Paul Ferneyhough - IR Miguel Martinez - CFO

Biraj Borkhataria - Royal Bank Filipe Rosa - Haitong Hamish Clegg - Bank of America Bruno Silva - BPI Anish Kapadia - TPH Jon Rigby - UBS Thomas Adolff - Credit Suisse Irene Himona - Societe Generale Nitin Sharma - JPMorgan Marc Kofler - Jefferies Fernando Lafuente - N+1

Thank you, operator. Good afternoon. This is Paul Ferneyhough, Head of Investor Relations at Repsol. On behalf of the Company, I'd like to thank you for taking time to attend this conference call setting out the Company's second-quarter results. This conference call and associated webcast will be delivered by Miguel Martinez, Repsol's Chief Financial Officer, with members of the Executive Committee joining him here in Madrid. Before we start, I advise you to read our disclaimer. During this presentation, we may make forward-looking statements which are identified by the use of words such as will, expect, and similar phrases. Please note that actual results may differ materially, depending on a number of factors, as indicated in the disclaimer. I will now hand the conference call over to Mr. Miguel.

Thank you, Paul, and thank you to those online for attending this conference call on our second-quarter 2016 results. This year's adjusted net income was €345 million, and €917 million for the quarter and the first half of 2016 respectively. In today's call, we will address three main topics. Firstly, an update on the progress of our strategic plan, secondly, the market environment and the Company's main operational highlights, and finally, a review of the quarterly results. The first half of the year has seen a continuation of the challenging macro environment that the industry has been facing over the last 18 months. Compared to the second quarter of 2015, lower commodity prices in the upstream were offset by increased production volumes, lower cost and lower exploration expenses. In the downstream, the quarterly result was lower than in the same period of 2015, when we achieved record refining margins and were benefiting from full refining capacity throughout the quarter. In the second quarter of 2016, the planned turnarounds at the Cartagena and Tarragona refineries have reduced, as expected, both our distillation and conversion capacity utilization. As a result of this, our actual margin for the quarter was close to Repsol's refining margin indicator. Nevertheless, the sustained strength of the chemical business and improved commercial results delivered another good quarter from this division. Let's now continue with an update on our progress towards the delivery of our strategic objectives. Moving into our efficiency and synergy program, we continue to make good progress in 2016 and are on track to deliver the cost savings targets set out in our strategic plan. By the end of the second quarter, projects have commenced that will secure approximately 7% of our savings target for 2016. For the full year, we expect to surpass our previous guidance of capturing €1.2 billion of synergies and efficiencies, which represents more than half of our €2.1 billion commitment for 2018. Remember that this 1.2 billion includes 300 million on CapEx efficiency. Focusing on post-acquisition synergies, by the end of the second quarter more than 90% of the run rate target for 2016 and 70% for the planned synergies by 2020 have already been implemented. In the first half of 2016, results include a pre-tax cash impact of around $140 million from synergies, more than 50% of our commitment for the full year. More generally, the implementation of cost saving initiatives across all parts of our business has progressed as expected in the second quarter, with highlights as follows. In upstream, in the first half of the year we have achieved more than 50% of our full year objective, and by year end we expect to be well above the OpEx and CapEx reduction targets that we have set for the year. In downstream, we remain in line with our objectives for 2016, with initiatives mainly focused on improving refining margins, increasing the reliability of facilities and reducing other operational costs. Finally, at the corporate level, our expected savings for 2016 are higher than our initial projections. Overall the pre-tax cash impact from synergies and efficiencies in the first half of 2016 has amounted to more than €600 million, with more than 50% of this figure coming from the upstream division. We continue working to deleverage the Company and strengthen our balance sheet through divestment and expenditure optimization and expect our capital investment to remain below the €3.9 billion guidance level for 2016. The cash flow from operating activities generated during the first half of the year covered net investments, interest and dividend payments. Looking forward, although oil price improved in the second quarter compared to the lower levels observed early in the year, we remain cautious on the short-term recovery of commodities and continue to focus our efforts on achieving cash neutrality at around $40 price level. With regard to portfolio management, our divestment program has delivered proceeds of approximately €600 million this quarter from transactions that closed in the period. In total, in the first half of the year we have received proceeds from disposals of around €700 million and expect to receive an additional €700 million before year end from transactions already announced. To conclude, lower net debt through improved cash flow in the quarter was helped by the recent dividend increase approved by GasNat. In addition, Repsol expects to receive another €100 million of Gas Natural dividends in the second half of 2016, based on a projected interim dividend due in September. Before going into detail on the results, let me now describe the market environment and main operational highlights in the quarter. At the macro level, during the second quarter, oil price recovered marginally and Brent crude averaged $45 per barrel compared to $62 in the second quarter of 2015 and two $34 in the first quarter of the year. Gas price was stable in the quarter, with Henry Hub averaging $2 per million BTU, lower than the $2.60 observed in the second quarter of 2015. In recent weeks there has been a change in this trend, with Henry Hub near month future contracts, seeing some support and averaging around $2.8 per million BTU. Equity markets suffered from significant volatility in the quarter, in particular with ongoing uncertainties associated to the referendum in the UK. During the second quarter the U.S. dollar maintained its strength against the euro and has further strengthened since the British referendum result. At the present time, Repsol does not expect a material economic impact from Brexit in the short to medium term. And we don't expect any changes to our current operations framework. We will monitor the situation closely and react should any unexpected circumstances arise. Turning now to the operational activity, let me start with the upstream. Average production in the quarter stood at 697,000 barrels of oil equivalent per day. This is a 33% higher year on year, mainly due to a full quarter of volumes from acquired assets versus only a partial contribution in the second quarter of last year, together with the ramp-up of Cardon in Venezuela, Sapinhoa in Brazil, and contribution from Gudrun in Norway, along with higher production in Peru. Compared to the first quarter of 2016, production was 2% lower, mainly due to the shutdown of the backfill in Norway, maintenance work in Trinidad and Tobago, the impact of higher prices on royalties in Southeast Asia, PSCs and the temporary suspension of production in Acacias in response to low prices. These effects were partially offset by the ramp-up of Sapinhoa and higher gas production in Peru. In the month of July, production has continued in line with the second quarter. In exploration, a total of three exploratory and three appraisals wells were finished in the quarter. The three appraisals delivered positive results. Two exploratory wells were negative and one remains under evaluation. Results from the appraisals wells have improved the prospectivity and economics of future developments in Alaska, Campos 33 and Southeast Illizi in Algeria. The appraisal well at Gavea in Brazil was completed successfully at significant lower cost than budget and in line with the efficiency measures contemplated in our strategic plan. In Brazil, the hook-up of the FPSO at Lapa has been concluded and the installation of flow lines is currently ongoing. According to the operator, first oil is expected in the third quarter, one quarter ahead of schedule. In the UK, we continue to reduce our lifting costs, with CapEx and OpEx below plan and production ahead of schedule, while development projects, MonArb and Flyndre and Cawdor progressed towards first oil in the first half of 2017. In North America, production in the Marcellus has increased year on year, while reducing drilling activity to one rig. With a cash breakeven close to the $2 per million BTU, this asset is cash-generative at gas price levels observed since the end of the quarter. Moving to Latin America, in Peru, the gross production from Kinteroni only increased in April to 160 million square cubic feet of gas per day. The development of the Sagari discovery is continuing, with first gas planned for 2018. This development will raise total production from Block 57, about 200 million square feet of gas per day, once on stream. In Trinidad and Tobago, the execution of projects to increase production is ongoing. The development of Juniper is reaching its final stages, and a start-up is planned for 2017. This offshore shallow water project will reach a peak production of 95,000 barrels of oil equivalent per day, and is 100% owned and operated by our bpTT joint venture, where Repsol holds a 30% stake. In Vietnam, we are progressing the development of the CRD project, also known as Red Emperor. This project, economic at current price levels, has taken advantage of falling industry costs and recently tendered two major facility contracts. Final project sanction is expected in the fourth quarter of this year and fresh production is planned for the end of 2019. Finally, in Malaysia, following the announcement of the 10-year extension at PM3, progress on the development projects at Bunga Pakma, and Kinabalu in Sabah continue, with first production projected for 2018 and 2019 respectively. Now let's move to our downstream business, starting with refining. The schedule maintaining stoppages at Cartagena and Tarragona were completed on time and on budget. These planned outages reduced our distillation and conversion capacity utilization in the quarter. We achieved an actual refining margin of $6.60 in the period, $0.10 over an indicator. Despite the market environment, we have seen a healthy refining margin indicator of $6.50, slightly above the first quarter. We have now completed our major maintenance program for 2016 and expect our actual margin to recapture the full benefit of our industry-leading facilities in the second half of the year. In the month of July, the real margin has been on average $1 above the indicator, in line with the pre-maintenance delivery. In chemicals, the second quarter saw another strong performance, thanks to the steady sales and strong margins. The increased cost of naphtha was offset by the positive price environment across most petrochemical products. For the remainder of the year, we expect margins to remain solid, supported by a favorable international environment and a strong demand. Commercial businesses' contribution to results remains strong. LPG in Spain benefited from price adjustments of previous periods, while in marketing the sales in services stations increased due to seasonality. The Spanish model fuel demand maintained its recovery and the market has grown by 3.6% up to the end of May. The resiliency of refining margin, despite the evolution of international price and the scheduled maintenance activity, together with the sustained strength of the chemical business and the stability of our commercial division has resulted in ongoing strong cash flow delivery from the downstream division. Now let's move on the second-quarter earnings performance. Second quarter 2016, CCS adjusted net income was €345 million, 100% higher compared to the second quarter of last year. CCS adjusted net income on the first half of the year was €917 million, 26% lower compared to the same period of last year that include significant post-tax gain coming from the exchange rate positions due to the net long cash position in dollars held for the acquisition of Talisman. Looking at the results by division, starting with the upstream business, adjusted net income for the second quarter was €46 million positive, 94 million higher than in the same period of 2015. Overall, compared to the same period in 2015, lower oil and gas price realization in the second quarter of 2016 were offset by the impact of higher volumes, lower cost resulting from our efficiency project and lower exploration expenses. Reduced exploration expenditure, together with a portfolio targeting low risk has contributed to the overall optimization of upstream CapEx and reduced the volatility of our exploration cost within the income statement. Year-on-year performance is explained as follows. Higher production contributed to an increase in operating income of €290 million, thanks to volumes from the acquired assets, ramp-up of Cardon and Sapinhoa fields, the contribution from Gudrun and higher production in Peru. This was partially offset by maintenance work in Trinidad and Tobago, production at Varg in Norway, and lower activity in midcontinent in the U.S. As a result of lower exploration activity, principally due to lower amortization of dry wells, the operating income increased by €144 million, excluding the exchange rate effect. Lower crude oil and gas price, net of royalties, have a negative impact on the operating income of €372 million. Income tax expense had a positive impact of €32 million, mainly due to the positive effect from the appreciation of some local currencies, principally in Brazil. Income of equity affiliate and non-controlling interest, depreciation and amortization, exchange rate and others, explain the remaining difference. Turning to the downstream division, CCS adjusted net income in the quarter was €378 million, 14% lower than in the second quarter of last year. Drilling down into the quarterly results, in refining, lower utilization rates, along with lower refining margins due to the planned maintenance reduced operating income by €224 million. The refining margin indicators decline in the period compared to the second quarter of 2015 due to narrower middle distillate and light heavy crude spreads, partially offset by lower energy costs. In chemicals, higher sales volumes and improved margins, aided by better market environment, generate a positive effect on the operating income of €14 million. In marketing and LPG, operating income was higher by €54 million compared to the second quarter of 2015. In gas and power and trading, the operating income was €18 million lower than in the second quarter of 2015. Results in other activities, equity affiliates and non-controlling interest, exchange rate and taxes explain the remaining difference. With regards to Gas Natural Fenosa, adjusted net income in the second quarter of 2016 amounted to €96 million, 9% lower year on year, mainly due to the lower profit in the gas commercialization business attributable to the current price environment. Moving now to the financial aspects, our second-quarter net financial result was negative €185 million, broadly in line with the second quarter of 2015. During the last few months, Repsol has taken advantage of market conditions to reduce its average cost of debt. The Group's net financial debt at the end of the second quarter amounted to €11.7 billion, a decrease of around €300 million compared to the end of the previous quarter. The Group's liquidity at the end of the first half was approximately 6.7 billion, including undrawn credit lines, which represents 1.8 times coverage of short-term maturities. To conclude, we remain cautious on the base of long-term commodity price recovery and expect further volatility going forward. Under that framework, we will continue to re-strengthen our balance sheet through portfolio actions, whilst maturing synergies and implementing self-help measures that will reduce the Group cash neutrality breakeven to our $40 objective. In the upstream, our reduced exploration costs have allowed us to more than breakeven of the adjusted net income level, even at current prices. The average production level in the first half of 2016 stays within our strategic plan objectives. And our OpEx and CapEx optimization measures are on track to reduce our upstream free cash flow breakeven. In downstream, having completed all major planned maintenance for the year, we are now able to capture all the potential from our refining conversion capacity for second half of the year, maximizing the cash flow generation from this business. Finally, we have almost achieved our divestment target for the period to 2017 and will continue assessing our portfolio for further divestments that will allow us to realize full value. In summary, we remain committed to our long-term strategic growth and are delivering against our shared term commitments. Thank you very much for your attention. And now we'll hand the call back to Paul, who will lead us through the Q&A session.

Thank you very much, Miguel. For those of you on the line, in case you run into technical problems during the webcast or conference call, please address any problems to our investor relations email address, investorrelations@Repsol.com, and we will contact you immediately to try to solve it. Operator, please can you remind the audience of the process for registering a question?

[Operator Instructions]

Thank you. Now we'll continue with a question-and-answer session. Our first question comes from Biraj Borkhataria at Royal Bank. Go ahead, Biraj.

Hi, guys. Thanks for taking my questions. I have three, if I may. The first one was on exploration. And I know you had a pretty low charge again this quarter. I was wondering if you could just remind us of the wells you're going to drill in 3Q and 4Q and any significant well results due in that timeframe. Second question would be on corporate and other cost line. That remains pretty volatile. If I'm looking one or two years ahead, what would be a sensible run rate for that number, obviously including Talisman in there? And then the third question for Miguel would be I wonder if you could just talk a little bit about refining margins. There's been a lot of talk about weak gasoline margins recently and is there any comments you can make on the potential for that to spill over into Europe on the middle distillates side and how that would impact Repsol? Thanks.

Thanks, Biraj. In relation with the exploration for the rest of the year, I would say that basically what we have, it's a modest project, and not only modest but also, I would say, a low-risk one because we have focused more on price or wealth. Having said so, the three basic wells we have in front of us are going to be Bulgaria, which is an offshore prospect; Papua New Guinea, an onshore prospect; and Colombia, also onshore. Other than that, there's going to be a small activity. In relation with the corporate level, I agree with you, but you have to take into account that in the first quarter we had the gains from the conversion of the Canadian bonds. We repurchased those, and this is probably what is changing the -- creating volatility in that line. I'd say that without any extraordinary items, the figure would be around 1.3 billion for the whole year. So it's more or less a little above 100 million per month. In relation with refining margins, only if I knew, I would be really happy. Basically what we have seen in -- during the month in July is a weakness due to a narrow margin between heavy and light, in one hand; second, the gasoline spreads that were quite nice, I would say, in the first half of the year has shrunk, which makes sense due to the end of the driving season for the refiners. And we have not seen yet the increase in the diesel spreads, so all in right now, it's true that refining margins are a little low. Having said so, I think that the main factor is going to be the weather in the fourth quarter. And also one thing we have realized since June, when we finish both the maintenance in Cartagena and Tarragona is that were well above the index. The improvement in operational capabilities plus the energy efficiency we have gained with this maintenance is giving us an extra room. And then we will have to see. But this is what I can tell you.

Thanks, Biraj. Our next question comes from Filipe Rosa of Haitong. Go ahead, Filipe.

So three for me as well, the first one on the hybrid bonds. If you could update us on where do you -- do you see a potential timing for you to come up with further issuance of these bonds? The second one relates to this new project, Lapa. I think that it's a little bit more complex than Sapinhoa. Could you just give us an idea where do you think it's the breakeven price for those projects? And finally, could you just update us on the situation in Venezuela? What's the current impact on the balance sheet and what are the prospects to try to solve this situation? Thank you very much.

Thanks, Filipe. I think that, as I mentioned in the first-quarter results presentation, I thought at that time that the entrance of the ECB acquiring corporate bonds was going to deflate the yields and then a window for the hybrids may open. If I look at our hybrids in the first days of the year, we reach a 10% yield. Right now it's around 5%. I'm talking about the [indiscernible]. So it's true that the trend goes in our direction and potential timing, I would say, fourth quarter looks to me at the present time the right moment, because I think that the influence of the ECB is going to be stronger month after month. In relation with Lapa, I will say that if we talk about CapEx and OpEx, the breakeven, at least our estimate is around $55 per barrel. Compare it with Sapinhoa, which had 30, well it's true that it's a little more difficult. But you have to think that, A, it's a smaller prospect, smaller -- which implies extra fixed cost, and also that this estimate, it's based on the first phase of Lapa. A second phase in the southern part of Lapa will probably reduce a little this breakeven point. And finally, in relation with Venezuela, Venezuela, right now the financial team of PDVSA, it's in Madrid in our offices. And we are trying to work out a way to somehow make the financials, so for the JVs to move ahead. Right now, there is some hub lock. This is one issue, and let's see through the idea of the straw count that we have been working with them for, I would say, probably 18 months, we are able to really start moving and generate the liquidity that is needed for the operations. In relation with Cardon, there was a contract amended that has blocked somehow the payments. Last week our CEO, Josu Jon Imaz, and Head of Upstream, Luis Cabra, were in Venezuela and the whole thing has been solved. We already have received the first payment for $25 million. And I think that the difference that that were or differences we had with them was what part of the fee was going -- had to be paid in dollars and which part in bolivars. At the end, it's going to be good for costs till the year end. And this is what I can tell you. We keep operating there and we expect, A, that in Cardon the new situation will allow us to obtain the recovery of our bills straight. And we also hope that the two financial teams that meet today, this week in Madrid, will solve the issue with the [straw count] in order to make the JVs work financially Did I answer you, Filipe?

Thank you, Filipe. Our next question comes from Hamish Clegg of Bank of America. Go ahead, Hamish.

Just a couple of quick ones, expanding a little bit on things you've talked about. First, just on the refining margins, you've mentioned a couple of times we're likely to see a premium and we are seeing a premium already over your benchmark. Could you maybe just extract what the main things are giving you that premium? Is it the increased product yields? Or is it the flexibility to purchase cheaper crudes? My second question was just regarding the hybrids. You mentioned that Q4 is the right time for it. Could you give us an idea of size and scale of what the appropriate -- a year ago you guided us to $3 billion of -- €3 billion of hybrids, sorry. Actually, maybe it was a little bit more than that. Could you update us on what sort of scale we're talking about? It was 5 billion, actually. Are we looking at potentially another 3 billion? And just finally, could you clarify a little bit how we can expect tax to impact the business going forward? I appreciate it was a currency impact in the second quarter. How should we think about modelling tax going forward? Thanks.

Thanks, Hamish. In relation with refining margins, I think that there are several factors. The first one is the conversion. We have all our five refineries in the first quartile, so our conversion is higher than those of our peers. Second, I may say that this allowed us to optimize the slate of crudes, so that's the first point. The second one, which I also think it's important, is that we operate the five refineries as a unit. So we maximize the group. Normally companies that have refineries here and there, they simply optimize refineries individually. To have all the refineries connected, give us the option to maximize the group. And I think those are the two main factors that give us always an edge. In relation with the hybrids, my thoughts move more in the direction of 1.5 billion. I think it's the limit, and this is more or less the limit we May aim at. And in relation with the tax, to model tax is quite complex. Honestly, because basically only the impact we have been suffering from the differences on foreign exchange really blow out any model you may put in. The real moved from 3.2 last year up to 4 point something and then back down to $3.2 -- sorry, BRL3.2 per dollar. The impact of this, it's enormous. The thing that we have to calculate, if you have 2 billion of capital invested there in dollars and all of a sudden the currency you are playing with reduces to a 50 percentage value, then you have to recognize day one the loss in depreciation that you are going to suffer because, in fiscal terms, your asset has shrunk to half of it. So it's really difficult, and especially in a call like that. But we are totally open if you want to sit with our tax people and they will try to clarify a little better than me. But believe me, it's not easy to model that, sorry. Hamish.

Don't worry. We'll try to figure out a rule of thumb. Thanks.

Thank you, Hamish. Our next question comes from Bruno Silva at BPI. Please go ahead, Bruno.

Morning, everyone. I have three quick questions, if I may. The first one, just a clarification. I did not quite understand if the level of breakeven in upstream of the $60 that you mention in page 24 versus the 65 that you have in the strategic plan entering force in the first quarter, if that's relating to a different time horizon or if you are actually at unclear, your ultimate goal on this front. The second one is related with -- you already mentioned CapEx execution this year. You said that it should be below the average target for the '16, '17 period. Are you now in a better position to be more precise about the CapEx guidance for the year and how much it will come from upstream? And finally, just a detailed question regarding the working capital evolution. I was revisiting your statements in the first quarter conference call and you already added something from Venezuela. But I'm still struggling to understand what could be a good figure for working capital change for the full year. So I would appreciate if you can help me guiding through. Thank you very much.

Thanks, Bruno. In relation with the first one, it's 60 and 65. The point is that 65 is the actual objective for the year, while 60, it's for the period '18, '20. Okay? So sorry if we generate some confusion, but the Repsol divisions have objectives for every year. So sometimes we'll refer to the 2016, sometimes we refer to 2018. Sorry we have generated confusion there. Going into the CapEx, you may think that for the whole year we expect to be a little below €3.9 billion. From those, approximately 800 million will come from the downstream division. So the rest would be upstream because corporate will not have any significance. Working capital is a good question. It has made me think a lot, because within the year we have increased our working capital by 750 million, more or less, 730 million. Within that we have the following impacts. In order to see where it's going to end up at the end of the year, first we have Venezuela, which has implied an increase of 215 million. I think that part of this is going to be recaptured in the second half of the year. Then we have a factor that was somehow surprising to me, which is due to the reduced level of investments, our accounts payable has shrunk, which is going against the working capital figure. And finally, for sure, there is a third factor that has been also important in this 730 million that we have suffered in the first half of the year, which is the price increase and the activity. So I may say that the first two can be arranged and the third one is something we may guess, based on the price finally -- final price of oil you have in your estimates. But one thing is clear I think that we should shrink that figure before the year end. I cannot measure whether it would be 100 million, 200 million or 300 million, but for sure it will shrink and will help the free cash flow of the company. Is that okay?

Yes, perfect. Thank you very much.

Thank you, Bruno. Our next question comes from Anish Kapadia at TPH. Anish, go ahead.

Good afternoon. A few questions, just firstly on CapEx for 2017, I was wondering if you could just update where you are thinking at the moment and where the flexibility is regionally in terms of upside and downside for that CapEx number. Secondly, just wondering if you can talk in a bit more detail about petchems, it's interesting that we are seeing a kind of different dynamic it seems in terms of petchem demand versus the refining demand there for gasoline and middle distillates. Just wondering what you're seeing there and why I suppose you're more confident on petchems. And then just finally on Trinidad, I see you've got a new project coming on stream to boost volumes over there, but it seems like it's an area with pretty low reserve life. I'm just wondering are there license renegotiations going on at the moment to extend out your contract? What's your longer-term outlook for Trinidad production? Thank you.

Thanks, Anish. In relation with the CapEx for 2017, we are starting now the process for 2017 budget, which probably will be more accurate that the strategic plan figure. But as a -- I would say, to give some color I would say the 3.94 billion would be the figure for the whole Company in 2017. In relation with the second one, if I understood, the question was somehow, and if you can confirm, Anish, it was which were the estimates for petrochemicals refining demands and middle distillates. Is that the question?

Well, no, it's more that I think the petrochemical market looks stronger than the gasoline and diesel market in terms of demand, I think in terms of where margins are at the moment. And you mentioned you expected petchems demand to stay strong. Just wondering how you're seeing in terms of your current demand estimates why petchems is staying so strong whilst gasoline and diesel is weakening.

The only answer I can give you, it's A, demand is going to be much dependent on GDP. Chemicals refers to GDP quite well. Spain is improving and also our European markets are doing quite well. So if I have to take a clue, I'll go along with the GDP volume stocking. Margin stocking, I would say that all the flexibility we have been working on in the last three/four years, plus all the impact of the dual capacity to feed our crackers either with gas or with naphtha is giving us the flexibility needed to optimize the crackers. So basically if the GDP remains, and it looks like it's doing that well, July it's been delivering okay, we don't have any doubt that probably it would be around 600 million, 650 million of EBIT by the yearend. And in relation with the Trinidad Tobago new project, I would say that licenses are still there so it's not a license negotiation. The only thing that is up, it's some of the gas contracts that have to be renegotiated. But they are in process so I cannot give you more data about that. But basically the licenses are not in discussions and the renegotiation refers to some of the gas contracts. Is that okay, Anish?

Thanks, Anish. Our next question comes from Jon Rigby at UBS. Go ahead, Jon.

Thank you. Hi, Miguel. Could you just go back -- well two questions, first one is could we just go back to the hybrid? I take the point about the cost of the hybrid coming down, but I think you note in the release that some of your shorter to medium-term bonds have been issued at close to zero interest rates. So how do you square up the relative cost of that kind of debt issuance and what the respective advantages of issuing more expensive hybrid debt versus standard bond issuance is, because clearly you're being quite successful in bringing down overall debt in any case and stabilizing the business? And then second question, can you just go through a little bit more on the dispute between yourselves and Sinopec, how it might get resolved and just confirm it's being compartmentalized and not affecting your day-to-day relationship in both the North Sea and Brazil, please? Thanks.

Hi, Jon. Nice to hear you. A, I think that the point there is not cost and there are certain limits. We are not issuing because of liquidity needs. Basically we are issuing for need of equity content. And that's the point. For us to maintain investment grade is a must and issuance of the hybrid, despite having an extra cost, it takes advantages in front of the ratios that the rating companies use. So to me the point, taking into account that it has a consideration of half of it, it's capital, it's equity, well if we take into account the cost of equity, well for 50% that shows somehow where it should be. But, as mentioned, it's not a liquidity issue. In relation with Sinopec, A, you know that according to the arbitration procedure rules I am under total confidentiality agreement. What I can do is refer to our press release dated June 16, in which we include the information. Having said so, I think that the arbitration has made the corporate relationship between Sinopec and Repsol increasingly complex and difficult. Operationally, our teams keep working in both JVs. North Sea and Brazil delivering well, ensuring effectively safe operations and delivering business objectives. So we will see. One thing is clear, Repsol is mindful of the interest of the JVs and we will continue to honor all the commitments undertaken. And we expect that other Sinopecs do the same. But it's all I can tell you. It's a pity that probably we have lost possibilities to have more corporate transactions with them.

Just going back to that point you make about the hybrid, would you consider that the loss of investment grade and then the additional cost of borrowing that would come with that in a standard borrowing environment exceeds the cost of retaining investment grade by issuing the hybrid? Is that the way to think about it?

No. I will not lose the investment grade. For us the investment grade is a must. I can mention at least five reasons why. A, you cannot enter in upstream multibillion projects if you don't have the investment grade. B, in trading activities, with very low margins, if you have to -- if your personal guarantee is not enough and you have to go to a bank for an [LC], then you're out of the trading activity. C, financing without the investment grade would be by far more expensive that the extra cost of the hybrid versus the senior bond. Fourth, some of the shares would be affected because some of the funds only invest in investment-grade companies. And fifth but not last, which I think it's important, it forces the Company to a discipline that really helps all the Company working in one direction. And considering the five factors I would say that, no, we are not going to lose the investment grade.

Thank you, Jon. Our next question comes from Thomas Adolff at Credit Suisse. Go ahead, Thomas.

Three questions as well from me, two fairly straightforward ones, I just wanted to go back to Lapa. In Lapa, you talked about phase two, the thousand part. I just wanted to make sure that this is a tieback to extend the duration of the plateau. And if that's indeed the case, what is the best case for the plateau duration? Secondly, on Sagari, you talked about that being developed, and I just wanted to get an update on was it a 1 to 2tcf field, and if so then I guess the 200mcf today is a gross peak production. Finally, Miguel, we've always had this discussion on the credit ratings, etc. And now the oil price is where it is and who knows what the future brings. But what is it you need to deliver from now until you meet with the rating agencies next, if anything? I recall when the S&P published a note a couple of months ago that they expected something material to happen to improve the credit metrics in the short term, and that's the next three to six months. So is that more disposals? And if that's indeed more disposals asides from the hybrids? I had a question specific to upstream in Tangguh, you have a small stake there, BP took FID there. Do you intend to monetize that minority holding? Thank you.

Thanks, Thomas, for the questions. In relation with Lapa, the answer is yes. There is no second FPSO; it's simply a tie-in. Basically, what we are thinking as of today is that the first phase will probably produce around 80,000 barrels of oil per day, and the second phase will add up approximately 20,000 extra. And in Sagari, the only data I have and the only thing I can tell you is that, A, we are doing good progress below budget. And the productivity of the wells, it's extraordinary. It's very good productivity. In relation with the rating, the point here is, and it's clear after the acquisition of Talisman, we have to strengthen the balance sheet. And we'll keep doing that by two ways. There would be more divestments, which I'm not going to talk about for sure or to disclose. And also we need some strength in the equity or in the capital, if you want. And we'll be doing that during the second half of this year. But it's not that the term is three months. I think that the track record with the agencies is clear. We have been in tougher situations. Remember Argentina. And we have been delivering with them and doing what we have promised. So we keep quite comfortable that we will deliver and that there will not be major problems. Is that okay, Thomas?

Thank you, Thomas. Our next question comes from Irene Himona at Societe Generale. Go ahead, please.

Thank you, both. Hello, Miguel. Two quick questions, please. Firstly U.S. upstream if you can perhaps update us on progress made in terms of unit OpEx, specifically cost benefits you're seeing after selling your Eagle Ford interest to Statoil last year. And then related to that is the second one. You referred to it before; it was in the cash flow you have a tax credit so you received a payment. How much of that was due to the Norwegian deal with Statoil, your acquisition of the Gudrun interest, please? Thank you.

Hi, Irene. Thanks for the questions. Basically if we take the upstream, we have been able to reduce a total of 895 million already booked in the P&L. If I apply that to the OpEx per barrel, starting by 2014 it would be $21.5 per barrel. We reduced that in 2015 by $18.7 and we are now this year at $15.7. It's true that this is a mix because the barrels were different. We didn't have in 2014 the barrels from Talisman. But the other figure, if you want to somehow fix the whole thing, is that as of today, in the P&L we have reduced or we have obtained synergies and efficiencies in OpEx for €195 million and that by the yearend we expect €492 million in the upstream division. Okay?

Sure.

And also you ask about Eagle Ford. Eagle Ford, the efficiency we have obtained, we measure it in approximately $10.9 million in the quarter is what we have obtained as of today. Could this improve? I think I will. We still have the commercialization issues with our partner, Statoil, and probably this figure will improve. If you take it back to the €492 million this year with a total production of 250 million barrels per year it would be around $2 per barrel of reduction. Okay?

Thank you.

And the second question in relation with the tax credit, how much was due to the deal with Statoil. I think that the deal with Statoil didn't help us. But I'll ask my tax people through the IR to answer you. I think that the tax credit we obtained in the past was due to former losses that Talisman had in Norway. And those were cashed in, if I'm not wrong, in 2015. But our IR people will confirm you that, Irene. Okay?

You're welcome.

Thank you, Irene. Next, we have Nitin Sharma from JPMorgan. Please go ahead.

Thanks, Paul. Afternoon, Miguel. Two questions from my side, if I might, please. First one is on operating cash flow. And I think you touched on part of that, but -- so obviously difficult to predict the macro-factors. Assuming a flat operating environment, would it be fair to think that ex working capital, €2.5 billion or EUR2 billion post payments, interest payments and leases can be doubled in 2016? If you can give some flavor on that. And the second one, you mentioned on the last slide that you continue to evaluate portfolio options. Now where does Gas Natural's stake sit in that thinking, strong earnings contribution and dividend inflows versus a possibility to strengthen the balance sheet here? So those would be my two questions. Thanks, Miguel.

Well in relation with the operating cash flows, this quarter -- this semester, sorry, this first half of the year we generated free cash flow of €775 million before dividends and interest. We already have paid the whole interest for the year. Those were 232 million and so this 232 million will help us. In the other hand, we have the working capital, which I think is going to shrink. So it will help us in the second part of the year. The penalty that we received in this semester was 731 million. So if we are able to block that, we'll have some extra 700 million. In relation to the divestments, remember that we have to cash in the pipelines, the propane pipelines that have been signed. By the way, last week we obtained the antitrust authority for the transmission. So probably the transmission to the buyers would be most of it in the third quarter and part of it in the fourth quarter of the year, and that implies another 700, which is more or less the divestments we have had in the first half of the year. So I'm quite positive that really the free cash flow is going to be well above what we have seen in this first half, without considering further divestments. I now turn to the second question, which I will not answer, because we have always mentioned it. GasNat has always been an optionality and we consider that both as a business and financially. And we keep attached to that. We'll keep divesting. We have a strategic plan, which is our goal of 6.2 billion for the five years. And we'll keep going ahead in that direction. But I'm not going to speak about any particular asset. Sorry about that, Nitin.

Thanks for calling in for the questions.

Thank you, Nitin. Our next question comes from Marc Kofler at Jefferies. Please go ahead Marc.

Yes. Hello and afternoon, everyone. Just one remaining question from me, please. It's now been around 12 months since integrating the Talisman asset. And I was just wondering if there were any comments around the decline rate for the Group as a whole now. And if you could just give us some color if there have been any changes from I think what historically you said was a very low decline rate for the whole Group. Thanks.

Yes, I remain in that position. 94% of our production by 2020, if we do not do anything, will come from our existing producing assets. And this is within four and half years from now. So the answer is yes, declining is quite low. I think that there are many reasons for that. A, because we are quite gassy. Second, because the nature of all the North American assets in Talisman being nonconventional really don't give us much declining. And, yes, we have a very low decline as a Group.

Thank you, Marc. Our next question comes from Fernando Lafuente at N+1. Please go ahead Fernando.

Hello, Paul. Hello, Miguel. Just a quick question on the dividend, the million-dollar question. What are your views on how can it be decided and when and your feelings of what can be done? Thank you so much.

[Foreign Language]. A dividend is something that it's on the Board, not on me. But I think that the Board has been quite sensitive, all of them, all of the members. And when the Company needs flexibility, as it happened last -- in the last payment, they delivered. So I think that we are not going to change the dates, so probably would be announcing October/November. And the figure, it's on the Board, not on me. It's going to depend much on how the situation evolves, for sure. But up to now it's improving or at least in the direction we were expected. And we keep thinking that we work for a Company that can be able and sustainable at $40 per barrel. Is that okay, Fernando?

It's great. Thank you, Miguel.

Thank you, Fernando. There's no further questions at this time, so we can bring this second-quarter call to an end.

Thank you for your participation, ladies and gentlemen. That will conclude today's conference call.