Chesapeake Energy Corporation (NASDAQ:CHK) Q3 2023 Earnings Call Transcript

Chesapeake Energy Corporation (NASDAQ:CHK) Q3 2023 Earnings Call Transcript November 1, 2023

Operator: Good morning and welcome to the Chesapeake Energy Corporation Third Quarter 2023 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Chris Ayers, Vice President of Investor Relations and Treasurer. Please go ahead.

Chris Ayres: Thank you, Anthony. Good morning, everyone, and thank you for joining our call today to discuss Chesapeake’s third quarter 2023 financial and operating results. Hopefully, you’ve had a chance to review our press release and the updated investor presentation that we posted to our website yesterday. During this morning’s call, we will be making forward-looking statements, which consist statements that cannot be confirmed by reference to existing information, including statements regarding beliefs, goals, expectations, forecasts, projections, future performance, and the assumptions underlying such statements. Please note there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our press release yesterday and in other SEC filings.

Please recognize that as except required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. We may also refer to some non-GAAP measures, which help facilitate comparisons across periods and peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure, which can be found on our website. With me on the call today are Nick Dell’Osso, Mohit Singh, and Josh Viets. Nick will give a brief overview of our results, and then we will open up the teleconference to Q&A. So, with that, thank you again. Now, we’ll turn it over to Nick.

Nick Dell’Osso: Good morning. Thank you for joining the call. I’ll start off by discussing a few of our third quarter highlights, and then I’ll get right to your questions. We delivered another strong quarter, advancing our strategy to deliver sustainable value to shareholders through cycles. As you’ve seen from our third quarter results, we came in on the low end of capital and the high end of production, despite the 60% deferral of planned third quarter turn-in lines and the extension of elective curtailments in the Marcellus. In the Marcellus this quarter, our rig fleet set a new company record, averaging 1,367 feet per day, marking a 16% improvement over the prior quarter. Overall, we drilled four of the top 10 fastest Marcellus wells in our company’s history.

That’s a pretty significant accomplishment given our long and successful history in the basin. Importantly, our decreased cycle times have also been accompanied by achieving a lower cost per foot, which means we will now be able to drill another well per rig year at a lower cost compared to what we projected at the beginning of the year. This is a great example of efficiency offsetting inflation. In the Haynesville, we delivered another robust quarter of base production with strong wedge volumes. Additionally, our sustained efforts to debottleneck our midstream has resulted in lower line pressures and higher production. We’ve realized a 15% quarter-over-quarter reduction in interrupted volumes attributable to midstream disruptions. The combination of our improved base production and effort to optimize gas flow assurance has led us to increasing our Q4 production guidance by 35 million cubic feet a day or approximately 2.5%.

Our strong operational performance serves as the backbone to our commitment to deliver superior capital returns for shareholders. We continue to execute our peer-leading return program in the quarter, repurchasing $130 million in shares and delivering our base dividend. Through the third quarter, we have returned approximately $725 million to shareholders through our buyback and dividend programs. We also announced another important step on our path to be LNG-ready with today’s LNG supply announcement with Vitol. Similar to our past agreement with Gunvor, under today’s heads of agreement with Vitol, Chesapeake will supply up to 1 million tons per annum of LNG to Vitol with the purchase price indexed to JKM. As we continue exploring these types of agreements, we see an appreciation of the premium rock returns and runway of our advantaged portfolio and the strength of our financial position.

Our approach to executing our LNG strategy has been consistent and benefits from production that is physically linked to LNG markets, access to international prices and downside protection through cancellation optionality. Our portfolio, balance sheet, and approach represents a clear competitive advantage among our gas peers and we continue to complete LNG agreements as we see export capacity come online over the next few years. Before opening the call for questions, I’d like to touch on our trajectory headed into 2024. We expect to maintain our current rig count of five rigs in the Haynesville and four rigs in the Marcellus for the first part of the year. Should gas prices firm up in line with the current 2025 strip, we believe there may be an opportunity to add an additional rig in the Haynesville during the second half of the year, which would positively impact volumes in 2025.

As you look to model our business in 2024, a fair starting point is to assume our annual production should be in line with our fourth quarter run rate of 3.2 Bcf a day in the Marcellus and Haynesville. Our CapEx for the full year should approximate $1.6 billion, assuming an additional Haynesville rig in the second half of the year. We’re now pleased to address your questions. Operator, if you want to assemble the queue?

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Q&A Session

Operator: We will now begin the question-and-answer session. [Operator Instructions] Our first question will come from Doug Leggate with Bank of America. You may now go ahead.

Doug Leggate: Hey good morning everyone. Thanks for taking my questions. Nick, I wonder if I could pick up on the 2024 outlook here because for quite some time now, you’ve talked about managing your production to maintain production capacity. I don’t know if I’m missing up the description of that. But as you think about the capital required in to maintain, let’s say, your exit rate and then set yourself up into 2025, what do you think that cadence of production and that associated capital looks like ex-Eagle Ford, obviously?

Nick Dell’Osso: Well, I’ll start here, and Josh may have some more color to add. But essentially, Doug, we’re starting the year with maintaining the production where it is today, right? five rigs in the Haynesville, four rigs in the Marcellus. That’s going to keep us where we are today at about 3.2 Bcf a day. We are paying attention to the fact that the export capacity for LNG should come online by the end of the year, setting up for unmet demand in 2025. If that looks like it’s going to play out and the strip looks like it’s going to hold up, then we would add a rig in the second half of the year. And so the $1.6 billion of CapEx that I gave you a minute ago does assume that we add a rig in the second half of the year in the Haynesville. If we didn’t have that rig, we would just stay at that level of production, it would be a little bit less.

Doug Leggate: Okay. That makes it ton of sense. Thanks. Nick, I don’t expect you to answer this question directly, but I wonder if I could ask you to frame your views on just broader industry consolidation. For Chesapeake, you’ve talked — we were in Haynesville with you in July. You said there was — there were no conversations happening, Mohit countered that a little bit in our bus tour basically saying, well, actually, there are a lot of conversations happening that was just two months later. So, how do you see the landscape and Chesapeake’s role within that, whether it be private or public?

Nick Dell’Osso: Well, I think you touched on some themes there that are pretty interesting and we’ve been very consistent in saying that we believe in consolidation in the industry. So, we’ve been pleased to see Exxon and Chevron do the deals that they’ve done. We think those are constructive for the industry. And the dialogue for M&A does come in ebbs and flows. And there are times in the market where it seems like more people are having conversations than others. Overall, we’ve continued to say that we’re very happy with the portfolio that we own. So, we don’t feel compelled to do anything and we certainly don’t feel compelled to do anything on near-term timetable. But at the same time, we believe in consolidation. We believe in the merits of attempting to have consolidation make the industry a more profitable, more productive place and we’ve been also very consistent in talking about how we would define that for ourselves.

And so for us, we go back to our non-negotiables and just to remind everybody, that means that we — in the context of consolidation, we don’t want to overpay, we will look for accretion in the transaction, we will protect our balance sheet, we will look for a good emissions profile or one we can quickly make better. And what that really means at the end of the day is that you have to make your company better through consolidation, not just bigger. And that’s not an easy thing to do, that’s a pretty high bar. So, we believe in consolidation and we’ll continue to pay attention.

Doug Leggate: Just a quick add-on to that very quickly, Nick. Is there interest in outside of the two basins that you’re in? Or when you say you’re happy with your portfolio, would that imply there for that any consolidation you would pursue would be focused on those two basins?

Nick Dell’Osso: Well, you got a couple of questions embedded in there. And I think the answers won’t be surprising to anyone. We like the basins we’re in. We like the assets that we’re in because we know that they are at the top of the heap for natural gas supply and demand fundamentals and delivering against that supply and demand fundamentals for many years. So, we’re happy being in the Marcellus and the Haynesville. We’ve been asked over time, would we look outside of those basins. And my answer there is our non-negotiables are a high bar. If you wanted to apply those non-negotiables to a place we don’t operate today, that bar is even higher. So, we continue to say that is an unlikely answer for us. But we do like where we operate today, and we think that we have a competitive advantage to be in both of those basins.

Doug Leggate: Thanks Nick. We’ll see you in a couple of weeks.

Nick Dell’Osso: Great.

Operator: Our next question will come from Zach Parham with JPMorgan. You may now go ahead.

Zach Parham: Thanks for taking my question. Just wanted to ask on the outperformance in the Haynesville. You’ve outperformed your guidance each quarter this year. You increased the 4Q guide looking at state data, well productivity seems to be trending positively. Can you just give us a bit more color on what’s driving that outperformance in the Haynesville and how sustainable you think that is going forward?

Josh Viets: Good morning Zach, this is Josh. We’ve been really happy with the way the performance has showed up in the Haynesville this year. And of course, going back to last year, we knew we had some bottlenecks within the midstream. And so we’ve done a ton of work over the last year to really shore that up. And largely, what that’s been attributed to is simply working with our midstream providers to introduce additional interconnects between gathering systems, helping support treating capacity expansion. And so those are things that are just simply will be sustainable through the years, and it’s allowing us to continue to mitigate midstream induced downtime. So, we’ll continue to work with our midstream providers to allow that to improve over time.

Well productivity has been strong through the course of the year. We’ve seen some modest increases in well performance. One of the things that’s actually allowed us to do is to delay the second frac crew that we’re bringing in. We’ve allowed ourselves to push that back by a couple of months. We’ll bring that second frac crew back now in the middle to late November, which allows us to preserve some productive capacity as we head into early 2024.

Zach Parham: Thanks for that color. And then just one clarification on 2024. You talked about $1.6 billion in CapEx, assuming that additional Haynesville rig comes back in the second half next year. Does that include the spend on the momentum pipe, which I think is around the $100 million next year?

Nick Dell’Osso: Good question, Zach. No, that does not include momentum. We’re trying to just give you a number to think about our regular way E&P business.

Zach Parham: Okay. Thank you.

Operator: Our next question will come from Umang Choudhary with Goldman Sachs. You may now go ahead.

Umang Choudhary: Thank you. Hi, good morning. Thank you for taking my questions. I would love your thoughts on the 2024 macro outlook for natural gas. And to follow-up on Doug’s question around your our activity levels in the Haynesville, you plan to add a rig in the back half of the year. Any thoughts or any color you can give in terms of where you think the spending level would be your production outlook would be for the year?

Nick Dell’Osso: Sure Umang. Yes. So, macro, start with that. We’ve got a lot of uncertainty in front of us here with winter just starting. And storage levels have been high — relatively high throughout 2023. They look a little bit better today than they did a couple of months ago, but the big variable in front of us now is the winter. What we’re all excited about in the industry is the step change that will come to the fundamentals when we have the incremental export capacity come online. We still think that happens around the end of 2024. We will watch that very, very closely. That’s the signal we’re really focused on from a macro perspective is will we have that connectivity to markets that are underserved, such that there is a call on US gas.

If that happens, we believe we have an important asset to meet that call in the Haynesville, and we would expect to add a rig if that looks like it’s coming in line with that projection. But to be clear, our $1.6 billion number that we gave you as an approximation for our 2024 CapEx which albeit it’s very early to be giving you that number. That’s an early estimate, and we’ll set a budget still as we go through the end of the year here and get ready to start next year as we really see where winter plays out. That would assume that we bring a rig on in the second half of the year in the Haynesville. So, if that macro view changes, and we don’t believe that LNG is going to come online timely or the storage environment changes because we have either a really cold or a really warm winter, we could certainly change that answer.

But as of now, we’re thinking about a business that would start off the year exactly where it is today and that has the flexibility to add a rig in the second half of the year. And so the starting point number we’ve given you for capital would assume we do just that. But just to reiterate, we have all the flexibility in the world to change our answer around whether or not that rig comes on in the second half of the year or any other changes to our capital program with plenty of flexibility, and we can be very responsive to what we believe the fundamentals are asking our industry to deliver in the way of supply.

Umang Choudhary: That’s very helpful. Thank you. And as a follow-up question, I wanted to understand a little bit about the midstream setup in the Haynesville. The production in the Haynesville has been declining and — but you also have made progress in terms of adding more capacity in the Haynesville. So, do you feel like you have sufficient capacity as we look to 2025, to group molecules in the Haynesville. That’s question number one. And can you also remind us on the progress on the Momentum pipeline? Is it on track to come online in the fourth quarter of next year?

Nick Dell’Osso: Yes, let me answer the first part of that, and then I’ll have Mohit talk about momentum. As for capacity, we feel very comfortable we can deliver what we’re planning for here. Remember that 2024 volumes in the Haynesville will be lower than we were in 2022 and 2023, where at the — during 2022 and the beginning of 2023, we experienced some of those bottlenecks. We’ve removed those bottlenecks so we can restore production back to those previous levels with that incremental rig, we feel very good about that and feel very good that if we ever chose to grow beyond that in the future, we have the relationships and the infrastructure in place to be able to do it.

Mohit Singh: Umang, this is Mohit. On the second part of your question about momentum. As we’ve said previously, we are very excited about the project and what it means for our flow assurance. We look at the volumes that we are producing in Haynesville and are trying to build a transport portfolio, which allows us to take it to Perryville or down south to Gilles. And the intent — this is part of our BLNG-ready strategy where we get production to Gilles and that’s where we can have connectivity to different liquefaction facilities. So, momentum has — it remains a critical part of our strategy, and we — it’s on track. We expect it to go into service probably late next year or early 2025 which is all still on track. We still like the project, and it remains a key part of our LNG strategy.

Umang Choudhary: That’s really helpful. Thank you guys.

Operator: Our next question will come from Bert Donnes with Truist. You may now go ahead. pardon me, Bert, your line is open for questions.

Bert Donnes: …your total company LNG pricing exposure, predominantly to an international index instead of a domestic one, is that an intentional shift? Or was this just kind of timing and maybe you have some Henry Hub agreements down the line even out the score? And maybe the second part of that is, is there any reason you haven’t signed an open ended agreement where you kind of retain control and sell the gas at the final destination.

Nick Dell’Osso: Sure. Bert, your — the first part of your question didn’t come through. I think maybe you were coming off a mute or something. But I’ll start to talk about LNG and Mohit will add in, and then you’ll have to just redirect us if we miss part of your question. But you were asking about percentage of international price exposure. We’ve been pretty consistent there to talk about 15% to 20%. I guess to clarify based on a question we got last night, when we talk about 15% to 20% of our production that we target for international pricing, that’s our net production generally, when companies announce these deals, they are announced under gross marketed production, which is obviously more. So, just to think about that, you need to consider what our average net revenue interest is across our production.

It was a pretty good approximation for how to net that down. So, we’ve got a little bit of ways to go to get there. We’re not done yet. And we like that we’re not done yet. We think there’s plenty more interesting deals to be had in the LNG space. And as to why we’ve done what we’ve done with a trader rather than try to market it ourselves, I think it’s going to take a pretty significant presence in LNG marketing to be really successful at marketing volumes. This is a market that is — the participants in this market are very, very large. The majors participate in this market and the big commodities traders participate in this market on a daily basis. And I think in order to be competitive there, you need to be part of a pool of volumes that can be traded around in a very fluid way.

And to be a producer that may ultimately have 3 million or 4 million or 5 million tons per annum on the water, we think is relatively small and would be a challenge to be competitive in that marketplace. That said, we’re always eager to be creative and how we think about the best ways for us to access international markets and achieve international pricing. We like what we’ve done so far. This market is evolving and evolving rapidly, and we’ll continue to think about the best ways for us to participate.

Bert Donnes: I appreciate that. And then just a small detail on the presentation. You kind of shifted your deflation expectations. I think prior, you were using 1Q over 1Q and you’ve shifted to first half over first half. So, I guess the first part is what was the shift there? And then the second part is of the 50% that you have locked in, are those locked in at fixed prices or are those maybe have some sort of escalator deal or something linked to commodity prices? Thanks.

Josh Viets: Yes, Bert, this is Josh. Yes, we did extend the expectation for inflation for the full first half of 2024. We’ve just continued to increase our confidence in that expectation as we’ve been able to shore up contracts. And so when we do reference that 50% of contracts, by and large, those are all fixed pricing. We do have some contracts that will start to show up in the second half of the year that have some built-in escalators, but that represents a relatively small amount of our total spend. And that’s why I think we feel pretty good about actually seeing and preventing any additional inflation in the second half of the year because the majority of the spend is locked in at fixed pricing for the large part of 2024.

Bert Donnes: I appreciate it. Thanks guys.

Operator: Our next question will come from Scott Hanold with RBC Capital Markets. You may now go ahead.

Scott Hanold: Yes, thanks. If I could probably ask a question on 2024. Nick, I think the prior commentary around — talked about optionality of bringing the Haynesville rig and the first part of the year and then maybe a Haynesville and Marcellus in midyear. And it sounds like you’re — I guess, your view on the market for the gas for 2024 hasn’t changed too much. In fact, you said that the inventory overhang went down a little bit. So, I’m just kind of curious on why sort of pushing back some of that production recovery into next year?

Nick Dell’Osso: Sorry, yes, I wouldn’t really view it as pushing it back, Scott. We’ve said during the year, and we could change the timing of that still a little bit. I mean, if we come out of this winter in a really strong market, we could bring a Haynesville rig on sooner. So, we’re trying to be pretty flexible in how we communicate this. As of right now, we think we’re pretty happy with where our Marcellus position sits relative to the production we can generate and the capacity of the market to take that production in the Northeast. If that changes, we could easily add a rig there, too. So, we’re pretty flexible around all of that. And in order to give you a CapEx number, we gave you a scenario, which is to bring a Haynesville rig on it midyear. And that easily could change, and it frankly probably will change. There’s a lot we need to understand about where this market is headed.

Scott Hanold: Okay. So, fundamentally, no major changes to your view on 2024 at this point versus, say, where you were two months ago?

Nick Dell’Osso: That’s correct.

Scott Hanold: Got it. Okay. And as my follow-up question, could you talk about the differentials in the Marcellus strategies you guys are using to help mitigate some of the blowouts. And you talked about extending your elective deferrals, just when you think that might end?

Mohit Singh: Yes. So, Scott, this is Mohit. We remain active in our hedging program. So, the guidance I would give you is we are about 75% to 80% basis hedged in both our businesses for the winter. And then when you start coming into next year, it’s more around 60%. So, again, that’s trying to take that uncertainty out from the future outcomes, and that’s a combination of financial and physical hedges that we are put into place.

Josh Viets: And Scott, just to build on to that as well as far as kind of current outlook. We are starting to see some improvements. in pricing up in the Northeast right now. That’s allowed us to start bringing on wells. We brought on about 12 wells through the first month of the quarter. We’re looking at opportunities right now to start taking some of the base that we’ve had curtailed for the last couple of months and bring that back into the markets here over the next couple of weeks. So, we are definitely starting to see some improvements there, and I think that just further supports the outlook that we provided for Q4 production in the asset.

Nick Dell’Osso: Yes and I’ll just add a little bit further specifics there. First of month pricing for November was materially improved and is encouraging around the pickup in demand that you generally see at this time of year. So, the elective curtailments usually end around now, sometime in early to mid-November. That’s a cash market decision, super hard to predict on a daily basis. So, they generally will fall away as you go through November as to whether it’s the beginning of November, the end of November. That’s a function of weather.

Scott Hanold: Got it. Thank you.

Operator: Our next question will come from Charles Meade with Johnson Rice. You may now go ahead.

Charles Meade: Good morning Nick, Mohit and Josh and rest of the Chesapeake there. Nick, I want to thank you for your really succinct explicit comments about 2024. That’s great. I think it probably took a lot with the sales — people question, but I want to ask a question about your LNG strategy. So, I noticed that this Vitol deal, just like the Gunvor deal doesn’t have the — there’s a block missing, a piece missing with the liquefaction. And so I’m curious if you can elaborate a bit on your thinking. Is this kind of an intentional bet that you guys and the Board is making that liquefaction facilities will eventually be overbuilt in the next, call it, five years? Or is it more — is it more along the lines of you want to do what you can now and figure out the rest later?

Mohit Singh: Hey Charles, this is Mohit. Thanks for the question. The way I would like you to think about this is, clearly, there’s a willing seller in Chesapeake, there’s a willing buyer in Vitol. And what we are taking to these liquefaction facilities then is a pre-wire deal where we have a buy and a seller already agreeing upon the terms. So, there is option value that’s embedded in such an arrangement. When you go talk to different LNG facilities, they might need one or two MTPA to get to FID. So, it creates a little bit of a competitive tension with different facilities as we go talk to them and figure out which one meets our requirements and Vitol’s requirements. And the ones that we think about primarily are — what’s the pricing.

What tool are you having to pay is number one? Number two is, is it accessible to our production. So, can we even get our equity volumes to those facilities through transport solutions. Number three would be what kind of accounting treatment are you getting, whether it’s derivative versus non-derivative and credit requirements is another one. And then last but not the least is about the FID timing and probability of getting to. So, when you put all that together, it works for us in this situation, but that’s not to say that this is how we will do the remaining ones, too. I mean, we are clearly looking at a lot of LNG transactions, and we might do it differently in the next one that we announced.

Charles Meade: Mohit, that’s helpful. And then a second follow-up on, I guess, A&D opportunities. I know this is — will be an ongoing discussion for you guys. But there was one major player in the Haynesville, BP, there’s been a lot of turmoil there lately. And I think just yesterday, there was an article saying that maybe they were going to be looking for partners in some of the US onshore assets. And I think someone says they’re looking for partners, they might be open to offers as well. But I recognize that you guys can’t talk a lot, it’s relatively new, and you can’t talk about anything that’s ongoing. But perhaps, Josh or Nick, you could tell me. My impression is that those BP assets are really high-quality assets. They are the old HK petrol and [Indiscernible] assets that those locations would be able to compete favorably in your portfolio. Is that the way you guys see it?

Mohit Singh: Hey Charles, this is Mohit again. Again, we don’t want to speculate on rumors. But one thing I’m sensitive to, I have — do have a BP legacy since I came to Chesapeake from BP. So, I know the team and those assets really, really well. I think your general comment around the quality of the assets is very competitive. I would agree with that. But maybe we’ll leave it there. And just if something were to happen there, and again, as we do, we always take a look across the lease line to see what else might be available.

Charles Meade: That’s what you was looking for. Thank you, Mohit.

Operator: Our final question will come from Noel Parks with Tuohy Brothers. You may now go ahead.

Noel Parks: Hi, good morning.

Nick Dell’Osso: Good morning Noel.

Noel Parks: So, I wanted to ask you about infrastructure and future investment there. With LNG coming to the picture, it seems like a lot of producers are looking at what level they might consider maintenance or expansion infrastructure investment. And I’m just wondering, is there anything either directly spurred by LNG or otherwise. Are there any nonobvious factors that would affect your decisions going forward about on balance sheet versus JV structures with infrastructure investments. I’m thinking about tax considerations or incentive considerations or things like that pretty much back burner when you’re looking at your down the road planning?

Nick Dell’Osso: Well, I’ll take a shot at answering that, Noel. I think the way we think about infrastructure when you’re looking to create access to new markets and premium markets, you often are going to need either expansions or new construction of infrastructure. When I think about what we’ve done with the NG3 pipeline with Momentum, that was an opportunity to support a project that we thought was a competitive project that would improve the marketability of our production. We also thought that the economics of that development were very attractive to us because you could invest at the preconstruction stage and have great line of sight into the fact that, that project would be successful since our equity production would be a big driver of causing it to be successful.

So, that kind of return opportunity is very compelling to us and it helps to underwrite a project that’s accretive to our entire portfolio of Haynesville production. So, that’s a great project for us. When we think about how or where, why we might participate in infrastructure, it’s when you have that kind of differential opportunity to earn return for your shareholders. If you can participate in infrastructure that without participating in it, you don’t have access to a premium market, sure, you can consider that. if you can participate in a place where there’s an outsized return that you’re uniquely capable of earning. That’s great, too. If it’s otherwise just to own infrastructure style producing returns of call it, high single, low double digits for fully developed assets, probably less interested in that.

I hope I’ve answered your question there. But strategically, we think about if we’re willing to make an investment in infrastructure, it should be for a differential return.

Noel Parks: Great. Thanks. That too get to what I was wondering. And I was wondering with the — either the Vitol or the Energy Transfer Gunvor deal. Are there any Right of First Refusal or similar conditions when it comes to the potential to add more volumes down the road? Or are both parties essentially just reagents to contract with whomever they want going forward?

Mohit Singh: Yes. So, the terms of the arrangements with both Vitol, Gunvor, Energy Transfer are confidential, Noel. We can’t get into all the specifics, but what I will tell you is we are delivering the LNG FOB and then it’s — that’s where the custody transfer is happening and then the buyer to take it to whichever end user, it makes sense for them.

Nick Dell’Osso: But just to be clear, those agreements that we have are limited to the volumes we’ve announced. We don’t have a broader partnership with any of those counterparties at this point. It’s 1 million to 2 million tons per annum with Gunvor and 1 million tons per annum with Vitol. So, beyond that, we are free to contract with anybody should we choose to do additional contracts.

Noel Parks: Great. And just one sort of cleanup item. I just wondered, in retrospect, looking back, do you have a sense that what happened with Freeport and the volumes that did not go out on that because of that outage. Do you think that, that impact has fully worked its way through either storage or through the markets perception of where supply/demand fundamentals really are right now? Or do you think there’s somebody to do that still an overhang or still sort of flying under the radar as we head into another withdrawal season?

Nick Dell’Osso: That’s a good question. I think it’s probably pretty well worked through. I think the fundamentals at this point are all about what the draw will be weather-related this winter, what the trajectory of production is from the capital reductions you’ve seen in US onshore through 2023 and then the timing of new export capacity coming online sometime around the end of 2024, beginning of 2025. Those are your three big variables and those are going to be your biggest drivers.

Noel Parks: Great. Thanks a lot.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Nick Dell’Osso for any closing remarks.

Nick Dell’Osso: Thanks everyone. We really appreciate everybody’s time and questions this morning. As always, our team is available today and any other day to answer any further follow-up questions. We’ll be at a few conferences between now and the end of the year and look forward to seeing everybody out on the road. Have a good day.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.