Good day, and welcome to the Cheniere Energy Inc. Second Quarter 2021 Earnings Call and Webcast. Today’s conference is being recorded. At this time, I would turn the conference over to Randy Bhatia, Vice President of Investor Relations. Please, go ahead.

Thank you, operator. Good morning, everyone, and welcome to Cheniere’s second quarter 2021 earnings conference call. The slide presentation and access to the webcast for today’s call are available at cheniere.com. Joining me this morning are Jack Fusco, Cheniere’s President and CEO; Anatol Feygin, Executive Vice President and Chief Commercial Officer; and Zach Davis, Senior Vice President and CFO. Before we begin, I would like to remind all listeners that our remarks, including answers to your questions may contain forward-looking statements. And actual results could differ materially from what is described in these statements. Slide 2 of our presentation contains a discussion of those forward-looking statements and associated risks. In addition, we may include references to certain non-GAAP financial measures, such as consolidated adjusted EBITDA and distributable cash flow. A reconciliation of these measures to the most comparable GAAP measure can be found in the appendix to the slide presentation. As part of our discussion of Cheniere’s results, today’s call may also include selected financial information and results for Cheniere Energy Partners LP or CQP. We do not intend to cover CQP’s results separately from those of Cheniere Energy Inc. The call agenda is shown on Slide 3. Jack will begin with operating and financial highlights, Anatol will then provide an update on the LNG market and Zach will review our financial results and guidance. After prepared remarks, we will open the call for Q&A. I’ll now turn the call over to Jack Fusco, Cheniere’s President and CEO.

Thank you, Randy, and good morning, everyone. Thanks for joining us today and thank you for your continued support at Cheniere. I’m pleased to be here this morning to review our results from the second quarter and our increased financial guidance for the full year of 2021. Please turn to Slide 5, where I will review some key operational financial highlights from the second quarter. The second quarter was an extremely productive one for us. As we achieved milestones across the enterprise and origination, marketing, operations and engineering and construction just to name a few. Global LNG market fundamentals continue to be extremely constructive and we have begun to see the return of long-term LNG contracts in support of the construction of new liquefaction capacity. For the second quarter, we generated consolidated adjusted EBITDA of $1.023 billion and distributable cash flow of approximately $340 million on revenue of over $3 billion. We generated a net loss of approximately $329 million due primarily to the unrealized derivative accounting treatment required on our hedges and on our integrated production marketing or IPM transactions, which is Zach will discuss in more detail in a few minutes. For the third consecutive quarter, we’re raising our full year 2021 financial guidance. We now forecast 2021 consolidated adjusted EBITDA of $4.6 billion to $4.9 billion and distributable cash flow of $1.8 billion to $2.1 billion. This increase in guidance is being driven by a number of factors. First, the continued strengthening of the LNG market is yielding higher net backs unopened volumes. For context, since our first quarter earnings call in May spot margins for 2021 doubled and our portfolio optimization team has been able to capitalize on that with our open volumes. In addition, we’ve been able to further unlock some additional production for the…

Thanks, Jack, and good morning, everyone. Please turn to Slide 9. Globally, the pace of recovery in LNG markets from the COVID-related lows has exceeded most expectations, especially when looking at demand growth in the fourth quarter of 2020 through the first quarter of 2021. This trend continued in the second quarter with not only meaningful growth over the same period in 2020, but also notably well above the five-year range, supporting our constructive market views on 2021 and subsequent years. We continue to see a fundamentally tight market over the next several years, breaking the trend for seasonal demand norms, even with rebounding LNG supply. As reflected by the historically high LNG prices in both Europe and Asia markets remain tight through this past winter with global LNG demand growing by 9% year-over-year in the second quarter, slightly surpassing the fourth quarter demand levels, despite the second quarter, historically being a shoulder period in the market. Asia and Europe exited spring with sizable storage deficits as the cold winter in Asia and the colder than normal spring in Europe intensified the inter basin competition for LNG supply. Asia and Europe’s robust demand plus spreads between the two regions to narrow, but European net backs even surpassing those in Asia in order to attract the imports amid insufficient LNG supply availability in Q2. Global LNG production rebounded 8% year-over-year in Q2, primarily on U.S. volume growing 80% compared to last year when customers were exercising their cargo cancellation rights. Through the first half of the year, U.S. LNG production is up 43% year-over-year, approximately 35 million tons. However, non-U.S. volumes have lag more than expected during most of 2021 so far and remain below 2020 levels in June. These non-U.S. volumes were impacted by feed gas constraints in Trinidad and…

Thanks, Anatol, and good morning, everyone. I’m pleased to be here today to review our second quarter financial results and our increased full year 2021 guidance. Turning to Slide 13. For the second quarter, we generated revenue of approximately $3 billion, consolidated adjusted EBITDA of approximately $1 billion and distributable cash flow of approximately $340 million, and a net loss of $329 million. As Jack mentioned, our results for the quarter were negatively impacted by the accounting treatment for our derivative instruments, which includes our IPM agreements. As we have discussed in prior quarters, our IPM agreements, certain gas supply agreements, and certain forward sales of LNG qualify as derivatives and require mark-to-market accounting, meaning that from period to period, we will experience gains and losses as movements occur in the underlying forward commodity curves. This accounting treatment coupled with significant volumes, long-term duration and volatility in price basis for certain contracts. Most notably, our IPM agreements will result in fluctuations in fair market value from period-of-period. While operationally, we seek to eliminate commodity risk by matching our natural gas purchases and LNG sales on the same pricing index. Our long-term LNG SPAs do not currently qualify from mark-to-market accounting, meaning that the fair market value impact of only one side of the transaction is often recognized on our financial statements until the sale of LNG occurs. The unfavorable pretax impact from changes in the fair value of our commodity and FX derivatives during second quarter of 2021 was approximately $672 million. Most of which was non-cash, but was the primary driver of our recognized net loss for the second quarter. For the second quarter, we recognized in income 522 TBtu of physical LNG, including 508 TBtu from our projects and 14 TBtu from third-parties. Approximately 80% of these LNG…

Thank you. [Operator Instructions] Our first question comes from Michael Lapides from Goldman Sachs. Please go ahead.

Hey guys. Thank you for taking my question. Congrats on a really good first half of the year so far. Just one maybe for Anatol, just two things. One, how are you thinking about the changes in contract structures that you’re seeing in the market, meaning we’ve seen some other North American LNG players announced deals that are priced at basically a sliding scale tied to JKM. Just curious when you’re thinking about what the market is going to do for new contracts, is your thought that it’s still an SPA driven kind of fixed fee driven type of market. Or do you think it’s going to go to more of a variable type fee structure for future deals?

Thanks, Michael. Good morning. Yes. In short, the market is growing maturing and we expect to see all of the above in greater quantities. We’re in the camp that the traditional SPAs long-term are part and parcel of this business and is required for us, for example, to commit capital. And we think that our commercial creativity is one of our main calling cards, right? We introduced the IPM business now over two years ago, and that’s a business where the producer gets exposure to those international indices, we collect our fixed fee and the producer passes allows for that commodity exposure to their underlying resource. So we think all of this stuff is part and parcel of the business going forward. You’ll see traditional SPAs and you’ll see as we mentioned, a lot more midterm business from us that we’ve been so successful with since we launched it less than a year ago.

Got it. And then one quick follow up on Stage 3, just curious, how much more do you think you need to contract before you think you’re getting close to FID?

Hey, Michael, I just wanted to add a little bit to Anatol answer to your question, and then we’ll talk about Stage 3. So I would say, we’re in the catbird seat, we have a great position. We’re able to offer solutions for customers. We’ve been very successful on offering short-term, mid-term contracts to those customers that want those that don’t use to grow the business. We’re not in the FID business, we’re in the making money business. So we’re staying extremely financially disciplined on our next expansion project, just like we have on the first nine. But I’ll turn it over to Zach to talk in more specifics on Stage 3.

Sure. Hey, Michael. So I’ll just start off the saying last November, Jack mentioned that we were around 85% contracted and at this point we’re 90% with all the work that the marketing team has done. And when you think about 90% on a 45 million ton book, that’s a little over 40 million ton, our contracted at this point. So we’re actually pretty darn close to considering a FID of Stage 3 and why we’re so confident about doing that next year. But as noted, as Jack mentioned, it’s all about our discipline approach to just major capital investments, meaning it’s not just about the volume, but about the returns on both the levered and unlevered basis from a highly contracted cash flow. So that when we thanks in a project, it’s value and credit accretive and the very, very best use of our cash. But with that all in mind, it is around, let’s say, four or so mtpa of additional contracting to underpin all of Stage 3, ensure our run rate contracted capacity remains in that 80% to 90% range, even at FID. And of course all the investment parameters are met. So again, we’re pretty confident that a 2022 could be a big year for us.

Got it. Thank you guys. Much appreciate it.

The next question comes from [indiscernible] from UBS. Please go ahead.

Hi, good morning, everyone. This is Brian on for Shneur. Appreciate all the color on the $300 million guidance range. Just curious if you could provide a little bit more color on the changes between 1Q and 2Q guidance. In your prepared remarks, you talked about the maintenance optimization and it was just kind of curious how much capacity Cheniere was actually able to free up at these attractive spot margins. I know you talk about a dollar change in marketing margin equals 25 and even an impact book was just kind of curious if you could provide a little bit more color behind, all of the drivers in the guidance range of $300 million. Thanks.

Well, thanks, Brian. And I have to say I’m so pleased with our operations and maintenance personnel and our ability to optimize our maintenance schedules and take advantage of what seems to be a very high price LNG market right now. But as far as the details of how it breaks down, I’ll turn that over to Zach.

Hey, Brian. So the $300 million upward move in guidance is pretty simple. It’s three things. it’s higher net backs, a bit more production and better lifting margin, but to be clear higher margins on the open capacity and some additional production where the vast majority of the guidance rage. So with the dramatic rise in CMI netbacks since early May from literally just under three bucks to over $6 today for the rest of the year. And with that 40 CBQ previously open that added almost 150 million of that raise. Then combine that with another, let’s say, four or so cargoes from opportunistically managing maintenance for the rest of the year to take advantage of these current market conditions. And that added alone another $100 million. And the rest with just higher Henry Hub prices for the rest of the year, as we expect to literally lift every last drop of LNG, lifting margin made up most of the rest. And that simply gets you $300 million or so.

Great appreciate all that color. Maybe to pivot capital allocation and just to follow up on CCL Stage 3, seems to suggest that you’re close to FID at this point, if you can get the necessary contracts, just in the overall scheme of things, with the desire to become IgE and with the recent positive outlooks of the credit agencies. How does growth and leverage reduction and effectively impact your desire around buybacks and a definite dividend initiation at this point? Thanks.

Sure. I mean, put it this way. We’re going to have $3 billion of BCF per year, and now with how the markets have improved and the curves have improved around $13 billion of available cash through 2025. And the equity check for something like Stage 3, which let’s say it’s around the mid-$3 billion range for the whole thing, is only about 800 million per year, once funded 50-50 with debt and equity, pro rata over time. So as you can see in the results, we’re pretty much at a point in our life cycle, where we can undertake the project with the scale of Stage 3 and not be limited whatsoever from also meeting all of our balance sheet and shareholder capital return goals over the coming years. So nothing’s really holding us back at this point.

Great. Appreciate the color and congrats on the quarter. Have a good day.

Our next question comes from Jeremy Tonet from JP Morgan. Please go ahead.

Hi, good morning.

Good morning, Jeremy.

Just wanted to pick up with the market outlook a little bit more. Second quarter last year, spot LNG, couple of bucks now LNG prices comfortably trading above a high teens for winter and seasonally high spot rates right now. And I’m just kind of wondering based on carbon prices and structural demand shift. How do you think about, I guess, the pricing dynamic today, has it changed or where do you see us in the cycle? And I guess, how that could impact, I guess, appetite for contract contracting?

Well, I’ll start and I’ll hand it over to Anatol. The increased volatility and the higher prices just bring more and more customers to want to lock in their energy costs naturally and reduce the volatility to their customer base. So as you know, Jeremy, we focused on selling to end users, we sell most of our product to utilities around the world and they need it. And as more and more of these countries, try to meet their climate goals and clean up their air, especially in and around Asia, you’re seeing the demand for that gas and the demand for LNG rise, fairly significantly and much greater than what was in any of our models initially, but I’ll turn it over to Anatol.

Yes. Thanks, Jack. Thanks, Jeremy. We’ve been fairly bullish on the markets in the first half of this decade and saw 2021 as a transition year, as we’ve touched on previous calls that transitioned faster than we expected, kind of across the board. Asia’s rebound and demand growth and all of this investment that we saw on gas infrastructure and LNG infrastructure and demand is playing out arguably faster than we expected. And in the aggregate, U.S. came to the rescue second half of last year and the first half of this year with additional volumes, but now everything is online obviously. We and everyone else are trying as hard as possible to bring this volume to market. And the market is still tight, right. Demand exceeded supply in Q2, which is why you saw the storage dynamics and the pricing dynamics that you mentioned. And we are only entering this phase of the market, as Jack said, this is the first time that in its tenure at Cheniere that is in the both part of the cycle for the sellers and long-term and mid-term commitments are accelerating as a result, right. It’s not a surprise to anyone that this is playing out, but it is playing out a little bit faster. And Zach mentioned our comfort level with 2022 is that much higher. The other important component that you touched on, on the carbon side, and this is why the journey to get this LCA product out that that we announced this morning was so important. We are highly confident that we have a very low profile, low emissions profile product that will be a major contributor to emissions reductions in Europe, Asia, and everywhere that, that we structurally deliver our product into. So there’s a mention of a case study in there that shows that our product reduces emissions by about 50% when displacing coal in China. And that is a great starting point on this journey that that we’ve announced this morning. So very optimistic about the structure of the market and our ability to offer these solutions both economically and environmentally.

Got it. So it seems like price of carbon could lift the LNG market maybe there. And maybe just kind of building on that last point a bit more, you announced this collaboration with natural gas suppliers and academic institutions to improve emissions monitoring. Just wondering what you’re learning here. I think you’ve touched on some of the points here, but just wondering, it seems like the market is going in this direction. Do you see any other kind of low-hanging fruit for Cheniere here? Some that are looking to compete with you have introduced CCUS strategies. Do you think that’s where the market’s going overall?

Look, I think the pathway to the energy transition is a very, very long road and it’s going to need some of everything, a lot of everything, that, that, that we can develop today and 20 years from now. We embarked upon the journey back in 2018. We’ve spent well over the last three years working on a company specific lifecycle analysis in LCA that we published recently with American society of chemical engineers, but it’s not – we’re – our program has been very thoughtful and very forward thinking, and we’re hoping to lead the industry into ensuring that our product is viewed as a sustainable provider of cleaner energy for the world. So that’s what it’s all leading to the life cycle analysis is extremely important for us to be able to produce our cargo emission tags or our carbon footprint per cargo for our customers. So we can help them strategize on whether or not what type of offsets, they would like to procure and the quantity those offsets. So – but – Anatol you have anything to add on?

No, we’re – Jeremy, as you mentioned, we’re taking this leading role in developing these technologies and collaborating and creating the baseline from which improvements will be made over time. We’re starting off at a great point. That’s much better than what had been assumed and what is the national average that’s – that is out there and with all of these efforts with our producer partners and our downstream partners, and of course at our own facility. As Jack said, we will continue to be laser focused on continuing to improve our emissions profile. We think that that’s a key success factors as we compete in the energy transition.

Got it. That’s helpful. I’ll leave it there. Thanks.

Our next question comes from Matt Taylor from Tudor, Pickering, Holt & Co. Please go ahead.

Yes. Thanks for taking my question here. I wanted to keep going on that LCA theme there. My question wants – focus on the cost. What are you guys seeing on a cost from in BTU basis for offering these cargo emissions tags. And then sort of the follow on comment to that, do you see this being more of a niche type product where customers are willing to pay a premium for those cargoes and offset those additional costs? Or do you just see this being the trend of where the market’s going?

On the – the first one on the cost, so we’re doing a lot of the work in-house, Matt. So we – the costs are born with our overall SG&A budgets, and there’s a slight amount of a little bit of capital dollars, but it’s insignificant. It’s more of the just the in-house expertise on each of the different areas and our ability to help influence the market. And I’m actually looking at Corey Grindal so on the supplier side to make sure that, that we’re getting good data, that, that we can quantify, monitor, validate, and report on that data and feel good that there’s an auditable trail that, that we can stand behind both from our supplier side, from the midstream and processing folks through our own liquefaction treatment and then in shipping to our customers docs. I do think the carbon emission tags are necessary for first, most of our European counterparts. They’ve applauded us for doing it. They’ve been buying offsets themselves. And in most cases they’re overbuying those offsets. So we – it just a part of doing business that we need to be able to quantify what the carbon footprint is of those of each and every one of those tankers for our customer base. Whether or not eventually we get paid a premium for having a clean cargo, we’ll see how that market develops. Right now, there’s just a lot of work, a lot of spade work that has to get done before we feel comfortable with actually marketing and selling a product like that.

Thanks for those comments, Jack. And then to finish off here, I know you don’t have formal guidance for 2022 yet, but that’s just how attractive margins, like you’re saying, Zack has become in the Train 6 starting commissioning activity here in July. Did you guys be able to provide some preliminary commentary on how you see earnings trending in 2022 versus your run rate guidance?

Sure. I’ll give you a little bit, but we plan to present that to you really in on the next call in November, after we go through the 2022 budget process, but it’s really going to come down to where margins are going to be for the winter, and then just timing with how Train 6 commissioning comes along in the first half of the year, but at the rate can SPL construction is going and with margins for 2022, right now, above $6 for the winter and over $3 for the rest of the next year. It’s looking likely that EBITDA should be over $5 billion for 2022 if things don’t move too much from here. So we’re obviously getting closer and closer to run rate.

Thanks, Zach. That’s it for me.

Next question comes from Mike Webber from Webber Research. Please go ahead.

Hey, good morning, guys. How are you?

Michael, how are you?

Good. Jack, I liked your quote earlier now that you’re in the business of making money, not in the FID business, which is relatively appropriate. So along those lines, and then maybe there’s a better question for Anatol. I’m curious how term pricing taking the net back deals kind of a side and because there is actually some term pricing deals that are getting done. If we sent any kind of lifts in terms of term pricing dynamics right now, just given the ramp out of COVID and the kind of homogeneous degree of supply slippage we’ve been seeing, are you getting any support in terms of where that, that long-term SPA level actually sits?

Yes. I would say thanks, Michael. We have a lot more appetite engagement traction I mean is only six, nine months ago where – when there was a – I would say a cadre of the industry that was thinking about remaining open for it’s a sort of fundamental requirements and relying on the spot market that started to fade a quarter after that. And I think that that strategy is – has not been largely forgotten. So now it’s about portfolio management, engaging and structuring a portfolio of mid-term and long-term volumes. And as a result of those conversations, the economics are stabilizing and firming. And you’ve seen that relatively openly in the slopes that you see on the Brent side, that that’s an easier one to track, where we’ve come off those very low levels. And obviously the economics are stabilizing now for term commitments out of the NYMEX market as well.

Got you. If I were to think about that – I’m sorry, go ahead.

It depends on when it’s going to begin also. So if you think about a term – if it’s steep deed on a greenfield project is going to begin five years from now. It’s probably priced at the marginal cost of the next investment or the next train, right. And if it’s like more like a Cheniere portfolio contract that can begin now or next year or any time for that matter. And then you should expect it to be priced at the – at a higher level, right for more certainty.

Got you. And I guess my follow-up is how uniform you think that is over the broader market. So if I think about maybe the way you guys have price term business, as kind of IG pricing versus the more aggressive pricing we’ve seen out of some greenfields be it net back or not. Do you think that spread between IG term pricing and greenfield is wider today than it was maybe this time last year or six months ago more than relatively consistent with.

I think the dramatic changes in that market, in that spread played out probably two or three years ago. I honestly don’t have enough precision to tell you if that’s moved around a bit, but as Jack said there was a premium that the market will pay for certainty and our track record in history. As well as for early volumes that are included in that, that obviously greenfield can provide. So I just don’t have enough precision to give you a good answer on that.

Fair enough. And then my follow-up for Zach, actually just along the lines of some of the more variable rate deals that we’ve seen in the market, do they directs net back deals or not? When you’re talking to your lenders about those kinds of deals, what kind of guidance do you get in terms of the makeup of a portfolio of a really financeable portfolio? And how should we think about what – how should we think about the concentration of those kinds of deals within a portfolio of business that is actually financeable?

I think I just go back to what Jack said, first and foremost, we’re here to create maximum value for LNG shareholders period. So it’s not just about the next FID or signing a contract for the sake of FID to win some race for the lowest price FID or the highest risk FID, I’m sorry, high risk SPA. So luckily with the funnel that Anatol and the team has, we think we’re just going to be clipping fix fees for a vast majority of our volume that will meet all of our investment parameters. And it’s going to be a mix of IPM, DS and FOB deals with each and every one with a credit worthy counter-party and fixed fees for a long, long time. We can’t really speak to other business models. That’s our business model and we’re sticking to it.

Yes. And I was curious whether you were getting any feedback from your lenders around that, but I can take that offline. All right. Thanks, guys. It’s done.

Thanks, Mike.

Next question comes from Ben Nolan from Stifel. Please go ahead.

Yes, thanks. So I wanted to – we’ll start with probably an easy one. You talked about the 12 million tons of mid-term volume that you have committed over the next 11 years or so. Maybe we get a sense of sort of what the average contract duration is for that portion?

It’s not that easy volume weighted. I would say it’s just inside of five years would be my guess.

Okay. That’s helpful. Sorry, go ahead.

I was just going to add, when we’re talking about those mid-term deals, we didn’t mention that all the deals we signed at is about $3 billion of fixed fees through the early 2030s. But just thinking about how much de-risking of our cash flows has just occurred over the past quarter. We now have locked in this year, fixed fees for about $400 million just in 2022 and comfortably over $1.5 billion through 2025. Just to give you perspective of how much has really been locked in the past quarter or so.

That’s great color. I appreciate that Zach. And maybe, well, boy, I wish I had more than one. We’ll stick with this one. So as you’re looking at Stage 3 at Corpus Christi, obviously we have higher steel prices, labor inflation is happening all over the place. As it relates to Corpus Christi 3, and maybe just in general expansion of for you and anybody else, are you starting to see any inflation and the cost of projects that might necessitate pushing up margins a little bit in order to generate good returns?

Thanks, Ben. And I have to say, we have a very strong relationship with Bechtel having completed nine trains and 45 million tons of liquefaction already. I have complete confidence in Bechtel that they can manage the project to its lowest capital costs out there. We haven’t seen any inflationary environments at this point, but I’ll turn it over to Zach and let him.

Yes. Just to reiterate, we don’t really see material risks on the cost side and we’re actively pursuing all opportunities through the – really the end of this year to make it as price competitive as possible. But I’ll just say we feel really good to meet all of those investment parameters based on the contracts we’re seeing and just the synergies we have with Corpus Trains 1, 2, 3. And that let’s say approximately six times multiple on CapEx to EBITDA is still the right one give or take for the full project.

Perfect. I appreciate it. Thank you.

Our next question comes from Julien Dumoulin-Smith from Bank of America. Please go ahead.

Hey guys, I know we’re getting to the top of the hour, so I’ll make it quick. If I can just come back to the carbon question, especially as you think about some of the advantage credits here, can you talk a little bit more about the specific structuring and how you would take advantage of the 45 to otherwise from a carbon neutrality perspective to the extent possible? And then separately, just how is relatively that position, your expansion opportunities here vis-à-vis alternatives. Again, I gathered that the geography might be more amenable than others, but that that’s open-ended here. I’d love to hear on that. And then do you have any sensitivity, you can speak to a little bit on the hedge position on the – to clarify last question there. But I’ll leave it there.

Okay. So Julien, let me – I think I heard your first part of your question was on carbon and carbon sequestration and just carbon and 45…

Yes.

I had spent weeks ago, I spent a week – and I will tell anybody that, that $45 to $50 a ton is not going to cut the mustard for especially for post combustion carbon sequestration. It’s not going to work and there’s nothing technically yet that is that economical to make that happen. We do sit on top of a very deep, a very large sailing offer that would be looks to be geologically a good spot to sequester carbon dioxide, doing it though is a whole another challenge. So we’re spending a lot of time and resources on categorizing, everything that can possibly putting a price tag to try and trying to see if four, five that works and so far it doesn’t. So I – and I am remiss to say that I don’t know why if I’m able to sequester a ton of carbon, that it’s all, I only get $50 of ton, but if someone else uses direct air capture, they get 175 a ton. Or if I drive an EV are in Cheniere electric vehicle, I guess 450 a ton. None of that makes sense to me, if a price of a carbon molecules should be consistent and it should reward those of us that can do something to put the world in a better position, so.

Then you mentioned something about open capacity 2022 and hedging. And yes, besides those mid-term fields that already locked in around $400 million to fix margin next year, you can expect that the at this point in the year, we’ll already hedging some of our capacity for 2022 in anticipation of giving you guys full your guidance in November, with $6 in there and $3 for the rest of the year. Yes. We’re using some of our capital to the hedge out forward.

All right, great. I’ll leave it there. It’s noon. Thank you all very much. Have a good day.

Thank you, Julien.

The next question comes from James Carreker from US Capital Advisors. Please go ahead.

Hi guys, thanks for the question. I guess, first off, really quickly, is there a I guess useful guideline to think about margins? When I look at the winter LNG curve at $16 and Henry Hub at $4, I kind of think of a number of potential margin much higher than %6. Am I doing some calculations wrong, or just any quick high level calculation to think about how that gets to a $6 margin.

Well, shipping curves have come way up also, James. You have to add, you can either add or subtract the shipping costs to either your JKM $16. You subtract it, or you add it to the $4, but shipping is not insignificant when margins get this high and everything is going to Asia that trip is a lot longer.

So it’s just plus or minus $6 shipping costs.

Not quite that high, but yes, and shipping also just like the curves themselves has a seasonality. So winter shipping is higher than shoulder shipping.

Yes. Okay. It just seems like it wouldn’t have moved to that much versus I guess just kind of the standard $2 estimates, but maybe it has. The other question…

Sorry. James, we’re also talking about a curve through next year. We’re not talking about like a news blurb on Bloomberg today, but like a trader printing a cargo. So just kind of thing…

Right. But you talked about $6 margins in the winter and 43 for the balance of the year.

That’s right.

Yes. I was referring just to the winter months. Then the other question was just now with the second quarter in a row where you found additional production, does that imply anything maybe about upside to the five mtpa run rate per train long-term?

Not at this point, that 49 to 51 mtpa per train is the right one. And honestly, a lot of the outperformance this year is thanks to a really smooth ramp up of Train 3. So yes, we’re still on that 49 to 51 range.

Thank you.

Next question comes from Sean Morgan from Evercore. Please go ahead.

Thanks, guys. So the – I appreciate the creative – creativity in terms of the commercial aspects with signing up IPMs to start to underpin some of the volumes to going to need for Stage 3. Is there a possibility to kind of back-to-back those IPM agreements with more traditional SPAs and sort of double up on fixed fees there?

Well, Sean, thanks. It’s Anatol. Look, it’s a large portfolio Zack mentioned it’s over 40 million tons now, and there are a number of positions that, that are managed in the aggregate. So it is exposure that we have and we are managing on behalf of our producer partners. And clearly there are synergies in that business with the downstream exposure that we manage on a day-to-day basis. So the short answer is, its part and parcel of the opportunity set that we have.

Okay, great. And then just really quick follow-up then. So those IPMs, I mean, in theory, the banks tend to get, it would be totally fine with you guys filling out that remaining 4 mtpa that you mentioned to get the FID with potentially just supply side deals.

Technically they would, but we think it’s going to be a mix and keep in mind, we already have a few contracts that are sitting at CMI and not allocated to a project yet, that, that are DS. So not everything will be IPM for sure, but again, it all comes back to credit worthiness, and a fix fee, and the capability to either deliver us the gas, or pick up the LNG and pay us that fixed fee as a percent of their EBITDA and these counterparties like Tourmaline check all those boxes.

Okay. Thanks, Zach.

Next question comes from Craig Shere from Tuohy Brothers. Please go ahead.

Hi, thanks for fitting me in. Doing the math on the disclosed fix fees for the mid-term contracts combined with their third IPM agreement looks like you’re contracting at over 2.30 in the second quarter, a little above first quarter levels. It might have been more 2.25-ish. Given the current market tightness, could that start approaching $2.5 for five to 10-year agreements?

Thanks, Craig. I have a spreadsheet in front of me that goes through that. And even with that spreadsheet in front of me, it’s pretty hard to summarize. So look, as Jack mentioned in the prompt for the next number of years, it’s market prices, right. And that, that obviously these sixes and threes that we’ve mentioned on this call filter through into those mid-term economics. So it depends on the tenor, but you should expect us to capture that that market or better for the relatively prompt volumes and then our long-term contract economics for the balance. So can those sprint above 2.5, if it’s a relatively short tenor deal, of course, right. That’s where the market is today.

Got you. And I understand the conversation that, hey guys, to clear the market, it’s going to take everything, some demand that used to be long-term fixed and bilateral, we’ll go to the medium and spot. There’ll be new long-term SPAs, they’ll be variable rate contracts. But in terms of the amount of new contracting, I’m not talking about 10 years that is filling in for expiring contracts, and it does support any new capacity. I’m not talking about yourself, I’m talking about maybe some of the Chinese stuff in the first quarter. It just seems like in terms of real SPAs or IPM that can support truly new construction and project finance, it’s been pretty thin. Do you see that starting to open up more? Do you agree? Do you see it starting to open up more? Could you see this in the future being a significant minority of the market, maybe a quarter of the new contracts?

I think your view is skewed to U.S. counterparties in those contracts. I think if you look globally, Craig, and you looked at the oil index contracts that are being signed almost daily, you’ll see the market in the contracting market has been very lively. But if you’re talking about just Henry Hub link, U.S. style markets are contracts than it’s been less, but still pretty strong.

Yes. I just to follow-up on Jack’s comments, 2020 was obviously an anomalous year, but even then you saw a fair amount of long-term contracting. And obviously 2018, 2019 were big years for the NYMEX market. And as we’ve discussed the margin environment and the window is clearly open for more of that engagement now. And I think we’ve viewed that that piece of the market is going to be volumetrically roughly similar to what it has been historically, just as the market grows, it’ll be a smaller percentage of the total.

Got you. Okay. Thank you very much.

Okay. So that appears, that is all we have time for questions for today. I turn the call back over to management for any additional or closing remarks.

I just want to thank everybody for your supportive of Cheniere. It’s been an interesting time with the pandemic. Please be safe out there. Please get vaccinated. And we’ll talk to you, I guess, in November. Thanks. Bye-bye.

This concludes today’s call. Thank you for your participation. You may now disconnect.