Welcome to the Repsol Third Quarter 2011 Preliminary Results Conference Call. The conference call will be conducted by Mr. Miguel Martínez, CFO of Repsol. We will start with a brief introduction by María Victoria Zingoni , Director of Investor Relations. Please proceed, María Victoria .
Good day, ladies and gentlemen. This is María Victoria Zingoni . On behalf of the company, I would like to thank you for taking the time to attend this conference on Repsol's third quarter results. The presentation, as explained, will be conducted by Mr. Miguel Martínez, our CFO. Other members of the Executive Committee are joining us as well today. Before we start, please, I invite you to read our disclaimer note. We may make forward-looking statements which are identified by the use of words such as "will," "expect," and similar phrases. Actual results may differ materially depending on the number of factors as indicated on the slide. I now hand the conference over to Miguel.
Thank you for attending this conference on our third quarter results. I would like to focus today on four main topics. First, the third quarter results. Second, the status of our upstream activity. Third, an update on unconventional oil in YPF. Finally, the startup of Cartagena Petronor. Starting with the results, this quarter we released a CCS adjusted net income of EUR 429 million and CCS adjusted operating income of EUR 1.2 billion. The CCS adjusted operating income is higher, almost 6% year-on-year and 25% sequentially. The good results are mainly due to the performance in YPF, the LNG division, and the increased results in upstream, partially offset by the downstream performance. On the upstream business, adjusted operating income was EUR 322 million, 4% up year-on-year. Higher realization prices and lower exploration expenses explain the increase in results, partially offset by lower volumes and the exchange rate effect.
Upstream was affected by Libya, around 40,000 bbl of oil, and Trinidad and Tobago, 24,000 bbl of oil per day. Decrease in gas production due to maintenance and refurbishing works in several producing platforms. However, upstream production is back to the 2010 levels of 30,000 bpd , and Peru has increased because of the LNG project up to 28,000 bpd . We maintain our guidance in production of an average of 300,000 BOE per day for the whole year without taking into account the recovery of Libya, when we are already producing 100,000 bpd . On a gross basis versus the 330,000 bpd production before the start of the crisis, due to the uncertainties regarding the safety conditions in the country's southwest region, it's impossible to make today reliable forecasts on the production recovery timeframe.
From a technical perspective, our facilities are in good condition. The key variables for increasing production are power generation, capacity to guarantee the water injection, availability of spare parts, and finally, the possibility of moving our expatriates and those of our main contractors to the Sahara Field. We are estimating in Libya for 2012 an average production of 170,000 bpd . However, we will keep on working to surpass this figure. Going to the LNG business, adjusted operating income in third quarter 2011 was EUR 108 million versus EUR 47 million posted in the same quarter last year. The year-on-year increase was driven by higher Peru LNG volumes and stronger LNG marketing margins. We have exceeded our mid-year yearly estimate, and we expect to finish the year with a result of around EUR 350 million, EUR 100 million more than our initial estimates.
In the downstream business, adjusted CCS operating income was EUR 219 million, 15% down year-on-year. In refining, the improvement of the product spread could not offset the higher oil prices and maintain the pressure on the refining margins. Earnings were also affected by lower utilization rates of the refining system due to the shutdown of the Cartagena refinery to do all the connections between old and new facilities for the startup of the new refinery. In the chemical business, the higher raw material cost also affected margins. On the positive side, in the marketing business, the resilience of results remains supported by an increase in the wholesale segment sales, resulting in higher market share and improvement of margins. These two factors have helped offset the 6% year-on-year decrease of volumes in service station sales.
In YPF, adjusted operating income in the third quarter was EUR 430 million versus EUR 393 million posted in the same quarter last year. An increase in prices at the pump in dollar terms year-on-year of 16% in diesel and 14% in gasoline, plus an increase of 3.4% in the sales volumes, drove a higher income. Additionally, the good performance of the agricultural sector caused a year-on-year increase of 8.5% of petrochemical product sales, mainly fertilizers. Oil production in the quarter was still recovering from the effects of the strikes in the second quarter. We managed to increase oil production by 24% quarter on quarter, from 183,000 bbl up to 227,000 bbl of oil per day. Current production level is close to 520,000 BOE per day, whereas 240,000 bbl are oil. Gas Natural Fenosa, at EUR 199 million adjusted operating income, was in line with the same quarter of last year.
Going now to the non-operational part of the results, we had an increase in our financial expenses due mainly to the results of the currency hedging positions. The $1.8 billion short U.S. dollar positions, which is a partial hedge of our overall long dollar exposure, had a negative impact in the results due to the dollar appreciation against the euro compared to the previous quarter. The depreciation of the Brazilian real against the dollar has affected the results as well. Additionally, I would like now to update on our current exploratory activity, as well as the wells that we'll start drilling during the rest of the year. Two discoveries have been announced in Brazil, Tinguá and Malombe. With respect to Tinguá, to properly evaluate the type of oil and deliverability, we will test the well in 2012, as soon as the right equipment is available from the operator.
Malombe has been a gas discovery with results volumes that indicate the discovery should be commercial. An announcement was made yesterday by our partner Anadarko, operator of the Montserrado-1 in Block LB-15 in Liberia. Although it has a limited net pay and this location itself is not commercial, it has hydrocarbons in two levels, and we are evaluating the extensions of these intervals. On the positive side, it confirms the existence of a hydrocarbon system in the area. We are currently drilling four exploratory wells, which will be finished before year-end. Three in Brazil, Abaré in Santos 9, Pão de Azúcar in Campos 33, and Itaboraí in Santos 44. Although it's early to draw conclusions, we feel positive about the three wells. One in Bolivia, Sararenda, which we expect to finish in December.
Moving to the appraisal drilling activity in the Gulf of Mexico, the Bascuñán 2 well was successful, confirming the initial range of resources, and the information is being evaluated to determine the location for the second appraisal well. In Brazil, Guará Azul was successful, and Guará RDI reservoir data acquisition is currently running DST. Finally, in the rest of the year, we're expecting to start six new wells, which will be finished in 2012. Two wells in Brazil, Sagitario in Block Santos 50 and Carioca Sela in Block Santos 9. Jupiter in the Sierra Leone Liberia Basin, Jaguar in Guyana, Sagari in Peru, and Ulvetanna in Norway. The Yewei well in Cuba will start early 2012 due to the delay in the reception of the rig.
Going through a short overview on the Santos 9 activities, we have drilled appraisal wells and finished a five-month extended well test in Guará, with a gross production of 2.4 million bbl. The results indicate a high productivity of the reservoir, confirming and improving our previous analysis and models. We started the extended well in Carioca Northeast on October 12th, with very good initial results. On the progress of the FPSOs, we are expecting the Cidade de São Paulo to arrive in Brazil before the end of the year in order to start the integration of the top sites. This FPSO is assigned to Guará, where first stall is scheduled for the first quarter 2013, with no change in our initial plan.
We also want to make a short comment regarding the startup of the Margarita and Kinteroni gas fields, with a significant amount of associated liquids, which is expected first and second half of 2012, respectively. I will now give you an update on various YPF topics. I will address first the marginal effect on YPF operations of the recent change in the Argentinian government made to the regulation about the treatment of the repatriation of export receipts. YPF has to comply now with the repatriation process that already applied to all the other exporting sectors in Argentina. Exports in YPF amounted to $1.5 billion last year, around 12% of our total revenues. The previous scheme allowed oil and gas companies to maintain 70% of the export receipts outside of Argentina.
The new regulation implies that we have to transfer our export proceeds to a foreign office of an Argentine bank in U.S. dollars. Moreover, depending on the product, there is a maximum of seven up to 12 months to convert those dollars in pesos. In order to neutralize the peso/dollar spread cost, we can match the dollar needs of our day-to-day activities, imports, loan payments, dividends, and foreign investments with the dollar sales coming from the exports. In this case, the only estimated impact to YPF cost is no more than $12 million linked to the credits and debit tax that these money inflows are subject to in Argentina. On November 2nd, YPF approved the payment of dividends. The dividend amount for Repsol will depend on exchange rates and will come up to around EUR 275 million. The payment date is November 14th.
I will now explain the progress in the oil non-conventional program we have had so far. Let me first recapitulate on the information we have given so far. Out of the nine salt rocks in Argentina, we choose Vaca Muerta, a 30,000 sq km formation, to start the non-conventional pilot project in Argentina. The net acreage we hold over Vaca Muerta comes up to 12,000 sq km out of the above-mentioned 30,000 sq km. We choose an area in the Loma La Lata field to start the pilot, and the conclusions we got there were, first, the formation is thicker than comparable basins with 200 m of average. Second, the initial production ranges between 200 bpd up to 600 bpd . Third, the estimated original oil in place per square kilometer is 43 million bbl.
We also announced back in July that we had an exploratory discovery outside of the Loma La Lata field in Bajada de Añelo. I will refer now to the recent developments and the future plans. I have finished the first stage in the area of 428 sq km in Loma La Lata Norte, with 15 positive wells in production, all of them with initial productions between 200 bpd and 600 bpd of good quality crude oil with an API between 40 and 45. Current overall production from these wells is 5,000 bpd . With these wells, we can confirm that this first area holds recoverable resources of approximately 930 million BOE , split in 741 million bbl of oil and 186 million bbl of gas. We will start booking reserves as early as this year.
We're still working on the development plan, analyzing several scenarios based on different assumptions for the number of the most important manageable variables, number of rigs, combination of vertical and horizontal wells, number of fractures per well, etc. With the information we have so far, we could expect $20 per bbl of development cost. In 2012, we plan to drill 24 vertical and 12 horizontal wells and build the required facilities to put the production on a stream. In total, we will be investing next year in this first area, $400 million. On top of the above-mentioned first area, we are working on a second one of 500 sq km. From those, 300 sq km approximately are net to YPF. In this second area, we have two discoveries, north and northeast of Loma La Lata, Bajada de Añelo and La Amarga Chica .
Even though resources associated to this area are still in the evaluation process, preliminary data make us feel positive about assuming same levels of recoverable ratios than in the first area and in consequence extend the 430 sq km up at almost 1,000 sq km. During 2012, we will proceed with further drilling in this area. To finish, we will continue working in the still important remaining part of the net 12,000 sq km area. We plan to move ahead with the information gathering appraisals and developments in modules of approximately 500 sq km. Going into our downstream projects, as you may be aware, the new Cartagena facilities are operating since mid-October, with all startups successfully concluded. Bilbao's Coker will be ready for oil by mid-November. As explained with this investment downstream, we expect between $2 and $3 per bbl in our refining margin.
This increase, in combination with a CapEx reduction of EUR 700 million, could positively impact the CCS free operating cash flow before taxes by around EUR 1.1 billion on an annual basis. On Tuesday, we announced a joint venture with SK L, South Korean Lubricants, to build a lubricant plant beside the Cartagena refinery. The EUR 250 million project and 630,000 tons per annum, in which we have a 30% stake, will produce lubricant base used for the production of ultimate generation lubricants suitable for EURO VI engines. This will be mandatory in Europe from 2014 onwards and will contribute to the reduction of greenhouse gas emissions. This project will start operations in 2014, will allow us obtaining more value from our refining residuals since it will use unconverted oil from hydrocracking units in Tarragona and Cartagena.
Summing up, we have delivered our downstream projects, achieving the objectives in terms of timing, cost, safety levels, and minimum problems at the time of startup. To finish, let me refer to our shareholders' agreement. On August 29th, two of our shareholders, Sacyr and Pemex, announced a syndication agreement of their stakes in the company. On September 28th, our Board of Directors analyzed the syndication agreement and took several resolutions regarding the situation created by it, which were publicly announced on the same day.
These resolutions include an emphasis on the importance of preserving the independence of Repsol and the development of its own strategy, and so an invitation to terminate that syndication agreement and an urgent amendment and analysis to the internal regulations with the aim of strengthening the protection of the corporate interest in the event of a designation of a competitor as a director and approval of related party transactions. The Board of Directors will continue to monitor the situation created by the syndication agreement. As managers of the company, we maintain our focus in the business and confirm that, first, we remain fully committed to the strategic plan, which remains on track with clear objectives in terms of growth and value creation, to continue this trend in the future.
Second, we also maintain our full commitment not only to all our shareholders, but also to the other stakeholders of the company. In consequence, we will keep our focus and effort on the delivery of our commitments. Now I'm open to any questions you may wish to put.
The Q&A session will begin now. If you would like to ask a question, please press zero one on your telephone keypad.
We have first a question from Santander with Jason Kenney . Jason, good morning. Please go ahead with your question.
Hi there. Thank you very much. I suppose I never really thought I would ever ask this question, but do you regret slightly now selling down YPF given the massive resource availability to that company in Argentina? Is it still the right thing to do for your political risk and capital risk exposure within your wider business? Could you just remind me on the specific timing for the Jaguar well in French Guyana?
Thanks for the question, Jason. Regarding the first one, we really don't regret anything. I mean, we know first that it was a portfolio issue. We always mentioned that YPF, it's a company with three clear assets, call it prices, call it growth, both conventional and unconventional. When we put in the market, it was a portfolio issue first. Second, I think that we can catalyze the value of the company better if we share it with partners, Argentine partners, international financial partners. I think it was the right move, and we are quite happy to share with others. Regarding Jaguar, our best estimate is that by mid-December, we'll start operations.
Many thanks.
Thank you, Jason. We have the next question from Exane BNP with Alex Marie. Alex, good morning.
Hi. Good afternoon, everyone. Thanks for taking my questions. The first question is on your LNG business. Clearly, you've beaten your guidance by a large margin there. I think the outlook for the business globally is pretty good. Can you give a sort of view on the run rate for future years on that business? Secondly, you mentioned in the press release that the strikes at YPF in Q2 did have an impact on Q3 volumes as well. Could you please quantify that? Finally, if you could just also give a quick update on your exploration plans in Cuba and your discussions with U.S. authorities there. Thanks.
Good morning. Alex, regarding the first question, I think that the results for next year on the LNG division are going to depend a lot on when the Manzanillo facility starts up its operations. I will say that the guidance, I will aim my best estimates today would be around EUR 300 million for next year, being a little optimistic. In relation with the strike, basically what we have suffered has been the ramp-up of the fall in Q2. The figures I can give you is we produce 183,000 bbl of oil in the second quarter, 227,000 bbl of oil in the third quarter, and we expect for this final quarter of the year around 240,000 bbl. My best estimate is that it has cost us 13,000 bbl of oil, more or less, per day. Regarding Cuba, good news there. Basically because there's no news.
We haven't received any problem, and by probably the first month of January 2013, it would be, sorry, 2012, would be starting operations.
Thank you.
Thank you, Alex. We have now from RBS, Barry McCarthy . Barry, please go ahead with your questions.
Thank you for the presentation. Three questions, please. Firstly, the response of the Argentine authority to this latest announcement of very significant resources of shale oil, does it reduce pressure in their minds to increase energy prices in Argentina? The second one is on the back of the release, and as you mentioned in your remarks, the changes at the board, if you could bring us up to date on what's going on in your discussions with Pemex. Finally, just to clarify, if the 12,000 sq km in the Vaca Muerta, is that net to YPF? Thank you.
I think with the third one, yes. I mean, it's 12,000 sq km net for YPF out of the 30,000 sq km of the whole Vaca Muerta area. In relation with the first one, I think that we have reached a situation with the Argentine government, which really helps both parts, and it's the best way to work out. I don't think that anything is going to change. Only for the small area we have started working on, which is this 428 sq km, we would need to invest something close to $20 billion. If you want to call for investments in a country, you really need to be moderate. We are, I think, there in good shape. Regarding realization price, today in Argentina, it's around $60- $61 per bbl. You have to think that this is also a split between the light crudes and the heavy crudes.
We have in the north, I mean, in Vaca Muerta, we're obtaining Medanito, which is 41 up to 45 degrees API. I think that with today's figures, those investments are profitable. In relation with the final question, which was your second one, which is in relation with Pemex, I think that both parties aim to normalize the situations. It will take some time, but I would say that the initial tension that was generated in August is coming down. We want to normalize our situation and find agreements with Pemex, which is the logical way to look for the future.
Thank you.
Thank you, Barry. We now have from Macquarie, Jason O'Connell . Jason, please.
Yes, thank you very much. I had a couple of questions on the Vaca Muerta, if I could, please. The first question I had is, what is the expectation for recovery on an individual well? Or, put another way, how many drilling locations would be necessary to recover the 930 million bbl that you referenced? The second question is, it appears to me that in 2012, based upon the drilling plan that you laid out, you'll be running somewhere in the three to four rig range. Is there any physical constraint on how quickly you could ramp up there if results are favorable, or could you get to 20 rigs relatively quickly? The third question I had is, what is the thought process behind drilling horizontally versus vertically, given that you have such a thick section? Is it going to be primarily a frac response issue? Thank you.
Starting with the first one, we're still in the learning curve, but right now, on average, per well, we will be, along its whole life, the estimates we have with these 15 initial wells, 350,000 bbl of oil. In relation with constraints, we have now five rigs and two frac equipments and teams there. We are in contact with some other suppliers that have contacted us because the work that should be, if news keeps coming in the good direction, could be massive. I don't see really with the contract we can provide the newcomers to have any problems regarding the advance or including more subcontractors there.
What? Oh, yeah. The third one referred to vertical and horizontal. As mentioned before, we are still in the learning curve, and we have started with vertical wells due to the thickness of the rock. This year, we will end up with two horizontal wells, and we will see the results. Initially, the cost is cheaper because for the vertical one, we are having costs of approximately $7.2 million- $7.3 million per well, while the horizontals would be a little more expensive in the range of $12 million- $13 million per well. We have to see. We are still in the learning curve, and we'll see, depending on the results we obtain, we'll be modifying our way of working. Think that, for example, in the range that we mentioned between 200 bbl and 600 bbl of oil per day, those in the area of the 600 bbl are the ones we have been drilling lately.
Basically, because we are learning, we are fracking more, we are including. I mean, it's still way too early. I expect that along the next year, we would be able to give you a better insight. Okay?
Yes, I appreciate that. Thank you.
Thank you, Jason. We now have from UBS, Jon Rigby. Jon, please go ahead.
Thank you very much. I've got three questions. I'm sort of jumping around a little bit. The first is, on the recoverable reserve assumptions that you're making, what are you assuming about how you develop this? Or put another way, do you think you can, is there an issue over the economics of this thing, depending on whether it's all verticals, all horizontals, or some combination of both? The second question is just to confirm, would this qualify for the petroleum plus bonuses, et cetera, as you add these reserves and resources? The third one is to go back to the LNG issue. I take your point that when Manzanillo opens, then you start putting LNG into that terminal.
The differential, it seems to me, between selling that LNG on a WTI netback, sorry, a Henry Hub netback price into Mexico, as opposed to selling it into, as you, I think, this quarter did Europe or Asia, is so great. Are you looking at some kind of infrastructure solution that could actually permanently divert those cargoes somewhere else? Is there something that is economically sensible, maybe linking with North America, that would make more sense than the current arrangement? Thanks.
Jon, in relation with the first question, basically, we are assuming the assumptions of the data we have today, and those are based on vertical wells, and those are based in the initial, I mean, production curves we are obtaining on these 15 wells. Along, as I mentioned before, the next year, we'll probably have a much clearer view on how it will evolve. Basically, we are thinking right now in approximately $20 per bbl on CapEx and approximately $6 - $7 on OpEx. This is when we, with all this data, then we reach the 300,000 bbl- 350,000 bbl for the whole production of one well with a good return. Those are our assumptions today. Probably, we will change it next year, but those are. In relation with Petróleo Plus , as you know, we lost first, second, and third quarter.
My estimate is that fourth quarter is going to be tough. We are going to be close, but probably we will not be able to gain it. Okay?
Going forward, with reserves recognized from this project, qualify under it?
Yes, for sure, Vaca Muerta will affect the thing that right now we are only producing 5%, sorry, 5,000 bbl.
Okay.
I think that the small area of 14 sq km of 400 sq km in which we are working, we will reach within three years, probably a plateau of approximately 4.5 million bbl per annum. I mean, it will help, but it will not guarantee to say something. Okay?
Okay. Yeah.
In relation with the LNG, yeah, it's true. It's a real pity to have to sell at Henry Hub prices. Though, as you know, we buy also in reference with Henry Hub. We still get a margin there. You also have to remember that thanks to this contract, we were able to obtain the project finance for the whole liquefaction plan. Basically, we'll have to stand with the existing contract and send our guys to Manzanillo. Okay?
Okay, thank you.
Thank you.
Thank you. Jon, we now have from SocGén , Irene Himona. Irene, please go ahead with your questions.
Yes, good afternoon. I had some questions of clarification, please. First, on Libya, you mentioned 300,000 bpd for this year, and you then mentioned 170,000 bpd for next year. Can I just ask on a net basis, what do you anticipate in Q4 and then in 2012? Secondly, a question again, clarification for your comments concerning Area 2 in Argentina. You said that the preliminary data is positive. Are you looking at similar levels of oil in place and recovery factors as in Area 1? Thank you. Sorry, final question. In terms of the economics, $20 of CapEx, $6 OpEx, what is the current oil price realization? Given those numbers, what sort of IRR are you looking at? Thank you.
In relation with Libya, our production before the war was 340,000 bbl of oil. That's gross. From those, our net was approximately 40,000 bbl. Right now, we are producing 100,000 bbl of oil per day. What we have estimated for next year, but being an estimate as bad as anyone, is that we will have, on average, 170,000 bbl of production in 2012. I would say November and December, we would be producing 100,000 bbl. From those, as a quick guidance, you can take our net multiplying by 0.14, approximately. Okay?
Thank you.
In relation with the second question, Area 2, Area 2 in the two wells we have drilled is behaving quite similar to Area 1. The answer is yes. Initially, with the data we have today, we can extrapolate up to this area. About realization prices in Argentina, as I mentioned, on average, the Argentine price today, average, as I said before, is $61 per bbl. Though Medanito, which is the type of crude we are producing in Vaca Muerta, is a little expensive. You can put $65, $66 per bbl. Okay?
Thank you.
Thank you, Irene. We have a next question from Tata Securities , Thomas Howard. Thomas, good afternoon.
Good afternoon. Of course, three questions, please. First, on Libya, I understand despite your production there, that at this stage, you cannot book production and profits yet. When do you expect this to be the case? Second, on YPF, just on a question on the board meeting, out of the 17 board members, the government rep rejected the dividend payment. I understand this was really the first time they did that. I wondered whether you can talk about why the government rejected this, whether it's related to the government wanting YPF to invest more domestically or anything to do with money supply in the country. The final question on Brazil and Carioca. My understanding is that the declaration of commerciality is due anytime soon. In fact, I think it's November.
Has this changed because you're still doing the extended well test and you've got the Carioca Sela well being drilled towards the end of the year, which is kind of key in terms of estimating the recoverable resources? Thank you.
Thomas, it's true that right now we are under the force majeure situation in Libya. We cannot increase that production, though the lawyers are in contact with the Libyan authorities, and we expect that short-term the situation would be solved. In relation with the dividend in YPF, as I mentioned, the dividend will be paid, and the government doesn't have any right to cancel this dividend. I mean, it's not an issue that the bylaws of the company, the government has any right to modify the majority. In relation with Brazil, the due date, as you mentioned, it was actually tomorrow, the 11th of November. We have asked for an enlargement of, and we have asked for an extension for two years to declare the commercialization. In the opposite terms, we have Guará, in which we are advancing, we are going to advance the commercial proposal. Okay?
Okay. Just to clarify, you've got this extension for two years, so it's now November 2013 for the deadline for declaration of commerciality there.
That's correct.
Okay. Thank you. Thank you very much.
Thank you, Thomas. We have a next question from Citigroup, Alastair Syme. Alastair, please go ahead with your questions.
Yeah. Hi, all. A couple of things. As you restart production in Libya, I'm just wondering whether you think the capital budget that you've got is sufficient, whether you're having to put in more CapEx, in other words, and how that might impact on your 2012 CapEx thoughts. Secondly, if I can just try and get a bit of guidance for you on where you think the EBITDA levels of YPF might be going forward. You've hit close to EUR 790 million this quarter. Is that a good run rate, do you think?
In relation with the CapEx, on a regular year, we normally invest in Libya approximately $120 million. Right now, we are, first, we have to see which additional investments are required because we don't have yet all the data. We are also in contact with the Libyan government to see how they are going to finance their part of the CapEx. I don't expect these figures to really affect our whole investments for the year. I mean, next year, probably without Gas Natural, we would be investing for EUR 5.5 billion. These investments in Libya will not modify the dial of the whole company. For this quarter, EBITDA in YPF, I would say that in the first three quarters, we have been able to have an EBITDA of EUR 2.2 billion, approximately. I really expect a good quarter on YPF. I think that we modify prices in July and August.
We have had only one month in this quarter with the prices. A little increase for the fourth quarter could be quite possible. I'll aim for the EUR 800 million EBITDA in the fourth quarter.
Okay, thank you very much.
Thank you, Alastair. We have a next question from Merrill Lynch from Hootan Yazhari. Good afternoon. Please go ahead with your question.
Hi there. One quick question regarding your downstream upgrades. You mentioned that Bilbao's coking activities will be ready for oil later this month. I just wanted to get some clarity in terms of what sort of conversion intensity you're expecting at all the new upgrading units that you've put through. What proportion of the upgrade margin are you currently capturing and do you expect to capture? Thank you.
We keep with our estimates. Basically, in the beginning, as I mentioned, we should increase for the whole system between $2 and $3. We will be producing next year approximately 300 million bbl, so between $2 and $3. We have been monitoring throughout 2011, which would have been the effective those investments were already in place, and those are the data we achieve. For sure, depending on the future and depending on the spreads between heavy and light crudes, this will modify along the future. I would say that we will start in the lower part of the approximately to the $2 to give you a guidance. Okay?
How much of that do you expect to capture in Q4?
Right now, the margins are quite rotten. I mean, today, yeah, actually, today was not a good day. When you see the margin index, but probably would gain $1.8, $2 maximum per bbl in this quarter. In the last two months, on average, with October, I would say $1.3, $1. something like that. Okay?
Understood. Thank you.
Thank you, Hootan. We now have from Barclays Capital, Lydia Rainforth . Lydia, please go ahead with your questions.
Thank you. Good afternoon. A couple of questions, if I could. Firstly, given the resource base in YPF, what sort of peak production would you now expect to get to? Secondly, you did just say that you'd be able to book some reserves from Vaca Muerta this year. Can you give us an indication of how much you might be able to book?
Okay. Lydia, in relation with the first one, I can give you the peak in Area 1. It would be really not prudent to give Area 2. In Area 2, we are still starting to know the area. In Area 1, I would say that the peak is 4.5 MMbpd , which approximately is 12,000 bpd . Okay? So 4.5 million per annum, 12,000 per day. The second question.
Regarding the reserves.
Yeah, refer to the reserves. Our estimates for this year is that approximately we would be booking something close to 20 million bbl- 25 million bbl. This is our best estimate today. Okay?
Okay, thank you.
Thank you, Lydia. We now have Peter Hutton from Royal Bank of Canada.
Hi, Miguel. Hi, María Victoria . Do you have any comments on the statement from YPF saying that the Vaca Muerta could be produced 50,000 bpd in the next four to five years? If so, what kind of, yeah, what number of rigs do you think is going to be necessary across the various areas to reach that kind of peak production?
I think that those were Tomás García Blanco's comments on a question saying, if everything behaves exactly the same, which do you think would be the peak? He mentioned this 50,000 bpd, but I'm not so risky. I kept to my first comment, and in Area 4, we would be able to, in Area 1, we would be able to produce next year, as a peak, 12,000 bpd . Okay?
Is that based on the sort of the five rigs that you were talking about before?
Starting with five rigs and two frac facilities, this will increase and ramp up in the following months and years.
Okay. You're not aware of any capacity restraints on pumping pressure in Argentina?
Not at all.
Okay, thank you.
Welcome.
Thank you, Peter. We now have Anish Kapadia from TPH. Anish, please go ahead with your questions.
Hi. I had a couple of questions. Just going back to the Vaca Muerta and thinking about the ramp-up over there. In the area that you've talked about, the 428 sq km, I think you'd need over 2,500 wells alone to develop that over time. It sounds like capital may be the main constraint with the current dividend policy within YPF. I just wanted to see how you're thinking about financing the growth in YPF. Secondly, just from the wider Repsol perspective, I was just wondering if we should expect further acquisitions in the E&P segment over the next six months. If so, is the focus more on the exploration side of things or buying production or early development assets?
In relation with Vaca Muerta, it's true that any figure you put on the table, all of them are enormous. I mean, only CapEx for this small first area, we are talking about $20 billion. There are many possibilities to finance this with partners, with special financing for this project. Our perspective is that still it's way too early. We want to know better what we have in Vaca Muerta before we start any correlation with third parties. Basically, we still have a minimum of a year to do our homework to see how Area 2 behaves, keep with the production of Area 1, and developing Area 1. For the next year, only this area will ask for more than $400 million. Probably in one year or so, we would be ready to make a movement.
In relation with acquisitions in E&P, we are not looking at the present time on any transaction. Basically, our model is based on organic growth. That's also the reason why we invest four times more than the rest of the international oil companies per barrel produced. We keep attached to our model, and only when we see exploration upside and additional exploration values when we move. We don't have anything right now in our portfolio too. We are not looking at any acquisition today.
Thanks. Can I just clarify one of your comments from earlier? You said 36 wells in the Vaca Muerta. Is that just in Area 1, or is that in the whole of the Vaca Muerta? The $400 million, again, is that just Area 1, or is that the whole of the Vaca Muerta next year?
What I mentioned, this 24 + 12, this goes straight to a part of Area 1. Okay?
There could be wells on top of that, exploration wells on top of that?
Yes, because you have to understand that we are totally in the learning process. This is our first estimate, but for sure, depending on the results, we will act one way or the other.
Yeah, there is an interest to develop part of the first area. You would expect some appraisal wells in the second one and more exploratory wells, as you mentioned, in the other part.
The $400 million refers to just Area 1.
Exactly, to the 36 wells that Miguel mentioned.
Great. Thank you.
Thanks.
You're welcome.
Thank you. We have a next question from HSBC, Paul Spedding. Paul, please go ahead with your questions.
Thanks very much. It's yet another question on Loma La Lata North. Most of the wells appear to have been drilled in the northern half of that license. I was curious as to whether that was due to geology or geography, whether it was not possible to drill in much of the southern part.
Yeah, because all the roads do today. Yes, most of it is based on geological reasons. I mean, we know that in this area, we have basically oil. If you move to the north and northeast, we have more oil. Moving down to the southwest, you have more gas. That's the reason why we are moving. On top of that, the reason why we choose basically to start in this area is because we have all the facilities in place thanks to the Loma La Lata gas field.
Can I ask a quick follow-up on the downstream, whether you could give us whether you're amortizing any of the refinery upgrade CapEx yet, and what the current book value of the refinery upgrades in Spain is?
It would be between 15 and 20 years, but we'll give you the exact data. Basically, it's between 15 and 20, but we'll provide you with the exact data through our IR people. Thank you.
We have a next question from Berenberg. Neill Morton , Neill. Just good afternoon.
Good afternoon. Just one question left for me. Again, back on to Argentina. You're clearly about to embark on a fairly major drilling campaign, yet Repsol is one of the few European companies not to have established a position in the U.S. shale revolution in recent years. That's clearly becoming a more sort of scientific approach. I just wondered whether you feel you've developed the necessary skills on your own, or do you feel that perhaps taking a position in the U.S. could increase your level of expertise, or alternatively, perhaps bringing in a U.S. partner into the Vaca Muerta? Thank you.
First comment is that we are not alone. I mean, in the Vaca Muerta area, we have the Exxon, we have EOG, we have Apache, and we have Total. We are not alone. We have been working for four years now in the Vaca Muerta area, and we have had a lot of contacts with different American institutes. I think that we have skill enough to understand and petrophysic capabilities enough to handle, which doesn't mean that we keep learning well after well. I'm optimistic regarding that sense. I mean, we are not alone. We have partners, and we have been for four years working and learning. I'm confident.
Okay, thank you.
Thank you, Neill. We have a last question from BBVA, Luis De Toledo. Luis?
Good afternoon. My question refers to the downstream activity and the potential outlook of the unit over the following on the fourth quarter and next month in the current macro scenario for Spain. You have provided reference for refining margins. Could you provide any detail on marketing and chemicals, and give some reference if you expect these to be floor levels of adjusted operating incomes providing the upgrade effect next year?
In relation with marketing, right now, we keep falling at 6.5% in the retail network, which I think is the most clear indicator. In relation with chemicals, we haven't had a shortage in the volumes we are selling. The margins have shrunk from the lower EUR 210 per ton down to EUR 160 per ton. I would say that I will expect a break even, so almost zero as operating profit for the chemicals, while in marketing, I think that through margins, we can offset the volume soul. Okay, Luis?
Okay, thank you.
We have also our last question. Thank you to all of you for attending the third quarter conference call. If you have more questions, please don't hesitate to contact us and your IR team. Thank you. Good afternoon.
Thank you for attending this conference call. Goodbye.