our efforts, we were able to be net cash flow positive along the year despite the contraction in profitability that we experienced as the pandemic heavily affected demand and prices of our products.

We did so by reacting quickly in adjusting investment activity to accommodate to the changing market conditions to prioritize financial discipline.

We therefore managed to reduce our net debt by about $500 million along the year, partially reversing the increase in the net leverage ratio as a consequence of the reduction in our EBITDA.

In the same line, we proactively engaged in a market friendly liability management exercised last July, addressing the upcoming $1 billion maturity of our March 2021 notes.

And we successfully refinanced close to 60% of debt maturity.

Nevertheless, new regulations introduced by the Central Bank in September obliged us to launch broader exchange offer last January.

This exercise allowed us to comply with the foreign exchange regulations and resulted in a financial relief of around $600 million for 2021 and 2022.

It shall provide partial indirect funding to our CapEx program aimed at reverting the oil and gas production decline trend of the last 5 years.

We not only work on the financial front, but also took the pandemic as an opportunity to rethink the way in which we conduct our operations and refocus on our core business, the oil and gas value chain.

We embarked in a company-wide cost cutting plan, aiming at achieving structural cost reductions and operational efficiencies.

Efforts were made not only in YPF, but also involving our suppliers and the unions to adapt to this new normal and enable mutual growth for all further explain and increasing the share of renewables in our total energy consumption.

So far, we see early results as encouraging, having reduced 17% average cost per well and over 20% in OpEx after netting one-off effect and we achieved key milestones in our sustainability track, improving our ranking position within the oil and gas industry, as we will further explain and working towards the energy transition by consistently reducing greenhouse gas emissions and increasing the share of renewables in our total energy consumption.

During the second half as demand gradually recovered, we started with periodic price increases at the PAM to stabilize prices in U.S. dollars and more recently recovered margins.

That process continues today as we monitor market conditions to adjust prices, although remaining conscious on the overall macroeconomic situation and the price effect on demand.

In the retail segment, in particular, our digitalization process has allowed us to be closer to consumers and consolidate our market presence.

Nowadays, 12% of fuel sales take place through our app, which has already reached 2 million users and 1.8 million monthly transactions.

All these actions help us create the basis for gradually resume activity in a more efficient way once economic conditions started to show signs of stabilization and partial recovery.

We were able not only to go back to pre-pandemic production levels at Vaca Muerta, but have also reached record production this February for our oil-operated areas.

And in Bandurria Sur, we have drilled the longest horizontal well in all Vaca Muerta with productivity being at the top of the shale play.

A similar case can be found on the conventional side, where we have continued beating record production levels at Manantiales Behr despite being a 90-year-old block, thanks to successful tertiary recovery techniques.

In addition, we have recently recovered the pre-pandemic utilization rate of our refineries as demand for diesel and gasoline continued improving during January and February of this year.

Let me end this introduction by saying that we are fully satisfied with the company's performance in such a challenging year, and that I am especially proud of our employees of their commitment and efforts.

I also want to thank our clients for the fidelity and our investors, partners and suppliers for their renewed support.

And now I leave you with Alejandro.

Thank you, Sergio, and good morning to you all.

Before going into our financial results, let me go deeper on how we are working to protect our people and to address the energy transition.

Sustainability is at the core of everything we do, and therefore, safety of our people is a top priority.

As we have gradually started to resume activity, the index that measures the frequency of accidents per million hours worked, reached its lowest historical value at 0.2% in 2020, improving more than 50% when compared to 2019.

However, while we continue to strengthen safety precautions, we have to regret the casualty of a fellow worker who lost his life in January of this year, while performing maintenance tasks at one of our oilfields.

As regards to our response to the pandemic, our COVID Committee continues overseeing the critical services and operations are maintained with the utmost care for our employees, suppliers and customers.

Over 90% of the people whose positions do not require face-to-face interactions are still working remotely.

We are also monitoring the health of our employees and contractors on a daily basis to prevent contagion.

And we have performed necessary testing and distributing more than 500,000 masks in our operational units.

We are also helping the communities where we operate with equipment to face the COVID outbreak.

We have helped hospitals and local municipalities and provided essential workers with protection and equipment to face the pandemic.

In addition, Y-TEC, our R&D subsidiary has developed NEOKIT, a molecular test that can diagnose the COVID virus in a simple and fast way.

So far, more than 1 million tests were produced, distributed, commercialized and some of them even exported.

Besides 200,000 liters of hydroalcoholic were produced for use of our employees and the nations.

Further focusing on sustainability, we have significantly improved our ranking position within the oil and gas industry to the 10th place based on a voluntary participation in the corporate sustainability assessment, designed for the Dow Jones Sustainability index.

In addition, YPF was included in S&Ps Sustainability Yearbook 2021, which includes companies with top-tier sustainability and ESG practices, ranking in the top 15% among oil and gas companies.

In line with our policy to promote cleaner and more efficient energy solutions, we have been working hard on reducing our direct greenhouse gas emissions.

We have set a target of 0.34 tons of CO2 equivalent per unit produced by 2023, and we are making good progress.

In 2020, we reduced the intensity of direct emissions by more than 2% as compared to 2019, already reaching 0.367.

Moreover, natural gas, which accounts for almost half of our hydrocarbon production mix plays a key role not only as a transition fuel, but also as a smart flexible partner for renewables intermittency.

We are committed to a cleaner oil and gas production by minimizing flaring, venting and methane leaks along our supply chain.

In addition, nearly 20% of the energy used in our operations in 2020 came from renewable sources, significantly advancing our target that was originally set for 2025.

In this front, YPF Luz, a power company controlled jointly with GE represent our strategic arm for the energy transition.

Despite the pandemic, YPF Luz managed to reach COD on several power generation projects between September and October, for an aggregate capacity of over 400 megawatts, including efficient thermal assets and renewables.

When including these projects now in commercial operation, the company has reached a total installed capacity of over 2.2 gigawatts, including more than 200 megawatts from wind farms.

In addition, another 231 megawatts are expected to be commissioned in the first half of this year, including 174 megawatts of renewable energy.

I will now go through our financial results for the year.

2020 figures were fully impacted by the effects of the pandemic.

It was an extremely challenging year for the worldwide oil and gas industry, and we will not be exception.

On top of the list, our revenues for the year contracted by 32%, mainly explained by a similar decline in fuel sales, both on lower volume dispatched as well as lower prices.

While natural gas revenues and jet fuel sales also contributed to the decline as natural gas prices dropped by about 30%, while jet volumes collapsed by more than 70%.

Compensating at least partially the severe decline in revenues, we managed to achieve a significant reduction in total costs that were down by 25% during the year or an even larger 30% when normalizing OpEx by eliminating some one-off items, as I will comment in a few moments.

While this was partially generated by the contraction in purchases and royalties on the back of lower volumes and prices, a key aspect was the reduction in OpEx, which produced savings of about $1 billion when eliminating one-off items.

This was the result of a company-wide structural cost-cutting program initiated last year that has already started delivering initial encouraging results.

But even more critically, as already commented by Sergio, we have reacted quickly and decisively upon the outburst of the unexpected pandemic to prioritize financial discipline by helping our investment plan, which was cut by about $2 billion when compared with the previous year.

And on this same line, we managed to reduce our net debt by about $500 million along the year.

However, as conditions started to normalize in the second half, we have been gradually increasing activity, leveraging on the cost efficiencies already secured, with CapEx reaching $538 million in Q4 more than doubling the amount invested in the previous quarter.

Based on the key variables already laid out, adjusted EBITDA for the year totaled $1.5 million contracted 60% year-over-year.

This figure was significantly impacted by nonrecurring charges in 2020, totaling close to $600 million, mainly related to abnormally high operating costs from rigs in standby mode, the voluntary retirement program for nonunionized employees, the reversal of Decree 1053 and the charge related to the termination fee of the floating LNG contract with Exmar.

When adjusting for these charges, normalized EBITDA would have reached over $2 million or 40% higher than reported adjusted EBITDA but still contracting by 44% year-over-year.

In terms of operating income, it is worth highlighting that during the fourth quarter, we recorded a reversal of an impairment charge of over $820 million, resulting in positive operating income for the quarter and leaving the cumulative figure for the year at a loss of $911 million.

The impairment reversal was driven by the revaluation of certain gas projects on the back of the confirmation of the new Plan Gas, which resulted in improved economics and midterm visibility for these projects, which was taken into consideration for the reassessment of the economics of our resources.

On a quarterly basis, adjusted EBITDA reached $183 million in Q4 or $385 million after normalizing for the nonrecurring items affecting this quarter.

This normalized adjusted EBITDA figure represented a 30% sequential decline, mainly driven by lower oil and gas production and higher OpEx resulting from the resumption in pooling and workover activities, despite the steady improvement in demand for refined products and the gradual recovery in fuel prices, all of which is fully in line with the guidance providing during the previous quarter's webcast.

Going into the upstream business.

Total hydrocarbon production for the year declined by 9%, in line with guidance provided in previous quarters as we adjusted investment and wellhead activity to face the effects of the pandemic on our financial situation.

Crude oil production went down by 9% year-over-year, averaging 207,000 barrels of oil per day during 2020 with lower conventional production being partially offset by higher shale oil.

On the natural gas front, production came at 36 million cubic meters per day, a decline of 10% versus the previous year, aligned with the company's objective taken in late 2019 to reduce natural gas production on the back of prevailing low prices as the supply overhang remain in place.

Finally, NGL production decreased by 5% year-over-year, mainly associated to lower gas production.

As economic conditions recovered on the back of the flexibilization of the lockdown measures, we have gradually resumed investment and wellhead activity, which had a negative impact in production in Q4 as total output decreased by 10% sequentially due to the temporary closing of wells to avoid interference while fracking and connecting new ones as well as program maintenance activities in natural gas pipelines.

During the year, our crude oil realization price averaged $40 per barrel, 24% down from the previous year.

This decline was lower than the close to 35% drop in Brent as local prices were not fully impacted by the collapse in international prices, given the introduction of the Barril Criollo on May 20, which established a minimum reference price for Medanito quality crude at $45 per barrel.

However, after the Barril Criollo expired in mid August, on the back of the recovery in Brent prices, local oil has since been freely negotiated following export parity.

On the natural gas side and still as a consequence of the excess offer, market prices were also below the previous year's realization price.

Our selling price averaged $2.6 per million BTU compared to $3.6 per million BTU in the previous year.

Going forward, we expect higher average realization prices, given that about 60% of our natural gas production will be sold through the 4 year contracts granted on the back of the new Plan Gas 4, at average prices of $3.66 per million BTU.

In terms of costs during 2020, we were able to reduce our average lifting cost by 19%, averaging $9.7 per barrel of oil equivalent, driven by operational efficiencies achieved on the back of our cost-cutting program as well as lower pooling and workover activities, primarily in the second and third quarters.

Therefore, although we expect cost reductions to be maintained and even increase in the future as the focus on efficiency became the new norm, lifting costs could increase in 2021, but still be well below 2019 levels as activity is fully restored and natural decline in conventional fields impacts the overall average.

Looking deeper into our shale production.

Despite the challenging environment, we were able to increase average production for the year by 9% when compared to 2019.

However, in Q4, shale production contracted 14% sequentially due to the maintenance works in gas pipelines and the temporary closing of wells in addition to a technical adjustment in the way we account for the NGL production coming from some non-operated blocks that generated a recategorization between natural gas and liquids for the previous quarters, with a net negative impact in total production in Q4.

More recently, in January, our oil and gas shale production has already started to recover, reaching 95,000 barrels of oil equivalent per day, up 7% versus average levels in the fourth quarter, while preliminary figures for February show a historical high from our operated areas, showcasing our investment focus on these assets.

Going into the right side of the slide, oil and gas conventional production for the year contracted by 12% compared to the previous year, with similar performance in both crude and natural gas production.

However, I would highlight that full natural decline was partially offset through the advancement of secondary and tertiary recovery techniques with encouraging results.

As an example, Manantiales Berg closed 2020 with the highest production in its history, reaching 21,600 barrels per day, increasing by 8% year-over-year, thanks to innovation and top-notch technology that allow us to improve the oil recovery factor.

Tertiary production averaged 2,200 barrels per day during the year compared to just about 100 barrels per day in 2019 and further increasing to 4,500 barrels per day last January.

YPF's ambitious EUR strategy in Argentina has included derisking of areas with high polymer potential to further expand those areas with proven pilot response.

The successful experience with tertiary recovery commenced in 2015 through an initial pilot using polymer flooding techniques at the green big field in Manantiales Behr, becoming the basis for the current operation of 5 polymer injection units at that field, while 3 additional PIUs are expected to be connected in 2021.

In addition, full planning for 2021 also includes the installation of 7 more PUS, 4 for the massification production at Chachahuen in Mendoza as well as 3 pilots at Los Perales and Cañadón León in Santa Cruz and El Trébol in Chubut.

Total investment for EUR development in 2021 is estimated between $60 million and $90 million.

Moving into the next slide.

As mentioned before, we have gradually started to resume activity in Q4 after having gone into a full stop during the second quarter.

As of the end of the year, we had over 80 rigs back in operation, including drilling, work over and pulling towers, which compares to an average of less than 20 pooling equipment in operation during the second quarter.

We have resumed activity in a more efficient way as each dollar invested having more power than in the past.

We have seen a significant improvement in frac speed, reaching 7 stages per day in Q4.

And while we expect this figure to be slightly worse in 2021 as the resumption in activity has mainly focused on our core hub, which has better logistics due to lower distances, it should still result significantly better than the average figure for 2019.

In addition, in January, we reached our historical record in terms of monthly stages totaling 412 fracs, outpacing the previous record of 3.85% reached in September of 2019.

We have also drilled the longest horizontal well in Bandurria Sur, which reached a lateral length of 3,800 meters and an IP of 2,200 barrels per day.

On the conventional side, we have accomplished a significant reduction in pooling intervention time as total hours per intervention in Q4 were 26% below the average for 2019.

And in terms of future opportunities, for 2021, we come with efficient sources of growth, thanks to the drill but uncompleted wells that we have in our backlog.

By the end of 2020, we have already connected 18 of the 81 DUC wells that resulted from the complete activity held in Q2 and plan to connect 48 additional wells during the first half of this year, with their associated production expected to reach 33,000 barrels of oil equivalent per day by the end of the second quarter.

Going into the evolution of hydrocarbon reserves, in 2020, 1P reserves contracted to 922 million BOE.

This decline was mainly driven by the reduction in investment activity.

While also being negatively affected by the impact from lower prices, we generated a downward revision of over 100 million barrels of oil equivalent, which more than offset the upward revision related to OpEx savings for about 50 million BOEs.

Despite this, the reserve replacement ratio for shale stood close to 150%, with our high-quality net shale reserves expanding by 5% year-over-year, now representing 39% of total proved reserves, up from 31% in 2019, led primarily by the incorporation of natural gas reserves, given the viability of new projects associated with the new plan gas that was already commented in this presentation.

Finally, the price visibility provided by the new Plan Gas, together with the overall lower cost base, also led to a significant addition of 2P and 3P reserves.

Total reserves, including proved, probable and possible, grew by 7% during the year as 3P reserves increased by more than 100%.

Switching to our downstream business.

Demand for refined products dropped significantly during the year, affected by the lockdown measures in place since late March.

During 2020, gasoline contracted by 30% and diesel by 11%.

The worst monthly record was in April when gasoline and diesel volumes contracted by about 70% and 35% year-over-year, respectively.

Since then, demand has gradually but steadily improved, closing the year with gasoline and diesel demand at minus 7% and minus 5%, respectively, compared to December 2019 levels.

Additionally, preliminary data for this year shows further improvement in diesel and stabilization for gasoline.

Separately, given the collapse in local demand, we explore the regional export market as an opportunity to take advantage of our [idle] refining capacity.

On this front, we managed to once again export fuels to Bolivia after 12 years and to Uruguay after more than 5 years, thus regaining our ability to act as a regional exporter of refined products.

In terms of refinery utilization, we reacted quickly to the falling demand and immediately adjusted our processing levels.

Thus, capacity utilization averaged 73% in 2020, down from 87% in 2019.

However, utilization has been increasing in line with recovery in demand after reaching its lowest level in April at 47%.

Utilization for the fourth quarter averaged 75%, and data for January shows average refinery utilization already at 86%.

On this topic, it is worth highlighting that despite the logistics complications generated by the pandemic, we decided to move forward with the program major maintenance at our La Plata refinery, taking advantage of the low demand environment to minimize economic impact.

Excluding these works, which ended in October, utilization would have been at 79% during the fourth quarter.

With regards to prices, the pandemic affected international reference oil and refined product prices in a very significant way, reaching levels not seen since 2003.

In this context and on the back of a weak macroeconomic local environment, our net fuels realization prices in dollar terms were in a sliding scale until we have managed to start with periodic adjustments back in August.

This permitted to stabilize our net prices in dollars and, more recently, regain some margin.

However, even after the cumulative increases since August, our average net prices for 2020 measured in dollars still stood about 15% below the average levels of 2019 and about 30% below the average for the past 10 years.

As mentioned before, we launched a cost-cutting plan across the company, and this effort should not only render very significant savings in our structural operating expenses, but also an equally or even more importantly, on our CapEx costs.

We have already reviewed about 90% of all vendor contracts and revisited a good portion of our internal operating processes, achieving important savings in key activities and have renegotiated conditions with the unions, introducing KPI-related compensation and flexibilizing working conditions.

Furthermore, in July, we launched a voluntary retirement program for nonunionized employees, which closed by the end of August and will allow us to organically reduce our overall size and G&A costs.

This program resulted in a reduction of 13% of our nonunionized workforce, having a total estimated cost of $125 million and generating future savings of over $50 million per year.

Early results are very encouraging for both OpEx and CapEx.

Normalized OpEx was down 24% year-over-year, both for full year 2020 and in Q4.

Normalized OpEx was calculated by excluding one-off items affecting the figure in 2020, such as the termination charge for the contractual agreement with Exmar, the cost of the voluntary retirement program, standby costs and the provisioning of gas distribution companies receivables related to FX variations granted by Decree 1053.

However, while it is fair to highlight that this decline was also the result of reduced activity during 2020, we expect cost efficiencies secured primarily during the second half of 2020 to render overall OpEx savings for 2021 when compared to pre-pandemic levels in the order of 20%.

On the CapEx side, further to the significant reductions in development costs already achieved along recent years at our oil hub at Vaca Muerta, we are very confident about the investment efficiencies that we are currently achieving through renegotiated contracts and new well designs.

We, therefore, expect average development costs for our core shale oil hub to decline by an additional 15% in 2021 when compared with pre-pandemic levels.

Turning to cash flow.

Let me start by reiterating something that was already mentioned in previous quarters about the impact of Central Bank Communication 70-30 on our liquidity position.

The regulation established by that communication, which restricts corporates in Argentina from holding liquid assets abroad, if they want to continue being granted access to the official FX market has led us to hold most of our liquidity locally and in pesos.

Given this situation and taking into consideration the dollarized nature of our long-term business, we have been monitoring our liquidity exposure related to FX variations, net of the stock of peso-denominated debt, which acts as a natural hedge.

And based on the residual exposure, we have decided to reduce the overall liquidity position, while at the same time, actively entering into FX derivatives to further hedge, at least partially our net exposure.

As a result of this, as of December 31, our net FX exposure related to our liquidity position stood at less than 30%.

Along this line, financial discipline continues to be a key priority for us, particularly during these uncertain times.

During 2020, our conservative approach on the back of the effects of the pandemic led to positive net cash flow from our operation as the results in operating cash flow was more than compensated by a further decline in investment activities.

This, together with the decision to reduce our cash position resulted in net negative borrowing of $471 million during the year.

Moving into our debt profile.

In July 2020, we managed to successfully secure a significant short-term debt relief after refinancing almost 60% of our $1 billion 2021 bond.

However, the enactment of Central Bank Communication 7106 in September changed the landscape.

Within this new regulation in place, and despite the refinancing executed earlier in July, we were required to either refinance at least 60% of the residual amount of $413 million on our 2021 bond or otherwise secure an equivalent amount of cross-border financing to be able to fully honor our commitments.

Given the limited options at hand and after formal confirmation from the Central Bank of our obligation to comply with the regulation, in spite of the earlier refinancing performed on the March 2021 bond, we launched a broader exchange offer last January, not only inviting receivable holders of the 2021s, but also holders of the rest of our international dollar-denominated notes with an aggregate face value of $6.2 billion.

It is important to highlight the rationale behind the decision to invite all outstanding bonds into the exchange offer.

As was commenting during the transaction, we consider that it was inequitable to offer such alternative only to holders of the 2021 bonds and not to the rest of our investor base, in case those investors consider it convenient to also exchange their short-term cash flows for a piece of the enhanced senior security that was being offered.

And if investors were to see value in the offer, the company would, in exchange, get a much needed cash relief to help in the process of obtaining indirect financing to fund the CapEx program for 2021 and that reverting the oil and gas production decline over the last 5 years.

The exchange resulted in a global participation of 32% and 60% in the case of holders of the 2021, allowing us to comply with the Central Bank regulations, thus avoiding a potential and voluntary nonpayment situation and generating a financial relief of around $600 million on aggregate for 2021 and '22.

We understand this successful result was possible primarily due to the reasonable proposal that was presented to the market and the open and constructive dialogue that we held with investors along the process, which permitted us to adjust the offer to accommodate investors' concerns while staying within parameters that we could commit to in the long term.

As a final demonstration of the success of this transaction, earlier this week, S&P announced a 2 notch upgrade to our international credit rating, taking it to CCC plus and mentioning it now being limited by the sovereign rating, while the stand-alone credit profile was further raised to be minus.

Supporting this decision, the rating agency quoted the post debt exchange cash flow relief that will free up capital to invest in production and recover volumes.

Looking forward, we have included a pro forma amortization schedule of our consolidated debt to reflect the post exchange adjustment of our debt stock as of December 31.

In summary, with this exercise, we have managed to significantly reduce refinancing risk for 2021 as most of the debt that comes due is in the local markets, both local bonds and bank loans, while cross-border maturities, excluding subsidiaries, debt that was already repaid or refinanced during January and February, and after netting the $165 million of the residual amount of 2021 to be canceled on March 23, stand at $275 million and are primarily concentrated in trade finance bank loans, which are typically easier to roll over.

Furthermore, very recently in February, after the consummation of the international exchange, we accessed the local capital markets, being able to successfully raise over $120 million equivalent through the combination of a reopening of a 3-year dollar-linked security at a yield of 3% and the new 42-month inflation-linked note at a real rate of 3.5%, both providing very competitive financing conditions.

Finally, let me add that although we have managed to further reduce our net indebtedness in the fourth quarter, our net leverage ratio calculated as net debt over last 12 months EBITDA has jumped to 4.9x on the back of the contraction in EBITDA during the most recent quarters.

And also worth noting, this ratio stood at the lower 3.7x when calculated based on the definitions for covenant purposes.

However, while leverage is likely to continue to increase this quarter as the full effect of the pandemic will be included in the rolling 12 months used for EBITDA calculation purposes.

Although we anticipate adding net new funding during the year, we expect net leverage to decrease in coming years as net indebtedness stabilizes, while EBITDA recovers, provided that market conditions continue to normalize and no particular contingencies materialize.

I will now switch back to Sergio to go through the outlook for 2021.

Thank you, Alejandro.

Now let me briefly go through what we expect for the year 2021 before moving into our Q&A section.

First of all, although we shall continue prioritizing our financial commitments on top of the investment activities, we expect to be able to accommodate our CapEx plan for the year set at $2.7 billion.

Funding should come from an enhanced cash flow from operations and increase in net debt within manageable levels and the potential sale of some nonstrategic assets.

Given efficiency gains secured in 2020 and those that are still expected to be achieved, each dollar invested from 2021 onwards will be more powerful, allowing us to progressively revert oil and gas production.

In this regard, we expect to invest close to 80% in the upstream segment, a 90% increase compared to 2020, still focusing investments included at $1.5 billion and around $600 million towards developing gas assets, mainly in line with our commitments under the Plan Gas 4.

When comparing full year production in 2021 versus 2020, we expect it to be relatively flat at around 208,000 barrels per day in crude and 35 million cubic meters per day in natural gas.

However, we expect production to increase in the second half by about 5% in crude and 9% natural gas compared to the same period in 2020.

So far, when looking at data for January and February, we are performing slightly better than our plan.

In addition, it was recently announced by Argentina's President that the executive power will send to congress a new oil and gas bill with special conditions to attract new investments such as export promotion, foreign currency access, stable pricing mechanism and special fiscal benefits.

Although we are not aware of the timing or the specific details of this new law, we are hopeful that it will incorporate attractive incentives.

And so once enacted, it should be a very useful tool to increase production levels, not just for YPF, but for the whole argentine oil and gas industry.

I am optimistic about reaching a new growth cycle for YPF.

The efforts made in 2020 towards becoming leaner and more efficient shall continue in the future as part of the model.

And it should provide for a better shaped company, more resilient in its operations and with discipline approach towards capital allocation.

I truly believe that we will have a much stronger 2021, both for the company and its stakeholders.

As I stated before, we will continue focusing on shale oil as our main driver for future growth.

Within unconventionals, more than $500 million will be deployed in our shale oil operated core hub, which is integrated by Loma Campana, Bandurria Sur and La Amarga Chica blocks.

These projects with proven track record in terms of productivity, have key facilities already in place, which drastically improved the cash flow profile as we will only need to direct about 15% of the total CapEx to incremental facilities.

During 2021, we expect to drill 90 wells in these 3 blocks, taking our net crude production from the current 33,000 barrels per day to almost 53,000 barrels per day at the end of 2021, a 60% increase.

Even after achieving the results, the average development rate for these blocks will continue being relatively low.

So we still see huge potential going forward, estimating a net production plateau of more than 130,000 barrels per day by 2027, with further potential from the future development of the Aguada del Chañar block, also projecting very competitive breakeven prices in all 4 blocks.

Following the new planned gas incentives, during 2021, we will invest $500 million in gas developments, over 80% of the total CapEx for the gas segment.

Also, when looking at the entire program, we plan to invest more than $1.5 billion in aggregate during the 2021, 2024 period, drilling more than 250 wells, including both operated and non-operated blocks.

The key projects that will provide new production in the immediate future are mainly those fully owned and operated by us, such as Rincón del Mangrullo and Aguada de la Arena.

But other projects such as La Calera and Rio Neuquén, where we have joint ventures in place, while also contributing in 2021 are projected to have a more significant contribution in coming years.

That would be all from our side.

Before taking your questions, let me once more thank you and the whole investor community for your support.

(Operator Instructions) Bruno Montanari with Morgan Stanley.

I have plenty of questions, but I may restrict to 2, 3. The first one is about this potential new bill that is going to pass.

So why would this time be different?

I mean, we've -- over the past decade, I think we saw a lot of incentives and new laws trying to be passed.

So I wanted to get your view on why an international company could be comfortable to invest again aggressively in shale in Argentina.

Second question is about working capital.

It seems that an important part of the cash flows in the quarter came from working capital release, mostly receivables and inventory.

So I was wondering how we should think about working capital in the coming quarters?

And the third question is about the asset sales potential.

So what would the company be willing to divest at this point?

I know you mentioned non-core, but could we eventually see YPF selling exploratory acreage in Vaca Muerta and some of the more perhaps non-core assets to raise a more significant amount of cash and then really be able to have a more comfortable short and mid-term debt amortization schedule.

Thank you very much.

Thank you, Bruno, and good morning to you.

Let me start by addressing, I would say, a more simple question, and then we'll go into more strategic ones.

Let me start with the working Capital one.

Let me say that probably you are commenting on the difference between the cash flow from operations and the EBITDA level for the year, which roughly has a difference of about $1.5 billion.

Part of that is not purely working capital.

Part of that differential comes from accounting reclassifications, primarily related to leasing expenses in the order of about a little less than half of that amount, about $700 million are represented by those reclassifications.

Then you also have some noncash items, mostly related to nonrecurring items included in EBITDA for about $400 million, I would say, which includes a portion of the voluntary retirement program that was noncash this year.

Also a portion of the cost associated with the early termination of the Exmar contract.

Also it's noncash in '21 and as it's being paid in installments.

So you have something there where you have noncash items in EBITDA or that are having working capital because we are financing that.

And then we do have specifically about $400 million in positive working capital in the year, mostly related with collection of legacy planned gas programs.

And going forward, I would say that we would expect positive working capital impact in this year, in 2021, probably in the order similar to what we had last year in the order of about $500 million, I would say, roughly speaking.

Going into your other questions, more generally speaking, and then I will turn to Sergio to comment a little bit more on the potential hydrocarbon law that is being discussed and potential asset sales.

But generally speaking, what I would say is that, well, clearly, the landscape for the industry as a whole is changing significantly on the back of this improved reference international prices for our industry, for oil in particular.

Then also what I would say is that once again, I think we are -- the achievements that we made in the latter part of last year of 2020 and the cost reductions that we secured during the last few months and that we expect to maintain or even improve in the coming years, basically puts our Vaca Muerta resource, in particular, at a very special point, right?

Basically providing us with attractive breakeven to consider aggressive investments for as long as we can accommodate those within our capital structure and maintaining financial prudency, which, as was mentioned by Sergio and during our presentation, is at the core of our strategic decisions.

So generally speaking, I would say that there is a tremendous opportunity for us to invest in developing this tremendous natural resource, which is still at a very low stage of development or an early stage of development.

But then also, there are -- as we expect, regulatory evolutions or regulatory considerations that could further improve the ability and the visibility such as the planned gas that was recently put in place, where we expect more of that down the road to further incentivize investments, not only by YPF, but also by international players.

But with that, I will let Sergio comment a little bit more.

Thank you, Bruno, for your question.

With respect to the new hydrocarbon law, as you may know, last Monday, Argentina's President announced that the executive power will send to congress a new oil and gas law with special conditions to attract new investments.

As you understand that this potential reform of the law is targeting 3 main goals.

The first one is to incentivize further investment of crude oil and natural gas to generate structural incremental volumes for exports by freeing up hard currency for producers related to exportable balance sheet and providing for some tax benefits.

The second goal is to encourage the execution of hydrocarbon distillation, such as LNG and petrochemicals through tax exemptions that in turn will contribute to substitute high-value imports and generate exportable surplus fuel and significantly improve the quality of fuel in the case of the refining.

And finally, regarding natural gas, we understand the focus is on incentivizing the production of natural gas under a scheme that allows producers to export 365 days a year enabling for long-term contracts, while ensuring the supply of the local markets.

At the same time, activities such as underground storage and development of LNG could be promoted in this law.

While we have an active and constructive dialogue with the government authorities, we are not aware of the timing of the actual measures, if any at all, that the executive power might end up presenting to Congress.

And with respect to the question about potential investments of assets.

Let me first summarize recent activities.

First, we reduced our stake at Bandurria Sur by 11%, which was acquired by Equinor and Shell.

Second, we sold for 15% stake in the offshore block, CAN 100 to Shell.

And third, we sold nonoperative office building to AySA, the local water utility company.

Going forward, as we commented in the past, we are focused on the oil and gas business in our core activities and optimizing our portfolio.

And in that regard and taking into consideration current financial restrictions, cash generation through divestitures of nonstrategic assets to provide us additional capital to permit a more rapid deployment of resources into oil and gas.

We are having conversations with several key international players for the possibility of entering into new farming agreements in Vaca Muerta.

And in addition, and at the same time, we are also analyzing a group of mature conventional areas of both oil and gas that might be subject to potential disinvestment, should we conclude that they could be operated more efficiently by a more flexible and focused niche operator, permitting us to allocate our resources to those assets where we can create the highest value for our stakeholders.

Finally, we will continue analyzing our portfolio of non-operating and non-strategic assets, and we likely look forward with the monetization should potential deal valuations will solve the reasonable.

Although we are working on some alternatives at this point in time and within the market environment we are living in, there is nothing material to comment on any particular relevant transaction.

Marcelo Gumiero with Crédit Suisse.

I have 2 questions here.

First one on lifting costs, so in lifting cost decrease substantially year on year, and I wanted to know as you mentioned in 2021 this could be higher.

I want to know how much of the 2020 listing cost was, I mean, continuous measures are one-offs?

And if you could provide a breakdown of those measures?

And how much we should expect lifting cost to rebound in 2021?

And the second question on CapEx and maturities.

And congratulations on being able to roll out the 2021 maturities and getting access to U.S. dollars and to service the debt.

But going forward, are YPF already comfortable with the maturity schedule?

And are you foreseeing the strategical change roll out maturities?

And I mean, if that was the case, I mean, could we expect a great level of CapEx still in 2021?

Thank you, Marcelo, for your questions.

In terms of lifting costs, and as we basically anticipated within our previous call in the third quarter, we were expecting lifting costs to increase somewhat in the fourth quarter as we remounted and resumed activity, mostly oil shale activity related to pooling and workover and O&M-type costs.

So definitely, we should expect more of that next year.

But in terms of the overall 2022 figure -- sorry, 2020 figure, what I would say is that roughly we could assume that about 60% or 2/3 of the actual cost reductions in lifting were related to actual cost efficiencies achieved along the year.

Well, I would say that about 1/3 of the reduction in listing cost was related to lower production and lower activity.

So all in all, that would basically mean that about 15% cost reductions were achieved during the year on average when compared to the previous year.

And that would translate into what we have presented in the -- during the presentation.

I mentioned during the presentation that we expect actual OpEx efficiencies, primarily lifting cost efficiencies to be in the order of 20% going forward.

So basically, what we expect is that when we compare operating cost and primarily lifting cost in 2021 versus pre-pandemic levels, normalizing for activity we would be -- we should be about 20% more efficient, thanks to all the efforts that were put together as part of our company-wide cost cutting plan.

But that may be mostly focused on the upstream business.

In terms of financial maturities and CapEx, your second question, what I would say is that after the liability management, the 2 liability management exercises actually that were performed, 1 in July and the second one very recently.

We now have a relatively smooth upcoming maturity profile, not only for the rest of this year, but also for the next few years.

Probably the next important bulk maturity only comes in 2025.

But looking more shortly to the next few months, I would say that for the most part, we have less than $100 million in maturities per month, averaging, I would say, more in line with $50 million with the exception of a couple of months related to 2 particular maturities, one, which is a syndicated -- a local syndicated loan for $250 million that comes due next June.

And then one local bond that matures in November for an amount of about $90 million.

So I would say that those are the only, I would say, relatively large maturities that we have ahead of us.

But again, both of them related to local market financing, both bank and local securities.

And we do not expect any significant or material risk in being able to refinance those maturities.

And on top of that, I would say that we do expect to even be able to access the local market for getting net new funding, as was commented also in the previous quarter and also during this presentation.

So we still believe and we are cautiously optimistic that our CapEx plan for the year, even though it has some risk that it should be achievable.

Of course, that will imply obtaining new funding and that will -- the exact amount will depend on how our cash flow from operations end up resulting.

And of course, there is still some uncertainties on that front given the uncertain environment that we are living in, mostly related to the pandemic.

And then also depending on actually, as was explained by Sergio before, depending on how we move on with the potential divestitures of nonstrategic assets.

So depending on all of that, we will have a resulting financial need for the rest of the year.

But in any case, we are feeling cautiously optimistic, as I said before, that we will be able to manage to secure the financial need to comply with the CapEx program that we had presented for the year of about $2.7 million.

Our next question comes from the line of Frank McGann with Bank of America.

Okay.

I was wondering if you could provide a little bit more information on the adjustments that were made for the abandonment costs because that seemed to be relatively significant.

And I was just wondering what were the exact amounts if you have them in the fourth quarter?

And then what really caused the change in terms of what your assumptions for the abandonment reserves that you have?

And how much of any adjustment, if any, was cash?

And then second, I was just wondering, 2021 looks like it's going to be a year where you see good improvement as you go through the year in terms of a little bit of acceleration in production.

I didn't know if you had any thoughts about the potential beyond 2021 in terms of what types of -- what type of growth you're targeting?

Sure.

Thank you, Frank.

In terms of the adjustment in abandonment costs -- in well abandoning cost, basically, that is mostly related to depreciation charges.

So it's -- first of all, it's fair to say that it's a noncash item affecting the evolution of the depreciation of the asset that is being booked as a counterpart to the contingent liabilities or future liabilities for the cost abandonment or the cost for abandonment of wells in the future.

So roughly speaking, the adjustment was related to primarily the estimated reduction in costs in part aligned with the overall cost reduction that the company secured in the last few months.

And also part of that is accounting issues related to the risk and value of those future costs.

So all in all, what I would say is that it's -- of course, it has an impact on our results and our income statement, but as I said, it's a noncash item.

And it's something that relates to the liability that the company has on the road, and I would say, for the next 30 to 40 years as wells become nonoperative and the company actually has to go ahead and proceed with the abandonment of those wells.

So all in all, in recent years, we've been spending, on average, between $30 million and $50 million, actually, cash, on well abandonment and for security purposes.

And we expect that level to remain the same in the future.

And again, so the adjustment is mostly related to depreciation issues, but more of an accounting than anything else.

And of course, if you have a further question from the technicalities on that, I will revert later on after this call for our technical team to provide you with further details on that because it's very technical.

Then in terms of production, as was commented during the presentation, we expect total oil and gas production during the year for 2021 to be relatively stable vis-à-vis 2020.

However, on a sequential basis, we see production increasing, both in oil and in gas.

Actually, when you look at -- and as was commented, when you look at the second half, production in oil should be around 5% higher than that of the second half of last year of 2020.

And then in terms of natural gas, it should be closer to 10% higher.

So that demonstrate clearly the CapEx program that we are anticipating and that we are predicting and aiming for.

And going forward, we expect that to continue in 2022, of course, always depending on our ability to work around the financial constraints that we expect to start subsiding in the coming future.

So all in all, and providing that no major modifications take place in terms of the possibilities to industrialize natural gas, as was commented by Sergio, as part of the potential new hydrocarbon law or anything like that, we are right now anticipating natural gas production to remain relatively flat in coming years.

And then, yes, of course, devoting all of our resources and our focus on improving and growing our crude oil production, primarily related to shale and primarily related to our core hub in terms of Vaca Muerta oil fields.

So that -- to the most part, I would say that, that's our look into future production.

Barbara Halberstadt with JPMorgan.

Most of my questions have been answered, but I would like to follow-up on 2 of them.

One is on liquidity.

And I just wanted to hear from you, what are you thinking in terms of minimum cash levels that if you're comfortable running the company with after of course the payment now in March of the '21, then all of this increased need for funding CapEx.

So just trying to understand what that level would be.

And also on the funding side, you said you're cautiously optimistic you'll be able to find the necessary resources to fund CapEx because I just wanted to get a little bit of more color on the debt side.

How much you're thinking in terms of incremental debt?

And if that would be sourced most likely?

Or is there -- or if the company is thanking of tapping international markets again?

In terms of liquidity and as was commented in the previous call and also in the presentation, we have voluntarily targeted a lower overall liquidity position, mostly related to Central Bank regulations, which prohibit us, I mean, the same as other corporates to hold a large position of our liquidity in dollars and abroad.

Basically, that required us to bring all of our liquidity onshore and being mostly held in local currency.

So because of that and because of the FX exposure that creates, we decided to work with an overall lower liquidity position.

So generally speaking, we feel comfortable with the total liquidity position that we had at the end of last year, so we will try to maintain roughly those levels.

Of course, seasonality will clearly depending on the cash flow seasonality that we have that could be somewhat modified along the year, but I would say that mostly will be in limited ranges, I would say, no more than 10% to 15% plus/minus the liquidity position that we had at the end of last year.

And that will include the upcoming payment on the receivable amount of the 2021 bond that is coming due on next March '23.

So based on that is that we will maintain that liquidity target in mind, and as Sergio was saying, we continue to prioritize our financial commitment, the same way that was done in 2020.

So I would say that the adjustment variable will continue to be our overall CapEx level.

But hopefully, we will be able to secure all the funding needed to comply with our CapEx target, as was mentioned before.

So in that front, again, it will depend -- the total amount needed from -- in terms of financing will depend on the final cash flow from operations and the potential divestiture.

But in any case, we do have -- we are working on different alternatives in terms of funding financial securities or financial instruments.

A good part of that we expect to come from the local market.

And also, we are exploring some potential cross-border alternatives, but mostly related to trade finance and potential multilateral agencies or multilateral type financing that we are exploring as well.

We -- at this point, and based on how our bonds are trading and the perception of investors, we do not expect to tap the bond, the international bond market in coming months or during the rest of the year to cover our funding needs.

Andres Cardona with Citigroup.

2 questions.

The first 1 has to do with the shale projects, in which you are investing $1.5 billion over the next 4 years.

Can you break down the lifting cost and cost per barrel?

In general, what I'm looking for is the breakeven for this time of projects.

And the second one is, when looking at the investment program for Bandurria Sur, La Amarga Chica and Loma Campana, I would like to understand how many wells are going to be drilled in each of these fields.

And if you can share some details about the 2021, 2024 program, in terms of CapEx and wells, also really the fields?

Thank you, Andres.

Well, unfortunately, we are, at this point, not fully disclosing some of the information that you are requesting.

But let me give you some general idea that I would expect to will serve the purpose of getting you comfortable with our expectations.

First of all, in terms of the 2021 to 2024 CapEx plan that we have related.

When you mentioned shale, probably, I would assume that you're referring to the CapEx plan related to our commitments towards a new planned gas, which is mostly sourced from shale fields, although those will have some conventional fields that would contribute such as È.

But generally speaking, on those projects, and again, we are only now assuming significant activity in terms of exploiting more aggressively our natural gas resources.

So of course, our breakeven they are still to be materialized although we do see the new prices provided -- the new price guidance or the new price opportunities provided by the new planned gas that as was commented is $3.66 per million BTU, flat on average for the next 4 years.

We do expect those prices to be more than enough to leave reasonable profitability for us to work on the development of our natural gas projects.

So down the road, we expect -- as we do see the materialization of those efforts come to reality, we do expect to be able to provide you more color on the actual development costs and hopefully also potentially the actual breakevens on those projects.

Now in terms of the core hub for oil, as you were asking for Loma Campana, Bandurria Sur and La Amarga Chica, as we commented, we are expecting an overall investment this year of somewhat over $500 million, expecting to drill about 90 wells during the year.

The breakdown between the different 3 fields or the 3 different projects, is roughly the same, probably you have a little bit less wells that are going to be drilled in Bandurria Sur than in the other 2, but roughly, you are talking about similar amounts invested in the 3 different projects.

And down the road, we expect similar level of activity in coming years, I would say, mostly 22% to 24%.

We will expect a similar amount of CapEx and amount of wells to be connected or completed in coming years.

And then probably expect a ramp-up in activity from '25 onwards to get closer to the plateau that was mentioned during the presentation by Sergio that we are expecting by 2027 at reaching a plateau of over 130,000 barrels per day among these 3 projects.

So that's -- and for that, I would say that you basically have an idea of how we are planning on that.

And by that time, of course, this oil production coming from our key shale fields will probably represent more than 50% of our total oil production by then.

Ezequiel Fernandez with Balanz.

So basically, I have 3 questions.

I would like to go one by one, if you don't mind.

The first one is related to fuel demand in Argentina.

If you could share with us your thoughts on what has been or what you think has been the structural impact of the pandemic, thinking about changes in mobility patterns, remote work and so on, on fuel demand in Argentina.

And more on the long term, what you're seeing or thinking about electric vehicles adoption and the impact on the Argentina oil demand as well?

Sure.

Thank you, Ezequiel.

Let's start with that one.

In terms of structural impact of the COVID pandemic into fuel demand, it is hard to predict yet, as we are still at the early stages of potentially understanding structural impact.

However, what I would say is that by the end of last year, and as was mentioned in the presentation, fuel demand recovered very significantly.

And I would say that even faster than we have anticipated, closing the year with ranges in the 5% to 7% between diesel and gasoline in comparison to pre-pandemic level.

And as of today, we have seen demand further improving, basically almost being flat in terms of diesel or close to flat and about 5% down on gasoline.

So it's still early to say those numbers, those figures would tend to imply that there could not -- there might not be a significant structural impact.

But again, as I said, it's -- I would say that it's still early to predict.

And we do expect to close the year -- based on our budget for the year, we do expect to end the year still a little bit below pre-pandemic levels, but in the order of 5% below pre-pandemic levels, although current levels might imply that we were conservative on that.

But of course, it's hard to predict.

We don't know whether there is going to be a second wave of contagion and a potential impact on lots of measures down the road.

We are not predicting that.

And so it's -- again, unfortunately, it's still early to call it a final decision on structural impact.

And in terms of potential impact from electric vehicles, also, I think in Argentina, at this point, it's very hard to predict when and how that will actually penetrate our market.

We still see an important evolution in developed countries.

But still, when you look at proportions, it's very timid.

And so it's -- I would say, at this point, it's very hard to predict the impact that we will face in coming years from the introduction of electric vehicles in our country.

Great.

My second question is related to the refineries output.

If we look into 2019, and if we are doing the math right, the diesel and gasoline output mix was roughly 80%.

And now we seem to be closer to a 70% mix for diesel and gasoline, basically a more diversified output mix.

Do you expect to revert back to that 80% mix if the old demand recuperates?

Ezequiel, 1 second, because it's a little technical, I'm getting some color on that.

Bear with me for a second.

If it's -- we can take it after the call if it's better.

No worries about that.

Yes, maybe that's better because it's a little bit technical, at least for me.

And maybe it's better to -- yes, if we can follow-up after the call, that will be better.

But yes, clearly, 2020 was a very particular year, and we adjusted.

On a general concept, we adjusted the refinery output to actual demand.

We managed to compensate mostly the reviews of the lower demand for jet fuel to compensate for further output of diesel.

And then -- but the general rebalancing between gasoline and diesel and other products, clearly we may have some other refined output that was designed to different markets.

So that, yes, maybe it's better to follow-up after the call.

Okay.

Perfect.

So my last question is, I think that's clear, anyway, it's helpful.

My last question is related to the latest Plan Gas 4 auction that we saw for -- just for winter volumes, the small one.

I was wondering why you opted not to participate.

So I think that's a very -- that's a more tactical and commercial decision the way our gas, natural gas business unit decided to make -- or make the best use of the opportunity created by the new Plan Gas.

And different companies have different approaches there.

And we understood that the way to maximize the benefit for us on a year-long basis or along the year was to -- the way we did it with 1 bulk participation for -- without seasonal adjustment, and that's -- no particular reason, basically, a decision on how to maximize and optimize the opportunities created by the plan.

And remember, Ezequiel, that -- this is Sergio, we participated in the planned gas with almost 21 million of -- cubic meters per day, I mean from the 70 million, 21 million cubic meters per day came from YPF with the prices that we explained before, $3.66 per million BTU, but it was a commercial reason that -- not to participate in this new plan.

Understood.

Commercial reasons.

That's great.

Luiz Carvalho with UBS.

Sorry, maybe to come back to the cash flow discussion.

When we tried to reconcile the numbers here, have a CapEx at $2.7 billion and debt interest of around $900 million, plus some amortization this year despite of the dollar debt maturity that you were successful.

And when we look to the -- we had cash availability of $1 billion and the potential EBITDA that you would be able to deliver, we still see a significant cash burn to this year.

And looking to your average at close to 5x and the recent debt negotiation, we still struggle to see how the company will succeed in terms of become again free cash flow positive and reduce the debt.

So just first question is, can you help me to try to reconciliate the -- I don't know how you plan to address the situation apart from cost reduction and so on?

And the second question is basically a follow-up on a previous question.

Maybe why not be more aggressive on divestments, I don't know, the non-core assets or even core assets in order to try to reduce the debt in the bit more short-term?

Thank you, Luiz, for your questions.

In terms of cash flows, basically, the way we look at it is, yes, we have this plan of $2.7 billion in terms of Capex, which is the amount of Capex, primarily related to the $2.1 billion targeting the upstream business.

And the basis for that is primarily reverting the production decline trend that the company experienced in the last 5 years, which was particularly affected in the last year in 2020 on the back of the clear hope that we had to pursue on our investment activity last year in the back of the pandemic.

So to be able to get to that level, it will depend on a number that the key number there is what's going to be the cash flow from operations during 2021.

Unfortunately, given the still some uncertainties that we have ahead of us, we are not providing a particular guidance on our EBITDA figures.

We will say what we expect in terms of working capital improvements and working capital contributions already in this call, but we are not yet fully mentioning or disclosing our EBITDA projections for the year.

Of course, we do expect a significant recovery in EBITDA last year.

And as it was mentioned during the presentation, even though we report the adjusted EBITDA is in the order of $1.5 billion, when netting for one-off effects the EBITDA level for the year was $2 billion, and that is with a collapsing demand and with very low realization prices.

So we do expect all of those to continue to rework and continue to improve along this year.

So clearly, the $2 billion, excluding one-off items of last year, will serve the purpose of providing you with a clear floor in terms of our expectations for EBITDA for next year.

And of course, we are expecting something significantly better than that, probably not yet reaching the levels that we see pre-pandemic.

So when you combine those 2 figures and including the working capital contributions that we expect, yes, we still have an amount or -- for the gap that will need to be financed, and that will come -- or that should come from the combination of divestitures and net new debt.

And we've been saying that since the previous call that most likely within 2021 we were going to have to go for the market to increase the amount of net debt.

And the reason for that is, of course, we need to put together a more aggressive CapEx program this year while our cash flow from operations or our ability to generate cash is still somewhat limited.

So, however, as we managed to get -- or to fund that CapEx -- that amount needed to comply with our CapEx target, and as we start putting our production back in line for stabilizing it this year and sequentially growing and expecting that to continue next year, we do see the combination of the incremental EBITDA or the normalization in EBITDA in itself stabilize our net leverage in terms of proportions.

And so we do not see a tremendous need at this point to more aggressively to reduce net debt.

That's why the ideas or the objectives of divestitures are more related to funding, partially our CapEx program, but not that much aggressively targeting a net reduction in debt because we believe that the overall net debt should stabilize itself by the improvement in EBITDA in coming years and not that much the need for a nominal reduction in the amount of debt.

So that relates to your second question in terms of being more aggressive in divestitures.

Again, we do actively pursue divesting nonstrategic assets.

And as was commented in the press, we even are considering selling our iconic headquarters office building and -- to generate cash because all that is nonproducing we are willing to contemplate and to put up for sale.

But in terms of the more strategic Vaca Muerta assets, at this point, we are not considering a full divestiture, but rather, as Sergio had mentioned before, potential JVs for further fundings.

Definitely, that's an efficient way of accelerating the development of those assets, which is not only good for YPF, but also for the country in terms of accelerating the development of the hydrocarbon reserves and producing more oil and gas as soon as possible.

So that's -- I hope that I answer your questions, but that will be the general answer.

There are no further questions at this time.

It is now my pleasure to turn the call back over to the YPF management team for final remarks.

Okay.

Thank you everyone for joining us today on this call, and thank you for your continuing support.

And of course, we remain open for any further questions that you may have.

Our IR team, as always, is open and ready to answer all your questions and concerns.

And with that, I will just close it, and thank you all, and have a good day.

This concludes the YPF full year and fourth quarter 2020 earnings call.

We thank you for your participation, and you may now disconnect.