Ladies and gentlemen, thank you for standing by and welcome to Total's Q3 2019 Results Conference Call. At this time, all participants are in a listen-only mode. There will be a presentation followed by a question and answer session, at which time, if you wish to ask a question, please press star one on your telephone keypad. I must advise you that this conference is being recorded today, Wednesday, the 30th of October 2019. I would like now to turn the call over to Jean-Pierre Sbraire, Chief Financial Officer. Please go ahead, sir.
Thank you. This is Jean-Pierre Sbraire. Total reported strong third quarter results, demonstrating the ability of our diversified portfolio to resist volatility in the markets, particularly in terms of strong cash flow generation. Debt-adjusted cash flow was $7.4 billion, a slight decrease of 2% compared to the same quarter last year, despite the 18% drop in the average Brent price and a decrease of more than 50% for spot gas prices in Europe and Asia. The resilience was due mainly to cash accretive volume growth of more than 8%, strong contributions from Integrated Gas and downstream, and company-wide efforts to cut costs and reduce the breakeven. Adjusted net income was $3 billion or $1.13 per share, down 23% compared to the same quarter last year, mainly due to the weaker environment, but also benefiting from the growth and the downstream resilience.
Looking at the first nine months compared to the same period last year. Debt-adjusted cash flow increased by 6% to EUR 21.1 billion. Adjusted net income was EUR 8.7 billion, down 17%. OPEX was EUR 5.3 per barrel in Q3, reducing the 2019 year-to-date OPEX to EUR 5.5 per barrel, which is a decrease of 5% compared to OPEX of EUR 5.8 per barrel for the first nine months of last year. With additional cost reduction of more than EUR 0.5 billion this year, we raised the cumulative savings target to more than EUR 4.7 billion for 2019 compared to our 2014 base. Operationally, the group's production hits a new high of more than 3 million barrel per oil equivalent per day in the third quarter, and production growth should reach 9% for the full year. It was 8.7% by end September. Q3 benefited from the ramp-ups of Ichthys, Yamal, Egina, Kaombo Sul and Culzean.
Johan Sverdrup will be started up early, so we will benefit the first quarter. Iara One in Brazil should start before year-end. We are continuing to high-grade the portfolio and delivering sustainable cash flow growth. We completed the acquisition of Mozambique LNG in September, and we should close the remaining parts of Anadarko portfolio, Algeria and Ghana, in 2020. We sanction Arctic LNG 2 in Russia. We participate in our second Guyana discovery, so we have a good start in this promising new basin. We won a new high-potential exploration license as operator in pre-salt Brazil. We maintain strict capital discipline in line with our commitment for return to shareholders. An example of this was the termination of our agreement to acquire part of Tullow's stakes in Uganda as we disagreed on the tax treatment of the transaction.
Also, we confirm that we will not participate in Brazil's transfer of rights as the underlying price deck for the bonus does not fit with our criteria. Looking at the results, the E&P segment generated cash flow from operations before working capital, which I will refer to hereafter as CFFO, of $4.5 billion in the third quarter 2019, a decrease of 14% compared to the same quarter last year. In a deteriorated environment, this performance reflects the resilience of this CFFO, thanks to the higher cash flow generation from new project startups and ramp-ups. Adjusted net operating income in the third quarter was $1.7 billion, down 29% from $2.4 billion in the same quarter last year, reflecting higher DD&A from new projects. The iGRP segment increased CFFO by more than 50% to $0.8 billion.
Adjusted net operating income in the third quarter was $0.6 billion compared to $0.7 billion in the third quarter last year, again, reflecting the weaker environment. Year to date, iGRP CFFO increased by nearly $1 billion, thanks mainly to the 55% increase in equity LNG sales, in particularly fueled by Yamal LNG and Ichthys. In the LNG business, in addition to the acquisition of Mozambique LNG and launching Arctic LNG 2, Cameron Train 1 ramped up in the third quarter. Train 2 and 3 are under construction and will start next year. We took over Toshiba's 2.2 million ton LNG portfolio in July, which came with a cash inflow of $800 million. We announced the expansion of a strategic partnership with private conglomerate Adani to develop access to fast-growing gas and LNG markets in India. We signed a gas agreement in Benin that includes a FSRU floating LNG regas unit.
We launched our first LNG bunker refueling vessel, which will operate in Northern Europe, supplying the next generation of container ships. In the renewable business, we added 500 MW of new solar and onshore wind farms in France. We sanctioned our first solar farms in Japan. We reached our 1,000th service station with solar panel. This is part of our ongoing plan to solarize 5,000 service stations globally and part of a broader plan to leverage renewable energy at our facilities throughout the group. We joined forces with Envision Group to develop on-site distributed generation solar project to B2B customers in China. Turning to the downstream. CFFO for the combined downstream was very strong at $2 billion in the third quarter, an increase of 14% compared to a year ago.
Adjusted net operating income for the third quarter was stable compared to the same quarter a year ago at EUR 1.4 billion. In Europe, cracker margins again benefited from the supply limitation as a result of a heavy turnaround season. In the U.S., petchem margins benefited from lower feedstock prices, notably ethane, but also LPG, with new supply coming online. The diversity of our downstream business units, including the counter cyclical and non-cyclical elements, is an important part of delivering sustainable performance. Year-to-date, downstream CFFO increased to EUR 5.1 billion and is well positioned to reach close to EUR 7 billion for the year. Refining and Chemicals generated CFFO of EUR 1.4 billion, an increase of 17% compared to the third quarter 2018, mainly thanks to higher petrochemical margins. Adjusted net operating income was EUR 1 billion, a slight increase compared to the third quarter last year.
European refining margins, ERMI, were EUR 47.4 per ton, stable compared to last year. Marketing and services generated CFFO of EUR 0.6 billion, an increase of 7%, notably due to higher margins in Africa and Europe. Adjusted net operating income was EUR 0.4 billion in the third quarter, down 13% compared to last year. Year-to-date, CFFO increased by 10% to EUR 1.8 billion. In terms of profitability, return on average capital employed for our best-in-class downstream was 25% for the past 12 months. At the corporate level, based on a rolling 12-month average, return on equity for the group was above 10% at 10.3% at the end of the third quarter. Year-to-date, debt-adjusted cash flow for the group is $21.1 billion, up 6% compared to last year.
Net investments, including acquisition and asset sales, were EUR 13.2 billion for the first nine months, and we expect the full year 2019 to be less than EUR 18 billion. Net acquisition and asset sales for the first nine months of 2019 was EUR 4.1 billion. This includes mainly EUR 3.9 billion for the Mozambique LNG acquisition and the EUR 800 million that we received for taking over the Toshiba LNG portfolio. Year to date, we have completed EUR 1.6 billion of sales, or about 30% of the EUR 5 billion target. In addition, we have sold but not yet closed around EUR 1 billion of assets, including mature U.K. North Sea asset, the Trapil pipeline network in France, and the sale of a non-operative block in Brunei. We are well advanced in the process. The organic pre-dividend breakeven is below $25 per barrel.
Maintaining a strong balance sheet is one of our top priorities, and gearing at the end of the third quarter was 17%, excluding capitalized leases, and 21% including them. The closing of the Mozambique energy acquisition added about 2.5% to gearing. One of the main messages from the investors' day is that we are accelerating dividend growth. Previously, our guidance was an increase of 10% over the 2018-2020 period, and we have been growing the dividend at more than 3% per year. Given our outlook for strong cash flow growth of about EUR 1 billion per year over the 2020-2025 period. The board has decided to accelerate the dividend growth for the coming years with a guidance of 5%-6% per year. In line with this, we confirm that the third interim dividend for 2019 will increase by 6%. Buybacks through September was EUR 1.15 billion.
Given the strong cash flow generation, we will end the year with EUR 1.75 billion of buybacks, exceeding our 2019 target of EUR 1.5 billion. We'll complete EUR 5 billion program next year. Finally, we announce that we'll open a digital factory in Paris in early 2020 that will pool the talents of 300 engineers, data specialists and other experts, to generate an estimated EUR 1.5 billion per year in value by 2025, through increased revenues and reduced costs and investments. Summarizing the third quarter results. TotalEnergies' integrated model is working well. Our efforts to reduce breakeven and high-grade the portfolio are paying off. Despite weaker oil and gas prices this year, we increased cash flow generation from our diversified portfolio, benefiting mainly from integrated gas and downstream. We are on track to grow cash flow over the coming years. We are disciplined in our capital investments, including net acquisitions.
The balance sheet is strong, and we are committed to returning value to our shareholders. That's it for my prepared remarks, and now we can go to the Q&A.
Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. If you wish to ask a question, please press star one on your telephone keypad. If you wish to cancel your request, please press the hash key. Once again, it's star one to ask a question. We will now pause for just a moment to allow everyone to signal for their question. The first question comes from the line of Lydia Rainforth from Barclays. Please ask your question.
Thank you. Good afternoon, Jean-Pierre. Two questions, if I could. The first one, just to come back to the asset sales. Can you just walk me through why the Toshiba LNG part is included in asset sales, just in terms of it seems a bit odd given that there is a liability associated with that. The second one, was just around the low carbon business and the highlight and the progress being made there. Can you give us an indication of where the returns might be across the different regions, whether it's France, Japan, China? Thank you.
Thank you, Lydia. Regarding Toshiba, you know the deal. We acquired the Toshiba LNG portfolio, it was in August this year. The rationale behind that is that, of course, for Toshiba, saw negative value in this contract and decided to exit from this non-core business. They have paid us EUR 800 million for that. In fact, it's an acquisition, but at the same time, we capture this EUR 8 million of cash for this portfolio. Since we received cash, obviously, in our cash flow statement, it's considered as a sale. The second question regarding low carbon. You know, and I think we are transparent, in September during the Investor Day. A typical renewable project deliver an internal rate of return, I would say 5%-6%. Of course, it's not in line with our criteria to sanction projects.
To boost our equity in low-carbon projects, and particularly in solar farms or wind farm, we leverage projects. Typically, we use a debt-to-equity ratio, 70%/30%. It could be higher, because of course, at present time, money is very cheap. In some cases, we can achieve 80/20% debt-to-equity ratio. That's the first step. Second, we sell down our shares, and we keep more or less 50% of the share. Doing that, we can achieve an IRR or equity above 15%. Low-carbon business, in our view, includes LNG as well, of course. You know that growing along the gas value chain is a key priority for us.
Understood. That's helpful. Thank you very much.
You bet.
Thank you. The next question comes from the line of Biraj Borkhataria from RBC. Please ask your question.
Hi, thanks for taking my question. Two, please. The first one on the buyback. The increase in the run rate is encouraging. You obviously maintained your guidance as flat into 2020. I would have thought with growing production, you got flat CapEx, and then you have the benefits of IMO 2020. That the 2020 buyback potential would be a little bit higher at least than 2019. Could you just talk about how you're thinking about that run rate as you go into next year? The second question is on Guyana. You divested part of your stake in the block to QP two or three weeks ahead of the discovery. Could you just walk us through what drove that decision? Because presumably, the well was either being drilled or had been drilled when that decision was made. Thank you.
Okay. First question regarding buyback. Last year, we bought back the equivalent of $1.5 billion. End of this year in September, we bought back the equivalent of $1.15 billion. We announced that we will buy $1.75 billion for the full year. That means an additional $600 million during the Q4. The strategy is very clear. We will deliver the 2018-2022 $5 billion program that has been announced in February 2018. Beyond 2020, I think we will act according to our priority of cash allocation. First, dividend growth of 5%-6% per year. I think it was the main message from the investor day that we will accelerate dividend growth. You know that before, our guidance was an increase over 10% over the period 2018-2022. We have been growing the dividend of more than 3% per year.
The board has decided to accelerate the dividend growth for the coming years with a guidance of 5%-6%. As you mentioned, the board has decided to implement this increase immediately. For this third interim dividend, you will see this 6% growth. Second priority is to deliver the company. I think we are very clear that we want to maintain a very strong balance sheet, and gearing is key in our strategy, in our views. Buyback, of course, we used to share extra revenues above EUR 60 per barrel. Regarding your question on Qatar Petroleum and the farm down to QP on Guyana. Total is a long-term partner of QP in Qatar, and we therefore support their international development. You mentioned the Guyana wells.
At the time, the partnership, we decided to let QP farm into some exploration acreage in Guyana, but also in some other countries, so Kenya and Namibia. The well was not drilled.
Thank you. We will now take our next question. The next question comes from the line of Oswald Clint from Bernstein. Please ask your question.
Yes, Jean-Pierre, thank you. Just two small ones on the 3Q results. The third-party LNG sales were down sequentially quite a bit. I just wonder what's going on with that line item, or if there's any LNG cargoes you're not actually lifting at the moment. Similarly, in affiliate earnings for refining chemicals and also marketing and services, both down quite a chunk sequentially on year-over-year. If you could just talk to what's happening in those. Maybe just a follow-up to Guyana, that you have had two discoveries on the block recently. How are you thinking, or how interesting is this block turning out to be from your perspective? Thank you.
Okay. Regarding the Q3 results and third party LNG sales. Yes, that's true that the sales from equity production and third-party purchases were down quarter to quarter, and it's clearly linked to less volumes of spot in our sales. I can say that there was a higher focus this quarter, in the Q3 quarter, Q3 2019, on using our European regas capacity instead of selling on spot markets. You will see that on nine months, the sale from Total are increasing by 75% compared to the same period last year. Second question regarding downstream. Yes. Okay. If the equity affiliate contribution to net operating income was around EUR 520 million this quarter, it's below last year. Last year, the same figure was on the same equity affiliate contribution to net operating income was at EUR 860 million.
It's in relation to a weaker gas price environment impacting Novatek in particular, on one side. On the other side, we faced lower availability in South Korea, in RGV with Hanwha, and in SATORP, RGV with Saudi Aramco in Saudi Arabia. Q to Q, I would say we are benefiting notably from Novatek and Yamal LNG. On exploration in Guyana, I will summarize by saying that it's a promising start in Guyana because we are successful in drilling two wells. We have the first well, Jethro, it's a high-quality sandstone reservoir. The second well that has been drilled, Joe, it's a play opener. I would say that our explorers are very excited by these two wells, and we hope that in the coming years, with additional wells, we'll confirm that definitely Guyana will contribute positively to our exploration results.
Okay. Very good. Thank you.
Thank you. The next questions comes from the line of Thomas Adolff from Credit Suisse. Please ask your question.
Hi, good afternoon. A few questions from me, please. Just going into iGRP, you've seen a sequential improvement in earnings. Perhaps you can talk about the moving parts in this division. What's driven the increase, and how did the integrated gas business perform on a quarter-to-quarter basis? Secondly, in Refining & Chemicals, there was a recovery in throughput in your refineries, but you still remain fairly low at 82%, and you've highlighted there's been some maintenance at Normandie and some issues around Grandpuits. I wondered where runs are in the fourth quarter and whether you have any major maintenance plan for 2020. Perhaps finally, if I may, just coming back to your comment on shareholder distribution and again, going back to the management day, and the message on the management day.
In 2021, assuming your macro scenario of $60 Brent, are you likely to pay a return 30% of cash flow to shareholder or 40% of cash flow to shareholders? Thank you.
Okay. First, perhaps the question regarding refinery and the situation in our French refinery. Grandpuits refinery was shut down end of February because of detection of a crude oil leak in the pipeline supplying the refinery. Now the Grandpuits refinery has restarted operation, and the restart of operation occurred mid-July. iGRP. The environment was weaker, obviously. We faced a low gas price environment, but at the same time, the CFFO for this business segment increased by more than 50%, so 53% year-on-year, at almost EUR 850 million. The main driver for this increase is the cash generated by Yamal LNG and Ichthys, and with the ramp-up of these two projects.
If I consider the first nine months, I think one of the main takeaway of our third quarter results is that we are able to increase the cash flow generated from iGRP. We are able, sorry, to deliver a cash flow around $1 billion, driven again by this LNG business. At the same time, the LNG production, as you noticed, was up by more than 55%.
Can I stop you there? Can you comment on 3Q versus 2Q?
Sorry.
Yeah.
Yes. We have a higher contribution from Ichthys, at the same time, for low carbon electricity as well. To answer to your question. The last question regarding the shareholder return in 2021. In February 2018, we announced how we'll allocate our cash flow, our CFFO, our cash flow generated by operation. At that time, obviously, we are lagging our competitors. It was in 2017. It has been said, we said with the board that, of course, we needed to rejoin the pack. We did catch up since there. Now, in 2018, we returned to our shareholder, the equivalent of 38% of the CFFO. Eventually, we'll get to the 40%. I remind you that with our guidance of 5%-6% increase per year of dividends, we will increase the dividend by about EUR 500 million.
At the same time, we will increase the cash, the FFO, by EUR 1 billion. That means that we'll return more or less half of the added of the cash we will generate. Our CEO, Patrick Pouyanné, gave that indication of 40% FFO, it was in July, but it was not a commitment. It's a medium-term aspiration.
Okay, great. Thank you.
Thank you. The next question comes from the line of Irene Himona from Societe Generale. Please ask your question.
Thank you. Good afternoon, Jean-Pierre. I had three questions, please. Firstly, in the third quarter, looking at marketing and services, NOPAT EUR 413 million. It fell sequentially, and year on year it fell about 13%. I wonder if you can explain what drives that relative weakness. Secondly, tax rate in Q3, the tax rate in E&P, I thought looked quite low. Can you just remind us, in a world of $60 Brent, roughly what we can expect for E&P tax in the fourth quarter and into next year? And my final question, looking at the coupon payment on your hybrids, your perpetual subordinated notes, in Q3, that payment jumped about 77% sequentially from EUR 74 million to EUR 131. In the nine months, you paid about 17% more than a year ago. I know you issued some more hybrids during the year, but I didn't think you issued 17% more.
I wonder if you can, again, give us a sense of what the payment schedule for these is, because clearly it impacts the EPS calculation. Thank you.
First question regarding marketing and services. First of all, I think that the net operating income year-on-year is more or less stable. It remain above EUR 400 million. The slight decrease is not very significant. At the same time, if you look at the cash flow, FFO generated by marketing and services, you see that this cash flow increased by more than 7%. It's completely in line with the guidance we gave to increase marketing and services cash flow more or less by EUR 100 million per year. Tax rate. The effective tax rate for E&P in Q3 was more or less 40%, and 39.7% to be precise. It's in line with the weaker environment. Last year, in Q3 2018, the effective tax rate for E&P was 40.47%.
It's very difficult to comment the tax rates on a quarterly basis, but it's in line with the figures we have in mind to have more or less an E&P tax rate between 40%-50%, depending on the Brent price in the range between $60-$70 a barrel.
Okay.
Hybrids. That's true that we refinance a part of our portfolio. I think it was in March or in April of this year. We haven't increased the total amount of hybrids. It's a refinancing, we issue a new hybrid, at the same time, we have decreased for the same amount, the level of hybrids in our portfolio. I would say the total level of hybrids is exactly the same. I do not have the exact payment schedule in mind regarding the coupon. What I can mention is that in my view, I consider hybrid as being a very cheap equity and the coupon overall for all the different tranches we have in our portfolio, the coupon are below 3% before tax. That means that after tax, it's around 2%. I will add something.
Through the refinancing, we are able, by the way, to reduce the coupon. It was a very successful refinancing.
Thank you very much.
Thank you. The next question comes from the line of Jon Rigby from UBS. Please ask your question.
Excuse me. Hello. Hi. Two questions. One on the downstream, one on M&A. On the downstream, just to go back to Thomas' question, you noted that throughputs and the refining were running low, actually low year-over-year. We're obviously seeing a pickup into the year-end with IMO. Are you able to just talk about, should we be expecting, by historical standards, relatively high utilization rates and throughputs through 4Q and into 2020 to take advantage of what might be a good opportunity? Just on that downstream, was there any decent or notable contribution from Oil trading in the quarter. Some other of your peers have noted some benefits, I guess that might be related to these changes. That's on downstream. On M&A, you obviously still got some outstanding payments to make around the Anadarko Africa transaction.
Are you able to say as of right now what you would be likely to pay, and let's say if it were to be, we say at $60 and you close it mid-year next year, what the delta would be on the consideration that you would expect to pay? Thank you.
First of all, I will not change the tradition, so I will not comment on trading contribution in the results, in the refining and technical results. The question regarding IMO, I am not sure to have really understood your question. Could you elaborate a bit?
Yeah. If you look at the refinery throughputs year-over-year, they're actually down. They're up sequentially, but throughputs are down. I'm just asking whether the plan to run the network hard through 4Q and into next year with the assumption that refining margins are helped out by IMO, so to make sure you get the full leverage for that.
You know that our refineries are ready for IMO. Regarding maintenance program for Q4, Normandy, there is a planned maintenance that will impact Q4. Once again, our refinery, all the investment has been done in our refineries. We are ready to benefit from IMO next year. Of course, to be able to capture potential additional margins, so we will plan to run as much as possible in our refineries.
Right.
Once again, it's very difficult to anticipate the refining margins. Our objective is to be ready to be in a position to capture additional value.
Okay.
M&A, you know we closed the Mozambique LNG acquisition. It was end of September. By the way, it was a very good achievement because we signed the SPA with Occi, it was in August, so we are in a position to close this part of the deal in less than two months. Once again, we consider Mozambique LNG as a jewel in this acquisition, so we are more than happy to have been in a position to close this Mozambique part of the deal.
Regarding the additional assets, so Algeria and Ghana. The discussions, I would say, with the authorities are still ongoing. We expect to be in a position to have the closing in 2020. Later, we will see the result of this discussion. By the way, we are of course, familiar to these kind of discussions. When we acquired the Maersk portfolio, we had this type of discussion, in particular, in Algeria. We'll see and we expect to have a closing in 2020.
Great.
Regarding the cash generated by these new assets, the cash flow that we anticipate at $60 per barrel, is more or less $700 million a year over 2020-2025.
Okay. You could expect that to be reduced off the consideration between the effective date and closing. Would that be fair to assume as we think about that?
Of course, the price will be adjusted according to the cash flow generated between 1st of January 2019 and the date of closing. It's normal way of managing acquisition in the E&P business.
Yeah. Great. Thank you.
Thank you. The next question comes from the line of Jason Gammel from Jefferies. You can ask your question.
Thank you very much. Jean-Pierre, I just wanted to come back to the strong production performance in 3Q. You did make reference to the strong contribution that you had from the five big major capital projects that have recently started up. I was hoping you might be able to address how near plateau production or peak production each of those projects are. My second question in the LNG business, you made reference to the start of the first train at Cameron LNG or first commercial operations there. I was hoping you might be able to address the attractiveness of exporting LNG from the U.S. Gulf Coast currently, given gas price environments as a general statement, and then how TotalEnergies's regasification and shipping assets might help to enhance that profitability.
Okay. For the first nine months of this year, the production is up by almost 9%. The figure is 8.7% compared to the same period in 2018. As I have already mentioned, the main contribution came from Yamal LNG, from Ichthys, but also from Kaombo, so our deep offshore asset in Angola, with 2 FPSOs. Egina, so a deep offshore well asset in Nigeria. Of course, the contribution of all the Maersk Oil assets. We confirm, we gave a guidance of production growth of 9% this year. Yes, we confirm this guidance. Regarding the big projects, so if you have in mind Ichthys or Yamal, I think for Ichthys, the 2 trains, they started respectively in October and November of 2018. Production, I would say, is currently at plateau. Regarding Yamal, as you know, the 3 trains started already.
We are above the nominal capacity. The fourth train is supposed to come on stream in the coming months, I think. It will contribute marginally to increase the production on Yamal LNG assets. Regarding other assets, Egina and Kaombo, that I mentioned as big contributors to production increase, the ramp-up will continue. We are, I would say, close to the plateau. In terms of ramp-up, I could add that Johan Sverdrup came into production very recently, we benefit from the ramp-up in Q4, and we'll have, at the same time, the startup of Iara in Brazil that will contribute to our production in Q4.
Thank you. The next question comes from the line of Lucas Herrmann from Exane. Please ask your question.
Thanks very much. Good afternoon, Jean-Pierre. Brief question, if I might. It's just on associates and associate dividends moving forward. Clearly, an increasing proportion of your growth or net income growth is going to come from associates. I just wondered whether you could give us any thoughts, guidance on how you see payout of that income progressing over the next short-term and medium-term. When will we move to a point where your equity associates are paying out in line with the contribution they're making towards your earnings? Can you give us any profile or idea of what the quarterly profile of pay you might anticipate or we should anticipate might be? Thank you.
Well, that's true that in our portfolio, the growth is coming from iGRP mainly and from its coherence with our strategy to develop LNG business. Yamal and Ichthys are big contributors in terms of cash flow growth through dividends. Of course, in the coming years, we will have Arctic 2 as well and Mozambique LNG. Definitely, the portion of the result coming from equity affiliates will grow.
Is it how we should model the cash that comes from that? If I look at the numbers today, for example, there's a very large negative adjustment to cash from profits from associate that is not received as dividend. Part of that looks as to have been the exceptional Novatek. Can you give us any steers?
It's clear when you compare the net operating results with the cash flow generated, you have to take into account the DD&A and the fact that on Ichthys in particular, given the level of CapEx that we have to spend to deliver the project, the performance in terms of net operating result is not the same compared to the performance in terms of cash. It's a bit difficult to reconcile net operating income with cash flow. Of course, our objective, I would say globally, is to be in a position to accelerate or to maximize dividends we can get from Yamal and from Ichthys. I can confirm to you that Yamal, for example, started to deliver a comfortable cash flow since the beginning of this year.
When should we expect Ichthys to start delivering dividends, if it's not already?
Ichthys, I think, yes. You have to remember that Ichthys project, you have to be aware of the structure of the project. You have the upstream that is consolidated in our balance sheet. You have direct access to the cash flow, and the upstream is a strong contributor to cash flow because, of course, this part is generating all the condensate production. You have a direct access to this cash flow through the consolidation of the upstream. The downstream, it's Ichthys LNG, it's another study. It's consolidated on an equity basis. Of course, the cash you generated from this asset will come either from dividends or from reimbursement of shareholder loans.
Okay. Thank you.
By the way, given that the contracts are good, the contract was signed when the prices were high, we have oil index contract. That's the main driver why we are competitive, or we think that definitely, Ichthys LNG will contribute to our cash flow generation in the coming years.
Super. Thank you.
Thank you. The next questions come from the line of Christopher Kuplent from Bank of America. Please ask your question.
Finally found the mute button. Thank you, Jean-Pierre. Sorry, I think my line got disconnected a little earlier, so please apologize if that question has been asked already. Just wondered whether you can comment on the change in language regarding the full year production growth guidance from above 9% to now should reach 9%. What's the reason behind that? Thank you.
No reason. We are at 8.7%. Once again, in Q4, we'll benefit from Johan Sverdrup startup. We'll benefit from Iara 1 startup in Brazil. There is no message, I would say, behind this wording. 9%, by the way, it's huge. We benefit from 8% last year, so it's 9% this year. I can add that we are focusing on value rather than on volume.
Okay. Thank you.
Thank you. The next questions come from the line of Bertrand Hodee from Kepler Cheuvreux. Please ask your question.
Good afternoon, Jean-Pierre. One question on U.S. LNG. You are taking some volumes from Sabine Pass train five right now. You are taking some volumes from Cameron LNG train one. You will get some volumes from train two and three. How can you mitigate, I would say, your contractual terms to make profit if those cargoes goes into Europe, at current prices? That's probably also why I think Toshiba realized they will not be able to make any money on those contract, and they pay Total EUR 800 million. Just wanted to understand, how are you going to mitigate the current environment, probably in the next two years?
We believe that the U.S. is well-positioned to supply cheap LNG. By the way, LNG is long term, in our view. We are expanding our exposure, that's true, with Sabine Pass, with Cameron. For example, Cameron LNG train 1 started up in May. We have two additional train that are supposed to come on stream next year. The takeover of Toshiba LNG portfolio will add the equivalent of 2.2 million ton per year. We see that LNG as competitive LNG supply. We have a very strong trading. This is definitely linked to the acquisition we made of Engie LNG portfolio. We have a global presence. We are a producer in the main LNG hubs. Once again, the case in the U.S., but also in Qatar, in Australia, in Russia. Just to give you the main hubs.
It allows us to make arbitrage between the different markets. At the same time, we have the capacity, the regas capacity in Europe. Definitely, we think that with the different position as a producer, as a trader, we will be able to capture all the value in this LNG portfolio. To come back more specifically on your question regarding U.S. LNG, we are short. Our purchases represent more or less 25%, but our sales around only 10%. At the same time, we are long oil. Our purchases represent 25% and our sales around 40%. It's a way for us to mitigate the risk you mentioned. Thank you.
Thank you. The next question comes from the line of Henry Tarr from Berenberg. Please ask your question.
Hi there. Thanks. Just a quick one on CapEx. Organic CapEx is running quite low through Q3. I guess we will see a tick higher in Q4, but it would need to be quite a bit higher probably to get us towards that EUR 18 billion figure. Could you talk about how organic CapEx has come materially lower this year? Perhaps, what Q4 might look like from a CapEx perspective. Thanks.
The capital investment guidance we gave in September, of course, will be in line with this guidance. I remind you that for our capital investment, so it's organic CapEx, but at the same time, the net between acquisition and the investments. You're right, traditionally, and so I just had a look at this figure very recently, so it was the case last year. The fourth quarter is higher than the previous quarter. For the full year for 2019, our CapEx should be in line with the guidance we gave in September, less than EUR 18 billion, taking into account, once again, the net M&A. For the coming years, of course, we will remain in the guidance we gave, between EUR 16 billion-EUR 18 billion per year.
Okay, great. Thanks. I guess whilst I've got you, just a quick other question on, what's the potential for the gas partnership with Adani in India?
Our objective is to position ourselves on growing markets, and particularly for gas, as far as gas is concerned. Definitely India gas markets, we see that as an opportunity. The country has set ambitious targets of increasing the share of natural gas in its energy mix. At present time, I think the portion of natural gas in the energy mix is around 7%, and the objective of the government is to increase this portion to 15% by 2030. We want to be part of this growth. Last year, we announced a firm deal with Adani Group, so it's a private Indian group. It was a JV of 50/50 on LNG to acquire the participation in Dhamra LNG and in Mundra LNG regas terminals.
We plan to develop LNG marketing in India, but also in Bangladesh, and the supply of the equivalent of 3 million tons a year from our LNG portfolio. That's true that we recently announced to the reinforcement of this partnership. Our objective is to acquire 37.5% of equity in a company called Adani Gas Limited. Whose business is to market gas and develop infrastructure through local concessions. This move, I would say, this JV with Adani, the acquisition of the share in Adani Gas Limited, once again, is very coherent with our objective to develop LNG on growing markets, and definitely India is part of this strategy.
Great, thanks.
Thank you. The next question comes from the line of Michele Della Vigna from Goldman Sachs. Please ask your question.
Jean-Pierre, thank you for the presentation. I had one question left. Could you give us an update on your discussions for progressing Papua New Guinea and Uganda towards FID? Thank you.
Papua and Uganda. Okay. Papua LNG. You know that last year we signed what we call a gas agreement with authorities, that gave the framework for the development and the fiscal term, the tax term for the development. Very recently, with the change in government, we have some discussions again with the authorities, and the gas agreement was, I would say, challenged at some point, but now the government has announced, and I think it was in September this year, that they will honor the deal. We are targeting FID for Papua LNG project in 2021. Regarding Uganda. Uganda, the project, I would say, is technically mature. We are ready to launch. We faced very recently some difficulties with the authority. We signed, it was in 2017, I think, with Tullow, to acquire parts of Tullow's stake in the project.
Given that we are not able to achieve an agreement on the tax treatment of the transaction, we decided to terminate the transaction. It's a matter for us of discipline in allocating our CapEx. We remain fully committed to move forward with the development. We'll see, and I think at the present time, it's a bit too early to assess when the FID could be taken for that project.
Thank you.
Thank you. The next questions comes from the line of Christyan Malek from JP Morgan. Please ask your question.
Hi, Jean-Pierre, thank you for taking my question. When I run the cash break-even at Total for 2019 on a nine-month rolling basis, it's $66 a barrel post CapEx and dividend, which is an increase on a like-for-like basis versus a year ago, if my math is correct. Now, I can understand this given the elevated CapEx in Mozambique, and clearly, you are paying a higher absolute dividend. However, what I struggle with is how cash break even fall meaningfully in line with the peer group if CapEx remains higher. Which leads me to my question: How do you plan to increase cash return over the medium term, say, in the form of additional buyback with the current capital frame? In this context, do you think disposals need to ramp up?
Would it be fair to say that additional cash distribution over and above the EUR 5 billion buyback beyond 2020 is now directly a function of increased disposals? If you can elaborate where you think the opportunities are in divestments, that would be great.
Regarding our asset sales, we mentioned a program of EUR 5 billion of assets that will be sold over the period 2019, 2020. We are on track to deliver this program. By the way, as of September, we performed or we have equivalent of EUR 1.6 billion of assets sold. We very recently, it was today, we mentioned that we were able to sell part of our Brunei assets to Shell, it will contribute to this program. At the end of this year, we will have more or less, performed 50% of the program. We do not need, I would say, to speed up or to accelerate on this program. Of course, it's a matter of opportunity. We continue to be opportunist. If we have some very attractive deals, why not enter into that deal? Once again, we do not need to accelerate this program.
Our pre-dividend break-even is below $30 per barrel. Over the first nine months, you know that for us, maintaining this low break-even is key and it's part of our strategy. What can I add? It is true that we increased the dividend, with the new guidance, 5%-6%. You can do your math, starting from this pre-dividend, organic break-even, adding the CapEx, the M&A I mentioned to you, and the dividends, more or less $8 billion a year before this 5%-6% increase. Yes, you can calculate your post-dividend break-even.
Just to be clear, I mean, on a post-dividend view, assuming all else is equal, should it be fair to say we should rule out additional buybacks over the medium term?
I was clear, I think, regarding our strategy beyond 2020. We will act according to the priority given on our cash allocation. The main message of the investor day, once again, was the acceleration of dividend growth. For us, is the tradition, the demonstration that we are very confident in our capacity of delivering additional cash. Once again, having a strong balance sheet is key and is another priority, and having a gearing below 20% is a priority. I have a very strong takeaway from Patrick de La Chevardière, my predecessor. He told me in 2015, we enter into the downturn having a gearing above 30%. I think at that time it was 32, 33. I do not want to be in the same position. I want to keep my agility to act countercyclically if we can see some opportunities.
That's why the balance sheet is the priority. At the same time, we are clear that the buyback will be used beyond 2020 to share extra revenues with our shareholders above $60 per barrel. By the way, in 2019, we bought back the equivalent of $1.15 billion of our shares end of September, and we'll accelerate the program over the fourth quarter with an additional $600 million buybacks. We are committed in delivering the $5 billion program announced in February 2018 over the 2018-2020 period.
Thank you very much.
Thank you. The next questions come from the line of Alastair Syme from Citi. Please ask your question.
Hi, Jean-Pierre. I just have one question. Yesterday, one of the leading players in European wind stood up and admitted that essentially all their economic models are wrong. It feels very symptomatic of a market that's probably chased more and more aggressive assumptions in low carbon to make marginal economics work. I just wanted to get your perspective. Really the question is: You look at the low-carbon space and your ambition to grow, do you get a sense that there's still many people out there that have very low hurdle rate thresholds or aggressive assumptions to try and grow their businesses?
I will not comment on BP, but I can tell you.
It is not just about BP.
our economic models are right. We are clear that we'll allocate more or less 10, more than 10% or around 10% of our CapEx in low carbon businesses in the coming years. Wind farm, offshore and onshore, are part of this strategy. We will use for this capital light model. I have already commented how we plan to leverage on this project to obtain, I would say, an acceptable profitability as far as our equity is concerned. Wind, yes. Wind farm, both onshore and offshore, they are part of our strategy.
Yeah. Just for reference, it wasn't BP. It was Ørsted that is sort of held up there as being one of the leading players in European wind. Yeah.
We participated to the bid in Dunkirk offshore wind very recently, by the way, with Ørsted. We are not successful, but we are not disappointed by the way, because if we are not successful, that means that the project could not fit with our economic criteria. We see we are not in a hurry. We are sure that a very profitable project that could meet our criteria will come in the coming years, so we have to be patient.
Can I ask on something like Dunkirk, are you close to being a winning bid, do you think, or are you far away from where the market's at?
I will not comment on that.
Okay. Thank you.
Thank you. The next question comes from the line of Jason Gabelman from Cowen. Please ask your question.
Yeah, thanks. I wanted to ask the equity affiliate dividend question a bit differently and specific to the LNG projects. Are the dividends that you receive from these projects once they're fully ramped, are they kind of on a straight line consistent basis, or is there a phasing element because the projects have to pay down project level financing at the project level first, and then as that gets paid down, you get an increase in cash streams from the projects? Then just two quick other questions. Firstly, on the other African assets that have to close, is there a point in time next year where if the assets don't close, you can walk away from the deal, and is that something you would be looking to do? Then just on the financials, there was a large Forex impact this quarter.
I think it was over EUR 1 billion. Can you just talk to what that was related to and if that's expected to persist or reverse going forward? Thanks.
Okay. Regarding equity affiliate dividends, I think each project is different depending on the project financing. In most of the cases, you are allowed to pay dividends. Of course, at the same time, you re-onboard the debt. It depends on the documentation, in fact. Regarding African assets of Anadarko, I'm not sure to really understand your question. What do you mean?
Yeah. If the asset sales don't close in 2020 because there's some reason they're being held up, maybe on the regulatory side in Ghana or Algeria, are you able to walk away from buying those assets given kind of the crown jewel, the Mozambique part of the sale already closed? If you do have the ability to walk away from buying those assets, is that something you would be willing to do?
As I mentioned already, so the discussion with Algerian and Ghanaian authority are still ongoing, so I cannot anticipate the outcome of the discussion, even if, of course, we are optimistic. Let's wait and see. We continue to expect this closing in 2020. Of course, I cannot preempt the decision from the authorities. Let's wait and see. Once again, in our view, the duo of the Anadarko assets, it was Mozambique LNG, and so the deal was closed. It's a very good achievement for us. The foreign exchange effect in Q3, you mean for the results or for the cash flow?
Yeah, on cash flow.
On the cash flow, the main impact is in fact for our dividends, because you know that our dividend is denominated in EUR. Of course, depending on the parity between EUR and USD, the amount in USD could change. I could add that for the results itself, the sensitivity to the EUR-USD is very limited. By the way, you have all the sensitivities in our documents, once again, it's very low.
Sorry, is that the dividend payment from past periods or in future? There was no dividend outflow for 3 Q.
Sorry?
You said the Forex impact was related to the dividend, but there was no dividend outflow in 3Q, so I'm wondering if that's related to a past period dividend outflow or future period?
In Q3, there was no dividend, but by the way, we cleared the situation, and in the coming quarter, you will have one payment per quarter.
Okay, thanks.
That was the last question. Perhaps to summarize our results, I would say that once again, during this quarter, we demonstrated that our strategy to reduce the break-even and to upgrade the portfolio for long-term sustainability worked well. The project we have in hand provide clear visibility on strong cash flow growth for the coming years. Based on this, we are confident that we can create value for our shareholders. Thank you for your time and attention.
That does conclude our conference for today. Thank you for participating. You may all disconnect.