New Fortress Energy Inc. (NASDAQ:NFE) Q1 2023 Earnings Call Transcript

New Fortress Energy Inc. (NASDAQ:NFE) Q1 2023 Earnings Call Transcript May 4, 2023

Operator: Good day, ladies and gentlemen, and thank you all for joining us for this NFE 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.

Patrick Hughes: 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 Investors section of our website under the subheading Events and Presentations. And in fact, at that same location on our website, you will 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 will be referring to that presentation and in that same presentation, you will 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 Guinta, our Chief Financial Officer; and Andrew Dete and other members of our senior leadership team. Wes, over to you.

Wes Edens: Great. Thanks, Patrick, and welcome, everyone. I have a lot of good updates to go through today. So let’s start with the deck as usual. So let’s start on Page number 3. 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, 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 was 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 the metrics that we look at. So segment revenues the $3.5 billion in 2023 versus $2.6 billion in 2022 that translated into 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 $6.50. So – 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% clip is an extraordinary ratio, and when that reflects the health and wellness of the business. So with that, let’s look at Page number 4. 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. GAAP financials are the way of ultimately leveling the playing field. So the GAAP 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. You’re going to 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 ships 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&A that gives you adjusted EBITDA then of course, subtracting interest in taxes and depreciation brings you down to GAAP net income, adding back depreciation, amortization gets you free cash flow. So I’m oversimplifying for the purposes of example, there are – 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. And on the right hand side, some rules of thumb that actually jump out of the financials are, adjusted EBITDA goal, the conversion of that from revenue is approximately 50% to 60%, so 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 and go through the financials. So with that, let’s flip to Page number 6. 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, we 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 at once you have established a beachhead basically over time to grow those operations and continue to expand both operations, volumes, and eventually cash flows. And you’re seeing now in this first quarter and then throughout the course of this year and forward, 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 years, dislocations in the energy prices caused in large part with the Russian invasion has paralyzed customers in many respects. TTF went from 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 remained 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 the what we’ve put through the terminals. We’ve had some very productive hedging and cargo sales over the last couple years.

That’s helped our earnings to an extent, but little breakout 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 just a second. But this basically looks back at the historical numbers of 2021, 2022 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. So 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 $1 billion 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, $1.071 billion 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 skipped down $97 million 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 Helius in the Brazil stuff, et cetera.

There’s a bunch of different things that have basically been washed out of it. This quarter there still is a bit of noise, but from this point forward, we expect you’re going to see very normalized numbers and then free cash flow, which of course is the ultimate measure of the health of a business. So $195 million in 2021, $237 million 2022, $1.4 billion 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 FLNG 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 in 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 turnover to Brandon. Brandon?

Brandon Bonfig: Great. Thank you, Wes. I really appreciate that. I’ll refer to Page 8. 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 an 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 customer needs when and as they arrive. So I’ll flip to Page 9. 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 give you a sense of the situation on the island, the energy system there is about 750 megawatts 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 cost 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’re 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 flipping 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 3, 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 capacities that they have. From the time we signed the contract, I’m pleased to report that actually last yesterday evening, we fired up the generators for the first time, so roughly about 60 days from the word go. April 19, 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 10 and both sites will be fully operational by June 15. In addition, we believe that this particular strategy has the ability to go from 350 megawatts to 600 megawatts to further compliment, 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 a struggle to manage through the energy transition. So with that, I think I’ll turn it over to Chris.

Chris Guinta: 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. 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 by three – 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 LN G 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 projects, 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 pipeline and mooring anchor installation is complete and awaiting rigs to arrive on site.

Our team is expecting to have the rigs sale 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 is 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 with 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 reason 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 world-class facility with all major aspects needed for a liquifier, including 250,000 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, we utilize two of NFE’s modular, 1.4 mtpa trains and all of the terminal’s existing infrastructure. Our significant and 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 liquifier. With that, I’ll turn it over to Andrew.

Andrew Dete: Thanks, Chris. Good morning, everyone. I have three points, I want to make this morning. The 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 in 2024 view on our LNG portfolio of supply and our contracted sales downstream. So turning to Page 17, what we’re seeing is a significant and 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 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 in 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 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 of 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 MMBtu supply context into low-20s per MMBtu. So this try 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. 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 FLNG 1 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 2024, 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 one, and then two and three 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 Barcarena 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 one, two, and three in 2024 is a partial year number. In 2025, 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 2023. So 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.

Wes Edens: Great. So two other kind of brief thoughts, and I’ll give it to have Chris walked 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 on, jump off the page. I mean, 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 generate free cash flow conversions of 30%, 35%, 40%. When you 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 today. And that I think in a very simple sentence 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’s – that really is the backdrop for this. We have one other incremental business update that I wanted to provide us 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’ll 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 days to 90 days to 120 days. But any event, it’s our expectations. By sometime this summer, we’ll have an effective registration statement and thus will 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 this share of this stock. This is a – 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. So as I said before, when you start with an electrolyzer or a 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. So 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 on the – publicly on the company at this point. When there is information publicly, we’ll obviously, we’ll 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, we have more to say about it. Chris?

Chris Guinta: Yes. Let’s turn to Slide 21 for the financial results for the first quarter. For the three months ended March 31, 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 MMBtu. One other comment here during the first quarter, we did close the Hilli transaction, and as a reminder, we sold our 50% interest back to Golar in exchange for a $100 million in cash, 4.1 million of share – 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. Be 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, including – all of our development objectives including FLNG. On this slide, we’ve 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 one through three, and includes the cost spent to date for units four and five. 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 as accretive and the best way to continue to grow earnings. Move please to Slide 23. And as you all know, throughout 2022, we executed on sale and undergoes transactions, and in 2023, we sold back to Golar, 50% interest in the Hilli.

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 over – 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 four more review of 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 your notching within the BB category.

In working toward that goal, the agency’s outlined things that would lead to an upgrade, including earnings predictability in 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 billion 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 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 is in turn is 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.

Patrick Hughes: Thanks, Chris. Jim, I think we’re ready for some Q&A. If you could tee up the queue please.

Q&A Session

Operator: Thank you, gentlemen. Our first question today will come from the line of Ben Nolan at Stifel.

Ben Nolan: Thanks. I appreciate the time here guys. I’m going to try to nest a few FLNG questions all into one. The first is or well, here’s my nested question. So any update on how all of this impacts the Louisiana and the MARAD process, also the Lakach process? And then as it relates to Altamira and 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?

Chris Guinta: Hey Ben. Hit them in sequence. So, 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. With regarding Lakach, there’s active engineering work and negotiates 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 is takes crew boats, you have to move supplies, consumables, water, et cetera.

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’s maybe 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.

Wes Edens: Yes, 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, it’s a – we tour the site now a number of times. There’s not a weed or a piece of rock out of place is 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. or first take an import terminal where many of the infrastructure elements that are there are usable. So as Chris said, the 150,000 cubic feet 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 transit 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 path to the hurricane zone. So Texas, Louisiana of course are frequently hit by hurricanes in some cases there, 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 liquefier, it’s going to be a significant positive. So working hard on permitting path on economics and whatnot, but we’re quite optimistic about this.

Ben Nolan: All right. I appreciate it. Thanks guys.

Operator: Our next question comes from Devin McDermott at Morgan Stanley. Please go ahead.

Devin McDermott: 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?

Wes Edens: Yes, 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 two and three to both be completed in the second quarter of 2024. The onshore component is civil work, and it’s really balance the 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 by not only in transportation costs, but of the pipeline, but also in the use of the terminal. So I expect that it’ll take several meetings with these guys, but we think that getting from here to a finalized agreement is a matter of a few weeks. And then we are finalizing fixed price and fixed term construction contracts to take these modules and have them installed onshore. Hopefully that it answers your question, Devin, happy to circle back on a separate call later today to go through anything more detailed.

Devin McDermott: Yes, 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?

Wes Edens: 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 and Cheniere and Venture Global. And the FLNG 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 sold basically to go into that.

Andrew Dete: And on the forwards, we’re just using the current Henry Hub and TTF strip prices basically marked for the quarter. And then we obviously have the transport cost that’s built into our shifts portfolio as well. So we we’re using market prices for the forward.

Devin McDermott: 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.

Wes Edens: You bet.

Operator: Sam Margolin with Wolfe Research. You have our next question.

Sam Margolin: Hey, good morning, everybody. Thanks.

Wes Edens: Hi, Sam.

Sam Margolin: So it – the story here I think 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 policy makers 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 in a position to grow and not just sort of see kind of curtailments and headwinds?

Wes Edens: Well, and look, I think 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 is Jamaicans use 10% much electricity as Americans do. Kenyans use 10% much electricity as Jamaicans do. So 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 or 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 the – you have something like 40% of the world’s population has insufficient electricity so that the amount of gas and electricity needed is incredible.

And what you’ve seen when – 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 that it’s obviously we’re all for carbon free energy everywhere, but there’s also the matters of access to 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. And 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 the 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, they’re not an industrialized countries in particular, lacks as of access to capital to build infrastructure is probably the top of the pyramid. But actually then beyond 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’m going to 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 that exists than Puerto Rico, but frankly, they’ll all exist through that. We’ll see – we see significant incremental demand in Barcarena, we see significant incremental demand in Santa Catarina, significant incremental demand in Mexico, 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 economics 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 cost, spread them out over time and be more effective than the next guidance.

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 a 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.

Sam Margolin: 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 any – if you have a lot of flexibility because you’re not on the hook to purchase gas through that pipe. Thank you.

Wes Edens: Yes, we have no purchase obligations. We have no commitments there at all. Nothing that would change the timeline of the project either.

Sam Margolin: Thank you so much.

Wes Edens: Thanks, Sam.

Operator: Our next question comes from Chris Robertson at Deutsche. Please go ahead.

Chris Robertson: 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?

Chris Guinta: No. We’re doing, we have excellent support from the team at CFE and the regulators. We have all construction permits in hand. We’re awaiting on our operating permits that are all expected to be received this month. We’ve received our FTA export license and the DOE – from DOE and the Mexican export license is expected by the end of next week.

Chris Robertson: Okay. Got it. Yes. 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 focus and kind of the process behind that?

Chris Guinta: Sure. I mean, we set 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.

Chris Robertson: Okay. Yes. Got it. Thank you.

Operator: Cameron Lochridge at Bank of America. Please go ahead.

Cameron Lochridge: 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 your downstream terminals guidance for 2024 seems to imply about a $10 margin down a little bit from the implied margin in 2023, presumably on its Barcarena and Santa Catarina 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.

Andrew Dete: Hey Cameron, it’s Andrew. I think you got that about right. I mean we’re – in 2024, we’re certainly turning on three new terminals. Those have like 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 shakes out in terms of margin.

Wes Edens: But what you’ll see is that as a – when a terminal is new and you get a base load, 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 that 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 was 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, your margins are going to get better over time.

Andrew Dete: Yes, Barcarena is the perfect example too, Cameron, where it’s like we start with the baseload next year and then the power plan in 2025 will kind of go right to the bottom line because we’ll be paying for the infrastructure.

Cameron Lochridge: 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 drillships 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 La Paz 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 may ride 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 ride and may maybe accelerate that permitting process?

Wes Edens: The answer to the question is could – is the marine infrastructure free up, the answer is yes, right? 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 ships to prepare them for acceptance of 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 be – 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 are, they’re more questions about the jack up rigs than it is concerns about it. I mean, jack up rigs are used all over the Gulf, so this is not a new activity. What’s new is simply grouping them together and actually having liquefaction on it. And so 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. And so we’re quite optimistic that we’ll get through that in due course.

Operator: Next we’ll hear from Sam Burwell at Jefferies.

Sam Burwell: 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 in the FLNG, that’s like $1.2 billion. You spent $560 million in 1Q. Is that implies a pretty solid drop off in CapEx for the rest of the year? So just wanted to confirm that’s indeed the case. And then another point of clarification, the not – into 2025 and the $1.3 billion in 2023 and 2024 respectively for FLNG, that’s just units one, two, and three, correct?

Chris Guinta: Yes. The short answer to both questions is, yes. We do expect a drop off and yes, this does include the completion of units two and – one, two and three, and then money that’s already been spent on number four and five.

Sam Burwell: Okay, understood. And then a follow-up on sort of the margin trajectory for the rest of the year. Doesn’t look like you guys disclosed like a explicit per MMBtu margin for the quarter, but I got to figure that there were cargo sales contributing to it in 1Q. And I would assume that those probably taper off through the year, but Puerto Rico should ramp through the year. And just curious like how should a blended – how should we think about like blended margins sequentially? Should those be pretty steady quarter-on-quarter or should we think about margin uplift in the coming quarters at all?

Chris Guinta: Yes. 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. Yes. That’s exactly correct.

Wes Edens: I mean, the – we got a lot of questions from analysts and from 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 that’s – but 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’s really, really clear window and I hope that you got to use guys soas well.

Sam Burwell: Got it. Understood. Thanks guys.

Operator: Our next question this morning will come from Sean Morgan at Evercore. Please go ahead. Your line is open.

Sean Morgan: Hey, thanks team. Thanks for squeezing me in. My question, if we go back to May of 2021, 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 following 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 sort of where you guys come out in that debate.

Wes Edens: Well, the – our focus has been on green hydrogen the whole time. So if there was – we definitely have looked at different solutions and we think that there are attractive economics based on the performers that we’ve seen on the blue hydrogen, but that blue hydrogen, blue ammonia is a very, very different business path than the green hydrogen electrolyzer path. So specifically, the product – project that we are engaged in is a piece of land in Beaumont, Texas, where there’ll be a balance of plant and then electrolyzers put in place. 120 megawatts is the size of it would be. To date, we think one of the biggest is 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 will – 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 kilogram production credits for green hydrogen. We think 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 the – a lot of the parallels people point to are the change in efficiencies in renewables over the years, which have 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’ll flow to the bottom line and it makes those projects be very economically viable, we think. And again, we have more detail on that, we’ll share it with you when the filing becomes a public one.

Sean Morgan: Okay. Thanks, Wes. And then just to follow-up on the gas procurement for Louisiana question from earlier, I just wanted to clarify. So there’s no purchase obligations outstanding right now. How long does it take to kind of pair off supply from upstream E&Ps? And do – like, what sort of lead time do you need before you guys say regulatory approval in Louisiana to kind of line up that gas to sell out of the terminal?

Chris Guinta: So we have access from pipe back to a 500 pool and back to readily access gas supplies that run across south Louisiana. So we’re not – 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.

Sean Morgan: Okay. Thanks, Chris.

Operator: And that was our final question from our audience today. I will turn it back to our leadership team and to Mr. Hughes for any additional or closing remarks.

Patrick Hughes: 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.

Operator: Ladies and gentlemen, this does conference. Thank you for your participation. You may now disconnect your lines.