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.

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.

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…

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,…

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.…

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…

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%,…

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…

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

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

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?

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.

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 [indiscernible] working hard on permitting path on economics and whatnot, but we’re quite optimistic about this.

All right. I appreciate it. Thanks guys.

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

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?

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.

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?

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.

And on the forwards, [ph] 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.

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.

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

Hey, good morning, everybody. Thanks.

Hi, Sam.

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?

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…

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.

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

Thank you so much.

Thanks, Sam.

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

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?

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.

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?

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.

Okay. Yes. Got it. Thank you.

Cameron Lochridge at Bank of America. Please go ahead.

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.

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.

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.

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.

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?

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 [indiscernible] 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.

Next we’ll hear from Sam Burwell at Jefferies.

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?

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.

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?

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.

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.

Got it. Understood. Thanks guys.

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

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.

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.

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?

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.

Okay. Thanks, Chris.

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.

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.

Ladies and gentlemen, this does [indiscernible] conference. Thank you for your participation. You may now disconnect your lines.