Hello, and welcome to the Repsol first quarter 2018 results conference call. Today's conference will be conducted by Mr. Miguel Martínez, CFO. A brief introduction will be given by Mr. Paul Ferneyhough, Head of Investor Relations. I'd now like to hand the call over to Mr. Ferneyhough. Sir, you may begin.
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 first quarter results for 2018. This conference call and associated webcast will be delivered by Miguel Martínez, Repsol's Chief Financial Officer, with members of the executive team joining us 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 call over to Miguel.
Thank you, Paul, and thank you to those online for attending this conference call covering our first quarter results. Today's call, I would like to cover the following principal topics. Firstly, a summary of the key messages and main operational highlights for the quarter. Secondly, the financial results. Finally, an update on the outlook for 2018 ahead of our strategic presentation next month. Starting with the key messages. At the macro level in Q1, the positive impact of the stronger oil prices was partially upsetting our financial results by a weaker U.S. dollar. The upstream division delivered record levels of daily production and another quarter of positive free cash flow. Downstream performance was in line with prior quarters, supported by underlying economic fundamentals and partially offset by planned heavy maintenance in our refining and chemical plants.
At the corporate level, during the quarter, the board of directors formally proposed to increase dividend to around EUR 0.90 per share. Additionally, the board proposed the implementation of a share capital reduction that will offset the dilution associated with our ongoing scrip dividend option. Both proposals are subject to approval at the annual general meeting to be held next week. Operating cash flow in the quarter was impacted by a working capital buildup due to higher stocks in downstream resulting from our maintenance activities, higher sales in upstream due to higher volumes and prices, and increased receivables in Venezuela. Our net debt figure closed at EUR 6.8 billion, impacted by the dividend payment in January and market operations related to our own shares in anticipation of the approval of the share capital reduction.
The closing of the Gas Natural disposal is progressing as planned, with the parties expecting to receive all required approvals before the end of June. Let me move on to the operational highlights of this first quarter. Starting with the upstream, production averaged 727,000 barrels of oil equivalent per day, a record level for the company, 2% higher than in the previous quarter, and a 5% increase year-on-year. First quarter volumes were positively impacted by new barrels coming on stream in our recently start-up projects in Algeria, Trinidad & Tobago, U.K., and Malaysia. Regarding Algeria, where we commenced gas production in December 2017, has contributed around 6,000 net BOEs per day on average during the first quarter. Consistent operations, basically free from interruption at the Sharara field during the quarter, allowed our net production in Libya to reach approximately 38,000 BOEs per day.
The recently acquired Visund field in Norway has contributed around 11,000 net barrels per day since February 1st. Production increases were partially offset by lower volumes in Peru and Russia. Development activity included continued work towards achieving first production during the second quarter at Bunga Pakma, part of the PM3 asset in Malaysia. Exploration activity included the completion of six wells, several of which were initiated in 2017. One well was declared positive, while the remainder were deemed negative. New exploration acreage was obtained in Mexico, Brazil, and Norway during the quarter. Moving to downstream. Starting with refining, the margin indicator remained above our long-term planning assumption at EUR 6.60 in the quarter. Compared to the fourth quarter of 2017, Brazilian middle distillate spreads, together with the strong heavy light crude differential, were partially offset by weaker spreads in gasoline, naphtha, and fuel.
The utilization rates of our distillation and conversion units were impacted by planned heavy maintenance at the Puertollano refinery, including deep conversion units as part of its multi-annual turnaround program. Unit CCS margin was lower than the margin indicator, impacted by the reduced flexibility in our refining system due to the maintenance. The chemical business performed in line with Q4 2017, despite increased prices for naphtha and lower volumes resulting from maintenance activity at Tarragona and Sines. Compared to the previous quarter, the commercial businesses contributed better results in LPG, helped by seasonality in gas and power and marketing. Moving to the financial results. I will summarize the main figures for the first quarter of the year and how they compare with the same period in 2017. First quarter 2018, CCS adjusted net income was €616 million, 46 million higher than in the first quarter of 2017.
EBITDA at CCS stood at €1.8 billion, a 5% increase year-on-year. Upstream adjusted net income was €320 million, an €86 million increase compared to the same period in 2017. Year-on-year variances in upstream were primarily due to the following. Higher volumes and prices had a positive impact on the operating income of €426 million. Higher income tax and higher royalties had a negative impact of €173 million. The depreciation of the U.S. dollar against the euro decreased operating income by €86 million. Higher exploration expenses had a negative impact of €109 million. Depreciation and amortization charges were €60 million lower, mainly due to the application of a new formula for depreciation of productive assets. Income from equity affiliates and non-controlling interests and others explained the remaining differences.
In the downstream division, CCS adjusted net income in the quarter was EUR 425 million, EUR 70 million lower than in the same period of last year. Year-on-year variances in downstream were primarily due to the following. In refining, operating income was EUR 87 million lower, largely due to lower margins. In chemicals, lower prices, along with maintenance activities, had a negative impact on the operating income of EUR 88 million. The commercial businesses, together with trading gas and power, contributed a EUR 116 million higher operating income. The depreciation of the US dollar against the euro had a negative impact of EUR 73 million. Lower taxes impacted positively by EUR 28 million. Finally, equity affiliates and non-controlling interests account for the remaining variance. In corporate and others, adjusted net income improved by EUR 25 million, thanks to lower corporate costs and a better financial result.
This quarter, the result of Gas Natural Fenosa has been classified as discontinued operations, with the adjusted net income of the first quarter 2017 also restated in the comparatives. As in previous quarters, for further detail on Repsol's results, I encourage you to refer to the financial statements and accompanying documents that were released today. Let me now finish with some comments on what we expect for the remainder of 2018. As you know, in June, we will release to the market our updated strategy, together with targets for the company through 2020. Having already delivered all key objectives of our strategic plan during 2018, the company has been working to the guidelines set out by our CEO in last quarterly call.
Our performance in the first few months of the year has kept us on track to deliver on the targets we set for 2018, with no material changes to our guidance. At the operating level, we are expecting average upstream production for the year to remain between 700,000 and 730,000 net BOEs per day, subject to fluctuations in Libya. Our investment program remains back end loaded with a full-year forecast of around EUR 3.4 billion, of which EUR 2.4 billion correspond to the upstream division. In the downstream business, the refining margin indicator has averaged above $7 in April, and we maintain our objective of generating a premium to the indicator on average for the full year. Planned maintenance at the Tarragona refinery will commence in June this year, and once this is complete, we expect no major maintenance activities during the year.
On the financial side, we are forecasting that the working capital build-up from the first quarter will gradually unwind throughout the year, with our industrial businesses returning to normalized level of stock once the maintenance season is finished. The share capital reduction subject to approval during the AGM will be implemented during the second half of the year. The final amount of shares to be amortized will depend on the level of acceptance of July's scrip. Finally, supported by the results achieved in our first quarter, we remain committed to cover in full our dividend payments and scrip buybacks with organic cash flow from 2018 onwards. With that, I will now hand the call back to Paul, who will lead us through a question and answer session. Thank you.
Thank you, Miguel. In case anyone on the call runs into technical problems during the webcast or the conference call, please address any problems to our email address, investorsrelations@repsol.com, and we will contact you immediately to try and resolve it. Before moving on to the Q&A session, I'd like the operator to remind us of the process to ask a question. Please go ahead.
Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, please press star one to ask a question.
Thank you, operator. We'll now move to the Q&A session. Our first question comes from Oswald Clint at Bernstein. Oswald, please go ahead.
Good afternoon. Thank you very much, Paul. Miguel, hi. First question. I'm just looking at the upstream unit margins, and I know you don't report pure OpEx production cost per barrel, but the implied production cost per barrel seems to indicate it may have ticked up a little bit sequentially in the first quarter. I wonder, is that true? If so, what's happening to that particular line, and where might you be starting to see some OpEx cost inflation, please? Secondly, I know you have your strategy day coming up, but just for the gas net proceeds, perhaps if there's any further discussion around allocating those cash proceeds. It seems to be gas and renewables is heating up somewhat with some of your peers increasingly starting to get into both gas, solar, and wind, and also including South America.
I guess the question is, you're still confident on executing the kind of transfer of those proceeds into something in the new energies category. Thank you.
Thanks for the question, Oswald. The objective for the full year at OpEx level, it's a reduction of a 2% per barrel along the year. If you have perceived an increase during this quarter, probably it should be due to the mix or something related. Basically, we are going to be more in line, and we haven't seen any cost inflation yet. The 2% remains as the objective of reduction for the upstream division for the full year. In relation with the proceeds of Gas Natural. Well, I have to say that part of the proceeds would be allocated to a new division. Part probably would be allocated into the downstream division, probably in the chemical sector, looking for niches, and partially perhaps within the upstream division. It's going to depend on the return we are going to obtain.
At the end, we are swapping somehow a dividend for EBITDA operated by us, and this is what I can answer. I don't have any particular amount fixed to any of the three areas, but it's not going to be any multi-billion investment in any of the areas. Is that right, Oswald?
Absolutely. Thank you very much for that clarity.
You're welcome.
Thank you, Oswald. Our next question comes from Biraj Borkhataria at Royal Bank of Canada. Biraj, please go ahead.
Hi, Paul and Miguel. Thanks for taking my questions. I had a few. Firstly, on upstream and DD&A. Could you just talk about the change in policy on the reserve base, and what was the trigger for that? Is that for the whole portfolio, or is that for a selected number of assets? Just a bit of guidance there would be helpful. Secondly, for Tarragona, the maintenance in June, how many days do you expect that to take? Then finally, could we just get an update on the receivables balance in Venezuela? Thanks.
Biraj. In relation with the first one, I have to say that the depreciation method generally used in E&P, it's units of production. A depreciation ratio in which the numerator are the units produced in the period, and the denominator are the units expected to be produced with the existing assets. Experience obtained in the operation of E&P assets, especially in non-conventional, and improvements in our estimation of recoverable reserves, have led us to move from 1P reserves into 2P reserves. Basically, we have obtained the agreement of both the former auditor, Deloitte, and the new auditor, Pricewaterhouse. It reflects better the match between revenues and expenses. That's the reason why we have changed it. It mainly affects non-conventional assets. In relation with the Tarragona maintenance, basically, we have to change the catalyzers in the hydro, and it will take around 26 days.
It will be much lower impact than the one we have had in Puertollano. In relation with Venezuela receivables, basically, we are billing approximately EUR 50 million per month. We have established a rule to accrue for one-third every month. Basically, our revenues were EUR 150, and we have accrued approximately EUR 50 million. This is somehow the ruling that we established in January based on the delay to recover these receivables. For sure, if the situation changes, we'll be adapting that ruling into the new situation. Is that right, Biraj?
That's very helpful. Thank you, Miguel.
Thank you, Biraj. Our next question comes from Irene Himona at Société Générale. Irene, please go ahead.
Thank you very much. Good morning. My first question is on the upstream, please. Miguel, if you can quantify for us Libya's contribution to your first quarter upstream operating and net profit, please. Secondly, working capital, obviously a material increase as you highlighted. What do you expect over the rest of 2018? Final quick question, you disclose some of your downstream plans for Mexico, 200 stations a year. What do you anticipate by way of returns on the investment you mentioned, the EUR 400 million over five years? Thank you.
Thanks, Irene. On Libya, for the full year, at the operating level, we expect something around EUR 500 million. After tax, this will ended up a little above EUR 200, so EUR 217. Within the quarter, the operating income was EUR 184, and the after-tax results were EUR 58 million. In relation for the working capital, I do not expect the figures we have seen in this quarter to continue throughout the year. Think that there has been several factors that have affected it. First, the maintenance. Once you have heavy maintenance, normally, you pile stocks. B, the fourth last days of the quarter were coincidence with Easter. This is also a factor in which generates more working capital. Also, we have paid a dividend in the quarter, and this also affects somehow the cash.
All in, I expect to really turn back to a more modest figure, similar to the one we have by the year-end 2017, other than the price impact. In Mexico, returns on investment, we expect in the long term to obtain around a 15%. 15% is the figure we have in mind. For sure not in 2018. For the full investment, which will take five years, our estimate is around 15%. Is that clear, Irene?
Thank you. Very clear. Thank you very much.
You're welcome.
Thank you, Irene. Our next question comes from Jason Kenney at Santander. Jason, please go ahead.
Thanks very much. Hi, Miguel.
Hey, Jason.
Where do you think net debt will be towards the year-end 2018, in two scenarios? Firstly, if oil stays where it is, and secondly, at your underlying assumptions. Just trying to gauge a sensitivity for net debt this year. The run rate of share buybacks over the next few quarters, if you had a view on that as well, that would be great. Finally, if possible, tax rate. Slightly lower in the first quarter than I was anticipating, effective even with the upstream delivery. Do you have a sense of where effective tax could average out over the year? Thanks.
Thanks, Jason. The net debt at the end of the year will have three major impacts. First, when we close the Gas Natural transaction, which is EUR 3.8 billion. Basically, from the EUR 6.3 billion we ended up last year, if we take the Gas Natural proceeds, does lead us to EUR 2.5 billion. Then we have to consider two other main impacts. The first one is the cash prepayment taxes. That would be around EUR 400 million extra due to the sale of Gas Nat. Then we also have to consider the amount of shares that we will buy back in the second half of the year For the cancellation or the amortization of the shares issued through the dividend of 2018. If we amount, let's say EUR 600 million for the buyback that will amortize shares in 2019, we should ended up around EUR 3.5 billion.
This is the best assumption I can tell you. In relation with the buybacks, the procedure will account as follow. First, we have to obtain the approval of the AGM. Second, we have to wait for the number of shares we issue in the next July for the scrip, then we will ask permit to the Comisión Nacional del Mercado de Valores to amortize those shares when we know exactly the number of shares. What we have done during this quarter is that we have already buy 37 million shares in order to advance the future amortizations. This is more or less how the whole thing of buybacks will work. In relation with the tax rate for the year, I think it's going to be around 40%. If you want to take a figure, at least it's the figure I manage.
In an average year with these prices, we should be around 40% of tax rate. Is that right, Jason?
Yeah. If I just come back slightly on the net debt number, at EUR 3.5 billion, perhaps. There is a risk in, say, two, three years' time, you've got a very flexible balance sheet. I know you are quite conservative about what you might reinvest in specifically for the Gas Natural money that is coming in. I'm just wondering, medium term, should we be thinking higher CapEx in 2019, 2020? I'm conscious you've got the June strategy update, of course, I'm just wondering where you're going to be spending cash in the medium term.
I think that probably within one month, just with June month, we will give more clarity on that question. To me, our run rate normally is around EUR 3.5 billion, EUR 3.7 billion of CapEx. If we are not able to really find investments, whether in upstream, downstream, or in the gas and power new unit, if we don't find opportunities to return the money back to the shareholders through buybacks. The thing is that at least we think that we deserve the credit to use these two years to really analyze what opportunities we have in order to recapture the proceeds we have been obtaining in the past from Gas Natural, with the advantage of converting those dividends in EBITDA operated by us and thinking long-term. I'm sure that Josu Jon will give you more clarity the 6th of June.
That's perfect. Thanks very much, Miguel. I really appreciate your time.
Thank you, Jason.
Thank you, Jason. Our next question comes from Jon Rigby at UBS. Jon, please go ahead.
Thank you. Hi, Miguel. Just a couple of questions. The first is on your reserve changes or the movement to 2P reserves on amortization. Is one other effect in Brazil as well? I'm conscious that other companies have talked in the past about the ongoing recognition of reserves in deep water related to drilling activity, et cetera. I just wondered whether it was deep water as well as unconventional. The second, just to deepen in on the CapEx, is there an expectation or a desire for Repsol to participate in the next couple of bidding rounds in Brazil? If so, does that CapEx guidance include some sort of provision related to an expectation of the kind of level of participation that you're going to be involved at? Thanks.
Thank you, Jon. In relation with the first one, as I mentioned, the most of the impact has been in the non-conventional. It's true that in Brazil we had an impact, which this quarter was EUR 17 million. The reason for that is that the non-proved reserves in Brazil, especially in the southern part of Lapa, has to be considered. The investments we have done there, it's for the whole project. In that sense, Brazil has a minor impact, but EUR 17 million were generated in Brazil. If we talk about the bidding rounds in Brazil, the budget that we have for bonuses in the year are around EUR 100 million, if I'm not wrong. It's on the exploration direction to really analyze whether or not it's a bet they could do or they would prefer something else. For sure, they would be looking at it.
Okay, Jon?
Super. Thank you.
Thank you, Jon. Our next question comes from Peter Low at Redburn. Peter, please go ahead.
Hi. Thanks for taking my question. Just one from me. On your gas price exposure, can you give any color on how your gas sales break down between, say, Henry Hub, NBP in the LNG linkages, and then fixed price contracts?
Yeah, sure, Peter. I will give you the data with gas and with the whole production, okay? Henry Hub have an impact. If you put two columns, in the first one, the percentage on gas, and in the second, for the full production. Henry Hub is 36 and 24. 36 is the percentage of the gas production, and 24 of the whole company production. Fixed price is 26 and 17. The thing that fixed price, most of it's in Southeast Asia, so prices are quite juicy. Brent related is 16 and 11. Other indexes are 22 of our gas production and 15 of the whole production. Within these others, you have references to ammonia in Trinidad and Tobago, to the Spanish electricity pool, and some others. Okay?
Thank you. That's really helpful. I appreciate the detail there.
You are welcome, Peter.
Thank you, Peter. Our next question comes from Alastair Syme at Citigroup. Alastair, please go ahead.
Thanks, Paul. Morning, Miguel. Can I just get a little bit of clarity on what's going on in the production profile? There's some quite big moves year-on-year, in terms of growth in Brazil and the European business, quite big declines in Latin America. Can I just understand the sort of the moving parts here?
Thank you for the question. Biggest variances in the production were, first, Algeria. Second, with 8,500 barrels per day. We have Libya with 9.3. We have Norway with four. In relation with LatAm, I don't see a big variance there. The largest is Trinidad and Tobago, with 5,000 extra BOEs in comparison last year with this year. In Peru, there was a problem with the pipeline, the figures are quite small. The only impact that you may perceive could be due to the PSCs that we have in Bolivia, in Algeria, and Southeast Asia, due to the change in the pricing. Other than that, variations country by country has been really small other than the ones I already mentioned. Thank you.
Just to follow, if we look at the full year, do you think what we're seeing in first quarter is going to be representative of what happens in the full year mix in production?
I would say that we would be happy from anything between 700,000 and 720, taking into account that we cannot put Libya at 100% as we have been in this quarter. Other than that, this will be our estimates for the full year. Okay?
Okay, brilliant. Thank you.
Thank you, Alastair. Our next question comes from Matthew Lofting at J.P. Morgan. Matt, please go ahead.
Thanks, Paul. Morning, Miguel. Thanks for taking the questions. Two, please, if I could. First, just coming back to CapEx, Q1 very light versus the full year run rate. I understand your point in terms of second half of year phasing, but just wondering whether continued capital efficiency benefits or gains are feeding through that ultimately enhance Repsol's CapEx headroom and imply increased scope to underspend or lower guidance again as we roll through 2018. Secondly, if you could just update us on Vietnam Red Emperor and where we are there, if you have any update following the project's recent suspension. Thanks.
Thank you. I think that most of the capital efficiencies were already incorporated. As a guidance, I would say that the EUR 3.4 for the whole company and EUR 2.4-EUR 2.5 for the E&P in both in euros is the color I can provide. Having said so, Josu Jon Imaz always said that the divisions always reduce the estimates by 10%. To me, the figure is EUR 3.4-EUR 3.5. Okay? In relation with Vietnam, we can confirm that we have received notice from PetroVietnam with instruction to suspend temporarily the activities in Ca Rong Do project. We are already in conversation with PetroVietnam and with the Vietnamese authorities in order to be compensated for the impact of the suspension, starting by the more immediate extra cost resulting from that decision. We have found the authorities and PetroVietnam as collaborative to reach a solution which is acceptable to both parties.
On the other hand, the Vietnamese law has specific provisions that clearly established that any cost resulting from suspension of offshore activities by the authority is to be fully compensated. The only update I can bring you is that we are in conversation with the authorities and with PetroVietnam.
Very clear. Thanks, Miguel. Appreciate it.
Thanks, Matt.
Thank you, Matt. Our next question comes from Rob Pulleyn at Morgan Stanley. Rob, please go ahead.
Thank you, Paul. Most of my questions seem to have been answered already, but just one quick one. In terms of the new capital projects, the ACDC plus, I believe you were looking to maybe progress with some of those sooner rather than later. I was just wondering if we could have an update, and maybe it's a bit preemptive in terms of the capital markets day, but is there an update in your thinking about high-grading the upstream portfolio? Something you've talked about in the past. Thank you.
Thanks for the question, Rob. I would say that the main new has been in Alaska, and has been through the ConocoPhillips drilling, which has test between the northern and the southern part of our acreage, and the results has been really positive. I'm fully convinced that the FID for Alaska will be taking next year. Also, Akacias is already in phase one, producing something like 4,000 barrels a day. A small production, but in the phase one. In the Duvernay, probably we will be taking the FID for an area called Ferrier East, in which we have identified as a sweet spot, and probably the FID will be taking in 2019. This is more or less the update that I may tell you that has happened during the quarter. Okay, Rob?
Yeah. Thank you. I'll turn it over.
That was our last question. At this point, I will bring our first quarter conference call to a close. Thank you for your attendance.
Thank you. That will conclude today's conference call. Thank you for your participation. You may now disconnect.