YPF SA (YPF) 2017 Q3 法說會逐字稿

Welcome to Third Quarter 2017 YPF Sociedad Anónima Earnings Conference Call. My name is Sophia, and I will be your operator for today's call. (Operator Instructions)

I will now turn the call over to Diego Celaá. Diego, you may begin.

Great. Thank you, Celia. Good morning, ladies and gentlemen. My name is Diego Celaá, head of Investor Relations at YPF. I would like to thank you for the joining the YPF third quarter 2017 earnings webcast. The presentation will be conducted by our CFO, Mr. Daniel Gonzalez. During the presentation, we will go through the main aspects and events that explain our third quarter results. And finally, we will open up the call for questions.

We will be making forward-looking statements, so we ask you to carefully review the cautionary statement on Slide 2. Our agenda today will include the review of the third quarter results, including an update of our shale and tight development projects, a brief description of our financial situation and a brief summary to conclude.

Also, our financial statement figures are stated in Argentine pesos and in accordance with international financial reporting standards, IFRS. In addition, certain financial figures have been adjusted to reflect additional information to let you better understand our key financial operating results.

Please, Daniel, go ahead.

Well, thank you, Diego. Good morning, everybody, and thank you for joining us this morning for the review of our third quarter 2017 results. This was, again, a solid quarter, generally in line with our expectations in which we continue to see a strong demand for our fuels in the local market and also a quarter in which we saw important definitions from the government with regards to local prices that should provide necessary clarity to make investment decisions going forward.

We have finally reached the full convergence of local crude oil prices with international prices. We are now in the free market for determining fuel prices. Regulated biofuel prices have seen a significant reduction, and we are passing through the effects of those prices on to consumers. Wellhead gas prices for residential customers are steadily trending towards our local market price. And finally, definitions were made with regards to unconventional gas subsidies, which has not come out as we expected, and I will touch on this later on.

Revenues were up 18% when compared with the same period of 2016, boosted by that strong fuel demand, coupled with higher prices in pesos. Gasoline and diesel sales volumes were up over 4% in the period. Adjusted EBITDA reached ARP 17 billion, which represents a 17% increase. And we recorded a net income, which was positive, for $250 million compared with a significant loss a year ago as a consequence of the ARP 30 billion impairment charge that had been registered in our Upstream segment in that quarter.

In line with the first half of 2017, we had a strong operating cash flow again this quarter that reached ARP 13.6 billion. However, this cash generation was lower than that of an unusually strong third quarter of 2016 when we had collected $650 million of pass-through subsidies.

Total hydrocarbon production was down 4.5% vis-à-vis a year ago. Natural gas production decreased 1.7%, basically due to non-operated areas, while crude oil production was down 8%, mainly due to a scheduled reduction of drilling activity, lower-than-expected crude oil production in the South and some residual effects of the severe weather conditions experienced in the second quarter of this year.

Total CapEx was up in the third quarter by only 6% in pesos, reaching ARP 15.9 billion, which is in line with our commitment 18 months ago to moderate activity in the Upstream segment. And we'll explain this in more detail in a few moments.

In this next slide, we show our main financial figures measured in U.S. dollars. And this third quarter, local currency depreciated 15.7% when compared to the same quarter of last year. Revenues, therefore, were up 2.2% in dollars, mainly driven by a strong demand of gasoline and other refined products. Prices in dollars for our most relevant fuels, however, were lower than a year ago, 4.3% down and 0.4% down for diesel and gasoline, respectively. However, export prices were up, in line with the recovery of international prices. And the price for natural gas was also up, in average, 2.7% in dollars.

Cash costs, expressed in U.S. dollars, increased by approximately 3.2%. Lifting cost was essentially flat in dollars in absolute terms, although it was 4.2% up on a BOE basis due to the reduction in total production. Royalties, which is the only cost component fully denominated in dollars, were down close to 11% as domestic crude oil prices and production declined more than the growth in natural gas sales.

So the one item that caused this cash cost to increase is the purchases of crude oil and biofuels, especially crude oil purchases that were up 48% in dollars as our own production was down while we processed in our refineries similar levels of crude than a year ago. As a result, adjusted EBITDA was up by close to 1% in the period.

Let's switch back to Argentine pesos to go over more detailed analysis of the quarter. Operating income has come up by 89% when we compare it with the third quarter of 2016 before the impairment charges of that period. This was mainly driven by the better operating results obtained in our Downstream business segment, which showed an increase of ARP 2.9 billion vis-à-vis a year ago on higher demand and higher fuel prices in pesos.

The Gas & Power segment also showed better results, in this case, due first to better tariffs in our subsidiary, Metrogas; and second, an increase of 130% or ARP 190 million in the power generation business. On the other hand, the Upstream segment results before the impairment charge recorded last year showed a decrease of ARP 691 million or 65%. This was mainly driven by the lower production of the period.

In order to better understand the reasons behind the increase of ARP 1.4 billion in operating income, we've broken it down into more detail, as we usually do. Revenues grew by a ARP 10.2 billion or 18%, resulting from the following factors: first, an increase of ARP 3.1 billion in gasoline sales, with higher prices in pesos of 15.6%, although modestly down in dollars; and an increase in sales volumes of 9%; then there was a ARP 2.3 billion increase in diesel sales, in this case, due to higher prices in pesos of 11% and an increase in volumes of 1.3%; then there was a ARP 2 billion increase in natural gas sales due to prices which were 18% higher in pesos and an increase in sales volumes of 2.7%; there was a ARP 1 billion increase in natural gas sales in the retail segment, which was mainly explained by the consolidation with our subsidiary, Metrogas, and a 54% increase in price and lower volumes of 12% due to milder winter.

Other products sold in the domestic market recorded an increase of ARP 2.3 billion, highlighting all-time record sales of asphalt and also strong performance in lubes, LPG, jet fuel and petrochemical products. All of them also with higher prices in pesos. Then we had higher exports of ARP 1.5 billion on higher volumes and higher prices.

Now on the other hand, fuel oil sales decreased by ARP 2 billion on lower volumes of approximately 68% and 7% lower prices in pesos as the power generation sector had more gas available to replace fuel oil.

Cost of sales, other than depreciation, increased ARP 3 billion. The only cost component which is fully dollarized are the royalties. The factors are explained, the increasing costs were the following: first, the lifting cost, which was up ARP 1.4 billion or 15%; then transportation expenses, which increased ARP 600 million or 33%; then the refining cost, which was up by ARP 450 million or 19% higher; and finally, the royalties, which are paid to the provinces on wellhead prices, which are set in dollars, and presented a slight increase of only ARP 145 million or 3%, driven by the 15% devaluation between the periods and partially offset by lower crude oil prices and the lower production on the period.

Depreciation was up by only 8.4% or ARP 1 billion due to an increase in the value of our assets, which are carried in dollars, which was partially offset by the net reduction of the carrying value of these assets as a result of the impairment charge that had been recorded last year.

Purchases of crude oil and others products for sale increased by ARP 4.1 billion. This increase was mainly concentrated in crude oil purchases from third parties, which increased by ARP 2.5 billion on 85% higher volumes, driven by the lower production on the period. Also, purchases of biofuels increased by ARP 1.1 billion as a result of higher prices in pesos and slightly higher volumes of ethanol and biodiesel. In the case of ethanol, derived from higher gasoline sales. Finally, purchases of grains as a result of the bartering in our agrobusiness had an increase of ARP 450 million.

Now on the other hand, imports were down by ARP 1 billion due to the combination of lower imported volumes of diesel and jet fuel of 73% and 21%, respectively, which were partially offset by higher international prices, 35% in the case of diesel and 24% in the case of jet fuel.

SG&A was up by 17%, in line with inflation and with the revenue increase and as a consequence of higher transportation expenses and salary increases, while exploration expenses remained essentially flat.

Other operating results in the third quarter showed a gain of ARP 316 million compared with a loss of ARP 26 million last year. This quarter includes a positive reassessment of certain legal contingencies, while the third quarter of 2016 included a ARP 204 million gain. It was a onetime income related to the expansion project in the Magallanes area that was funded by a 50% partner in that area, ENAP.

Entering now to our Upstream business segment. Operating income decreased by 66% against the third quarter of '16. And this was before the impairment charge to reach approximately ARP 360 million. Revenues increased by 6.5%, reaching ARP 30 billion, driven by the following combination of factors: on the one hand, higher natural gas revenues of ARP 2 billion, which was 21% higher on higher prices in pesos and that 2.7% increase in sales volumes; but on the other hand, lower crude oil sales by ARP 531 million or 2.8% due to 2.3% lower volumes transferred to our Downstream business segment at 1% lower prices in pesos.

In line with the terms of the agreement between the refiners and producers signed earlier this year, the average realization price in dollar terms for crude oil decreased to $51.40 per barrel with average prices of $55 and $48 per barrel for light and heavy crude oil, respectively. As it is widely known, this agreement was suspended towards the end of the quarter, and prices are fully determined based on import and export parities. For natural gas, the average price was $4.92 per million BTU, which was 2.7% higher than last year.

Now on the cost side, these were up by ARP 3 billion, an 11% increase compared with the third quarter of '16, mainly due to the increase in items related to the lifting cost. The lifting cost on a per barrel equivalent basis increased by 4.2% compared with the third quarter of '16 to $12.60 per BOE. And this was mainly due to the production decline. Actually, a flat production would have resulted in a reduction in the lifting cost per barrel. Total cash cost per BOE reached $20.50, and that is including royalties and other taxes of $5.80 per BOE. Exploration expenses increased 7% or ARP 22 million, as we also described in previous slide.

Moving now to production. Crude oil production in the third quarter of '17 decreased 8% to 227,000 barrels of oil per day. As explained in previous quarters, part of the decline was already expected and reflects the reduction in activity started last year as a natural decline of some mature fields. Additionally, production was slightly below expectations in the provinces of Chubut and Santa Cruz. And the balance was mostly -- the balance decline was mostly a consequence of the heavy rains and snowstorms that had affected the south of the country in the second quarter of the year and still had a residual effect this quarter. Crude oil production in October was above that of the quarter, and we therefore expect a slightly stronger fourth quarter in terms of crude oil production.

Natural gas production on the other hand showed a decrease of 1.7%. We produced 44.1 million cubic meters of natural gas per day, while natural gas liquids production decreased by 3%, producing 48,600 barrels of liquids per day. These reductions are mainly explained in the non-operated areas, for example, the scheduled stoppage in the Magallanes facilities, which took longer than expected. As a result of crude, natural gas and NGL production figures, total hydrocarbon production dropped 4.5% vis-à-vis the same quarter of '16 to 553,200 barrels of oil equivalent per day.

Now let me provide an update on our shale gas and shale oil activity. Net shale production for the quarter reached 37,600 BOEs per day. And gross operated production was 71,900 BOEs per day.

In terms of our activity as operator, during the third quarter of the year, we connected a total of 17 new wells, taking the total to 596 shale wells in production. Bear in mind that during July, we closed the farm-out process of Bajada de Añelo block to Shell, including the assignment of the operation. So from now on, the number of wells and the production coming from this block is no longer included in these figures as operator.

In relation to the well cost, I would like to highlight that as we have started to test longer laterals wells, the cost per well in itself does not help understand the cost improvement trend. So as you can see on the chart at the right side of the slide, we decided to measure well cost in terms of dollars per lateral foot. Having said that, in this quarter, our well cost in Loma Campana was reduced to $1,600 per lateral foot, proving that our efforts extending the well length and improving operational performance are paying off.

Finally, and as a result of this shift to longer lateral bells, in the last chart on the page, we see that the increase in the average length is now 2,200 meters and the average is 27 frac stages per well. As we mentioned a few weeks ago in our Investor Day, the development of the shale is one of the pillars for growth in production in our 5-year strategic plan. So we will gradually start providing more detailed information regarding each of the areas under development.

In Loma Campana, our main development in Vaca Muerta in which we have just agreed with our partner to add a third dedicated rig and have announced a joint investment of $500 million for 2018. We started to receive the monthly average oil production data from the first 2,500-meter long lateral well, showing a very promising production of 1,000 barrels per day in the first month of production, which is kind of twice the production that we were seeing from the shorter lateral wells. In addition, we have started to drill the first 3,200-meter long lateral well.

In El Orejano, the shale gas development we have jointly with Dow and where we expect to have 1 dedicated rig throughout 2018, we were able to successfully complete one part with 6 wells in line. And this is in line also with our preliminary estimated development cost in the $1 per million BTU area.

Now moving on to our pilots. In La Amarga Chica with Petronas, we are testing up to 5 different navigation levels in this pilot that still has another year to be finalized. And then in Rincón del Mangrullo, we were able to complete the first 3 wells with objective to Vaca Muerta with an average of 20 frac stages per well. Remember here that although we have 50% of the tight gas rights in Rincón del Mangrullo, we have reserved 100% of the rights to Vaca Muerta in this concession area.

Regarding the new pilots we started this year, we still have competed -- we will have completed by year-end 11 wells. And we will have another 4 wells, which will have been drilled and awaiting completion. And these are in 5 different areas, including those wells in Rincón del Mangrullo, Vaca Muerta that I just mentioned.

With regards to our tight gas projects, we are showing the chart on net tight gas production, which continued to show encouraging results, reaching 14.1 million cubic meters a day. And this way, tight gas production represents now 32% of our total natural gas production.

In terms of the activity of tight, we have put in production 5 wells targeting the Lajas formation in Aguada Toledo, where we own 100%; 8 wells targeting the Mulichinco formation in Rincón del Mangrullo, where we own 50%; and 11 wells in EFO, where we also own 100%.

The Downstream segment reported an operating income of ARP 3.2 billion, almost 10x higher than the ARP 330 million operating income reported a year ago. Revenues were up by ARP 6.9 billion or 16%. As explained before, gasoline sales were up by ARP 3.1 billion on 15.6% higher prices and 9% increase in volume.

Sales volume of Infinia, which is our premium gasoline, increased by more than 25% this quarter. Diesel sales were up by ARP 2.3 billion on 11% higher prices and 1.3% higher volumes. And again, it is worth highlighting the increase of almost 40% in sales volumes of our premium product, Infinia diesel. Fuel oil sales dropped by ARP 2 billion on lower volumes and lower prices, as I explained before. And in turn, the domestic sales of the rest of our refined products increased by ARP 2 billion with record high sales of asphalt and also strong performance in petrochemicals and other refined products. Finally, sales in the export market increased by 35%, as explained before.

Costs increased by only 8.4% in the Downstream, well below inflation. We highlight here, first, higher crude oil purchases of ARP 1.9 billion on 85% higher volumes purchased through third parties, offset partially by 2.3% lower volumes transferred from the Upstream business segment to the Downstream business segment, and of course, both at lower prices in pesos; then higher purchases of biofuels of ARP 1.1 billion with higher prices for both biodiesel and ethanol, 22% and 15%, respectively; higher purchase of grains; lower imports of ARP 1 billion due to the reaction in volumes of imported diesel and jet fuel; higher depreciation of ARP 500 million; and finally, ARP 450 million increase in items related to the refining cost.

During this quarter, the volume of crude oil processed in our refineries was 294,000 barrels per day, which was 0.6% higher than the third quarter of last year. Regarding domestic market, total volumes decreased by 3.2%, but this was driven by the 68% and 31% reduction of fuel oil and LPG demand, respectively. These 2, by the way, are 2 of our products with lowest margins. However, the volumes sold of our main products showed an increase of 9% and 1.3% for gasoline and diesel, respectively.

As we can observe in the charts plotted in this next slide, demand was very strong for gasoline in the left, with a consistent 9% increase, as mentioned in previous slides. Diesel demand also showed a good performance, increasing 1.3% in the quarter despite the significant reduction in the demand from power plants explained by more availability of natural gas due to the mild winter. In October, sales of both products were actually stronger than in previous months. So demand continues to be solid, allowing us to continue to increase prices and sustain our Downstream margins.

Market share for both products continue to be strong with 55% in gasoline and almost 57% in diesel. And market share for the premium products is actually higher at 61% and 58%, respectively.

In our Gas & Power segment, we continue making progress in the 4 new projects that will allow us to reach a total generation capacity close to 2 gigawatts. Our thermal project, Loma Campana I, recently commenced operations, adding 107 megawatts to our current capacity, which is now at 1.4 gigas. And the other thermal project, which is Loma Campana II, is expected to commence operations later this month. Regarding the thermal project in Tucumán, operation is expected to start during the first quarter of 2018, and that will add 270 megawatts.

Similarly, the wind farm project is also expected to start up during the first half of 2018, and that one will add another 100 megawatts. In terms of additional projects, we have recently been awarded PPAs for 80 megawatts of cogeneration in our La Plata complex and 200 megawatts for the add-on project in the Tucumán open cycle under construction.

Additionally, we've also participated in the last auction for renewable energy, presenting 200 megawatts in 3 different projects: another wind farm and one solar and one biomass projects. As discussed in our Investor Day, our plan is to grow this business without allocating any additional equity, and we continue to work towards the incorporation of at least one partner to capitalize the power vehicle to fund all these projects.

During the third quarter of 2017, total CapEx for the company amounted to ARP 15.9 billion, which was 6% above the level of 2016 but showing a reduction of 8% if we measure it in dollars. Upstream CapEx amounted to ARP 12.5 billion, which is an increase of 7%. And our activity there was mainly focused in drilling and work-over, which represented 71% of the Upstream CapEx, followed by the buildup of our facilities with a 21% share. And finally, exploration and other activities represent 8% of the Upstream CapEx.

During the quarter, we drilled and put in production a total of 124 new wells, including those 17 new wells in shale that were mentioned before and also including 24 new wells in tight gas formations. The most meaningful investment have taken place in the Neuquina basin, most specifically in unconventionals, in all the shale and tight gas blocks where we have activity, highlighting the commencement of 2 pilot projects targeting the Vaca Muerta formation, which were in the blocks of Rincón del Mangrullo, as mentioned before, and Aguada de la Arena, which was acquired last year.

In conventional areas, Chachahuen in Mendoza was the most relevant in that basin. In the Golfo San Jorge basin, and as a result of the recent agreement to reduce royalties with the province of Santa Cruz and also as a result of new drilling rates, we resumed activity of 2 drilling rigs in 2 blocks. And of course, we continued our drilling activity in both the Cuyana and Austral basins.

With regards to exploration in this quarter, we completed 3 exploratory wells, 2 of them looking for oil and one with natural gas objective. In Downstream, CapEx was ARP 2.4 billion, which is 2% lower compared with the same period of last year. To highlight, during the period, we finalized the revamping of the topping unit in Lujan de Cuyo, and we began the pumping tests in the Señal Cerro Bayo-Puesto Hernández crude oil pipeline. This pipeline reversal is key to be able to provide our Lujan de Cuyo refinery with the necessary crude to be working at full capacity. By the way, Lujan de Cuyo is our refinery that has a conversion ratio of 100%.

In our Gas & Power segment, CapEx reached ARP 670 million, and this is a result of the construction of the power plants, which we discussed earlier.

Now let me switch to the financial situation. Operating cash flow remained strong in the quarter, reaching ARP 13.6 billion. However -- and despite the ARP 2.4 billion increase in adjusted EBITDA, this cash generation of the quarter represents a 19% year-over-year decrease. But this was mainly due to the extraordinary $650 million collection of the Plan Gas unpaid subsidies that we had received in the third quarter of last year.

This quarter, CapEx slightly exceeded the cash generation of the period. Nevertheless, cumulative free cash flow before interest for the 9 months of the year remains well above the capital expenditure level and in line with our objective of having positive free cash flow before interest for the year. This cash generation, coupled with a sound refinancing activity, results in a strong cash position of ARP 30 billion at the end of the 3rd quarter 2017, including the dollar-denominated sovereign bonds which we're still holding in treasury.

As previously explained, the cash position is enough to cover our debt maturities over the next 12 months. And our next important debt maturity is only December 2018. Our leverage ratio stood at 2x net debt to EBITDA, in line with the target for the year. And the average interest rate in pesos was 22%, while the average cost of our debt in dollars was 7.7%.

In summary, this was a strong quarter, in line with our expectations and allowing us to reaffirm guidance for the full year of 2017. The main driver of the good results has to do with the strength of the local demand, which we expect we will continue to experience in the remainder of the year and throughout 2018.

The liberalization of prices at the pump has allowed us to increase prices by approximately 10% in average after the close of the quarter. And we expect to continue to increase prices if import priority rises as a consequence of sustained global crude oil price increases. Going forward, we will readjust prices based on market dynamics, including competition and import parity and based also on FX.

The upstream sector did not have a solid quarter as production was somewhat below our expectations. The exception, of course, was unconventional that continued to perform well. Our Upstream cost structure is still negatively affected by costs associated with the reduction of activity in the last 18 months. We have made some management changes and put in place a plan to address summer production shortages, especially in the south of the country, that makes us confident that we will revert the crude oil production decline of this quarter.

Natural gas production performed well, especially the one operated by YPF, and average prices are attractive. However, the recent regulation regarding natural gas subsidies for the next 4 years is disappointing to us and will lead us to reevaluate our CapEx dedicated to natural gas.

Basically, the new gas price subsidies will apply only to new unconventional production in each concession area, which is above the average production of the last year in such area. This is good for all of our new pilots but could be negative for those areas that are already in production. This effect will be partially offset by the higher market price that we expect to receive from the gas distribution companies, in line with the pricing path outlined by the government.

However, we might decide to cut investments on those unconventional areas under development where we don't believe we can get that price of $7.50 to $6 per million BTU. Initially, we estimate that this regulation will result in a reduction in cash flows coming from natural gas during the life of the 5-year plan. But we expect to make up for this loss by redeploying capital towards crude oil projects that are now more compelling as current and expected crude oil prices are well above those used for the plant.

Now in addition to that, the reduction in income tax that will be presented to Congress in the next few weeks and that was not factored in, in our plan should also have a positive effect in the cash flows to be generated in the 5-year period.

Our improvements in the shale are extremely encouraging. We have said that we expect that more than 50% of our total production in 5 years will come from unconventional sources. Therefore, it is key to prove that we can improve the productivity of the wells, which is exactly what we are doing with the lengthening of the lateral of the wells.

As soon as we have some meaningful history for these wells, we will start sharing that information with you and sharing also the well tight curves.

As we have shown during the presentation, the cost per lateral foot has been coming down. And if EURs are substantially higher than those of shorter laterals, as we expect, the economics of the wells will be significantly better.

Finally, the recent developments in the power generation segment, including the successful award of PPAs for 270 megas and the projects proposed for the renewable energy auction, are proving that this is a credible additional source of growth that was not there for us a couple of years ago.

So with this, I would like to pause and stand by for questions. Thank you.

(Operator Instructions) And our first question comes from Frank McGann from Bank of America.

Just a couple of questions, if I could. One, just in terms of production trends, what your expectations are over the next 12, 18 months in terms of whether we'll continue to see declines because of the greater weight of mature fields versus production coming from new developments. And then the second question, just following up on the gas comments that you had. I'm just wondering how serious is this in terms of real profitability from those fields because obviously, the profitability is quite a bit lower, if you're pricing at $1, $1.50 on average lower than -- at least for a year or 2 lower than what you would have otherwise gotten. But the -- my understanding has always been the profitability was still very, very high in those areas potentially at even lower prices. So I'm just wondering if you could just follow up a little bit more about the kind of return effects that the new Plan Gas will have. And what's driving your potential reduction in investments?

Thank you, Frank. On production, as I mentioned, on the fourth quarter, we do expect a higher production figure for crude oil. For natural gas, we are doing fine from an operating perspective. There were a few days in which demand for natural gas was low, so we needed to reduce productions. I like first to understand how this evolves in the next few days before giving you any estimates for the quarter. But in terms -- again, natural gas in terms of -- from an operating perspective, the trend is good. We are doing very well. And of course, crude oil, starting from this low base that we had in the second quarter and then a little bit higher in the third quarter, I think fourth quarter is going to be higher than the 2 previous quarters. So that is good. Now going forward, as you know, we said that we expect to grow total hydrocarbon production approximately 25% in 5 years. So I expressed that as a 5% per year although we don't think that we're going to be growing production 5% in 2018, taking into account that all of the production increases will come from the shale and still the shale is a small part of our total production. Growing, growing substantially. It was actually 10% higher this quarter but still small. So growth in production will accelerate during the course of the plan. With the new gas, and that takes the new gas rules, and that takes me to the second part of your question, I think that we will probably see more growth in crude oil than in natural gas vis-à-vis what we were ambitioning in the plan, which actually we did not disclose exactly what was the breakdown between the 2. But I do think that we're going to be reallocating capital towards some crude oil projects from natural gas. Now are there any natural gas new projects that with the new rules do not work? No. All the work -- all the projects were fine, okay, because all the new projects -- were absolutely fine because all the new projects will have the full impact of the subsidy, okay. Therefore, we have absolute clarity of good prices in the first 4 years that is the period of the subsidy. The impact is not so much in the new projects but in the existing unconventional development projects. Those projects like the tight gas in Aguada Toledo, where we are producing 5 million cubic meters per day, give or take, and that will not have the benefit of the subsidy going forward because we will not be able to show additional production in that project specifically. Now if you want the good news there, is that those tight gas projects that do not -- or that might not have the benefit of the subsidy going forward are all in the Neuquina basin where we have the highest price -- market price, which is very close to $4 per million BTU. So chances of having projects -- new projects that do not work, very low. I think all the projects will work nicely. The question is there are some developments that we had plans to continue to invest in next couple of years, those are the ones that we need to readdress and decide up to what extent that it is worth putting our money there as opposed to just opening up new pilots that we know will have the full benefit of the subsidy.

Our next question comes from Luiz Carvalho of UBS.

Daniel, everyone, just a couple of questions. The first one is related to the pricing policy. We have been, I mean, hearing some news that you say now the pricing policy is basically free. And you've just mentioned during the call that you expect that, let's say, you're going to be able to actually pass through the volatility. So I just would like to understand a bit better, how would be the communication? And what would be the, let's say, the company, how can I say, process in order to communicate that to the market? And also, if you can provide some, how can I say -- I mean, at least a color in terms of what could be the margins impact looking forward. And the second one, I would like to actually come back to this Gas Plan, I mean, disappointment, how can I say, regulations changed that you just mentioned during the last question. You mentioned that probably you're going to have to shut down some projects. And I would like to understand, what will be the impact in terms of the negotiation with the unions and how this could be, let's say, addressed in terms of -- can you reallocate the workers from one project to the other? Or you're going to have to actually dismiss some of them? And last question, if you have any updates on the asset sales process which, for us, it's one of the main, how can I say, catalyst as well for the [attributed case]?

Luiz, on the pricing policy, we expect at least once a month to review the factors that affect the pricing and decide changes. We have not decided to have a formal communication process of price increases. I don't know up to what extent that is of value generally. But we can certainly think about that, especially with you guys. Now the reality is that each time we touch our prices, it is widely known and that's in the front page of the papers anyway, okay. So it's impossible to assume that any price increases or decreases will come out unnoted, okay. So what I'm saying with this is it will be widely known. We do expect to -- the increase in crude oil prices to have a positive impact in our margins, okay. You know that we've traditionally had strong Downstream margins, which we expect at least to maintain. And we always say the same. Remember that selling fuels locally is the way that we monetize our crude oil production. So it will always be very important for us to continue to keep margins. Now at the same time, in a free market, if margins are ridiculously high, market share will be lost because you'll compete with other forces internally and eventually with importers. So I think that we have a strong market share. We have a strong brand. Everything that we need in order to sustain the margins as we have them or higher. I don't expect any negative impact on margins at all. On the second part of your questions regarding the Gas Plan and if we were not to invest in several projects, what would we will do first is to reallocate any CapEx going to gas projects that do not make sense to other gas projects that make sense because as I said in the previous question, all the new pilots, all the new developments that do not have any production and that therefore have the full benefit of a subsidy work very, very nicely with these prices, okay? So I believe that we have alternatives -- investment alternatives within natural gas to redeploy capital. Of course, that will not have an immediate effect in production. Now the second thing that we would do eventually is to reallocate towards crude oil, okay. And no, definitely, this should not have any impact at all in jobs and should not have any impact at all in our relationship or negotiations with the unions. As we've been saying, we believe that we have already touched bottom in terms of total hydrocarbon production and investment. We are not assuming a huge increase in the rig count, but definitely, we are not going to be reducing the rig count. So if anything, I think over the medium term, you will see an improvement in terms of the number of jobs. So this should not have a negative impact at all. And on asset sales, there isn't much to say. We've been asked many times regarding Metrogas. We have said that we have hired a financial adviser, that we started to put together information packages and everything, but that we're also waiting to see the impact of the increase in the natural gas tariffs reach the financials of Metrogas and eventually, if we decided to sell in the future, do that based on better financials. So this will eventually be an event of some point mid-next year. Nothing imminent to report. And that's the only one. The other which is not an asset sale but that we also went public with some information regarding the capitalization of our power subsidiary in which we will dilute our equity stake by incorporating one or more partners to capitalize the company and fund that vehicle with necessary equity capital for those projects that we made during the call. Hopefully, we will see news about that much earlier than those that I just mentioned regarding Metrogas.

Okay. Just one follow-up in this question related to the earlier comment. Is there any news on the JVs? Because I mean, from the asset sale perspective, you expect something pointed to mid-next year, but what about the JVs? Anything on the short term in the pipeline?

Nothing imminent that you will hear in the next few weeks. We continue to work with different parties that have expressed interest in different properties. As I have said in the call a few months ago, we are in a much more comfortable situation in terms of capital. And therefore, we're going to be extremely picky in terms of doing more JVs. We haven't changed the strategy though, which is to continue to develop the unconventionals with partners. We like that, but for the plan that we have for next year, in which a good part of the pilots are actually going to be 100% funded by our partners because all those JVs that we announced this year and that will have substantial investments in new activity next year are going to be part of the carried -- of the carry agreement in which our JV partners will put 100% of the CapEx, right? So what that is doing is freeing capital for us to go forward with the pilots, those that I have mentioned that we're doing this year and some additional pilots that we're going to be doing next year. So bottom line is yes, you should expect us to continue to do JVs over the medium term. There's nothing imminent on the works right now.

Our following question comes from Ricardo Cavanagh from Itaú.

Well, at your Investor Day, you provide or you give significant importance to the outlook for cost reduction. So thinking about progress in terms of negotiations with the unions, how are you seeing 2018 in that sense on the possibility of making something similar to what you attained last year or early this year in Neuquen province, let's say, in Santa Cruz or elsewhere in Patagonia?

Ricardo, well actually, even before 2018, because we still have a couple of months to go, we are making some changes in the province of Santa Cruz where our cost structure is the highest. We did a big part of the adjustment in the last 12 to 18 months in terms of reducing the activity to those developments that actually made sense from an economic perspective given that high cost structure and the reduction in prices that we have been seeing in Argentina as we converged with international prices. But the second part of the adjustment has to do with O&M, with the lifting and the OpEx in Santa Cruz generally. And we do expect to move forward with some of the changes in the next few weeks, and those should have a positive impact in 2018 and onwards. So Santa Cruz and the south of Argentina generally is, as I said, where cost structure is highest. And when we talk about reducing OpEx generally in average, a good part of that reduction is coming from these areas, whereas the unconventionals, for instance, have already a pretty low lifting cost, which still can be optimized but we don't need that big of savings over there. And to your point, we have made a lot of progress in changing the agreements with the unions applying to unconventionals this year. So cost reduction continues to be a big part of our focus going forward. We are not going to be waiting to do some of the changes that we need to do. Now we're not having any discussions with the unions regarding the 2018 labor agreements because we're just almost 6 months away from that, right? So you will hear eventually news towards the end of the first quarter.

Our following question comes from Pavel Molchanov from Raymond James.

You mentioned that you're not anticipating 5% production guidance for 2018. Have you formulated a specific plan at this stage for 2018 in terms of capital budget and production growth expectations? And when might we be able to hear the details of that?

Pavel, thank you. We do that as part of our budgeting process for 2018. We are obviously very advanced on that process, but it will only get approved in our next board meeting in the first half of December. What I can anticipate at this point is that CapEx will be around $4 billion generally, okay. So pretty much in line with the guidance that we have provided this year, although this year was going to be below guidance in terms of CapEx. I still do not feel comfortable in providing guidance in terms of production. It's definitely going to be substantially lower than that 5% per year average, which is not surprising to us because when we put together the plan for 5 years, we knew that we were coming from a low base and a big part of our production is that legacy mature production that experiences high decline rates and that we will gradually replace that with unconventional production. But as I said in one of the questions earlier, that's going to take some time, right, because still the unconventional is a small part of the total production. So bottom line is we will see some growth but are far away from that 5% average, but that doesn't change our 25% production increase for the full period as a whole. That guidance for 5 years is not changing at all.

And let me also ask about the Vaca Muerta partnership that you have signed earlier this year, for example, Schlumberger and Total and so forth. Have any of those partners expressed concerns or criticisms of the revised gas price policy that you've discussed?

Well first, most of the partnerships have to do with the oil window of Vaca Muerta. And therefore, the effect on the economics of the total development, the effect of this gas pricing program is not that significant. Second, because all of these JVs are on new development areas, they will all have 100% of the benefits of the subsidy. So there isn't any harm. And third of all, this regulation just came out a few days ago. So we haven't had the chance of revisit any of the plans with our partners. But I don't anticipate any pushback.

Our following question comes from [Andreas Luzona] from Citibank.

Just follow up regarding the gas pricing policy. Do you think this is an issue that is closed for the government or there is room to further negotiations? And the second one, if you can help me to understand how much of EBTIDA came from Loma Campana power plant facility during the third quarter.

Hi [Andreas]. The gas pricing policy is a resolution that came out of the ministry a few days ago, and that is definitive. As in everything, there are always gray areas and things that we need to reconfirm and that we are already in consultation with the ministry to understand the details. But what I have described during the call applies. And no, we are not expecting any changes at all there. I didn't understand your second question.

Sure. There was a power plant, if I'm not wrong, at Loma Campana that kicks off during the third quarter. How much was the EBITDA contribution for that power facility?

No, it was completed very, very recently. So it had no impact at all on the EBITDA of the quarter.

Our next question comes from Regis Cardoso from Credit Suisse.

Daniel, 2 topics that I wanted to touch. The first one is rather simple. It's regarding production recovery from the automation, the residual effects of the floods and storms from the previous quarter. Do you expect production for the fourth quarter to fully recover from those weather impacts? And then the second topic is regarding prices. First, on prices, I wanted to get a sense of how much pricing power do you believe to have and how much room for imports you believe there is for them to take market share from you. So let's put it this way, if let's say Brent continues somewhere around, let's say, $60 or slightly above it, how much more room do you think would there be for price increases? And let's say you pushed too hard these price increases. Do you have a sense of how much market share do you believe you could lose? And then still on prices, you mentioned in the strategic -- in the event you carried out in New York about the strategic plan that you did not intend to have a pricing policy that was as volatile as daily, right? But maybe that is one way you could maybe not make your price adjustment so visible to the press every time because I mean, if you adjust it every day, then it is not so much of a big event, right? Have you considered this? Are you still looking for monthly price adjustments? How do you think it will impact on your pricing power in the domestic market?

Thank you, Regis. The first question, yes, we have fully recovered from those events of the second quarter. As I said during the call, on the third quarter, just the effects were -- I think I said residual effects were not that significant. But you should not expect any effects at all on the fourth quarter, not coming from those events on the second quarter. And on prices, we believe that they're at or around $60 per barrel. We have the prices that we need today, okay, give or take, okay. We will need to review because today we are at $63 and change per barrel, okay. So we will review that, as I said, at least on a monthly basis. We are not expecting to lose any market share. We believe that with these prices and the protection that we have for having the logistics that we have countrywide in Argentina and the quality of our products, pricing, locations of our service network -- service station network and so on, we are not expecting any market share reduction. Of course, also as I said, if we were to increase prices well beyond what is reasonable, then you start creating an incentive for other people to come in. But we will always monitor that in a way that we have the price that we need to have based on market -- on market dynamics, okay. So if we are in a free market, I think that our prices will just reflect what is the fair price based on import parity and based on our competitive position. I will take note of your suggestion regarding daily price adjustments. We probably don't think that, that is a good idea. It would create a lot of confusion with clients and wholesalers and service stations generally. But I get the point. Obviously, I think that as time goes by and people get used to pricing changes more often than in the past, the whole importance of our price change will gradually go away and we'll have a lower profile than what we have today. But I don't think that we will move to daily pricing changes.

Our final question comes from Santiago from AR Partners.

My first question is related to the current Plan Gas. Can you give us an update regarding the timing of collections for the government considering that I believe until recently, there haven't been any payments and they have been paying with considerable delay. Then my second question is related to the new Plan Gas. What do you think will be the impact of the plan since January 2018 in your average gas price as you received it today? Besides -- and regarding pricing, 100% of the new conventional projects will be paid $7.50 per million BTU. But as I understood from what I heard earlier in the call, you need to increase production in like 16 projects to get the subsidy. However, if you were to increase production in an existing project, will you get the $7.50 price for the whole output or only for the incremental production? And third question, if I may, now that the price of crude have reached full convergence with international benchmark, what's the pricing outlook you expect for 2018?

Thank you, Santiago. Actually, you raised a couple of questions of -- I think that I should have mentioned during the call. On the Plan Gas collections, we collected after the close of the quarter, the months of fourth quarter of 2016, okay. So that was on the good news side. But that means, of course, that everything that we have accrued this year, we have not collected, okay. We are in constant dialogue with the government regarding that. We are, in fact, in the same situation that the rest of the industry is in Argentina. And we -- the government is fully aware of this, and we expect to have some collections before the end of the year. And gradually, as the subsidiary goes down in terms of size for the government, I think that the arrears will also come down as it's going to have less of a fiscal impact for the government. So we expect in 2018 to see an improvement in terms of the number of months that it takes the government to pay its subsidies. On the new Plan Gas and its impact on the average realization price for natural gas, it's a little bit too early to provide numbers. But we should say that we expect a slight reduction in the average wellhead price of gas for us in 2018, and again, an increase in 2019 and onwards. To understand -- and this goes to the next part of your question, which is some of the developments that are in production today, and in many cases, provide for a substantial amount of natural gas production, we'll probably not get the effect of the subsidy, but we'll get the market price of the basin that is actually increasing every quarter. In terms of which projects get and which do not get the subsidy, you're right. The subsidy is only on the incremental production, okay. But remember that all of the new projects almost do not have any production at all today, okay. So you should assume that substantially all of the production that those projects throw out will have the benefit of the subsidy, okay. So the negative effect will not be on those new projects which are exactly in the same situation that they were before this resolution came out. The negative effect is on the projects already under development. And in terms of crude oil prices, we never provide an outlook of where crude oil prices will go. We haven't changed our long-term view that we should plan for crude oil prices at or around where they are today or maybe a little bit lower than where they stand today. We would obviously try to profit as much as we can from these high prices that we are experiencing. But we never provide an outlook there.

We have no further questions at this time.

Okay. Well, thank you very much, everybody, for participating. And as always, if you have any follow-up questions, you feel free to call me, Diego or Pablo at any time. Have a good day.

Thank you ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.