Good afternoon, ladies and gentlemen. Thank you for standing by, and welcome to the Total First Quarter 2019 Results Call. At this time, all participants are in a listen only mode. There will be I must advise you that this conference is being recorded today on Friday 26th April 2019. And I would now like to hand the conference over to your host today, Patrick De La Chevardiere, CFO of Total.
Please go ahead, sir.
Thank you. Patrick De La Chevardiere here. Let's go straight to the results and then to the Q and A. The environment has been volatile starting the year weak, but then gaining strength And in this environment, we reported Q1 2019 adjusted net income of $2,800,000,000 or $1.02 per share debt adjusted cash flow of $6,500,000,000 up 15% year on year and very strong organic free cash flow of $3,200,000,000 up 18% year on year with a pre dividend cash flow breakeven below $25 per barrel. We are in line with our February presentations and on track to grow cash flow over the coming quarters progressively as our major projects ramp up.
Total has been moving at a very rapid pace in recent years, continuing to deliver on production growth, cost reduction, portfolio management and capital discipline. 1 of the highlight marking our progress has been the creation of the new Integrated Gas, Renewable and Power or EGRP segment. Effective this year, the LNG business including the up upstream and midstream operation, is being reported as part of the EGRP segment. So we have provided restated past results and the current results reflect this new format. Also this year, we have revised some of our indicators and we have of course implemented IFRS 16.
The group's production hit a new high of more than 2,950,000 barrels per day in the Q1, an increase of 9% year on year and 2.4% quarter on quarter. In February presentation, we highlight 3 start up costs that will contribute $3,000,000,000 of cash flow in 2019 with Brent at $60 per barrel and all 3, Aegina, Carmo, North and South and Ichthys have started and are ramping up now. Operationally, upstream is on track and performing very well and our main priority is to FID new major projects like Mero 2 in Brazil and Arctic LNG 2 in Russia to lock in low development costs and ensure profitable growth well into the next decade. I would also like to point out that exploration has delivered some good news recently. In our core North Sea area, we made the Glengorm gas condensate discovery, the largest in the area since 2008 on a block that was part of the Maersk acquisition.
And in deep offshore South Africa, we made a significant play opening discovery with the Brule Pada well. For the Redefined E and P segment, 1st quarter adjusted net operating income was 1 $700,000,000 compared to $1,800,000,000 a year ago and $2,000,000,000 in the previous quarter. Brent averaged $63 per barrel in the 1st quarter compared to $69 per barrel in the 4th quarter. Our average liquid price realization was stable quarter to quarter at $59 per barrel, reflecting mainly the rebound in Canadian differentials. Natural gas, however, was down about 10% from previous quarter to $4,500,000 BTU, mainly due to mild weather in the Q1.
And I should point out that exploration expenses increased by about $100,000,000 in the first quarter compared to previous quarter and the same quarter last year. Our confidence in the future has been reinforced by the strong cash flow delivered this quarter despite the lower Brent and gas prices. In the Q1, the Redefined E and P segment generated cash flow before working capital change of $4,200,000,000 a 9% increase compared to the previous quarter. Volume growth from cash accretive new projects more than offset the lower price. Moving to eGRP, this new segment spearheads our ambitions in fast growing integrated gas LNG and low carbon electricity businesses.
Overall, LNG sales were 7,700,000 tonne in the 1st quarter, double compared to 3,800,000 tonne in the Q1 last year and stable compared to 7,900,000 ton in the previous quarter. EGRP adjusted net operating income was $600,000,000 in the Q1 2019, an increase of 23% year on year. IGRP generated $600,000,000 of cash flow before working capital changes in the Q1, a 50% increase compared to the Q1 last year, reflecting mainly the 50% increase in our equity LNG production. Quarter on quarter, EGRP cash flow before working capital changes was stable despite the sharp drop in NBP and LNG spot prices. Total's portfolio of LNG project is unmatched in the industry.
Yamal LNG and Ichthys LNG are ramping up and Cameron LNG Train 1 is set to start in May. We signed the definitive agreement for our entry into Arctic LNG 2 as well as the gas agreement with the state of Papua New Guinea to clear the way for Papua LNG. In North America, we are working with our partners to add 2 additional trains at Cameron as well progressing the ECE project in Baja, Mexico and we further committed to invest in Tellurian's Driftwood LNG project. In addition, we are actively pursuing the expansion of Nigeria LNG with an FID target by the end of this year. By 2020, we expect our LNG business to grow to with a platform to effectively optimize profitability along the entire LNG value chain.
The eGRP segment is active in many growing markets. In the Q1, we announced a 10 year LNG supply agreement with Wang GUI Energy in China that calls for 700,000 ton a year that will source from our global portfolio. On the marketing side, we have merged Total Spring into Direct Energy and the combined entity is now trading as Total Direct Energy. We also announced that our fast battery unit is creating a joint venture with the Chinese group Tianheng to develop and manufacture advanced lithium ion cell for EV, e bike and energy storage solutions or ESS. China is the largest and fastest growing market for EV and lithium ion batteries.
Turning to the downstream, I think most of you already know this story well. We are concentrating our new investment in growth areas, mainly advantaged feedstock, brownfield expansion of petrochemicals in RMC and entries to the new fast growing larger market for M and S. These segments are important to total impairments, consistently generating high returns and providing a countercyclical source of free cash flow. Refining and Chemicals generated $800,000,000 of adjusted net operating income in the 1st quarter compared to $700,000,000 a year ago and $900,000,000 in the previous quarter in part due to margin volatility. For refining, we changed the reference indicator to the average margin on variable cost achieved by our own European refineries and this was $33 per tonne in the 1st quarter compared to $30 per tonne a year ago and $41 per tonne in the 4th quarter.
Petrochemical Margins in Europe, while still relatively strong, have generally been running below their 2018 levels. Marketing generated $343,000,000 of adjusted net operating income in the 1st quarter, stable compared to the 1st and Q4 of last year. The combined downstream segment R and C plus M and S generated operating cash flow before working capital changes of $1,700,000,000 in the first quarter, in line with the annual $6,500,000,000 to $7,000,000,000 contribution we have been delivering in recent years. In terms of profitability, the Downstream continued to be remarkably strong with Roache of 24% for the 2 segments over the past 12 months. At the corporate level, organic free cash flow was $3,200,000,000 in the first quarter.
The pre dividend organic breakeven is below $25 per barrel, including net acquisition of 0 point $3,000,000,000 capital investment was $3,100,000,000 in the $16,000,000,000 In terms of profitability, the group return on equity was 12% for the 12 months ended March 31, 2019, stable compared to 12% for the year 2018. Gearing at the end of the Q1 remained below 20%, despite including the impact of applying the new IFRS 16 standard for leases, which increased the net debt to capital ratio by more than 3%. A strategic priority for the group is to maintain a strong balance sheet with gearing below 20% and we are committed to this objective even under the new IFRS rules. We are also committed to increasing returns to shareholders and we are on track with the 2018 2020 framework that we presented in February. We increased the 1st interim dividend for 2019 by 3.1% in euros and we are in line with the target to increase the dividend by 10% over the 20 eighteen-twenty 20 period.
We have bought back the scrip share issue since 2018 and we will eliminate the scrip dividend as of June. Last year, we set a target to buy back $1,000,000,000 of stocks in a $60 per barrel Brent environment and we bought back $1,500,000,000 This year, we have set a target at $1,500,000,000 again based on a $60 per barrel environment and in the Q1 we bought back $350,000,000 of stocks. Globally, in dollars, we returned 38% of operating cash flow before working capital to shareholders in the Q1. We are continuing to grow the company, reduce the breakeven and manage the portfolio, free cash flow is increasing, particularly in the current environment and this allow us to deliver on our objective of strengthening the balance sheet and increasing returns to shareholders. And now let's go to the Q and A.
Thank you, ladies and gentlemen. We will now begin the question and answer session. And your first question comes from the line of Alastair Syme of Citi. Please go ahead. Your line is open.
Thank you. Patrick, two questions. You set these cash flow targets for 2019 back in February. I just wonder if you can quantify the impact that weakest spot gas prices might have had on this quarter, both in terms of the conventional business and also the IG business? I'm just trying to figure out that if gas prices remain weak through the course of this year, is that going to have a material impact on your guidance?
And I'll give you my second question now. I guess P1 made some comments on the 4th quarter results around U. S. Shale that I think have been interpreted in different forms in the market. I just wonder given all the activity in the U.
S. In the last couple of weeks, whether you can maybe set the record straight around Total's view on U. S. Acquisitions? Thank you.
Thank you, Alistair. I'm glad to see that you definitely recover from our trip to Moscow.
That was a long time ago.
Question about CFFO target. We don't change the guidance. It is true that currently spot prices are affected by a mild winter. And we see gas price going down on Europe and in Asia, including on top of that, Henry Hub losing $1 per 1,000,000 BTU. And we expect short term pressure on gas price, not only because of that, but also because of supply.
I'd like to remind you that most of our equity LNG is sold long term. There is one exception this quarter about Yamal because Yamal started up 1 year in advance and long term contracts are not yet active. So Yamal had to sell its gas on spot market, mainly in Europe, where the gas price is weak at the moment. We expect ENRIE to remain below $3 In Europe, on the other hand, gas demand for power gen is incentivized by low gas price and by higher carbon price penalizing coal against gas. In Asia, we still see China increasing import on a year on year.
And we see new importers like Pakistan and Bangladesh adding sizable volume. So all in all, I would say that demand is very strong. Last year, demand increased by 10%, 11%. Actually, if you have a look to our eGRP result this Q1, the cash flow from ops from this segment was about 600,000,000 in comparison to EUR 400,000,000 where so an increase of 50% in line with the increase of the production. So the CFFO target given in February, I don't think we will change them now.
It is not yet the moment. Of course, a weak gas price will have an impact, but let's wait for at least 2 quarters to see how much it will impact the result. The second question and it is not actually a surprise about M and A. And I am going to make it clear and we discussed that with Patrick Pouillane and myself and the Executive Committee. We are not interested in being shale asset in the U.
S. Is it clear, Alastair? I think so. So can you please repeat it to your friend, we are not interested. Of course, there are other assets that we can be interested in, for instance, transfer of rights in Brazil, things like this, But we are not interested in shale in the U.
S.
Very clear. Thank you. Hey, Patrick, could I just draw you back on the first question on the as you think year on year, is there a way of trying to help us quantify the impact of weaker spot prices on the overall Upstream business?
Sorry, I can't give you the numbers. I don't have the numbers in my dossier. Wait for July and we will have a better understanding of the actual effect after 2 quarter.
Your next question comes from the line of Oswald Clint of Bernstein. Please go ahead. Your line is open.
Patrick, thank you. Yes, I'd also like to ask about the Integrated Gas, Renewable and Power business. Certainly, with the new return on capital employed numbers, you've broken out for that division, the 7.4% that it's done over the last 12 months. I think that fits in the 7% to 9% range that you kind of indicated back last September at around $60 which is what we've had in that time period. So I just want to get a sense from you what has to happen to get that up closer to the top end of that 7% to 9% ROACE target, please?
That's my first question. And then secondly, I wanted to ask about marketing. You said the marketing earnings were generally quite stable. I think optically, of course, they're still down 7% year over year. I also remember Momar talking about the retail expansion initiatives adding probably quite easily $100,000,000 per year.
So my question is, I don't really see that coming through here this quarter. Is that part of the strategy working? Is the retail expansion program really starting to deliver the earnings? Thank you.
Thank you, Oswald. The first question about eGRP. First, there is the effect of the start up of project at the moment. We just started Ichthys. So let's add Ichthys at full capacity with it upstream and then we will have the full benefit of Ichthys in eGRP.
That's the first comment. And this is a very profitable upstream part in the LNG business, the upstream of Ichthys. 2nd, there will be more low carbon electricity, I think so, with the run of some CCGT that we bought recently. And having as an objective a double digit ROACE, I can't say I am 100% confident, but the range 7% to 9%, I am confident. We are in the low side of this range at the moment because we just started some operation.
About M and S, M and S, the result is quite stable. The net operating income is quite stable from quarter to another at around 350 $1,000,000 per quarter. Then we see the adjusted net operating income in 20 18 was the result of this quarter in 2018 was due to the sale of TotalErg that we lose. We don't have any more operation in Italy, So we don't have the benefits of TotalErg marketing under the Total brand anymore. I think those are the main effect.
That's very clear. Thank you. Thank you.
Thank you. And your next question comes from the line of Biraj Borkhataria of RBC. Please go ahead. Your line is open.
Hi, thanks for taking my questions. I had couple, please. The first one is, could you just update us on the next steps for the LNG product in PNG and how you expect to progress towards FID and the rough timings? And the second one is just could you provide an update on your activities in Argentina and the Vaca Muerta? That would be helpful.
Thank you.
Let's start on Argentina because it is quite simple. We recently have signed an agreement for tax purposes in Argentina where we pay some tax in advance and we're permitted to upgrade our DD and A. So in Argentina, the overall financial situation is difficult. We are quite happy technically with what we are doing on the Vaca Muerta. We are strongly positioned.
We have about 300,000 or more than that 300,000 net acres in dry gas, wet gas and oil windows. It's a low cost and conventional. The question mark is, are we ready to put a lot of fresh money in the country at the moment? That is the question. 2nd question about Papua New Guinea.
Total has 40% before government back in and 31% after. We have signed an agreement, Exxon and Oil Search and Total, what is called the gas agreement with the state of Papua New Guinea defining the fiscal framework of the Papua LNG project. This is a very important milestone and this allow us to enter into the FEED phase that will lead to FID in 2020. I remind you that the project consists of 2 trains of 2,700,000 tonne per year and we unlock about 1,000,000,000 barrels of reserve. Thank you.
And your next question comes from the line of Thomas Adolff of Credit Suisse.
Good afternoon. Just going back to Alastair's question on gas prices and your exposure to spot. If we say the broader market is roughly 75%, 80% contracted medium- or long term and the rest on a spot or short term basis. Perhaps you can comment whether your portfolio is similarly positioned or whether you have less spot exposure considering the outage on the Yamal LNG? And secondly, just staying with LNG, your guidance is for 40,000,000 tonnes by 2020, both equity and third party gas.
You've got a very good pre FID hopper. And I wonder what your base case is for 2025 or 2030? Thank you. Thank you, Thomas. First, about gas price.
As I said to Alastair, basically our equity gas is sold long term. Some portion of it is spot like Yamal at the moment, because the long term contracts are not yet active, but basically it's long term. Then you have and this is roughly 50% of what we sell on the market. The next 50% is contracted volumes that are sold either through formulas linked to Brent or Henriette or either sold on the market on a spot basis. I would say that a vast majority we try to have the vast majority of our contracted volumes, equity or not, committed to a long term buyer.
There is a remaining spot basis volume on the in our portfolio that we sell and we would and we are developing a network of regas terminal to have outlet for this gas and we have enough. For instance, we have a large base in Europe at the moment. We have projects in Africa, in Cameron, for instance, that will help us to sell our gas on a spot basis, taking advantage of the arbitrage, which may happen by time to time in different locations. But I think that more important for us is that even if today spot prices are weak, which is the reality, This does not jeopardize our long term view. There is no other supply that we see on the market by 2024.
There is maybe another supply today. Maybe, I said, but we don't foresee any more oversupply by 2024. Demand is growing currently at the rate of more than 10% a year. And we are quite confident that our strategy to increase our exposure to LNG is the right one. So next question was about what is the guidance beyond 2020 for LNG.
As you notice, we set a target of 40,000,000 ton per year by 2020. The equity production by 2025, the equity production by 2025 will be around 30,000,000,000 ton per annum. And this is representing a growth of 50% basically. Trading is half of the equity production today, so this may be helping you to figure out what could be the guidance by 2025, having in mind this equity production by 2025 of 30,000,000 ton per year.
Perfect. Thank you very much.
Thank you. And your next questions come from the line of John Rigby of UBS. Please go ahead. Your line is open.
Thank you. Hi, Patrick. Two questions. The first is on Asian gas, which has seen a big pickup in production levels since the start of last year. And obviously, some of that latterly has been Ichthys.
I just wondered a couple of things. One is, where are we with Ichthys? Are we still just with running with one train? The second question is, is it all related to that is, is GLNG seeing some better performance in terms of gas production in the last sort of 3 or 4 quarters? Just trying to get an idea about the trajectory of production there.
And the second, just sticking on the gas theme and the LNG theme is, I was struck by your investment into the Driftwood because you already had exports, I believe, out of Sabine and obviously with the ONG assets as well. So could you just sort of elaborate or give a bit more color around the strategy around how you allocate investment dollars to U. S. Export. I would have thought, to my mind anyway, perhaps an expansion of your existing ENGIE positions might have been more economic, but I'd just be interested to hear your perspective.
Thanks.
Thank you, John. Asian Gas, currently 2 trains started up at Ichthys in October and in November actually. The ramp up is ongoing. The production currently in March was about 300,000 barrels per day equivalent. I remind you that those two trains are selling their production on as we are this is a Japan Inc.
Project. I'd like to remind you also that we as a partner, we are not so happy with the cost increase we were facing end of last year and that we reduced our stake by 4%. We divested 4% and that currently our remaining stake is 26%. Also keep in mind on Ichthys that thanks to the upstream where it's producing about 100,000 barrels per day at full capacity, we are making a lot of cash in this project. Then you have another question on GLNG.
Honestly, I don't know how I don't have the answer. I ask Mike to return to you because I don't have the answer for the LNG. Sorry for that. The outlook for the Far East LNG production, I see the blue sky policy from China being a big driver and able to be the market where all Far East well positioned low cost production can go. On top of that, I don't know if you have been to China recently, but discussing with those people, the blue sky policy is a real policy.
They want to clean their city. And that's part of the appropriation of the politicians to be nice with their people.
Driftwood,
You know that as an equity partner in Tellurian Terminal, we enjoy offtake at good condition at a lower price at the nominal offtaker. This is why we are interested in offtaking our stake of the production of the Driftwood asset. And on top of that, the capital we allocate to this project is not a lot of dollar. It's about $200,000,000 I think, if I will remember. Okay.
Perfect. Thank you.
Sir. Thank you. And your next question comes from the line of Lydia Reinsworth of Barclays. Please go ahead.
Thank you and good afternoon. Two questions, if I could. The first one, just on the downstream on the refining environment and just what you're seeing at the moment and whether you're really seeing any impact to the IMO side as yet or how you think that will play out? And then the second one was around what you're looking at in terms of costs and CapEx. Are you seeing any sort of either inflation in the CapEx side or on the cost side?
Is that proceeding according to what you expected at the Capital Markets Day? Thank you.
Our trading people on IMO 2020 started to see an effect on the market, started to see. Actually, on the prices of light oil, we I haven't seen in the Q1 any impact of the IMO 2020. It may be too early. It may be a matter of a quarter or 2. On the cost side for inflation, the question is, has cost deflation bottom out?
I don't think so. Outside of the U. S, we are not in the U. S. Onshore, I remind you, and we are not willing to go, if I may repeat it.
Outside of that, we don't see inflation coming back currently on the market.
Thank you. And your next question comes from the line of Irene Himona of Societe Generale. Please go ahead.
Thank you. Good afternoon, Patrick. My questions are both on cash flow items. Firstly, if we look at DD and A in the quarter, leaving out asset impairments, it appears that underlying DD and A jumped about 10% sequentially. Obviously, there is a lot more production.
I just wonder if you can give us some full year guidance here. Should we expect the Q1 level to sort of to remain for the rest of the year? And then secondly, on working capital, I realize you look at free cash flow excluding this, but there was a substantial increase in Q1. Oil prices are even higher now. You told us in the past, I believe, that you have a sort of committee watching this or managing it.
I wonder again if there is any guidance you can give us for the full year in terms of working capital, please. Thank you.
Your first question on DZ and A, this is true that there is an increase in Q1 2019 of about 0 point $3 per BOE. This is due to the startup of cash accretive project like Aegina, Campbell and Ichthys. As we are expecting production to continue and grow, I see that I can expect DD and A to continue and increase following the production increase, startup after startup. The working cap, honestly, I'm not very happy anyway because we were in a $60 environment Q1 this year. 2 elements in that.
We will try and control the working capital once again in the second quarter, but there is an effect of the oil price, which is still rising, which has an effect on the inventories and it will have an effect on the working cap. So I can't say that I am not happy to see the oil price at $70 I am happy with that, but this will have an effect in my view on the working cap of the 2nd quarter.
Thank you.
And your next question comes from the line of Christopher Copeland of Bank of America. Please go ahead.
Patrick, just wonder whether you could give us a little more detail on the impact from IFRS 16. Is that another reason why D and A sequentially has increased? Also, any color you can give us on how the full year guidance you gave us in February is broken down by quarter? Is this should we divide that by 4? Can you give us some sort of insight now that you have the Q1 results in front of you, how much of the net income and more importantly, net cost of debt as well as CFFO items have moved because of the IFRS alone?
And second question, and that's really just more looking for confirmation. Your €15,000,000,000 to €16,000,000,000 full year CapEx guidance includes things like payments for Arctic 2. Please can you confirm and maybe give us a little bit of an insight how much now that the deal is closed, how much cash outflow you are expecting in 2019 from R3 2? Thank you.
So IFRS 16, a very interesting topic. This has an effect of 3% on gearing. This will remain stable. The impact on capital employed is between $5,000,000,000 and 6 $1,000,000,000 Actually, I think it is $5,700,000,000 in the first quarter. It has an effect of about $1,000,000,000 per year on our debt adjusted cash flow.
So per quarter, dollars 200,000,000 to $250,000,000 On the net income, it has no effect. And those guidelines which were given in February remain valid. The CapEx guidance of $15,000,000,000 to $16,000,000,000 are including the Arctic LNG 2 payment, the EUR 600,000,000 that we have paid already. And that's it. I mean, in 2019, we will pay $600,000,000 for Arctic LNG2.
And it's included in our $15,000,000,000 $16,000,000,000 guidance. Okay.
Thank you, Patrick. Can I just ask one follow-up on Arctic 2? You've got a CAGR in terms of your top line out there for 2022. Would Arctic 2 be additive to that CAGR, please?
It's included.
It's included. Okay. Thank you.
Thank you. And your next question comes from the line of Lucas Hermann of Deutsche Bank. Please go ahead.
Yes. Patrick, good afternoon. I'm not sure if I should be saying thank you
as well for all
the help over the years because I'm not aware as to whether this is your last conference call or not, but whatever. Many thanks. And now the irritating part.
I wanted to
push you a little bit more on Lydia's question around costs, not least on LNG, given the level of activity that's starting to build in the industry and the number of you that are trying to push projects into what seems like a gap that's going to be filled very quickly. So question 1 was really just to check and go back on Lydia's question of whether you're seeing anything happening and also make an observation on Cameron, the other project that is due to start up this year? And thirdly, very simply, the guidance you give on cash flow per $10 move, how does that split, if at all, between Upstream and EGRP?
Okay. Thank you for your word, Lucas, but this is not my last call. My last call is in July. On costs, honestly, when I said to Lydia that I don't see we don't see any cost inflation in our main businesses, which is deep offshore, conventional onshore, offshore and LNG. This is based on our thinking both of what we see actually on the market.
I remind you that Chinese yard are currently competing with Japanese, Singaporean and Korean yard. On top of that, now Russia is building its own capacity to build LNG plant. So we see a strongest competition, a large capacity available, which lead us to think that we are not yet at the time where we will see prices going up. Thank you for the question on Temparossa because honestly, as you know, technically, we are ready. Italy has always been a difficult country for us.
We are still waiting for an authorization from the administration. Shall I say it is a mess? No, not exactly, but we are not happy.
You can't quite talk, any Patrick?
Obviously, in May. Okay. Can you repeat your question about the split between the E and E?
Yes. The guidance on sorry, the guidance on sensitivity, dollars 10 move is $3,200,000,000 of cash flow or $2,780,000,000 I can't remember quite offhand on EBIT. Given you've split out the LNG activities or a number of the LNG activities, which have a sensitivity to the oil price, How does that cash impact split by division or profit impact as well split by division? Is that clear?
About I would say that in our sensitivity, about no, I don't want to give you any figure. I'm going to make a mistake. So no, I don't have the answer. But I understand your question. Ask it again in July, and for sure, I will answer.
Okay. Well, you got to forgive me getting my numbers very wrong by then, which is pretty frequent as Michael will testify. Patrick, thank you.
Thank you. And your last question comes from the line of Jason Gabelman of Cowen. Please go ahead.
Yes. Hey, thanks for taking the question. I just wanted to touch on share buybacks. I know in the press release you said in a $60 oil price you would buy back $1,500,000,000 this year. Clearly oil prices are well above that.
So just looking for updated thoughts around what level you think share buybacks could come in at if oil prices stay at this level or if Brent persists above $70 a barrel for the rest of the year? Thanks.
Okay. 1st quarter last year, sorry, we gave a guidance of $1,000,000,000 at $60 and we actually buy back $1,500,000,000 because we were at around $70,000,000 $71 if I will remember dollar per barrel. We are currently at the moment being at the pace of $1,500,000,000 a year. But what we have done in the first last year is an idea of what can be done. But it's very premature to believe that the oil price will remain at $70 for the full year.
Honestly, I have no idea. It was $60 1st quarter. We are temporarily maybe at 70 at the moment. So I don't like to make forecast on oil prices and taking the conclusion of what can be a very wrong assumption. So I'm sorry, at the moment, we are on a $1,500,000,000 program at $60 Last year, we gave the guidance of $1,000,000,000 and we did $1,500,000,000 Then up to you to dream a little bit.
Got it. Thanks for the time.
Thank you. That was the Q1 result of which are another example of total ability to deliver on clearly articulated strategy. As you see, we are growing our cash flow effectively, investing in growing businesses and using free cash flow to increase return to our shareholders and bye bye and see you in July.
Thank you, ladies and gentlemen. That does conclude your conference for today. Thank you