Golar LNG Ltd (GLNG) 2022 Q1 法說會逐字稿

Good day, and thank you for standing by. Welcome to the Golar LNG Limited Q1 2022 Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Karl Staubo, CEO. Please go ahead.

Thank you, and welcome to Golar LNG's Q1 earnings results presentation. Thank you for taking time to dial in. My name is Karl Fredrik Staubo, CEO of Golar LNG. Before we get into the presentation, please note the forward-looking statements on Slide 2. I'm accompanied today by our CFO, Mr. Eduardo Maranhao to present this quarter's results.

On Slide 4, we have outlined the company overview. Golar today owns 2 FLNGs, the Golar Hilli in operation in Cameroon and the Golar Gimi under construction to start a 20-year contract with BP from Q4 of next year. Furthermore, we own an LNG steam carrier, the Golar Arctic where we announced last week that we have agreed with Snam to forward sell the ship as a converted FSRU. Lastly, we own the Golar Tundra, the most modern promise available FSRU globally, currently operating as an R&D carrier. We have developed 3 FLNG designs that form the basis for our growth. All 3 designs are based on the same proven liquefaction technology, and we will highlight some of the key characteristics of the different capacities of the units later in the presentation.

As a result of significant corporate transactions over the last 12 months, we have 3 listed shareholdings. We own 6% of New Fortress Energy valued at $558 million on yesterday's close. We own about 31% of Cool Company Limited, the shipping spin-off we established during Q1 of this year. We own around 24% of Avenir LNG, a small-scale LNG shipping and terminal business, and the total value of these investments amount to approximately $720 million. Golar celebrates its 75th year of operation this year, 50 of which we've been actively involved with LNG maritime infrastructure assets. Golar has through its history, pioneered some of the key developments in the sector, including the industry's first FSRU, the first FLND as well as the first-ever integrated FSRU to power plant projects. We have a market-leading operations and have achieved 100% commercial uptime since the start-up of Hilli in 2018. We're now focusing the company for FLNG growth opportunities.

Turning to Slide 5. And again, as a result of the M&A activities over the last 12 months, with a total enterprise value of $6.2 billion at the time of sales. We have significantly strengthened our balance sheet. We currently have $1.4 billion of cash and listed securities where about half is cash and half is listed securities. We currently have a net cash position. Adjusting for the remaining CapEx on the FLNG Gimi, we have a total net debt position after delivery of Gimi of $300 million. That number excludes operating profits between now and Gimi delivery. So we anticipate that, that number will be lower. Based on increased capacity utilization of Hilli, commodity upside on the tolling fee and start-up of Gimi in Q4 of next year, we expect EBITDA generation to quadruple in 2024 versus 2021 levels. We've also refinanced corporate facilities, and we currently have no debt maturities until 2025.

I'll now hand the call over to Eduardo to present our Q1 results.

Thanks, Karl, and good morning, everybody. I'm very pleased to provide an update on our group results for the first quarter of 2022. So turning over to Slide #7, I wanted to show some of the highlights of this quarter. Starting with our FLNG units. Our first vessel, Hilli, continues to operate with a very solid performance, delivering 100% uptime. The Brent-linked kicker in our contract generated an incremental EBITDA of $16 million this quarter or 36% up when compared to Q4 last year. Since 1st of January, we've started to realize our TTF-linked production from 23, which added an incremental EBITDA of $22 million. I will explain those different elements in more detail further in his presentation.

Construction of our second FLNG unit, the Gimi, continues in Singapore and is now 83% technically complete. We continue to make substantial progress on commercial discussions with future FLNG units, and we have a strong pipeline of opportunities for growth projects. So moving on to shipping and FSRUs. The formation of Cool Company was successfully completed this quarter. We've raised $275 million in a private placement in January, followed by the listing of its shares in the Euronext Exchange in Oslo. In connection with that, Cool Company acquired 8 of our TFDEs vessels. In May, we announced the award of EUR 269 million contract with Snam for the conversion of the Golar Arctic into an FSRU. Due to the current geopolitical situation in Europe, we continue to see a very active FSRU market and have received inquiries from multiple European counterparts for the deployment of our last unit, the Golar Tundra.

We continue to strengthen our balance sheet. And since the start of this year, we have released $470 million in cash proceeds from the Cool Company's spinoff and also the sale of a portion of our NFE stake. In February, we have repaid $317 million of our outstanding convertible bonds and then also entered into a new bilateral corporate facility of $250 million. We've continued our share buyback program, and so far, we have repurchased approximately 400,000 shares this quarter, leaving 108 million shares after that outstanding.

So moving on to Slide #8. This quarter, we recorded an adjusted EBITDA of $93 million. This result is inclusive of Hilli, Arctic and Tundra, but excludes the TFDE vessels that were sold to Cool Company. When compared on a like-for-like basis to the previous quarter, this represented an increase of 55%. Net income attributable to Golar was $345 million in this quarter, and that includes $168 million noncash gain, which was recognized on our Hilli Brent oil and TTF-linked derivatives and also a BRL 344 million also noncash market-to-market gain recognized on our NFE shares, but based on March 31 position, which carried a value of $42.61 per share. Our share of contractual debt at the end of the quarter stood at $1.7 billion. However, $0.5 billion of that relates to 4 TFDE vessels that were sold to Cool Company in April.

So that leaves us with $1.2 billion of contractual debt, post the completion of the 8 vessel sale. Total cash at the end of Q1 was $329 million. When we consider the very subsequent events that took place since the end of the quarter, including, for example, the $252 million of sale of NFE shares. Our total cash position, including access to revolving credit facilities stood at around $870 million. Further to that, when we take into account the value of our listed securities in NFE, Cool Company and Avenir, we have a liquidity position of just close to $1.4 billion. We estimate that this amount could allow us to fund 2 new FLNG growth projects.

Moving on to Slide #10. I wanted to provide a bit more color on the breakdown of our share of the distributable earnings from Hilli. As a result of the higher Brent and TTF prices, our share of Hilli's EBITDA almost doubled from the previous quarter, reaching $57 million in Q1 of 2022. Interesting to note that this increase of almost 3.5x when we compare to Q1 of 2021, came at no additional CapEx to Golar. While the base tariff has stood in line with the previous quarters, we recorded an incremental $16 million from Brent-linked revenues and close to $23 million from TTF-linked earnings already net of the interest swaps that we have entered. When we assume the forward commodity prices, our share of the 2022 adjusted EBITDA from Hilli remains on track to reach around $245 million in 2022.

I will now hand over to Karl, who can talk a bit more about that forward-looking aspect.

Thank you, Eduardo. Turning to Slide 11, which elaborates on the embedded upside on the commodity exposure of Hilli's tariff. As you can see, during 2021, Golar's pro rata share of Hilli's EBITDA was $99 million. This is expected to grow by 2.5x for 2022 on the back of higher Brent-linked earnings, where Golar generates $2.7 million of EBITDA for every dollar Brent is above 60. This is expected to generate about $91 million of EBITDA for 2022. Furthermore, the startup of the incremental 0.2 million tons of TTF-linked production that commenced in January, added another $22.6 million in Golar's share of Hilli Q1 EBITDA.

For the full year, the TTF-linked production is expected to add $81 million in incremental revenue, where the TTF gas price exposure for Q2 and Q3 has been hedged at $25.38 per MMBtu. We remain open for Q4 TTF gas price exposure. Putting the charter of the unit as a onetime 3-year option to declare up to 0.4 million tons of increased production from 2023 until end of the contract in July 26 on the same TTF-linked tariff as the current 0.2 produced this year. The option is declarable within end of July, and we see that increasingly likely that Perenco will take up the option on the back of strong gas prices, but subject to the final outcome of the drilling program to tie in more reserves to Hilli.

We do not expect Perenco to take up the option until closer to expiry of the option in July. The commodity exposure on Hilli enable us as an FLNG provider to charge significantly higher tolling fees for traditional long-term tolling arrangements. As you can see from the boxes on the slide, the effect in tolling fee for Hilli during 2021 was $3 per MMBtu. This has increased to an effective tolling fee of $13 per MMBtu during 2022. Hence, the commodity exposure of our FLNG contracts, both existing and the ones we will target going forward, we see an extremely compelling risk reward. And we will continue to target similar type of structures.

Turning to Slide 12 and an update on the construction of the FLNG Gimi. She is now 83% technically complete for her conversion at Keppel shipyard in Singapore. We have currently worked over 19 million man-hours on the conversion. The remainder of the build is mainly around construction, installation and testing of equipment ahead of her 2023 sail-away and Q4 '23 startup. In light of the recent resurgence of COVID in certain parts of Asia, we continue to closely monitor and take precautions for any potential COVID impacts for the 3,500 workers on site. We currently have no material impact on site. And again, this is a situation we are monitoring closely, and we feel comfortable with the situation where it stands today.

Turning to Slide 13, and as promised earlier in the presentation, elaborating on the different FLNG designs we have available. We have developed 3 different designs, all based on a generic design, meaning that they will not be tailor-made to a specific field, but can be redeployed or interchanged increasing operational flexibility and reducing residual value risk. They're also based on the same proven liquefaction topside and an extension of Golar's proven operational track record. The Mark I has a liquefaction capacity of up to 2.7 million tons a year and is suitable for stranded and associated gas resources. Both Hilli and Gimi are Mark I design FLNGs and are based on conversion of existing LNG carriers. The Golar Tundra remains a Golar-owned conversion candidate for potential future incremental Mark I units.

The Mark II design is also a conversion of an existing LNG carrier into an FLNG. However, instead of adding liquefaction equipment to the width of the ship, Mark II places a liquefaction topside on a new ship mid-section added to an existing carrier. This allows for larger liquefaction capacities of up to 3.5 million tons and reduces the conversion construction time. Hence, this is a fast-track solution for somewhat larger production projects than from Mark I.

Lastly, our Mark III newbuild design is one we have worked to develop for more than a decade. Mark III has a liquefaction capacity of up to 5 million tons and is competitive also to larger shore-based liquefaction solutions. The lower CapEx per ton and lower carbon footprint even compared to land-based solutions make the Mark III, a more economical faster to deploy liquefaction solution for large liquefaction projects globally. The newbuild hole also allows for increased storage and deck space. So our primary focus going forward is to develop projects that suit one of these 3 design alternatives.

On Page 14, we outlined why we mainly house on floating African LNG projects when we look at our growth pipeline. When considering FLNG growth projects, there are 3 key input factors that drive the deliver cost for LNG. Those are sourced gas, liquefaction costs and lastly, the shipping distance or shipping costs from production site to the end user. We believe that you can develop a stable source gas price of between $1 to $3 per MMBtu, dependent on the size of the field in question, if you target African gas. This compares to current spot prices for Henry Hub source gas in the U.S., where most of incremental liquefaction projects are planned of around $9 per MMBtu today.

Secondly, as we are building a fit-for-purpose efficient liquefaction design in Asia, Golar's CapEx per ton compared to other floating or shore-based liquefaction solutions is very competitive. Lastly, African gas from a geographical point of view has a shorter sailing business to end users, whether they are in Europe or in Asia compared to U.S. liquefaction projects. Hence, if you have a lower input cost, a lower CapEx per ton and a shorter shipping distance, you should have a compelling competitive advantage when looking at the economics of incremental growth projects.

Elaborating on that on Slide 15. Again, this is a familiar slide that we have presented at earlier occasions, it gives a strong picture of the LNG value chain and the economics of an FLNG project. With source gas in Africa at around $1 per MMBtu, liquefaction costs on a tolling fee basis, similar to what we charge BP on the Gimi of between $2 to $3 per MMBtu and shipping costs of around $1.50. African FLNG projects can today deliver LNG to end users for about $5 per MMBtu. If you compare that to current gas prices, these projects have a repayment of less than 1 year in the current market environment. This backdrop drives our FLNG project pipeline for potential charters and also explain why Golar is focused on projects where we can get exposure to commodity prices, driving the effective tolling fees significantly higher than for long-term tolling fees as proven by FLNG Hilli. This business model doesn't only work in a high gas price environment.

On the right-hand side, we have highlighted the $5 MMBtu of landed LNG price versus historical LNG prices. This business model makes money in most historical LNG price scenarios. However, we are strong believers that the energy and gas prices the next 10 years will be significantly higher than the previous 10 years. And hence, FLNG should be an even better business going forward than what we have seen historically. In terms of illustrative economics, a tolling fee based on a large Mark III 5 million tons FLNG unit and a $3 tolling fee, we can generate an EBITDA of such a unit of around $750 million a year versus a CapEx of around SEK 2.5 billion for such a large unit. Integrated projects, however, using a 2.5 million ton Mark I design, as an example, and the landed gas price of $25 per MMBtu, in current gas price environment, that would create an annual EBITDA of $2.5 billion to the project owners that we would target to be split between the upstream provider and the FLNG owner. So whether you go integrated or tolling, it's an attractive business. But if you believe as we do that we will see higher energy prices, you want to focus on integrated exposures.

Turning the attention to FSRUs and the development that we have seen in Europe year-to-date. We have highlighted how the FSRU market has significantly changed on Slide 17. Entering into 2022, Europe had a total of 32 import facilities where 29 are land-based and 3 are FSRUs. Year-to-date, we have seen 22 potential FSRU projects surfacing, where 8 has already secured an FSRU and 14 remains on the planning stage. This compares to a global FSRU fleet of 46 units and an estimated availability of another 3 to 5 units in total between now and 2025. So the way we see it, it's 3 to 5 units available to service up to 14 of incrementally planned FSRU projects. We, at Golar, have received strong interest from several European countries for our open modern FSRU, Golar Tundra.

Turning to Slide 18. You can see that the gas price fundamentals keep on strengthening and keep on providing them. Starting on the far left, you can see the forward prices in May last year in January this year and the 20 of May. The point being is, one thing is that the front month is constantly lifting, but we're encouraged to see the future gas price also lifting, providing further visibility for potential FLNG charters. On the mid side, you can see the expected liquefaction projects to come on between now and 2020. These are essentially pre -- I would call it, pre-Ukraine-Russia situation, liquefaction projects. And this was seemed to be needed to meet a balanced LNG market going forward.

On the far right, we've taken some statistics to show how meaningful the impact of the Ukraine-Russian situation may be on the need for liquefaction going forward. The global LNG market was last year 400 million tons. Russian pipeline gas exports to Europe was last year about 115 million tons or 25% of the global LNG market. Hence, if European countries are to make reel their ambitions to replace Russian gas with international LNG, we need to see a significant ramp up, not only of regas terminals with key focuses on right now, but gas sourcing. Keep in mind that the gas price in December was significantly higher than what it is today, even in the midst of the current situation. So this is a fundamentally tight market, pre-geopolitical shocks and after we expect it to be significantly stronger for longer.

Turning to Slide 19 and a bit further background on last week's announced forward sale of the Golar Arctic. Golar Arctic is the only remaining steam LNG carrier in our fleet. By a long while, the less competitive asset we have in our fleet. We entered into an agreement with Snam where they will pursue a development of a virtual pipeline into Sardinia. Snam is listed in Italy and has a market cap of around EUR 18.7 billion. The transaction is a forward sale of the Arctic at EUR 269 million, payable in installments at defined milestones. Our estimated conversion CapEx is $160 million, excluding contingencies and vessel costs. Hence, we think that by doing this measure, we have significantly high-graded the value of the ship. We found a long-term use for a steam carrier, and we leverage on the learning effects we did from a recent and similar conversion of the Golar Viking, which was sold to LNG Croatia.

Turning to corporate on Slide 21. Golar recently announced our 2021 ESG report, now available on our website. We continue a very strong safety record. We improved lost time injuries, we high grade our AER data, and we're proud to say that throughout the pandemic, we have maintained a very high retention. We have more than 70% of cadets still employed with us and for senior officers, we have a retention of more than 94%. Not only is that important to keep high-quality of operations, it's also important to cater for future growth, especially in light of the LNG new buildings coming on stream going forward.

Turning to Slide 22, highlighting the earnings potential from our existing asset portfolio. In the last 12 months, we made $148 million of EBITDA. And to that, the contractual EBITDA of Gimi starting in Q4 of next year and the commodity upside on the commodity linked production from Hilli, we expect our run rate EBITDA to be more than $400 million from 2024 onwards. And on a fully delivered basis, we trade at an EBITDA of just shy of 7x with capacity to add at least another 2 FLNG growth projects just from our current balance sheet position.

To summarize on Slide 23. We are a leading owner and operator of pioneering maritime R&D infrastructure. We expect our EBITDA to quadruple in 2024 versus 2021 levels. We have cash and listed securities of SEK 1.4 billion and net -- fully delivered net debt of less than $300 million. We have a book value of standing currently at $2.54 billion, and we are very focused on our FLNG growth pipeline going forward.

That concludes our Q1 presentation. And I'll now hand it over to the operator for questions.

(Operator Instructions) And the first question comes from the line of Chris Tsung from Webber Research.

Can you provide some color on the decision for Snam to convert the Arctic compared to (inaudible) Tundra? Was it based on price or timing deployment or perhaps preference by Golar to unload the remaining steam vessel?

This is a project that we have developed with Snam over a long time. It predates the geopolitical situation in Europe. I think the backdrop for their decision is the success of the LNG Croatia and the capacity needs in Sardinia and that this would be a cheaper alternative than to buy more modern tonnage for that specific project.

I see. All right. And just on -- just a follow-up for that. Can we think of the difference between the sale price that EUR 269 million and the conversion cost (inaudible) is that the actual sale price is that the way to think of it?

Sorry you're breaking up a bit. You said the difference between --

EUR 269 million and the conversion cost, is that effectively the vessel sale price?

That's of course, one may you can put it. So if you take the difference between the (inaudible) outstanding debt of around $30 million, you get the equity balance.

Understood. Great. Okay. And just one last quick one. Of the 3 designs, the Mark I, II and III, which one could be deployed the fastest?

We're working on projects on a tolling fee basis for Mark III on an integrated basis, where we are balancing the decision between Mark I and II. So it's difficult to say which one comes first. Currently, it's tempting to say Mark I or II.

Next question comes from the line of Sean Morgan from Evercore.

Karl and Eduardo, question on the potential conversions and new FLNGs. You said that net cash balance is obviously -- net debt balance is actually quite low. So you could potentially finance these out of cash. Would you want to do that or would you look at a more balanced approach to incorporate more debt or do you kind of look at a potential expansion at LNG as a way to sort of deleverage as you drill?

I mean, first and foremost, we have cash and listed securities of $1.4 billion and the company is free cash flow positive every quarter going forward based on the current performance of the group. So that means that all that money can be put to growth and around half of it is already in cash. So I think we can fund one FLNG project just out of available cash, the way we see it right now. And should we get more than one FLNG project. We could look at the listed securities position or re-lever on Hilli and Gimi, which on average, has very low leverage at the moment.

Okay. And then another question we get a lot, it's sort of difficult to gauge is in terms of counterparties off the (inaudible). You talked about the low price to extract the gas reserves from that region. But when you think about contracting a new FLNG, do you go to sort of the nation state that controls the oilfield or is there like a series of E&P partners that you would kind of be negotiating with first? And how does that process work in terms of converting an idea into an actual FLNG projects?

If you think about it, we work for -- we are about to start to work for BP in Africa, we are working for Perenco in Africa. So on both of those, that explains to you who the counterparts are in that context, it's BP and Perenco and they are the ones interfacing with the local government. And to some extent, there are a good representation of the different sort of opportunity set. One of them on a fixed tolling fee to a solid counterpart for a long time and one of them with more commodity exposure.

So the way we're working this is mainly with partners with a significant presence in country, but it also explains some of the reasoning why it's a bit difficult from time of time to guide on expected timings of when projects will be sanctioned because we want to have done it yesterday and so can the charter but you are reliant on governmental -- environmental time-offs and upstream to be in place, and that's really what's driving the timeline more than the interest from either us or the charter.

Okay. And so beyond your 2 existing counterparties, is there like 5 to 6 other E&Ps that are working in that region or is it more limited scope or potential partners?

That's a fair statement that we have several other gas operating in that area. You have a lot of proven and associated reserves and in this market that's the way to resource.

Next question comes from the line of Ben Nolan from Stifel.

Yes so, I guess, I'll start again on the FLNG side. There's been -- you guys have been working on this for a while. And maybe could you just characterize what the conversations are like today with your customers versus maybe a year ago? There's obviously been some thought that there would be some positive developments, but there haven't been any major incremental ones in the last number of years. So how do you think now is different, I guess, is the question?

I think what's happened, but this is mainly currently a driver of the gas fundamentals and the fact that the gas market is tight. You just see the amount of interest when the gas price is high, the economics for these projects is significantly better, and that's what drove the incremental increase in interest the first 6 well -- up until the Russia-Ukraine situation. After the Russia-Ukraine situation, you've seen first a massive scramble from Europe to secure FSRUs. Now they're slowly moving into the LNG carrier market, and you can see term rates almost in double vessels operate, even as we enter into the soft part of the year because Europe is scrambling to secure energy security.

And then ultimately, they now understand that the market was tight, they have created import terminals, but they haven't got their hands on the hydrocarbon. So you'll not see a lot of these countries leading the way, you've seen the likes of Germany, first go to Qatar then the U.S. And yesterday, they announced that (inaudible) African is a significant part of European Europe's energy solution. So that's coming. And with the European countries, you can more easily secure offtake and financing, then you could pre the Russia-Ukraine situation.

Okay. So people seem to be more serious, is that sort of the takeaway here?

The economics are better, and the financing and offtake are more available than ever.

Okay. And then for my second question, I might slip in it 2 for on this one, but -- so you talked primarily about Africa and you gave the illustrations about Africa. In the past, you guys have talked about other regions like the Middle East and the Mediterranean and different other places. Are those still on the table, first of all or are they substantially behind it? And then for part #2, you talked about 2 -- being able to fund 2 incremental units, but Mark III, the cost is substantially different than a Mark I. So is that assuming like on 1 Mark III, 1 Mark I or how should we think about how you're thinking about 2 units?

Third quarter (inaudible) yes, it's also other geographies of West Africa. That's why we say mainly African gas because we see the attraction of the interest and the (inaudible). But there are other areas, for example, in the Middle East, where the gas is essentially free. So that's obviously still part of the project and the considerations or development, but we are focused mainly on African, but there are other projects as well, both in the Middle East and elsewhere. Sorry, the second part --

Just how to think about when you say you can internally fund 2 projects Mark I versus Mark II or a combination?

If you take the CapEx on this, you have -- of course, you can source debt funding. So if you take the example of Hilli, for example, we have -- when we built upon, it was a $1.4 billion CapEx, and we have $960 million of debt available. So that's call it $500 million equity check. And with the $1.4 billion cash in listed securities balance and the free cash flow to equity positive operation, we can fund it to FLNG. When it comes to the larger assets, you can typically get yard financing, which you cannot as easily get for conversion.

Okay. So when you talk about self-funding entities, it's one of each? Is that how to think about it?

We will take the projects that we think (inaudible) the economics. If that's 2 Mark IIs or 1 Mark III and a Mark I remains to be seen when we announce the project.

Okay. But just 2 in general, that's the capacity as the takeaway. Okay.

We can comfortably fund from the current balance sheet and the rest is a timing thing. So we generate cash flow pretty much every day. So it depends on the timing of when further units beyond those 2 but I think if we double the FLNG fleet, we can look at our situation at that point. Look for now, the focus is on getting to the next 2.

Next question comes from the line of Greg Lewis.

Karl I was hoping you could comment a little bit on the ongoing drilling campaign you highlighted in the press release and the well testing that's going on in West Africa? And really, what I'm curious about, and maybe it's a little bit of both, is the driver or are the customers doing those drilling campaigns? Is that going to potentially lead to more volumes for the Hilli or is it potentially going to lead to maybe an extension on the Hilli and then with Perenco?

It's a good question and it's kind of yes to both. So the primary purpose of the drilling campaign we understand is to tie-in more proven reserves so that you increase the gas flow and enable the 0.4 million in increased production. What we have very clearly publicly stated, both to the market and of course, to Perenco and SNH, the governmental body in Cameroon is that we will not enter into extension discussions until they declare that 0.4 million because currently, we, of course, have paid for equipment that also (inaudible) and every incremental production is straight through to net income or free cash flow to equity, if you like. And we don't want to be working on any expansions until we better utilize the equipment already in place. But if we find substantial gas, that should lead to expansion discussion as well. But for us, it's sort of -- you have to tackle one obstacle at the time. And for us, it's the increased production that's the key driver on Hilli right now.

Yes -- no, perfect. And then, realizing that we were selling the steam, the Arctic, obviously, you're highlighting the Tundra and the opportunities to the Tundra. I guess a 2-part question there. One is, as we think about the path forward for the Tundra, is that more around an asset sale or could we potentially just see that be contracted and remain a core part of the fleet? And just piggybacking on that question, are there opportunities for Golar to expand its FSRU footprint?

Okay. So to the first part of your question, at the beginning of this year, there were several FSRU projects being worked, none of them in Europe. I think with what happened in the geopolitical situation, as we tried to highlight on the slide, the incremental increase in new FSRU projects out of Europe is unprecedented. And on the balance, we are very confident that, that unit will end up in Europe and not elsewhere. If you look at what's communicated by the various governments in Europe, some of them are targeting chartering opportunities, and some of them are targeting acquisition of units. I think, for us, we remain agnostic whether we sell a charter. We will do what we think caters for the best risk adjusted economics. And that's our target.

And with the amount of interest and the specification of Tundra, we feel very comfortable about that situation. When it comes to the second part of your question, what we want to focus on going forward is FLNG project because we think we have a unique competitive edge. And we still think that the economics of FLNG project is the most compelling in the LNG value chain, at least for the next decade or so. However, we have no noncompete with any of the corporate transactions that we have concluded over the last 12 months. And should there be an attractive FSRU project coming up -- there's no reason why we should not take it on. However, I would highlight that our focus is FLNG growth. Look we remain open to anyone who wants to talk to us for any attractive LNG infrastructure business.

The next question comes from the line of Craig Shere from Tuohy Brothers.

So besides the Gandria that you already have, how do you see availability of vessels for acquisition for additional Mark I or Mark II conversions? And do you have any thoughts about timing and announcement of a full 2.4 mtpa deployment of the Hilli post your mid 2026 current contract expiration?

Okay, Craig when we talk about source vessels for Mark I and Mark II, those will most likely debate on a (inaudible) designed carrier. So the one with the balls on top. Both carriers are mainly steam carriers that will face significant operational challenges due to the new environmental regulations from 1 of January. So basically the new EEXI and CII regulations. Hence, these ships will be less suitable to operate on LNG carriers and more suitable for floating storage jobs or as conversion candidates, whether for FSRU or FLNG. Because of the amount of those ships that will become less competitive for shipping and therefore, need to find alternative work with a limited amount of companies with a track record of successfully redeploying or recharacterizing those type of ships, we're confident that there will be abundant that's also available for conversion candidates.

To the second part of your question, when it comes to Hilli, I think we always try to do A before we do B, before we do C and so forth. And for us, the next step from Hilli is to secure the 0.4 million tons in July of this year. After that, I think it's for sure, in Perenco and Cameroon's government to fortifying solutions to keep that unit in country. For both of them, this has been a massive economical success. And we think both of them have an interest in keeping the unit in country. On the other hand, I think the operational track record and the fact that the unit has no construction risk.

And lastly, that the very soon the quickest FLNG, you can get your hands on internationally, we think that in this gas price environment, her attractiveness for potential work outside of Cameroon is increasingly attractive by the day. So to try to give some guidance on when we think we have development there, we would say it's hard to -- probably up to 12 months after the (inaudible) by summer next year or so in that time period.

Great. And one last question on FLNG negotiations for new projects. I think you all understand that the upstream producers are your counterparties. But the -- how many upstream producers have in Africa, have set in stone relationships as far as royalties, profit sharing, what have you with the host governments? And to the degree there's a major upsizing of a play with, say, your FLNG, does that reopen these things and make very complicated discussions where obviously, the host governments want to get as much value from the current market as possible.

That's an extremely qualified question, and I think you're touching upon parts of the core of why the reason some of these projects is a bit difficult to guide on exactly when they will happen. I think it's fair to say that neither us nor any upstream partners would enter into such projects without very clear agreements with both governments on these specific points that you touched on like the agreement on how things should be shared, flexibility and so forth. This is basically the key gating item in terms of timeline for the new FIDs.

The flip side of the argument is that these are stranded gas reserves that are proven and no one has the technology to monetize those fields. That's what we cater for. And today, we don't see anyone else doing FLNG or floating liquefaction as a service, with a proven track record at least. Therefore, I think we are the solution in terms of monetizing the unit and it's a matter of finding a fair framework that works for the government, the upstream partner and for us.

Next question comes from the line of Chris Robertson from Jefferies.

I apologize in advance, it's a little mundane. But on the NFE shares, how are you guys thinking about those in terms of -- are you just wanting to hold them until you need to monetize ahead of a new FLNG project or what's the thinking there?

That's a good question, Chris. So I think as you know, we got 18.6 million shares in total consideration when we sold the share component of the consideration. Earlier in May, we solved 1/3 of that holding, freeing up $253 million. We like the development of NFE. We like the direction they are taking the company. However, we have no lockup and no (inaudible) and no access to any nonpublic information. Hence, we're pretty much free to do what we want with that shareholding. The way we see it now, it's far better to hit NFE than to hit cash, and we have significant balance sheet flexibility to fund at least one FLNG projects without touching that facility -- sorry, those shares. And for now, we are holders of the name.

Okay. Is there any room for, I guess, the greater partnership with New Fortress now that they're getting into some floating LNG with offshore rigs? Any expertise that you could offer or discussions there?

I think as disclosed by NFE and Wes Edens on his earnings call, we are, as Golar working together with NFE, helping them out to develop their FLNG solution, both on the engineering side and also on the operational side. Keep in mind, Golar still operates all of the maritime assets like the ships and the FSRUs that we sold to NFE. So we have a good working relationship on sort of all levels of the organizations. There's currently no specific plans, but I think we would certainly be open to working together when the right opportunities arise.

Next question comes from the line of [Nick Linnane] from (inaudible).

How many yards are there that you think can do final Mark III conversions? And how many do you think could do Mark III new builds? And do you have any guaranteed slots to do those types of work? And if so, like when you have options on those slots until it seems like the yards are getting quite busy?

That's very correct observation. The yards are getting extremely busy. So to some extent, that's a bit of an unusual situation for I think anyone in the maritime space, we haven't seen that in sort of the 2006 to 2008 cycle. But then again, the yard capacity has been built down significantly since then and then the resurgence in activity has caused longer lead times. And obviously, the general supply squeeze globally. But to answer your question, on Mark III, we think it's essentially one shipyard that we are -- that we think is up to the part. And on that one, we are in detailed discussion about securing slots.

The way the shipyards think about things is that they are, of course, selling most of the capacities to fairly aggressive LND carrier and container orders, but they are saving some space for what they call large offshore infrastructure projects. They have learned over time as most other people that the shipping markets are cyclical. And it's not wise of them to build down engineering and offshore capabilities because you never know when they are in the land and when that ramps up activity. So they are saving some slots for larger projects, but it's a limit to how long they hold the slots, given the pressure on container and LNG carrier orders.

That said, I think we have long-standing relationships with the key yards in question, and we are currently working to secure slot options for Mark III. When it comes to Mark Is, we have built Keppel in Singapore, and we think that's the best shipyard to build Mark Is. We have not explored others, and we have no intention to explore the others for Mark Is either. When it comes to Mark IIs, that's considered to be done at a different shipyard from both Mark Is to Mark IIIs. So basically, we have one select shipyard we've been working on for quite some time, on Mark II and III, and we're already having a very established relationship with Keppel and Mark Is.

There are no more questions at this time. I would like to hand back over to Karl Staubo for final remarks.

Thank you all for listening in and for good questions. And we look forward to connecting with you next quarter. Have a great day.

That does conclude our conference for today. Thank you for participating. You may all disconnect.