NFE - NASDAQ

Ladies and gentlemen, please standby. Good day. And welcome to the New Fortress Energy Third Quarter 2022 Earnings Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Patrick Hughes, Managing Director, Investor Relations. Please go ahead.

Thank you, Jake, and good morning, everyone. Welcome to New Fortress Energy’s third quarter 2022 earnings conference call. As Jake said, this call is being recorded and will be available by replay on the Investors section of our website under the subheading Events & Presentations. At the same location you will also find our Q3 2022 Investor Presentation, to which we will refer during today’s call. The presentation contains 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 turn to today’s call. This is Patrick Hughes. I look after Investor Relations here at New Fortress Energy. Joining me today are Wes Edens, our Chairman and Chief Executive Officer; Chris Guinta, our Chief Financial Officer; Andrew Dete, Managing Director responsible for Commercial activities, as well as several other members of our team. With that, I will turn the call over to Wes.

Great. Thanks, Patrick, and thanks everyone for calling in this morning. So as usual, I am going to refer to the investor deck that we posted here this morning. So if you could pull it up and follow along, that would be great. So let’s start on page number four. Q3 was another great quarter for the company. Very, very solid quarter financially $291 million in EBITDA, that puts us well on track for our $1.1 billion goal for the year. It’s up significantly from Q3 a year ago of $170 million, and just in general, on a financial basis was actually -- was quite a productive quarter. In addition, we made significant progress on our two major aspects of our business, the supply side and the demand side. The supply side, of course, I am talking about the FLNG business. Chris will talk about that in some detail. We hosted a large group of investors, equity analysts, other participants last week down in Corpus Christi to share with them, not only the details of what we are actually doing down there, but also introduce them to the very talented team people that we have got who is executing for us and we feel great about that. On the demand side, there’s a lot to talk about. Andrew will spend a lot of time on that and it’s really a question of the two aspects of demand. In the short-term, the dislocation in the world is significant and we all know about that. We will talk about that specifically. Long-term, our mission to provide power to the places in the world that needed most is very much the mission of the company and the problems and the dislocations in the world that we have seen in Europe, in particular, have only exacerbated the needs that people have. So we will talk a lot about that as well. So both sides, that’s great. Other significant financial aspect of the quarter is we have increased our guidance of our illustrative goals for next year from $1.5 billion next year to $2.5 billion. So significant upward adjustment based on what we see in the world right now and Andrew will talk about that here in just a moment. So look at page number five. This is a new page, new format for us on presenting kind of the supply-demand side and I find it particularly helpful. On the top you can see the summary of the supply side. So the volumes TBtus, 74 TBtus in 2021, 88 TBtus in 2022, 161 TBtus as FLNG volumes kick in, in particular, in the second half of 2023. Lots and lots of different adjustments in this business. 52 TBtus equals about 1 million tons of gas, so about 1.5 million tons last year, closing on 2 million tons this year and then 161s TBtus, we are actually making a big upward adjustment next year, but then follow over to the right and you can see what our expectations are for the rest of our FLNG volumes in 2024, 2025 and you can see a fairly profound shift to the right in terms of volume. So take those volumes. And now look at the second line down, which is the margin that we have realized on our positions. So simply put, if you took the volumes, times and margins that equals adjusted EBITDA. So I couldn’t be a clearer and more transparent way of looking at the business. You can see in 2021, we realized margins of $8.14 for TBtu, 2022 $12.50. Our forecasted $2.5 billion in EBITDA results in a $15.53. So you see margin improvement each of these years. That should match your intuition of what’s happening in the world, right? So as the world has gotten dislocated, the opportunities to realize higher margins are there. But then what we are obviously very focused on is not the short-term, but the long-term. And so if you look on the right-hand side, what we have done is normalized those margins for what we believe is achievable largely through the sale of power and gas to our customers around the world, and again, Andrew will spend a lot of time talking about this. But at $10, $12.50 to $15, you ended up with illustrative EBITDA in those years ranging from $3.3 billion in the low side in 2024 to $6.96 billion on the high side on the other side. Now, this all assumes that the amount of supply that we have in our inventory equals what we have already effectively committed to, obviously, we think that there’s significant growth opportunities across the world and across our portfolio. But this is a very discreet way of looking at it and I hope that you find it helpful. So, with that, let’s look at page number six. With the good news on the operational side, we are a significant generator of free cash flow. Cash on hand today $1.4 billion, targeted operating cash flows over the next three years approximately $10 billion. So simply backing out the CapEx that we required to finish our FLNG and other initiatives we have got across the company, we expect to generate $5 plus billion in liquidity over the next three years. So a significant amount of liquidity and the question is then what do you do with that? The three obvious choices are in the box down below. So number one, you can obviously make additional investments. Number two, you can return capital to shareholders, either by deleveraging the company and then issue dividends, deleveraging the company and buying back stock or some combination of all of those things. We have yet to conclude specifically the path that we are going to take and we have a significant amount of liquidity now. We talked about with the Board yesterday is doing a lot of analysis over the next 30 days or so. And our target is on or around December 15th to come out and make a clear statement to shareholders about what our intentions are, both in the short-term and the long-term with respect to our dividend policy in particular and what we intend to do with this capital. So it’s a serious exercise. As we say, when we look at our balance sheet and capital structure, it’s the old proverbial measure twice, cut once situation when you are talking about significant amounts of capital. But it puts us in a great position to return capital potentially to shareholders, do things to grow our business and those are the things we are going to take into account. So more on that to come here in a month or so. Page seven is my last page before I will turn it over to the rest of the team. If a picture is worth 1,000 words, this might be worth 10,000 words. So this is actually a chart that you could print out and carry around with you, because I think it talks a lot about what the situation is in the world today. When you look outside the yellow box, you will love to see, for the most part the three major indices of natural gas. Henry Hub in this country, TTF in Europe, JKM in Asia, moved relatively in a synchronized fashion for many years. What’s notable is that when we start to get the dislocation here, you will see the timeframe for that actually occurring is July 2021, so full nine months before actually the Russian invasion is started to get a significant change in the balance or imbalance in the world and that caused prices to spike. The question, of course, when I look at this chart is, what do I expect to happen when you continue to add this out to the right and things are normalized? And what is the new normal and what is the level that we would expect for gas to eventually settle out that once this crisis is settled in one shape or form or the other. My own perspective of it is, I think, the new normal may be at a marginally higher rate, perhaps, a markedly higher rate. And maybe the era of cheap energy, in particular, in Europe is one of the past, and that when things normalize, if indeed they do normalize, you will end up in a higher place overall. But that obviously has a big impact on margins in the business, margins for us and is something to really keep your eye on. But there are a number of factors that are not included in this chart that, I think, could have a significant impact. Most notably is that, in Asia there has been a pronounced step down in LNG importation in China, in particular, the zero COVID policy there has obviously impacted them economically. They have actually scaled back dramatically on that. That’s something that we watch carefully. It’s something we think could actually change markedly. But really, the other thing I’d mention about this chart is that this talks very much about the developed world. So this is about the United States, about Europe, about Asia, and of course, there are many, many billions of people that are outside the developed world that desperately need energy. Andrew will talk about that here in just a second. But I think that even regardless of what’s going to happen in Europe, you have a massive demand and a need for power in these different markets and so this is something to keep your eye on. But an interesting chart in the last. I will turn it over to Chris. Chris?

Yeah. Good morning. Thanks, Wes. Let me let direct you to slide number nine and I will update you on our LNG supply portfolio and what we are actively doing to increase it specifically our fast LNG developments. On this slide, you can see substantial growth in the portfolio from 2021 through 2025. Our current supply contracts went from 74 TBtu last year to 88 TBTu this year will be 114 TBTu in 2023 through 2025. When you layer on FLNG volumes, we have an additional 350 TBtu or approximately 7 metric tons per annum coming online in the short-term. The first unit will begin operations in May or June 2023 and then the remaining five will turn on before the end of September 2024, so less than two years from now. This will result in 161 TBtu in volumes next year growing to 464 TBtu for 2025. Now let’s turn to slide number 10 and talk about the progress in LNG. As you know and many of you attended, we hosted an Investor and an Analyst event last week in Kiewit shipyard in Corpus Christi and it’s a great opportunity for us to give investors a glimpse of the progress we have made. As we mentioned on site, nothing that we are doing is overly complicated or difficult, but it does require the team to be organized, efficient and accountable to one another. The two key takeaways from the event last week and the highlights of the quarter are, one, we are making excellent progress on FLNG Number 1 and expect to achieve mechanical completion on March the 17th and then have the asset deployed and operating in May and COD in June 2023. Second, we made huge progress in the deployment options, including permits for our various locations, which we will outline in a couple of slides. As mentioned, our FLNG 1 is rapidly approaching completion. On the modules in the top left of this page, there’s a picture showing where we assemble the modules that will be lifted under the jackup rigs. Module one for gas treatment goes on the first rig. Module two liquefaction goes onto the second rig and then we will have one smaller module for utilities and accommodations that goes on to the third rig. Each of these large modules will be 4 levels to 7 levels high, when completed will way over 5,000 tons. Below is a picture of the jackup rigs where the modules will be installed. We have completed the demolition and are nearing the completion of the whole strengthening and enhancements to the foundation, as well as a complete overall and upgrade of the marine systems. Further, we are in the middle of preparing for deployment and operations once the FLNG construction has been completed. We have hired our commissioning team that’s working to commission as much of the asset in the yard as possible. Once the system is completed, we can work to activate and test immediately. Regarding installation, we are doing things to have all subsea tie-ins, pipelay, mooring, riser work completed in order to ensure that once the FLNG is on site, we can immediately begin operations. And in operations itself, our team of people has already begun training and simulations to be ready to operate the asset once it’s on location. Flip to slide 11 and we have talked about these locations before, but we have expanded our FLNG options to deployment to three different spots, which we could accommodate up to six FLNG units. As Wes mentioned, we were in Mexico City for another -- for another meeting with President López Obrador and the Director of the CFE, where we signed binding documents to deploy up to three units at Altamira. This would utilize U.S. feed gas molecules transported into Mexican waters via the Sur de Tuxpan pipeline. We have submitted all permit applications and those are undergoing final review. We have active, vocal public support by all relevant permitting agencies in this process. We expect to complete the permit process early next year. The second box is the West Delta 38 location where we submitted our MARAD application to install two FLNG assets. This would again utilize existing pipeline infrastructure and reverse flow of gas from onshore to our unit offshore. As many of you know, our stock clock order was lifted on October 28th and we expect EPA to issue our draft environmental impact study very soon. This puts us on track to receive final permits in the first half of 2023. The third location is an innovative partnership with Pemex to complete the Lakach field. NFE will complete seven wells and then begin producing in summer 2024. We will send approximately third of the gas to shore for Pemex to use and the remaining two-thirds will be used as speed gas for our FLNG 4, which will use the Sevan semisubmersible drillship. We really like this model, which captures proven but undeveloped and stranded gas reserves and sends a portion to sure and the remainder to NFE for feed gas to turn into LNG. Turn please to slide number 12. Let’s talk about this page last week in Corpus, but this provides a roadmap of which units we are building, where they are being built and when they are expected to be complete. The page shows the mechanical completion dates for each of the units and then it takes between two months to three months to mobilize, install and commission before reaching COD. These schedules are the result of simplifying the design with a focus on repeatability. We have the module fabrication time line and the marine infrastructure make ready down to about 12 months to 14 months to mobilize hookup and install is about a two-month to three-month process. The commissioning is one month to two months, and all told, we can be done on future units in 18 months to 20 months from FID to COD. Further, we have already ordered all of the critical or long lead items for each FLNG unit 1 through 4, and obviously, we are using the same providers on each unit. By using a uniform design on the engineering of the modules, the bulk of the procurement is common across the units. So there’s Baker Hughes for compression, Chart for the cold box, Siemens for gas turbines, Shell Gor [ph] for marine equipment, et cetera. So, in conclusion, you can see our supply of LNG is growing rapidly over the next two years. These will not only fuel expanding downstream portfolio but also perfectly positions us to capitalize on current market dynamics and the growing global need for reliable LNG to boost energy security. With that, I will turn it over to Andrew.

Thanks, Chris. Hello, everyone. It’s great to be with you last week in Corpus Christi. Amazing what Chris and a lot of [ph] and the team have done. It was fun to stand on those rigs and kind of look out and see all the component parts about to be lifted on to them. And in my role on the commercial side, a very important moment for us. So as Chris just went through NFE is creating 7 MTPA of new volumes in the short-term. So that takes our total portfolio up from about 2 MTPA to 2.5 MTPA to 9.5 MTPA, which, as Chris showed is 464 TBtus by 2024 on a run rate basis. So I am on page 14 and what we want to do now is spend a minute to frame our long-term commercial strategy for selling these volumes in a way that creates long duration sustainable returns. And what you will see that the strategy is generally in line with the same core mission is he’s had since the beginning of expanding access to affordable power globally, which we think is both a good business and a great mission. And so on page 14 on the left side, what we are showing really is an energy density chart of the world. So the tagline is 70% of the world electricity is consumed by just 10 countries. And so what we see every day in these markets and what we believe is that these other countries that are less kind of energy dense are only going one way and that’s towards more energy consumption, more electricity consumption. I think I almost have to pay a royalty to Wes to say this. But as long followers and if you know, Jamaica consumes about tenth of what we consume in the U.S. and Kenyans consume about a tenth of what Jamaicans consume. And so what we see is a tremendous opportunity and a huge market, which is to provide affordable power in places that don’t have it today. And the more time we spend in these markets, what we see is that demand is really only curtailed by supply, and in that case, by affordable supply. And so when we look at the right side of this page, which is new data from EIA, what they are showing is that in the first time of 20 years of collecting data on access to electricity, they are actually seeing the number of people that don’t have access to electricity increasing for the first time in 2022. That’s a bit of the canary in the coal mine about a broader story about energy flows being redirected towards Europe and generally the developed world and about the world being short energy on a global basis. So this really sets the framework for what we think the opportunity is and why we think it’s important to us. And long term, what we continue to believe is that by integrating our LNG supply with power production, we can achieve differentiated sustainable margins over the long-term. I want to give some insight today on how we are going to do that. So flipping to page 15. NFE really is an integrated power company today. We have supplied converted, acquired and built over 3,000 megawatts of power to-date across eight different power assets. And so what we want to provide here is some background on what we have done as we dimension and assess the opportunity going forward. Selling power is truly a downstream business. We are integrated all the way down to the consumer and now we are adding supply to effectively close that loop, and we are going to do more power. Power provides a basic necessity and service to consumers and industrial businesses, it’s typically acquired on a long-term contractual basis and it’s very resilient from a credit perspective. It’s very difficult to replace ones operating, it’s more expensive to turn it off and our credit experience across these countries has been extremely positive even through a global economic downturn, we have been paid on time in all of these jurisdictions. So 90% of the operational volumes today an NFE are power related and the over 3,000 megawatts that we have been either a supplier or an owner of is really going to speak to what we are going to do going forward. So flipping then to page 16. On the left side are the dimensions of the supply that Chris talked about. So 464 TBtus is where we are going to be on a run rate basis in 2024. 130 TBtus of that will be spoken for in current contracts and 334 TBtus of that will be new supply. Roughly, we kind of use a rule of thumb that for every 10 TBtu that’s about 100 megawatts and so that 334 TBtus translates to about 3,300 megawatts of new power demand that we are going to fill with our LNG supply. On the right side, we are already in development on 1,700 of those megawatts. That’s the power plant in Barcarena, our 600-megawatt power plant in Ireland, 300 megawatts in South Africa and 200 megawatts of new power in Jamaica. We also have a development pipeline in growth markets to over 5 gigawatts. And so what we want to show here is, as our supply ramps up to this overall portfolio of 9.5 MTPA, the opportunity to actually integrate that with power demand downstream is about the size of what we have done before and we are already in development on over half of that volume. On page 17, what I want to do is take that opportunity that’s in front of us and trying to dimension it from a margin perspective. So when we think about power, we really think about kind of selling long-term power in their PPA at competitive rates. That starts me on the kind of the left side of this page, which is $0.125 per power. That’s a cost that we think is competitive around the world in these growth markets. Typically, there’s also either a capacity payment or return on CapEx, the difference between what it costs to build and what the value of the plant is, but it’s roughly around $0.025. So we see long-term for 100 megawatts of simple cycle power, as we can sell power for an all-in rate of about $0.15 per kilowatt hour. Assuming a 9,000 heat rate, that’s about a $17 per MMBtu sale of gas. Our cost of production on FLNG plus transport is about $7 MMBtu, which leads to a total gas margin of about $10 for MMBtu. That’s in line with historicals Wes showed earlier, $8 going to $12 going to $15 and also what we believe for the long term. So in the bottom of this page, we are looking back to our margin page that we showed earlier to show as we get to our goals of 464 TBtus run rate 2024, 2025 at $10 in margin, that’s $4.6 billion of margin. And so this really is in line with what we have done in the past and what we are looking to do going forward. Let me flip then to page 18 and kind of address how we get there. So the amazing thing about this opportunity for us today and that’s been different about this business in the past, is it’s an amazing time to be building supply and to have a long position, because there’s effectively an unprecedented market opportunity for LNG on a short-term basis. On the left side of the page, we have actually been doing a ton of detailed modeling about 2023 gas balances in Europe and for those of you who follow this, there’s -- it’s a highly variable problem, but we like to go back to kind of one simple metric, which is in 2021, there was 122 MTPA of Russian gas supply through pipelines, in 2022, there was 67 MTPA and in 2023, we expect to be zero. That’s effectively replacing 1,500 LNG cargoes and you need 20 plus new LNG terminals to do it. And so there’s a lot to be said about what will happen in 2023, but I think, we effectively believe that market will be continuing to be short. And the price graph on the right, which is the one we showed previously, which is when we all carry around in our pocket today, is really the short-term opportunity. So we are building a long position into this opportunity that we are going to term out over time with integrated LNG to power. Page 19 goes a little bit further in terms of the infrastructure in Europe, because we want to describe some of these details to you to understand just how good this opportunity is and how we are going to attack it in the very near-term. Europe has substantial regas infrastructure today and a very connected LNG market. So there’s approximately 30 terminals, about 3,000 LNG cargo slots a year and the market trades on an index price. So that the main index is called TTF. It’s the gas network in the Netherlands and the other gas networks in different countries in Europe effectively trade at some basis to the TTF price. Now the great thing for us that is very different from most of NFE’s life is we have got two things. We have got existing infrastructure and we have got a centralized market price. So we don’t have to go find individual buyers. We can sell effectively on a centrally cleared exchange at an index price. And so there are choke points for this infrastructure of getting into Europe, and obviously, now those are getting more full, we are creating new capacity, which we highlighted here, which is the Eemshaven terminal in the Netherlands, which we partnered with Gasunie and is the first new terminal to turn online since the Russian vision. There will be other new terminals, especially in Germany, some in Italy and other places as well that will expand that infrastructure, probably, not enough to make this market anything, but very tight for the next few years. But there will be available infrastructure for suppliers like us to be able to supply gas into Europe. Again, replacing 100 MTPA of Russian flows, that’s probably 15 to 20 new regas terminals to really try to dimension that opportunity. And so as we expand the portfolio of supply, we will be able to sell into Europe using existing infrastructure and at the market price, which is giving us great short-term returns. On a long-term basis, what we really believe is that LNG to power is the differentiated way to build competitive advantage. It provides a real service downstream, it provides competitive margins and it’s something that NFE has the expertise and the experience to do. And so that’s a little bit more information on how we are looking about the long-term opportunity and how we are going to deploy all these LNG volumes and look forward to talking more. Back to Patrick.

Thanks, Andrew. I am on slide 21. We are just going to spend a few minutes talking about hydrogen. So we -- I guess, I’d start by saying we continue to make significant progress with the hydrogen business, what we are calling zero during the third quarter. And as Wes has said many times, we are very strong believers in the role that hydrogen will play as a cornerstone of a clean energy future. In particular, we think it plays a big role in difficult to abate sectors of the industrial economy, things like refining, petrochemicals, steel and cement manufacturing where you can have a real impact on decarbonization. But what we are also seeing, actually, especially in recent months, there’s a lot of related opportunities in kind of secondary and tertiary areas like transportation, hydrogen storage and renewable power, and we continue to look at a number of opportunities in those areas from a strategic perspective. All of that said, we are really in the early days of seeing a clean hydrogen economy really come to life. So let’s start with Beaumont and the asset we have talked to you about in past quarters and then we will step through a few other items before I turn the call back over to Chris. So we are proud to be -- a really true first-mover advantage in the space with our first industrial scale green hydrogen plant in Beaumont, Texas. We are building a 120-megawatt green hydrogen facility, which will be capable of producing 50 tons per day of green hydrogen, which is about 18,000 tons per year. At that level, it will be the biggest of its kind in the U.S. once it becomes operational, which we expect in 2024. Beaumont itself is a big industrial center in Southeast Texas that many of us are familiar with from past transactions and activities, lots of refineries in the area and lots of others that use hydrogen today and so our natural customers are right there, both inside and right outside of our property sense line. To put it in perspective, just three or four refineries in the immediate vicinity have demand for over 1,000 tons a day of hydrogen, and again, we are producing 50 tons in our initial scale. So 1,000 tons per day is over 20 times what our plant alone would be able to produce in our initial phase. So plenty of demand and plenty of growth potential in the immediate region. As many of you know, during the quarter, we secured our long lead equipment for the facility, including our electrolyzers in our deal with Plug Power. They are the manufacturer of essentially the machines that make the hydrogen. The first of these units will show up at our site in 2023 and we will complete assembly and start operations, as I said, in 2024. Also during the quarter, we signed an agreement with Entergy to provide the renewable power to our site. There are actually multiple facets to that agreement and they have been a great partner so far. Entergy, of course, is helping with the power connections, the high side, the transformers on the site that you see on slide 21, but we are also looking at other areas of potential collaboration with them. So now on to slide 22, as it turns out, the U.S. is really going to be the best place to build clean hydrogen projects, probably, of anywhere in the world. Earlier this year, as many of you know, Congress made a major investment in clean energy infrastructure, actually the largest climate investment ever made in the history of the U.S. The so-called Inflation Reduction Act as the legislation is known is expected to spur more than $4 trillion of infrastructure investment over the next 10 years. That will include a tripling of annual hydrogen spending and other big commitments toward things like carbon capture and storage, solar, electric transmission, really the network that makes all of this possible. We are quite focused, of course, on the $3 per kilogram clean hydrogen production credit, which takes our hydrogen business from marginally profitable to very profitable and really allows our industry to produce green hydrogen in an economic and scalable way. So you go to the last slide in the hydrogen section, which is page 23. As we shared on our last call, we are working on projects in the Gulf Coast and in other locations around the U.S. We mentioned, in particular, the Marcellus project on our last call. What we are doing here is putting together really a pure-play multi-asset clean hydrogen infrastructure business and our plan is to separately capitalize this business in the near future. Over the last several months, we have continued to put all the pieces together for Beaumont and we have learned a lot. We are applying those learnings to really optimize our approach to future projects, including being very thoughtful about our customers, and where the demand for hydrogen actually is, really putting these clean hydrogen markets in place right where they are needed. So we are basically using all the good things about the Beaumont project and kind of stamping out that model in other parts of the country. To put this all in relatable terms, we are building really the leading industrial scale clean hydrogen business and our platform initially is expected to be the equivalent of five Beaumont. So this 90,000 tons per year number that you see on your screen is equivalent to about 600 megawatts or about 520-megawatt Beaumont facilities. As you can see, there’s much more to come on this front. We will be in touch again soon with key commercial milestones at Beaumont and details of our path for expansion and separate capitalization. Chris, over to you.

Great. Thanks, Patrick. Please turn to slide 25. I will quickly run us through the financial performance for Q3. For the three months ended September 30, we had adjusted EBITDA of $291 million, which is approximately $1.2 billion on a trailing 12-month basis. The terminal segment operating margin was $251 million with another $88 million from the ship segment and you can find more detail in the appendix. Net income for the quarter, $86 million, which is about $0.41 per share when excluding onetime items. This quarter we sold 24 TBtus in total volumes, which equates to an average operating margin of around $15 per MMBtu, which obviously is in excess of what Andrew is saying we can do long-term. Henry Hub averaged 8.30 [ph], which is obviously a pass-through, but did have an effect both on revenue and costs over the period. Move to slide 26. We are showing a side by side of the balance sheet as it at June 30, 2022 versus where it is now, and as you can see, it’s a completely different picture. As a result of the incredible work of our M&A teams, we have executed on our promise to monetize over $2 billion worth of assets, which fully funds our growth initiatives. We have simplified the corporate debt to just two tranches of bonds at 6.75% and 6.5%, respectively. We also have $440 million revolver and a $250 million letter of credit facility, which provide us access to low cost flexible capital as needed is currently undrawn given our cash position. And lastly, we have the Jamalco bonds, which is an asset-level debt, non-recourse NFE, but it is consolidated in our balance sheet and thus included here. As you can see, the liquidity profile is strong with over $1.4 billion in available capital. If you turn to slide 27, we have made significant progress on our financial goals and we will use this slide to talk to the rating agencies in the coming weeks. We think we are well positioned for an upgrade and look forward to speaking with them. Today, as I mentioned, our trailing 12-month EBITDA is approximately $1.2 billion, with seven terminals either online or nearing completion, we have debt-to-EBITDA ratio of less than 3 times. As you can see on the graph at the bottom left, deleveraging is rapid as each FLNG unit comes online. There will be -- we will be under 2 times leverage with our first FLNG asset below 1 time once the second one comes online later next year. Finally, at the bottom right of the page, we show our cash on hand plus availability into the working capital facility is $1.4 billion, which combined with our operating cash flow fully funds the FLNG initiatives. Finally, on slide 28, this shows our continued focus on being a world-class operating company. In Q3, we delivered 24 TBtus to customers and asset reliability remains above 98%, important to note that our excellent teams in South Florida and the Caribbean were able to effectively and safely shutdown activity while hurricanes approach facilities this fall and then had operations back up and running within 24 hours of the all clear notice from the Coast Guard. Last but certainly not least, we had no safety incidents during Q3 and maintain our 0.0 total recordable incident rate. With that, I turn the call back over to Patrick.

Thanks, Chris. So, Jake, I think, we are ready to take a couple of questions. So if you could explain the instructions to the callers that would be great. .

Of course. [Operator Instructions] And we will begin with Ben Nolan with Stifel.

Yeah. Thanks. I appreciate the time here. I wanted to start a little bit just understanding on the FLNG side what goes where. It feels like the Altamira is first in line for the jackups and I guess that would mean that floaters would go to Louisiana. First of all, is that right, and if it is, does it change the MARAD process at all with respect to sort of approvals and time lines or anything like that?

Hey, Ben. It’s Wes. Good to see you last week. The -- as Chris said, we signed agreements with the Government of Mexico on Friday, right after our tour in Corpus. And so we have definitive agreements that allow us to place units into Altamira, which is great. So that gives us a lot of certainty that with say the FLNG business, there’s two things that matter. One is building the unit and two is having a place to put it. And so we feel great about our situation in Mexico and feel like this is the first of many different opportunities we have done there. Second, with respect to MARAD, we have a very engaged process with them. Our permitting team is in daily interactions with them at this point. As you know, there’s a 364-day period that they have to grant you a permit by statute. If they have questions along the line, they can stop the clock basically while they ask you to give them more detailed responses and then start the clock once they are satisfied that you have done so. We went through exactly this process here recently. So they stopped the clock on a project in the middle of August. They restarted the clock at the end of October, which we feel great about, and so both of those sites, we think, are very active candidates for the first of these units. I’d say at this point, Altamira has a modest lead because they are a little bit further along in the process. But our goal really for next year would be to deploy assets in both sides. That would give us the most diversification of the company would allow for incremental units to be applied in addition to that. So that’s where it is. So I’d say right now, we would be the first one midyear in Altamira, second one later in the year in Louisiana.

Okay. And if it’s in Louisiana, if it’s a float or does that change the process at all?

We are really permitting both the floating rate, as well as the fixed platform in Louisiana. We expect to do both there. So either or, right? So I think as Chris laid out, we try to be very specific on this. We have got a pretty detailed view as to the calendar that goes on. So first one due out of the yard in March, second one in November and then every few months thereafter. So it gives us a lot of flexibility in terms of the nature of the infrastructure. Obviously, as we said before, the substance of the liquefiers are the same regardless of the marine infrastructure we install them on.

Okay. Perfect. And I think I get an extra one. But just real quick, any update on Ireland, it has been sort of on and off, but where does it stand at the moment?

Yeah. So we are in final review. Obviously, there’s been some dates that have previously been published by the permitting authorities in Ireland that have extended a bit. We think we are in a very good position there. There’s public comments now about the government supporting LNG and the security supply review that the government has gone through definitely recommends LNG and so we are working every day collaboratively to answer questions and do other things to kind of make sure our permit gets finalized here before the end of the year, but we are confident that it will happen. And that includes both the terminal and the 600 megawatts of power, which we want to make sure we are clear on as well.

All right. I appreciate, Wes and Andrew. Thanks for the time.

Yeah. Thanks, Ben.

We will now move to Sam Margolin with Wolfe Research.

Hey. Good morning, everybody. Thanks for taking the questions.

Hi.

You pointed out in the prepared remarks that you are converting operating margin to cash much more efficiently this year and that’s great. As you stand up FLNG production, some things change with like working capital needs and how the financials come in and out. Can you talk a little bit about how -- anything that needs to happen with respect to the balance sheet or liquidity to manage working capital positions as you become a major LNG producer?

Hey, Sam. It’s Chris. So short answer is, we don’t expect it to be a big working capital drain at all. In fact, like right now, we are buying LNG cargoes from the existing suppliers and prepay, that’s strictly a function of not being investment grade is common in the industry right now. When we start taking feed gas supply, what we have done is, the feed gas supply contracts that we will have in off of the sort of baseline from the CFE or in Louisiana will each be paid in arrears. And then in the case of Lakach, we actually are the people that are paying Pemex. So I expect that you will be able to be working capital positive in pretty short order. The actual turning on of the equipment, obviously, is not big spend, I mean, it’s labor and its power, which is functionally the cost of the feed gas that goes into the unit, so not expecting big drags at all. Importantly to note, I mean, we continue to upsize the revolver in the LC [ph] facility, which allow us a lot of flexibility, too. That’s cheap capital.

That’s fantastic. Thanks. And then just a follow-up. As you -- as the slides indicate, the forward curve of TTF fully supports like this margin view after 2025. A lot of LNG capacity perspective, capacity works at like a $15 margin, a lot less works at, say, like a $3 to $4 margin, but I think that yours does. And so the question is, as you advance this term business, how competitive do you really want to be against this competing capacity as you sort of advance this strategy to deliver energy to energy in covered places? Thanks.

Yeah. I mean, the -- one of the reasons we had Andrew go through in detail what the economics are on the power side and the dimensions of the power shortage in the world is to show what the long-term path of the company was. We started creating our own supply long before these are crisis and we did so in order to satisfy what we view as a virtually inexhaustible amount of demand on the other side of it. The margins that you realize there are significant. If you look at our margins of $8, $12, $15 and you compare them to the margins -- published margins of the large gas producers at $1 or $3, $4, $5, obviously, they are materially higher. They are materially higher because it’s harder. You have to build terminals. You have to build infrastructure. You have to build power plants. You have to supply operations for it. If it was easy to make high margins everybody would have them. So we have made a profound effort on the downstream side to solve people’s problems and knock would have done so pretty successfully. One of the other things I think that is actually is underestimated is that, one of the measures of how successful that has been is the credit profile of that downstream activity is tremendous. So we just lived through a global pandemic still feeling the effects of it in many parts of the world. We have the areas that we do business in, among the hardest hit economically and we do not have a single dollar of late payments from any of them. Mean the service that we provide is critical, and they have to have power. They have to have energy were the most affordable options they have gotten. So even though it is significantly more commitment on resource and on capital and on time and on personnel, the sum of all those things is you end up with the downstream portfolio that complements your upstream portfolio, you generate higher margins and you are solving real-world problems rather than just being a wholesaler. So we are a retailer, not a wholesaler at every level and that’s a big commitment that you can see very visibly now what the benefits are just in terms of the economics that drop to the bottomline, but also the credit attributes of it and also just the mission in which we are trying to accomplish things, so.

Thanks so much. Have great day.

Thanks.

Our next question will come from Sean Morgan with Evercore.

Hey, guys. So the DOE application for Altamira, I think, it’s interesting. It looks like you are going to be able to potentially source gas from Baja, Build [ph], which has been a bit of a holy grail for U.S. exports, because people kind of view that gas generally is lower priced than some of the Henry Hub guests where there’s a lot more export capacity kind of servicing off of that. So when you guys think about you have to transport this gas a little further, there’s a couple of pipelines evolve I believe in terms of getting the gas wellhead to jetty, where do you think that your sort of export costs play out relative to some of the existing competition in the U.S. Gulf?

We think that the bottomline is that our economics are fairly similar, whether that we actually produce LNG in Agua Dulce gas down in Altamira or off the Coast Louisiana. I mean there’s obviously basin differential, transport costs, personnel costs and the, like, there’s a whole host of different reasons. But at the end of the day, it’s actually highly competitive in one place versus the other. Big picture, 97% of the world’s LNG today is produced on land, 3% at sea. Obviously, with these five developments that we are building right now, we immediately jumped to the top of the list of being the world leader in actually producing these. There’s only 16 units that exist in the world today, we are producing an additional five. So that makes us the world leader. That IP, I think, is incredibly valuable. So, obviously, what we are doing in the first couple of installations, because we are using existing pipeline gas from the U.S., which that’s a ready source of gas, it’s good pricing, it’s reliable and that’s a terrific place to do business. The development that we are working on with Pemex will be the first time we actually buy gas directly from a productive well offshore. We think that the implications for that long-term are extraordinary. And we think that the IP in order to build the equipment actually operate in those conditions allows us to access truly stranded gas and that’s the next increment of incremental benefit to us that is out there. So it’s a step-by-step analysis, but the direct answer to your question is we think the economics are roughly the same. There could be a plus or minus on either side of it, but they are not that differential when you take into account both basin differential, as well as transport. But we think that the next leg of it would be to actually source actually true standard stranded gas and that could be incrementally a very, very different result.

Yeah. All right. That’s helpful, Wes. And just one quick follow-up on Altamira. So I think the application is looking for 2.1 and I think in last week, we talked about 1.4 export capacity in total. So the 2.1, is that just headroom in case you want to expand the Altamira project, and also, what’s the maximum that the existing pipeline infrastructure could sort of accommodate on a MTPA basis?

Heading -- this is Chris. So, yes, we want excess headroom, exactly right. The pipeline capacity is 2.6 B a day. We understand that there’s active discussions to expand that capacity to a little bit above 3. The public filings indicate that historical use on the pipeline is around 20%. So the -- what we are really doing here is solving a problem NFE has, which is helping them defray some of the costs of their firm transportation and then also being a partner with them as we market the LNG globally.

All right. Thanks, Chris. That’s it from me.

Thanks, Sean.

We will now move to Sam Burwell with Jefferies.

Hey. Good morning, guys. I wanted to hit on terminal sales and really the flexibility that you guys have to continue selling to third parties next year and I guess in 2024 as well, given that you have got some terminals that are due to come online? And sort of on that subject, slide 27, you mentioned seven terminals today, nine in 2024. So could you just run through what those seven are and then what the eighth one and ninth one would be?

I am happy you are talking about the terminals. You don’t talk about the kind of downstream opportunities.

Yeah.

So the seven terminals we are referencing are Old Harbour, Cammobay [ph], San Juan, La Paz, Puerto Sandino, Nicaragua, Barcarena, Santa Catarina. We expect to complete developments that we are in discussions on in Ireland and in South Africa, which takes us from the seventh to the ninth.

Yes. On the first question, we -- there’s a couple of contracts I think will come on here through 2023 Norsk Hydro and Barcarena being the big one. Not sure I totally understood the question, but we will continue to turn on those contracts. I think we are showing 130 TBtus of kind of run rate 2023 volumes. So we have got a little bit of a bridge between kind of where we are now and where we will end 2023 with Norsk Hydro being the big part of that.

Okay. That pretty much answers. Thanks. I guess the follow-up would be, on the MARAD process. I know you have talked about it in the prepared remarks and the Q&A already, but given your experience thus far, how it’s gone and what you have learned? How would you characterize the repeatability of the process and do you think it could be done more quickly going forward, because it strikes me that the U.S. Gulf of Mexico is probably a great place for you guys to scale up fast LNG beyond these first five units. So I am curious on your thoughts about that.

Well, the MARAD process involves a bunch of different agencies, right? And our interactions with them have been highly professional and very responsive. So we feel like they have done 100% of what they are obligated to do, both in letter and in script, and we feel great about that. When you look at what they have done historically, they have permitted, they are responsible for permitting all the fixed platforms in the Gulf, which is I don’t know what the actual number is, but it’s probably in the tens of thousands. So this is a very, very experienced group. And so what we are doing is really not that novel relative to what they have done. Obviously, the thing that is different is we are putting a liquefier on it. A liquefier has a power plant, because you need compression to turn that gas into LNG. So that’s that air permit is the one incremental difference, but it’s a modest difference and we feel their response has been entirely appropriate and engaged and very professional. And so with all that said, we obviously think it’s highly repeatable and there’s a variety of different locations that we have looked at, both in Louisiana, as well as in Texas, that would be logical places to have follow-on developments as and if this is successful, which we expect it to be, but it’s been great. And I think when the modular approach to building the liquefaction and putting it on existing marine infrastructure is, A, significantly cheaper and be significantly faster. And so when I referenced that 97%, 3% is the ratio of what it is today. I think it is very, very likely, i.e., 100% likely. That those numbers will shift over time, because this makes so much sense, not just for installations off the coast of the U.S. where it’s cheap and abundant gas. There is cheap and abundant gas all over the world. This allows us to go from one place to the other and cheaper and faster is simply better. So it’s great.

All right. Thanks very much. Appreciate the color.

And moving on to Martin Malloy with Johnson Rice.

Good morning. I have a question on zero. And I heard -- I’d like to get your thoughts about the offtake from that hydrogen facility and how you are thinking about the optionality. Obviously, there’s a lot of industrial load down in that area, but I believe Entergy also has a proposed power plant that’s pretty large. They can take hydrogen in and they have got some pipeline and underground storage assets as well. And also, I guess, related to that, how you are thinking about milestones in terms of scaling that up?

Yeah. Thanks, Marty. So you are absolutely right. There’s quite a bit of diversity in the offtake pool in the immediate vicinity. I am talking about literally within hundreds of feet and then within a couple of miles. So you are touching on the -- so the refining sort of community is the number I gave you before, which is 1,000 tons per day of hydrogen demand just among the three or four that are right there, and again, we are producing 50 tons. So as you can imagine, we are quite popular and a lot of folks looking at the 50 ton a day of green hydrogen, which is a pretty unique offering. We are also indeed working with Entergy on their needs in the region on the power side, the facility you are talking about is called Orange County Advanced Power Station, and they have a significant need over time as well. And then I mentioned the storage and the transportation. So you have things like Spindletop and a number of other existing pipeline networks to move the hydrogen kind of all around the region. So a lot of options for us and what we are trying to do basically is look at how to optimize that first phase. And then it’s -- the good news about electrolyzers is fairly straightforward to scale, because it’s just -- it’s largely a function of just adding units. So the first 120 will be 2024 and then we can add units thereafter as the demand picks up and there’s more of a need for green hydrogen in the region.

Yeah. I mean bottomline though is that you are producing hydrogen inclusive of the production credit is something close to zero.

Yeah.

And obviously, the economics of that are very powerful and people are willing to pay a market price for it. As Patrick said, the dimensions of what’s needed is vastly greater than what’s been produced. So this is, well, I think, it’s the upside in hydrogen production, green hydrogen production, blue hydrogen production, not just in the U.S. but across the world is immense. The fact is that today, it’s a hobby. It’s a relatively small part of the overall energy landscape. It’s something that I think is the Inflation Reduction Act actually provides capital to a number of different aspects of it, including the production of it, but also batteries, including carbon capture and storage. There’s a number of different aspects of it that are actually very powerful. And the demand, in my opinion, for green hydrogen is virtually inexhaustible period and we can do so at economic levels. And so this has gone from a business that is actually marginally profitable, but still something which would be interesting, something that is absolutely profitable and then could be expanded greatly. And so, but you can’t build a second until you built the first, and so that’s what we are very focused on right now. And then I think you hope for efficiencies across the entire landscape, so not just in the production of the hydrogen, but the transport of it, the utility of it, all the different aspects of it that actually will make this be something that’s not a hobby that actually does then put a material role in decarbonization.

Great. And my second question, I just wanted to try to get your thoughts on progress towards investment grade rating and do you think you will have to get a few of these fast LNG projects up and running before you are able to achieve that?

Well, if the rating agents are listening in and hope that they are, we think we should be investment grade now. I mean the cash flow generation and the conversion of EBITDA to free cash flow is significant and all seriousness. And the rate agents been great partners with us along the way. We have had a great dialogue with them, really post this earnings as we intend to go back and revisit with them. One thing that we want to get credit from the rating agencies, we want to get credit from the equity analysts and the investment community broadly is, the dimensions of the cash flow generation that we are about to experience are tremendous. I mean it’s not an overstatement to say when you look at the 500 companies in the S&P 500, there is a handful of those and maybe even none of those that actually generated $5 billion in EBITDA in their first 10 years of existence. And so we have an extraordinary opportunity as a company to produce a meaningful amount of cash flow and have done so largely without raising other people’s capital, it’s been internally generated. And so when rating agencies, when equity analysts, when investors look at our business, it’s not just the generation of the cash flow. The question is, can you do it without asking other people for money and that actually is a question that we can answer with a resounding, yes. When I say we have got a significant amount of cash on balance sheet which we do and we expect to generate a lot more. And the repeatability, the sustainability of it is, of course, that all of those three counterparties are very, very invested in. That’s why Andrew and others spent a lot of time looking at the long-term attributes, not just the short-term dislocation and the market opportunities there and the excess of cash flow that will generate, which we believe will happen. But also the long-term doing what we originally set out to do, which is basically to provide power and gas to power in a meaningful way to communities around the world that need it that is both doing well by doing good. So it’s obviously a very good business for us long-term. We are actually making a meaningful impact on the communities that we service. So those are all the considerations for it. My experience with the agencies is that it’s not an event, it’s a process and it’s doing consistently what you said you are going to do. And I feel like our report card, if you look back from the day that we went public until now is fairly unblemished that we have generally performed financially at or significantly better than what we said we were going to do. And I think they take those things into account and they tend to be followers. That’s the nature of the business on the rating side as opposed to leaders on it. But we feel very optimistic about our chances long-term.

Thank you.

We will now move to a question from Greg Lewis with BTIG.

Yeah. Thank you and good morning, everybody and realizing we are on the hour, I will just ask one question. Wes, as we think about the cadence surround the fast LNG and I guess right now, there’s seven MTPA on the Board. Clearly, you guys are seeing opportunity in the market, but would you keep going back to the bigger picture. As we think about the gating factor in terms of how big your FLNG solution can be, is the right way to think about it that eventually, we are going to hit a point where we are servicing our projects in the Caribbean, our projects in Brazil and elsewhere, i.e., is that kind of we are building these units with an eye on meeting our demand for these projects as we see them in the future or will we always be or do you see a scenario where you are always in a normalized environment down the road selling gas into the open market outside of your company’s end markets?

Yeah. That is actually a spectacular question and it’s -- I will tell you my perspective on it, but it’s not possible to really predict the future. We size our FLNG production initially to meet the demand that we saw visibly in the markets that we service. That said, we are servicing a fraction of what the actual needs are in places like Mexico or Brazil or South Africa or Ireland even. So the upside to just build the infrastructure and continue to grow organically in those markets is tremendous. Now the question longer term is when I addressed earlier is, what is the new normal when you are all done with this, and I think that, that’s obviously a debate, not an answer, and there’s a lot of different elements to it. The one thing I would say is that the downstream portfolio, we know that it’s a great addendum to the business because it provides duration. So when people talk about returns, they should also be talking about duration. I have sat across the desk as many of you have from 1 million people in my life have told me they could make 15% or 20% or some investment return. The reality is the people that can make 20% returns for 25 years, are named Warren Buffett and just a few others. So duration really matters and the duration that we get from these long-term portfolios is significantly valued. I think it’s undervalued, significantly so right now, by the way, both in terms of the quantum of the earnings that we have, as well as the complete durability about them. One other thing that is actually underestimated in my opinion is that the flexibility that is granted to you when you actually enter in these long-term contracts is significant. And what I mean by that is the world chronically under nominates the amount of gas and power that they need. I think it’s actually a human characteristic and so this is not something specific to developing countries. I would say the same thing happened across Europe, where countries basically knew that they needed significant amounts of supply to meet their needs. They under nominated and they always just assume that they would be able to buy more on the margin on spot when they needed it. That actually incremental demand is one that in the normal market just becomes more demand at the same price. In an extraordinary period, what it does is it basically allows you to have excess supply to then actually take advantage of it in the market. So it’s a nuance, but it’s a very, very significant one. But we believe deeply that the combination of the upstream, the supply downstream, which is the demand. Those two things together are not only good business partners, they are actually necessary if you are really going to manage the business properly and the margins that you generate then are markedly different. If you go back and look at any of the other gas producers across the entire spectrum, they have great businesses, but they do a thing typically. They produce gas, they either ship gas or perhaps some of them actually use gas in different installations, no one does it in the same way that we do it. And I think that the economics of it and the margins that we generate are testimony to the fact that the reason why that’s such a good thing to consider. So it’s a long answer to your short question, but I appreciate it. Thank you. Very good one.

Jake, I think given that we are at the top of the hour. This is Patrick. We would like to maybe close the call. I suspect we might still have more questions. So by all means for those who may not have gotten their questions answered, please feel free to reach out to me. So, Jake, if you could close down the call that would be great.