Okay, good afternoon. I'm Michael Johnson with JP Morgan, pleased today to have a fireside chat with Nick Dell'Osso, CEO, longtime employee of Chesapeake Energy. Nick, thanks for coming today. I understand you've been on a golf trip with your dad, so glad we got you back safely from that. He was in Ireland and Scotland. I'll start with the easy question: any update on the timing for the Southwestern merger? No, no update. We've continued to say second half of the year. Obviously, we have received a second request from the FTC, which everyone knows. We do have our shareholder vote, occurring here just in a couple of hours this morning. So we're looking forward to being past that step in the process, and then we will continue to work with the FTC to comply with the data request they've had and follow through on that process. It's a little bit of a hard thing to pin down on an estimate of time, so we'll continue to stick with second half of the year. Got it. Safely saying it won't close before the end of this month. Thank you. So when you're combined, you'll be the largest producer of natural gas in the U.S. We're always interested in your view on the macro, but before we get to that, I also want to ask: you've conducted what would have been called an experiment 10 years ago in curtailing production and cutting back on CapEx to let production fall. There was a time in our careers where that would have been somewhat of a suicide move for the equity valuation. You've held up nicely through that. Can you just give us some insight? How was the debate that led you to do that? Was it controversial? Are you happy with how that's gone? It's a really great question, and I would say even sooner than 10 years ago, that would have been a challenge, right? The way equity markets have generally valued companies like ours is they use production as a really important proxy for health. And so if you are allowing production to fall historically, that causes a model to suggest that the company has underlying financial problems or underlying asset problems. I think the market today has recognized that gas in the United States is abundantly supplied and therefore can be oversupplied pretty obviously at times. And at the moment, we clearly have oversupply, but we also have demand forecasted to grow pretty significantly, and so we have pretty steep contango. We debated a lot what the market reaction would be to the decision we made to pull back on activity and allow production to decline. But we ultimately thought it was just a very clearly correct answer for the market overall, which appeared to us to be very clearly oversupplied, as well as for our shareholders in the long run so that we didn't force excess oversupplied gas into a market that didn't need it, generating, you know, little to no profit. So we thought it was the right answer on all fronts. We decided to roll that out on our earnings call that was the Q4 earnings call, which we had in late February. And frankly, I was prepared to need to really defend this to equity holders. I was prepared for a negative response. We as a team had talked about it a lot. We did, you know, some Q&A prep where we expected to get some negative response to that. The market understood it pretty immediately, which I think shows you that there's just a better understanding, a better appreciation of the supply-demand dynamics that are at play today, and the need to be able to be more flexible with your business and how you think about bringing production to market. A couple of things that are really, really important that have changed. The first is that the market's understanding and expectation about what a decline in production may mean for the health of your company has changed, as I talked about a minute ago. That's just no longer the single and sole measure of health that it used to be. The second is that we, along with a lot of other companies, have reduced explicit and implicit requirements to hold production at a higher level. And I'll talk about that just for a second. Historically, we had a lot of commitments around pipelines where if we allowed production to fall, you would have seen our unit cost of gathering and transportation go up pretty significantly. That all changed for us when we went through our restructuring. But in addition to that, we no longer have the same level of debt that we had historically, to put it mildly. And we therefore no longer have that pressure to maintain a near-term cash flow. So what I mean by that is if you think about the volumes that we've allowed not to flow this year, we are foregoing immediate near-term cash flow that we could otherwise have that would be positive. The gas that we're not flowing today would have a positive operating margin despite the fact that in its full cycle would not be attractive to produce. Historically, when we had a very, very over-levered balance sheet, that near-term operating margin was crucial for us to maintain. We really couldn't allow our cash flow to dip for a period of time. And today, we just feel less bound by that. With a healthier balance sheet, with a healthier business overall that has, again, less implicit, less explicit commitments around what our production and cash flow need to be in the short term, we can think more long term. We can think more about what the market needs from a supply-demand perspective. We can think more about what maximizes the opportunity for value creation for our shareholders over time. I think we make better decisions as a result. So I think that's proved out, with this, and we're pretty pleased at how it's gone. We're pleased with the productive capacity we have to respond to growing demand, and we do think demand will be growing and will be growing, as we get into the end of this year and certainly into 2025. The exact timing of that, we will probably never be very good at estimating, and so we'll continue to just be flexible. And how do you unwind that curtailment, some of it is curtailment and some of it is capital reduction, which just takes longer to unwind? How do you think about that? And also, as you see declines basin by basin, are you seeing any surprises? Not really seeing any surprises. If you think about let's start with the declines first, and then we'll talk about how you unwind the declines, what we're seeing today, gas bottomed out around 97 in May. It's back up to around 100. That's all off of being at a peak of around 105-106 BCF a day in January. So what we have today is some artificial decline that's shown up through curtailments as well as through deferred activity. And then we have true underlying decline. Remember, rig count peaked sometime at the very beginning, end of 2022, beginning of 2023. It started falling through the spring, and it reached a relative low point mid to late last summer. It's continued to grind a little bit lower, into the beginning of 2024 and has stayed steady. So it takes quite a while. If you think about when rig count really grew and then and when gas peaked, it was more than a year in between when rig count hit its top and gas production peaked. We should expect the same on the down on, on the down dip, side of this equation. So, rig count really started to come off and, and fell last summer. It's going to take at least a year. We think relative to the 105- 106 BCF a day that we saw in January, you have seen some true underlying decline. You've also seen some acceleration of that decline through curtailments. We've seen in with prices in June being a little bit better, we've seen some of that curtailment come back up. So I don't think we've seen anything that's surprised us. and we don't really think you'll see the true decline show up until sometime, in the second half of this year, probably towards the end of the year. So we have that out there as the underlying decline. And then you think about what, what is happening within our portfolio and kind of bucket our, productive capacity that's available to us in three buckets. The first is the production that was flowing that we have just curtailed. The second are wells that we have drilled and completed and are ready to be turned in line that we have chosen not to turn in line. And the third is, wells that we have drilled but not yet completed. So when you think about the first category, that is immediately available to us. So we started this quarter with a decent amount of production curtailed. I think we told everybody that we started the quarter around 500 million a day of curtailment and that we expected that to decline through the quarter. That's exactly what's happened. And when you think about the demand spike that we should see in the Northeast going into this weekend as it's going to get very hot, we will be ready with additional volumes to bring to market. As demand shows up, we'll be ready to respond to that demand. It's really important for us. We do think about that quite a lot. We think about really being responsive to market conditions is the appropriate way to manage your supply and therefore make sure that the market doesn't ever go short and make sure that we don't push gas into the market when it's just not needed, therefore not valued. So that's sort of bucket one. The fastest, most obvious, easy to bring back bucket two, our deferred turn-in lines. They're almost as easy to bring online. This is as close as you can get to the concept of pushing a button to bring gas online. We do need to go out and start these wells. Most of the time, that takes some physical intervention on location. But it's, it's very easy to be done. These wells are connected to pipe. They have been drilled. They have been completed. We just need to start production. By the end of the year, we'll have quite a few of those wells, ready to flow but not flowing if we don't start sooner. And so what you would see is that we have the physical ability to do all of that in a very short period of time. But the practical reality is that you would layer those in because several of them will sit close to each other. You'll have logistical constraints of personnel required to go and achieve the turn-in line as well as hydraulic constraints on a gathering system. You can't bring on too many wells on the same lateral at one time, for example. So, that could take some period of time to bring those online. But if the market was really robust and that gas was needed, you could bring all of those wells online rather quickly, say, even within a month. The third being deferred completions, and you've got to get a frac crew out and complete those wells. And we'll have some of those, not as many as we will have that are deferred turn-in lines. Those will take a little bit longer because, of course, you have to schedule the completion, get the frac crew, and you can't do all of those at once without hiring a bunch of frac crews at once, which would be inefficient. So, we can respond in phased ways, which we think is important. By the end of this year, we would expect to have no flowing production curtailed and just our deferred turn-in lines, assuming that market conditions are as expected. And we should be in a position throughout the fall if market conditions need the gas to respond with our deferred turn-in lines. And if it doesn't, we can continue to hold those until the market needs the gas. So we're ready to be responsive to market conditions. We'll continue to do that. Got it. That's great. You recently resolved some litigation around your Momentum Pipeline. And in general, we all know that you sell gas at the wellhead, and you got to get it to the market. How do you feel in general about your ability to do that? And are you worried about basis differentials anywhere? Not really worried about basis differentials right now, especially in the Haynesville. Feel good about our ability to access multiple markets out of the Haynesville. We have a good amount of production that moves east of the Haynesville today on the Tiger Pipeline towards Perryville. The Momentum Pipeline that will come online sometime around the end of 2025 will be an attractive additional outlet for us to the south. We have a few other places that we sell gas out of the basin as well. And so we're pretty well piped out of the Haynesville. Importantly, we don't need to grow volumes to fill the Momentum pipe. We will have the ability to grow volumes to put into that pipe should we want to, but we don't need to, and it's not currently within our plan to do so. We can redirect volumes that are going elsewhere to the Momentum project, and send that gas towards Gillis. Gillis is an attractive place to deliver gas. Of course, this is going to end up being, not truly a hub, but an aggregation point, for gas that will be destined for the LNG facilities along the coast. So it's a really important market for us to access, and we have quite a bit of capacity on the Momentum pipe, to deliver to Gillis. So we're excited about that project. We're really happy that that litigation has been resolved, and that project is back on track and, under construction. So it's a great, great project for us. We were really happy to participate in it as an equity holder in the pipe, and really looking forward to its completion. And, you know, the Haynesville, there's a lot of demand immediately adjacent to the Haynesville. There's a lot of market connectivity. So, we see that some of the constraints that were had in the Haynesville in 2022 as production was being ramped very quickly have been resolved as there was a lot of work done. And I spent a fair amount of time talking about this at the time. There was a lot of very near wellhead work that needed to be done. We needed to expand gathering systems. We needed to expand offtake points from those gathering systems. We did all that work, in, in late 2022 and in early 2023. So we have a lot of capacity throughout the Haynesville. Feel really good about that and don't expect to have significant basis bottlenecks in the Northeast, the I don't it hasn't changed. It's the same as it's been. And so there will continue to be bottlenecks. There will continue to be basis challenges in the Northeast. But I think we're all very comfortable with those. We've watched them at play through tight markets, through loose markets, and everything in between. So I think we know what to understand there. You have done, even recently done some, transactions to get your gas onto the global markets through LNG. Can you talk about your outlook for that? And if, if LNG prices tend to be higher, the gas tends to be priced higher on the global markets, how much of your gas would you expose to that market? Why not 50%? Great question. So implicit in doing that, I mean, if you think about getting your gas to an international market, you have to take on some form of contract that looks a lot like any other pipeline contract. It's just much bigger dollars. And so what's your appetite for the underlying commitment of an FT contract? That's the way you need to think about your LNG as well. There's a lot of ways to get exposure to international markets. The first way that we've done is through a transaction that we've structured with Gunvor, that will effectively work as a basis swap for us. We're going to have gas that would otherwise be sold on a Henry Hub style basis, sold on a JKM basis. And so we get to trade what would have been exposure to Henry Hub for JKM. There's cost to doing that. That cost, you can approximate roughly with the cost of liquefaction, shipping, re-gas, etc., to yield the difference between those two markets. So that's good. That's a basis swap. You want to have diversity in where you're exposed to pricing markets. We're really happy about that. We think this will be an evolution for us over time. This was a really good way for us to start. There is an underlying commitment to that, as we've talked about quite a bit. We have the ability to cancel cargoes under that contract over time. It's a mitigation to those costs. Nonetheless, there is a cost. And it's a pretty real cost. And so, as you think about building a portfolio of that over time, and as you have an opportunity to be with a larger company, a company that will be investment grade post-merger, we expect to have more and new and additional opportunities as we build out a much more robust marketing organization to participate more fully in that LNG value chain. That would give you opportunities over time to be exposed to how gas is sold optimally rather than just a direct basis swap. All of those things are going to take quite a bit of time for us to put in place, quite a bit of structure around our business to make sure we're mitigating risk appropriately. And it's going to take a, a significant effort and years to put all of that in place. But that's something that, you know, we absolutely see in front of us as a really important step to being able to diversify the markets to which we're attached and sell our gas. The U.S. market will absolutely change with this next wave of LNG that's coming online. And that's so much more of the demand that shows up in our market comes from these international markets that have very uncorrelated prices to the U.S. And so if you have a big slug of your demand that is uncorrelated to the price at which you sell your gas, you're mismatched with the supply-demand fundamentals. And you need to solve that. So we need to have exposure to international markets, and we'll continue to try to do that in a risk-mitigated, logical, thoughtful way. And it'll evolve quite a bit over time. But we're going to build out a marketing effort, designed to approach that appropriately, as well as maximize the value for the gas that we sell domestically. I want to turn for a second to hedging. But before I do that, this is the harder question that I save for midpoint here. There are large gas producers out there who are saying that the way to build a company that the long-onlys want to own is to be integrated and lower those breakevens. Your breakevens are higher, partly because that's the way the Haynesville works. And they would also say that you should do that in such a way that you don't need to hedge. You've taken a different view, which you say you do hedge. So just explain why your model is better. Sure. First and foremost, one of the reasons why we liked the Southwestern transaction is it gives us an ability to lower our breakevens. We are in the Haynesville. It's a higher-cost basin. We have higher breakevens by definition. But we also, through scale, can grind those breakevens lower. We can drive our cost structure lower. That's really important. That's a fundamental encouraging reason for this transaction. The second is that the scale that's offered with the aggregation of volume, the investment grade rating that we should receive at closing, the marketing presence we will have will offer us an opportunity for higher revenue. That's the promise of the Haynesville, right? Yes, the Haynesville is higher cost, but yes, the Haynesville is closer to bigger market demand, growing market demand. LNG export capacity is obvious, but industrial demand growth is very real in the Louisiana Gulf Coast market. Power demand growth in the southeastern United States is very real, and much ink has been spilled over the last couple of months. Those are all conversations we are better equipped to participate in and either allow us to increase the revenue for our product or decrease the cost for creating the product, all of which lower our breakevens. So very strategically important for us to lower our breakevens. Very important strategic driver for us to be interested in pursuing the merger with Southwestern. It is the fundamental thing that we are taking on, challenge as a company that we're taking on to lower our breakevens. Now, hedging. We believe in hedging. Just plain and simple, we believe in hedging. We produce a product that declines every day, and it's capital-intensive to offset that decline. That means that at any point in time, you can look at our annual CapEx, and you can see that that aggregate amount, regardless of who we are, standalone Chesapeake, combined Chesapeake and Southwestern, that annual CapEx is about what you have at risk at any point in time. And so if prices turn upside down on you in an unexpected way, you know pretty clearly that that capital that you have at risk at that time is not going to earn a return. In fact, you're going to lose money on that capital. It's a big number. It's on a combined basis, it will be few billion dollars. So we think it's not prudent to have that amount of capital at risk with no protection to it at any point in time. You make the decision to drill wells. You make the decision to run rigs with some understanding of what the strip is going to be. You have the opportunity to layer in risk mitigation around that capital that is at risk. We generally do it with mostly collars and relatively wide collars. The last couple of years, we've been putting on collars that you could broadly say are $3 by in between $5 and $6, often over $6. That's a pretty attractive range of risk mitigation to be able to put in place. Yes, you are giving up some upside on that percentage. But generally, we try to think about it as only hedging that capital at risk, which means that we're not giving up the upside on base production, production that's been online, that is flowing, that you don't have incremental capital at risk to being able to deliver. So we have a lot of our production that will remain unhedged, and we can participate fully in that upside. But the year we're having this year, where gas prices have dropped significantly, we're hedged on the capital that is at risk. And that gives us full flexibility to say, i t's totally fine if we don't bring these wells online. We have financial protection for that. We don't need to bring them online. We're still going to collect on those hedges, and we have the ability to bring that gas to market when that gas is needed. So we, we really like the strategy. We expect to continue the strategy. We believe our cost structure needs to go lower. We believe the industry's cost structure is going to face challenges over the next five, 10+ years. We will continue to see costs grind higher on the industry. So we need to innovate and disrupt costs lower. We will continue to focus on that as a company. We expect to be in a much better position to do that as a combined organization with greater scale. I'm going to quickly turn to M&A, and then we'll open a couple more minutes here, and then we'll open it for questions to the audience. The macro for gas, I've heard you say before, and our own research has said is really good longer term between data center demand and LNG, something like 100 BCF a day going to 120 BCF a day of demand by 2030, something like that. At the same time, inventory is being depleted. So my question to you is, do you stick with gas 100%, or do you ever move back into liquids or oil as you've been in the past? For us, it's all about value. We've really enjoyed the gas portfolio that we have, the market position that it creates for us. Our ability to participate in delivering needed product to that growing demand, we think is, is really attractive. So we, we really like all of that. But we don't have a philosophical opposition to owning oil. It just hasn't been economically attractive for us to do it. And I'm not sure that's going to change in the near term. I'm not sure that's going to change in the medium term. So, we don't ever need to own oil again, but we're also not philosophically opposed to it. If the right transaction came about to own liquids that allows us to leverage the strengths of our organization, which are really built around how we drill and complete wells, how we operate those wells, how we bring hydrocarbons to market, we're not afraid of that, but we also don't see anything that's obviously economically attractive to do it. So I would say, you know, we're staying the course for now. One more before we turn to the audience. Capital return framework. You've been disciplined. You've been consistent, with the variable dividend, 50% of free cash flow after the base dividend. Do you feel like you get appropriately rewarded for that in the marketplace, and what are investors telling you? Yeah, I think we ultimately do. I mean, it's really hard to say that when you see periods of time where there's a lot of excess cash flow and there's a high variable dividend, which leads to a very high yield on your stock, that doesn't feel like you're being valued for it. But we all know that in this cyclical business, that is a temporary high yield. And so you shouldn't really be seeing that valued in a full basis. We have a lot of conversations with investors about the optimal way to return capital and the discipline that it imposes in your business by having that optimal solution. And we're pretty happy with where we sit today. We're going to continue to think hard about that over time, and we'll probably, you know, always stay away from absolutes and, and never type statements. But we're happy with what we have today. We have really good engagement with shareholders that like the variable dividend structure. They like generally that we have the flexibility to engage in buybacks when and how we see fit and can do it countercyclically. But the procyclical nature of paying out variable dividends as opposed to feeling pressure to buy your stock when your cash flows are highest, therefore you're likely to have the highest stock price is, we think, a logical approach. Got it. Okay. Now we're going to open up. I see a question here. Wait for the mic, if you don't mind, please. So my question is both for Chesapeake and your view of the industry. We have this first-time-ever situation where production's being managed through curtailments and TILs and stuff like that. When that comes back, there's a flush and there's a higher production. But we're not; you had mentioned the lags before on new drilling. We're not seeing the new drilling. So how does that work out? Because some of the TILs will have a high decline rate. You'll get a component of base plus flush from, you know, the curtailments coming back. But then those aren't going to be filled in fast enough. What are you seeing in terms of Chesapeake's production profile, in terms of a curve shape? I'm not asking for numbers. And same for the industry. Yeah, good question, Ross. So I think we should have the ability to try and manage through a production profile that doesn't fall off a cliff. I mean, I get what you're saying that we can create a sort of artificial cover for the fact that we've reduced activity. But if you think about what we've done is that we really haven't cut rigs very much. We've reduced the number of wells that we're drilling a little this year. And we think we can catch back up to that once we decide it's time to do so relatively easily. So we have thought about that, and it's one of the reasons why we favored the approach we did, which was to achieve the curtailed volume approach by really not curtailing CapEx all that much. We've been able to insert some savings into our CapEx program that allowed us to reduce CapEx over time, over the year. We've been able to defer a little bit of completions. It's, it's relatively straightforward to catch up on deferred completions because you bring on an extra crew for a period of time, and you can catch that back up in your, in your sort of, work plan. And then we can always build back rigs as we need to, and, and you have a little bit of a longer lead time on that. So we feel pretty good about being able to manage this over time. If we were to see some unexpected result, this year going into next year, prices stayed much lower for much longer, and we cut more rigs, then I think that question becomes, you know, at some point you will see a permanent decline in volumes that you're going to have to build back up to. But I think at this point we're pretty well positioned to manage that. Do you want to write here? Hello. It seems to me at least that the inventory, S&D, and even price outlook for gas has improved, much faster than one would have thought back in February. And so I'm just wondering how that has changed your outlook in terms of bringing back that productive capacity towards the back end of the year. It's a good question. You've seen the prompt price show that, right? But I'm not sure that it's really faster than one would have expected given the reductions in rig count that we saw relative to where rig count peaked. And, you know, to follow on to what Ross asked about just a second ago, our program has been a bit more stable, right? We've pulled back a rig, maybe two, for periods of time. So we haven't had this huge spike and huge drop within our program. The industry did, right, in the aggregate. So we expected to see production decline when we had that big spike and then that came off. We are seeing that now. Prompt pricing is showing that. The storage overhang relative to the five-year average peaked out somewhere around 40% earlier this year. It looks like today it's probably under 25%, still a big number to be 25%, over the five-year average, but it is headed in the right direction. That said, storage is about 3 TCF today, and we're in mid-June. And we all know 4 TCF is a pretty full place where you're going to see a definite price impact. So I don't think we've, I don't think we've significantly taken that off the table at this point. I think we're headed in a better direction. But we still have more gas out there at the moment than it looks like is, is needed. Now, you know, we're going to, as we go through the summer and we have weather demand spikes like we'll have over the next week, that won't be true. And we'll, we'll bring as much gas to market as we can to be responsive to that. You know, I think the industry is being prudent in how it's been managed. So I think that you're starting to see some of that in prompt pricing. But the overall storage situation is better, not completely solved. That's it for the time. Thank you very much, Nick. Good to talk to you as always. Yeah, thank you as well. Thank you, Michael.