And welcome to the Repsol First Quarter 2018 Results Conference Call. Today's conference will be conducted by Mr. Miguel Martinez, CFO. A brief introduction will be given by Mr. Paul Furnihew, Head of Investor Relations.
I'd now like to hand the call over to Mr. Furnihew. Sir, you may begin.
Thank you, operator. Good afternoon. This is Paul Fernejo, 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 Q1 results for 2018. This conference call and associated webcast will be delivered by Miguel Martinez, 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 Q1 results. Today's call, I would like to cover the following principal topics. Firstly, I summarize summary of the key messages and made operational highlights for the quarter. Secondly, the financial results.
And 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 stronger oil prices was partially offsetting our financial results by a weaker U. S. Dollar. The Absinthe division delivered record levels of daily production another quarter of positive free cash flow.
Downstream performance was in line with prior quarters, supported by underlying economic fundamentals and partially offset by planet 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 $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 €6,800,000,000 impacted by the dividend payment in January and market operations related to our own shares in anticipation of the approval the share capital reduction. Finally, the closing of the Gasnab disposal is progressing as planned with the parties expecting to receive all required approvals before the end of June. Now let me move on to the operational highlights of this first quarter. Starting with the Apsum, 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. 1st quarter volumes positively impacted by new barrels coming on stream in our recently start up projects in Algeria, Trinidad and Tobago, UK and Malaysia.
Regarding Algeria, where we commenced gas production in December 2017 has contributed around 6 1,000 net BOEs per day on average during the Q1. Consistent operations basically free from interruption at the Sahara field during the quarter allowed our net production in Libya to reach approximately 38,000 BOEs per day. Also, the recently acquired Bisonfield in Norway has contributed around 11,000 net barrels per day since February 1. Production volumes. Production increases were partially offset by lower volumes in Peru and Russia.
Development activity included continued work towards achieving first production during the Q2 at Bungapagma, part of the PM3 asset in Malaysia. Exploration activity included the completion of 6 well, several of which were initiated in 2017. 1 well was declared positive, while the remainder were deemed negative. New exploration acreage was obtained in Mexico, Brazil and Norway during the quarter. Moving now to downstream, starting with refining, the margin indicator remained above our long term planning assumption at $6.60 in the quarter.
Compared to the Q4 of 2017, Brazilian middle distillate spreads together with a 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 Puertoiano 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 4Q 2017 despite increased prices for naphtha and lower volumes resulting from maintenance activity at Tarragona and Sines. Finally, compared to the previous quarter, the commercial businesses contributed better results in LPG helped by seasonality in Gas and Power and Marketing.
Moving on now to the financial results. I will summarize the main figures for the Q1 of the year and how they compare with the same period in 2017. 1st quarter 2018 CCS adjusted net income was €66,000,000, 46,000,000 higher than in the Q1 of 2017. EBITDA at CCS stood at €1,800,000,000 a 5% increase year on year. Upstream adjusted net income was €320,000,000 and €86,000,000 increase compared to the same period in 2017.
Year on year variances in Afzim were primarily due to the following: higher volumes and prices had a positive impact on the operating income of EUR 426,000,000 Higher income tax and higher royalties had a negative impact of EUR173,000,000 The depreciation of the dollar against the euro decreased operating income by EUR 86,000,000 Higher exploration expenses had a negative impact of €109,000,000 Depreciation and amortization charges were €60,000,000 lower mainly due to the application of a new formula for depreciation of productive assets. Finally, income from equity affiliates and non controlling interest and others explained the remaining differences. In the Downstream division, CCS adjusted net income in the quarter was €425,000,000 €17,000,000 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 €87,000,000 lower, largely due to lower margins.
In chemicals, lower prices along with maintenance activities had a negative impact on the operating income of €88,000,000 The commercial businesses together with trading gas and power contributed €116,000,000 higher operating income. The depreciation of the dollar against the euro had a negative impact of €73,000,000 Lower taxes impacted positively by €28,000,000 Finally, equity affiliates and non controlling interest account for the remaining variance. In corporate and others, adjusted net income improved by €25,000,000 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 Q1 2017 also restates in the comparatives. As in previous quarters, for further 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 update 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 1st 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 7,000,730 1,000 net BOEs per day, subject to fluctuations in Libya.
Our investment program remains back end load with a full year forecast of around €3,400,000,000 of which €2,400,000,000 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 buildup from the Q1 will gradually and win 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 script. Finally, and supported by the results achieved in our Q1, we remain committed to cover in full our dividend payments and script 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 e mail address investorsrelationsrebsol.com and we will contact you immediately to try and resolve it. Before moving on to the Q and A session, I'd like the operator to remind us of the process to ask a question. Please go ahead.
Okay. Thank
Thank you, operator. We'll now move to the Q and A session. Our first question comes from Oswald Clint at Bernstein. Oswald, please go ahead.
Yes. Good afternoon. Thank you very much, Paul. Miguel, hi. First question, I'm just looking at the upstream kind of unit margins, and I know you don't report pure 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 Q1.
I wonder, is that true? And if so, what's happening to that particular line? And where might you be starting to see some OpEx cost inflation, please? And then secondly, I mean, 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. So 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. I mean, the objective for the full year at OpEx level, it's a reduction of a 2% per barrel along the year. So if you have perceived an increase during this quarter, probably should be due to the mix or something related. But basically, we are going to be more in line and we haven't seen any cost inflation yet. So the 2% remains as the objective of reduction for the Absa division for the full year.
In relation with the proceeds of Gas Naturale, well, I have to say that part of the proceeds would be allocated to 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 is 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 particularly amount fixed to any of the three areas, but it's not going to be any multibillion 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 Bakhatarya 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 and 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? And just a bit of guidance, that would be helpful. Secondly, for Tarragona, the maintenance in June, how many days do you expect that to take? And then finally, could we just get an update on the receivables balance in Venezuela? Thanks.
Birak, in relation with the first one, I have to say that the depreciation method generally used in E and 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 and P asset, 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 reached have obtained the agreement of both the former auditor, Deloitte, and the new auditor, Pricewaterhouse, because it reflects better the match between revenues and expenses. And 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. So it will be much lower impact than the one we have had in Puerto Liano. And in relation with Venezuela receivables, basically we are billing approximately $50,000,000 per month.
And we have established a rule to accrue for 1 third every month. So basically, we have our revenues were $150 and we have accrued approximately $50,000,000 This is somehow the ruling that we established in January based on the delay to recover these receivables. And 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 Societe Generale. 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 Q1 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? And final quick question, you disclosed 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 €400,000,000 over 5 years? Thank you.
Thanks, Irene. Well, on Libya for the full year at the operating level, we expect something figure around €500,000,000 And after tax, this will end up a little above €200,000,000 so €217,000,000 And within the quarter, the operating income was €184,000,000 and the after tax results were EUR 58,000,000 In relation for the working capital, I do not expect the figures we have seen in this quarter to continue throughout the year, saying that there has been several factors that have affected it. First, the maintenance. Once you have heavy maintenance, normally you pile stocks. B, the 4th last days of the quarter were coincidence with Eastern And 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. So 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. And in Mexico, returns on investment, we expect in the long term to obtain around a 15%, 1 5% is the figure we have in mind, For sure not in 2018, but for the full investment, which will take 5 years, our estimate is around 15%. Is that okay? Very clear.
Thank you. Very clear.
Thank you very much.
Thank you, Irene. Our next question comes from Jason Kenney at Santander. Jason, please go ahead.
Towards the year end 2018 in 2 scenarios: firstly, if oil stays where it is and secondly, your underlying assumptions. I'm just trying to gauge sensitivity for net debt this year. And the run rate of share buybacks over the next few quarters, if you had a view on that as well, that would be great. And finally, if possible, tax rate slightly lower in the Q1 than I was anticipating, effective even with the upstream delivery. Do you have a sense of where taxes, effective tax could average out over the year?
Thanks.
Thanks, Jason. Well, the net debt at the end of the year will have 3 major impacts. 1st, when we close the gas natural transaction, which is €3,800,000,000 So basically from the €6,300,000,000 we ended up last year, if we take the gas natural proceeds, it does lead us to €2,500,000,000 dollars And then we have to consider 2 main 2 other main impacts. The first one is the cash prepayment taxes that would be around 400 extra million due to the sale of Gasnats. And 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, €600,000,000 for the buyback that will amortize shares in 2019, we should ended up around $3,500,000,000 This is the best assumption I can tell you. In relation with the buybacks, the procedure will account as follows. First, we have to obtain the approval of the AGM. 2nd, we have to wait for the number of shares we issue in the next July for the scrip. And then we will ask permit to the commission Nacional Mercado Velores to amortize those shares, one we know exactly the number of shares.
What we have done during this quarter is that we have already buy 37,000,000 shares in order to advance the future amortizations. So 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, this is the figure I manage. In an average year with these prices, we should be around 40% of tax rate. Is that right, Jason?
Yes. If I just come back slightly on the net debt number, at $3,500,000,000 perhaps. I mean, there is a risk in, say, 2, 3 years' time. You've got a very flexible balance sheet. And I know you are quite conservative about what you might reinvest in specifically for the gas natural money that is coming in.
But I'm just wondering medium term, is this should we be thinking higher CapEx in 2019, 2020? I'm conscious you've got the June strategy update, of course. But I'm just wondering where you're going to be spending cash in the medium term?
I think that probably within 1 month, just for joining month, we'll give more clarity on that question. But to me, our run rate normally is around €3,500,000,000 €3,700,000,000 of CapEx. And if the question I mean, if we are not able to really find investments whether in upstream, downstream or in the gas and power new units, we will not have doubt to if we don't found 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 2 years to really analyze what opportunities we have in order to recapture the proceeds we have been obtaining in the past from NAS Natural. With the advantage of converting those dividends in EBITDA operated by us and thinking long term.
But I'm sure that Josu Jon will give you more clarity the 6th 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. John, 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 deepwater related to drilling activity, etcetera. So I just wondered whether it was deepwater as well as unconventionals. And the second just to just deepen on the CapEx. Is there an expectation or a desire for Repsol to participate in the next couple of bidding rounds in Brazil? And 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. [SPEAKER JOSE RAFAEL FERNANDEZ:]
Thank you, John. Well, in relation with the first one, as I mentioned, the most of the impact has been in the non conventional. But it's true that in But it's true that in Brazil we had an impact, which this quarter was €17,000,000 And the reason for that is that the non proved reserves in Brazil, especially in the southern part of Latva has to be considered. I mean, the investments we have done there, it's for the whole project. And in that sense, Brazil has a minor impact, but €17,000,000 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 €100,000,000 if I'm not wrong. And it's on the exploration direction to really analyze whether or not it's a bit they could do or they would prefer something else. But for sure, they would be looking at it. Okay, John?
Super. Thank you.
Thank you, John. Our next question comes from Peter Low at Redburn. Peter, please go ahead.
Hi. Thanks for taking my question. Just one for me. On your gas price exposure, can you give any color on how your gas sales breakdown between say Henry Hub, MVP and LNG linkages and then fixed price contracts?
Yes, sure, Peter. Basically, our and I'm talking only about I will give you the data with gas and with the whole production, okay? And we have an impact. If you put 2 columns, in the first one, the percentage on gas and in the second for the full production, Henri have is 3624, 36 for the is the percentage of the gas production and 24 of the whole company production. Fixed price is 26.17, but think that fixed price most of it, it's in Southeast Asia.
So prices are quite juicy. Brent related is 16 and 11. And other indexes are 22 of our gas production and 15 of the whole production. Within these others, you have referenced says to ammonia, Enfinita and Tobago to the Spanish electricity pool and some others. Okay?
Thank you. That was 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. Good morning, Miguel. Can I just look at the get a little bit clarity on what's going on in the production profile because there's some quite big moves year on year in terms of growth in Brazil and Latin and the European business, but quite big declines in Latin America? Can I just understand the sort of the moving parts here?
Thank you for the question. I mean, biggest variances in the production were first Algeria, second it's with 8,500,000 barrels per day. We have Libya with 9.3. We have Norway with 4. And in relation with Latin, I don't see a big variance there.
I mean, 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, but the figures are quite small. And 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. But other than that, variations country by country has been really small other than the ones I already mentioned. Thank you.
And just a follow-up, if we look at the full year, do you think what we're seeing in Q1 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 700,720 taking into account that we cannot put levy at 100% as we have been in this quarter. But 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 Matt Lofting at JPMorgan. Matt, please go ahead.
Thanks, Paul. Good morning, Miguel. Thanks for taking the questions. 2, please, if I could. First, just coming back to CapEx.
I mean, Q1 very light versus the full year run rate. I mean, 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? And then 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.
[SPEAKER JOSE RAFAEL FERNANDEZ:] Thank you. I think that the cap most of the capital efficiencies were already incorporated. So as a guidance, I would say that the 3.4 for the whole company and 2.4, 2.5 for the upstream both in euros is the color I can provide. Having said so, Yoshu Joni, Mathol always said that the divisions always reduce the estimates by 10%. But to me the figure is 3.4%, 3.5%, okay?
And in relation with Vietnam, we can confirm that we have received notice from Pietro Vietnam with instructions to suspend temporarily the activities in Carondeau project. We are already in conversation with Pietro Vietnam and with the Vietnamese authorities in order to be compensated for the impact of the suspension, standing by the more immediate extra cost resulting from that decision. We have found the authorities and Petrobran as collaborative to reach a solution, which is acceptable to both parties. On the other hand, the Vietnamese law has specific provisions that clearly establish that any cost resulting from suspension of offshore activities by the authority is to be fully compensated. So 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 Konoco drilling, which has test between the northern and the southern part of our acreage and the results has been really positive. So I'm fully convinced that the FID for Alaska will be taking next year. Also, Akathias is already in Phase 1, producing something like 4,000 barrels a day, so a small production, but in the Phase 1. And in the Duvernay, well, 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.
And this is more or less the update that I may tell you during the that has happened during the quarter. Okay, Rob? Thank you. I'll turn it over.
That was our last question. And at this point, I will bring our Q1 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.