Golar LNG Ltd (GLNG) 2018 Q3 法說會逐字稿

Good day, and welcome to the Golar LNG Partners LP 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 and good morning, everyone.

Welcome to the Golar LNG Third Quarter 2018 Results Presentation.

I'm joined today by Golar CFO, Graham Robjohns; and our Head of Investor Relations, Stuart Buchanan.

Today's results reflect the first full 3 months of Hilli FLNG production and the start of a resurge in the 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 Graham to take you through the numbers in more detail.

Graham?

Thank you, Iain, and good day, everybody.

I'd like to start on Slide 3, the financial highlights, and commencing with the income statement.

As anticipated and communicated in last quarter's earnings release, revenues from vessel operations, predominately 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 for tri-fuel diesel electric vessels and $11,000 for steam vessels.

The TFDE rate was impacted by the dry-docking of 1 vessel as other Cool Pool vessels earned slightly over $50,000 a day.

We expect Q4 to show further significant improvement and have guided TFDE vessels' TCE at between $85,000 and $95,000 per day for Q4.

Adding to these improved shipping revenue numbers was an increased contribution from the FLNG vessel Hilli Episeyo, which completed its first full quarter of operations, which was without any commercial downtime, and therefore, maximum base tolling fee was achieved.

In addition to the approximate $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, charterhire 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 costs of which are 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 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 noncash charge of $3.7 million in respect of share options.

The Brent-linked component of Hilli Episeyo's invoice fees generates additional annual operating cash flows of approximately $3 million for every dollar increase in Brent crude prices, between $60 per barrel and the contractual ceiling.

Monthly billing of this component is based on a 3-month look back at average Brent crude prices.

This hire 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 hire component increased by $77.5 million during the quarter, were the corresponding unrealized gain of the same amount.

Other operating gains and losses reported a third quarter gain of $23.3 million for the quarter.

A cash recovery of $26 million was made during the quarter as a result of proceedings in respect of a former contract for the Golar Tundra.

Mitigating the Q3 cash recovery in respect of 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 a full quarter's operation of the Hilli Episeyo.

Similarly, interest expense increased by $8.6 million to $32.6 million, mainly, as I said, due to a full quarter's interest expense in respect of Hilli.

The third quarter recorded $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 Partners earn-out units derivative.

Other financial items reported a Q3 gain of $2.5 million compared to $1.7 million in Q2.

The $2.7 million Q3 equity and net earnings of affiliates includes $4.1 million loss in respect of Golar's 50% share of Golar Power and income of $6.9 million in respect of Golar's stake in Golar Partners.

Net income attributable to noncontrolling interests represents external interest in the Hilli Episeyo 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 at September was $764 million, including the long-term restricted cash, of which $306 million was unrestricted and $175.5 million relates -- included in the restricted cash, 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 and dropdown transaction were made.

There are still, however, some final CapEx spends to be made in Q4, which amount to approximately $38 million.

A payment of $24.8 million has also been 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 as at September 30 was $1.86 billion, and 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 Slide 5. Over the last 5 years or so, we have invested some $4 billion in new ships, FSRUs, an FLNG vessel and a gasified 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 3 business lines: shipping, FLNG and FSRUs and power, in addition to, of course, an MLP.

In the last 3 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 3 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 4 to show annualized EBITDA of $173 million.

It should be noted, however, that this effectively includes approximately $15 million of noncash share option expense and approximately $22 million of project development expenses, which are mainly related to the BP-Kosmos Tortue project fee costs that we cannot capitalize yet.

We have then added an assumed TCE rate of $80,000 a day for the tri-fuel vessels, which in today's market looks pretty likely.

We also add 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 have taken the $502 million of EBITDA and shown it by business line.

We have also shown indicative 2020 total debt service by business line, and as you can see, this shows a net EBITDA, less 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 the Sergipe project, which has a 25-year contract life but an average debt life of 9 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 to the presentation.

Thank you.

And with that, I'll turn back to Iain.

Thank you, Graham.

Starting with FLNG on Slide 7. Hilli Episeyo continues to perform well.

And as Graham mentioned, we've got 100% commercial availability, and we are in a 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 know-how.

And we are turning that know-how 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.

And moving on to BP's Tortue project.

As a reminder, that project is to supply an FLNG unit similar to Hilli on a tolling basis for 20 years, which will be located offshore in Mauritania and Senegal.

We have completed the fleet 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 #1 focus right now for an imminent 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 about 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're 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 progress the technical work in parallel with supply and offtake considerations.

The 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 stable Hilli operations.

Turning to shipping now, on Slide 8. 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 in production to some 388 million tons per annum by 2020.

Growing ton miles from an increased component of U.S.-based deliveries confirms that the market appears to be short some 30 to 40 vessels over the next 2 to 3 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 steamships at the 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 a continued increase in term-related inquiries and probably see some better convergence of charterers' and owners' expectations sometime in 2019.

We also continue to examine different options for creating shareholder values with different solutions for the shipping fleet.

And as stated in earlier reports, Golar's 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.

Good progress in this 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 in 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 3 companies have committed a total investment of $182 million into Avenir, of which Golar's 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 IMO 2020, 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 onboard 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 hook-up being implemented by a team of over 2,000 people on site.

The gas and water pipelines are being installed along with construction of the associated pump house 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're well positioned with several projects, including, of course, the potential for an expansion of Sergipe 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 the simple vessel contracts 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 our summary and outlook.

FLNG Hilli Episeyo has delivered $52.3 million of EBITDA this quarter.

Golar and our charterers are pleased with the vessel's performance, and discussions continue on the utilization of the vessel's spare capacity.

We remain focused on being able to support BP on the Tortue project and are progressing the development of additional FLNG opportunities, including Fortuna, Delfin and others.

The shipping rate scenarios that only a few months ago may have been -- appeared 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 a 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 of 2019.

Golar Power is now less than 14 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 LNG infrastructure covering carriers, FSRUs, the Hilli Episeyo and Sergipe is drawing to a close.

And it 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.

(Operator Instructions) We can now take our first question from Jon Chappell from Evercore.

Iain, I appreciate the comments on the spare capacity on Hilli, and I understand that you're negotiating process right now or there are conversations right now.

But just curious, end of the year is now just a couple weeks away or a few weeks away.

What's left that needs to be done?

Is this something that's strictly up to you and Perenco on finalizing the terms?

Is this 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?

So a couple of comments on that, Jon.

First of all, 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 it to that level will require government engagement with Perenco.

We'll leave those discussions internally to those 2 parties.

We're also aware that Perenco is underway with compression increase at the onshore site to allow additional volumes of gas to come through.

And what we'd like to do is just allow those discussions to play out so that when we advise where -- when we think that the third train is 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.

Just my second question, then.

The Delfin commentary was surprising in just that it seems like it's moving forward.

I was unaware that they'd had a leadership transition there.

So you'd mentioned late '19 FID.

Realistically, what's the startup for that potential project?

And we know it's obviously a significant amount of gas.

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-asset field?

Well, the way that we are focused is, let's get one project away before we get carried away on the others.

So the timescale for building 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 3.5 to 4 years.

I'd like to say, we're focused on getting one away.

If we do -- if we can get that sorted and get an FID next year on the first train, we'll be more than happy.

We can now take our next question from Randy Giveans from Jefferies.

So quick question.

Looking at Slide 5, you show an additional FLNG EBITDA of $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 looks like.

Okay, perfect.

And then on the LNG shipping side, 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 $150,000, $160,000, $170,000 a day.

No.

We say in the report that Q3 utilization was 86%.

And I think Iain referred to charters that 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, the Cool Pool is all well busy.

We can now take our next question from Michael Webber from Wells Fargo.

Iain, I wanted to circle back to your first couple of 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 you're highlighting the fact that you could give some clarity around Hilli by the -- train 3 by the end of the year.

But I guess, at least within, at least from what I heard in the answer, it didn't seem a whole lot different than the commentary we got last quarter.

So I'm just curious, if I think about -- aside from the management change at Delfin, I guess, like, has there been a material change there in terms of the commercialization process or something that would justify, I guess, kind of moving that up or making that more prominent within your project pipeline?

And I guess, the same question for Hilli train 3 in terms of maybe the level of engagement between Perenco and the government.

When I read that in the release, I assumed that there was maybe an uptick in conversations there and that it at least started to make progress.

Can you maybe -- what's incrementally different about those 2 processes today than last quarter?

If I take the Perenco story, first of 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 at liberty to expand on that any further.

I just -- I'm 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 progressing on that 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 rejigged their shareholding.

They've got some new leadership there that's going to revise and increased enthusiasm and momentum on the project.

And after a little bit of a lull over the summer, this new leadership and enthusiasm is translating in stronger engagement with us, and that stronger engagement with us is also translating into more focus and momentum in trying to get the solution sorted out on the project.

So it's 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 rates have gone kind of parabolic recently.

In terms of using that carrier upside as leverage in terms of FSRU contracting now that there's a viable alternative stream of employment, are you noticing that -- either you or the people you are competing within 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 used to be for some of those FSRU relets?

Or is that something we will more likely see in kind of '19 or '20?

Yes, we're not seeing it yet.

It's a good point and we've talked about it a lot internally, but we're not seeing it yet.

I mean, the good news, of course, is that any conversion candidate or actual FSRU, such as the Tundra, continues to trade well in the spot market.

But you would think that, that sort of convergence 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 there's still a little bit of an oversupply.

But you've got to think the 2 are going to be more aligned.

We can now take our next question from Ken Hoexter from Merrill Lynch.

Iain, just the -- you mentioned, on the power auctions -- on the power auctions, I think, you mentioned delayed until the first -- or now it's going to be in the first quarter.

I thought last we had -- you had 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 hands of the Brazilian government.

We -- I have no idea why it's being delayed, and there's nothing untoward about.

It's just that they've decided that's when the next power auction is going to be.

Our understanding is it's an auction that we might be interested 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 those auctions next year.

Any change or any commentary from the government, given the new kind of -- as the new government rolls in on that process?

Or you're saying, just a little slight delay, nothing more to it?

I've heard nothing back from the team on the impact.

It's early days for the new government.

I mean, we were watching that with interest, obviously.

But I don't believe they are necessarily related, but they could be.

Okay.

And then just my second one, a 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 the 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 talk to our chartering department several times every day, and the -- it would appear that the number of available ships and the number of cargoes that are after those number of available ships are somewhat disconnected already, and so we're hearing of very high rates, spot rates in the market.

And of course, the very high rates that you hear are for short-term voyages.

But my personal belief is this is something more than the seasonal spike because of the rate that the -- or the steepness that the rates have increased.

So I think it's -- and 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 the spot?

Or do you move to charter them on a more -- out of the pool, I guess?

Well, right now we're keeping and operating them on the spot.

But I would say, in terms of term business, what we think will happen is sort of halfway through towards the second half of 2019, we'll start to see a convergence of the amount of time that we would be prepared to fix a vessel out for and the desire of the charterer.

Right now it's too early in the cycle for us to give out which could be -- what could be a bit of an advantage for us later on.

So I think it's too early to think about fixing on the longer term, but certainly, the inquiries are coming in.

It's just that those inquiries that are coming in are not attractive enough yet for us.

We can now take our next question from Fotis Giannakoulis from Morgan Stanley.

Graham, you mentioned earlier that we shouldn't rule out the 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 the Asian shipyards move in regards with a contract for an FLNG conversion and the associated financing package?

So it's Iain.

I'll take that, Fotis.

Just working back from the end, our discussions with the financing in Asia continue to progress well, as do the conversations around a technical solution.

So whilst -- if we end up with, say, for example, we end up with a Chinese-based solution as opposed to a Singapore-based solution, that will add a little bit of time onto 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 of EG.

And that's a key item.

If that PSC is 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 are continuing with the work that we're doing in both the technical, commercial and partner-related areas, in anticipation of a positive outcome.

I want to ask about the competitive landscape for new liquefaction projects, especially after the LNG Canada FID that does not have aligned end users or off-takers.

And it seems that, also, Qatar is going to go ahead without having aligned customers.

Is this a new norm?

In order for new projects to reach FID, do they need to have the backing to be able to -- the financial backing to be able to go ahead, even before the customers are aligned?

And I want to ask specifically about Delfin, if Delfin can take FID without long-term offtakes?

So I think it would depend very much on who the project proponent is and how they're funding the project.

So if you're a big oil company and you're funding a project through equity, I think it's a much more straightforward decision to take on whether you're aligned behind an off-taker 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 on any project is, on minimum, is to cover our debt service and operational costs on any project through some form of offtake.

But on that regard, if you look at Delfin, that's something that we are considering.

It's a U.S. Gulf of Mexico-based project, so the finance for that you would think will be fairly straightforward.

And for us, considering now debt service coverage and OpEx as the starting point for an offtake is not a bad place to start.

I don't know if that answers your question.

If whether it's a new norm or not, I think the spot market in 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.

We can now take our next question from Chris Wetherbee from Citi.

James on for Chris.

I wanted to have a look and ask about 2019 and the dividend.

It seems like it's going to be pretty solid cash flow year, but how are you going to balance potentially dividend increases, if possible, other claims on the cash, like other projects ramping up?

Well, I think as we refer in the earnings release

(technical difficulty)

The desire and intention to grow the distribution, but that will be dependent on our cash flow generating success, which is obviously partly dependent on how well the shipping market does.

And it's related to capital needs.

I think we've also said that given our cash position, the amount of operating cash that, I think, we can be generating in the next couple of years and also the $126 million of cash that's coming out of the restricted LC over the next few years, we're in a pretty good position to finance the next project.

All right, got it.

And then on Avenir, I wanted you to talk about possible synergies along the lines of improving utilization per asset.

So what other synergies into the market development might tie directly into some of the existing projects you have from there?

Well, just expanding on the example, if we take the Nanook FSRU, sitting there with 2/3 of its capacity not being utilized because the Sergipe power station at 1.5 gigawatts only requires 1/3 of its capacity, if we take the example, where we could use one of the small Avenir ships to break bulk on there and transport LNG, we can take that through dam, local rivers, into different destinations and think about 2 possible scenarios.

So the first scenario is where you put the LNG into isotainers, send them upriver on smaller barges and into local gas-fired power stations.

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 a smaller ship, transferring that around into containers and using that to fuel an LNG trucking fleet.

And I don't know if you know, in Brazil, the LNG trucking fleet is pretty massive and they have road trains moving up and down massive road corridors moving crops to the coast and to the export ports.

And if you took those, these diesel fired trucks and transfer them to LNG, again, you get this double benefit of low cost.

So it's a benefit to the owners and also the environmental 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 into Brazil, fully sort of imported, for the same price as a diesel truck.

So this is a real thing that we believe is going to happen.

And that's an example of how this small-scale market can unlock avenues for distribution of LNG.

And Avenir's business is not about fueling trucks and owning trucks.

It's about distributing LNG.

We can now take our next question from Donald McLee from Berenberg.

So first question, this goes back to your comments on the cyclical versus seasonal spike in LNG carrier rates.

What role do you believe the pending increase on January 1 on LNG tariff into China might have played in helping to support higher rates as well?

I don't know that it's made that much of a difference that we can see at this point.

Got it.

And then looking at the Hilli -- sorry?

I'm just going to add is that there are so many reloads going on, whether that's LNG coming in from the north, from Yamal.

I think the whole movement of LNG and the reloading and more spot nature of the market is probably obscuring any direct line of sight to any of the sort of China-related embargo issues that we can see.

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 the Hilli?

And wondering -- just to get an idea of what demand might be for train 3 potentially coming online.

So on the pace of cargoes, it's defined per the contract and our availability.

So there's a cargo lifted every 2 and a bit weeks.

And that -- as there are 2 trains running, that will not change other than through planned scheduled maintenance outages.

That won't change for the life of the contract.

In terms of demand for train 3, I mean, I think there's plenty demand out there.

It's not -- at this stage, it wouldn't it be our cargoes to deal with.

That will be something for the owners of the LNG to deal with.

(Operator Instructions) We can now take our next question from Espen Landmark from Fearnley.

On the potential separation of the LNG fleet, I mean, I guess, we're finally starting to see some earnings in that fleet now as your fourth quarter guidance suggests.

So next year, if the market persists, that the fleet is adding substantial cash flow, I guess, supporting distribution and even being complementary on earnings, so I mean, is that changing any way you're thinking around the spin-off, given the majority of Golar's final incremental earning sales will materialize, 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 a lot of work has been going on in the last quarter and will continue through this quarter.

So I 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 carrier seldom change 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 not sure we can really comment on that, Espen.

Certainly though, I guess, given the way the market is going, the value has certainly gone up.

We can now take our next question from Ben Nolan from Stifel.

My first question is related to the Mark II, which, obviously, you're working on with Delfin and potentially for tune-in.

And in the release, it said that it was cost-competitive with the Mark I. I assume that's on a per ton basis.

But could you maybe give any color as to sort of how you're thinking about what 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 around there for -- 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 commitment.

So in that framework, when you think about the dividend and potentially increasing it, should we think of dividends as sort of a floating number?

If cash is available then you would pay it, but if you have a lot of projects then maybe you dial back the dividend a little bit?

Or are these sort of plateaus that you're looking at?

So Ben, I mean, I think we're always going to be wanting to increase the dividend rather than decrease the dividend.

So we -- and in looking at where we're going with the distribution, that will take into account, as I said earlier, our earnings potential, which is obviously 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 feeling pretty comfortable about at least another FLNG project.

So I don't think we're going to be -- I mean, it's difficult to say.

But the -- we're not -- to say if it's going to be a floating distribution is, I'm not sure, is correct right now.

I think it would be -- our intent is for that distribution to be stable and growing over time.

The other thing about -- you mentioned that we've 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 out there.

So it's 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 has been something that we've not been great at in the past that we hope to try and get better at.

We can now take our next question from Chris Snyder from Deutsche Bank.

My question is around the guidance.

Can you talk a little bit about your spot rate expectations over the next 2 months that are underlying that $70,000 to $80,000 a day Q4 rate guidance you gave, just so we can kind of calibrate our models?

Well, so we also -- we kind of guided to the element of the tri-fuel vessels components of that TCE, obviously, at around $85,000 to $95,000.

Utilization for Q2 was 86%.

We would expect that to probably go up for Q4.

However, you need to take into account that quite a lot of Q4's revenue has already been 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.

And then just kind of me following up on the -- just comparing the TFDE guidance to the overall rate guidance, it seemed like you guys are expecting a very little impact from the steam fleet.

I would have just assumed that given -- as how tight the market is, that those vessels will kind of see a pretty nice ramp-up here in Q4.

Can you maybe just talk about how those, the 2 steam vessels, are performing?

Sure, well, I think that this neatly illustrates the point that I was just making.

So one of the steam vessels is and has been on a sort of a medium-term contract for the last couple of years at a 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 been going through some kind of work to get her up and ready to enter into the market.

And she's now booked to go on stream in December at a decent rate, as I think we referred to in the earnings release.

So you've got one vessel that's on a low rate because it's contracted several years ago and one that's 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 expect it to be in Q4.

And that's the sort of time lag effect.

Okay, 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 does Perenco have like the requisite production to utilize train 3 without any incremental CapEx or incremental field development?

So that's part of the work that Perenco has been doing, is figuring out how it can satisfy an increased demand, or as you know, supply us with enough gas.

And it's supplies with enough gas, not for 1 or 2 years, but out for the duration of the projected life of Hilli being on station.

So it's -- I know it sounds very simple from the outside, but internally, it's a little bit more complex than that because it's a multi-dimensional thing that they're working through.

I'm confident that they are going to come up with a solution that will work for us, and hopefully, we've got that information by the end of the year.

And then just a real quick modeling question.

It seems like the Hilli margins were squeezed a touch during Q3 relative to Q2, which I know was only 1 month.

So just kind of modeling forward, which one is kind of the correct run rate to use?

Or will it be somewhere in between kind of the Q2, Q3 margins?

When you, first, say op margins, I assume you're referring to the fact that the operating costs were slightly higher?

Yes.

So the [revenue], yes.

So OpEx were a bit higher in the third quarter, a bit higher 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 it's going to be.

(Operator Instructions) We can now take our next question from Magnus Fyhr from Seaport Global.

Just one question related to the Delfin project.

It seems, like you said, they're getting more motivated to pursue that project.

Can you elaborate what you think the 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, is fully permitted.

That's one of the advantages of the work Delfin have done in acquiring the pipeline systems that they have.

Obviously, there are 2 main differences compared to, for example, West African production that we see in 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 adverse weather such as a hurricane.

And secondly, there's a requirement in the Gulf of Mexico to use air cooling rather than seawater cooling.

And those 2 elements drove the development of the Mark II design initially.

So that, it 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 it in West Africa as well because we get enhanced production in terms of more volume.

More volume generally means, assuming that the gas is there, improved 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 2 main changes, and we feel confident that our Mark II design can overcome both of those.

We can now take our final question from Frode Morkedal from Clarksons Securities.

There's been a lot of questions on the dividends, 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 or even down despite very strong LNG shipping rates, Hilli being a success and oil prices being high.

So the question is have the board signaled any, let's say, intention to increase the buyback program if you don't get paid in a couple markets given, what I would say, is quite strong fundamentals?

We haven't made that indication now, 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.

That we're going to balance that effective cash distribution to shareholders against future capital needs, and we need to get that balance right.

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.