Good day and thank you for standing by, and welcome to Golar LNG Limited Q1 2022 Conference Call. Please be advised that today's conference is being recorded. 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 am 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 two 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 promptly available FSRU globally, currently operating as an FLNG carrier. We have developed three FLNG designs that form the basis for our growth. All three 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. Other results of significant corporate transactions over the last 12 months include three listed shareholdings. We own 6% of New Fortress Energy valued at $558 million at 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. The total value of these investments amounts 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 FLNG, as well as the first-ever integrated FSRU to power plants project. We have market-leading operations and have achieved 100% commercial uptime since the startup of Hilli in 2018. We're now focusing these companies for FLNG growth opportunities. Turning to Slide 5, 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 sheets. We currently have $1.4 billion of cash and listed securities, which is about half cash and half listed securities. Currently, we have a net cash position. Adjusting for the remaining CapEx on the FLNG Gimi, we have a total net debt position after the delivery of Gimi of $300 million. That number excludes operating profits between now and Gimi delivery, so we anticipate that will be lower. Based on increased capacity utilization of Hilli, commodity upside on the tolling fee, and the startup of Gimi in Q4 of next year, we expect EBITDA generation to quadruple in 2024 compared to 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 the 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. Turning to Slide Number 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, which is up 36% compared to Q4 last year. Since January 1st, we've started to realize our TTF linked production from FLNG Hilli, which added an incremental EBITDA of $22 million. I will explain those different elements in more detail further in this 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 for future FLNG units, and we have a strong pipeline of opportunities for growth projects. Moving on to shipping in FSRUs, the formation of Cool Company was successfully completed this quarter. We raised $275 million in a private placement in January, followed by the listing of its shares on the Euronext exchange in Oslo. In connection with that, Cool Company acquired eight of our TFDE vessels. In May, we announced the award of a EUR269 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. Since the start of this year, we have released $470 million in cash proceeds from the Cool Company spin-off and also the sale of a portion of our NFE stake. In February, we repaid $317 million of our outstanding convertible bonds, and we 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 outstanding. Moving on to Slide Number 8, this quarter we recorded an adjusted EBITDA of $93 million. This result is inclusive of Hilli, Arctic, and Tundra, but excludes the eight TFDE vessels that were sold to Cool Company. When compared on a like-for-like basis to the previous quarter, this represented a 55% increase. Net income attributable to Golar was $345 million in this quarter, and that includes a $168 million noncash gain, recognized on our Hilli Brent oil and TTF linked derivative, along with a $344 million noncash market to market gain recognized on our NFE shares based on the March 31 position, which carries 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 debt relates to four TFDE vessels that were sold to Cool Company in April. This leaves us with $1.2 billion of contractual debt post the completion of the eight vessel sale. Total cash at the end of Q1 was $329 million. Considering subsequent events that took place since the end of the quarter, including, for example, the $253 million of sale beneficiaries, 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 close to $1.4 billion. We estimate that this amount could allow us to fund two new FLNG growth projects. Moving on to Slide number 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. Notably, this increase of almost 3.5 times compared to Q1 of 2021 came without any additional CapEx to Golar. While the base tariff remained consistent with 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 disruption we have entered. Assuming 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 discuss debt and forward-looking aspects.

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 2.5 times 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. Perenco, the charter for the unit, has a one-time three-year option to declare up to 0.4 million tons of increased production from 2023 until the end of the contract in July 2026, on the same TTF linked tariff as the current 0.2 produced this year. The option is declarable by the end of July, and we see it as increasingly likely that Perenco will take up the option, supported by 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 the expiry of the option in July. The commodity exposure on Hilli enables us as an FLNG provider to charge significantly higher tolling fees for traditional long-term arrangements. As illustrated, the effective 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, presents an extremely compelling risk-reward scenario. We will continue to target similar types of structures. Turning to Slide 12 and an update on the construction of the FLNG Gimi, which is now 83% technically complete for conversion at Keppel Shipyard in Singapore. We have worked over 19 million man-hours on the conversion. The remaining 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 this is a situation we are monitoring closely and feel comfortable with 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 three different designs, all based on a generic design, meaning that they will not be tailor-made to a specific field, allowing them to be redeployed or interchanged, thus increasing operational flexibility and minimizing 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 design 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 the liquefaction topside on a new ship midsection 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 first direct solution for somewhat larger production projects than for Mark I. Lastly, our Mark III new build design, one we have worked to develop for more than a decade, has a liquefaction capacity of up to 5 million tons and is competitive with larger shore-based liquefaction solutions. The lower CapEx per ton and lower carbon footprint compared to land-based solutions make the Mark III a more economical and faster-to-deploy liquefaction solution for large liquefaction projects globally. The new build hull also allows for increased storage and leg space. Thus, our primary focus going forward is to develop projects that suit one of these three design alternatives. On page 14, we outlined why we mainly focus on floating African LNG projects when we look at our growth pipeline. When considering FLNG growth projects, there are three key input factors that drive the delivery cost for LNG: source gas, liquefaction costs, and shipping distance from production to the end user. We believe that you can develop a stable source gas price of between $1 to $3 per MMBtu depending on the size of the field if you target African gas. This compares to current spot prices for Henry Hub source gas in the U.S., where most 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 distance to end users, whether they are in Europe or in Asia, compared to U.S. liquefaction projects. Hence, with lower input costs, lower CapEx per ton, and shorter shipping distance, we 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 on earlier occasions. But 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 cost on a tolling fee basis similar to what we charge BP on the Gimi of between $2 to $3 per MMBtu, and shipping cost of around $1.50, African FLNG projects can deliver LNG to end users for about $5 per MMBtu today. Comparing that to current gas prices, these projects have a repayment period of less than one year in the current market environment. This backdrop drives our FLNG project pipeline for potential charters and explains 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 fees, as proven by the FLNG Gimi. 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 is viable in most historical LNG price scenarios. However, we strongly believe that energy and gas prices over the next 10 years will be significantly higher than the previous 10 years, making FLNG an even better business going forward than what we have seen historically. Regarding illustrative economics, a tolling fee based on a large Mark III 5 million ton FLNG unit at a $3 tolling fee can generate an EBITDA of such a unit of around $750 million a year versus a CapEx of around $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 the current gas price environment, that would create an annual EBITDA of $2.5 billion for the project owners, which we aim to split between the upstream provider and the FLNG owner. So whether you choose integrated or tolling, it presents an attractive business. If you believe, as we do, that we will see higher energy prices, you want to focus on integrated exposures. Turning our intention to FSRUs and the developments 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 has a total of 32 import facilities, of which 29 are land-based and three are FSRUs. Year-to-date, we have seen 22 potential FSRU projects surfacing, where eight have already secured an FSRU and 14 remain in the planning stage. This compares to a global FSRU fleet of 46 units and an estimated availability of another three to five units total between now and 2025. Thus, we see three to five units available to service up to 14 incrementally planned FSRU projects. We at Golar have received strong interest from several European countries for our open modern FSRU, the Golar Tundra. Turning to Slide 18, you can see that the gas price fundamentals keep strengthening and providing length. Starting on the far left, you can see the forward prices in May last year, in January this year, and on the 28th of May. The point being, while the front month is consistently rising, we’re encouraged to see future gas prices also lifting, enhancing visibility for potential FLNG charters. In the midsection, you can see the expected liquefaction projects to come on between now and 2028. These essentially pre-, I would call it, pre-Ukraine Russia situation liquefaction projects, which will seem to be needed to meet a balanced LNG market going forward. The far right of the slide shows statistics indicating how significant the impact of the Ukraine-Russia situation may be on the need for liquefaction going forward. The global LNG market was last year at 400 million tons, with Russian pipeline gas exports to Europe being about 115 million tons, over 25% of the global LNG market. Hence, if European countries are to meet their ambitions to replace Russian gas with international LNG, a significant ramp-up in not only re-gas terminals but also gas sourcing is necessary. Keep in mind that the gas price in December was significantly higher than what it is today, even amidst the current situation. Therefore, we expect this to be a fundamentally tight market. In light of geopolitical shocks, we predict 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. The Golar Arctic is the only remaining steam LNG carrier in our fleet, and it is by far the least competitive asset we have. We entered into an agreement with Snam, where they will pursue the development of a virtual pipeline into Sardinia. Snam is listed and has a market cap of around EUR18.7 billion. The transaction is a forward sale of the Arctic at €269 million payable in installments as defined by milestones. Our estimated conversion CapEx is $160 million, excluding contingencies and vessel costs. We believe that by executing this transaction, we have significantly enhanced the value of the ship. We found a long-term use for this steam carrier, and we leverage the learning effects from a recent and similar conversion of the Golar Viking, which was sold to LNG Croatia. Turning to corporate and Slide 21, Golar recently announced our 2021 ESG report, which is now available on our website. We maintain a very strong safety record and have improved regarding lost time injuries. We have high-graded our AER data, and we're proud to report that throughout the pandemic, we have maintained a very high retention rate. We have more than 70% of cadets still employed with us, and for senior officers, we have a retention of more than 94%. This is not only essential to maintain high-quality operations, but it's also important for future growth, especially in light of LNG and new buildings coming on stream going forward. Moving to Slide 22, which highlights the earnings potential from our existing asset portfolio, in the last 12 months, we made $148 million in EBITDA. Adding to that the contractual EBITDA of Gimi starting in Q4 of next year and the commodity upside on production from Hilli, we expect our run rate EBITDA to exceed $400 million from 2024 onwards. Therefore, on a fully delivered basis, we trade at an EBITDA of just shy of seven times, with the capacity to potentially take on at least two FLNG growth projects from our current balance sheet position. To summarize on Slide 23, we are a leading owner and operator of pioneering maritime LNG infrastructure, and we expect our EBITDA to quadruple in 2024 compared to 2021 levels. We have cash and listed securities of $1.4 billion and fully delivered net debt of less than $300 million. Our book value currently stands at $2.54 billion, and we remain very focused on our FLNG growth pipeline going forward. That concludes our Q1 presentation. Now, I will hand it over to the operator for questions.

Thank you. We will now begin the question-and-answer session. The first question comes from the line of Chris Tsung from Weber Research.

Can you provide some color on the decision for Snam to convert the Arctic? Was it based on price, timing of deployment, or price preference by Golar Tundra between any of the two vessels?

This is a project that we have developed with plans over a long time; it predates the geopolitical situation in Europe. The backdrop for their decision is the success of the LNG Croatia and the capacity needs in Sardinia, as this would be a cheaper alternative than to acquire more modern tonnage for that specific project.

I see. And just a follow-up on that. Can we think of the difference between the sale price at EUR269 million and the conversion costs for change? Is that the vessel sale price a right way to think about it?

Sorry, you're breaking up a bit. Is that the difference between...?

The EUR269 million and the conversion costs; is that effectively the vessel sale price?

That's of course one way to look at it. If you take the difference between the deal and the net of outstanding debt of around $30 million, you get to the equity balance ownership.

And just one last quick one. Of the three designs, Mark I, II, and III, which one could we deploy the fastest?

We're currently working on projects on a tolling fee basis for Mark III. I'm going to integrate the 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.

Hey, Karl and Eduardo. I have a question regarding the potential conversions and new FLNG. As you mentioned, the net cash balance is quite strong and the net debt balance is relatively low. Would you consider financing these through cash, or would you prefer a more balanced approach that involves taking on additional debt? Or do you see potential expansion of FLNGs as a means to reduce leverage as you grow?

I think first and foremost, we have cash investment securities of $1.4 billion on the company's free cash flow positive every quarter going forward based on the current performance of the group. This means that all that money can be deployed to growth, and around half of it is already in cash form. So I think we can fund one FLNG project solely from available cash the way we see it right now, and should we get more than one FLNG project, we could look at our securities position or leverage Hilli and Gimi, which on average have very low leverage at the moment.

And then another question we get a lot, it's sort of difficult to gauge in terms of counterparties off the coast of Africa. You talked about the low price to extract gas reserves from that region, but when you think about contracting a new FLNG, do you go to the nation state that controls the oil field or are there a series of E&P partners that you would negotiate with first? And how's that process work in terms of converting an idea into an actual FLNG project?

We've started working with BP in Africa and are also collaborating with Perenco there. They represent our main partners in the region and are the ones engaging with the local government. This illustrates the variety of opportunities available, one involving a fixed tolling fee with a reliable partner for an extended period, and the other with more exposure to commodities. Our strategy primarily involves partnering with entities that have a strong presence in the country. However, this also sheds light on why it can be difficult to provide precise timelines for when projects will receive approval. While we are eager to move forward, we depend on government processes, environmental approvals, and upstream conditions, which are the main factors influencing the timeline rather than our or our partners' interest.

So beyond your two existing counterparties, is there like five to six other E&P operators working in that region, or is it a more limited scope of potential partners?

That's a fair statement that you have several other companies operating in that area. There are proven and associated gas reserves, and in this market, we do not want to waste the resource.

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

I would like to begin with the FLNG aspect. You have been working on this for a while, and could you describe how your conversations with customers today compare to a year ago? There has been some belief that positive developments would occur, but there haven't been significant advancements in recent years. So, what makes the current situation different?

I think what's happened is mainly current driver of gas development, 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 this project become significantly better, which drove the incremental increase in interest. The first six months were influenced by the Russia-Ukraine situation. After that, we've seen a massive scramble from Europe to secure FSRUs. They are now gradually moving into the LNG carrier market, and you can observe term rates almost being below what was operational, even as we enter into the soft part of the year because Europe is scrambling to ensure energy security. Countries now understand that the market was tight. They have created import terminals but haven't secured hydrocarbons. Hence, we see a lot of these countries leading the way. For example, Germany first approached Qatar, then the U.S., and recently announced that they regard African gas as a significant part of Europe’s energy solution. This development is ongoing, and we can more easily secure offtake and financing than we could pre the Russia-Ukraine situation.

So the people seem to be more serious; is that sort of the takeaway here?

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

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

First part of the question is yes, we are also targeting geographies beyond Africa. That's why we say mainly African gas; we see the attractions of the input and the distance, but there are other areas, for example, in the Middle East where the gas is essentially free. So that's still part of our project considerations and developments. Sorry, I didn’t catch the second part of your question.

How do we think about when you say you can internally fund two projects, like Mark I versus Mark II, or a combination?

If you consider the capital expenditures for these projects, you can source that funding. For instance, Hilli had a $1.4 billion capital expenditure with $960 million in available debt, which means around a $500 million equity contribution. With a $1.4 billion balance in cash investment securities and the free cash flow from operations, we can finance it through our balance sheet. For larger assets, you can usually obtain yard financing, which simplifies the acquisition process.

So when you talk about self-funding two of these, it’s one of each; is that how to think about it?

We will select the projects we believe have the best economics. It could be either two Mark IIs, or one each of Mark III and Mark I; it remains to be seen when we announce the projects. We can comfortably fund two projects from our current balance sheet; the rest depends on timing. We generate cash flow consistently, so it depends on timing regarding which further units we pursue beyond those two. Our focus remains on getting to the next two.

Next question comes from the line of Craig Lewis. Please announce your company name.

Karl, I was hoping you could comment a little bit on the ongoing drilling campaign you highlighted in the press release and the well-passing that's going on in West Africa. I'm curious if the driver is customers doing those drilling campaigns. Will this potentially lead to more volumes for the Hilli, or could it lead to maybe an extension with Perenco?

That's a good question, and it's somewhat yes to both. The primary purpose of the drilling campaign we understand is to tie in more proven reserves, increasing gas flow and enabling the 0.4 million increase in production. However, we have clearly stated to both the market and Perenco that we will not enter extension discussions until they declare that point four, as we have already paid for equipment not fully utilized; every incremental production goes directly to net income or free cash flow. We do not wish to engage in discussions on extensions until we better utilize existing equipment. Nonetheless, we acknowledge that it could ultimately lead to extension discussions.

Realizing that we are selling the Golar Arctic, obviously, you're highlighting the Tundra and its opportunities. I have a two-part question: Is the path forward for the Tundra more around an asset sale, or could we see that contracted and remain a core part of the fleet? And piggybacking on that, are there opportunities for Golar to expand its FSRU footprint?

To your first question, at the beginning of this year, several FSRU projects were underway, none of which were in Europe. As indicated by recent geopolitical situations, the increase in new FSRU projects in Europe is unprecedented. We are confident the unit will ultimately end up in Europe. Various European governments have expressed interest in both chartering and acquiring units. We aim to do what presents the best risk-adjusted economics, whether via sale or charter. We feel positive about the Tundra's situation. Regarding the second part of your question, going forward, our focus is on FLNG projects, as we believe we have a unique competitive edge. We still think the economics of FLNG projects are most compelling in the LNG value chain over the next decade. That said, we have no non-compete in any of our corporate transactions, so should an attractive FSRU project arise, there’s no reason we wouldn’t consider it. However, we emphasize that our primary focus is on FLNG growth.

Next question comes from the line of Craig Shere from Tuohy Brothers.

So besides the Golar Tundra 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 the timing and announcement of a full 2.4 MTPA deployment of the Hilli post your mid-2026 Franco contract expiration?

Regarding source vessels for Mark I or Mark II, these will mostly be based on old design carriers, specifically steam carriers that will face significant operational challenges due to new environmental regulations effective January 1. Therefore, these vessels will become less suitable for operation as LNG carriers and more appropriate for floating storage jobs or as conversion candidates for FSRU or FLNG. The number of these ships becoming less competitive in shipping requires limited companies with proven redeployment or recharacterization track records, assuring us that we will have vessels available for conversion candidates. On the second part regarding Hilli, we generally prioritize A before B, and our next step for Hilli is to secure the 0.4 million tons by July of this year. After that, we will assess options with the Cameroonian government to find solutions to maintain that unit, as it has been a substantial economic success for both parties. The operational track record indicates the unit has no construction risks, and it is the quickest FLNG available internationally; its attraction for potential assignments outside of Cameroon is rising by the day. In terms of potential development timelines, we estimate a timeframe of around 12 months after the 0.4 million response to be more precise, likely by summer next year.

And one last question on FLNG negotiations for new projects. I think we understand that the upstream producers are your counterparties. How many upstream producers in Africa have firm relationships regarding royalties, profit sharing, and what have you with the host governments? To the degree there’s a major upsizing with your FLNG that reopens these discussions, does that complicate negotiations since the host governments want to capture more value from the current market?

That's an extremely qualified question. You're addressing the core issue of why some of these projects are challenging to guide on regarding timing. It's fair to say that neither us nor any upstream partners would proceed without clear agreements with host governments on these specific points, including the agreements on how profits should be shared, flexibility, and so forth. This serves as the key barrier for new FIDs. However, the flip side is that these are stranded gas reserves. Monetizing those fields requires our technology and proven capabilities. Today, we don’t see anyone else doing floating liquefaction as a service; we have a very proven track record for this. Therefore, I believe we are the solution for monetizing that unit. It's about finding a fair framework that works for the government, the upstream partner, and us.

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

On the NFE shares, how are you guys thinking about those in terms of holding them until you need to monetize ahead of a new FLNG project, or what’s the thinking there?

That's a good question, Chris. We received 18.6 million shares as total consideration when we sold High Growth as part of the agreement. Earlier in May, we sold one-third of that holding, freeing up $253 million. We appreciate the development of NFE and like the direction they're taking. However, we have no lock-up, board system, or access to any nonpublic information. Hence, we are free to manage that shareholding as we choose. Currently, it seems more advantageous to hold NFE shares rather than cash. Additionally, we possess significant balance sheet flexibility to fund at least one FLNG project without touching those shares; we see ourselves as holders for the time being.

Is there any room for greater partnership with New Fortress now that they are entering the floating LNG market with offshore rigs? Is there any expertise you could offer or any discussions there?

I think it was disclosed by NFE and Wes Edens on their earnings calls. We at Golar are currently collaborating with NFE to develop their first LNG solution on both the engineering and operational sides. Keep in mind, Golar still operates all maritime assets like the ships and the FSRUs that we sold to NFE. We maintain a good working relationship at all organizational levels. Currently, no specific plans exist, but we would certainly welcome opportunities for collaboration when the right opportunity arises.

Next question comes from the line of Nick Linan.

How many yards do you think can do Mark I or Mark II conversions? And how many could do Mark III new builds? Do you have guaranteed slots for either of those types of work? And if so, when do those options expire?

That’s a very correct observation; they are becoming extremely busy. To some extent, this presents an unusual situation for anyone in the maritime space; it has not been seen since the 2006 to 2008 cycle. However, the capacity has significantly diminished since then, and the resurgence in activity has resulted in longer lead times amid a global supply squeeze. To answer your question regarding Mark III, we believe there is essentially one shipyard capable of handling that type of conversion. We are currently in discussions to secure slots. Shipyards typically prioritize aggressive LNG carrier and container orders but save space for large offshore infrastructure projects over time. They have learned that shipping markets are cyclical and should maintain their engineering and offshore capabilities. Consequently, they are conserving some slots for larger projects; however, they have limits on how long they can hold those slots amid pressures from container and LNG carrier orders. We've developed a long-standing relationship with the pertinent key yards and are actively working to secure slot options for Mark IIIs. When it comes to Mark Is, we built at Keppel in Singapore, which we consider the best yard available for Mark Is. We have not sought other options and have no intention of doing so. For Mark IIs, that customization is expected to be done at a different shipyard than those utilizing Mark I or III techniques. Thus, we have one shipyard we’re working with for Mark III and a different shipyard for Mark IIs.

Thank you. 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 the good questions. 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.