YPF Sociedad Anonima (NYSE:YPF) Q2 2018 Earnings Conference Call August 8, 2018 8:30 AM ET
Diego Celaá - Head of Investor Relations
Daniel Gonzalez - Chief Executive Officer
Sergio Giorgi - VP, Strategy and Business Development
Bruno Montanari - Morgan Stanley
Frank McGann - Bank of America
Regis Cardoso - Credit Suisse
Luiz Carvalho - UBS
Pavel Molchanov - Raymond James
Welcome to the Q2 2018 YPF Sociedad Anonima Earnings Conference Call. My name is Richard, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later we will conduct a question and answer session. [Operator Instructions]
I will now turn the call over to Mr. Diego Celaá. You may begin.
Great. Thank you, Richard. Good morning, ladies and gentlemen. My name is Diego Celaá, Head of Investor Relations at YPF. I would like to thank you for joining the YPF second quarter of 2018 earnings webcast.
The presentation will be conducted by our CEO, Mr. Daniel Gonzalez; our VP of Strategy and Business Development, Mr. Sergio Giorgi and myself. During the presentation, we will go through the main aspects and events that explain our second 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. Also, our financial statement figures are stated in Argentine pesos and in accordance with International Financial Reporting Standards, IFRS.
In addition, certain figures have been adjusted to reflect additional information to let you better understand our key financial and operating results.
Please Daniel, go ahead.
Well, good morning. And before Sergio Giorgi go through the details of the quarter, I would like to provide some context. This was a difficult quarter for Argentina where the currency devalued by more than 40%, interest rates skyrocketed and the economy started to soften. Under these conditions I am acknowledging that we were kind of slow in passing through the prices the effects of devaluation.
Results were again strong and our growth plans for the future remain essentially unchanged. Revenues were up by 55% in pesos and EBITDA by 53%, both also up in dollar terms despite the devaluation. Total hydrocarbon production was 1% below last year, very strong in unconventional but mixed in conventional, especially natural gas.
And again, we were free cash flow positive as operating cash flow more than doubled to Ps 27.8 billion, while CapEx amounted to Ps 19.3 billion. So, with that please, Diego, go ahead.
Okay, thanks, Daniel. Moving now into our main financial figures measured in U.S. dollars. In this second quarter the local currency depreciated by almost 50% when compared with the same quarter of 2017.
However, revenues were up by 3.3% driven by a strong of our main products gasoline and diesel. Increase that was in NASDAQ said the lower prices in dollars for both products. Exports increased due to a combination of higher international prices and higher exported volumes.
On the other hand price of natural gas was down in average 1.9%, as a former playing gas expired in December 2017 and less volumes are now eligible for the non-intensive plan for our conventional new gasolines. Cash costs expressed in U.S. dollars remained essentially flat lifting our refining cost in dollars decreased by 40% and 22.8% in absolute terms respectively.
Royalties, which is the only cost component fully denominated in dollars were up close to26%, in line with increasing domestic crude oil prices.
Crude oil purchases were down 9.7% in dollars, as our crude oil production increased 3.6% while we processed in our refineries lower levels of crude oil than a year ago. As a result, adjusted EBITDA was up by 2.3% in dollars.
Finally, total CapEx for the company amounted $124 million, almost 1% lower compared to Q2 2017. Upstream CapEx in the quarter amounted to $686 million, 8.6% higher than Q2 2017, our activity was mainly focused in drilling and workover which represented 70% of the Upstream CapEx followed by a buildup of facilities with a 19% share as a total and exploration and other activities 11% During the quarter, we drilled and put into production a total of 96 new wells including 14 new shale wells and another 12 wells in tight gas formation.
In Downstream CapEx was $414 million, activity was focused in refining which represented 38% of the Downstream CapEx followed by logistics with a 26% share of the total, then marketing representing 20% and finally chemicals with 16%.
Now let’s switch back to Argentine Pesos to go over the more detailed analysis of the quarter. I think I am seeing this slide this time, we decided to focus the analysis in adjusted EBITDA of our business segments instead of operating income to provide a better understanding on how each business segment contributes with the cash generation of the company putting aside the FX impact on depreciation and amortization which are in fact a non-cash effect.
This way, adjusted EBITDA has come by 53.2% compared with the second quarter of 2017. This was mainly driven by the better operating results obtaining the lower Upstream business segment which show an increase of almost Ps 13 million vis-à-vis a year ago. Revenues of this segment increased by 74% mainly as a result of higher crude oil and natural gas prices in pesos, while on the other hand, cash cost of this segment increased by 41% below revenue increase as lifting cost or other OpEx were partially diluted by the devaluation.
The Downstream segment results show a decrease of almost Ps 1.8 billion. This is basically explained by a gasoline and diesel price increase in pesos of only 8% and 9% respectively in the quarter being not enough to offset the increase in crude oil and by our fuel purchases which are denominated in dollars. However, revenues of this business segment managed to increase by 54%, driven by a solid demand of our main products coupled with higher price in pesos although lower in dollars of gasoline and diesel as explained before, higher sales of petrochemical products and higher exports on higher volumes and international prices.
It is worth mentioning that refining costs show an increase of only 15.5% compared to the same quarter 2017 as the currency depreciation played a beneficial role as well.
The gas and power segment also show a reduction of Ps 477 million. Although it’s worth highlighting that from Q1 2018, YPF Energía Electrica is no longer consolidating in the business. As a result, and in the second quarter of 2017, this company has contributed with Ps 299 million of EBITDA. So if we do normalize this effect, adjusted EBITDA of this segment would have grown by Ps 122 million.
Corporate expenses increased by Ps 864 million, mainly due to higher salaries, IT and advertising costs. Also there was a lower EBITDA contribution for our controlled company.
Finally, those results rated in the recent business segments that are not back to third-parties are eliminated in the column of eliminations. Basically due to the difference in valuation of inventories between transfer price and replacement costs.
The cash generation in the second quarter of the year which – 27.6 billion, more than doubling the operating cash flow of a year ago. This increase of 14.6 billion was mainly due to an increase in adjusted EBITDA while Ps 8.6 billion and a reduction in working capital and higher accounts payable as a result of the higher purchases of the period and the partial collection for the assignment of the Aguada Pichana Este and Aguada de Castro areas among others.
This operating cash flow more than exceeded the Ps 18 billion CapEx of the period and contributed during the last quarters that is part of our five year plan. Finally, this cash generation including the dollar denominating sovereign bonds still having treasury results in a strong cash position of Ps 57.6 billion at the end of the second quarter 2018.
As we can see in the graph, on the right, we are fully funding our CapEx program with our own cash generation. The explained cash position is enough to cover our debt maturities of the year and also the first half of 2019. Our leverage ratios came down to 1.8 times net debt-to-EBITDA bringing our two-time target for the year while the average life of the debt remains in the six year area.
The average interest paid in pesos increased to 31.7%, while the average cost of our debt in dollars remains stable at 7.4%.
With this, I would like to turn the presentation to Sergio, who will better explain our operational results.
Well, thank you, Diego. Good morning, everyone. Let me start by sharing with you this slide as Safety as a core value for YPF. Our daily work is done in places with some of the liquids, high pressure and – spaces. So we need to be a bit of vigilant and ensure that all the safety measures are taken so I can produce safe transport and send our products without harming our workers, environment or the community.
As you can see in the chart the currently injury frequency rate indicate that the measure of the number of people injured every million hours worked. It’s the lowest over the last ten years proving of the actions that we have been taking over the last few years regarding safety measures are paying out. Despite this figure, it is important to remain vigilant as we are reminded from time-to-time that we are working in potentially dangerous environment.
We have been focusing in formalizing as well the efforts and initiatives that we have been doing in terms of environmental, social and corporate governance, also known as ESG in order to position YPF in the first quarter compared to prior. We are penalized in our 2017 ESG report under the global report initiative standard so shortly it will be available in our workplace.
Now let’s move to the analysis of the second quarter production. Crude oil production in the second quarter increased 3.6% to 226,000 barrels of oil per day, whereas in the comparison with the second quarter of last year, we need to integrate the consequence of the severe weather conditions that time production in the Golfo San Jorge basin.
It is also worth mentioning on the positive side, that we saw an increase in oil production from our such oil field in Mendoza Province, an increase in liquids produced in our tight gas field at Estación Fernández Oro Rio Negro province and we also sold our [Indiscernible] field which production is not considered anymore.
Natural gas reached 44 million cubic meters per day, a 1.3% decrease compared to the same quarter last year, mainly due to the lower demand of sales for this product during the quarter and some delay in the – [Indiscernible] a non-operated offshore JV.
NGL’s production decreased 19% due to a scheduled maintenance in our affiliated company for reaching a total of 41.6000 barrels per day in the quarter. As a result, total hydrocarbon production dropped 1% vis-à-vis the same quarter of 2017 to 544.5000 barrels of oil equivalent per day. This production level is somehow similar to the fourth quarter 2017 and first quarter of 2018. So we start seeing a kind of stabilization.
When we break down the sources of production, we kind of serve that shale production contributed with 19.3000 additional BOEs per day in the quarter, while tight production show a slight decrease of 2.2000 BOEs per day mainly related to a lower production of natural gas liquids as a consequence of the stoppage in negative explained before.
As you kind of serve, growth is coming from our conventional fields and clearly most of the declines from our conventional fields. So we would like to do a deeper analysis on this in our next slide.
In this slide, you can see that our conventional production decreased by 5.5% vis-à-vis a year ago. First of all, it is worth mentioning that crude oil production in the second quarter of 2017 was affected by the weather contingencies that we already mentioned while in this quarter natural gas production was affected by lower demand of this product as explained before.
Having said that, due to the second quarter we have been focusing in the following aspects. First, managing the decline of our conventional fields by launching a series of initiatives in terms of primary, secondary and tertiary recovery, as well as natural gas compression in order to extract the maximum value while remaining profitable.
While primary recovery initiatives are the main contributors to improve the recovery factors for our conventional fields, we are also working to improve the process facilities and the quality of the water to accelerate our secondary recovery projects.
At the same time, we are currently developing three tertiary recovery projects two in San Jorge and one in Neuquina basin. And in the short-term, we will be adding five more pilot projects with a purchase of ten additional facilities for that purpose.
We had also continued with our strategy of disposing high cost non-core assets in order to focus on what is core. In that respect, we found out four additional material blocks in the Neuquina basin which by the way we are contributing with 2.2000 BOEs per day in the second quarter of last year and we will continue with this portfolio management activity.
We have also incorporated good quality blocks in our portfolio, such as Cerro Manrique, a tight gas block just reside at Estación Fernández Oro, one of our best tight gas fields.
Moving now to unconventional, net shale production of the quarter reached 66,000 BOEs per day showing an increase of almost 53% compared to a year ago. If we add to our net shale production the 96,000 BOEs of tight gas and liquids, our total unconventional production of 152,000 BOEs represent now almost 28% of our total production.
In terms of our activity as operator, during the second quarter, we produced 97,000 BOEs per day and we connected a total of 18 new shale horizontal wells. In relation to cost in our shale operations, the development cost in Loma Campana continues in the good trend staying in the first half of the year in the $12 per BOE area.
Operating expenses show a similar improvement coming down to the $7 per BOE area from more than $16 two years ago.
Although the peso depreciation effects are rapidly seen in lifting cost, it takes a longer period to impacting the CapEx as the average drilling and completion done is close to 180 days because we drill and complete and that took us forward. Therefore, we expect to see further reductions in the development cost in the following quarters.
Now, let me provide a general update on our shale projects. Continuing with our main shale development, Loma Campana, the operating JV we have with Chevron, it is important mentioning that we have successfully drilled completely then put into production the first 10,000 feet long lateral well with forty fracs and the total well cost is approximately $14 million.
Although it is still at early days as they were have been put into production for one week and we are still – it is up. It is already producing an interesting amount of oil and expectations reach an EOR in the order of magnitude of 1.5 million BOEs.
Based on the good results, we are having to still – we are not planning to increase the activity level next year, adding one more rigs to the already three rigs that are working there. For this reason, I am sure that we have the drilling and evacuation capacity for the additional production.
We are launching an expansion in the midstream capacity. These works include a Phase 1 expansion of the Loma Campana premium facilities, as well as the construction of a 88 kilometer oil pipeline.
These facilities will allow treating and transporting oil production not only from Loma Campana, but also other adjacent blocks in Vaca Muerta. The pipeline is already being constructed and expectation is to finish it by year-end.
In addition to Loma Campana, while we plan a gross production plateau reaching 100,000 barrels of oil equivalent per day in 2024 from the total level of 44,000 BOEs. As we mentioned in previous calls, we are currently derisking our Vaca Muerta acreage through 17 operated and non-operated pilots. The result we have seen so far are promising and therefore we expect two new FIDs by the last quarter of this year.
One of them is La Amarga Chica, a shale oil JV with Petronas and the second is Bandurria Sur, a JV with Schlumberger. We currently have one rig on each of one of these blocks and we will have up to two rigs on each block next year.
In line with these results, we are also analyzing launching additional pilots to reach more acreage and the challenge will be then being able to achieve the same development metrics that we have in Loma Campana on those new fields.
A series of initiatives have been launched in the Upstream segment to ensure those results. Among them, incorporating technologies. For instance, we know that just hearing from control room using data analytics and powerful databases to – failure, to optimize best plans, and to prioritize those developments are looked more attractive.
Also ensuring our people working collaborative mode, so that the user information is exchanged and – as well our facility design to reduce cost and lead time. We are also focusing in reducing the derisking to development cycles by having teams organized by projects and a sensor group that ensures best practices from one project are applied on the other projects.
YPF is very active on well position in Vaca Muerta with good quality acreage both in shale gas and shale oil areas. We are operators and 100% share or in JVs in some of this acreage and in others, we are not operators or within JVs with international renowned partners.
The situation combined with a short-term cycle investment like Shale is providing us with interesting optionality allowing us to direct up to a certain extent our CapEx to the most profitable fluids and projects.
Moving now to our Downstream business segment, during the quarter, the volume of crude oil process in our refineries was 275,000 barrels of oil per day, 6.6 lower than the second quarter 2017 mainly as a result of scheduled maintenance in our La Plata Refinery.
Regarding sales, total volumes were essentially flat with a reduction in domestic volumes almost offset by exports. Although demand for our main products diesel and gasoline increased, total volumes in the local market were down mainly to a significant reduction in fuel oil demand from power generation plants as there was more availability of natural gas.
Now, to provide more detail about fuel demand, on this slide, we can see on the left-hand side how gasoline sales evolved every month compared with the previous two years and on the right-hand side the same for diesel oil. Gasoline demand in the first half of the year is showing the same trend as in 2017 and 2016 with a total of 5.6% increase.
Diesel demand also show a good performance in 3.5% in the quarter despite the severe drought that affected agricultural sector this year, being this one a very great source of demand for this product. Market share for both products continued to be strong and are up 2017 with 55.7% in gasoline and 58.2% in diesel.
Market share for our premium products and Infinia Gasoline and Infinia Diesel were at 51.5% and 59.1% respectively. As explained at the beginning of the presentation, the spiking effect coupled with an increase in international price that happened in April put an increased pressure to our margins, and slightly for gasoline and diesel were reduced in dollar terms.
At that time, the government requested the industry to help govern inflation and in May an agreement was signed with refiners by which prices of the pumps would not increase for 60 days.
This agreement was amended in June towards some increase in fuel prices and include producers that agreed to negotiate lower price for local crude oil and to work closely with refiners to face operational difficulties that a macro situation was presented.
However, as the oil price gets on increasing and the peso continue devaluating in construction with the government and the other needs to players will be excited to terminate the agreement as well – until what the sharp negative effect in our client base and the overall economic activity, we decided to adjust our prices gradually in order to make up for these lower prices and this is what we have been doing as we will be showing late in the next slide.
Having said that, in this scenario, our Downstream EBITDA per refined barrel and without considering the revaluation of inventories decreased by $4 in the quarter whereas our fuel prices declined by the dollar.
Finally, in this slide, we are showing the evolution in the price of our main products diesel grade 2 versus the evolution of the import parity price in pesos. As you can see, since April, we have been adjusting gradually in order to start reducing the gap. This same analysis also applies for our regular gasoline which has a very similar evolution to the one for diesel shown in this chart.
Now, I would like to offer Daniel the opportunity of giving us the final remarks and then we will open the Q&A session.
Thank you, Sergio. Well, in summary, we are again reaffirming our guidance for 2018 of 10% growth in EBITDA in dollar terms with the production down 2% area, leverage should stand comfortably below our two times previous expectation as CapEx should be around 3.5 billion in the year.
Shale oil and gas production continues to provide great result about budget by the way and positions has to be able to double the number of drilling rigs dedicated to shale oil next year. As La Amarga Chica and Bandurria Sur move to full development and will be joining Loma Campana.
We are still slightly below budgeting conventional production in a couple of areas and the reasons behind such shortfall have been identified and are being dealt with. We should start seeing crude oil production growth next year as it was envisioned in the five year plan.
In terms of prices, we have made substantial catch-up in fuel prices last month or so, with average increases well above 10% and they are on track to full convergence before year end. Non-premium products still have another 10% give or take to catch up and premium products are almost there.
The situation with crude oil prices is similar as they are only 5% to 10% below export parity and should also converge with international prices before year end. The government has publicly and repeatedly made it clear that they do believe in market prices and that we are going in that direction. Natural gas prices are still not that clear. As a regulator it needs to determine how the devaluation effect will be passed through to consumers.
In any event, it is likely that the local gas prices will trend towards the $4.5 to $5 per million BTU range, which is below what some people have been expecting but consistent with our $4.5 number used in our five year plan. We will be making investment decisions with regards to natural gas depending on where the average price finally lands.
Access to financing remains open to us, especially in the bank markets, where lines of credits are virtually unused and liquidity is extremely strong. Therefore, there is no need to change any of the growth target that we have established in our five year plan.
So YPF has proved again its resilience to macroeconomic volatility and that’s also proved the value of our integrated business model approach. We will be conducting our Annual Investor Day in New York on October 26 and hope to see many of you there in person but with that, I would like to address your questions.
So, thank you and let’s start the Q&A session.
[Operator Instructions] And our first question online comes from Bruno Montanari from Morgan Stanley. Please go ahead.
Good morning everyone. Thanks for taking my questions. The first one is about pricing policy. First wanted to get some more color on natural gas. I understand that the situation is not very clear yet, but we read that the intention is to have a free market with tenders and bilateral agreements, but also read about this resolution seeking to prices for thermal power plants at least in the near term.
And gas distributors also pushing for a lower price. So, in the companies, what is the optimum policy? How should natural gas prices works in the country? Trying to think here about the framework and not necessarily about the actual price level which you mentioned $4.5 to $5 per million BTU that’s quite clear. But the framework to me is not a very transparent yet.
And on refining, it seems that June was the month with a wider gap versus the international fare, we see, looking at the chart in the presentation followed by the gradual improvement. Does that mean your refining margin should already improving in Q3 relative to Q2 or should we think of stable margins on other quarter until the gap fully closes?
And also I have a question about cash flows. So, we have now seen three quarters or so of positive free cash flow after interest payment with the strong trends now in the second quarter nearly $200 million. Do you think this trend will be sustained for the coming quarter especially now with the lower level of CapEx? Thank you very much.
Thank you, Bruno. Well let me address those questions. On pricing for natural gas, the question regarding the framework, I think that what we would like as a company and I believe the government is also going in that direction, it’s a free market with a possibility of contracting with the distribution companies with the independent power producers or initially with the Enarsa consolidating the natural gas for the power producers. I think we are going that direction.
The mentioned – I mentioned that you made to the price, which is actually around $4.20 what is being paid by – for the power generation gas. It’s only for the remainder of the year. We believe the intention of the government is to move to the auctions next year.
And as long as those auctions are for the medium-term, and have the ability of having low – maybe lower gas prices in the summer and higher gas prices during the winter, I think we should be fine and if we are right in terms of prices converging in the $4.5 to $5 per million BTU range, I can say that that can jeopardize any of our shale gas projects going forward.
But, as I said, we need to understand that better before making investment decisions because some projects may work with the prices in the $4.50 range others may need higher prices and others that can survive with lower prices. So depending on what the average wellhead price of gas is that will determine what is the size of our natural gas investments for the future.
Sorry to interrupt.
So you still want anything under the prior incentive plan, any of the assets you are getting higher priced?
Oh yes, when we talk about $4.50 to $5, that also includes in the weighted average a small percentage of a subsidy under the new plan. The old plan is gone. We have a few projects, some of which have already been approved and others that are in the process of being approved that should benefit from the pricing incentive that starts at $7.50 and goes all the way down to $6 per million BTU in the next four years.
Still that’s a very small amount in the total scheme of things in terms of natural gas for us, okay. But, it is definitely part of the weighted average price for us.
In terms of refining margins, yes, you are right. June was the one – the month with the widest gap. We can say that both refining and commercial margins should go up on the third quarter especially after the price increases are re-effected in July and our cost which were more than 10% in average and where the FX and the crude oil prices.
And I would say, import parity of refined products remaining essentially flat during this period. So, you should definitely expect that the refining margin of the second quarter should be kind of a slower and we should start recurring refining margins again. And in terms of cash flows, the answer to your question is, yes, we will continue to see positive free cash flow going forward.
You know, Bruno, that this is something that we will be guiding on for quite some time that in 2019, we would have positive free cash flow. So that shouldn’t surprise anybody and that should be the trend, as I said for the remainder of this year, but for next year and going forward also.
Perfect. Thanks a lot Daniel.
Thank you. Our next question online comes from Frank McGann from Bank of America. Please go ahead.
Yes, hi, good morning. Just on the JV that could be moving towards the development phase, as of the end of this year and next year. What – I was just wondering how you see those relative to Loma Campana in terms of potential production. You indicated Loma Campana will be close to 100,000 barrels a day by 2024. Do these other areas have similar potential and beyond the two that you talked about that could go into development by the end of this year, do you see more coming in 2019?
Yes, hi, Frank. So, as you know, both blocks La Amarga Chica, and Bandurria are not that far from Loma Campana. And we are both having good results in pilots from both blocks. So, as we say, well, Loma Campana is already more advanced, but we are going to increase activities on both blocks. We expect a same level of productivities that we are having Loma Campana, sometimes better.
And so, we are still in early days to define a production plateau. But probably La Amarga Chica where we are a little bit more advanced could be around 75,000 BOE plateau and in Bandurria Sur, probably 50 or more, but it’s still early days to confirm. And in terms of other blocks, as I said before, we are performing 17 pilots operated. We are having good results in all of them.
As an example, a non-operated pilot that is operated by Total in a well at Pichana Este. We just finished a pilot of 20 wells with very good results productivities are very good and we are going to start discussions now on a plan on a multi-year plan to add probably 40 more wells there. And I could go on, on every block, but just to say that we have a good portfolio and that we will be – going into FDIs as soon as we are well.
And I would say complementing what Sergio well explained, in these two additional shale oil blocks, Loma Campana, I’d say by the end of next year, approximately 20% of YPF’s crude oil production will come from shale oil, just from these three blocks, 20% give or take.
So, and that is obviously well below those plateau figures that are going to be reached in some place in the five to seven years. But only by one year ahead of us they are already going to be representing 20% of our total production.
If I could just follow-up, as you look going forward with more infrastructure now being put in place and already in place and a lot more experience, do you think the ramp up towards that plateau will gradually come quicker as a result of being further along the learning curve?
I’d say, it will depend on what we negotiate with our partners. In all these cases, we are 50-50 JVs and the phase of ramp up is directly proportional to the level of investments and we will have to sit down with each of our partners and decide what is the ideal level of investments that we are willing to make and that will result in what is the pace of acceleration. But in terms of costs, in terms of knowhow and so on, we haven’t found any reason why they should be different to Loma Campana.
Okay. Thank you very much.
Thank you. Our next question online comes from Regis Cardoso from Credit Suisse. Please go ahead.
Good morning, Daniel, Sergio, Diego, everyone. Thanks for the questions. A few questions from my side. One is regarding to your accrual of the receivables for natural gas prices and I understand that during the second quarter, you booked as revenues the full price for natural gas.
But you cannot collect the prices in full because of the depreciation in peso that still needs to be pass through tariff. So that the distribution company can effectively pay producers. So, is this diagnostic correct? And if this is the case, how much have you accrued and what is your expectation going forward.
Second question is regarding CapEx efficiencies, because you’ve effectively reduced CapEx forecast for the year while you’ve maintained production growth for the years ahead. So, I just wanted to understand if you are indeed seeing a more efficient CapEx. If that’s the case, how would you explained in terms of maybe – tax devaluation maybe more productive wells lower development cost. I mean, how representative are each of these factors?
And still on the CapEx efficiency side, I wanted to get a sense if you can share with us what should we consider to be the type oil curves, I mean it’s typical parameters, right if you can provide you are natural lands ID rates in both oil and gas windows. And finally, if we can do just a quick follow-up, the Downstream margins presented in Slide 15, I assume those also include the commercial distribution margins, right? Thanks.
Hi, Regis. Diego Celaá, let me address the first question. In terms of the trade receivables, yes, you are right. We haven’t been collected the full sales of gas, not only to natural gas but all the other distribution companies. The total amount that we have accrued is around $350 million and the reason why it is because those the tariffs that were pacified in April at a exchange rate of Ps 20.5.
Actually, the government have been saying the lead price using those that same exchange rate. Now we are discussing we are negotiating also with natural gas to see how we can end up trying to passing – pass through this into consumers. So we don’t have a lot of tariff yet. We are under negotiations. But I would say that, this we’ll be clarifying this in the next couple of months.
Now regarding CapEx, the reduction in CapEx is mostly related to devaluation in currency depreciation. I would say that most of the reduction is there. Maybe some light or maybe some small CapEx in some facilities are being postponed to next year.
But, again, most of the reductions are coming from currency depreciation and we are not in cutting activity in terms of drilling activity. So that reduction is not going to offset the production. In terms of type curve, well, I don’t know, and maybe Sergio can address that part for you.
Okay, so, in terms of type curves, first of all we have different type curves in one field and not only I would say geographically, but also by dept, because we will have different landing points and we have several fields.
So it is very difficult to provide one type curve for gas and one type curve for oil. However, we understand that question, I would probably will try to show something in our Investor Day in October. But there is no one, I would say type curve for oil and one type curve for gas.
Let me complement which is our – as Sergio say, because he did mentioned what half million barrels of EOR for our extended reach well, it’s just one well. We do believe that exercise is successful. It could be a total game changer for us.
Let’s put things in context for those of you that have been following us for five years or so, we started with the vertical wells that were expected to accumulate 300,000 barrels of oil during the life of the well. And initially they were also costing us $14 million, as Sergio said this well cost, right. So, again, it’s just one well, but it could represent a significant change.
And in terms of the – what up to recently we call the extended wells, which were those with the 2500 meters of lateral length, those, as Sergio said, vary from area-to-area. But just to give you a range, we are talking about 750,000 to 1 million barrels of EOR depending on the area even within concession areas, there is this variation.
And in natural gas, it’s much more difficult for us to provide a meaningful number given that the experience is somehow more limited. But the initial wells are giving us results that they should accumulate 10 Bcf in the life of the well. Okay, but again, let’s take these numbers we are going – because they are very initial results. So they are expectations on low number of wells. I should put it that way.
Okay, that’s very clear.
We still have the last question pending, yes, the free margins actually are including the marketing margins.
Thanks guys for the very complete answers.
Thank you. Our next question online comes from Luiz Carvalho from UBS. Please go ahead.
Hi, morning guys. Morning, Daniel, Diego, Sergio. Just two questions from my end here. The first one, back to the pricing policy. First, looking to the slide 16 when you mention about the 53% increase since the beginning of or late 2017.
My question is, why you cannot give a bit more visibility about what is the gap in terms of parity for each product and then, maybe I don’t know, on a monthly basis or on a quarterly basis and really it showed how much below parity and what’s the plan in order to close the gap looking forward, I think that would give more visibility on how to actually to look this – how can I say, topic in a bit more specific numbers?
That’s the first one. And the second, back to the divestments and form outs, you mentioned about some divestments that when the pipeline and also do you gave some updates under current JVs, but I am more looking for here and how should we see further divestments over the next three, six to nine months and also potentially JVs being signed.
Is there something in the pipeline that we expect or I mean for now, with the crude oil cap in the country is somehow more difficult? Thank you.
Good morning, Luiz. Thank you for the questions. Well, regarding pricing, the thing here is I’d say this is a competitive market. We do have more than 50% share, but we do not set prices for anybody and actually if you look at how our competition has raised prices in the last month, some of our competitors have raised prices well ahead of us and some of our competitors have raised prices in line with us.
And then, our pricing policy is at – takes into account a lot of different things and it’s not the same price in different parts of the country. It’s not the same price in different channels. So, when I talk about the catch-up that we still need to make, that is on average. Right, but the reality is that prices varies from region-to-region and from channel to channel and from product-to-product.
We may have efficient of increasing premium product prices well ahead of non-premium prices in early July and we made a decision not do the same in this last price hike a few days ago during the last week and the increase in premium products was only one percentage point higher than non-premium products. So, what I am trying to say with this is, we don’t want to hint competitors of exactly what our pricing policy is.
What I can tell you with what – I can is that, non-premium products still have a 10% catch-up to make 10% to our objective prices, meaning where the margins that we have never disclosed, but that we have put in our budget that we are trying to accomplish and the costs that we already know. And premium products, for the year, we have a positive margin, not the margins that we expect to have.
So we still need to do some catch-up but not a lot. And as I said during the presentation, you should assume that we will continue with this gradual catch-up during the next few months and this catch-up should be completed before the end of the year. And in terms of divestments, we are not working in any meaningful divestment in terms of Vaca Muerta.
What we have disclosed sometime ago is that we are close to finalizing a very small sell-side process of mature fields in Neuquina basin for fields. And once that transaction is over, we will probably start with a new one. Actually, we are in the process of starting with a new process again to sell out another few fields that we believe there are other people that can be more efficient than we are because of the size and the marginality of those fields.
This is in line with the strategy that we have laid out last year to over the long-term operate lower number of fields and concentrate in larger opportunities. But in terms of, again going back to Vaca Muerta, we believe that we have all the capital and the knowhow needed in order to develop those fields that are under pilot mode today.
So we don’t envision any need for additional farm outs over the short-term. Depending on where natural gas prices land, we will make decisions in terms of developing some of those natural gas fields and maybe part of those decisions have or result in teaming up with other partners to develop some of those gas projects.
But the reality is that, of those pilot projects, there are lots that we are operating with partners and there are many which we are not even operating and that we have our partners operate for us. So, there is very few acreage or very few areas under which we are already working at a 100%. Actually, in crude oil, there is none. So, no need for divestment over the short-term.
Okay. Just one last follow-up here. On the Slide 16, just to clarify, you mentioned the green line about import parity and the blue line the retailer price, right. But in the comment one, you made, this does not include internalization costs. Just to clarify this internalization cost is you mean from the forward and channel to the country, is that correct?
Because I just want to understand what the import parity means you. Is it including due to the cost – to the cost, the freight cost, I don’t know, from U.S. Gulf of Coast, Gulf of Mexico, to Argentina or is it sort of the export parity, I mean comparing prices, screen prices from Argentina to - I don’t know to any other regions.
Thank you, Luiz and sorry for the confusion here. But, internalization costs are included in the import parity
Oh, are included, right.
Yes. Can you say, does that included internalization cost, so, I just want to be clear that we are…
No, no, what we are comparing is the increases in retail prices with the increase in import parity with all costs included – including internalization and I understand there is a confusion in the slide. So, sorry for that.
Okay. Okay, thank you very much.
Thank you. Our next question online comes from Pavel Molchanov from Raymond James. Please go ahead.
Thanks for taking the question. In January of 2017, the Macri administration announced plan gas which targeted reaching self-sufficiency in natural gas by the year 2022 and I am curious with the changed approach to gas pricing, is it still realistic for Argentina as a whole to reach gas self-sufficiency within the next four years?
Thank you, Pavel. I think it is. I don’t see any reason why it isn’t. As I said, it will depend a lot on where natural gas prices in average end up landing meaning if it’s $4.50 to $5, which is our base case, I think there are substantial projects that can continue to be developed and therefore provide for all that additional production growth needed in order to reach self-sufficiency.
In any event, I think, what you need to differentiate is winter from summer, because self-sufficiency doesn’t mean that Argentina will not be continuing to import some LNG during the peak days of winter and maybe exporting natural gas in some form during the summer.
But, in all, what I would say is that, developments should continue if prices are attractive and we still believe that we are trending towards prices which continue to be attractive maybe not as attractive to the expectations that some people had six months to a year ago, but again $4.50 to $5 per million BTU should be good enough pricing.
Okay. At Loma Campana, last October, as I recall, there was a third rig being added. Can you give an update on how many rigs are currently running? And are there any plans to increase the rig count from current levels?
Yes, you are right. There are three rigs today. There is a plan to increase an additional rig next year. That’s just Loma Campana. But as I said, we still – or we need to start thinking of La Amarga Chica, and Bandurria also which will become very significant next year and in years beyond.
And we do expect we have one rig in each of those areas we do expect to add another two rigs by the end of next year in each of those areas. That’s why I said during the call, that we were expecting to double the number of rigs going after unconventional crude oil by the end of next year from five today to ten by the end of next year.
Okay. Thank you very much.
Thank you. Our next question online comes from Santiago Wesenack from AR Partners. Please go ahead.
Hi, good morning everyone. Thank you for taking my questions. Actually, I have a couple of questions. First, we have seen a lift in cost depressing this quarter 15% year-over-year in dollar terms around that. Could you give us any color on this and shall we expect this to be sustainable going forward? The second question is regarding the incentive plan for unconventional gas.
I would like to know which process was already approved by the government and which ones are still waiting for the final approval considering that the government is – Sergio say that going forward will be suspending these incentive plans. And taking this into consideration, which could be the implications going forward of these change in the gas plans. Thank you very much.
Thank you, Santiago. On the lifting cost question, where clearly the second quarter had the full benefit of the devaluation without the effect of inflation that follows – typically follows a devaluation of this size. So, I’d say, we will be giving back some of that during the remainder of the year. However, directionally, the trend is that we will continue to lower lifting cost.
Among other reasons for two - I’d say main drivers. One, the increase in the mix coming from Shale oil which as you know has a much lower lifting cost that’s our conventional production and Sergio showed in the presentation, a number of – I think it was $7 of lifting - $7 per barrel of lifting cost, okay. And the other reason is that, as we do expect not or the remainder of this year.
But on 2019 and going forward, an increase in production and given that some of our costs are fixed, we will start diluting some of those fixed costs and therefore reduce the lifting cost going forward. So, short answer to your question is, over the short-term, we will be giving back some of the benefits from the deval. Over the long-term, we will continue to see additional reductions in lifting cost.
And in terms of your question regarding incentive plan for natural gas, and which projects have and have not been approved yet, we will not get into detail because it’s a confidential and in many cases, most cases, these are projects that we have jointly with partners. But, what I can say is that approximately, half of the projects that we have filed have been fully approved. And the other half are still in process of being approved, but all of them have been appropriately filed.
That’s perfect for me. Thank you.
Thank you. Our next question online comes from [Indiscernible] from HSBC. Please go ahead.
Hi, thank you for the opportunity. I have one question. Could you please give more details on the cost side of El Orejano and another thing is, when I see the Loma Campana the oil cost, why would these be much lower than the oil cost for other shale players, right.
And is this more on a comping side. You kind of showed, maybe the $8 million per well. And while others indicate that it could be $12 million, maybe it’s accounting or indeed maybe it’s better productivity? Thanks.
Hi, Lilliana, before we answer the first question, can you clarify a little bit further the second question? That’s not fully clear to us.
Yes, in Loma Campana, right, you used to show that the well cost was about $8 million. Now you are kind of show in the slides more on the development cost, it’s about $12 million, right. Maybe could you clarify what else is there to make the gap and how can I compare the Loma Campana well cost versus the well cost of other players that indicate higher cost, or maybe I am wrong on that. So, if you could maybe compare well cost low in Campana versus other projects please?
I am not sure that the $8 million per well is comparable to the development cost. What we – the reason why we have moved from the cost per well to the development cost concept is that we have been changing the mix of wells. We went from the 1500 long laterals to 2500 and hopefully we are going to go longer in the future.
So, it basically be comparing – in order to compare apples-to-apples, we talk about development cost and that is why we are sharing with you what are the element cost is instead of focusing on the cost per well. Now, why is it that one of our wells is cheaper than some of the other players in the basin. I cannot say. We have drilled, how many wells in Loma Campana already?
More than 500 wells in Loma Campana already, well above 500 wells. And we are probably comparing with people that have only drilled a handful of wells. So, it’d be logical to assume that we are further down the curve and therefore are more efficient than others.
Yes, to complement on El Orejano, so we have development cost in El Orejano which is around $1 per million BTU. We are now moving into a new zone. So this is why we are not disclosing the development cost because it’s still new which we need to have production from this zone.
Okay, thank you.
Thank you. Our next question comes from[Indiscernible] from J.P. Morgan.
Good morning. I had just one follow-up on the accrued receivables from the gas distribution companies. I don’t know it’s from the Metro Gas side, do you know the amount of accrued gross accounts payables from Metro Gas to gas producers that you can disclose? Also can you please talk a little bit about refinancing plans?
I know you mentioned that you have almost $2 billion on the cash balance to, I guess, pertained to amortizations in 2018, but I don’t know if you can explain a little bit on the refinancing plans there? And we have also heard about financing plans and YPF is here, if you can comment on that as well. Thank you.
Hi, regarding the first question, unfortunately, we don’t break down the receivables by different companies. Again, of the total amount that we have accrued so far is $350 million.
Yes, and we see Metro Gas any other distribution company on a non-length basis. So there is no substantial difference in terms of what Metro Gas owes to us vis-à-vis what the rest of the system owes.
To the second part of your question, we do not have any financing plans for YPF S.A. because we have positive free cash flow and significant liquidity cushion and not any important debt maturities other than 400 and something million dollars coming due by the end of this year of the first bond that we issued back in 2013.
There are absolutely no plans for us to issue in the debt markets soon. What I did say during the presentation is that, we’ve seen the bank market while open to use and willing to lend money to us on a medium-term tenors which is good news and that’s a market that we haven’t tapped in quite some time.
So, that means, that any refinancing that we might have to do in the next few months is more likely and not to go through that part of the market as opposed to the bond market.
And in terms of YPF Energía Electrica, that’s a company with substantial projects going forward, substantial growth and definitely they will need to raise some debt in order to cope with all the CapEx with each of those projects. Some of the refinancing will come from ECAs. Some might be done as a project finance basis as it has been done in the past.
And that’s all we have to say for now. We are not working now I am talking for YPF EE, which by the way we have renamed YPF Luz. We are not working in any bond offering as we speak. Of course, if the markets reopen before the end of this year or next year, it is possible that YPF Luz will decide to tap those markets.
Okay, thank you.
And thank you. Our final question comes from[Indiscernible] Please go ahead
Thank you. Good morning, Daniel, Sergio, Diego. Can you – I have just one question here. When you see the prices of $4.50 to $5 are good enough to support gas production, what sort of IRRs are we looking at and can we assume that $4.50 is for tight and $5 is more for shale? Thank you.
Thank you. No, you should not assume that $4.50 is for one type of gas and $5 for the other. As I said, the way we look at it is, weighted average price of gas for the company. So, if it’s going to be Shale or is it going to be tight or it’s going to be associated gas, it will all depend on the returns on a project-by-project basis.
We do prioritize projects based on expected returns and if shale projects are more or less attractive than tight projects, those are the ones that will or will not get a sanction. Okay, but, I don’t think that we are going to a pricing scheme in Argentina, where there is going to be a difference in terms of the type of development. If it’s tight or if it’s shale or conventional.
And unfortunately, to the other part of your question, regarding IRRs, we do not disclose what are the expected IRRs. What we have always said is that, 13% on a dollar unlevered basis is our cut-off rate and that we do not sanction projects where the expected returns below that return or that level, I should say. But, from there, upwards, it varies a lot from project-to-project and we have never disclosed the IRRs on any given project.
Got it. Thank you, Daniel.
And we have no further questions at this time. I would now like to turn the call over to Daniel for closing comments.
Well, thank you very much everybody. Thank you Sergio, and Diego for organizing the call and as always, if there are any follow-up questions, please feel free to email or to call any of us here today. So, have a great day. Bye.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.