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Golar LNG Ltd
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Good day and welcome to the Golar LNG Partners Third Quarter 2018 Conference Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Mr. Iain Ross. Please go ahead, sir.
Thanks Operator. Good afternoon, good morning everyone. Welcome to the Golar LNG third quarter 2018 results presentation. I'm joined today by the Golar CFO Graham Robjohns, and our Head of Investor Relations, Stuart Buchanan.
Today’s results reflect the first full three months of Hilli FLNG production and the start of a resurgent shipping market. And Golar is pleased to be able to report improved revenue, EBITDA and net income for the quarter and we expect further growth on these in the fourth quarter and into 2019.
Before we discuss the operating sectors, I’d like to Graham to take you through the numbers in more detail. Graham?
Thank you, Iain. And good day to everybody. I’d like to start on slide three, the financial highlights. And commencing with the income statement. As anticipated and communicated in last quarter’s earnings release, revenues from vessel operations, predominantly from the Cool Pool, increased significantly during the quarter, as a result of a strongly improving shipping market.
Our fleet utilization rose from 62% in Q1 to 86% in Q3, and daily time charter equivalent earnings rose from $19,600 in Q1 to $41,200, representing $48,100 per charge fuel diesel of electric vessels and $11,000 for steam vessels.
The TFDE rate was impacted by the dry-docking of one vessel as other Cool Pool vessels earned [ph] slightly over $50,000 a day. We expect Q4 to show further significant improvement and have guided TFDE vessels TCE between $85 and $95 per day for Q4.
Adding to these improved shipping revenue numbers was an increased contribution from the FLNG vessel Hilli for sale which completed its first full quarter of operations which was without any commercial downtime and therefore maximum base totaling fee was achieved.
In addition to the approximately $51 million of tolling fee revenue, we also earned $11.3 million of Brent linked revenue which kicks in when Brent is above $60 per barrel.
Total operating revenues net of voyage chart higher and commission expenses therefore increased from $42.9 million in Q2 to $98.4 million in Q3. Total operating vessel expenses increased $8.4 million to $28.9 million in Q3, largely as a result of the increased operation time for Hilli, the cost which is slightly higher than expected average operating costs for this vessel however.
Taken together, admin and project development expenses were lower than Q2. The major part of the project development expenses was continuing fee costs incurred in respect of the FLNG conversion project for the BP-Kosmos Tortue project.
Admin expenses also include a non-cash charge of $3.7 million in respect of share options. The Brent linked component of Hilli sales invoice sale generates additional annual operating cash flows of approximately $3 million for every dollar increase in Brent crude prices between $60 per barrel under contractual ceiling.
Monthly billing of this component is based on a three month look back at average Brent crude prices. This high component for the quarter amounted to $11.3 million. The fair value of the derivative asset i.e. the value at September 30 of the potential future cash flow from the oil linked high component increased by $77.5 million during the quarter, with a corresponding unrealized gain of the same amount.
Other operating gains and losses reported a third quarter gain of $23.3 million for the quarter. The cash recovery of $26 million was made during the quarter results of proceedings in respect of a former contract for the Golar Tundra and mitigating the Q3 cash flow recovery and respect to the Tundra was an FLNG related cost of $2.7 million in connection with the dissolution of OneLNG. Future costs in connection with dissolution are expected to be minimal.
Depreciation and amortization increased as a result of full quarters operation of the Hilli Episeyo, similarly interest expense increased by $6 million to $32.6 million mainly as I said due to a full quarter’s interest expense in respect of Hilli.
The third quarter reported $10.7 million loss on derivative instruments compared to a 2Q loss of $0.1 million, and this includes mark-to-market valuations on total return equity swaps, interest rate swaps and the Golar’s Partners Earn-Out Units derivative. Other financial items reported a Q3 gain of $2.5 million when compared to $1.7 million in Q2.
The $2.7 million in Q3 equity and net earnings of affiliates includes $4.1 million loss in respect of Golar’s 50% share of Golar Power, an income of $6.9 million in the respect of Golar’s stake in Golar Partners.
Net income attributable to non-controlling interests represents external interests in the Hilli sale and the finance lease variable interest entities. As a result of the above, we report net income attributable to Golar LNG shareholders for the quarter of $66.2 million, which is a 90% increase from $36.3 million in Q2.
Turning over to the balance sheet, our total cash position as of September was $764 million including the long term restricted cash, which $206 million was unrestricted and $175.5 million were -- likes including 50 relates to the Hilli Episeyo letter of credit collateral support.
Of this $175 million, approximately $126 million is expected to be released to free cash between 2019 and 2021.
During the quarter, most of the payments due in respect of the Hilli Episeyo conversion dropdown transaction were made, there are still some final CapEx spends we made in Q4, which amounted to approximate $38 million. A payment of $24.8 million is also being made in Q4 in respect of Golar’s 25% interest in Avenir and against this a further $14 million has been received from the former charterers of the FSRU Golar Tundra.
Golar’s net debt at September 30 was $1.86 billion, an analysis of this can be found in the appendix of this presentation. Also, a reconciliation of our balance sheet debt, which includes the consolidated VIEs to our legal debt, is included in our earnings release.
Turning over to slides five, over the last five years or so we've invested some $4 billion in new ships, FSRUs and FLNG vessel and a gas fired power station. During this time, we have endured one of the worst ever LNG shipping markets and suffered a dramatic oil price collapse. However, we have still managed to contract a significant amount of these assets and finance them.
It's been tough for us, and it's been tough for shareholders and we're therefore delighted to see that a significant amount of light is now appearing at the end of the tunnel, and that cash flow is now beginning to flow.
As we have grown and developed, it has been commented by some that we are a complicated company. We don't see it like that. We see that we have three business lines; shipping, FLNG and FSRU using power in addition to of course an MLP.
In the last three years, apart from Golar Partners, none of these business lines have generated any cash flow. Today shipping and FLNG are generating cash flow and from the end of next year, all three businesses will be generating significant cash flow.
So on this slide, we have taken actual Q3 adjusted EBITDA results and further adjusted for one-off items and Golar Partners share of Hilli’s contribution. We have then multiplied by four to show annualized EBITDA as $173 million. It should be noted, however that this effectively includes approximately $15 million of non-cash share option expense and approximate $22 million project development expenses, which are mainly related to the BP-Kosmos Tortue projects fee costs that we cannot capitalize yet.
We've then added and assumed as an assumed TCE rate of 80000 a day for the drive fuel vessels which in today's market looks pretty likely. We also have the impact of the Hilli Train 3 option being exercised, as well as the impact of the contracted cash flow from Sergipe and Nanook, which altogether brings us to an annual EBITDA of just over $500 million based on our current business.
Turning to the next slide, we've taken the $502 million of EBITDA and shown it by business line. We've also shown indicative 2020 total debt service by business line and as you can see this shows a net EBITDA less [ph] debt service of $242 million per annum.
Again, this is net of the annualized share option expense and project development costs for a total of $37 million. Additionally, it reflects a relatively high level of debt amortization particularly with regards to Sergipe project, which has a 25 year contract life, but an average debt life of nine years.
Also reiterating again this is based on our current fully financed business. An analysis of adjusted EBITDA and indicative debt service can be found in the appendix of the presentation.
Thank you. And with that, I’ll turn back to Ian.
Thank you, Graham. Starting with FLNG on slide seven, and Hilli Episeyo continues to perform well and as Graham mentioned, we've got 100% commercial availability and we are in the process of offloading our 10th cargo.
Production has been stable with no material upsets over the quarter. We continue to learn from operating the vessel and both the offshore and onshore teams are generating unique and valuable knowhow and we are turning that knowhow into differentiated corporate experience with every month of production.
In terms of increasing production, into Train 3, we continue to have constructive dialogue with Perenco, and in line with previous guidance we hope to be able to confirm the proposed timing of that production increase by the end of this year.
Then moving on to BP’s Tortue projects, as a reminder, that projects to supply an FLNG unit similar to Hilli on a tooling basis for 20 years, which will be located offshore Mauritania and Senegal. We’ve completed the feed and we're making good progress as we continue preparations to move into the execution phase.
BP continues to guide publicly towards a decision to go ahead with the project in 2018, and we'll be ready to move forward on the project in line with BP’s timetable. This project is our number one focus right now for an eminent FID.
On Fortuna, we have no material update but confirm that we continue to work the financing solution. We continue to work the technical solution, and we continue to finalize a replacement equity partner in the project. As before, we're not making predictions, but we just want to clearly communicate that we have not given up on that project.
A few words now by the Delfin project, which has become more interesting in recent weeks. Delfin is based on our Mark II FLNG design, that can liquefy over 3 million tons per annum at a similar cost per ton to Hilli, and we expect it to be able to deliver the lowest cost liquefaction solution in North America when connected to Delfin’s existing pipeline infrastructure.
A revised ownership structure and leadership within Delfin has created momentum on the project and we are currently in discussions with the Delfin team to establish a joint way forward on the project, and our next activities will be to conclude the development of a vessel specific agreement, and then move on to progressive technical work in parallel with supply and off-take considerations.
Delfin project is a clear candidate for FID later in 2019. Other FLNG opportunities continue to be developed, and the frequency of inquiries is also increasing on the back of a stable Hilli operations.
Turning to shipping now on slide eight. The spot shipping rates continue to increase in line with a market that's becoming increasingly tight on available capacity to move cargoes. Our second quarter TCE doubled into Q3 and with continued upward pressure, and based on the fixtures we have to date, we expect this will almost double again in Q4.
Continued strong demand from Asia underpins a forecast 10% year-on-year growth and production to some 388 million tons per annum by 2020. Growing 10 miles from an increase component of U.S. based deliveries, confirms that the market appears to be short some 30 to 40 vessels over the next two to three years. And the inability to get new orders delivered before 2021 indicates higher rates over the coming years.
If we consider the last shipping cycle, which ran from 2010 to 2013 and had steam ships as a reported average TCE of around $118,000 a day, that cycle had a limited number of available vessels driving the rates.
We have a very similar dynamic happening today and with some short term spot fixtures reportedly running well above $150,000 a day today quite early in the cycle, this is signaling potential for the rates to average higher than the last cycle.
Correspondingly, we see -- we expect to continue to increase in term related inquiries and probably see some better convergence of charters and owners expectations sometime in 2019. We also continue to examine different options for creating shareholder values with different solutions for the shipping fleet.
As stated in earlier reports, Golar is continuing to work with other LNG ship owners to try and establish a consolidated structure, which will give LNG shipping investors more direct exposure to the LNG shipping market, and good progress has been made over the last quarter.
Turning now to small scale LNG. Small scale LNG and downstream distribution markets interest us for a couple of reasons. Firstly, the market's relatively immature, but ready for growth, and secondly there's a shorter CapEx cycle and developing small scale LNG compared to the larger FLNG and power projects.
So our initial approximately $25 million investment in Avenir, which is owned by Stolt-Nielsen, Höegh and Golar represents our effort to stimulate this market and in doing so, gain an early position.
Together, these three companies have committed a total investment of $182 million into Avenir of which Golar share will be $45.5 million. Avenir is expected to list on the Norwegian OTC in the coming weeks.
Small scale opportunities to be pursued by Avenir include delivery of LNG to areas of stranded demand, development of LNG bunkering services and supply of LNG to the transportation sector.
Savings as a result of high-margin oil-to-gas switching, policy changes including IMO2020, and the environmental merits of LNG relative to other fossil fuels are all expected to generate significant growth in this sector.
Avenir has taken FID on an LNG receiving terminal in Sardinia, which is targeting local distribution of LNG and Avenir has also ordered four 7,500 cubic meter vessels which will be delivered progressively from the end of 2019.
And of note, logistics and shipping services provided by Avenir may also be utilized in the event that Golar Power elects to use some of the spare capacity on board the FSRU Golar Nanook to break-bulk LNG in Sergipe
So on that turning to Sergipe and Golar Power on slide 10, the Sergipe Project in Northeast Brazil continues on schedule to start operations in less than 14 months. Construction is progressing well with module installation and hookup being implemented by a team of over 2000 people on the site.
The gas and water pipelines are being installed along with construction of dissociated pump houses and receiving facilities. The project is fully funded with all equity paid in.
FSRU Golar Nanook was delivered to us in September and is now steaming to location and is scheduled to arrive next year in order to start commissioning activities for the power station. The next Brazilian power auction is now scheduled for the first quarter next year and we are well positioned with several projects including of course the potential for an expansion of Sergipe and ready to participate.
The FSRU market outside Brazil remains pretty competitive, and we're selectively considering and bidding on a few of the many available opportunities that are out there. We do have active tenders in several continents and hope to convert one or more of these into term contracts in due course.
We remain interested in FSRU projects that go beyond a simple vessel contract and involve downstream infrastructure such as terminals, pipelines and power stations. Noting that further breakdown of LNG into smaller scale distribution can increase the attractiveness of the project.
Turning now to the summary and outlook. FLNG Hilli Episeyo delivered $52.3 million of EBITDA this quarter. Golar and our charters are pleased with the vessel's performance, and discussions continue on the utilization of the vessels spare capacity. We remain focused on being able to support BP and the Tortue project and are progressing the development of additional FLNG opportunities, including Fortuna, Delfin and others.
The shipping rates scenarios that only a few months ago may have been feared ambitious are beginning to materialize. Third quarter EBITDA from vessels and other operations amounted to $38.7 million based on a fleet TCE of $41,000 a day. For every $10,000 a day increase in TCE annual EBITDA from ships trading in the spot market will increase by approximately $40 million. We expect to deliver fourth quarter TCE in the range of $70,000 to $80,000 based on our current fixtures including TFDE and vessel TCE in the range of $85,000 to $95,000.
We expect to see further improvement to Q4 EBITDA and cash generation from shipping in the first quarter 2019. Golar Power is less now less than 40 months away from commencing regas and power generation operations at its Sergipe power plant.
Upon commencement in January 2020, and assuming those dispatch, this is expected to generate around $100 million in annual adjusted EBITDA per year and $45 million after the deduction of debt service.
A prolonged period of investment of around $4 billion in an LNG infrastructure covering carriers FSRUs, Hilli Episeyo and Sergipe is drawing to a close, and has been a challenge but concepts and investments are finally being transformed into operations and cash flows.
It is Golar’s intention to use this increasing cash flow to continue to grow the company through prudent investment in the right projects concurrent with increased distributions to the company shareholders.
With that, I would like to hand back to the operator for questions.
Thank you. [Operator Instructions]. We can now take our first question from Jon Chappell from Evercore. Please go ahead. Your line is open.
Thank you. Good afternoon Ian, I appreciate the comments on the spare capacity on Hilli and I understand your negotiating process right now are the conversations right now, but just curious end the year is noticed a couple weeks away or a few weeks away or a few weeks away, what’s left that needs to be done. Is there something that's strictly up to you and Perenco on finalizing the terms? Is there something that needs the government to sign off on something, and I think we've been so focused on just the 25% capacity of Train 3? Is it realistic that Train 4 can be included in this end of year time frame as well?
A couple of comments on that, John. First of all we, so we do already have a contracted position with Perenco for Train 3. We're discussing with Perenco Train 3 and Train 4 in terms of potential, and getting into that level will require government engagement with Perenco, and we’ll leave those discussions internally to those two parties.
We are also aware that Perenco is under way with compression increase, the on shore site to allow additional volumes of gas to come through and what we like to do is just allow those discussions to play out, so that when we advise, when we think that the third train's going to be utilized and the potential for the fourth train at some point in the future after that we can do it without any caveats around it.
Understood. My second question then, the Delfin commentary was surprising and just that it seems like it's moving forward. I was unaware that they'd have had a leadership transition there. So you'd mentioned late 2019, FID, realistically, what's the startup for that potential project and we know it's obviously a significant amount of gas, or are we thinking, are you thinking just one asset first with options on the others or is it realistic that upon the startup it could be a multi-year asset field?
The way that we are focused is that, let's -- let's get one project away before we get carried away only on the others. So the timescale for building our Mark II we're still working on that. But it's going to be in the order of the same sort of period of time of three and a half to four years. I'd like to say, we're focused on getting one away. And if we do, if we can get that source and get an FID next year on the first train, we'll be more than happy.
Okay, thanks for the comments. And I'll turn it over.
Thank you. We can now take our next question from Randy Giveans from Jefferies. Please go ahead. Your line is open.
Thanks Operator. Good morning and good afternoon gentlemen. Quick question. Looking at Slide 5 you show an additional FLNG EBITDA $95 million as the run rate. Now, what are the components of this? I guess specifically, how much of this is related to Train 3 and how much is related to maybe additional Brent-linked upside?
It's all related to Train 3, Randy. It's effectively the contractual it's assuming the contractual option that Perenco have gets exercised, and at the current Brent price, that's what the economics look like.
Okay, Perfect. And then on the LNG shipping side. Well what is the current utilization and what rate did kind of your most recent charter get fixed at basically, just seeing if you see any fixtures getting down at these headline levels of 150, 160, 170,000 a day?
We’d had a report that Q3 crystallization was 86%. And I think Ian referred to charters have been done well above the 100,000 level in the market. I don't think we're going to comment on specifically what our leading edge rates are, but it's those are the current market rates.
Okay, so 3Q 80% and then currently all the vessels in the Cool Pool still employed, so 100%utilization as of today for 4Q?
Yes, Cool Pool vessels are busy.
All right. Well I’ll turn it over. I’m sure these were the questions. Thanks so much.
Thank you. We can now take our next question from Michael Webber from Wells Fargo. Please go ahead.
Hey, good morning guys. How are you?
Hi, Mike.
I wanted to circle back to your first couple answers. So when I look at the deck, one of the things that jumped out to me are that Delfin is making an appearance for the first time in a while and then you're highlighting the fact that you could you get some clarity around clearly by Train 3 by the end of the year. But I guess – [Indiscernible] what I heard the answer didn't seem a whole lot different than the commentary we got last quarter. But just curious if I think about aside from the management change at Delfin, I guess, has there been a material change there in terms of the commercialization process or something that would justify I guess kind of moving at up or making that more prominent within your project pipeline? And I get the same question for Hilli Train 3 in terms of maybe the level of engagement between Perenco and the government. When I read that the release, I assume that there was maybe an uptick in conversations there and I think we started make progress. Maybe what’s incrementally different about those two processes today than last quarter?
If I take the Perenco story first all, obviously there’s a limit to what I can say publicly in terms of what is decided and defined. I can see a pathway to Train 3 being engaged with us. But until Perenco tell me that they've aligned everything internally in their own organization with the government I’m not liberty to expand any further. I just trying to reiterate the fact that we feel confident that we'll have some guidance by the end of the year, and that, things are progressive -- progressing on a positive keel there.
And in terms of Delfin, simply pointing to the fact that Delfin in terms of the Delfin company itself, they’ve reached their shareholder and they’ve got some new leadership there that’s going to revise and increase enthusiasm, momentum on the project. And after a little bit of a lull over the summer this new leadership and enthusiasms translating into stronger engagement with us, and that’s stronger engagement with us is also translating into more focus and momentum and trying to get the solution on the project, so, its incremental progress. I just feel it's worth mentioning that for Delfin because of that renewed focus that we’re seeing from the other side of the table.
Okay. All right. That’s helpful. Just one more from me, obviously LNG carrier rate have gone kind of fairly volatile recently. Just in terms of using that carrier upside as leverage in terms of FSRU contracting, now that there’s a viable tonnage of stream of employment. Are you noticing that are you or the people you’re competing with the market frankly for the opened FSRU capacity. Are you guys able to use that as leverage to maybe start inching up returns back to where they use to be for some of the FSRU relates? Or is that something we’d more likely see in kind of 2019 or 2020?
Yes. We’re not seeing it yet. It’s a good point and we’ve talked about that lot internally, but we’re not seeing it yet. I mean the good news of course, is there any conversion candidate or actual FSRU such as Tundra continues to trade well in the spot market. But you would think that soft conversion is likely to happen sooner rather than later. But we haven’t seen it play out yet, I think partly due to the fact that there are several FSRU vessels due to be delivered and still a little bit of an oversupply, but you’ve got to think that you’re going to be more aligned.
Okay. All right, guys. Appreciate your time. Thank you.
Thank you.
Thank you. We can now take our next question from Ken Hoexter from Merrill Lynch. Please go ahead.
Great. Good morning here and good afternoon there. Iain, just you mentioned on the power auctions, hey, Graham. On the power auctions I think you mentioned delayed until the first or now it’s going to be in the first quarter. I though last week you’d mentioned maybe in November/December. Anything on the – change in the process or any update on that?
No. I mean that’s in the – it’s in the hand of the Brazilian government. I have no idea why it’s been delayed and there’s nothing untoward about. Its just they’ve decided that’s when the next power auctions is going to be. Our understanding is it’s an auction that we might be interesting in participating in. And as I’ve kind of indicated in the prepared remarks, we’ve got a number of sites that are really well advanced and we think one or more has some competitive advantage there. So we look forward to results since next year.
Any change there or any commentary from the government given the new – as the new government rolls in on that process? Or you’re saying just a little slight delay, nothing more to it?
I’ve had nothing back on the team on the impact. It’s the earlier days for new government. I mean, we’re watching that with interest obviously but I don’t believe that that it necessarily related, but it could be.
Okay. And then just my second one, follow-up on the rates – just as obviously the strength we’ve seen recently. Is there anything to suggest this is – I guess, how do we interpret? What if this is this normal seasonal spike that we would see at this point in the year versus what you see as more sustainable given the supply demand dynamic?
I talked to our chartering department several times every day. And it would appear that the number of available ships and a number of cargos that are after those number available ships are somewhat disconnected already and so we’re [Indiscernible] of a very high rates, spot rates in the market. And of course a very high rates that you hear for short term voyages. But my personal belief is this is something more than the seasonal spike of the rate – the steepness of the rates have increased. So I think it's all the information I’m getting would suggest, it's more like the cycle that we saw between 2010 and 2013. It certainly has the makings of being of that ilk.
So do you keep them operating in the spot or do you move to charter them on a more – out of the pool, I guess?
Well, right now we’re keeping operating them in the spot. But I would say in terms of term business, what we think we’ll happen is sort of half way through towards the second half of 2019. We’ll start to see conversions of the amount of time that we would be prepared to fix vessel out for and the desire of the charter. Right now, it’s too early in the circle for us to give up which could be – what could be a bit of advantage for us later on. So, I think it’s too early to think about fixing on the longer term, but certainly the enquires are coming in. It just those enquiries that are coming are not attractive enough yet for us.
Great. Thank Iain and Graham. Appreciate for the time.
Yes, Ken.
Thank you. We will now take our next question from Fotis Giannakoulis from Morgan Stanley.
Yes. Hi, gentlemen and thank you. Graham, you mentioned earlier that we shouldn’t rule out Fortuna project. And I’m just trying to understand what is the room for this project to be revived? Is there a possibility of the license agreements between Ophir and the government to be extended beyond year-end or is this going to be a binary result? And how quickly can Asian shipyard move in regards with the contract for an FLNG conversion and the associated financing package?
It’s Ian. I’ll take that, Fortis. Just working back from the end, discussions with the financing in Asia continue to progress well as do the conversations around the technical solution. So first, if we end up with a -- say for example, we end up with the Chinese-based solution as opposed to Singapore-based solution. That will add a little bit of time on to any project as that transaction takes place. So, but other than that things are progressing very well. In terms of the Ophir PSC extension, that's obviously a matter between Ophir and the government [Indiscernible] and that’s a key item. If that PSCs extended then there’s life in Fortuna, and conversely if it's not extended then there won’t be much life I would expect so. But we’re continuing with what we’re doing in both the technical, commercial and partner related areas in anticipation of a positive outcome.
Thank you, Iain. I want to ask you about the competitive landscape for new liquefaction projects especially after the LNG Canada, FID that it does not have aligned or end users or offtake, and it seems that also Qatar is going go ahead without having aligned customers. Is it a new norm in order for new projects to FID? Do they need to have the backing and to able to – that the financial bank to be able to go ahead even before the customers are aligned? Then I want to ask specifically about Delfin, if Delfin can take FID without long-term offtakes?
So, I think it will depend very much on how the project proponent is and how they’re funding the projects. So if you’re big oil and you’re funding project through equity I think its much more straightforward decision to take on whether you’re aligned behind an offtake or not. If you're a smaller entity such as we are then project finance plays a big part in the equation and obviously what we will be looking to in any project is a minimum, is to cover debt service and operational costs on any project through to some form of offtake.
But on that regard if you look at Delfin that's something that we’re considering, it’s a U.S. Gulf of Mexico based projects. So the finance for that you would think will be fairly straightforward and for us considering debt service coverage in OpEx as the starting point for an offtake not a bad place to start. I don’t if that answers your question. Whether it’s a new norm or not, I think this spot market and LNG is going to continue to increase and projects again it just depends how they’re financed whether it's through debt or equity and what combination of both.
Thank you very much, Iain.
Thank you. We can now take our next question from Chris Wetherbee from Citi.
Hi, guys. James on for Chris. I want to ask about 2019 and the dividend. It seems like its going to be a pretty solid cash flow year, but how do you going to balance potentially dividend decreases if possible, other claims on cash like other projects are ramping up?
Well, I think as we refer in the earnings release, desire and intention to grow the distribution, but that will be dependent on cash flow generating success which is obviously and probably dependent on how well the shipping market does. And it’s related to capital need. I think we’ve also said that, given our cash position the amount of operating cash flow that we’re going to be generating in the next couple years and also the $126 million of cash is coming out of the restricted LLC of next few years. We’re in a pretty good position to finance the next project.
All right. Got it. And then on Avenir, I want you talk about possible synergies online that improving utilization for assets. What are the synergies into the market developments might tie directly into some of the existing projects you have from there?
Well, just expanding on the example. If we take the new FSRU sitting there with two-thirds of its capacity not being utilized because this Sergipe power station 1.5 gigawatts, only requires a third of its capacity. If we take the example where we could use one of the small Avenir ship to break bulk on there and transport LNG. We can take that through then local rivers into different destinations and think of two possible scenarios. So the first scenario is where you put the LNG into isotainers, send them upriver on the smaller barges and into local gas-fired power station. So distributed power generation, that gas is displacing diesel and there’s a very strong economic argument in terms of the cost, the cost equivalency of using LNG as a fuel rather than diesel, not only that there’s obviously a strong environmental argument.
And the other one around transportation involves a similar arrangement in breaking bulk down from the big FSRU into smaller ship transferring that round into containers and using that to fuel an LNG trucking fleet. And I don’t know if in Brazil, the LNG trucking fleet is pretty massive, and then have road trains moving up and down, massive road corridors moving crops to the coast and to the export port. And if you took those diesel fired trucks and transfer them into LNG, again you get this double benefit of low cost. So it’s a benefit to the owner and also the environment benefit.
And just to put some reality on that, there’s some work being done in parallel that’s demonstrating that we can get an LNG fueled truck and into Brazil fully sort of imported for the same prices as diesel truck, so this is a real thing that we believe is going happen. And that’s an example of how this small-scale market can unlock avenues for distribution of LNG. An Avenir’s business is not about fueling trucks and owning trucks. It’s about distributing LNG.
All right. Got it. Thank you.
Thank you. We can now take our next question from Donald McLee from Berenberg. Please go ahead. Your line is open.
Good morning, guys. So, first question goes back to your comments on the cyclical versus more spike in LNG Carrier rates. On what role do you believe the pending increase on January 1 on LNG tariff in the China might've played in helping to support higher rates as well?
I don’t know it’s made that much of a difference that we can see at this point.
Okay. Got it. And then looking at the Hilli, sorry…
I’m just going to add, there are so many reloads going on whether that’s LNG coming from the north from Yamal. I think the whole movement of LNG and their reloading in more spot nature of the market is probably obscuring any direct line of sight to any of the sort China related embargo issues that we can see?
Got it. That’s fair. And then one more on the Hilli, has there been any change in the pace of LNG cargo being picked up from Hilli? And wondering, just get an idea of what demand might be for Train 3 potentially coming on line?
So, on the pace of cargos it’s defined for the contract and our availability, so there’s a cargo listed every two about weeks. And that as there are two trains running that will not change other than through planned scheduled maintenance averages that would change the life of the contract. In terms of the demand for Train 3 I think there’s plenty of demand there. It’s not – at this stage it wouldn’t be our cargos to deal with, that’s be something for the owners of the LNG to deal with.
I appreciate guys for taking the time and the questions. Thank you.
Thank you. [Operator Instructions] We can now take our next question from Espen Landmark from Fearnley. Please go ahead. Your line is open.
Hi, good afternoon. On the potential operation of the LNG fleet, I mean, I guess we’re finally starting to see some earnings in that fleet now of your fourth quarter guidance suggests. So, next year if the market persist that the fleet is adding substantial cash flow I guess supporting distribution and even being complimentary on earnings. I mean, is that changing and what you’re thinking around this spin-up given the majority of Golar’s kind of incremental earnings sales will materialized I guess in 2020 and later?
So, as we mentioned in our release we’re continuing to look at ways of structuring a solution there. And lot of works being going on in the last quarter and we’ll continue for this quarter. So think that’s all we can really say on that just now.
Fair enough. And maybe I mean, on the valuation on this, I mean, this carriers tell them to changed hands. So I'm curious to hear what you think 14 and 15 TFDEs should be worth in today's market kind of above the broker assessment?
I’m sure we can really comment on that, Espen. Certainly, I guess, given the way the market is going the value certainly gone up.
Okay. Fair enough. Thank you.
Thank you. We can now take our next question from Ben Nolan with Stifel. Please go ahead.
Thanks. Hey, guys. My first question is related to the Mark II which obviously you're working on with Delfin and potentially for tenant and then the release it said that it was cost competitive with Mark I. I assume that's on a per ton basis, but could you maybe give any color as to serve how your thinking about what’s the capital cost of one of these Mark II might be just to clarify that a little bit?
So you’re right. It’s competitive on a dollars per ton basis. So if you’re looking at 1.6 million, 1.8 million somewhere round there for a billion rather for something north of 3 million tons a year.
Okay. And then just to circle back around on the dividend questions that have come up, obviously the number of potential projects that you guys have is quite large and would -- if things go well consist of multiple billions of dollars worth of capital commitments. So in that framework when you think about the dividend and potentially increasing it, should we think of dividends is sort of a floating number, if cash is available and you'd pay it, but if you have a lot of projects then maybe you dial back the dividend little bit or are these sort of plateaus that you're looking at?
So, Ben, I think, we’re always going to be wanting to increase the dividend rather than decrease the dividend. So, and in looking at where we’re going with the distribution that will take into account as I said earlier that our earnings potential which is obviously not on the upward cycle pretty dramatically and also capital needs. So where we are right now with the cash resources that we have, we’re pretty comfortable about at least another FLNG projects. So I don’t think we’re going to be – I mean, its difficult to say, but we’re not – to say, its going to be floating distribution is I’m not sure its correct right now.
Okay.
I think our intent for that distribution would be stable and growing overtime. The other thing about, you mentioned that we got many, many projects, I mean, the truth of the matter is these projects are difficult to get going. So the actual number of projects that we take FID on is a lot less than the number of the opportunities that are right there. So its trying to get a convergence between maintaining good dividend distribution and hitting the right projects at the right time and doing it with a degree of confidence around the timing of those projects which is been something that we’ve not been great at in the past that we hope to get try and get better at.
Okay, understood. Appreciate. Thanks guys.
Thank you. We can now take our next question from Chris Snyder from Deutsche Bank.
Hey, good morning. My question is around the guidance. Can you talk a little about your spot rate expectations over the next two months that are underlying that $70 into $80,000 a day, and Q4 rate guidance you gave just so we can calibrate our models?
Well, so we kind of guided to the element of the tri-fuel vessels components of TCE obviously at around 85 to 95. And utilization for Q3 was 86%. We expect that to probably go up for Q4. However, you need to take into account that quite lot of Q4’s revenue has already being contracted and some of it was contracted back in Q3, so there’s always going to be a bit of a time lag in between where headline spot rates are and what the TCE rate is going to be even if you’re at sort of 95% plus utilization.
Okay. Thank you for that. And then just kind of following up on the – just comparing the TFDE guidance to the overall rate guidance to the overall rate guidance, it seems like you guys are expecting a very little impact from the steam fleet. I would have just assume that giving us how tight the market is, that those vessels would kind of see a pretty nice a ramp up here in Q4. Can you maybe just talk about those -- the two steam vessels are performing?
Sure. What it does, its neatly illustrates the point that I was just making, so one of the steam vessels is and has been on sort of medium term contract for the last couple of years at sort of relatively low rate. That comes to an end probably around January/February time. And then the other vessel has been taken out of lay-up and it’s been go through some kind of work to get her up and ready to enter into the market. And she's now booked to go on streaming in December at a decent rate, as I think we’ve referred to in the earnings release.
So, one vessel that’s on the low rate that is contracted several years ago, and one just kind of entering into the market. So the difference between Q1 and Q2 next year for those steam vessels is going to be sort of dramatically different to what we expected to be in Q4, but not this sort of time lag affect.
Okay. Thank you for that, very helpful. And then maybe just following up on Perenco and Train 3, I know you guys can bring Train 3 online without any incremental CapEx, but this Perenco have the requisite production to utilize Train 3 without any incremental CapEx or incremental field development?
So that’s part of the work that Perenco is been doing, is how it can satisfy an increased demand or supplies with enough gas, and its supplies with enough gas not for one or two years, but out for the duration of the projected life of Hilli been on station. So I know it sounds very simple from the outside, but internally it's a little bit more complex than that because it's multidimensional thing that that they're working through. I'm confident that they’re going to come up with a solution that will work for us and hopefully we’ll get that information by the end of the year.
Thank you for that. And then just a real quick modeling question. It seems like the Hilli margins were squeezed to touch during Q3 relative to Q2 which I know was only one month. So just kind of modeling forward which one is kind of the correct run rate to use or it will be somewhere between kind of the Q2, Q3 margins?
Firstly, I’m not interest in your [Indiscernible] operating cost was slightly high.
Yes.
Yes. So OpEx were bit higher in the third quarter, a bit high than the average kind of run rate, so I would sort of probably take Q2 and maybe add a little bit as a guide to where its going to be?
Okay. Thank you guys. That’s all from me. Thanks for your time, guys.
Thank you. [Operator Instructions] We can now take our next question from Magnus Fyhr from Seaport Global.
Yes. Hi, guys. Just one question related to the Delfin project, that seems like you said they’re getting more motivated to pursue that project. Can you elaborate what you think that technical challenges are on that project given it’s the first Offshore FLNG project in the Gulf of Mexico, also is the permitting process different for the Offshore FLNG versus an Onshore LNG and where do they stand in the process?
So coming from your second question back, the Offshore permitting process is quite different and the project as I understand its full permitted. That’s one of the advantages of what Delfin have done in acquiring the pipeline systems that they have. Obviously there are two main differences compared to, for example, West African production that we see the Gulf of Mexico. The first difference is, you've got to be able to disconnect the facility and steam away in the event of an adverse weather such as a hurricane.
And secondly, there’s a requirement in the Gulf of Mexico to use air cooling rather than sea water cooling. And those two elements drove the development of the Mark II design initially. So that its started out as a design focused on the Delfin project and through time it's kind of morphed into – and by the way we can use in West Africa as well because we’re getting enhanced production in terms of more volume, more volume generally means assuming that the gas if there, improve project economics. So for example, back to Fortuna if we use the Mark II design there that would have an improved project return compared to a Mark I design. Anyway, those are the two main changes and we feel confident that our Mark II design can overcome both of those.
Okay. Very good. Thank you.
Thank you. We can now take our final question from Frode Morkedal from Clarksons Securities. Please go ahead. Your line is open.
Yes. Thank you. There's been a lot of questions on the dividend. So maybe one just on the buyback potential. I mean if you look at the share price year-to-date, I think it's been flat even dumb, is it despite a very strong LNG shipping rate, Hilli being success and oil prices high. So the question is has the board signaled any intention to increase the buyback program? If, if you don't get paid in a couple of markets given what I would say is quite strong fundamentals?
We haven't made that indication. But of course it's an option. Although I would say it's kind of a little bit the same answer relative to the dividend and we've got to balance that effective cash distribution to shareholders against future capital needs. And we need to get that balance right.
Okay, fair enough. Thank you.
Thank you.
Thank you. That will conclude the Q&A session today. I turn the call back over to you for any additional or closing remarks.
Thanks, operator. So we appreciate your attendance on the call today. We hope, we have finally turned the corner in achieving sustainable profitability for the business and look forward to demonstrating that to you over the coming quarters as we build the business into the future. Thanks again.
Thank you. That will conclude today's conference call. Thank you for your participation ladies and gentlemen. You may now disconnect.