Excelerate Energy: Floating Ideas and Defying the Skeptics

A decade ago, Excelerate Energy defied the skeptics by developing an innovative concept for the floating regasification of LNG. Today it is the leader in the rapidly growing floating regas industry. Now the company is aiming to defy the sceptics yet again – this time with the development of floating liquefaction technology that could, if the company can live up to it claims, be an even bigger game-changer. According to CEO Rob Bryngelson, FLNG promises to be cheaper, quicker and easier to implement than land-based solutions, especially in remote locations. In this exclusive interview he explains why floating regas and FLNG are increasingly competing with shore-based solutions. Interview by Alex Forbes

Floating storage and regasification has come a long way since Excelerate brought into operation its first Floating Storage and Regasification Unit (FSRU) in 2005. How do you envisage your business growing over the coming decade?

There are a number of ways I can answer that. The first is simply the number of projects. Now that the industry has accepted FSRUs, most projects look at FSRUs as one of the first solutions. Historically it was “can we build land-based and maybe we’ll think about the crazy floating stuff”. Now it gets equal footing and sometimes top billing because of the timing, cost efficiencies, flexibility and so on.

I see many more opportunities for FSRUs to come into the market. Historically, if you were above 500 MMcf/d you could probably justify a regas terminal onshore and people tended to look offshore for smaller volumes. What we’re seeing now is the potential for offshore to work in excess of a billion cubic feet per day (Bcf/d). We have designs that range from sub-100 MMcf/d up to over 1.2 Bcf/d to tackle a broad range of markets.

Also FSRUs are increasingly competitive. The cost of land-based infrastructure has continued to go up over time while ship prices have stayed relatively constant. If you look from our first FSRUs up to the most recent ones we’ve built, the pricing is relatively flat if you normalise for size and capability. We haven’t seen the same escalation.

So I see more projects for us, ranging in size from very small to very large. Emirates LNG is a good example of that. It tendered out last year for 600 MMcf/d offshore plus another 600 MMcf/d of potentially onshore vaporisation, to get an early solution and then build it up bigger onshore. There are lots of new ideas and concepts coming to market.

Your company has been developing a generation of FSRUs intended to be “a true alternative to land-based terminals”. That still attracts scepticism from some quarters. Some people find it hard to believe that an FSRU is ever going to compete with a land-based terminal with two 160,000 cm storage tanks . . .

. . . I don’t follow that logic. Look at five years of continuous operation at Bahia Blanca and going on our third year in Escobar. In year-round operations we’ve never had an issue of hitting tank tops or bottoms. It’s all about logistics. And those are smaller vessels. When you get to a 173,000 cm vessel, our Experience class vessel, and even some of the newer ones – we have a design for a 260,000 cm FSRU called FSRU-Plus – it’s all cargo management and logistics.

It’s a fallacy that having all the storage onshore improves your reliability and your deliverability. We’ve never seen it as an issue in any of the projects we’ve been operating. And if it is, one way of accommodating it, and one of the things that some new projects are thinking of is to have a conventional vessel sit alongside an FSRU as additional storage. That aside, we consistently see over 99% availability for all of our projects.

When might we see the first 260,000 cm FSRU-Plus?

As soon as we get the right customer for it. We’re looking at it for a few new projects. The vessel would have 1.2 Bcf/d of vaporisation and the cost numbers are extremely compelling. Cost doesn’t scale linearly with the smaller vessels – so it’s not a big jump of cost to go to that size. The more throughput you get the more storage-sensitive you are and that’s why we’ve upsized the size of the vessel to 260,000 cm.

You’ve seen the pace at which some of these projects move. We have things now that we’re starting to close on that have been in the pipe for three or four years. Puerto Rico is an excellent example of that. We started looking at that project in 2008 or 2009, and we just tied up the terms and conditions last year. We’re finalising the permitting process over the next year with the Federal Energy Regulatory Commission (FERC) and we’ll go into service at the beginning of 2015. But that’s been a long time coming.

We like to keep the toolbox full. We have our 138,000 cm vessels, our 151,000 cm vessels, our 173,000 cm vessels, which we call the Experience class, and then the 260,000 cm FSRU-Plus. I’d love to do one of those soon.

All the main FSRU providers – yourselves, Höegh and Golar – say that there’s a long queue of potential projects, and yet we have several existing FSRUs working as conventional LNG carriers (LNGCs). Why is that?

It’s the speed at which the counter-parties move. Most of these entities, because they’re governmental or quasi-governmental, have to go through a tender process and those processes tend to be very slow.

The reason that we have FSRUs that are employed as conventional vessels is that initially Excelerate got into the business to trade LNG into the US and so we went long ships to do that. Well, of course, shale gas came around and we had to re-invent the company and change the strategy – so we employ them in conventional service until they are placed into a term project.

We currently have two FSRUs in Argentina, one in Kuwait, one in Israel, and two in Brazil – Petrobras has the ability to use one of the regas vessels in Brazil as regas or conventional, and then we’ve got one that’s providing a bridging service until our new FSRU, the VT3 ship that we’re building, is completed next year.

So six out of eight of our regas vessels are employed in service. So that leaves two we’re in the market doing different things with. And one of those two will be going to Puerto Rico at the beginning of 2015. So that really leaves one open ship that we’re looking to do things with, and one that we’ll get back from Brazil – the bridging vessel that will come out of service next year – when the new VT3 vessel goes in.

My view is we keep one – maybe two – ships open for the ability to strike on new projects quickly, but also as backup and as trading vessels for the broader fleet.  However, for the right opportunity we’ll place all of our vessels in long-term regas service.

Höegh has a similar strategy, of always having one uncommitted vessel, doesn’t it?

It makes a lot of sense. If tomorrow I had those other two vessels completely tied up, I would probably recommend to my board that we go spec build one to have one long.

The market’s fairly split now. About half the projects we look at could use one of our existing vessels and then others have a bigger requirement and want more bells and whistles and so we’d look at a new-build. So that’s why we went out and secured the option slots with DSME.

When do you think you might exercise some of those options?

You’ll probably see us exercise one in the third quarter. We’ve got a couple of things out there that we’ve tendered for. The option slots are pretty much quarterly and they have a 28-30 month delivery window. We may let some of them expire if we don’t have an opportunity, and we may try to work with DSME to put them on the back end so that we keep a string of options out there.

Can you describe how you allocate your ships to the various projects?

We generally allocate specific ships for specific projects. However, we do work with our customers to try to incorporate substitution clauses in the event that there’s ever a problem on a ship, or we need to move the fleet around. But it’s rare we do that because you do incur costs positioning ships in and out of a project.

The way things are set up is to try and keep things flexible. For instance, if one of our projects has a ship that would be ideal for another project we’re bidding on we may consider a swap; but if that deal doesn’t happen then we’ll leave things as they are. Keep in mind that we’d only do the swap if the customer consents and it doesn’t impact them. Similarly, we might do it when we need to go in for dry docking. We don’t swap ships in and out at a whim. We’ve only done it two or three times over all of our projects – and again only with customer consent and proper planning.

One of the technologies that’s been crucial to the development of floating regas – and relevant also in floating liquefaction – is ship-to-ship (STS) LNG transfer. When you began working on STS transfer there were concerns about the increased risk of the technique compared with conventional offloading operations. What do you say to the critics and the sceptics after seven years of experience with this technology?

I get a weekly update of how many STS transfers we’ve done. As of June 7 we’d done 414. Of those, 66 had been between our own vessels and 348 had been with third-party vessels. That’s 44.5 million cm of LNG we’ve moved without incident.

I don’t know how many others our competitors have done, but overall, with ours included, you’re talking probably well over 500 transfers that have happened. And, knock on wood, no incidents to date.

We’ve designed the system with all the fail-safes and the controls that you would expect in the LNG industry: emergency shut-down valves, dry-break connections, and so forth. We’ve worked closely with all the regulatory bodies and classification societies, and written very specific guidelines for how to do this. It’s a very controlled, very well thought out process. We’ve recently done several ship-to-ship transfers with BP. We’ve done a whole host with Repsol into Argentina.

Before a vessel can be considered for ship-to-ship transfer, we do a full vessel vetting. We look to make sure that the vessels are compatible. We run a compatibility study on manifold locations, and the relative motions between the two ships, to make sure we don’t have any issues.

So what I tell the critics is: look into the process, it’s very well-documented, very well-controlled – a very carefully orchestrated process.

If there are ever any issues that crop up, everything stops. The connections are dry-break connections where the amount of LNG that would be released on a hose separating from the flange is so small you’re going to see vaporisation before it even has a chance to hit the water curtain underneath it.

We have hosted numerous groups through at the various projects, and they have looked at the process to get comfortable with it. People walk away satisfied.

Are there still any major LNG companies that resist the use of the technology – because some did for a while?

Resist, or they want everything done their way, are two different things. We do have people come in, some of the majors, who say: “This is all great but because of this I want you to change things up a bit.” Okay. Or “because of a particular requirement I have, I want you to change your control system logic to add this.” If there is repeat business or it’s part of a broader project we’ll do it. We’ll gladly do whatever it takes. But if it’s for a one-off cargo and might cost us $200,000 to do, we’re not going to pay for that.

Moving from floating regasification to floating liquefaction, you’re one of the companies in the queue for a licence to export LNG from the United States, with your Lavaca Bay Floating LNG (FLNG) project. There are now around 17 projects trying to export LNG to non-FTA countries. Following the recent Freeport approval, you’re now eighth in the queue. How confident are you of getting a licence, given the controversy surrounding US LNG exports, and given your position in the queue?

The Department of Energy (DoE) separated the applications into two groups. As I understand it, we are part of the first group. The latest we’ve heard from the DOE is that the applications will be considered in the order received, with some re-prioritisation based on how far along in the regulatory (FERC) process the project is.

I’m confident that this will ultimately come out to be a market test for these projects. What will limit this will be cost creep. Essentially, you’ll see the first projects go at a reasonable price, and as resources start to get strained – even in the Gulf Coast things can get strained to build LNG tanks and liquefaction trains – you are going to see costs creep up. Eventually you’ll get to a point where you hit economic indifference as to whether or not you build the project.

I don’t think it takes 17 projects for that to happen. I don’t know if it happens at 2, 5 or 7. I’m not sure where you run into that. But ultimately the cost of construction and the delivered cost per tonne of the LNG plant is really going to be what dictates this. I’m probably more confident that something will happen than a lot of other folks. Whether or not all the capacity [that gets built] will get utilised will be the interesting question.

A DoE export licence is only one of the major approvals that you will need. You need FERC approval as well. You’re about to join the select group who’ve gone through the pre-filing process with FERC and moved on to formal applications. You did your pre-filing in November last year. When do you expect to file a formal application?

Resource reports, which we’re finalising now, will be filed with the FERC in August. We finished our front-end engineering and design (FEED) at the end of February and we’re refining our cost estimates. We’re very comfortable with where we are. We are coming in at $540/tonne/year, all in. That includes the land-based infrastructure that we have to dock to, the vessel, everything. We’re looking at a 4.4 mtpa project so it should be right around or south of $2.4 billion.

That sounds like very good value for money for a 4.4 mtpa project.

It is. We’ve run into the naysayers everywhere else in the business. Our board of directors has pushed for confirmation from us that these costs are correct. To that end, I need to be clear that these aren’t just estimates. We’ve worked with Samsung, who will build the hull for us, and Black & Veatch, who will provide the topsides, and going all the way to the purchase orders with vendors to get accurate pricing for everything. These aren’t material take-offs or cost estimates on a design that’s not finished. These are plus-minus-10% cost numbers on a completed FEED.

The problem now is we have a year to wait in the permitting process before we can do anything. Until we hit final investment decision (FID) there’s not a lot more we can do. We may advance some detailed design work but we’ve just got to move through the FERC approval process.

Which is likely to take at least a year from when you put in your formal application just because of the amount of work involved . . .

. . . it is. And we don’t file anything incomplete just to get the clocks moving. We’re very careful in what we submit to the FERC. This is our fourth siting, construction and operation permitting process. So we know what the FERC wants to see in an environmental impact statement. We’ve been talking to them about the project for a long time. They’re very familiar with it.

Because of the floating regas projects they are more comfortable with some of the issues of FLNG – not so much the production side but the cargo transfers, the operation of equipment and the handling of LNG in an offshore environment. Even though this is dockside it’s still technically offshore.

If everything goes well, what’s the soonest you could take FID and when might we see the project come on stream?

Soonest FID would be the middle of next year. With construction, transport, installation and commissioning, we’re talking about 44 months from that to first commercial gas. Our target is January 2018.

What prospects do you see for the development of the wider FLNG business now that we have some real projects under way?

The market has the same perception of floating liquefaction that it did initially on floating regas, which is that it’s only for specific applications: such as stranded gas that you can’t reach by other means. But if we truly can deliver at the numbers that we say we can, then FLNG becomes competitive with land-based liquefaction in almost every scenario. It really could change things in terms of much quicker times to construction, and much better cost control.

If you want to build an LNG project in a remote location, you have to go in and spend half a billion dollars to build a town and infrastructure and roads and an airport to get people in and out. And that’s just the beginning. You’ve also got to fly everybody in to build tanks and to put the whole plant together.

We do all that in a shipyard. The workers are there. All the equipment is there. You don’t really have to change anything. And all you’re building on site is pretty basic infrastructure. It’s either just a simple jetty and a pipeline – the vessel can do gas processing on board or you can put it onshore – and if it’s a far offshore location it’s a subsea buoy system, like we use to moor the regas vessels offshore the Gulf of Mexico and Boston.

So it gives us better cost control. That’s one of the things people will start to recognise: that FLNG it’s a good way to de-fray some of your cost risks – really in virtually any project.

Have you been looking at East Africa at all?

We have – quite a bit. Mozambique is an interesting opportunity.

Indeed. From what you’ve said, you’ve got a market there where’s there’s very little infrastructure, one of the poorest countries in the world, but, it seems, an awful lot of gas.

The issue with floating liquefaction is everybody wants to be second. The challenge is finding the right project to be first.

That’s really why we picked Port Lavaca. It gives us a dockside project so you take away the concerns with it being offshore. Now this vessel is designed to withstand rough weather conditions offshore, but you take that out of the picture. The project will be getting pipeline quality gas from the US gas grid, so you take away the reserve risk. So what you’re getting down to is purely about “Does this technology work on board a vessel?” That’s a lot easier for people to put their arms around for the first project.

But it has the potential to really change things. So if we can make something happen here, our ideal project is less of a tolling structure, which is what we’re doing for Port Lavaca, and more of a partnership structure, going in with the producers and saying: you bring me gas, we’ll bring the vessel, let’s sell the stuff downstream and figure out how we split up the deal from there. We really want to be more involved in taking more risks than just a simple tolling deal.

What about the sceptics? What do you say to them?

The world has really changed since before we launched the first regas vessel 2005. People were downright rude at conferences, walking out in the middle of presentations, or openly laughing about the concept. Now you’ve got regas vessels, you’ve got ship-to-ship transfer, you’ve got re-exports from terminals, you’ve got the concept of floating liquefaction. I’m thankful for the companies like Petrobras, and YPF and Enarsa and KNPC, because they saw that floating regas would work, and didn’t have the scepticism. They helped us create the market.

We’ve had three or four groups come through and do detailed due diligence work on our floating liquefaction. They’ve come in being sceptical and they’ve left being convinced it works.

The approach we take is not a blank sheet of paper. Some enterprising young engineers want to take a blank sheet of paper and create something new. Whereas we said: “Let’s take an existing hull and modify it.” “Let’s look at an existing liquefaction process and marinise it.” “Without creating anything new, let’s package existing things and make sure they work.” Which is how we advanced floating regas. When you do that you save on costs, you save on time, and you don’t have to prove up quite so many things.

So, again, it’s all in the approach. We just look at things differently and there are people out there who are ready to accept that.

We keep energy moving.

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