All right. Looking forward to this conversation as well. Chesapeake Energy, really glad to have Nick Dell'Osso, our CEO of Chesapeake, to be here and talk about the latest, and I'm sure you've been getting a lot of questions on gas macro. So, Nick, thank you for being here. Thanks, Betty. I'm sure so far today you have talked about gas macro multiple times, so would love to get your thoughts on, you know, what are you thinking, your latest thoughts on how the market is developing and what has surprised you the most so far in this market? Sure. There's a couple things that go into the surprise category, but the way we're thinking about it right now, I would say we're fairly optimistic about where the gas markets are heading. And I would describe first, the big, broad trends that are multi-year. And the first of that is the growth in LNG demand, which we see coming online, starting in the second half of this year and then extending all the way until Golden Pass comes online, which is probably, you know, you all in the room have just as good of information on that as I do. But we would say end of 2025-ish, could be beginning of 2026. Plaquemines is already starting to take a little bit of gas. Corpus Christi, Train 3 is starting to take some gas. So those projects are happening sooner. That's a lot of demand, well over 4 Bcf a day from those two projects alone, Golden Pass being then on top of it. In addition to that, other big trend is now 12 months plus of pretty significant capital reductions across the natural gas space. I would point out that the Haynesville rig count is currently sitting at 33, I think was what I saw last week, which is about the same as the lows experienced during COVID. Pretty low investment in gas today. There's been a tremendous amount of activity curtailed in gas. We have a lot of activity that has been held back on the sidelines. We have quite a large number of deferred and completed wells, which we call deferred turn-in-line, so D-TILs in our vocabulary, and then DUCs or drilled but uncompleted wells that others talk about also. So that adds some confusion to the market as to really what supply currently is. Additionally, we've seen curtailments of base production throughout the year. We saw that in the spring. Those volumes mostly came back online in June when prices perked up. Now we're seeing curtailments show up again. Those curtailments are making it difficult to see the underlying decline. We think that that underlying decline is possibly underestimated in some of the macro models that are out there. And when we think about that, we look at the fact that our first quarter production going towards our fourth quarter production that we put in our slide deck with Q2 earnings shows pretty significant drops, especially as you go from Q3 to Q4. And that basically removes all of the curtailment noise. If you just follow Q1 all the way to Q4, you would then remove the noise of curtailments along the way. That shows pretty significant decline, and we think that ought to be representative of the way the rest of the industry is set up. In fact, maybe even a little bit less in that we haven't cut rigs to the same percentage that the overall industry has cut rigs. We, we think that the underlying decline there is pretty significant, and is going to continue to show up as we get into the end of this year and into next year. So all those two forces are pretty significant. They're longer term trends, and they will collide to create a much tighter gas market. The one thing I continue to tell people is that I am not nearly smart enough to know if that collision occurs in Q4 of this year, Q1 of next year, Q2 of next year. We find it hard to see that you get all the way to next year without that, without those two really showing up as a very tight market for gas. In terms of what's been surprising, I think it's a little surprising to see production holding up as strong as it is. I think you have a couple of different phenomena there. Reduced activity in the field means better activity. That's always true. So the entire industry is a lot more capital efficient with less rigs running. And I think you also see a lot less congestion in pipes, and so things just flow better. And you have more robust production, flush production that comes back after there was curtailment in the spring. All those things are very real. And ultimately that will work its way through the system, and we'll see these declines show up as we get towards the end of this year. The other thing I would say, though, that I think is surprising, is that in past cycles, at this point, where we've had capital on the sidelines now for a year, and we have a pretty strong macro environment set up for 2025, you would typically see companies like us and our peers contracting for and standing up rigs today to be ready for adding production in 2025. We're just not seeing that happen. The rig count is not going up. Talking to the rig service providers, they're not getting pestered for long-term contracts. So there are, you know, well-to-well contracts that happen, but long-term contracts are not being signed up today. So I think those are the two biggest surprises, is that production has been a little bit more resilient, but you're also not seeing capital show back up yet. That's really interesting. On that point, do you think that's a function of producer capital discipline on the operator side, on the public side, which we do see? Or is it the private market is different this time around than the past? It's both, and clearly, the private market is behaving a little bit differently than, say, in 2022. Obviously, in 2022, we were in a very bullish market. The capital cycle began pretty strong in 2021. Really, as soon as we got into the summer of 2021 and gas prices began to perk up and you really saw the declines from COVID show up, you saw, particularly in the private market, people started to pour capital back into the space. That accelerated into the start of the Ukraine war, and you saw, production really begin to grow once you got to 2023. We're just not seeing that kind of activity today. I do think there's capital discipline. I do think there's fatigue on behalf of sponsors for private companies. I do think that higher interest rates over the last year or two has made it more expensive to access growth capital for private companies. And I do think you also have some inventory exhaustion amongst a number of private companies. I think people ran really hard in 2022 in the smaller private companies, and some of the mapping work that we've done suggests that they ran through a very large percentage of their inventory, particularly in the Haynesville. It's interesting to see. Getting back to curtailment. Curious, do you think the second wave of curtailment that we're seeing now is it a much smaller in scale than the initial curtailment, what we saw? And then for Chesapeake, specifically, I know the second half guidance does not include any curtailment, but is there a price where it could be back on the table? We are curtailing some volumes right now, so yes, there is a price at which it could be back on the table, and that's what we see today. We think it's gonna be, I mean, first-of-month pricing for September was very weak. We nominated less gas, particularly in the Marcellus, and we will pull back production to match those nominations. We'll have the flexibility to turn that around and deliver more gas in the daily market should the market conditions change, but we really don't see the setup this month as likely for that to occur. I would be surprised if you see the magnitude of volumes curtailed this fall that we saw in the spring, but, I mean, it wouldn't shock me. Right now, I would say the setup doesn't look to be as weak as it was, but we'll have to see where it goes. Great. All right, thanks, Really nice in New York City right now. Despite the fact that we're inside, we are noting that there's not a lot of excess electricity being used this week. Wow, it's... It must be brutal down South because then- No, it actually cooled off- -here ... in the South, too. So, yeah. Yeah. Moderate. Hearing a lot of that. Looking at the 2025 strip pricing today, it's lower than when you first made the decision to defer activity and that built that one Bcf per day of productive capacity. Can you talk about, like, is there a price sensitivity around how quickly you bring that productive capacity back when you look at next year's pricing? Like, but certainly, it's still much higher than where it is this year, so- Sure. So want understand the bookends around that. Sure. We definitely pay very close attention to the underlying supply and demand fundamentals when we think about whether or not we want to plan for bringing those volumes back online or bring them online to start with. Just as a reminder, we have a large slug of wells that have been drilled and completed that we call D-TILs, and then the ones that have not yet been completed, that we call DUCs. The D-TILs are greater in number than the DUCs, and so they take less time to activate, but we have a scorecard effectively, that looks at about 14 or 15 different fundamental pieces of data that we monitor, and it's month-over-month trends in production. It's month-over-month trends in rigs and completion activity. It's some demand metrics. It certainly includes price, but price is really an output of those others. And so we really don't think about this as being purely, "Hey, see a price on a screen, then react." We really think about this as trying to understand the trends, and we really want to only bring that activity online when it's clear that the market has balanced enough to need those volumes to come back. We really don't want to go drop all of those volumes into the market before the market is ready for them. Got it. That's clear. Then, talking about the base production, despite the fact that there's been no activity, the base production from the underlying business is actually a bit better than expected. What's really driving that, and is it a transient impact, or is this something sustaining? Both. Yeah. The transient part of it is that, again, as you have less activity, you have, you know, less offset activity to have to shut in nearby pads when you're completing a well. You have less congestion in the gathering system, so things flow more freely, but we are, we believe, drilling better wells. We're drilling wells faster. We continue to improve our capital efficiency in a very durable fashion, so we think about, and we track, components of our performance in a year like this, and we've bucketed them into deflationary trends, which obviously would be temporary, activity-driven trends, which would be temporary, and then things that we believe we would sustain through the cycle. We tried to highlight some of that in a slide in our last earnings deck- ... where we pointed to, particularly in the Marcellus, some improved drilling times that we believe are absolutely sustainable. In the Haynesville, we've done a lot of reducing of OpEx, which has been great, but the base production in both assets has been strong. And again, there's also a little bit of just focus of the team. When you're doing less with new production, you have much faster turnaround time on any maintenance activity that's needed, and you can be a lot more effective with your base production. So it's better maintenance of the base? I think it's all of it contributes to it, but we do hope to hold on to as much of this as possible. Got it. Can you maybe speak a bit more on the cost deflation side? You guys are one of the few companies, the only one in our coverage, that actually cut spending this round, and some of that is deflation. As you look out next year, how much of that can you retain for when you think about 2025 budget? So deflation in and of itself, if you think about it, it's, it's obviously not just the day rate of a rig, but it's the easiest way to talk about it. It's we still see day rates as relatively soft and softening slightly. I would not... We're not seeing some big step changes coming in front of us, but we are locking those lower rates in for 2025 as much as possible. We tend to have a very rolling contract strategy, so we don't want to be levered to any one point in time where we have a lot of contracts roll off, or we take a lot of price from a particular point and putting a lot on. So this rolling strategy has allowed us to lock in some ever increasingly better rates for 2025. So we feel pretty good about that and holding on to the lower cost structure there. But the lowering of our CapEx on the last quarter call was really as much about the fact that the base is performing quite well, and so we really don't need to be drilling as many wells to hold up production where we had before. In the Marcellus, in particular, we're really hoping to make that a sustained answer for us. In other words, reducing our maintenance capital in the Marcellus permanently. That's a goal of our team. I'm sure we'll hear more about that next year, when we get that 2025 outlook. When we talk about 2025, Southwestern is definitely a big part about that. Can you give us an update on just your latest thoughts on deal timing, and what has the integration team been focusing on during this prolonged closing time? Yeah. So, timing, we said on the earnings call Q4, I think that's still the right answer. We're hopeful that it could be early Q4, but it's really not in our control, and it's hard to predict with any precision. That said, we have had a long time. It's been about eight months since we announced the transaction, and we've really endeavored to make great use of that time. We have a very extensive integration plan that we've been able to pursue. It starts with talent selection. It's the most important thing to get right. In a transaction like this, is to get the right people from both organizations so that you have a true best of both, going forward. I've said to both of our teams since the day we announced this deal, that the new company here should have an ability to perform better, to, deliver a better answer for shareholders than either company was capable of on its own. That's very clear to us, that that opportunity exists, and in order to achieve that, you really have to go into it with a mindset that what we were doing at Chesapeake is not as good as we can be in the future. What we were doing at Southwestern is not as good as it can be in the future, and so everything should be looked at with a, "What is the better answer?" And it's not just is A, the better answer, or B, the better answer. It's often C, which is either some combination or some evolution of what either or both company were doing. So we're really excited about the work we've been able to do there. The teams are divided up into eight or 10 different work streams that we have. It's everything from operating approach, to IT systems, to org design. There's a culture integration effort. We have a really extensive integration approach that we're employing here, and we've been able to spend quite a lot of time working together. Those integration teams are staffed. If there's four people in a particular work stream, that means there will be two from Chesapeake and two from Southwestern. And so this is really a joint approach to creating the best possible company that we can create. One of the key focus areas at the time of the merger announcement was lowering the break even on a go-forward basis. I think Southwestern actually had a higher break even than Chesapeake. So, what are the low-hanging fruits can you attack to bring that break even down? Not just on Southwestern stand alone, but on a combined basis going forward. Yeah. So it starts with the synergies that we identified, right? So one of the big features of the synergies is G&A. That's pretty easy to understand when you bring together two companies of this size. But there's also quite a bit from an operational perspective, from drilling. That's one of the biggest ones from an operational perspective, but you also have longer laterals as you join land positions. You have optimization of aboveground costs, like water disposal. You have optimization of the way that we deliver volumes to market. That's a little bit harder to quantify in that synergy number, but something we absolutely expect to be able to do. And so it starts with those synergies. And then you say from there, now, what can we build upon with our scale, with the better information that we have from that scale, and try to continue to advance how we approach the development of our assets. And one of the things that I firmly believe in is that this company, given its opportunity set, is so different than what either company had previously, is that we should be willing to be disruptive in how we think about what it is that we're trying to do when we lower our costs. We should not be just thinking about taking a few pennies off of the cost of a per foot analysis. We should be thinking about how we really fundamentally change the way that we allocate capital and deliver production to market. And I think our ability to have the capital allocation strategy that we employed this year is good evidence of that. To be able to say that we are going to drill and complete wells on a consistent basis throughout 2024, that we can separate the decision to bring those volumes online to a time at which the market needs the volumes more than we need today, I think is a way to identify what a company of scale and balance sheet strength that this new organization will have, can do, that we couldn't do historically. And I think that's a really key point, is that the financial strength of this organization is significant. We do expect to get an investment-grade credit rating that leads us to a, you know, much more flexible financial position, where you can do things like invest in working capital, which is what we've effectively done this year to have a better answer. In addition to that, something that is difficult to quantify and is not included in that number of synergies that we think is a real opportunity is to expand the way we market our volumes. And we think we can be a lot further downstream away from the wellhead, have better relationships with customers, and capture some of the value chain that otherwise goes to other gas marketers in between us and the burner tip today. Yeah. I wanted to ask about the marketing, 'cause that's an area that you really get really excited about. How does it manifest? Like, how does that benefit manifest in a, should we expect to see more direct LNG contracts or, contract with an end utility? Does it ended up... Are you looking to commit more of the volume in the portfolio to this type of premium pricing- potential premium pricing- Yeah - agreement? I think the key word there is premium pricing, and if you do see premium pricing opportunities, we want to be there and ready to be able to... When you have premium pricing, it means that someone has a need for volumes that is currently not adequately met today, and we want to be able to solve those problems. And if you can solve those problems for someone, then you can earn excess rent. And that's how we want to position our portfolio. We want to be able to show up where and when gas is needed, with the volumes that are required, so that we can fulfill a customer need and get paid for it appropriately. That means that you need to be able to take capacity on infrastructure that historically has been harder for us to do. It means you need to be able to invest in things like we did with the NG3 pipeline in Louisiana that should be online by the end of 2025. It does mean that you should have some allocation in your portfolio for some longer-term contracts. LNG contracts are pretty interesting. They're not without risk, and so we go into those with our eyes wide open about how those should work, how we'd think about mitigating those risks, how we would think about being prepared to set a magnitude, a total magnitude, that we would be willing to be exposed to there. Because at the end of the day, what those end up functioning like is one really large FT contract. So just like we're not satisfied to have 100% of our volumes sold at Leidy and TGP Zone 4 in Pennsylvania, we're not satisfied with having 100% of our volume sold domestically when there are other markets that are underserved internationally. But you also know that those markets, the spread between our market and those markets, will not always be in the money. And when you sign up to have capacity to deliver those markets and it's not in the money, you will pay that demand fee in one way or another. And so you should have a real thought about your portfolio and how much you're willing to expose there. I think we're going to continue to evolve that, and as we become a larger company with greater scale, we can think a lot more constructively about the right ways to do that, but we do still believe it makes sense to have some exposure to international prices and would like to have quite a bit of exposure to international prices under the right constructs, and we're excited that all of the projects along the Gulf Coast really are pretty actively engaged with us, given that we'll have such a large volume of production right there in Louisiana, connected to so many different outlets. We have well over 20 different sales points that we connect to in Louisiana, and that's really helpful when you think about how to be able to meet a variety of customers' needs. So it's really an all-of-the-above approach, and it's really about being able to engage with and be responsive to customers' needs. Got it. You said you mentioned the right construct. What would be the right construct? I mean, the right construct for us would be that we take absolutely no risk in terms of a demand charge, and we get full exposure to international prices. We won't get that, so we'll try to negotiate for what each other needs to land on the right balance of that. It's always a bit of a negotiation. Of course. In-basin demand, or whether you call that data center or behind-the-meter- Right. I think you have a great perspective, being you're in both basins in Northeast and in the Gulf Coast. Are you seeing any differentiation in how those conversations are evolving in different regions? Yeah, there's a lot more interest in in-basin demand projects in the Northeast because you have so much better connectivity and access to market from the Haynesville assets that you really don't see sustained differentials to Henry Hub that drive you to think that you can have a lower cost of supply in the same way that you can have in the Northeast. So we're really intrigued by those discussions. They're going to take some time to figure out. If you were to start today on a behind-the-meter power plant, it would take you two to three years, not including regulatory hurdles. If there are, if you're going into a regulated market with that power, it might take five or six years. So these things are going to take quite a while, but there are a lot of power gen facilities under construction today already that need gas. And we think the power gen market has, for a variety of reasons, really underestimated the growth required to keep up with demand. And so that's showing up today. There's a lot of capital being thrown at it. We're pretty excited about it. You know, when you think about trying to solve these problems, there's all of this demand. The demand, largely, people are focused on the East Coast because that's where the population is. West Coast is a completely different market and will have to get solved in different ways, and it will, and there's plenty of solutions there. But the most relevant place for us is the East Coast. You know, our assets in Northeast Pennsylvania being primarily Bradford County and Susquehanna County, Pennsylvania, they're about a hundred and fifty miles from New York City. So when you think about trying to solve the delivery of data, ultimately is the right way to think about this, you're really not talking about a significant latency challenge. Two hundred and fifty miles from DC, a hundred and fifty miles from New York, two hundred-ish miles to Boston. So, you know, you need three key pieces of infrastructure to do this, right? You need a piece of fiber from the user of that data back to the data center. The data center needs transmission lines back to a power plant, and the power plant needs a pipeline back to a gas source. Two of those three pieces of infrastructure are controversial. You can't really build pipelines, and you can't build transmission lines easily in this country. You can put fiber anywhere. Everyone's eager to have fiber, and so we think locating your projects close enough to population centers where fiber is a relatively easy solution and minimizing the distance of transmission lines and pipelines is the right answer, and so we think Northeast Pennsylvania is a really perfect spot to be focused on this. What does it mean for in-basin pricing dynamics as a result? Ultimately, if you could imagine a bunch of demand being built in-basin, it would mean one of two things. Either no one grows volumes, and you just see some of the supply get used up in-basin, which means the pull out of basin is higher, and therefore, pricing goes up. Or it means that producers are able to grow into those volumes for in-basin demand, and you have a base load of supply that gets an attractive price, and the rest of your volumes are not harmed by that, and you don't see basin basis pressure driving lower, despite the fact that you've been able to grow volumes. It's kind of hard to predict which way it would go, and it kind of depends on absolute price as to what people's return opportunities are there. That's interesting. And what would be the Chesapeake's preference to grow volume? We'd be more than happy to not grow volumes initially and just, you know, dedicate some existing production. We have, you know, at the moment, just under 4 Bcf a day of gross production in Northeast Pennsylvania. We have plenty of volumes we could dedicate to projects like this. That's great. When do you think we'll hear more about this? I think it'll take a little while. Yeah. I don't think this is a next month type event. Yeah, no, of course. Yeah. It takes time. Have you guys picked out a name for the new company yet? Yes. And we'll hear about it with the Hear about it around the time of closing. Yeah. Great. Looking forward to it. Yeah. Any bets? Should we poll the room? Yeah, I'm not sure if it's worth that. I'm sure you'll be getting that. Yeah. Yeah, no, thank you very much. Really appreciate the conversation. I'm sure a lot more to hear about once the deal closes. Yeah. Thank you so much. Yeah, we're excited to be able to talk more about it post-close. Thank you, Betty. Okay. Thank you. Appreciate the time.