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spk01: gentlemen, and thank you all for joining us for this NFV first quarter 2023 earnings conference call. As a reminder, all lines are in a listen-only mode, but later you will have the opportunity to ask questions. To get us started with opening remarks and introductions, I am pleased to turn the floor to Mr. Patrick Hughes with Investor Relations. Welcome, sir.
spk05: Thank you, Jim, and good morning, everyone. Thanks for joining today's conference call, during which we will discuss our first quarter 2023 results. NFE's recent development and operational highlights and what continues to be a very bright future for our business. As Jim said, the call is being recorded and will be available by replay on the investor section of our website under the subheading events and presentations. And in fact, at that same location on our website, you'll find a press release regarding our first quarter 2023 results and the corresponding presentation that we'll walk through on today's call. As we proceed through the discussion with Wes and the team, we'll be referring to that presentation, and in that same presentation, you'll also find a series of important disclosures related to forward-looking statements and non-GAAP financial measures. We encourage participants to review these important disclosures in addition to the description of risk factors contained within our SEC filings. Now let's get underway with the call. This is Patrick Hughes, and joining me today here at New Fortress Energy are Wes Edens, our chairman and chief executive officer, Chris Junta, our chief financial officer, and Andrew Deedy and other members of our senior leadership team. Wes, over to you.
spk04: Great. Thanks, Patrick, and welcome, everyone. have a lot of good updates to go through today, so let's start with the deck as usual. So you'd start on page number three, just looking at the financials starting from left to right. Very good quarter and very good start to the year. Segment revenue for the quarter, $601 million. Adjusted EBITDA, $440 million. Free cash flow, $185 million. Push to the right a little bit on the page, and you can see that our Guidance for the year, we are confirming at segment revenues of $3.5 billion, adjusted EBITDA $2 billion, net income $1.2 billion, that's GAAP income, and estimated free cash flow of $1.4 billion. So significant increases from last year, which themselves were significant increases from the year before. On the right-hand side in the box, I basically provide a couple of metrics that we look at. So segment revenues, The $3.5 billion in 2023 versus $2.6 billion in 2022, they're translating to revenues of approximately $16.50 per share. Adjusted EBITDA goal and objectives of $2.0 billion would be roughly $10 per share, free cash flow of $6.50. And I'll talk about this a little bit in just a second, but free cash flow margin, which is – Something that I pay a lot of attention to is estimated to be 37% for the year. So simply translating our revenues into free cash flow at 37% QIP is an extraordinary ratio and one that reflects the health and wellness of the business. So with that, let's look at page number four. What I've tried to do here is just simply lay out the way that I look at the earnings and the way that we actually try and calculate ourselves our progress and our scorecard. We are making every attempt possible to make the financial statements conform to this simple way of laying things out. Gap financials are the way of ultimately leveling the playing field, so the gap numbers, of course, are there. But we are putting a lot of effort this quarter, and I think you'll see next quarter as well, in an attempt to make this be as clean and as simple, actually, as the business really is. And just to start from the top to the bottom, The math of the business is the terminals business, the gas and power that we sell, our terminal operating margin, plus cargo sales because we do sell cargos that are free volumes for us to sell. We make money on our ships. We have a ship's portfolio that's financed, and there's some complexity in accounting on that, but the simple numbers are we reflect in the financials, minus the core SG&E. That gives you just an EBITDA. Then, of course, subtracting interest and taxes and depreciation brings you down to GAAP net income. Adding back depreciation and amortization gets you free cash flow. So I'm oversimplifying for the purposes of example. There's lots of nuances that, of course, are very important in GAAP rules and how we actually account, but this is the way that you should be able to follow the business. On the right-hand side, some rules of thumb that actually jump out of the financials are With an adjusted EBITDA goal, the conversion of that from revenue is approximately 50% to 60%. So a very high conversion of revenues into adjusted EBITDA. And then the result of that is, of course, a significant amount of that turns into free cash flow. So that's the way we view the business, and that's the way we'll try to go through the financials. So with that, let's flip to page number six. So the earnings growth is supported by the continued expansion of the terminals business. The organic growth has been material. It's what we expected. Basically, the business construct is to go and establish terminals and operations in countries that we think have got significant needs for energy and power and clean energy, which is our business. And then once you have established a beachhead, basically over time to grow those operations and continue to expand both operations, volumes, and eventually cash flows. You're seeing now in this first quarter and then throughout the course of this year and you know, the impact of what these are. We'll go through an example here in Puerto Rico in just a second that Brandon will walk through, but the numbers are significant. In the last couple of years, dislocations in the energy prices caused in large part with the Russian invasion has paralyzed customers in many respects. TTF went from, you know, modest prices to very, very high prices, and prices really that were not relatable and usable by people in making new energy commitments And so if you look at our volumes over the period of time, they remain relatively stagnant. The energy prices have reset to what we think of as a new normal, which is very healthy for everyone. Higher than they were before, lower than they are for alternatives. And as a result, you've seen significant increases in customer activity inquiry and significant increases in customer activity in terms of what we've put through the terminals. We've had some very productive hedging and cargo sales over the last couple of years. That's helped our earnings to an extent, but we'll break out for you the impact of our terminals business versus some of our cargo stuff. There's nothing wrong with making money the old-fashioned way, which is buying low and selling high, but the durability and the duration and the quality of earnings that come from the terminals business is what we pay the most attention to. So if you look at the following page, I'll just walk through these numbers and I'm going to turn it over to Brandon in just a second, but This basically looks back at the historical numbers of 2021-22 and the guidance for 2023 and our estimates for 2024. If you just follow along the top line, you can see what our annual estimates are for the terminals P&L, and it's actually moved, obviously, very, very substantially. $236 million in terminals in 2021, $221 million in 2022. As I said, higher energy prices really did paralyze people at that point in time. That has changed dramatically. So our current guidance for the year is $1.3 billion. So over a billion dollar increase from last year. Cargo sales relatively flat over that period. Ships also relatively flat, down a little bit, but a modest decrease. Core SG&A roughly the same. Adjusted EBITDA then going from $605 million in 2021. A billion 071 is the number in 2022. Our guidance is $2 billion for 2023. So obviously a massive increase from last year, which itself was a big increase from the year before. Net income, if you skip down, $97 million in 2021, $194 million in 2022, $1.2 billion in 2023. Not only are there significant amounts more of economic activity, but there's lots of noise from past transactions, the non-control transactions, the know the helis and the brazil stuff etc there's a bunch of different things that have basically been washed out of it uh this quarter there still is a bit of noise but from this point forward we expect you to see very normalized numbers and then free cash flow which of course is the ultimate uh measure of the health of a business so 195 million dollars in 2021 337 million dollars 2022 1.4 billion dollars uh as our estimate for 2023 2024 these are not official guidance numbers but i wanted to reflect What we see in the business today, the simple impact is that where we see the business going structurally in the terminals business, we expect that to continue over the course of this year and next year, especially with the incremental FOMG volumes that Chris will talk about. coming online here later this year and next year. We think we have significant amounts of opportunity for us to grow our business on a core basis. So again, not only the total quantity of earnings and cash flows to increase, but the quality and the durability of those cash flows to go up as well. Nowhere have we had a bigger impact on our business over the last 12 months than in Puerto Rico, there's been some significant development there, all of the constructive. And with that, let me just walk through the example and give a turn over to Brandon. Brandon?
spk12: Great. Thank you, Wes. I really appreciate that. I'll refer to page eight. As Wes mentioned, the Puerto Rico terminal for us is a terrific example of the embedded value that we have in our terminal assets and really putting us in a position to respond to customer needs. So as you recall, we opened our terminal in 2020 with the vision of providing critical energy infrastructure to Puerto Rico, really to accelerate their own vision of energy transition. Today, the terminal provides fuel to on-island customers in the power, industrial, commercial, and transportation sector. From an infrastructure perspective, it has regas capability, truck loading bays, which allows us to move LNG around the island to various customers that are on and off grid, and, of course, a very robust and expandable LNG supply chain that allows us to drive significant volumes to the terminal. All of that really uniquely positions the terminal with embedded expansion capacity, which puts us in a position to respond to, you know, customer needs, you know, when and as they arrive. So I'll flip to page nine. What this has allowed us to do is earlier this year, the government of Puerto Rico put out a call for additional supplemental power and just to kind of you know, give you a sense of the situation on the island. The energy system there is about 750 megawatt short power, which really translates into a situation that creates a very high instability in the grid, which puts them about 55% more likely to have an outage than, let's say, you or I would in mainland U.S., And from an economic perspective, every outage costs Puerto Rico $14 million of economic activity. And so over the course of the year, it's expected to result in about $700 million of lost economic activity. So obviously extremely significant. This situation is further exacerbated by the fact that they are extremely vulnerable to natural disasters, such as hurricanes and earthquakes, which there are many examples over the last 24 months. So what the government did is they came out and said, we need additional capacity to help us stabilize that situation, particularly before hurricane season, which starts in about 45 days. That power would both stabilize the grid. It would provide coverage for maintenance work that needs to be done on their existing fleet, which has an average age of about 30, 35 years. And then most importantly, it ensures an adequate reserve margin so as things come off unexpectedly that they can maintain stable and reliable power for essentially an economy that's 50% driven by industrial output. And flip into page 10. So to give you a sense of what we've done, the call for power came out earlier this year. On March 3rd, we signed our first contract for 150 megawatts at an existing power station they have at Palo Seco. We brought in supplemental generation to augment the existing capacity that they have. From the time we signed the contract, I'm pleased to report that actually yesterday evening we fired up the generators for the first time, so roughly about 60 days from the word go. April 19th, so just about 45 days later, we signed an additional contract for 200 megawatts at the San Juan terminal, which we have existing infrastructure at, for 200 megawatts. So that's 350 in total. And we expect to turn that supplemental power on around June 10th. And both sites will be fully operational by June 15th. In addition, we believe that this particular strategy has the ability to go from 350 megawatts to 600 megawatts to further complement the strategy that the government has in terms of increasing available capacity. And we also believe that this particular strategy can be replicated in other jurisdictions around the world that are suffering from the same issue as they struggle to manage through the energy transition. So with that, I think I'll turn it over to Chris.
spk03: Great. Thanks, Brandon. Good morning, everybody. Let me direct you, please, to slide number 12, and I'll give you an update on our Fast LNG projects. You know, from the beginning, we've always known that fully integrating the business is the best way to produce the maximum value, not only for our shareholders, but also for the customers. Fast LNG enhances our business in three critical ways. It provides us access to LNG supply in a competitive market that's tight physically and from a credit perspective. Second, It will increase control over our portfolio of LNG supply, which provides valuable flexibility for our logistics chain. And three, fast LNG enables us to extract incremental economics when we sell into our downstream assets or into the global market. As we say on the slide, we believe that the true IP here is the modules. We can deploy them on rigs, on ships, or on land. By executing the construction in a shipyard with access to top quality craftsmen and in a controlled environment, We're able to build them faster and cheaper than a greenfield project, which takes as much as twice as long. Turning to slide number 13, our first fast LNG project is nearing completion. At this point, we're executing the final phases of our construction program while we prepare for offshore operations. The modules have been completed, lifted, and set on the rigs and are currently undergoing integration and testing. The pipeway and mooring anchor installation is complete and awaiting rigs to arrive on site. Our team is expecting to have the rigs sail from Ingleside over the next 30 to 60 days and gas to be introduced into the system in the month of July. Finally, our expectation is that we will announce COD in August. Our full commissioning team is on location in Ingleside now and working to complete as much commissioning in the yard as possible in order to shorten the time between first gas and COD. And finally, regarding operations, the full installation team is currently working from the rigs and undergoing simulator training, control room competency drills, and familiarizing themselves with the asset. Turn to slide 14, and let's just quickly talk about modules. We've ordered all the critical long-lead procurement items, and the construction is underway, obviously, on modules for FLNG 2 and 3. Both units were expected to be completed by Q2 2024. Now, one new thing we're excited to announce is that we've signed a letter of intent with the CFE to install them on land. Prior versions of our FLNG contemplating putting these modules on fixed jacket platforms offshore. But this new partnership would allow us to deploy the modules quicker and operate them much more efficiently. Turn to slide 15 and I can provide a bit more color. We're very excited about the onshore Altamira project for reasons similar to the one offshore. Our modular liquefaction design allows us and the CFE to operationalize an underutilized asset. The massive onshore import terminal has been sitting effectively idle for the past five years, but the infrastructure remains highly valuable if it's paired with the right technical solution. So much the same way as was done with Sabine Pass 10 years ago, NFE and CFE will convert the Altamira LNG import terminal into a 2.8 million ton LNG export terminal. The current terminal is a world-class facility with all major aspects needed for a liquefier, including two 150,000 cubic meter tanks that are kept cold, access to gas networks and power supply, and excellent marine infrastructure. We've toured the site, and I can tell you personally that it's an extremely impressive and well-maintained facility. The new export terminal will utilize two of NFE's modular 1.4 MTPA trains and all of the terminal's existing infrastructure. Our significant procurement and construction progress, coupled with the strategic alliance with the CFE, provides NFE a tremendous timing advantage versus starting the development from scratch today. Both trains will be constructed, installed, and operational during 2024, years ahead of any other new-build local fire. With that, I'll turn it over to Andrew.
spk10: Thanks, Chris. Good morning, everyone. I have three points I want to make this morning. First will be a quick macro update for the global gas markets. Second, we'll try to zoom in and apply that to our business and what we're seeing in our core geographies. And third, we'll go through the sort of current year and 2024 view on our LNG portfolio supply and our contracted sales downstream. So turning to page 17, what we're seeing is a significant widening spread between U.S. domestic gas and international LNG. At the top, we plot both TTF, the European Gas Index, and Henry Hub, the U.S. Gas Index, for the last 12 months. In both cases, we've seen really sharp declines. In Europe, reduced supply concerns after last winter have led to much lower prices and also much lower volatility. Wes hit on it. We think it's actually a new normal and a very positive situation for us to be in, where prices have settled in at a level that people are willing to transact at and to engage in conversations over long-term contracts. We certainly see upside risk remaining as Russian gas remains offline in terms of supply to Europe. As we enter next winter, the forward curve today is at about $12, and we already have a curve that kind of by December is $18 or $19. So the market's certainly pricing some of that risk in, but we remain in an undersupplied and somewhat jittery scenario on these prices. Henry Hub has also experienced dramatic, even more dramatic price declines. This time last year, we were at $8. Today, we're in the low $2 per MMBTU. That forecast remains flat over the next couple years as you have big U.S. gas production largely from the associated gas that's in the Permian and other places in the U.S., but you don't really have meaningful export capacity turn online until 2026 and beyond. So what that means is the Henry Hub to TTF spread in the bottom of this page remains really supportive for our business, which is, you know, basically taking U.S. gas and exporting it to our growth markets. So you can see today we have about a $10 per MMBTU spread. That widens to about a $15 per MMBTU spread between Henry Hub and TTF by the end of 2023 and maintained kind of throughout 2024. Just to kind of put that in context, for the economics of one FLNG unit that Chris just went through, our payback time on this forward curve is well under three years. Let me flip to 18 and apply that a little bit to our business. So what we've tried to put here is to show at the bottom of the page an illustrative portfolio cost for NFE, then in the middle of the page where the global energy indices for gas and diesel, which is typically what we compete against in our core geographies, And then at the very top, we've tried to put specific prices for the Q1 averages for places that we operate, Mexico at the La Paz Terminal, Jamaica, and Puerto Rico. And what you can see here is the opportunity to accelerate growth in our downstream terminals has almost never been better. We have the infrastructure and the supply to basically connect the bottom of this graph to the middle of the graph. which is basically that we control our LNG supply, and then connect the middle of the graph to the top of the graph by having the terminals, the downstream infrastructure, and the midstream infrastructure to actually deliver to end customers. So we go all the way from our kind of $5 to $7 per MBTU supply context into below $0.20 per MBTU. So this tries to give you a sense really for the overall margin opportunity. and then really how the power of integration to these downstream markets allows us to serve customers rather than just selling into the short-term global energy industries that are in the middle of the page. Let's turn to page 19. The story here is growth. So this is a bit of an eye chart of the numbers on the left side, so apologies for that, but I do think it's important to kind of go through it. In 2023, our overall LNG supply is going to be 152 TBTUs. That's up 75% from 88 TBTUs in 2022. You can see the contribution from our existing supply contracts and then from FLNG1 turning online this year. We have contracted sales, so contracted today, of 122 TBTUs in 2023. That's about 80% of the volumes. And we have about 30 TBTUs at open volumes, which is a great foundation to do more customer business in 2023 and beyond. In 24, we're going to have continued growth. So 150 TBTUs will go to 217 TBTUs. That's 150% up from 2022. That includes 82 TBTUs from FLNG 1 and then 2 and 3 on the schedule Chris showed earlier turning online in 2024. We have 180 TBTUs of contracted sales in 2024. That comes from turning on the Barcarina Terminal, the Santa Catarina Terminal, and the Nicaragua Terminal in 2024, developments that are nearing the end of construction or done with construction and are just basically completing what's right in front of us in terms of 2024. Then we're looking at seven TBTUs of open volumes and 30 TBTUs of contracts we have in discussion today to sell out the overall 217 TBTUs. Beyond that, this 82 that we're showing from FLNG 1, 2, and 3 in 2024 is a partial year number. In 25, we would expect that to be close to 195 TBTUs a year when we fully run-rate those assets. The thing I'd point out as well is our organic growth in 23. So I tried to show this, but we basically have increased by 34 TBTUs, which is about 40% year-over-year in terms of organic growth in our terminals. With that, I'll turn it back to Wes.
spk04: Great. So two other kind of brief thoughts, and I'll have Chris walk through the financials. One is when you look back at the construction of our earnings and the conversion of revenues to EBITDA and revenues to free cash flow, the numbers jump off the page at me. And we've thought about this a lot and tried to understand what it is that allows us as an industrial business that has got a capital-intensive enterprise to to generate free cash flow conversions of 30, 35, 40 percent, when we look typically across industrial businesses, they are much, much lower. And the answer, obviously, from our standpoint, is that of the integration. When we look at our business, there really are four distinct groups of activities that we have inside there, each of which has public market and private market comparables of companies that perform those activities in a fine way. But, of course, for each of those companies that are solely focused on one element of the business, they themselves have a profit motive, of course. So there is liquefaction, there is shipping, there are terminals and terminal managers, and, of course, power providers. The free cash flow conversion in those sectors across the board tends to range, broadly speaking, from 10% to 20%. So a 20% free cash flow result for any of these industrial complexes would be good. From our standpoint, of course, we don't view any of those activities to have a profit motive by themselves, but rather the aggregate of all those together is what we view our business to be. And that, I think, in a very simple sense is why we're able to convert what is otherwise industrial businesses that have 10% to 20% free cash flow conversion to 30%, 35%, 40%. And I think you'll see this borne out over time. We've done some work on this. internally that we'll probably share at our next quarterly call to kind of go through this, but that really is the backdrop for this. We have one other incremental business update that I want to provide is on our hydrogen business. The board authorized the filing with the SEC for our company Zero Parks last night, and we expect to file that last night or this morning, I think. And the filing basically is a separate registration statement for that as an enterprise. that will allow us basically to dividend out to shareholders that company sometime this summer. The process of registration is a fairly straightforward one. You basically file documents with the SEC that describes the business, describes the accounting for it, gives it a full picture of the company. They then comment on it. There's a period of going back and forth that, depending on how busy they are and how complex the business is, that can range from 60 to 90 to 120 days. But in any event, it's our expectation that by sometime this summer, we'll have an effective registration statement, and thus we'll be in a position to dividend out this company to shareholders. In simple terms, I would expect a shareholder of NFE to end up with a share of this stock. This is, I think, a material development for that business. I am more optimistic than ever of the impact of green hydrogen, green ammonia, steel, cement impacts on it. The approach that we have taken is to geolocate plants next to users of it. As I said before, when you start with an electrolyzer or green hydrogen, you start with a chemistry problem of breaking the molecule up and taking the hydrogen out. That quickly turns into a transportation problem because it's then challenging to transport. From our standpoint, the most logical way to do this and approach to do it is to basically geolocate next to big users of ammonia, steel, cement, et cetera. And, in fact, the first facility that we're building is in Beaumont, Texas, which is in the heart of those activities. There's ammonia plants all over the place. There are big petrochemical users. There are refineries. There's lots of users for it. So, bottom line is that when we finish the registration process, we'll have a lot to say about this. The statements are filed confidentially, so there's not information available publicly on the company at this point. When there is information publicly, we'll obviously spend a lot of time and effort to update you on this. But I feel like the impact of green hydrogen on the world is likely to be significant. We think it is one of the principal ways to decarbonize some of these industrial activities, and we intend to be a big part of that. And I just wanted to share that with you, and we look forward to talking with you when we have more to say about it.
spk03: Matt, Chris? Yep. Let's turn to slide 21 for the financial results for the first quarter. For the three months ended March 31st, we had $601 million in revenue, $440 million in adjusted EBITDA. The adjusted EBITDA number is the highest we've ever had in any quarter. The terminal segment operating margin was $405 million and $76 million from the ship segment, and obviously that's detailed in our appendix and in the press release. Adjusted net income for the quarter was $187 million, which is $0.90 per share when excluding impairment charges. This quarter we sold 25 TBTUs in total volumes, which equates to an average EBITDA margin of just over $17 per MBTU. One other comment here, during the first quarter, we did close the Hilly transaction. And as a reminder, we sold our 50% interest back to Golar in exchange for $100 million in cash, $4.1 million in shares, which have since been retired, and the discharge of $325 million in off-balance sheet debt. Turn to slide 22. This is a really informative slide, responsive to questions we've had in the past, demonstrating the company does not require external financing to execute on our near-term growth plans. We want to point out that historically, the company has funded our growth by choosing to sell non-core assets, executing bespoke asset-based financings, and through internally generated cash flows. These same drivers will continue to fund all of our development objectives, including FLNG. On this slide, we provided information on inflows and expenditures to demonstrate we have ample liquidity over the next two years. The 2023 numbers include actuals from Q1 and our expectation for the remainder of the year. To provide a little bit more detail on the CapEx, we've broken this out by terminals, which includes growth and maintenance CapEx, plus any ship-related CapEx as well. For FLNG, this is showing the aggregate spend remaining for FLNG 1 through 3 and includes the cost spent to date for Units 4 and 5. Finally, as you can see on this page, we're not forecasting any additional dividends beyond our current quarterly payment of $0.10 a share. Our view is that continuing to reinvest our cash flows into development projects is a creative and the best way to continue to grow earnings. Move, please, to slide 23. And as you all know, throughout 2022, we executed on the Sergipe sale and Energos transactions. And in 2023, we sold back to Golar, 50% interest in the Hilly. As Wes alluded to, these transactions reduced our overall debt and simplified the capital structure greatly. On the left side of the page, we show the current balance sheet is comprised of really just three things. First, the corporate revolver, which is $742 million. Second, two tranches of bonds in the amount of $2.75 billion. And third, two discrete asset-level financings in the amount of just over $400 million. When you add it up, it's $4 billion of borrowings against $2 billion of earnings, implying two turns of leverage. Over the past two weeks, we've gone and met with the rating agencies and requested that we initiate a formal review in the hopes of continuing our upgrade path. As we've mentioned on prior calls, our goal is to be one day to be investment-grade, but the first step is to increase our notching within the BB category. In working toward that goal, the agencies outlined things that would lead to an upgrade, including earnings predictability and the duration of cash flows, maintaining a modest leverage ratio, contract with diverse, high-quality credit counterparties, and have a fully funded capital plan. And frankly, to put it bluntly, we've done exactly that. Number one, we have earnings visibility over $2 billion adjusted EBITDA this year, growing to approximately 2.3 in 2024. Two, our leverage ratios are under three terms on an LTM basis and under two for fiscal year 2023. Three, we estimate over 80% of our 2023 sales to be to investment-grade counterparties. And four, as I mentioned, we can self-fund all of our development activities. If you turn to slide 24, we've included some quick credit metrics that have evolved over time and supports our case for an upgrade. As you can see, we've gone from negative EBITDA at the time of our first rating to over $2 billion this year, which in turn has dramatically lowered leverage. The combination of increased EBITDA as well as the debt retirements associated with the asset sales puts us below two turns. And lastly, we've increased our operating assets from three to 20 and operate now in 11 different countries. Finally, on slide 25, you've seen this slide each quarter, but it continues to evidence our operating prowess. With over 700 employees working tirelessly to ensure uninterrupted gas and power supplies to our customers, we delivered approximately 25 TBTU and maintained near-perfect reliability. Last and certainly not least, with our collective focus around the globe, we had no safety incidents during Q1 and maintain our 0.0 total recordable incident rate. With that, I'll turn the call back over to Patrick.
spk05: Thanks, Chris. Jim, I think we're ready for some Q&A. If you could tee up the queue, please.
spk01: Thank you, gentlemen. And to our audience joining today, if you would like to ask a question, please signal by pressing star and 1 on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star 1 to ask a question, and we'll pause for just a moment to allow everyone an opportunity to signal. Our first question today will come from the line of Ben Nolan at Stiefel.
spk07: Thanks. I appreciate the time here, guys. I'm going to try to nest a few FLNG questions all into one. The first is, Well, here's my nested question. So any update on how all of this impacts the Louisiana and the Merritt process, also the Latchitch process? And then as it relates to Altamira, curious how the operating economics might be any different, both with respect to OPEX onshore, but then also any update on how we should think about the profit sharing for CFE?
spk03: Hey, Ben. To hit them in sequence, so, you know, we still have our application in with MARAD for the Louisiana project. We're continuing to try to work with them on Q&A and try to get a permit as an option for FLNGs in the future. Regarding Lakosh, there's active engineering work and negotiations with PEMEX for the release of equipment that would be needed to be installed, and we'll deal with that over time. But right now, we're just working on the engineering and the permitting side. For operating economics onshore, we do believe that there are significant efficiencies. I mean, not to go through too many details, but offshore you have standby tugs, you have more frequent ship-to-ship transfers, you have to ferry people offshore, which takes crew boats, you have to move supplies, consumables, water, etc. All of that is not needed onshore. Adding to this, and this has not been negotiated, you could receive significantly cheaper power. I mean, we have a partner in the CFE who has power access and over a gigawatt worth of power generation in the area, and so we see there may be some efficiencies there. And as far as the profit share, we have not disclosed that, and we're in active discussions with the CFE, and we'll expect more information to be released to you and shareholders over the course of the coming quarters.
spk04: Yeah, and just to amplify a little bit, I mean, the site that Chris described, the import terminal they've got, is a thing of beauty, Ben. We toured the site now a number of times. There's not a weed or a piece of rock out of place. It really is a beautifully constructed import terminal. And it's ironic, of course, that this will follow the path of really the LNG exporting in the U.S., where first take an import terminal where many of the infrastructure elements that are there are usable. So as Chris said, the 150,000 cubic meter tanks, the wharfage and the marine infrastructure, the pipeline activity, the access to power, of course, all those things are directly usable. And there just happens to be a completely flat and perfect piece of land next to the wharfs that would actually be ideal to receive the trains we put in place. So it is an ideal situation. It's one where it's underutilized in its current form by the CFE. They've been a great partner of ours, and we've had really good dialogue about this. And the modular construction that we have engaged in basically allows us the flexibility to put the modules. The liquefaction model, the gas treatment modules can go anywhere. They can go onto jack-up rigs, they can go into a ship, they can also go to land. And I think that with the location of this where it is, unquestionably be the most reliable LNG terminal in the entire Gulf Coast, right, because you're really out of the direct past of the hurricane zone. So Texas, Louisiana, of course, are frequently hit by hurricanes. In some cases, they're significant, and there's downtime as a result of that. Here, you are due south of that, and so as a result, your reliability, I think, both compared to our offshore installation, but frankly, compared to all the other Gulf Coast liquefiers, it's going to be a significant positive. So It's not the LOI. We're working hard on permitting path, on economics and whatnot, but we're quite optimistic about this.
spk05: All right. I appreciate that.
spk01: Our next question comes from Devin McDermott at Morgan Stanley. Please go ahead.
spk02: Hey, good morning. Thanks for all the helpful detail today. So my first one is just following up on the Altamira onshore LNG opportunity. And specifically, I was wondering if you could just talk through what some of the milestones are from here into turning this into a formal deal from an LOI. And then also, is there any differences in the permitting path onshore versus offshore? I'm trying to put this into context with the 2024 targeted and service dates and what needs to happen to get there.
spk03: Yeah, so to deconstruct a little bit, Modules are undergoing construction right now. All the long lead procurement has been executed on will arrive to the Ingleside yard and be kitted and put into a final module. And we expect that all to be completed, you know, two and three to both be completed in the second quarter of 2024. The onshore component is civil work, and it's really balance of plant tying in those modules to the existing marine infrastructure and into the existing gas infrastructure. So our teams are currently doing engineering and design right now in conjunction with the operators at the terminal and with the CFE to make that efficient and to finalize all the contracts for that work. From a permitting perspective, we have experienced great partnership with the CFE to move through all of their related permit hoops. The President, the Secretary of Energy, the CFE, all are very supportive of this. Again, this is an underutilized asset by the CFE, so we're saving them money not only in transportation costs, but of the pipeline, but also in the use of the terminal. So I expect that it'll take, you know, several meetings with these guys, but we think that getting from here to a finalized agreement is a matter of, you know, a few weeks. And then we are finalizing fixed price and fixed term construction contracts to take these modules and have them installed on shore. Hopefully that answers your question, Devin. Happy to circle back on a separate call later today to go through anything more detailed.
spk02: Yeah, that's great. And then my follow-up is I appreciate the additional detail on the buildup of guidance. It's helpful to see the building blocks there. I was wondering if you could talk in a little bit more detail about where the FLNG units fall within this and also the assumptions that you're using on the 2024 cargo sales in next year's guide.
spk04: The FLNG is really a source of product into the portfolio. So as Andrew laid out where you see an aggregate cost of our LNG. It comes both from the third-party contracts we have from providers like Shell, Engineer, and Venture Global, and the FOMG will just simply feather into that for an aggregate cost. And so what we do from an economic standpoint, is basically take an aggregated cost, allocate that to terminals, and then use the revenues generated by the terminals to calculate kind of the net spread. We think that's the simplest and fairest way of doing it. So we don't view the FLNG itself to be a profit center, but rather just a source of good soul, basically, to go into that.
spk10: And on the forwards, we're just using the current Henry Hub and GTF strip prices, you know, basically marked for the quarter. And then we, you know, obviously have the transport costs that's built into our SHIFT portfolio as well. So we're using market prices for the forward.
spk02: Great. Very helpful. I mean, there should be a lot of stability in that guide as well. So that's great. Thanks for the detail. You bet.
spk01: Sam Margolin with Wolf Research. You have our next question.
spk06: hey good morning everybody thanks um so it the story here i think is is really vertical integration you want to participate in shortages of power not gas and you want to participate in extraction costs of gas not the market price of gas and so within that you get better returns than anybody in a pure play within the supply chain but i think what we've seen in the market is just sort of commercial questions because Demand is just very sensitive to these prices, and it seems like the solution of regulators and policymakers is to press more renewables capacity when power markets get short because it's still viewed as the lowest part of the cost curve. So I guess as you prosecute this plan across the whole value chain commercially, what are you seeing, and specifically in industrial markets, not just power, where gas at this price is really – is really in a position to grow and not just sort of see kind of curtailments and headwinds?
spk04: Well, look, I think a couple things. One is, yes, there are definitely efforts by people all over the world to introduce renewables into their system, but I'll use the same example because it's a real one. Jamaicans use 10% as much electricity as Americans do. Kenyans use 10% as much electricity as Jamaicans do. The average person in East Africa uses in a year what you use in three days. So it's not simply a matter of a decarbonization trade, which, of course, the Western Europeans, Americans, other more industrialized countries are doing. Many of the places we do business, obviously, are emerging countries where the actual availability of power is so scarce there is a vast, vast, vast amount of demand. So, you know, you have... something like 40% of the world's population has insufficient electricity. So the amount of gas and electricity needed is incredible. And what you've seen, as I said, when prices were very high, nobody can really afford $60 gas or $50 gas or $40 gas. Today, and I thought the chart that Andrew laid out is actually quite an effective one, the gas at this price is still a material discount to the diesel at this price. So to the extent that you need to turn on electricity anyplace else, it's a bargain to use natural gas versus using diesel. And I think the thought or the notion that somehow renewable power is going to displace all this instantaneously is just simply fiction. It's just like it's obviously we're all for carbon-free energy everywhere. But there's also the matter of access to energy, energy stability, energy security, and I think that the amount that you need for it is actually quite significant. And the vertical integration point is two things. One, economically, it's vastly better because 35 is more than 10 or 15, and it's not that complicated to figure it out. When you actually look at the numbers, that's what we see. I'd be happy to talk with you or anybody else offline about that, but the actual free cash flow conversion of our business is significantly greater than industrial complexes that are more than pure play, number one. And number two, with respect to our business, we feel like that's what we have to do because it's a logistics chain we have to provide for everybody. And there are significant impediments to bringing gas and power to people. Namely, there's the infrastructure that's needed to be constructed and the capital that is needed for that. And in any logistics exercise, If there are 10 things that have to be done and nine of them are done perfectly and one is done inadequately, the whole chain breaks down. And I think when you look at the development of energy systems around the world, again, in non-investorized countries in particular, laxus of access to capital to build infrastructure is probably the top of the pyramid, but actually then beyond it, it's credit issues, it's supply issues, it's a whole host of other issues, and that's what creates the value in these things. And the last thing I'll say, and I'll give you a long answer to a very short question, is The value proposition by creating a terminal in a place where there's going to be a significant amount of demand is vast. And no better example of that exists than Puerto Rico. But frankly, they'll all exist through that. We see significant incremental demand in Bacarena. We see significant incremental demand in Santa Catarina. Significant incremental demand in Mexico. you know, et cetera, et cetera. And we know that these are grounded terminals that provide us with an entry into the country, but it's very, very simple. If you can build infrastructure for one purpose, and it makes economic sense, and use it for two or three or four, the economic, actually, the margins increase, it flows to the bottom line, and you provide a better product to your customers, because now you can actually take your costs, spread them out over time, and be more effective than the next guy in. So... But I think that the decarbonization thing is a great point, and, of course, we're all for that, but it is not close to reality in many of the places in the world where we do business. It's just the access to energy is the trump card for it.
spk06: All right. Thanks so much. And then I just have a quick follow-up. It's a maintenance question, but it's about Louisiana and if there's any, like, gas purchasing or procurement commitments that affect your timeline on that project, if it has to be pulled forward or if you have a lot of flexibility because you're not – on the hook to purchase gas through that pipe. Thank you.
spk03: Yeah, we have no purchase obligations. We have no commitments there at all. Nothing that would change the timeline of the project either.
spk06: Thank you so much.
spk03: Thanks, Sam.
spk01: Our next question comes from Chris Robertson at Deutsche. Please go ahead.
spk08: Hey, good morning, everyone. Thanks for taking my questions. Chris, can you just give a quick update on any permitting remaining for the first FLNG project and the non-construction timeline around that project from here?
spk03: No, we have excellent support from the team at CFE and the regulators. We have all construction permits in hand. We're waiting on operating permits that are all expected to be received this month. We've received our FTA export license from DOE and the Mexican export license is expected by the end of next week.
spk08: Okay, got it. Yeah. And just going back to the second and third module here regarding the Altamira project, can you just talk about when those discussions kind of first came about, how that really transitioned from being more offshore focused to onshore focused and kind of the process behind that?
spk03: Sure. I mean, we said it a little bit on the slide. I mean, the module is key, right? So the module is the secret sauce, and it can be deployed in any ship, rig, land-based opportunity. The simple answer is it's cheaper and it's faster. Offshore infrastructure takes longer depending on if it's a fixed jacket. This is able to use and capitalize on the marine existing infrastructure, the existing tanks, for cheaper deployment. And we've spoken to the CFE about this. They have said that they really support the project and want to have this thing operational as quick as possible. We've been talking to them over the last three months, and this is something that they want to see happen and see us use the asset that they're not able to make the most out of.
spk08: Okay. Yeah, got it. Thank you.
spk01: Cameron Lovridge at Bank of America. Please go ahead.
spk09: Hey, good morning, guys. Thanks for taking my questions, and thank you also for some great disclosures here. I really appreciate that. I wanted to really quickly start off and just ask about margins on the terminal side of the business. So, If I look at, you know, your downstream terminals guidance for 24 seems to imply about a $10 margin, down a little bit from the implied margin in 23, presumably on, you know, as Bark Arena and Santa Cat Arena come online. But just wondering if you can kind of unpack that a little bit and help us understand some of the moving pieces behind what's going to influence and determine that margin for the terminals.
spk10: Hey, Cameron. It's Andrew. I think you got that about right. I mean, in 24, we're certainly turning on three new terminals. Those have slightly different profiles. When we average them all together, you're in the right ballpark. I think that's about it. And it's not particularly complicated from that perspective. We just have long-term contracts, and we kind of average into them over time. And I think now you can get a relatively clear sense of how the overall pie, you know, shakes out in terms of margin.
spk04: But what you'll see is that when a terminal is new and you can do a baseload, the margins tend to be the lowest that they're going to be, right, because you're loading up the bulk of your expense and getting that first terminal done. So we looked at the – I didn't do this separately, but we looked at the margins for the terminal in Puerto Rico – from three years ago when we first turned it on, which is just about now, three years ago, those margins versus today would obviously be lower than where they are today because we're using much of the same infrastructure and our capacity factor across our terminals is about 25 to 30%. So obviously we have a ton of incremental capacity and to the extent that you then deploy that across other customers or other power solutions, you know, your margins are going to get, you know, better over time.
spk10: Yeah. Buckering is a perfect example, too, Cameron, where it's like, you know, we start with the baseload next year, and then the power plant in 2025 will kind of, you know, go right to the bottom line because we'll be paying for the infrastructure.
spk09: Got it. Got it. That's helpful. Thank you. And then for my follow-up, I wanted to ask about, so if I'm thinking about this correctly, the drill ships that were slated, originally slated for FLNG 2 and 3, given that those units are now going to be onshore, that frees up some marine infrastructure, whether it's for La Cache or Louisiana or what have you. In the case of Louisiana, the way the permitting process has gone so far, I think there's been some concern on the part of MARAD around the jack-up rigs and the safety there. And so Could this move to bring these units onshore in Mexico kind of free up some ships to assuage any concerns that may arise and maybe accelerate that permitting process?
spk04: The answer to the question of is the marine infrastructure freed up, the answer is yes. So we're very focused on one, two, and three, and that's what we've got FID for capital deployment and construction. There's a significant amount of work that has been undertaken on the two Savant ships to prepare them for acceptance of you know, the liquefaction and the gas treatment modules, and that still continues. With respect to the merit application, the applications are very specific to the product that you're looking to employ, and so obviously the site work we've done, a lot of the engineering, there's a lot of things that would be usable about that. But if we were to go to a different solution, that would basically be restarting the clock, hopefully in an abbreviated manner because you get the benefit of some of the work that's already been done. But we're not anticipating doing that right now. Our goal right now is to finish the application with the infrastructure in place. And our reading of the questions, there are more questions about the jack-up rigs than there's concerns about it. I mean, jack-up rigs are used. all over the Gulf. This is not a new activity. What's new is simply grouping them together and actually having liquefaction on it. Those are the nature of their questions. They're all, we think, good and reasonable questions, and they have good and reasonable answers to it. We're quite optimistic that we'll get through that in due course.
spk01: Next, we'll hear from Sam Burwell at Jefferies.
spk00: Hey, guys. Good morning. I wanted to ask a question on CapEx, focusing on slide 22. The CapEx figure for 2023, if you add up the terminals and the FLNG, that's like $1.2 billion. You spent $560 million in one queue, so that implies a pretty solid drop-off in CapEx for the rest of the year. So I just wanted to confirm that's indeed the case. And then another point of clarification... The 25 and the 1.3 and 23 and 24, respectively, for FLNG, that's just units 1, 2, and 3, correct?
spk03: Yeah, the short answer to both questions is yes. We do expect a drop-off, and yes, this does include the completion of units 1, 2, and 3, and then money that's already been spent on number 4 and 5.
spk00: Okay, understood. And then a follow-up on sort of the margin trajectory for the rest of the year. It doesn't look like you guys disclosed, like, an explicit per MMBTU margin for the quarter, but I got a figure that there were cargo sales contributing to it in one queue. And I would assume that those probably taper off through the year, but Puerto Rico should ramp through the year. And I'm just curious, like, how should we think about, like, blended margins this Sequentially, should those be pretty steady quarter on quarter or should we think about margin uplift in the coming quarters at all?
spk03: Yeah, I would say the short answer is we had implied margins of around 17 and we expect to stay about there for the remainder of the year. You're exactly right that you're going to have cargo sales that were sold in the first two quarters that are a little bit higher than we would expect in the third and fourth quarters. but you are going to have increased profit margins coming through for the downstream terminals. So that's exactly correct.
spk04: I mean, we got a lot of questions from analysts and investors about the economics of the terminals business versus the cargo sales. And so this is... directly responsive to that. We think it's the right way to be responsive to it. That said, we're very sensitive about disclosing specific performance of any given terminal or customer for obvious reasons. Customers wouldn't like it, terminals wouldn't like it, countries wouldn't like it. So we think by doing it and reporting it annually, we give a very clear snapshot of what we think the economics are of the business, and hopefully that's helpful to you and to other investors alike. And as Chris said, those numbers that are shown there are representative of the full year. So there may be variations across the quarter, but they do reflect kind of the activity for the year. We think that that's a really, really clear window, and I hope that you guys think so as well.
spk00: Got it. Understood. Thanks, guys.
spk01: Our next question this morning will come from Sean Morgan at Evercore. Please go ahead. Your line is open.
spk11: Hey, thanks team. Thanks for squeezing me in. My question, if we go back to May of 21, I know it's been quite a while since zero parks got kind of rolled out. And at the time we were definitely, or the company was talking about blue hydrogen and I guess a lot's changed since then. The cost of kind of feedstock for blue hydrogen, natural gas has increased quite a bit. The cost for generation has kind of gone down a little bit. So maybe you can just kind of Talk a little bit about your thinking because it seems that based on today's presentation We've shifted a little bit in terms of our mindset from blue to green hydrogen and then also just kind of falling on that hydrogen theme just curious to know your thoughts on sort of the expected Treasury decision related to hourly matching of sort of green renewables power generation versus annual and for where you guys come out in that debate and
spk04: Well, our focus has been on green hydrogen the whole time. We definitely have looked at different solutions, and we think that there are attractive economics based on the performance that we've seen on the blue hydrogen. Blue hydrogen, blue ammonia is a very, very different business path than the green hydrogen electrolyzer path. Specifically, the project that we are engaged in is a piece of land in Beaumont, Texas, where There will be a balance of plant and then electrolyzers put in place. 120 megawatts is the size of it. It would be, to date, we think one of the biggest, if not the biggest, green hydrogen projects in the country. There's a ton of localized demand for the product, and so I think that we expect to conclude sales of our product in the short term, and that's all detailed in the filing that we're doing, so I don't want to talk. more specifically about that. The IRA didn't exist two years ago, so I think that obviously the implementation of it is something that people are focused on. The big picture from our standpoint, of course, is $3 a kilogram production credits for green hydrogen. We think that that takes a neutral or modestly money-losing business into a money-making business, which is very important, and From here, we think the technology is only going to improve and make those economics better and better. So I think a lot of the parallels people point to are the change in efficiencies in renewables over the years, which has obviously been dramatic as solar and wind and other renewables have come down in price dramatically and gone up in efficiency dramatically. We think the same kind of things will happen with the influx of capital into this sector, and we're meeting with companies all the time that have got new and exciting views on how to make things more efficient. And the simple answer on the IRA is we think that we will get the full benefit of the production credit, and it will flow to the bottom line. And it makes those projects be very economically viable, we think. And, again, when we have more detail on that, we'll share it with you when the filing becomes a public one.
spk11: Okay. Thanks, Wes. And then just to follow up on the gas procurement for Louisiana question from earlier, I just wanted to clarify this. So there's no purchase obligations outstanding right now. How long does it take to kind of pair off supply from upstream EMPs? And what sort of lead time do you need before you get, say, regulatory approval in Louisiana to kind of line up that gas to sell out of the terminal?
spk03: So we have access from pipe back to a 500 pool and back to readily accessed gas supplies that run across south Louisiana. So we have no purchase commitments today. We're not worried about being able to source the molecule. These are small volumes, right? I mean, it's about 200 million cubic feet a day. So nothing that's committed now. We don't see this as an issue going forward. Okay, thanks, Chris.
spk01: And that was our final question from our audience today. We'll turn it back to our leadership team and to Mr. Hughes for any additional or closing remarks.
spk05: Jim, I think we're all set here. Thanks, everyone, for joining us today. We remain available to you guys, as always, to answer additional questions as they may arise, and we wish you a good day. Thank you.
spk01: Ladies and gentlemen, this does conclude our conference. Thank you for your participation. You may now disconnect your lines.
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