New Fortress Energy Inc.

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 and 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 Junta, our Chief Financial Officer, Andrew Deedy, Managing Director, responsible for commercial activities, as well as several other members of our team. With that, I'll turn the call over to Wes.

Great. Thanks, Patrick. And thanks, everyone, for calling in this morning. So as usual, I'm going to refer to the investor deck that we posted here this morning. So if you could pull it up and follow along, that'd 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 the Q3 a year ago, about $170 million, and just in general on a financial basis was actually 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'm 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 to introduce them to the very talented team of people that we've got that's 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'll talk about that specifically. Long term, our mission to provide power to the places in the world that need it most is very much the mission of the company. And the problems and the dislocations in the world that we've seen in Europe in particular have only exacerbated the needs that people have. So we'll 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 and 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 in 2022, 161 as FLNG volumes kick in, in particular in the second half of 2023. Lots and lots of different adjustments in this business. 50 TBTUs equals about 1 million tons of gas, so about a million and a half tons last year, closing in on 2 million tons this year, and then 161, so we're actually making a big upward adjustment next year. But then follow over to the right, you can see what our expectations are for the rest of our FLNG volumes in 2024 and 2025, and you can see a fairly profound shift to the right in terms of the volume. 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 the margins, that equals adjusted EBITDA. So it 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. Our forecasted EBITDA $2.5 billion in EBITDA results in a 1553. 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're obviously very focused on is not the short term, but the long term. And so 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, and $15, you end up with illustrative EBITDAs in those years, ranging from $3.3 billion on the low, low side in 2024 to $6.96 billion on the high side and the other side. Now, this all assumes that the amount of supply that we have in our inventory equals what we've already effectively committed to. Obviously, we think that there are 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 for 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've got across the company, we expect to generate five plus billion dollars 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 or deleveraging the company and buying back stock or some combination of all 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 what 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 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 balance sheet and capital structure. It's the old proverbial measure twice, cut once situation when you're 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're 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'll 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 it talks a lot about what the situation is in the world today. When you look outside the yellow box to the left, you 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 you start to get the dislocation here, you'll see the timeframe for that actually occurring is July of 21. So a full nine months before actually the Russian invasion, you start 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 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 at 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'll end up in a higher place overall. But that obviously has a big impact on margins in the business, margins for us, and it 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, you know, the other thing I would 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. And we'll 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 nonetheless. Let me turn it over to Chris. Chris?

Yeah, good morning. Thanks, Wes. Let me direct you to slide number nine, and I'll update you on our LNG supply portfolio and what we're 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 this year, will be 114 in 2023 through 2025. When you layer on FLNG volumes, we have an additional 350 TBTU, or approximately seven 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 FLNG. As you know and many of you attended, we hosted an investor and an analyst event last week in Kiewich Shipyard in Corpus Christi, and it was a great opportunity for us to give investors a glimpse at the progress we have made. As we mentioned on site, nothing that we're 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're making excellent progress on FLNG number one 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've made huge progress in the deployment options, including permits, for our various locations, which we'll outline in a couple 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 assembled the modules that will be lifted onto the Jacob rigs. Module 1 for gas treatment goes on the first rig. Module 2 for liquefaction goes onto the second rig. And then we'll have one smaller module for utilities and accommodations that goes onto the third rig. Each of these large modules will be four to seven levels high, and when completed will weigh over 5,000 tons. Below is a picture of the jack-up rigs where the modules will be installed. We've completed the demolition and are nearing the completion of the hull strengthening and enhancements to the foundation, as well as a complete overhaul and upgrade of the marine systems. Further, we're in the middle of preparing for deployment and operations once the efflungy construction has been completed. We've 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're doing things to have all subsea tie-ins, pipeway, mooring, riser work completed in order to ensure that once the effluent 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've talked about these locations before, but we've expanded our FLNG options to deployment to three different spots, which could accommodate up to six FLNG units. As Wes mentioned, we were in Mexico City for another meeting with President Lopez Obrador and the director of the CFE, where we signed binding documents to deploy up to three units at Altamira. This would utilize US feed gas molecules transported into Mexican waters via the Cerro de Tejas pipeline. We've 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 MERAD 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 stop clock order was lifted on October the 28th. and we expect the 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 LaCache field. NFE will complete seven wells and then begin producing in summer 2024. We'll send approximately a third of the gas to shore for Pemex to use, and the remaining two-thirds will be used as feed gas for our FLNG-4, which will use the Savan semi-submersible drill ship. We really like this model, which captures proven but undeveloped and stranded gas reserves and sends a portion to shore and the remainder to NFE for feed gas to turn into LNG. Turn, please, to slide number 12. Wes talked about this page last week in Corpus, but this provides a roadmap of which units we're building, where they're being built, and when they're expected to be complete. The page shows the mechanical completion dates for each of the units, and then it takes between two 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 timeline and the marine infrastructure make ready down to about 12 to 14 months. To mobilize, hook up, and install is about a two to three month process. The commissioning is one to two months. And all told, we can be done on future units in 18 to 20 months from FID to COD. Further, we've already ordered all of the critical or long lead items for each FLNG units one through four. And obviously, we're 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, Trelleborg for marine equipment, et cetera. So in conclusion, you can see our supply of LNG is growing rapidly over the next two years. This 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'll 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 Alap 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 onto them. And in my role on the commercial side, you know, a very important moment for us. So as Chris just went through NFE, it's creating seven MTPA of new volumes in the short term. So That takes our total portfolio up from about 2 to 2.5 MTPA to 9.5 MTPA, which, as Chris showed, is 464 TBTUs by 2024 on a run rate basis. So I'm 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'll see is that the strategy is generally in line with the same core mission NFV'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're showing really is an energy density chart of the world. So the tagline is 70% of the world's 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 of NFP know, Jamaica consumes about a 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're showing is that in the first time of 20 years of collecting data on access to electricity, they're 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 RLNG supply with power production, we can achieve differentiated sustainable margins over the long term. I want to give some insight today on how we're going to do that. So flipping to page 15, NFV really is an integrated power company today. We've 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've done as we dimension and assess the opportunity going forward. Selling power is truly a downstream business. We're integrated all the way down to the consumer, and now we're adding supply to effectively close that loop, and we're going to do more power. Power provides a basic necessity in 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 once 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've been paid on time in all of these jurisdictions. So 90% of the operational volumes today at NFE are power-related. And the over 3,000 megawatts that we've been either a supplier or an owner of is really going to speak to what we're 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're going to be on a run rate basis in 2024. 130 of that will be spoken for on current contracts, and 334 of that will be new supply. Roughly, you know, we kind of use a rule of thumb that for every 10 TBTUs, that's about 100 megawatts. And so that 334 TBTUs translates to about, you know, 3,300 megawatts of new power demand that we're going to fill with our LNG supply. On the right side, we're already in development on 1,700 of those megawatts. That's the power plant in Barcarina, 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 that's 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've done before, and we're 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 try to dimension it from a margin perspective. So When we think about power, we really think about kind of selling long-term power under PPA at competitive rates. That starts me on kind of the left side of this page, which is 12.5 cents for 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 a return on capex. The difference between what it costs to build and what the value of the plant is, that's roughly around 2.5 cents. So what we see long-term for 100 megawatts of simple cycle power is is we can sell power for an all-in rate of about 15 cents 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 per 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're looping back to our margin page that we showed earlier to show As we get to our goals of 464 TBTUs, run rate 24-25, at $10 a margin, that's $4.6 billion of margin. And so this really is in line with what we've done in the past and what we're 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 it'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've actually been doing a ton of detailed modeling about 2023 gas balances in Europe. And for those of you who follow this, 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 there 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 continue to be short. And the price graph on the right, which is the one we showed previously, which is the one we all carry around in our pocket today, is really the short-term opportunity. So we're building a long position into this opportunity that we're going to turn out over time with integrated LNG to power. Page 19 goes a little bit farther 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're 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 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 a basis to the TTF price. Now, the great thing for us that is very different from most of NFE's life is we've got two things. We've got existing infrastructure, and we've 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're creating new capacity, which we highlighted here, which is the M7 terminal in the Netherlands, which we partnered with Gassoneon and is the first new terminal to turn online since the Russian invasion. There'll 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're looking at the long-term opportunity and how we're going to deploy all these FLNG volumes, and I look forward to talking more. Thank you.

Thanks, Andrew. I'm on slide 21. We're just going to spend a few minutes talking about hydrogen. So I guess I'd start by saying we continue to make significant progress with the hydrogen business, what we're calling zero, during the third quarter. And as Wes has said many times, we're 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're also seeing actually, especially in recent months, is 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're 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've talked to you about in past quarters, and then we'll step through a few other items before I turn the call back over to Chris. So we're proud to be a really true first mover advantage in the space with our first industrial scale green hydrogen plant in Beaumont, Texas. We're building 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 US 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 fence 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. Again, we're producing 50 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 regions. 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're the manufacturer of essentially the machines that make the hydrogen. The first of these units will show up at our site in 2023 and 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've 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're also looking at other areas of potential collaboration with them. So now on to slide 22. As it turns out, the US 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're 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're 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're 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've continued to put all the pieces together for Beaumont, and we've learned a lot. We're 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're needed. So we're 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're building really the leading industrial-scale clean hydrogen business, and our platform initially is expected to be the equivalent of five Beaumonts. 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'll 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'll quickly run us through the financial forms 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 from the quarter, $86 million, which is about $0.41 per share when excluding one-time 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's saying we can do long-term. Henry Hub averaged $830, which is obviously a pass-through, but did have an effect both on revenue and costs over the period. Move to slide 26. We're showing a side-by-side of the balance sheet as it's 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've executed on our promise to monetize over $2 billion worth of assets, which fully funds our growth initiatives. We've simplified the corporate debt to just two tranches of bonds at 6.75% and 6.5% respectively. We also have a $440 million revolver and a $250 million letter of credit facility, which provide us access to low-cost, flexible capital as needed. It's currently undrawn, given our cash position. And last, 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've 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 three times. As you can see on the graph at the bottom left, deleveraging is rapid as each FLNG unit comes online. We will be under two times leverage with our first FLNG asset and below one times once the second one comes online later next year. 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 shut down activity while hurricanes approached facilities this fall, and that 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'll turn the call back over to Patrick.

Thanks, Chris. So, Jake, I think we're ready to take a couple of questions, so if you could...

explain the instructions to the callers that would be great of course ladies and gentlemen if you would like to ask a question please signal by pressing star 1 on your telephone keypad keep in mind if you are using your speakerphone make sure the mute is released to allow that signal to reach our equipment once again star 1 for questions we'll pause for just a moment to allow everyone an opportunity to signal 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 Altamira is first in line for the jackups, and I guess that would mean that the 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 timelines or anything like that?

Hey, Ben, it's Wes. Good to see you last week. As Chris said, we signed agreements with the governor 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 a lot of certainty that, you know, when I 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, many different opportunities we have down there. Second, with respect to MARAD, we have a very engaged process with them. You know, 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're satisfied that you've done so. And we went through exactly this process here recently. So they stopped the clock on our 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're 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 as a company. It 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 mid-year in Altamira, second one later in the year in Louisiana.

Okay. And if it's in Louisiana, if it's a floater, does that change the process at all?

We're 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've got to 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 that we install them on.

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

Yep, so we're 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're working every day collaboratively to answer questions and, you know, do other things to kind of make sure our permit gets finalized here before the end of the year, but we're confident that it will happen. And that includes both the terminal and the 600 megawatts of power, which we want to make sure we're clear on as well.

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

We'll now move to Sam Margolin with Wolf Research.

Hey, good morning, everybody. Thanks for taking the questions. You pointed out in the prepared remarks that you're converting operating margin to cash much more efficiently this year, and that's great. As you stand up FLNG production, some things change with working capital needs and how the financials come in and out. Can you talk a little bit about 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 the short answer is we don't expect it to be a big working capital drain at all. In fact, like right now, we're buying LNG cargos from the existing suppliers in prepay. That's strictly a function of not being investment grade, as is common in the industry right now. When we start taking feed gas supply, what we've done is the feed gas supply contracts that we'll have in off of the certification line from the CFE, or in Louisiana, will each be paid in arrears. And then in the case of LaCache, we actually have the people that are paying PEMEX. So I expect that you'll 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 it's power, which is functionally a 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 and the LC facility, which allows a lot of flexibility, too. That's cheap capital.

That's fantastic. Thanks. And then just a follow-up, you know, as the slides indicate, the forward curve of TTF, you know, fully supports, like, this margin view out to 2025. A lot of LNG capacity, prospective capacity works at, like, a $15 margin 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-impoverished places? Thanks.

Yeah, I mean, 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 there was a 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 published margins of the large gas producers at $1, $3, $4, $5, obviously they're materially higher. They're 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, you know, we've made a profound effort on the downstream side to solve people's problems, and NOC would have done so pretty successfully. You know, one of the other things I think that is actually – is underestimated is that one of the measures of how successful it 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 were among the hardest hit economically, and we do not have a single dollar of late payments for any of them. I mean, the service that we provide is critical, and they have to have power, they have to have energy, We're the most affordable options they've got. And 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 a downstream portfolio that complements your upstream portfolio. You generate higher margins, and you're 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, not just in terms of economics that dropped to the bottom line, but also the credit attributes of it and also just the mission in which we're trying to accomplish things.

Thanks so much. Have a 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're going to be able to potentially source gas from Agua Dolce, which has been a bit of a holy grail for U.S. exports because people kind of view that gas generally as lower price than some of the Henry Hub gas, 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 involved, I believe, In terms of getting the gas wellhead to Jetty, you know, where do you think that your sort of export costs play out relative to some of the existing competition in the U.S. Gulf?

You know, we think that the bottom line is that our economics are fairly similar, whether we actually produce LNG and Agua Dulce gas down in Altamira or off the coast of Louisiana. I mean, there's obviously, you know, basin differential, transport costs, you know, 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 at actually producing these. There's only six units that exist in the world today. We're producing an additional five. So that makes us the world leader. That IP, I think, is incredibly valuable. So obviously what we're doing, the first couple of installations is we're 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're 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 it 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. 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 a minus on either side of it, but they're 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 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. I think the application is looking for 2.1, and I think last week we talked about 1.4 export capacity 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 an MTPA basis?

Hitting this, Chris. So, yes, we want to access headroom. That's 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 three. The public filings indicate that historical use on the pipeline is around 20%. So what we're really doing here is solving a problem CFP 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 for me.

Thanks, man. We'll 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've got some terminals that are due to come online. And sort of on that subject, slide 27, you mentioned seven terminals today. in 2024. So could you just run through what those seven are and then what the eighth one and ninth one would be?

I'm happy to talk about the terminals. Do you want to talk about the kind of downstream opportunities? Sure. So the seven terminals we're referencing are Old Harbor, MoBay, San Juan, La Paz, Puerto Sandino, Nicaragua, Bacarena, Santa Catarina. We expect to complete developments that we're in discussions on in Ireland and in South Africa, which takes us from the 7th to the 9th.

Yeah. On the first question, you know, we – you know, there's a couple contracts I think will come on here, you know, through 23, Norse Hydro and Baccarina being the big one. Not sure I totally understood the question, but, you know, we – We'll continue to turn on, you know, those contracts. I think we're showing 130 TPTUs of kind of run rate 2023 volumes. So we've got a little bit of a bridge between kind of where we are now and where we'll end 2023 with Norse Chydra being the big part of that.

Okay, that pretty much answers things. I guess the follow-up would be on the merit process, I know you've talked about it, the prepared marks and the Q&A already, but given your experience thus far, how it's gone and what you've 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 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. You know, when you look at what they have done historically, they have permitted, they're 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're doing is really not that novel relative to what they have done. Obviously, the thing that is different is we're putting a liquefier on it. A liquefier has a power plant because you need compression to turn that gas into LNG. So that's the that air permit is the one incremental difference, but it's a modest difference. And we feel that 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. You know, the modular approach to building the liquefaction and putting it on existing marine infrastructure is A, significantly cheaper, and B, significantly faster. And so when I reference that 97-3 as 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 there's cheap and abundant gas, There's cheap and abundant gas all over the world, and so 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 call.

Moving on to Martin Malloy with Johnson & Rice. Good morning.

I have a question on Xero, and I'd like to get your thoughts about the off-takes. from that hydrogen facility and how you're 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've got some pipeline and underground storage assets as well. And also, I guess, related to that, how you're thinking about milestones in terms of scaling that up.

Yeah, thanks, Marty. So you're absolutely right. There's quite a bit of diversity in the offtake pool in the immediate vicinity. I'm talking about literally within hundreds of feet and then within a couple of miles. So you're touching on 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're producing 50. So as you can Imagine that we're quite popular and a lot of folks looking at the 50 tons 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're 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're trying to do basically is look at how to optimize that first phase, and then it's – The good news about electrolyzers is it's fairly straightforward to scale because 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 bottom line though is that you're producing hydrogen inclusive of the production credit is something close to zero. And obviously the economics of that are very powerful and people are willing to pay a market price for it. You know, as Patrick said, the dimensions of what's needed is vastly greater than what's being produced. So this is, you know, well I think it's, you know, 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 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 today. 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 to something that is absolutely profitable and then could be expanded greatly. And so, but you can't build a second until you've built the first. And so that's what we're very focused on right now. And then I think you hope for efficiencies across the entire landscapes and 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 play a material role in decarbonization.

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

Well, if the rating agencies are listening in, and I hope that they are, we think we should be investing right now. I mean, you know, the cash flow generation and the conversion of EBITDA to free cash flow is significant in all seriousness, and the rating agencies have been great partners with us along the way. We've 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 that 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, you know, the 500 companies and 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've 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, what all of those three counterparties are very, very vested 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 excessive 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 a doing well by doing good. So it's obviously a very good business for us long term. We're 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 were going to do. And I feel like our report card, if you look back from the day that we were in 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'll now move to a question from Greg Lewis with BTIG.

Yeah, thank you, and good morning, everybody. And realizing we're on the hour, I'll just ask one question. You know, Wes, as we think about – the cadence around the fast LNG, and I guess right now there's seven MTPA on the board. Clearly, you guys see an opportunity in the market, but we 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're going to hit a point where we're servicing you know, our projects in the Caribbean, our projects in Brazil and elsewhere, i.e., is that kind of we're building, you know, 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're always in a normalized environment down the road selling gas into the open market outside of your companies and markets?

Yeah, that is actually a spectacular question. And I'll tell you my perspective on it, but it's not possible to really predict the future. You know, we sized our FLNG production initially to meet the demand that we saw visibly in the markets that we service. That said, we're 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 one I addressed earlier is what is the new normal when you're 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've sat across the desk, as many of you have, from a million people in my life who 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 valuable. 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 of both of them. One other thing that is actually underestimated, in my opinion, is that the flexibility that is granted to you when you actually enter into 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 assumed that they would be able to buy more on the margin, on the 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 marketplace. It's a nuance, but it's a very, very significant one. But we believe deeply that the combination of the upstream supply, the downstream, which is the demand, those two things together are not only good business partners, but they are actually necessary if you're 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, the margins we generate, are testimony to the fact that there are reasons why that's such a good thing to consider. So it's a long answer to your short question, but I appreciate it. I think it's a very good one.

Jake, I think given that we're at the top of the hour, this is Patrick, we'd 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.

Of course, ladies and gentlemen, this does conclude your conference for today. We do thank you for your participation, and you may now disconnect.