Golar LNG Limited (NASDAQ:GLNG) Q1 2023 Earnings Call Transcript

Golar LNG Limited (NASDAQ:GLNG) Q1 2023 Earnings Call Transcript May 30, 2023

Operator: Welcome to the Golar LNG Limited Q1 2023 Results Presentation. After the slide presentation by CEO, Karl Fredric Staubo; and CFO, Eduardo Maranhão, there will be a question-and-answer session. Information on how to ask a question will be provided then. At this time, all participants are in a listen-only mode. I will now pass you over to Karl Fredrik Staubo. Karl, please go ahead.

Karl Fredrik Staubo: Thank you, operator, and welcome to Golar LNG’s Q1 2023 earnings results presentation. My name is Karl Fredrik Staubo, CEO of Golar LNG, and I’m accompanied today by our CFO, Mr. Eduardo Maranhão, to present this quarter’s results. Before we get into the presentation, please note the forward-looking statements on Slide 2. On Slide 3, we present our company overview. During the quarter, we exited our investments in Cool Company Limited as well as New Fortress Energy. We also reacquired New Fortress equity stake in the FLNG Hilli. We also sold the LNG carrier, Golar Gandria, and acquired the LNG carrier, Fuji LNG intended for FLNG conversion. Hence, our key assets continue to be the FLNG Hilli operating for Perenco in Cameroon and the FLNG Gimi delivering later this year to start a 20-year contract for BP on the Tortue field offshore Mauritania and Senegal.

With the acquisition of Fuji LNG, we are advancing the potential ordering of our third FLNG, which we intend to be a Mark II FLNG with an annual liquefaction capacity of 3.5 MTPA. Turning to Slide 4 and highlights for the quarter. On the left-hand side, starting with Hilli, As previously announced, we reacquired NFE’s equity stake in Hilli for a total consideration of $100 million, plus our remaining 4.1 million NFE shares and taking over $323 million of debt associated with New Fortress Energy stake in the unit. We also unwound our TTF hedges, locking in a total of $140 million of operating cash flow on the hedges whilst maintaining exposure to TTF-linked production. We also agreed to compensate the 0.04 tons of underproduction in ’22 with a similar amount of overproduction during 2023.

We’re also pleased to announce that we have agreed and received credit approval for improved terms under our existing debt financing on Hilli. This will lower our debt margin and increase our free cash flow to equity from that unit. Eduardo will explain the amendments in further detail later in the presentation. Gimi is now 94% technically complete. Our sail away dates have been pushed from first half this year until Q3 this year to allow for time to fully complete the vessel, conduct increased testing at the yard and in line with the overall schedule for the project. Under business development, we have over the recent months seen significant increasing interest for our FLNG solutions, and especially for recontracting of the FLNG Hilli given her second half 2016 availability and proven operational track record.

We’re currently in discussion with several gas resource owners. This includes signing of a memorandum understanding with NMTC during the quarter to explore FLNG deployment on specific NNPC controlled proven gas resources in Nigeria. On the back of increasing commercial interaction for FLNG deployment, we have advanced yard and financing discussions for Mark II FLNG and acquired the Fuji LNG, as already described. Turning to the right-hand side and corporate and others. Q1 financial highlights include a cash position of more than $1 billion, adjusted EBITDA for the quarter of $84 million, net cash proceeds from exit of NFE and Cool Company of $102 million. We bought back $20 million of our unsecured bonds at par and agreed to amend the bonds to increase financial flexibility.

Following the bond amendment, we have reinstated dividend payments and have approved to pay $0.25 per share for Q1. Our target is to declare a stable and overtime increasing quarterly dividend, and we will address our dividend outlook ambition in further detail later in the presentation. We have also approved $150 million share buyback program. Turning to business development on Slide 6 and some further detail on Gimi. The majority of remaining works are piping, system testings and pre-commissioning. As mentioned, expected sail away has shifted from first half until Q3 ’23 and the updated sail away timing is not expected to impact first feed gas on the Tortue project. Due to overall project and FLNG delays, pre-commissioning contractual cash flows have started.

Part of these contractual cash flows from BP to Golar is currently disputed, and we are now working to resolve the matter. The updated sail away date and pre-commissioning cash flow dispute will have no impact on the wider execution of the 20-year project that is expected to unlock around $3 billion of adjusted EBITDA backlog to Golar, equivalent to an annual adjusted EBITDA of just around $150 million. Turning to Slide 7 and FLNG business development, which is the most exciting area of our business. We experienced increased interest from gas resource owners for our FLNG solution. We’re currently in discussion with five to six gas resource owners for potential FLNG deployments. Our key priority is to secure a charter for Hilli at the end of the current contract expiring in July 26 to secure increased cash flow visibility, increased shareholder distribution before taking FID on our Mark II FLNG.

Several of the potential clients in discussions have resources sufficient to accommodate either Hilli or our Mark II FLNG. We continue to target commercial structures where we, together with the gas resource owner, focus on attractive cash breakeven liquefaction of stranded or associated gas field and share of fund through commodity price offtakes. A fully utilized Hilli based on current LNG forward prices has an annual revenue potential in excess of $1 billion. This will then be shared between the gas resource owner and Golar as the liquefaction provider. In April, we signed a memorandum of understanding with NNPC, which is one of the five to six gas resource owners described earlier. NNPC is Africa’s largest domestic energy company. Nigeria is currently producing 33 million tons of LNG annually.

This compares to more than 4 billion tons of proven gas reserve. Hence, there is significant capacity and ambition to monetization of these volumes. Since signing of the MOU, both parties have allocated significant resources to develop a named gas feet for a potential FLNG project. We’ve made material, technical and commercial progress. Overall, the MOU has a five-year duration and both parties have an ambition to explore the potential for multiple FLNG projects to be deployed on proven and stranded gas fields in Nigeria. We find it best to start with one named one as opposed to try to tackle all at once. Continued progress is also made with other gas export opportunities both in West Africa and South America. Turning to Slide 8. On the back of this increased charter interest, we decided to high-grade our FLNG conversion candidate.

We decided to sell Gandria and to clear our option to acquire the LNG carrier, Fuji. The key advantages with the enhanced FLNG conversion candidate includes younger age and better sailing conditions, increased cargo capacity, larger deck space and lower boil-off. We continue to advance yard EPC discussions as well as progressing a debt facility for Mark II FLNG projects. The final investment decision will be linked to charter visibility on recontracting of Hilli and/or Mark II FLNG. Turning to Slide 9 to further highlight the earnings potential from integrated FLNG projects. We continue to see very healthy margins for FLNG projects. We believe gas prices have reverted to a more sustainable level at a cost advantage to more polluting sources of energy, supported by long-term visibility in the commodity forward markets.

As described in previous quarterly presentation, we believe stranded or associated gas upstream opportunities can be developed between $1 to $3 per MMBtu in upstream costs. FLNG OpEx, including fuel costs equate to about $0.60 per MMBtu. Add shipping costs to end users in Europe or Asia and you have delivered cash breakeven of between $3 to $5 per MMBtu. This compares to forward prices of north of $10 per MMBtu, indicating annual EBITDA for a fully utilized Hilli of $550 million or $875 million for Mark II FLNG. We continue to believe in our business model, where the majority of incremental supply over the next 5 to 10 years will be sourced from the U.S. Hence, if you have a business with three key cost components, namely gas source costs, liquefaction costs and shipping costs, and you’re cheaper on all three components, we believe that’s an attractive competitive situation.

As you can see in the top right corner, this business model has an attractive risk reward in a historical context with limited downside and significant upside potential. Current forward curves are significantly higher than that of historical LNG prices. Turning to Slide 10. The world needs more and cheaper sources of LNG. Looking at gas prices over the past year, it has become clear that the world needs more LNG from a wider range of suppliers at cost-competitive levels. While LNG may previously have been considered a transition fuel, the events unfolding in 2022 underpins LNG and natural gas as a critical part of long-term solutions to ensure energy security. However, existing production and current build-out of LNG plants will not be sufficient to cover the expected demand growth in the coming decade.

According to S&P Global, LNG demand is set to increase from around 400 million tons in 2023 to approximately 630 million tons by 2035. This is equivalent to a compound annual growth rate of 3.5%. Turning to the right-hand side of the slide, we have shown the estimated CapEx for liquefaction projects currently under construction. The steep cost inflation recently witnessed is pushing costs higher, leading to the supply cost shifting higher. You can see from the majority of the U.S. liquefaction projects, you’re talking CapEx per ton of liquefaction capacity way in excess of $1 billion. While there are several factors impacting the ultimate economics of a liquefaction project, keeping liquefaction CapEx contained is one of the three cost drivers of an LNG export project and the key aspect of success which makes us continued confidence in Golar’s FLNG solutions.

Turning to Slide 11 and an update on Macaw Energies. Macaw Energies is a start-up entity replicating Golar’s model in treating and liquefying flared and stranded gas but on the shore side. Macaw was founded by the same team that created Golar Power, which was later renamed Hygo. Golar Power started with an initial investment of $5 million and grew through a joint venture between Golar and Stonepeak and was sold five years after inception at 3x to 4x the invested capital. Golar has committed up to $25 million for the team to concentrate its efforts on constructing a proprietary modularized small-scale liquefaction unit as well as partnering with complementary small-scale LNG businesses to develop LNG-to-EV charging in areas of high flaring activity, significant trucking demand and the grid currently not capable of supercharging of EV trucks.

This will include areas like the Permian in the U.S. and several stranded gas resources in South America. Subject to the continued development of Macaw, the Macaw management team and Golar will explore a spin-off of Macaw Energies at a later point in time. It’s a business we believe in. It’s a team that has proven to deliver to us previously and the model that’s replicating what we are doing at larger scale offshore, but this will not be a significant CapEx requirement funded by Golar balance sheet. It will then be lifted out from the balance sheet for capital markets to fund it. I will now hand the call over to Eduardo to present our Q1 results.

Eduardo Maranhão: Thanks, Karl, and good morning, everyone. I’m very pleased to provide an update on our group results for the first quarter of 2023. So if we can turn over to Slide number 13, I wanted to show some of the financial highlights of this quarter. We had total operating revenues of $74 million, up 25% compared to Q4 2022. We also had FLNG tariffs of $110 million, up 15% when compared to Q4 2022. LNG tariffs is a key non-GAAP metric comprised of total revenues from liquefaction services and realized gains on oil and gas derivative instruments. The contribution from our FLNG operations were very strong this quarter, and we recorded increased earnings from Hilli of close to $98 million, up 23% when compared to Q4 2022.

On a consolidated basis, this quarter we recorded an adjusted EBITDA of $84 million. As a result of noncash mark-to-market charges of $188 million, we recorded a net loss attributable to us of $102 million in the quarter. Those charges are inclusive of movements in the value of our TTF and Brent derivatives of $115 million, changes in listed equity securities of $62 million and interest rate swaps of $100 million. After closing the acquisition of NFE’s stake in Hilli just in March, our total share of contractual debt stood at $1.1 billion. We continue to have access to ample liquidity and our cash position at the end of the quarter was just over $1 billion. So moving on to Slide 14. I wanted to provide some further color to our increased shareholding on the FLNG Hilli.

In exchange for 50% of the common units, which we didn’t control, we paid a total consideration to NFE of $100 million in cash plus our remaining stake of 4.1 million shares and also we assumed $300 million of debt. As previously announced, the acquisition of Hilli is expected to increase our run rate adjusted EBITDA by $70 million per year. This transaction has closed on March 15. However, the economic benefit to us is effective since January 1 of this year. As a result of our strong operational track record, corporate simplification and confidence in the unit recontracting, we received the management approval from the existing lender to improve some key terms under the current financial facility. A combination of reduced interest margins, extended maturity and reduced amortization schedule is expected to generate additional distributable cash flows to us of approximately $75 million until the end of the current contract.

We expect that those changes will become affected in Q3 of this year. Moving to Slide 15. I wanted to provide a recap of our historical earnings from Hilli. As you can see on this slide, Hilli tariffs can be broken down into three main components: a fixed tolling tariff, a Brent-linked fee and a TTF-linked fee that started on 1st of January of last year. The contribution from fixed tolling fees more than doubled this quarter to $34 million as a result of the closing of the transaction with NFE. Lower gas and oil prices this quarter have reduced the contribution from the TTF and Brent-linked fees to $37 million and $18 million, respectively. In total, we had $88 million of adjusted EBITDA from Hilli this quarter, an increase of more than 55% when we compare to the same quarter of 2022.

Moving on to Slide 16. I now wanted to provide some further details around our debt optimization strategy for Hilli, which I touched on before. So as I explained before, we have received management approval from our existing lender to optimize certain conditions of our existing facility. We’re not planning to increase the overall leverage of the units, but those changes alone should allow us to increase our free cash flow to equity generation to the tune of $26 million per year or approximately $75 million until the end of the current contract. In Q1 2023, we crystallized gains of around $140 million under our TTF hedging program. But it’s important to highlight that we remain open and exposed to TTF prices between March until December of this year as well as 100% between 2024 and 2026 when the current contract expires.

For every incremental dollar change in TTF prices, this will contribute $3.2 million of earnings to Golar. In addition to that, for every dollar change in Brent prices above $60 a barrel, we will generate $2.7 million per year. Moving on to Slide 17. Our balance sheet continues to strengthen, and we now have greater flexibility to allow for shareholder returns and at the same time, to fund our FLNG growth program. When adjusting for our cash receivables from the unwinding of our TTF hedges, we are now practically debt-free with a net debt position of just $25 million. Out of the original issuance amount of $300 million, we have bought back $161 million and approximately $139 million is owned by public bondholders. On May 25, we received approval to amend certain distribution conditions under those bonds, which will now allow us to anticipate shareholder returns, including the ability to distribute up to 51% of total Cool Company cash proceeds, which were $371 million as well as up to 50% of the last 12 months adjusted net income.

Based on that, we’re very pleased to announce the reinstatement of our dividend distribution due to a strong cash flow visibility from our contracted assets Hilli as well as Gimi and also the establishment of a $150 million share buyback program. Now moving on to Slide 18. When we look at the implied dollar per ton cost of liquefaction, we believe that Golar is attractively priced considering our share of net liquefaction capacity from both Hilli and Gimi. Our proven FLNG technology at only $590 a ton is extremely competitive and offers the world’s leading solution to floating LNG liquefaction in the market. That supports our approach to share buybacks, and this was one of the reasons which supported our announcement to update our capital allocation strategy.

I will now hand over the call to Karl, who can talk a bit more about our approach to shareholder returns and also provide some closing remarks.

Karl Fredrik Staubo: Thank you, Eduardo. And turning to Slide 20, as Eduardo mentioned, the update on capital allocation, the way we think about it is with strong cash flow visibility, with more than 70% of expected 2024 earnings based on fixed tariffs and further upside in commodity exposure, we have clear cash flow visibility over the coming years. Add to that the delivery of Gimi that further enhances cash flow. There is also a significant further upside in FLNG projects. We believe dividend should be paid from operating cash flows whilst the strong balance sheet position should enable FLNG growth. As reiterated numerous times during the call, we now have a cash position of more than $1 billion. We’re practically debt-free, and we have an attractive capital market pricing.

Hence, we believe the current balance sheet enables FLNG growth, a buyback program as well as debt optimization of Gimi post delivery and securing a debt facility for the potential construction of a Mark II FLNG. So again, to reiterate, operating cash flow is for the stable quarterly dividend distributions growing alongside the delivery of Gimi and further upside in Hilli. And the balance sheet will be put to work for FLNG growth. Turning to Slide 21 and summary. We have initiated a quarterly dividend distribution, We see embedded earnings growth following Gimi delivery, increased Hilli commodity exposure and 2026 recontracting opportunities and, of course, further earnings growth potential from new FLNG projects. We see the current valuation as attractive and therefore have put in place $150 million share buyback program.

The balance sheet has the capacity to fund FLNG growth. Therefore, we exercised the option to acquire the Fuji LNG. And we see the increasing interaction with prospective FLNG clients, including the signed MOU with NNPC and building in momentum and gives us further confidence of attractive recontracting of Hilli and commercial opportunities for Mark II. This concludes our Q1 earnings presentation. Thank you for dialing in, and we’ll now hand the call over to the operator for any questions.

Q&A Session

Operator: [Operator Instructions] We’ll now take our first question. Please standby. First question from the line of Chris Robertson from Deutsche Bank. Please go ahead.

Chris Robertson: Guys, you’ve often mentioned the cost advantage of African gas. But I think you mentioned that one of the five or six counterparties that you’re currently in discussions with is in South America. Could you briefly talk about any possible cost differential between the two regions? And does this bias you to one region or another as you’re in these discussions?

Karl Fredrik Staubo: Chris. So the — what we see in the South American opportunities is abundant gas reserves, a domestic market that cannot offtake the amount of potential gas development and a source cost not too different than what we see for the West African opportunities. However, subject to what end users end up with, they’re somewhat longer sailing distances. But other than that, we see them as another area of interest for FLNG development. And that’s why we’re also focusing on both South America and at Africa.

Chris Robertson: Yes, that makes sense. That’s good stuff. I guess my second question relates to the MOU, not maybe specific to this current MOU but just broadly speaking, can you just talk about the process that an MOU would have to go through in terms of getting to a contract in terms of how long that would typically take? What milestones you typically have to reach? And just kind of a little bit more detail there?

Eduardo Maranhão: Thanks, Chris. I think since we signed the MOU, that’s the question we’ve gotten the most. And being the only service provider of FLNG in the world, I don’t think there’s a text book as to how these deals go about. It’s custom made between us and whoever the counterparty is from time to time, and it only be then two times in the past. So how standard or not it is, I think it’s a little bit hard to describe. When it comes to the specific MOU with NNPC, the MOU is a requirement to unlock significant resources from the NNPC side, which we have certainly felt the difference in pre and post signing of the NNPC — sorry, of the MOU. That said, we have other potential charters within the group of five to six that we mentioned, where we have not formalized the discussions through an MOU but we’re at least equally as advanced as we are with NNPC.

So I think it’s really down to the procurement process from the charters as well. And, NNPC being NOC, the MOU is a requirement. What we are encouraged by is that none of us signed that MOU for the sake of signing it and real momentum with some neutral deadlines to be met, have been agreed, and I think we’re on track to meet those. That’s where we done in advance. An exact timing is difficult to say, but both of us want to see a resolution sooner rather than later.

Operator: Thank you. We’ll now take next question. Please standby. And this is from the line of Ben Nolan from Stifel. Please go ahead.

Ben Nolan: Eduardo, Karl, I hope you guys are well. I wanted to ask a little bit as it relates to the recontracting of the Hilli. Is it fair to assume in order to get full utilization of the asset that it will likely need to move? And then along with that, how should we think about the timing of contracting? Because obviously, if it does move there will need to be some infrastructure put into place in advance. And so, should we expect this to be a 2023 event? Or is there a little bit more time to work with on the contracting side?

Karl Fredrik Staubo: So yes, it is likely to move from the existing site. There are other fields within Cameroon that could have the resources to facilitate Hilli. So it could — it will very likely not stay on current site. It could stay in Cameroon, and it could equally well go elsewhere like the MOU with NNPC with the signup. In terms of the timing we would need, I think by dealer from an operational and engineering point of view, you would like to know around mid ’24. That should give sufficient planning for any relocation and site preparation for recontracting. And then obviously, there are commercial aspects as to why you would want to see it earlier, but from just an operational and engineering point of view, mid-’24 is when we should have a pretty clear view.

Ben Nolan: Okay. That’s helpful. And then I guess as my follow-up. Am I understanding it right that the order of priority is the recontracting of the Hilli first and then a contract on the second vessel, which you would need in order to go FID? So just trying to think through timing. So if it is anywhere in the, call it, the next 12 months, but could be as much as 12 months for the Hilli, should we expect the contract on the Mark II to be center point after that? Or does it not necessarily have to go in that order?

Karl Fredrik Staubo: In broad strokes, you’re correct. So priority number one is to recontract Hilli, thereafter is to FID the Mark II. The rationale behind the thinking is that we don’t want to be exposed to Hilli coming off-contract in July 26 around the time when a Mark II also will deliver. So you want to fix at least one of the two before FID Mark II. And based on current discussions, we believe it’s significantly more likely that we fixed Hilli before fixing Mark II. But if you fix Hilli attractively, there’s sufficient charter interest that you go ahead with Mark II even if it’s not against the contract from day one.

Operator: Thank you. We’ll now take the next question. Please standby. And this is from the line of Craig Shere from Tuohy Brothers. Please go ahead.

Craig Shere: Congratulations on the progress. Picking up on Ben’s questioning, where does shipyard availability, the queue stand? And what’s kind of the drop dead time that you need to lock that up, commit it in order to maintain your Mark II time line that you originally envisioned?

Karl Fredrik Staubo: There’s no harm in that yard slots is an increasing challenge across, I guess, the whole maritime space. We are focused on shipyards, obviously in Singapore, where we built Hilli and Gimi and I think have strong relationships. And we’ve also explore yard opportunities in China where we believe we would also have the right team to construct a Mark II unit. We have, as you know, secured long lead items for Mark II construction that safeguards timeline somewhat. But of course, the longer you sleep on FID, the longer you push out delivery. Based on the current lay of the land, one day delay of FID is potentially somewhat less than a day delivery — day two delivery because we continue to progress engineering and preparational work like, for example, acquiring the Fuji.

Craig Shere: Got you. And as you think about the Mark II conversion and additional prospects you have. I suppose, with your half dozen discussions, it’s not inconceivable that you could have something beyond the recontracting of the Hilli and the Mark II deployment. So in order to kind of be prepared for that just how much liquidity do you need to maintain on your balance sheet?

Karl Fredrik Staubo: Eduardo, do you want to have a go?

Eduardo Maranhão: Yes, sure. So Craig, as you can see under the current amendment, we have also committed to maintain an incurrent stash of a minimum cash position of $100 million after the payment of a dividend. We have stated that we plan to reinstate the dividend program on a quarterly basis. So, I think this will be done, as Karl mentioned during the call today on a sustainable basis from our cash flow from operations. We believe that our current liquidity position is more than enough to allow us to develop the Mark II project. You have also to bear in mind that the CapEx will be spread out over a period of time, which not only we will benefit from the liquidity position we currently have, but we’ll also be generating cash during that period. So, we feel quite confident that our current position is more than enough to fund both the dividend program as well as the development of Mark II.

Karl Fredrik Staubo: And also just to add, I think we have several liquidity levers, of course, in refinancing Gimi upon completion. That’s a $3 billion EBITDA backlog, which currently has $700 million of total debt against that. There’s also the potential to increase leverage on Hilli upon recontracting. I think through the refinancing announced today, the support from the existing lenders is very significant. And we are also experiencing strong support for debt facilities even during construction of a Mark II unit. So, those combined, including the cash flows that Eduardo alluded to, we are confident that we can fund the foreseeable growth.

Operator: Thank you. We will now take our next question. Please standby. This is from the line of Gregory Lewis from BTIG. Please go ahead.

Gregory Lewis: I was hoping to get a little bit more color — and I guess, congrats on starting the dividend. I was hoping to get a little more color around — and realizing it’s early days, but how we’re thinking about the Gimi debt optimization. Really just any kind of broad strokes you can give us as we try to figure out potential cash flow that’s going to be available once that unit starts working as we think about the dividend rate next year. So really, yes, any type — I mean, what type of interest rates are we seeing for that type of unit, what type of duration of debt are we thinking about? How much is this going to be, like 60% financed or potentially more? Any kind of broad strokes you can give us, I think, would be super helpful.

Karl Fredrik Staubo: Eduardo?

Eduardo Maranhão: Yes. Sure, Greg, I think I can provide some update on that one here. So when we look at some of the key alternatives we have when it comes to Gimi, I think on a high-level basis, considering we have $700 million of debt today, the unit is highly under leveraged. Yes, I think we all agree on that one. And we basically have a few alternatives that we have been exploring over the last few months which range, for example, from existing or upsizing the existing bank facility. So we have a syndicate of around 11 banks in the current facility. Today, we can potentially explore to upsize that facility to a level anywhere from $1 billion to $1.2 billion. I would say when it comes to tenor, that could be anywhere between eight to 12 years.

But this is not the most, I would say, attractive alternative when it comes to potential volume and also when it comes to cost. So moving on to the other alternatives, we also see a potential sale leaseback as one of the most attractive alternatives here. And we have explored the idea of potentially entering into a leasing agreement, which could unlock, I would say, anywhere between $1.2 billion to $1.3 billion in total financing amount. When we look at tenors, I would say that this would be probably longer in duration when compared to bank financing, so anywhere from 12 to up to 15 years. So still a remaining tail of — when it comes to the contract duration of 20 years. But we also see as a potential alternative the potential issuance of U.S. private placement bonds where we could fully benefit from the full contract duration and the contract backlog.

We believe that this alternative could offer us the highest and the biggest volume while at the same time offering a very competitive cost. Of course, this will depend on where the market is at the time of the issuance. But based on the fact that the total amount will be sized based on the potential cash flows from the project and when looking on the SCR basis, we believe that this alternative could raise anywhere from $1.5 billion to $1.7 billion. So as you can see, the alternatives, they range quite a bit in terms of volume as well as tenor. But we believe that we could benefit the most, if we wait until we reach COD. And by that point in time, we will then take a decision to move on with the refinancing of Gimi.

Gregory Lewis: Yes, 100%. Thank you for that Eduardo. And then, Karl, I mean, I guess just you announced the buyback. That was good to see. As you’re out talking with investors, clearly, you’re trading at below $600 a ton on liquefaction capacity. I guess there was that — not a — I guess it was a large, but nevertheless that was well over $1,000 a ton. Any kind of feedback you’re getting from clearly, we believe the stock is undervalued. Any kind of thoughts around what that dislocation is between where we’ve seen some market transactions and where Golar is today?

Karl Fredrik Staubo: That’s also one of the questions we get the most, is why the stock is trading where it’s trading. At the end of the day, we need to try to run the business to the best of our ability and the market needs to set the price thereafter. I think given what we see, not just from dollars per ton, but I think in cash flow multiples following delivery of Gimi and through some of the parts valuation, at least management and Board views the valuation as very attractive, which is why we put in place the buyback program. And that’s what we intend to do. Some investors obviously want us to go significantly larger on the buyback program, if you see some of the market share, about what the people are speculating on. But at the end of the day, for us, I think $150 million is meaningful.

And on top of that, we started the dividend, which both of them combined. This is, of course, the start of shareholder returns, which we just based on visible cash flows and significant upside, as we have explained, should have the ability to grow significantly over the coming quarters and years.

Gregory Lewis: Yes. And then just as I think about that, if we were to decide to move forward with the conversion candidate of like the Fuji, any kind of — realizing that there’s inflation, there’s shipyard availability, all the things that go into doing a mega project like this, any kind of thoughts for what we could get that unit up and running for on a cost basis?

Karl Fredrik Staubo: Yes. We definitely see inflation. I think everybody sees that everywhere. But where we currently see it based on the EPC contract and where we have placed the long lead items, we believe it is achievable around current pricing of Golar, so call it, $600 a ton. But keep in mind, that’s with construction risk and a couple of years without cash flow. If you buy Golar today, Hilli is delivered and generating cash flow and Gimi is delivering this year starting cash flow. So if you take that into account, it is more expensive to go for a new build but the integrated contract opportunities, we see also have superior economics to that current contract of Hilli and Gimi, which is why you don’t think it makes sense, and you can fund it from balance sheet without having to impact dividend as long as you base dividend on operating cash flow.

Operator: Thank you. We’ll now take our next question. Please standby. This is from the line of Sean Morgan from Evercore.

Sean Morgan: So, as we kind of circle back to Hilli, I think the contract is up in July of ’26. So what sort of logistical challenges are there to moving an FLNG offsite? I mean, I imagine there’s not a whole lot of precedent cases in what’s happening, are there environmental concerns? And then in terms of the cost, does Perenco bear most of the customers who are disconnecting? And what do they do with all the undersea equipment when it’s no longer connected to FLNG on the surface?

Karl Fredrik Staubo: That is actually surprisingly simple because this is a standardized unit, which is designed to be redeployed at different locations. So effectively, what you need to do is to disconnect from the upstream pipe and the soft yoke, which is the mooring system and off you go. The unit even has engine and propeller. So theoretically, you don’t even need tugs, but subject to where you go, you probably need a tag. And that’s it. The only thing we leave in the ground, which we need to decommission is the bottom part, which is fixed to the seabed of the mooring system, which we think has a total decommissioning of around $5 million.

Sean Morgan: Okay. And then I guess you have on a calendar basis, about two years. But as you — as a management team, you guys realized obviously the equity markets start to look ahead and equity markets don’t tend to love uncertainty. You would have the game up and running by then. So, it’s not like you wouldn’t have any assets producing, but what sort of time line are you sort of internally thinking about for when this needs to get completed and moved so you don’t start to run into a bit of an uncertainty overhang?

Karl Fredrik Staubo: I think as we tried to explain earlier, as long as — from an engineering and operational point of view, you have very comfortable time if you have charter visibility by mid next year for where the unit will recontract. That leaves plenty of time to plan decommissioning. Any potential vessel upgrades or amendments and new mooring locations set up a new shore base and everything that’s required. So that’s comfortable. It’s certainly not lost on us that the capital markets appreciate earlier visibility and frankly so do we. But at the end of the day, there’s the internal trade-off between what’s industrially right in terms of optimizing economics of the project versus just fixing an uncertainty. And with the level of interest we see around the ship now, you don’t necessarily want to marry the first one that shows up at the door but have a little round on the dance floor to see who delivers best.

Sean Morgan: Okay. I like that super analogy. So hopefully, this Hilli turns out to be the prettiest girl at the ball and we have a lot of choices on where that asset goes. Thanks a lot Karl.

Operator: Thank you. And there are no further questions at this time. I will hand the call back to Karl Staubo for closing remarks.

Karl Fredrik Staubo: Thanks again, everybody, for dialing in and listening to us and the interest and very relevant questions and we will continue to progress the Company to the best of our ability. Hopefully, we’ll speak before. But if not, we will speak to you all again in the next quarter. So thanks again, and have a great day.

End of Q&A:

Operator: Thank you. This does conclude the conference for today. Thank you for participating, and you may now disconnect. Speakers please stand by.