Ladies and gentlemen, thank you for standing by. My name is Bhavish, and I'll be your conference operator today. At this time, I would like to welcome everyone to the YPF 3Q 2023 Earnings Webcast presentation. At this time, all lines have been placed on mute to prevent any background noise. I will now hand the call over to Margarita Chun, Head of Investor Relations Manager. You may begin your conference. Good morning, ladies and gentlemen, and welcome to YPF's third quarter 2023 earnings call. My name is Margarita Chun, and I am the new Investor Relations Manager at YPF. Let me start by saying that it's my pleasure to have joined YPF, the largest and leading energy company in Argentina. This presentation will be conducted by our CEO, Mr. Pablo Iuliano, and our CFO, Mr. Alejandro Lew. During the presentation, we will go through the main aspects and events that explain the quarter results. Due to agenda issues, our senior management has to pre-record this presentation and will not be available for the usual Q&A session. However, the IR team will be open for any further questions. Before we begin, I would like to draw your attention to our cautionary statement on slide two. Please take into consideration that our remarks today and answers 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 expectation contemplated by these remarks. Our financial figures are stated according to IFRS, but during the call, we might discuss some non-IFRS measures, such as Adjusted EBITDA. I will now turn the call to Pablo. Please go ahead. Thank you, Margarita, and good morning to you all. Let me start highlighting that this was another quarter in which we continued delivering a solid operational performance. Total hydrocarbon production with 520,000 barrels of oil equivalent per day, rising 1% sequentially and 3% on a year-over-year basis, mainly driven by a sound performance in our shale operations, which recorded an internal expansion of 16%. Focusing on crude oil production, we've recorded a slight sequential decline of 2%, mainly in our shale operations, bouncing back since September, on track to meet the production target for the full year. Adjusted EBITDA reached $926 million in the quarter, decreasing 8% sequentially and 38% compared to the Q3 of 2022. The lower outcome compared to the previous quarter came especially on the back of lower domestic fuel prices in dollar terms, mainly triggered by the discrete devaluation in mid-August, not fully passed through in the retail segment, and a downward trend in the prices of other refinery products, other than gasoline and diesel, partially offset by higher seasonal natural gas sales. Our bottom line came in at a loss of $137 million in the Q3, particularly affected by an impairment charge in our natural gas assets of $506 million pre-tax, primarily on the back of lower long-term expected prices as a result of increased competition and potential oversupply in the domestic natural gas market in coming years. This revised outlook for the local natural gas market further biases our strategic view of prioritizing oil versus gas in terms of profitable opportunities in the short terms and medium terms, leading to lower expected natural gas production volumes in coming years compared to our previous forecast. In terms of our investment activities, we continue deploying our aggressive CapEx plan during the quarter, which increased 13% sequentially and 36% on a year-over-year basis, accumulating more than $4.2 billion during the first nine months of the year. With regard to the CapEx target for 2023, we expect to end with a slight upward deviation as a result of higher cost in dollar terms. On the financial side, Free Cash Flow was a negative $379 million, as expected, as the deployment of our investment plan was not fully compensated by the cash flow from operations, taking our Net Debt almost $6.7 billion and increasing the Net Leverage Ratio to 1.7 x. For the full year, we expect that the combination of the slightly higher CapEx mentioned before, together with a lower Adjusted EBITDA level for a full year compared to our previous internal estimates, to result in the leverage ratio exceeding the ceiling guidance of 1.75 times, provided at the beginning of the year, also remaining within prudent levels. On a final note, let me briefly comment on the recent development related to the disruption in the normal supply of fuels to consumer and fuel prices increases. During the Q3, we recorded the highest level ever dispatched of diesel and gasoline, which extended even further during October. Additionally, since the end of July, we have been executing program maintenance stoppage at our Luján de Cuyo and La Plata refineries, which combined with a lower portion of biofuels in the blend due to reduced availability in the local market and some delays in the regular process for importing fuels in October, stressed our supply logistic in certain regions of the country. However, at YPF, we led a broad sector effort to face this exceptional demand high, through higher than historical imports, particularly in October, and a significant inventory drawdown that allowed us to normalize the local supply during the first days of November. In terms of local fuel prices, after September 3, we introduced two price adjustments at the pump. One in late October, primarily aiming to compensating an increase in biofuel prices, and more recently, last week, by an average of 10%. Therefore, and in conjunction with the government policies that extend during October, tax refunds on imported gasoline and diesel, we managed to mitigate, to a large extent, the economic impact of imported volumes running above normal levels, managing to partially reduce the gap of local fuels prices to international parities. Going forward, although the global and local environments are full of challenge in coming months, we will remain committed to exploit the huge opportunities that we have ahead of us. In that sense, the cumulative results achieved in the first nine months of the year permit us to reaffirm our oil-oriented growth strategy, while maintaining profitability and financial prudence at the forefront of our decisions. I now turn to Alejandro to go through some further details of our operating and financial results for the quarter. Thank you, Pablo. During the quarter, our total hydrocarbon production grew modestly compared to the previous quarter, but still resulted in an increase of 3% on a year-over-year basis. Crude oil production recorded a slight sequential decline of 2%, mainly due to interference effects of new well construction activity over existing production in our Shale Core Hub fields, together with some delays on our program for new tie-ins. But later in October, we have recovered our healthy growth trend, surpassing the 100,000 barrels per day average for the first time in our shale oil production, being on track to meet the total oil production target of the year. Beyond crude, natural gas production increased 3% sequentially to 38 million cubic meters per day, primarily driven by demand seasonality, while NGLs production increased by 9% quarter-over-quarter. The positive interannual evolution in hydrocarbon production came, as expected, on the back of our total shale production, which continued delivering solid results, expanding by 16% year on year, mainly led by our shale oil production. On the conventional side, crude oil production was 1% below the previous quarter, mainly driven by the natural decline of our mature fields, mostly compensated by our tertiary production, which increased 9% sequentially and 30% versus the same period of 2022. The positive evolution in tertiary production came primarily from Manantiales Behr block, our flagship project that represents almost 70% of our EOR production, together with the solid results of the pilots deployed at Chachahuen in Mendoza and El Trébol in Chubut. Moving to costs, lifting averaged $15.6 per barrel of oil equivalent across our upstream operations, 2% below the previous quarter, primarily driven by the evolution of macroeconomic variables, while lifting costs for our Shale Core Hub operations remained almost stable sequentially at a very competitive level of $4.2 per barrel. Regarding prices in the upstream segment, crude oil realization prices averaged $61 per barrel in Q3, declining 4% sequentially, mostly driven by a contraction of Medanito crude oil price, which was set at $56 per barrel as of mid-August, based on an agreement between local refineries, upstream companies, and the Secretary of Energy, partially offset by growing crude oil exports. On the natural gas side, prices increased about 9% sequentially to an average of $4.3 per million BTU, as a result of the seasonal adjustments within the planned gas contracts. Zooming into our shale activity, during the quarter, we completed 38 new horizontal wells in our operated blocks, reaching a total of 117 completed horizontal shale wells during the first nine months of the year. We also continued increasing the rhythm of drilling activity to enlarge our inventory of drilled but uncompleted wells. In that sense, in Q3, we drilled 47 new horizontal wells in our operated blocks, mostly oil-producing blocks, and only one targeting shale gas, aligned with the aforementioned strategy of prioritizing our shale oil opportunities, accumulating a total of 141 drilled horizontal shale wells during the first nine months of the year, 24% higher than the same period of 2022. It is also worth noting the remarkable interannual expansion of our shale oil production of 20%, averaging 92,000 barrels per day during the quarter. Despite the minor sequential contraction of our unconventional oil production recording in Q3, more recently in October, based on preliminary figures, shale oil production jumped 11% to over 100,000 barrels per day, accumulating an increase of 68% over the last two years. In terms of efficiencies within our shale operations, in Q3, we continued setting new quarterly records on drilling and fracking performance, averaging 297 meters per day in drilling and over 217 stages per set per month on fracking, increasing by 14% and 12% respectively when compared to the previous quarter. It is worth mentioning that during September, we achieved the highest drilling speed for one well in Aguada del Chañar block, reaching 415 meters per day for a well of over 3,200 meters of horizontal length, which was fully drilled in 14 days. As a result, average development cost for our core hub oil operations remains stable at $10.1 per barrel of oil equivalent. We strongly believe that maintaining our focus in the continuous improvement of our well construction operations in Vaca Muerta is key to maximize value generation for all of our stakeholders. In addition, we are moving forward with the strategy of exploring new shale opportunities beyond Vaca Muerta. In that regard, in September, we were awarded with two new shale exploratory concessions in Palermo Aike, La Azucena, and El Campamento Este blocks, to explore their potential in coming years. More recently, in October, we started drilling the first-ever horizontal well at the Palermo Aike formation in El Cerrito block. Now, let me briefly comment on the progress achieved in the different initiatives aimed at unlocking the oil evacuation capacity of the Neuquén Basin. Regarding the evacuation to the Pacific, during Q3, we continued growing oil exports to Chile through the Trans-Andean Pipeline, totaling 1.7 million barrels of oil, which represented 8% of our total oil production and 13% of our Medanito oil output, totaling net export revenues of around $135 million. Moreover, the Vaca Muerta North Pipeline is nearing completion, as we started filling the line pack a few days ago, and we expect it to be fully operational during November. However, since the shale oil to be exported through the new Vaca Muerta North Pipeline presents a lighter quality than the heavier oil currently being exported to Chile, the export growth enabled by the new pipeline is expected to be gradual, likely to start increasing as of early next year, as our client shall be testing its refining process in response to its lighter crude mix. Moving to the projects to expand the evacuation capacity to the Atlantic, Oldelval added 20,000 barrels per day of evacuation capacity to its system last month, as planned, reaching 300,000 barrels per day of transportation capacity. In addition, OTE has continued moving forward with the construction of two new storage facilities of 50,000 cubic meters each, as well as the export terminal at Puerto Rosales. Lastly, regarding the Vaca Muerta South project, during the third quarter, we began the design competition process for the new pipeline and export terminal, and obtained the environmental permits for the first tranche of 127 km that will connect Loma Campana to Achén, the town where the entrance of the existing Oldelval's network is located. Switching to our industrial and commercial segments, as commented before, domestic sales of gasoline and diesel reached the highest level ever dispatched in any given quarter, jumping 3% when compared to the previous quarter, driven by an expansion of 5% in gasoline demand and 2% in volumes dispatched of diesel. The latter, mainly due to higher retail and transportation sales, partially compensated by lower power generation demand. On a year-over-year comparison, diesel demand remained essentially flat, while gasoline sales recorded a strong expansion of 6%. In terms of refinery utilization, processing levels at our refineries averaged 276,000 barrels per day, declining by 1% year-over-year and 10% quarter-over-quarter, primarily driven by two program maintenance stoppages at Luján de Cuyo refinery during July and August, and the shutdown of a topping unit at La Plata refinery, which started in September, as the final stage of the revamping project that will increase our processing capacity by around 5% by the end of this year. Despite the lower processing levels, we were able to meet the historical high fuel demand recorded in the quarter through higher imported volumes and a significant drawdown of inventories. On a cumulative basis, though, during the first nine months of the year, we managed to process 296,000 barrels per day, 5% higher than the previous year, while achieving a record high production of gasoline and middle distillates through maximizing our refinery conversion levels. In terms of prices, average local fuel prices measured in dollars decreased by 7% sequentially and stood 18% below a year ago, mainly triggered by the discrete devaluation in mid-August, not fully passed through in the retail segment, in contrast to wholesale diesel prices that were fully adjusted. To compensate for the lower retail adjustment, the federal government implemented some initiatives, such as temporary tax refunds on imported fuels, deferred payment on employee social security contributions, and export duties on oil and refined products that positively impacted on our cash flow, temporarily neutralizing the negative economic effect of the lower price adjustments. Consequently, the contraction in local fuel prices in dollar terms, combined with an upward trend in international gasoline and diesel prices, resulted in a widening of the gap to an average of 27% during the third quarter, significantly higher than the 13% reported in the previous quarter. Nevertheless, after the two last pump increases introduced in late October and early November, we managed to reduce the gap back to levels of around 20%. Lastly, the average price for our basket of refined products, other than gasoline and diesel, dropped by about 6% vis-a-vis the previous quarter and 30% versus the same period of last year, aligned with the downward trend in international prices of petrochemical and certain refined products. Switching to the financial front, cash flow from operations in the third quarter amounted to almost $1.4 billion, 7% higher than the previous quarter. Despite the sequential contraction in Adjusted EBITDA in the third quarter, higher cash flow from operations was the result of a negative non-cash inventory variation recorded in Q3, as well as other positive working capital variations, such as the temporary deferred payments of part of the purchases of crude oil from third parties to the first days of October. However, given the continued deployment of our ambitious CapEx plan, together with our regular interest payments in the quarter, Free Cash Flow came at -$379 million. Consequently, our net debt increased to almost $6.7 billion, and the Net Leverage Ratio, calculated as net debt over the last 12 months Adjusted EBITDA, increased to 1.7x. In terms of financing, during the third quarter, we continued advancing our financial program by securing both local and cross-border trade-related loans obtained from relationship banks, and by tapping the local capital markets at very attractive financing costs. In that sense, in September, we issued a five-year dollar-linked bond for $400 million at 0%, and more recently, in October, we issued a three-year dollar-linked bond for almost $130 million, and recorded a negative funding cost of -10%, benefiting from the currency arbitrage in the local market. Moreover, as already mentioned during the previous call, in August, we disbursed a cross-border A/B loan led by CAF for $375 million as an early refinancing of an existing loan, increasing the outstanding facility size by $150 million and extending its average life by almost three years. All in all, during the first nine months of the year, we were able to raise about $2.3 billion, representing net new funding of over $1.2 billion after deducting the debt amortizations paid during the period. On the liquidity front, our cash and short-term investments remained stable at almost $1.5 billion by the end of September. In terms of cash management, we have continued with an active asset management approach to minimize FX exposure, ending the quarter with a consolidated net FX exposure of only 2% of total liquidity, down from 13% as of the end of the second quarter. With this, we conclude our presentation for today, and for any further questions, please contact the IR team. Have a good day! Thank you, ladies and gentlemen. This does conclude today's conference call. You may now disconnect. Thank you. Thank you so much. See you.