Good morning, everyone, and welcome to the New Fortress Energy First Quarter 2024 Earnings Conference Call. Today's conference is being recorded, and all phone participant lines are in listen-only mode, but later we will have an opportunity to ask questions. To get us started today with opening remarks and introductions, I am pleased to turn the floor over to Managing Director of Strategy and Investor Relations, Mr. Chance Pipitone. Please go ahead, sir. Thank you, Lisa, and good morning, everyone. Thank you for joining today's conference call, where we will discuss our First Quarter 2024 results. The call is being recorded and will be available by replay on the Investors section of our website under the subheading Events and Presentations. At this same location, you will find a presentation that we will walk through on today's call. Please review this as it includes important information, including disclosures and risk factors. With that, I'll now hand over the call to our Chairman and CEO, Wes Edens. Great. Thanks, Chance, and welcome, everybody. As usual, please refer to the materials that we sent out as that's what we'll be using to kind of walk through the financial presentation for the day. Flip to page number three, and first, let's start with the results. Quarterly results were very solid: $340 million in EBITDA, right on top of our estimates, still tracking on our guidance for the year. Financially, a very, very good quarter for us. Financial results were exactly as expected in the past, so the rest of the year is now very clear. Our business now is one that is fully focused on generating long-term, sustainable, and growing results, and we've never felt better about it than we do today. Now let's turn to page four, and I'll talk about each of the three major updates that we'd like to talk about and introduce them for you, and then turn them over to the guys that run each part of these businesses. Brannen McElmurray, who runs our Puerto Rican operation; Andrew Dete runs the Brazil operation; and then Chris Guinta, our CFO, who's also in charge of our Fast LNG projects. Let's turn to page 4 and talk about it. First, Puerto Rico. Let's just put where we are today into context. We went to Puerto Rico in the fall of 2017, three days after Hurricane Maria, saw the devastation of the island, saw the need for power and for cheaper power, and went to work. Built the logistics chain to bring gas and power into the island, opened our terminal in June of 2020, right in the middle of COVID, and entered into a contract for roughly 25 TBTUs to provide gas to San Juan for the first time. This is a big first step for us. Three years later, in 2023, in response to a FEMA process, we bid successfully, and were awarded the contracts to build two additional power plants, 425 million MW of power in total for FEMA and the Army Corps. We did so in record time. The power has been dispatched 98% of the time, so it's been highly reliable. It's provided the critical 15% of the margin to the system and has had a massive impact on the island. This has been a very powerful economic result for us, as you know as well, but the most asked question we get is, "How will this transition, and what will be the long-term future for us with respect to this and other gas opportunities on the island?" Today, we have that answer. The government has done exactly as we said that as we thought that they would. When FEMA decided to end the contract, the decision that was made to not only keep the power plants on and keep them using gas but to also greatly expand the use of natural gas around the island. The goal from the Puerto Rican government is very simple: first, replace distillate fuels, diesel and fuel oil, with gas. It's much cheaper, it's much cleaner, and it can be done throughout the island with our extensive logistics chain. So when the government terminated the agreement, they also put out for the bid a contract to provide gas for roughly twice as much fuel as what's being used by FEMA. The 40 TBTUs that they were using previously now goes to 80, and the term that they were using it for extends from one year to four. Twice as much fuel, much longer duration. What we said before is exactly what we expected to happen: sell more fuel at a lower price so we make less money on the margin, but we make it up on volume. Brannen will walk through in detail, but in simple terms, the need for on the portfolio across the island is for a total of about 300 TBTU, and we detail that in the presentation. So even with this new contract, we are now at 105 TBTU. So think of 25 from the original contract, another 80 from this contract. That's approximately 2 million tons of LNG, so it's a very significant downstream customer for us, but it only represents only about one-third of what the current need is. So it's really an amazing outcome for us and an amazing outcome for Puerto Rico. Simply switching fuel from distillate fuels to gas will save them billions at no capital cost to the island and cut emissions dramatically. And this then paves the way for the next leg of this, which is exactly what we expect them to do now, which is now to go out and build new efficient generation plants to replace the old power plants. This will increase the reliability of the system dramatically. It'll extend the term of our contracts and save even more money for Puerto Ricans. What's left for us in Puerto Rico and our business is simply long-duration, highly sustainable, highly predictable gas contracts for us all, which is amazing. That's the outcome that we are looking for, and with this today, we can see the path to getting there exactly as we predicted. The last piece of the FEMA situation is the economic resolution of the early termination of the contract. There are clear contractual obligations that now will be met. This is an ongoing process that should be resolved in the near term and under terms that are agreeable to both parties. Brannen will detail this, but it's a very, very good outcome for us and a good outcome for them. This will complete the transition for us, and we'll be able to provide much more clarity to you in the coming quarters as to the marginal economics of Puerto Rico, just as we have marginal economics of each of our major markets. Second item up that I wanted to highlight is Brazil. Brazil is, without question, the greatest gas-to-power situation in the world, and one where we're in a dominant position to transact. It has every element you could possibly wish for. It's large. The size of the country is large. It's significant: 200+ million people, one of the biggest energy markets in the world. Number two, need. 75% of their power in their system is renewable, which is great. It provides baseload production for a very, very low cost, but it is not entirely reliable in all situations. So what they need is baseload, dispatchable power to balance the system when the sun doesn't shine or the rain doesn't fall. They have been running capacity auctions for nearly 20 years in Brazil, so the term structure and the plumbing of how they auction off this capacity is very, very well known. To date, they have auctioned nearly 30 GW of power, and they have recently announced another 8 GW to be auctioned off later this summer. The duration of these power assets that we have there is very, very long-term: 15 and 20 years in total, 18 years on average. Very, very long-term, very easy to predict economics. Next, credit quality. These are direct obligations of the Brazilian government, basically sovereign risk directly from the government, which is the largest country in South America. So it couldn't be better in terms of the need, the duration, the credit quality of the contracts we enter into. And lastly, and of course, from our perspective, the most important is we have a massive competitive advantage here. We have two huge LNG terminals that are completed and are up and running operationally today. They are delivering gas into the system as we speak. The way the auctions are structured, you need to provide power immediately at call. Capacity simply means that when the sun doesn't shine and the rain doesn't fall, they can call you, and within 72 hours, you're asked to provide the power to them. The only way to do that is to have standby gas and power. The only way you can have standby gas and power is with LNG. The only LNG terminals that are down there that are owned privately are the ones by us. It's a massive competitive advantage. This is not just a theoretical in-the-future opportunity for us. What we've accomplished to date down there is incredible. We have both terminals operating. We have one 2.2 GW of power that is under construction today, and it will be delivered next summer and the summer afterwards. On the books is $500 million of highly predictable and long-duration cash flow, wholly owned by us, fully funded, and has the potential for it to grow significantly with these auctions this summer, which we have an incredible competitive advantage to talk about. We're now in the middle of the process of thinking through how to bring this value to our shareholders, and we're in the middle of the process to do two things: one, to bring in a partner or partners to buy a piece of the business, both to return capital from our original investment and also to validate the value of the business, both of which we think are going to happen. We think that'll be a process that culminates this summer, and it'll be shown an attractive valuation to us and provide liquidity to us back on our original investment. And two, we expect to file this company for an IPO this summer, probably in July or August. We'll see how the auctions transpire in the fall and then get this into the equity markets. We think the valuation proposition for investors is tremendous, and obviously, the derivative of that is the valuation to us. It's an incredible opportunity. It's an incredible portfolio of assets that exists today. It's an incredible management team with huge growth opportunity, and that translates into huge value for our shareholders. Third item on the list is the FLNG update. Today, the liquefier is mechanically complete. We are in the final stages of commissioning it. We expect gas in the matter of the next several days, not months. We expect the first cargo in June. This is the culmination of many years of hard work. It represents a huge accomplishment for our team, both here and in the field. It represents an incredibly valuable asset for us that we can then finance in the manner of all other LNG projects once it's completed in operations. Putting finance against this will allow us to repay significant amounts of corporate debt, lower the cost of our debt, and extend the term, which are all very important and achievable financial goals for us as a company. That's the update. With that, let me turn it over to start with Brannen. Brannen? Yep. Thank you, Wes. And I'll refer to page seven in the presentation, and I appreciate you all joining us this morning. As Wes so often says, "Affordable, clean, reliable power is the cornerstone of economic growth, and in that regard, a majority of the world is underserved." For our business, we seek to address that need by providing infrastructure solutions that are responsive to needs today with technology that supports a desired future. Puerto Rico is a great example of executing on that strategy. As Wes said, we've been investing in Puerto Rico since 2017. We have a large and growing energy presence there, and we've been growing our footprint and expanding our franchise for about six years. Today, our portfolio includes a world-class LNG terminal, which is the only terminal in the north where most of the population is and the demand center, so it's perfectly positioned on the island. In addition, we have logistics assets, which include off-island logistics chains, which are ships both large and small, on-island logistics chains, which are trucks and ISOs, and of course, our outstanding operational personnel and expertise. This logistics chain allows us to reach each and every customer on the island of Puerto Rico and service it through our existing terminal. In terms of customer contracts, we initially started with a 25 TBTU contract for San Juan 5 and 6, which itself has generated hundreds of millions of savings for Puerto Rican ratepayers. In March 15th of this year, we entered into an 80 TBTU islandwide contract, which allows us to serve Palo Seco, San Juan, incremental power plus additional sites, which fold into our strategy in terms of gasification around the island. In total, this is 105 TBTU, which is a significant portion of Puerto Rico's entire energy need, but it has room to grow from there. And finally, we have our Genera Asset Management Platform, which today manages over 4,000 MW of installed power at 12 plants across the island. We have approximately 800 people, and we manage a budget of over $3 billion. In short, this particular platform allows us incredible visibility and also the ability to integrate with the transformational plan in Puerto Rico as the asset base transforms from distillate to natural gas over time. These assets, together with our people and expertise, position us perfectly to execute on our priorities, of which we have two. One, accelerating the transition from distillates to natural gas. In short, as Wes mentioned earlier, this transformation would save Puerto Rican ratepayers $1 billion a year. To put that in perspective, that's the equivalent budget for the Department of Education and its spends on teachers every year. So this kind of savings year-over-year is incredibly impactful in this jurisdiction. The second priority is adding more reliable generation to the system. In addition to saving money, what reliable generation allows us to do is also to accelerate the transformation to renewables on the island and fundamentally take the asset base now, retire old and inefficient units, replace it with natural gas-fired units that over time will support batteries and solar as the island transitions, consistent with its public policy to a net-zero grid. Put simply, NFE is uniquely positioned to drive transformation of the Puerto Rican energy system because of its existing infrastructure, on-the-ground organization, and market knowledge. Turning to page eight. As Wes also mentioned, a majority of the power in Puerto Rico still runs on diesel and heavy fuel oil. This is a very unique situation for the U.S. and its territories. Big picture, less than 1% of the power on mainland U.S. runs on distillate, versus approximately 60% in Puerto Rico. This energy mix for Puerto Rico contributes to it having the highest price for electricity and the worst electricity in terms of service in the U.S. and its territories. This creates an incredible situation for NFE, and this opportunity we intend to push forward with our existing assets. Our goal here is to transform the grid from one that relies on diesel and HFO today to renewables and gas in the future. So how are we doing that? In March, we took that step by entering into an 80 TBTU islandwide contract, as Wes mentioned, adding to our existing 25 TBTU portfolio, bringing us to 105 TBTU. If you look at the graph on the left or the chart on the left-hand side of the page, it's interesting to think about it from a demand perspective. We've bucketed our opportunity into four categories. First, gas now, and those are assets that exist and run on gas, exist, could run on gas, and just needed supply, for example, the 80 TBTU contract that we just entered into. In sum total, that's one gigawatt. The second category is gas-ready, which are assets that today could run on gas but today run on diesel and so need both infrastructure and a little bit of work on the units to make them gas-ready, but these are projects that could be done in under six months. Today, that's about 600 MW. Then there are additional conversion opportunities, which roll up to about one gigawatt. And as Wes mentioned, there are plans on the board and active steps being taken on the procurement side to build new generation, partly Genera PR's responsibility for about half and then partly responsible for the P3 and an ongoing procurement. Altogether, this will roll up eventually to about 1 GW of additional power that'll be there long-term. This illustration to the right basically points out a very simple fact, which is once the distillates are pushed out of the system, which would also include coal that's being operated by a private operator, all in the chart on the left, including new generation, if dispatch at 80%, is approximately 300 TBTUs for the island. That encompasses today's demand and then where we expect and hope Puerto Rico will grow as their economy expands. The end state of this is we expect all oil and HFO power on the island to be retired and the island to be powered simply by natural gas supplemented with solar and battery, and that is going to be Puerto Rico's future. Our business is perfectly positioned to capture this growth, and our job is to drive that transition as fast as possible. What is unique about Puerto Rico is there's complete alignment between our strategy, public policy, and just the sheer economics of what will happen. And so this is simply a question of time, and our job is to accelerate that time as fast as possible and to convert these cash flows into long-term, durable earnings that further increase the value of our franchise. Moving to page nine. As Wes touched on, we had an incredibly successful year last year from an installation and execution perspective by responding to a FEMA mandate to install emergency power. We built 425 MW of fast power across two sites. Both projects were done in less than 120 days, both based on two-year contracts with Weston and the Army Corps. Both projects were viewed as incredible success stories from our side, the federal government side, Puerto Rico's side, and the ratepayer side. This is a highly unique situation given the success of this project and given the real-world on-the-ground impacts. Our contract ended on March 15th. We then switched to a longer-term contract with the government of Puerto Rico for gas on the 16th of March, and on the same day, we sold the power plants to the government of Puerto Rico. So this 425 MW that started off as temporary power will effectively become permanent. Discussions are ongoing with Weston and the Army Corps on terms of our settlement. They've been incredibly constructive and positive. We're finalizing our claim submission, and the recovery is expected to be significant. Just for perspective, the gross amount owing under the remaining term for both contracts is over $1 billion, and we expect those discussions to progress and end constructively as well. We continue to invest in Puerto Rico and expand our franchise there by adding essential infrastructure. These projects and the experiences they bring can be readily applied to other markets addressing similar challenges, creating opportunity for NFE and other jurisdictions seeking solutions to accelerate the energy transition and driving value to NFE as a solution provider and, of course, to our shareholders. I will now turn it over to Andrew to talk about Brazil. Great. Thanks, Brannen. Thank you, everybody, for joining us this morning. Excited to be talking with you about Brazil. There's three main points I'm going to go through here. The first is an update on our two LNG terminals, which are now online, are contracted for the long term, and we're making rapid commercial progress. The second is describe the near-term growth opportunity, mostly at our Santa Catarina terminal, around the announced power auctions Brazil and growing LNG supply through that terminal. And then the third one is to update you on our capital plan for Brazil, which Wes mentioned a little bit. So turning to page 11. We've talked a few times about this in the last calls and updates, but just to kind of level set where we are in Brazil today. So in February, we turned on two LNG terminals, one in Barcarena, one in Santa Catarina. The FSRUs hooked up to the pipeline. We finalized commissioning, and now we have 12 MTPA of LNG import capacity in Brazil. That's over 600 TBTUs a year. We also have contracts for 2.2 GW of contracted power with an average duration of 18 years and 50 TBTUs of baseload gas supply, also with an average duration of 18 years. That leads to $500 million in contracted EBITDA on a run-rate 2026 basis. We have effectively completed now our regional strategy of bringing online critical infrastructure for Brazil that would deliver on both the power and the energy needs of these regions and the country as a whole. Flipping to page 12, we want to give a little bit more of a deep dive on the Barcarena terminal and how we're constructing the commercial portfolio here. So first is our Norsk Hydro Agreement, so 15-year gas supply agreement that's fully started. We are ramping up that contract now as we commission each boiler and calciner in the aluminum refinery for Norsk Hydro, and we hope to expand. This is the sort of classic NFE project but done at scale. So we have benefits for Norsk Hydro in terms of cost, especially with a more volatile oil market. We've got benefits for Norsk Hydro in terms of maintenance using gas versus distillate fuels is much cleaner. And then we've got huge benefits for the region on emissions and on local air quality. So we're seeing immediate benefit. This is exactly kind of what the mission of the company is, and we're really happy to be in this long-term agreement. And we're working to expand it and really to power the whole facility is our hope at some point in the future. Second is the Barcarena power plant, so 630 MW, 25-year PPA. This project is about 60% complete under a fixed price, date certain EPC contract with Mitsubishi and Toyo Setal. That'll come online in July 2025. And then the third big contract here is the Portocem power plant. That's 1.6 GW. So on December 23rd of 2023, we announced the acquisition of this PPA. Between December 23rd and, I think, March 17th, we effectively completed the transfer of this PPA from a state in Brazil called Ceará to our site adjacent to the Barcarena terminal. We have also, during that time, signed a fixed price, date certain contract for construction with Mitsubishi and Andrade Gutierrez, and we have financed the project at the asset level and started construction. So really rapid progress here in terms of being able to use our existing infrastructure to acquire this project and really begin construction. This will turn online in July 2026, which is why you see most of our numbers kind of on a run-rate 2026 basis when these three big contracts are online. We've also signed two other small contracts at the port for almost 1 TBTU but important contracts to us with Imerys and Alubar, who are located right next to Norsk Hydro. So just pausing on Barcarena for a second, and if you see the graph on the right, this is really, for us, really the footprint of what a great LNG terminal looks like. We've got our terminal there in yellow at the top, so extended jetty in the FSRU. We've got the Norsk Hydro facility on the right side of this page where we're supplying gas long-term. And then we've got the two sites for building power that we own to the left. If you think about the overall portfolio composition, we have one FSRU with 6 MTPA of capacity. We've got 2.2 GW of power, and we're basically, today, reserving 4 MTPA of contracted LNG supply. 1 MTPA of that is for baseload supply under the 18-year duration agreements that we talked about, and then 3 MTPA of that is reserved for when these power plants dispatch. And that price is connected to the JKM spot price plus a very significant premium. This is really set up with a combination of baseload supply, contingent supply, and then long-duration fixed capacity fees from the power plants. Flipping to page 13, I want to provide an update on our Santa Catarina terminal. Exciting developments here. First is that we've signed our first commercial contract in Santa Catarina, which is with the Trans-Bolivia Gas Pipeline System, which we refer to as TBG. We've signed up two different products with TBG. First is just baseload gas supply, which will be used in the pipeline system to run the compression. And then second is a really important thing that'll become more of a theme for us in South Brazil, which is we're providing balancing to the pipeline system. So basically, on a daily basis, we will help the system inject gas to balance out customers, which basically, as they supply almost, I think it's 200 customers on the pipeline system, we'll be able to help them balance their daily needs against some of the domestic gas that's also in that system. So really providing the flexibility that's necessary for this pipeline system. The second big opportunity here is the announcement of the 2024 power auctions in Brazil. So those were announced in March for an August 30th auction and really represents the huge commercial opportunity for Santa Catarina and for the power system in the south of Brazil, which we'll talk about here on page 14. So Wes alluded to this a little bit, but Brazil is really, really unique for us because we can't find another market that has the following three things: majority intermittency, so Brazil is over 80% hydro and renewable. At scale, Brazil is over 200 GW grid, so I think the seventh-largest electric grid in the world and 200 million-plus people. And then we can't find a market like this that is majority intermittent, at huge scale, and also continuing to grow. So on the right side of this page, you can see how overall energy consumption and natural gas consumption per capita really lag behind the developed world in a very significant way and represent a huge opportunity for Brazil to continue growing. So this really is the market setup as we head into these power auctions. What we're going to see is that what we really need, and flipping to page 15, is we need in Brazil firm capacity. This page 15 shows not our forecast but the actual Brazilian regulator forecast. There's a group called EPE, which does this work in Brazil. What they forecast is a need for 20 GW of firm power to be added to the grid by 2032, which includes 8 GW that are going to be auctioned this year. What they do here is they forecast the retirement of the existing firm power. They forecast the growth in power consumption in the country, and they want to maintain a 5% grid reserve, which is pretty low. That's what shows this 20 GW of need. Brazil has actually done an amazing job of responding to the needs of the power system, which are effectively they need firm capacity. They need insurance in the fact that as consumption grows and you have days where hydro capacity and renewable capacity maybe isn't producing as much as you think, you have reliability. Brannen mentioned it, but the things you need for economic growth are affordable and clean power, which Brazil has in spades. But what they really need to work on and what they're focusing on is reliability. So if we flip to page 16, the opportunity for us at NFE is really to provide that reliability in a really dedicated regional strategy from the Santa Catarina terminal. So today, there's over 3.5 GW of existing power plants in the region that are connected to our pipeline system and do not have firm gas contracts or firm power contracts. NFE is also developing a number of greenfield sites that we will bid into the auction. What we really want the message to be and for people to understand on this call is the scarce resource here is incremental fuel supply and then flexible fuel supply. In order to run these capacity contracts, you need to have power plants that can respond to the grid in a matter of hours. That is what our LNG terminals allow because we can store gas and supply it throughout this pipeline system on an almost instantaneous basis. And so we're providing something which is a new import point and critically storage, which the grid in Brazil and especially in South Brazil does not have today. There's a reason that all these power plants do not have PPAs, and that's basically because they don't have fuel and they don't have flexible fuel. And so that's what we're going to provide at Santa Catarina. So what we believe happens in the auctions this year is that they will auction off 8 GW of new power contracts, all with 15-year terms for the new power plants and seven-year terms for existing power plants. We believe we can capture an opportunity of 2.5 GW. That will be both new-build power from NFE and also contracts where we supply power to sorry, supply gas to existing power plants for third-party owners. So that's what we have coming up in August of this year and what we're really positioning for the rapid development of the Santa Catarina terminal. Last page is page 17. So I wanted to provide an update on our Brazil capital planning here. The unique thing we have in Brazil is we have a business that is highly contracted today, so 500 MW or $500 million of EBITDA on a 2026 run-rate basis with just the contracts that we have today. And then we have a huge opportunity for growth. We think we can effectively double that with our Santa Catarina terminal and deliver almost $1 billion of EBITDA by 2028. So we stand at a really important time for the business, and what we want to achieve here is we want to capitalize the business for growth. We want to continue to grow very quickly. We want to continue to grow very capital efficiently. And we have this opportunity we've been talking about, the size of Brazil, the need for power capacity, and then the really effective mechanism and local capital markets that make this attractive. We'll look at a minority sale here in the near term, and we'll also look at an IPO later in 2024 to help continue to capitalize this business and grow into the opportunity we see available in Brazil. Chris, I'll flip it to you. Thanks, Andrew. Good morning, everybody. Let's flip to page 19 and talk through the FLNG projects. On this slide, we've included a recent photo of FLNG-1 offshore Altamira. The positive news is we are in the absolute final stages of commissioning. We've fully commissioned all safety systems, power and utilities equipment, the gas treatment modules, LNG pumps, and the LNG transfer hoses, and we're working on the final system to be completed, which is the MR compressor. I do want to take a moment and confirm that we did experience an incident with a pipe fracture inside of our cold box last Friday, April 26th. This is an extremely unfortunate given that we were expecting first LNG a mere 72 hours later. The pipe incident caused the box's insulation material, a non-toxic volcanic sand called perlite, to be emitted all over the rigs. Thankfully, no significant injuries were sustained, and as a result of our excellent team in the field as well as our preventative measures, together ensured that no adjacent systems were damaged. While the incident looked like it was much more extensive than it actually was on account of the perlite dusting, the damage was isolated to one pipe and manifold within the box and is expected to be repaired by next weekend. This is why commissioning is so important and why we've invested in excellent partners that have been overwhelmingly supportive as we try to move through the balance of the commissioning work and produce LNG. Moving on to slide 20, we talk about why we chose to insource the production of LNG and demonstrate the value of the FLNG-1 asset. We estimate the value of FLNG-1, the unit, exceeds $3 billion. This value is built up by a combination of, one, the cost to replicate the liquefier, and, two, the time value of having production in today's still elevated market for global LNG. We have talked with various EPC firms on what it would cost for a fully wrapped LNG project at similar size, and we've been provided a range of $1,300-$1,500 per ton excluding storage. This is just the cost paid to the EPC firm and does not include all of the project support expenses such as permitting, environmental studies, SG&A overheads, and, of course, interest during construction. The second reason is the fact that NFE's FLNG asset will produce approximately 280 TBTUs or a little more than 90 cargoes over the next four years, which is when the majority of the projects recently FID'd will come online. The value of this LNG sold into the current market is worth another $1 billion. So when you combine the $2 billion paid to the EPC with the carrying cost of developing the asset and the time value of LNG now, you have an asset worth well in excess of $3 billion. Let's flip to the next slide and talk about this with a little bit more detail. On slide 21 and last quarter, we talked about how the LNG supply market is dominated by investment-grade participants, and our FLNG solution is intended to be responsive to the needs of our customers now. As a result, NFE built an asset that has meaningful near-term cash flows as well as provides us long-term operational confidence. The graph on this page shows the value of having LNG production in the current market as opposed to an ordinary course SPA, which is priced around 115% Henry Hub plus 250. Over the next four years, which is about when a new SPA would begin providing cargoes to the buyer, our first Fast LNG unit will produce around 280 TBTUs of supply worth an estimated $1 billion using the forward TTF price less shipping. This year, in-the-money value of the LNG is remarkable, but the operational benefits are also important to recognize. First, it gives us surety of supply and ensures that we are not at the behest of producers with competing interests. Second, it provides increased flexibility to manage supply and demand imbalances at our terminals. And third, our location should see increased uptime as opposed to U.S. Gulf projects that have weather and congestion to contend with. So move to slide 22, and this is designed to share with you our plans for the FLNG capital structure moving forward. Our goal is to finance the assets on a secured basis with a project bond similar to what's been done in other LNG projects in the past. Granted, it made sense to finance the asset on balance sheet using corporate debt while it was under development, but we feel that this will be a better solution for us. We are targeting $1.5 billion-$1.75 billion in proceeds, which represents a low loan-to-value given the asset exceeds $3 billion, as we outlined on slide 20. This furthers the three primary objectives listed on this slide. First, the financing structure would provide longer-term with little or no amortization in order to match the tenor with the asset life. Second, the lower loan-to-value on an operational asset with fixed cash flow stream should yield a lower borrowing cost than the corporate parent. And third, given that right now this asset is pledged to the Term Loan B in the revolving credit facility, we would pay off both of these upon a successful financing, thus lowering our corporate debt. This financing model of building with on-balance sheet financing using corporate debt and then refinancing with asset-level bonds is the path we intend to deploy in a similar fashion on future FLNG projects. Now let's move to slide 24 and talk about the financial results for the first quarter. Total operating margin was $350 million from sales to customers through our downstream terminals, and we had another $34 million of operating margin from the ships segment. The $34 million in ships operating margin will be mostly flat for the balance of the year and then goes down in 2025. When you back out SG&A, our adjusted EBITDA for the first quarter was $340 million. The majority of the change from Q4 2023 is a decrease in the ships margin as well as the early termination of the FEMA contract. We're happy to report that, as has been the case in all of the second half of 2023, we had no material sales from open market cargoes. All of the earnings are coming from our downstream customers through our terminals or vessels. Move to slide 25, and this shows GAAP net income for the quarter, which was $54 million or $0.26 per share on a diluted basis. However, as Wes mentioned, this does include some noise associated with the loss incurred on the sale of the turbines to PREPA. So when you add back the non-recurring charges, it results in net income for the quarter of $138 million or $0.67 per share. The funds from operations for the first quarter was $189 million or $0.92 per share when backing out the non-recurring losses. As mentioned in the bullet on the right, the bulk of the non-recurring charges are related to the sale of the turbines to PREPA and part of the termination of the emergency power contract. As a refresher, we sold 14 TM2500s for a total price of $303 million. Of the units sold, NFE owned 11 and purchased three of the units that we were leasing. The way that the accounting treatment applies here is we have to include a cost basis in the turbines that we owned plus the purchase and payoff of lease obligations. Additionally, we included some maintenance obligations in the carrying value. All this leads to a loss of $78 million recognized in the quarter, and we further detailed in the 10-Q filed later this afternoon. Finally, when we settle out the remaining components of the claim in Puerto Rico, as Brannen and Wes discussed, those proceeds will be recognized in earnings. Quickly on slide 26, a comment about our financing strategy for the rest of the year. Now that terminal development is virtually complete and FLNG has been successfully deployed and soon to be operational, we are focusing on financing assets at the project level and using proceeds to reduce corporate debt. We met with the rating agencies over the past couple of weeks, and we will work with them on a review and update of our corporate credit rating, which we believe should be sitting squarely in the BB to BB plus range with a strong path to improvements over the next 12-18 months. As such, our goal is to, one, get upgraded and refinance the $875 million notes due 2024, pushing out the near-term maturities. And, two, execute on the previously mentioned rated bond deal secured by FLNG1 asset with estimated proceeds of $1.5 billion-$1.75 billion, which we will use to repay the Term Loan B in the revolving credit facility. This ensures we have a fully funded capital plan with robust free cash flow generation and sound financial policy. With that, I'll turn the call over to Wes for some comments. Great. I mean, so that's the update. It's been an incredible quarter for us and it's an incredible time in the life of the company. We're all very focused on our core initiatives, as we've just detailed. This will be the most productive summer of our lives if we continue to achieve what we're focused on in the very near term. There's one additional adjacency that's worth mentioning that we're also focused on. There's perhaps no greater growth need in the world than data centers, and there's no greater need in the data centers for core dispatchable power. Power is a core competency of ours. Rapid development of highly reliable power is what we do extremely well and have demonstrated that in a number of markets. We've received numerous reverse inquiries in our core markets of Puerto Rico, Brazil, and in Ireland on situations where people are looking for us to help provide the solution to allow them to develop the data centers. There's nothing to report today, but stay tuned on this. This could evolve into a direct adjacency of our core capabilities, and we're very focused on this opportunity. The company or companies that help solve these needs will benefit greatly. We're clearly focused on our core businesses. This is a direct adjacency that we think also has material impact for us in the future, and so it's just something I wanted to highlight. With that, I'm going to turn over a chance for a few questions. Thank you. Operator, if you would, let's open the lines up for questions. Thank you, sir. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure to mute. Your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll take our first question from Craig Shere with Tuohy Brothers. Please go ahead. Your line is open. Hi. Good morning. Thanks for taking the questions. So can your incremental Puerto Rico growth beyond the 80 TBTU PREPA contract also be linked to liquid fuel pricing to afford acceptable spreads during sustained elevated LNG market pricing? And can you update us on current spot LNG spreads to perhaps 73% of landed Puerto Rican diesel? And finally, any thoughts on hedging out LNG to liquid spread risk? I'll let Brannen talk about it specifically, but the nature of the conversation with Puerto Rico about this contract was to basically, during this interim period where they want to switch fuels and benefit from that while looking to enter into longer-term contracts, they want to make sure that they had a contract that ensured them savings. And so linking it directly to diesel was the simplest and most direct way of doing so. So 73% of diesel today, diesel's roughly $20, 73% is roughly $15. So $15 represents a significant savings versus what they're spending on diesel today, and it also represents significant margins for us relative to our business. Our view is that this is something that will actually is the correct algorithm and the right way to price this in the short term over this next four-year transition period. But I would expect long-term contracts for new developments would be direct Henry Hub-based. And so that's what I think we expect, and that's what you all should expect. And it's the same basic pattern of transition of how we go from a short-term contract to provide gas and power that was a very, very good contract for us with FEMA. We now provide twice as much fuel as we did to them at a lower price, but the P times Q, the quantity is greater, so there's more volumes to run through that. And then as they expand their needs around the island and actually look to longer-term generation, we would expect that to expand even more. As Brannen said, it's 300 TBTUs in total demand right now, which is roughly 3x what we have. Without knowing exactly how much of that will get converted and when it will get converted and what it is, all you can say is that it's 300% of what the current capacity is today, so it represents a meaningful increase to it. Brannen, do you have any thoughts about that? Yep. Just, I think that captured it perfectly. Maybe just the two quick ones, and then I think I'll hit one of your points. First of all, a more macro point, which I think is kind of highly relevant here, particularly when you think about the 300 TBTU. For the first time, actually, in probably 10 years, the official estimates for GDP growth and population growth in Puerto Rico are being revised up, basically from flat to maybe even slightly negative to now positive. Not that much different than what other people are seeing, but really a tremendous opportunity for them because even if you kind of think about our plans in terms of generation that exists today and transformation, etc., most of that has historically been based on flat kind of projections going forward. But you can certainly imagine now what'll happen as the place grows. You need more power, and in particular, you need more gas- fire d power. So specifically, I think what you're asking about and actually what Wes indicated, the current contract for 80 TBTUs, which is really a four-year contract, one year with a few extension periods, which will certainly get exercised, in my view. What that really supports is the current fleet as it's being transitioned. But as Wes also mentioned, the idea and they're taking action on it, they are building now long-term power. So you could certainly imagine this diesel index over time migrating to a Henry Hub index and potentially even migrating to something that resembles more of a fixed price concept. In particular, because you raised it on the hedging, we have started conversations with them about that. They are deeply interested in it. And I think the idea here is if you're buying 25 years of solar on fixed PPAs, you might start to think about buying 25-year gas on a fixed price basis. So that's conceptually certainly something that will likely be discussed. But I think in particular, we expect there to be growth beyond the 80 TBTU. As Wes said, it'll be likely Henry Hub index. But as the whole energy complex moves to really gas plus renewables, what they're also trying to do is get long-term price certainty because that really, for them, supercharges the growth proposition on the island. Thanks. If I could just fit in one more quickly. From an adjusted EBITDA standpoint, thoughts on how to treat proceeds from settlement of the early FEMA contract end. And excluding that, is it fair to envision a U-shaped EBITDA performance as the lost FEMA contract is filled in over an extended period of time with the 80 TBTU FEMA contract, growing Genera contribution, and then the 630 MW Barcarena, Brazilian plant, and finally Nicaragua? The bulk of the money in the settlement would be earnings, right, simply. There's some that could be a return of capital for certain things that we have paid for and whatnot, but the bulk of the settlement would be expected to be earnings. With respect to the U-shape of it, it really is a function of how rapidly the transformation happens in terms of switching fuels from diesel fuels to gas. That is a multi-month process, not a multi-year process. As Brannen did a great job of kind of outlining, there are significant amounts of power on the island today that is gas-ready that actually can simply be hooked up and just needs regas capacity and maybe some very, very modest capital improvements that can burn gas today. But all of this can happen in a relatively short period of time. With respect to the U-shape with the rest of the company, it's a little harder to predict because simply there are some massive other issues that could happen in the short term, in particular, the developments in Brazil, turning this stuff on in Nicaragua, etc. I recognize that actually modeling the company during this period of transition is difficult. We've tried to get as much guidance as we can. You're probably a quarter away from being able to provide country-by-country data, which will make the modeling exercise much, much simpler. The one thing I can say with great certainty is, in any model result, it looks like the valuation proposition of what we have on the books today, not prospectively, is vastly greater than the sum of the parts in the capital structure today. So, I think that, A, that it'll be much, much simpler to model once all this transition is completed. That's why we are so positive about the events in Puerto Rico and elsewhere. But all you have to do is look at the numbers. The numbers that Andrew went through in Brazil, these are not theoretical forecasts. These are not theoretical growth numbers. These are actually in-place cash flows on existing assets. So when we forecast these over the next couple of years, we're really showing them actually on a direct basis. So when you add those into our current business, it doesn't look to me like there's a U to it at all. So I think timing differences over a quarter or two could happen, but certainly over a one or a two-year period, we think there is nothing but upside to our numbers from this point, both in terms of size but also in terms of duration, so. Ladies and gentlemen, we will move to our next question. It comes from Theresa Chen with Barclays. Please go ahead. Your line is open. Good morning. I wanted to follow up on the Puerto Rico side. As far as what is the timeline and pathway near-term to ramp to the 80 TBTU? Can you give us an indication of what the May volumes are? And And if that's possible here, please. Yep. Yep, sure. Yeah, this is Brannen. I think as Wes said, and I think actually the slide, I mean, in my view, actually lays it out well. Even from a modeling standpoint, if you kind of just start with the basics for what we have today, which is 25 TBTU going into San Juan 5 and 6, and then you look at the temp power that has now really been converted to permanent power, which all in is 425 MW, that exists today. Then if you look at the existing assets that are in Palo Seco, and then you look at the opportunity, for example, in Mayagüez and to add supplemental power, depending on the month you want to pick and depending on how you want to kind of model that in, the way I kind of think about it is you're likely to get there certainly by the end of the year and then want a ramp rate that starts off at 20 plus 30, so that's 50, going to 80 over the next quarter and a half. But depending on how you want to kind of think about that, I think the drivers of timing that you on our side, we're obviously racing to settle quickly, are a little bit of infrastructure, a little bit of logistics around asset movement, and then, of course, finalizing permits and permissions that you might need to increase utilization at some of these sites. But all of these are things that are in progress. I would say they're just very ordinary course events from a development perspective. And if you look at our history in Puerto Rico, we've obviously been highly successful getting those things done in the past. We've never not done it. Not to say there won't be bumps in the road going in the future, but we're very confident that we'll be able to do that. And then even beyond the 80, I think, as Wes indicated, I mean, there's incremental opportunity that we're working on at the same time. So I don't think our view, certainly my view is I don't view 80 as a ceiling. I view it kind of as a start. And then we want to see what we can do from there. It's very clear that the megatrend there is all the oil-fired and HFO stuff is going to be retired. On the Genera platform, we're in charge of those retirements. That's certainly driving that schedule. And so we're highly motivated to have that happen, not only because it's the right thing to do, but the island desperately wants to get to a scenario where they are gas-fired plus solar and battery. But I think that's how we kind of see it towards the end of the year and then certainly going into next year. But the trend is sort of, in my view, kind of up and to the right. We'll move to our next question. It is coming from the line of Sherif Elmaghrabi with BTIG. Please go ahead. Your line is open. Hey. Thanks for taking my question. I hopped on late, so I apologize if this has been asked. On the power auction in Brazil, can you remind us when this power would come online? Yeah. We'll start with that. Hey, Sherif. It's Andrew. So the announcement is for two different products. The first product is for existing power plants, and that's a seven-year contract. And effectively, because it's existing, would come on immediately. And then there's a product for 15 years, which is for new generation only, which you have to be online by 2028. But obviously, if you finish earlier, you can go to the agency and apply to start earlier. Because this is generally simple cycle power, we think it's probably a two-year build for larger power plants from when the auctions run. So that's kind of August 2024. So we think it would be online by the end of 2026, maybe 2027, for new power plants. And we expect to have a mix of those two products in our portfolio. That's helpful. Just to amplify a little bit. I mean, as Andrew said, when you think power auctions, I think that the knee-jerk reaction is to assume that it's going to come on two or three years from now because that would be the normal course of events. Given that there is a significant amount of power in the south that does not have gas, that would actually be eligible to bid into these auctions if they had gas, those are partnerships that we think are mutually beneficial for us potentially as a gas provider. And obviously, for them, they're life-changing because they can now bid an existing asset into the marketplace. So this is a unique situation where a gas auction or a power auction may well result in power turning on at the end of this year or early next year. And so these financial results that we're showing for 2025, 2026 may be increased by these kind of long-term auctions in the short term. That's what is so incredibly exciting about this from a valuation standpoint. Wes, you actually touched on my second question. But so for the 3.5 GW that you guys highlight on slide 16, the 3.5 GW of power plants without contract, is it possible to go merchant power and enter agreements with these plants directly? I'm thinking you highlighted Puerto Rico's desire for price certainty, but it seems like there's a similar opportunity in Brazil. Yeah. No, it certainly is possible. Brazil's certainly a different grid, though, right? So in many parts of the year in Brazil, you've got a lot of hydro and a lot of renewable power at very low cost. So there is a merchant opportunity there, but it's going to be more in times of stress where the cost of generating power at these plants is in the money. And we think that certainly is an opportunity. But the real big opportunity here is the auctions because they basically allow for a fixed capacity contract and then also the merchant opportunity as well, right? So when you have these capacity contracts, not only are you getting a fixed fee, but then you're also in the sort of regulated and organized market to generate when the system needs you on a JKM basis. We'll move to our next question that comes from Martin Malloy with Johnson Rice. Please go ahead, sir. Your line is open. Good morning. Thank you for taking my question. First question's on Brazil. Outside of the power auctions, could you maybe talk about the outlook for adding additional volumes? I know you mentioned the additional potential volumes for the Norsk Hydro facility. Could you maybe talk about how we should be thinking about other opportunities there? Yeah. So on the gas supply side, so we're announcing today our first contract at Santa Catarina, which is with the Trans-Bolivia Pipeline. It's about a 14 TBTU contract. We're also working with a number of the other large industrial consumers in the region. We've got about 300 TBTUs of consumption today on this pipeline system. And our terminal has a few benefits that are kind of outside of just molecule pricing. So first is basically the transport benefit we have. So customers that are buying from us will have a lower, basically, pipeline fee to pay than if they're buying from the other sources, which would be either Bolivian gas or offshore gas that comes from the north of Brazil. The second is we can help some of these consumers transition from buying from their regulated distribution companies to buying as what they call a free consumer in Brazil. So they can save some money on that by paying less in regulatory fees. And then also, they can get a contract from us, which is much more flexible and is usually designed really around their consumption patterns rather than kind of the inflexible contracts they have today. And then, of course, we can compete on actual price. But there's a few other benefits as well by kind of going with the more flexible, lower transport cost solution from us. So that's applicable to a number of the larger kind of industrial consumers who are typically good credits as well in Brazil. And we're working on that. We expect our portfolio in Santa Catarina to look a lot like Barcarena. So if we do this right, we'll have kind of 1 MTPA of baseload supply, which we'll make money on, and will also give us the ability to then go and contract the more intermittent capacity contracts on the power side. So we might end up with kind of 4 MTPA of sort of total contracted supply, 1 MTPA of which is baseload, and three is probably contingent on the power dispatch and linked to international energy spot prices. Great. Very helpful. And my second question, just wanted to ask about CapEx. I think it was around $680 million during the first quarter. Could you maybe talk about how that year? Yeah. I mean, so sorry. Microphone open here, guys. There's a lot of ins and outs because there's been financing actions. It'll be further detailed as you see the notes in the Q. If you have follow-ups, we can go through it. But fundamentally, when I look at the balance of the rest of the year, there's very little equity CapEx required to build out what we are executing in Nicaragua and then the conversions in Puerto Rico. Specifically, Marty, it's about $100 million in total across the terminals and vessels and about $100 million associated with the Puerto Rico expansion. The rest of the CapEx is FLNG2 in Brazil, both of which are fully financed on a debt base. Our next question comes from Chris Robertson with Deutsche Bank. Please go ahead. Your line is open. Hey, guys. Say hi. Thanks for taking my questions. Chris, I just wanted to follow up on that last question just with regards to the CapEx guidance from the previous presentation. I think it was around $1.5 billion. So just trying to see how much of the first quarter of CapEx is related to FLNG1 spending, and then how should we think about the cadence and overall total spend for the remaining part of the year as it relates to gross CapEx? Yeah. So I stand by the $1.5 billion with $1.25 billion being financed. That still kind of works for what we're expecting in the Brazil assets and FLNG2. For FLNG1, we spent in first quarter 2024 around $140 million. And then for the balance of the year, that'll really taper off. You'll still have some spend through April and May, of course, on that asset, and then very little spend we expect June, July, August as we kind of complete a few make-ready activities post-first LNG. As I mentioned, you spent a little bit of money on the Mexican asset and modest maintenance CapEx in the first quarter for Jamaica and Puerto Rico. And that'll obviously be outlined in the Q. And then for the rest of the year, as I said, it's really not much equity CapEx. It's really just the terminals and the conversion in Puerto Rico. Now, you will start ramping up CapEx spend for FLNG2 once you go first LNG on FLNG1. And then obviously, the Brazil business continues to spend on its build of the Barcarena power plant. But all of the CapEx for the terminals should be done as of the end of the first quarter. Right. And just to circle back, so the Barcarena power, as far as I understand, the financing against that is just drawn down in tandem with the spend so that nets out basically. So there's no need for equity cash there. But on the second, the Portocem facility, is there financing against that one as well, and how much CapEx is going to be spent on the 1.6-gigawatt power project this year? Yeah. Yeah. Perfect. So you're totally right on the Barcarena power plant. So that's fully financed with BNDES, the Brazilian Development Bank. And all of the funding is in there, and we'll just draw it down as we keep building. So zero incremental kind of CapEx from the NFE side today or equity CapEx, is I think you're saying. On Portocem, so same thing, basically. So we have closed on a loan with four Brazilian banks, and we are funding CapEx as we go. We will probably transition that debt structure to a longer-term bond structure in Brazil over the next few months. But from a net result basis for kind of what you're talking about from a CapEx perspective, same thing. We'll just draw that down over the course of construction from now to then. So we don't expect really any incremental CapEx from NFE. That concludes today's question-and-answer session. I'll turn it now back to Chance Pipitone for any additional closing remarks. Well, great, everyone. Thanks for calling in for the update. Obviously, it's a clarifying and exciting update from our perspective, and I hope that we found it informative. We look forward to following up any questions you have, and we'll talk to you in a few months. Thank you very much. Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect.