TotalEnergies SE (TTE) 2017 Q3 法說會逐字稿

Good day, and welcome to the Total Third Quarter 2017 Results Conference Call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Patrick de La Chevardière, CFO.

Please go ahead, sir.

Hello.

Patrick de La Chevardière here.

We are pleased to report a strong set of results for the third quarter.

Oil prices and refining margins were up, and we took full advantage of this.

Year-on-year, third quarter adjusted net income increased by 29% to $2.7 billion or $1.04 per share.

For the 9 months, adjusted net income increased by 31% to $7.7 billion or $3.02 per share.

For the 12 months ended September 30, our return on equity has increased to nearly 10%.

Production is up 6% year-on-year.

From a management perspective, we concentrate mainly on cash flow.

For the group, organic free cash flow was $2.1 billion in the third quarter and $5.2 billion for the 9 months.

For the 9 months, operating cash flow before working capital changes increased by $3 billion, demonstrating our ability to fully capture the benefits of a $10 per barrel increase in Brent and $11 per ton increase in refining margins as well as the higher production and lower costs.

Organic CapEx was $3.1 billion in the third quarter and $10 billion year-to-date, in line with our target of around $14 billion for the year, keeping in mind that the fourth quarter can be a bit heavier on average.

Based on our 2017 sensitivity of $2.5 billion for $10 per barrel change in Brent, our pre-dividend cash flow breakeven is below $30 per barrel, and we are on track to further reduce it to around $20 per barrel by 2019.

This has allowed us to move faster than expected to further reduce gearing to below 20% at the end of September.

And one of our primary objectives is to reduce the level of debt.

But I should remind you that we have not yet closed the $2 billion strategic alliance with Petrobras, which will require some cash, and we expect this to happen before year-end.

Most of you are aware that we presented our strategy and outlook in London last month, and we have met with many of you over the past few weeks.

So I think our story is pretty well known.

Basically, we are maintaining discipline and continuing to reduce breakeven.

We are investing countercyclically and taking advantage of the environment to add low-cost resources and launch new projects in areas where we are already strong, like Africa and the Middle East as well as in new areas like Brazil, where we can leverage our deep offshore expertise.

More recently, we announced the $7.5 billion acquisition of Maersk Oil, and this will increase our production by 160,000 BOE per day, mainly in the North Sea, when we close the deal in the first quarter of 2018, and then grow to more than 200,000 BOE per day post 2020.

This acquisition is accretive in 2018 at $50 per barrel for cash flow and earnings per share.

We have a portfolio that is rich with long and short-cycle opportunities, and we have positioned the company to take advantage of the currently low development costs to lock in high return growth for the future.

Now getting back to the third quarter results.

I will make a quick review by segment, and then we will go to the Q&A.

For E&P, third quarter 2017 adjusted net operating income was $1.4 billion, an increase of 84% compared to the same quarter last year, while Brent increased by only 14%.

Production grew by 6%, 2.6 million barrel per day.

E&P operating cash flow before working capital changes was $3.2 billion, an increase of 15% from last year.

Operationally, we are continuing to perform well.

We are in line with our target to grow production by 5% in 2017, mainly thanks to the startup of our operation in Qatar on the giant Al-Shaheen field in mid-July, plus the ramp-up on Kashagan and Moho.

We anticipate an on-time and on-budget startup of Yamal LNG by year-end.

In all, we have 16 projects starting over the period 2017 to '19 that represents more than 700,000 BOE per day of production and more than 10 projects to sanction by the end of the next year representing more than 350,000 BOE per day, all with high returns at $50 per barrel.

Also, we have some good news from Brazil.

We received a waiver on the local content issue, so we expect to sanction the first Libra RFPs very soon.

This will be the first of several RFPs on Libra and represent the next generation of best-in-class deep offshore developments.

In addition to growing the production, cost control continues to be a high priority.

In the third quarter, OpEx was $5.1 per BOE.

And year-to-date, we are around $5.4 per BOE.

We are on track to achieve our OpEx reduction target to less than $5.5 per BOE in 2017 and then $5 per BOE in 2018 from nearly $10 per BOE in 2014.

Moving on to the Gas, Renewable & Power segment.

GRP contributed $97 million of adjusted net operating income in the third quarter, in line with $95 million in the second quarter.

Turning to the Downstream.

Refining & Chemicals contributed more than $1 billion of adjusted net operating income in the third quarter and generated $1.2 billion of operating cash flow before working capital changes, an increase of 16% year-on-year.

Refining margins in Europe averaged $48 per ton for the quarter, benefiting from strong product demand, while supply was limited by shutdowns in part due to Hurricane Harvey.

Petrochemical margins have remained favorable, but below the very high levels we saw last year.

Demand has remained strong globally for Refining & Chemicals.

The contribution from Marketing & Services continues to increase.

In the third quarter, it was $506 million of adjusted net operating income and $517 million of operating cash flow before working capital changes.

During the quarter, Marketing & Services announced its entry into the distribution sector in Mexico, the second-largest market in Latin America.

The combined Downstream segment, Refining & Chemical plus Marketing & Services, generated operating cash flow before working capital changes of $1.7 billion in the third quarter and more than $5.1 billion year-to-date, in line with our guidance for the full year of about $7 billion.

And in terms of profitability, the Downstream continues to be remarkably strong with a ROACE of more than 30% for the 2 segments over the past 12 months.

Based on the strong performance of all segments, at the group level, operating cash flow before working capital changes was $5.2 billion in the third quarter and $15.2 billion in the first 9 months, an increase of $3 billion compared to the first 9 months of 2016.

This demonstrates our ability to capture upside across all segments and reflects our combined efforts to reduce the breakeven while growing the business.

From our perspective, the oil market remains volatile.

On the one hand, we have stronger than expected demand and on the other hand, inventories are decreasing, but still remain high.

There is a balance today, mainly thanks to the 1.8 million barrel per day OPEC, non-OPEC cuts, which are part of the complicated geopolitical environment that always carry the risk of uncertainty.

So we are not committed to any particular oil price scenario.

Instead, we are committed to reducing the breakeven.

As the legacy CapEx holds off and we regain flexibility, we can move selectively to high-guide the portfolio and secure profitable growth for the future, and this is what we have been doing.

We have divested some noncore assets, and there will be more to come, primarily high breakeven upstream assets.

We have acquired some resources and added to an already rich portfolio of development projects.

The strategic alliance with Petrobras and the deal with Maersk are important steps towards long-term value creation.

And we recognize that we are in a window that provides us with the opportunity to lock in low development costs on a variety of new projects.

As we said in London last month and during the meeting we have had over the past few weeks, we have established track record for executing and delivering on our strategy.

We have moved faster than our peers to adjust to the new oil price environment.

And we are moving now to lay the foundation for competitive performance in the future.

And now I am ready to start the Q&A.

(Operator Instructions) We will take our opening question from Christyan Malek of JPMorgan.

Just 2 questions, please.

First, regarding the scope around CapEx for 2018, would you -- I mean, considering there has been some reductions around CapEx targets and through this quarterly season, do you see there are any sort of further scope to reduce beyond $14 billion?

Or is that sort of a hard floor?

The second question comes back to sort of the potential for scrip utilization from next year.

Has that sort of been revised?

Or is there a potential for at a board level meeting to think about cash return in 2018?

Thank you, Christyan, for your question.

Let's answer first to the CapEx guidance.

For the group, we plan to invest $40 billion on organic CapEx in 2017, excluding resource acquisition, and $13 billion to $15 billion for the coming period 2018, 2020, and we don't change our guidance.

I remind you that this guidance for 2018 and after includes the CapEx coming from Maersk Oil.

Financial discipline has always been the core of our expense to strictly (inaudible), and we are investing through the cycle, taking advantage of the current window of low costs.

So we do -- as an answer, we do maintain our guidance from $13 billion to $15 billion for 2018 and onward.

Then I am surprised that you give -- asked me a question about the scrip dividend.

We have not revised our thinking.

We recognize as we generate $5.2 billion of free cash flow year-to-date, but remember, there is no M&A in this spending.

And basically, the priority for us is to reduce the gearing.

We say to our shareholder and we repeat it steadily, it is simply, and as soon as the company covers CapEx, including net acquisitions and dividend, you will have no dilution from the scrip dividend.

It will happen in 2019 at $50 or by 2018 at $60.

Thank you.

We will take our next question from Irene Himona of Societe Generale.

Patrick, I have 2 quick questions, please.

Firstly on Iran.

What is management's understanding on the issue of sanctions?

And whether you can, let's say, legally proceed with your project there?

And then secondly, in Q4, if we are looking at the current oil price environment, $57, $58, what can you say in terms of working capital and tax rate for the group given where we were in Q3?

And indeed, your working capital movement was surprisingly large, I thought.

Okay, Irene, thank you for your question.

Today -- first question on Iran.

We have signed a contract in Iran, and we keep working.

And we are carrying our activities in Iran in full compliance -- sorry for the noise, in full compliance with international law.

There is, and you are right, political uncertainty in the U.S. at the moment and there will be, hopefully, more clarity in the coming months.

We are committed to the project, but if there are laws which force us to withdraw from Iran, we will of course comply with them.

Another information which is important, tenders are on their way, and we should award the main contract by beginning of '18.

By that time, we will have clarity on the U.S. framework.

Second question was guidance on working cap.

At the group level, basically, we have a move of working cap of about $800 million, if I well remember.

Working cap increase in the upstream with higher receivables, driven with production and price increases, along with lower payable related to the completion of project like Edradour-Glenlivet in the U.K. or Moho Nord in Congo.

In Downstream, working cap increased from a low level at the end of the second quarter, in line with higher throughput and higher margins.

Of course, and you know that working cap is volatile by nature, and I will look at it on a yearly basis.

Tax rate.

The effective tax rate for the group was about 33% this quarter, an increase of 4 points, driven by the upstream tax rate.

Remember that the second quarter was low, so we are now back with the guidance.

With Brent in the range of $50 to $60 per barrel, we expect the E&P tax rate to be between 40% and 50%.

Below this level of price, we would expect the upstream rate to be extremely volatile.

Going forward, Downstream should be pretty stable at around 30%.

And let's assume Brent in the range of $50 to $60, we would expect E&P tax rate to be 40% to 50%, with the group rate around 30% to 35%.

We will take our next question from Thomas Adolff of Credit Suisse.

Just on Upstream, you have, obviously, 4 key areas, which include LNG, deepwater, the Middle East and West Africa.

And as far as the Middle East is concerned, I'm reading that you might be interested in Majnoon, which Shell exited more recently.

Perhaps you can confirm this and why.

And as far as LNG is concerned, again, there are some press articles there suggesting that you may be looking at ENGIE's LNG business.

Perhaps you care to comment if you can.

And finally, my question is on Kashagan.

I wondered whether you were surprised that the government actually didn't come after you guys, and maybe they're letting you ramp up to plateau before tax changes could happen.

Or are you comfortable around the current tax framework on Kashagan?

Thank you, Thomas.

I hope you recover from your trip from Moscow.

Your first question about Majnoon.

Basically, I would say that Iran is a land of low-cost oil, but let's find the right condition to operate in this country.

Majnoon, obviously, will not accept -- will not accept terms that are refused by a competitor.

So let's say that as a matter of principle, we are interested, but that all depends on the condition of the contractual condition and the tax condition attached to the project itself.

LNG, ENGIE.

It is true that ENGIE has recently announced a strategic review of their Upstream LNG activities.

They have mentioned discussion with counterpart, including Total.

And by the way, our CEO confirmed talks with ENGIE.

As you well know, LNG is one of our core strengths, and our strategy is to play on our strengths.

We are looking opportunities at all time.

So if a good opportunity arise while discussing with ENGIE, we are willing to size it, of course, but we will see.

And at this stage, there is no more to say on my side.

So last question about Kashagan.

Why do you want me to be surprised that the Kazak government comply with the laws they have implemented?

Okay.

So you are very confident.

We will take our next question from Biraj Borkhataria of Royal Bank of Canada.

I had a couple of these.

First one on the Downstream.

Could you just remind us what, if anything, needs to be done for your Refining system to comply with the -- or take advantage of the IMA regulations in 2020?

And whether there's any CapEx associated with that?

And the second question regarding FIDs.

What are you seeing currently on the service side versus, let's say, 6 to 9 months ago?

Can you repeat the second question, please?

Sure.

Regarding new FIDs, what are you seeing on the offshore services side?

Are you seeing costs still go down versus 6 to 9 months ago?

First question, your first question was about Downstream and how to comply with the new regulation coming on.

This new specification change has been discussed for a while and obviously was on our radar, but there are still some uncertainties on how the shipping industry will adapt, with potentially the installation of scrubbers and also the penetration of LNG as a fuel for tankers.

In any case, we don't need any massive investment in Europe to face this new specification.

This specification is going to reduce any fuel oil demand, and our recent investments are in line with this, and I try to summarize them.

Port Arthur is not producing any more fuel oil.

SATORP is also fully converting the bottom of the barrel.

Antwerp modernization is just finishing, and we are significantly reducing heavy oil production from both Antwerp and Flushing refineries.

The Lindsey project has also increased the conversion ratio, and we have shut down La Mède, which was producing a lot of fuel oil.

Honestly, volatility is to be expected in 2020 as the market change.

It's emphasized again that the good strategy is to reduce the breakeven.

As you know, this is what we have been successfully doing for the past years.

Then you have a question about FIDs in offshore, and if we see some event coming from the offshore services.

We are still seeing some cost decrease in some categories like logistic and well services.

We haven't seen any cost increase so far.

It is clear that project won't be sanctioned if the returns are not there, so costs are under pressure to align with the market outlook for prices.

The expectation will be parts of the U.S. that are very active, so you should extract from your data the data that is coming from the onshore U.S. We don't foresee any increase in our key and core areas.

That will be my answer.

We will take our next question from Jon Rigby of UBS.

Patrick, just a quick question on how you will think about the situation.

Should we be in, I guess, situation that no one thought we might be a year or so ago, where you were actually running cash surplus.

And you've talked about debt reduction, and I think you also referenced, if I'm not wrong, anti-dilutive buybacks.

But -- you are one of the few companies that have explicitly said that parts of your spending will be devoted to inorganic.

I just wonder, when you think about inorganic right now, given the absolute sort of visibility on prices or volatility on prices, does that tend towards -- does that lean you towards buying assets that have production rather than longer life development opportunity, just simply because it creates less risk because you have more confidence over mid-term oil prices than maybe you do over medium, long-term oil prices?

Honestly, Jon, you know that our way to secure our future production is mainly to acquire nonproducing assets and resource under the ground that we are able to buy at a price below $3 per BOE.

On top of that, it's happened that you see some producing assets, like Maersk, that we are able to acquire on an accretive manner.

So there is no exclusion of those type of acquisition, provided that they provide good return when you acquire them.

But there are 2 issues in your question.

The first one is renewal of resources for undeveloped resources acquisition, then taking opportunities like the Maersk deal.

Right, yes.

Exactly.

And just to clarify also, you have a plan, and it's sort of set at a price where you expect the company to perform at, and then there's the potential to generate free cash flow over and above that.

And you've talked about debt reduction, and you've talked about anti-dilution, which I think is both very welcome, but you wouldn't exclude if you were generating free cash flow over and above the needs of those to be somewhat tactical in the M&A market as well.

Will that be a sensible characterization?

As you have seen on the Maersk acquisition, we use shares.

And even if we were in a weak environment, we were able to make this acquisition being dilutive on both cash flow per share and earning per share.

Let's assume the oil price is getting better.

If there is any excess cash flow, and obviously this will depend on the oil price, it will be used to continue to consolidate the balance sheet, to feed return to shareholders and to continue to invest for the future.

That is the order I will give you.

We will take our next question from Rob West of Redburn.

I have 2. I thought I was original, but they've been addressed in different guises previously, I'll ask them in slightly different ways, though.

One is just back on ENGIE.

Are you specifically interested, as you've confirmed, in the Upstream part of the LNG portfolio?

Or would your interests theoretically include regas infrastructure as well?

That doesn't have to be a ENGIE-specific question, if you could comment on whether regas infrastructure is something you'd acquire, that would be helpful.

The second was back on Biraj's question about the service side.

You're going through the process of EPC in Nigeria, Angola, Argentina, the Caspian, Brazil, Iraq, ADCO, which I think effectively makes you the most active company I can think of in the world right now internationally.

So could you comment on specifically the EPC pricing you are seeing onshore and the [SURF] pricing you're seeing onshore, and just a sense of year-over-year, what would be your finger in the air estimate of where pricing is, what the same thing cost today versus what it would have cost a year ago, that would be helpful.

On ENGIE, I am sorry, Rob, but I'm not going to comment on discussion which are going on.

I'm not going to be very helpful to you at the moment, but my answer is no comment.

On the service side and the EPC pricing, for CapEx, IHS index stabilized at about minus 30%, which is a mix of increase in the U.S. and decrease outside of the U.S. And we -- as you know, we are basically outside of the U.S. Rig rates and well services have fallen by 50% for some categories.

The -- and I think this is important, the industry launched about 1/3 as many project per year in 2015 to 2017 compared to the period 2010-2014.

So there is a lot of available capacity in the market.

Engineering companies and shipyard are near the end of their backlogs, so we don't only consider deflation, which is given by the markets, to cut cost, but we modify also our approach of development for optimize and good enough design.

With about 13 pre-FID opportunities expected in the forthcoming 18 months, we are in a good position to get very competitive pricing and, obviously, capture attractive level of costs.

Thank you.

We will take our next question from Lucas Herrmann of Deutsche Bank.

Patrick, 2 or 3 if I may, unfortunately, but they're all relatively quick and some are relatively repetitive.

The first, just remind me, because I can't remember, forgive me, dividends converting to dollar.

It's just that I watched the euro rate go up, and what the French restrictions were in terms of your ability to do that.

Secondly, Angola, we've heard from a couple of companies over the last few days talking about tax settlements with Angola over past claims under PSC.

I just wonder whether you could comment at all on where Total sits, if there's any potential liability or otherwise, or there's been any settlement.

And thirdly, when you -- in terms of balance sheet, Patrick, I mean, the gearing is 18% on your debt over equity basis, or if I looked at you relative to others, it's probably nearer 15% if I do debt over debt plus equity as others report, where would you like to see debt equity settle before you feel more confident about your ability to move and move quickly given balance sheet into the future?

When you say this is quick question, I'm not sure the answer will be quick.

The first easy one on dividend in dollars.

We were looking at it, but honestly, denominating the dividend in dollar is extremely complex under French law.

And basically, we will need to have the law changed, and we are not yet there at the moment.

It is therefore unlikely that we will be able to implement it in the short term.

Honestly, it -- without any change in law, it will be a pure nightmare for our shareholder.

Angola, I was listening to ENI 1 hour ago.

We have settled the same with a similar amount, around $200 million, and the tax issue is settled.

And that's in this quarter's numbers, Patrick, or was that earlier?

Can you repeat?

Sorry.

The settlement that you've reached, has the cash outflow occurred this quarter, or was it in the prior quarter?

This quarter, the third quarter.

Guidance.

Yes, it is currently going down, but I remind you that there is our strategic alliance with Petrobras to be paid, hopefully prior year-end.

This is about $2 billion.

Then you will have the Maersk deal where we will assume $2.5 billion of debt, which will once again deteriorate the gearing.

It is true also that $2 billion of cash is 2% gearing.

Honestly, I remind the period where the oil price started to fall, and our competitors were enjoying a gearing close to 10%.

We were above 20%, and I was not comfortable.

So if I may say so, I will be more comfortable with lower gearing and much below 20%.

We will take our next question from Christopher Kuplent of Bank of America Merrill Lynch.

Patrick, just a few ones to clean up.

One on working capital.

As I understood your answer to Irene, it sounds like your current working capital is sustainable rather than a temporary -- the result of temporary changes, if you could confirm that.

And secondly, Suncor sounded quite optimistic about finding a resolution as far as Fort Hills is concerned.

Can you give us any detail about how optimistic you are?

I don't have to be optimistic or not optimistic.

It's a dispute we have with Suncor on Fort Hills.

And the process is going on.

We are still discussing among ourselves, but there is no reason to be negative or positive.

There will be an outcome.

There is a legal process, and that's it.

On working cap, it is true that when the oil price goes up, working cap is increasing.

So I would say that the move I saw on the third quarter was anticipated, but you know we are working on working cap.

You remember that a year ago -- or 2 years ago, sorry, we had difficulties to control this working capital, and that we dedicate a special team on it.

And at the end of the year of 2015, we did control the working cap.

And that was the same in 2016.

And it will be the same for 2017.

And we will control and manage our working cap by year-end, hopefully, at a lower level than the one we had at the third quarter.

We will take our next question from Lydia Rainforth of Barclays.

Patrick, 2 questions, if I could.

On the first one, it was around the cash flow per barrel numbers in the Upstream.

Are you -- are they where you would expect them to be at this point in terms of relative to your own guidance?

Or are there areas where they're falling short or doing better than we are?

I'm just thinking in terms of the premium cash margin barrels that are coming on stream.

And then the second one was just quickly on the Downstream side.

What you are actually seeing in terms of demand (inaudible) refining margins at the moment?

Your cash flow per barrel question first for the Upstream and the premium we expect for the new project coming on.

We have started already 16 projects since 2015 and ramp-up are going well.

All of these projects contribute to the production growth and the cash flow growth.

On accretive, they are all of them cash accretive compared to the production base, and their cash margin is higher than the base.

This portfolio is a mix of giant long plateau assets and high-margin deepwater projects.

I can give you a few of them, for instance, CLOV is providing at $50, $38 per barrel, Vega Pleyade $25, Kashagan only $10, I would say.

That's roughly the range of magnitude that we can expect.

On the project demand, yes, the answer, project demand is strong.

For 2017, the international energy agency revised its growth forecast to 1.6 million barrel per day for this year with strong demands from non OECD countries, in particular Asia.

Demand evolution on 2015 to 2017 is plus 5 million barrel per day, which is above 2012, 2014.

Clearly, demand reacts very strongly to price.

And the demand should continue to grow at a sustained pace in 2018.

And someone are forecasting 1.4 -- plus 1.4 million barrel per day increase of demand for oil products.

We will take our next question from Jean-Luc Romain of CM-CIC Market Solutions.

Your partner in Yamal LNG recently mentioned an opportunity to build a fourth train there.

Can you comment a little more on that in terms of what the capacity would be?

And if it would be using the same technology as of 3 trains?

As a reminder, there is an extension -- fourth train extension into study development at Yamal for capacity of 1 million ton a year, and we are positively looking at this project.

This will be fourth LNG train.

It will be small because this capacity will be an additional 1 million ton above 16.5 million ton capacity with the first 3 train.

It is low-cost profitable development, taking advantage of the existing facilities, and of course, of the giant onshore resources in Yamal.

I think as far as I am aware of, this fourth train will be a test of small-scale innovating LNG technology developed by Novatek that could be applied on other LNG development later on, if any, for this size or not, I don't know.

So it's a new technology.

I think it is basically a Russian technology, so it will be a test.

Thank you.

We will take our next question from Theepan Jothilingam of Exane BNP Paribas.

Patrick, it's Theepan here.

I've got 2 questions, please.

Just from a modeling perspective, could you just outline what you see in terms of proceeds coming in from disposals already announced maybe in Q4 and then first half next year, just timing there?

And similarly, just on the payments for the DROs?

The second question reverts back to what was discussed at the Analyst Day just around quick payback projects, the short cycle.

I'm just wondering what, I think, 3 or 4 areas were mentioned: Angola, Qatar, Nigeria and the U.K. what -- how would you sort of prioritize those opportunities as we go into 2018?

So I am going to try and help you with your model, Theepan.

Let's talk about the progress on our disposal plan.

You know that the $10 billion disposal plan is essentially complete.

Since the beginning of the year, we closed disposal for more than $3 billion, namely Atotech SPMA pipeline and LPG activities in Germany.

Looking forward, we intend to monetize high breakeven in noncore asset for $1 billion per year.

And we are in strong position, and we will only sell assets if the price is right.

By the way, the high breakeven concept applies to Canada, but I don't think this is the right timing for selling Canada at the moment.

And I remind you also that we have a sale in Gabon for a few hundred million dollars.

I think Gabon is $300 million.

And you also have the sale of Total Air, which is going on, but there is a lot of debt in this equity affiliate, so at the end of the day is not going to be a large amount of cash net to Total.

So the short cycle, you like it Theepan, this is short cycle.

Yes, we have short cycle opportunities as the one we presented to you in the Investor Day in September.

These opportunities are a mix of infill drilling in Nigeria, Angola, Brazil, North Sea, Qatar, for example, and Shell projects such as Vaca Muerta in Argentina.

And of course, we have our small exposure in (inaudible).

All infill wells not drilled since 2015 are ready to be drilled if we decide.

In total this project are material, representing 1 billion BOE of reserve and about 100,000 to 150,000 barrel per day by 2020 -- not barrel, but BOE, sorry, by 2020.

These projects are obviously quite attractive with IRR above 20% at $50 per barrel due to low CapEx at around $7 per BOE.

With all those figure, I'm sure your model will be perfect.

We will take our final question from David Gamboa of TPH.

Patrick, just had a quick one in terms of organic resource replenishment.

So if I'm not wrong, last year you added around 500 million barrels from your exploration program and you guided that you were going to be drilling around 40% more wells this year for less -- 10% lower cost than last year.

I was just wondering if you could give us a sense now that we're almost 2 months away from the end of the year how your exploration program has performed this year.

How you're tracking versus your target of organic resource additions?

If you can give us some comment around that, that would be very helpful.

Being frank with you David, the result of this quarter have been disappointing, but we are continuing to reposition the portfolio.

The target remains the same, 400 million, 500 million barrel of BOE per year.

But don't forget that we found some gas in Myanmar, and we continue to successfully operate the Northwest panel of (inaudible).

We have recently captured promising acreage in Mauritania, Senegal, Namibia and the Gulf of Mexico through a farm-in with Chevron.

So we are continuing our repositioning, and I'm pretty convinced that after a few years, it will deliver some results.

Thank you very much.

I think that was the last question?

So the third quarter results are in line with our targets and expectations.

We are managing our cash flow effectively in the current environment.

Gearing is going down.

Production is going up.

We are continually adjusting the breakeven to the environment.

And we have the portfolio we need to continue growing well into the future.

Thank you for joining us today.

And I hope you enjoy the next call you have.

Thank you.

That will conclude today's conference call.

Thank you for your participation, ladies and gentlemen.

You may now disconnect.