Great. We'll get started with the next presenter is Expand Energy, and we have with us Executive Vice President and Chief Operating Officer Josh Viets. Josh, welcome. Thanks, Mike. Colby Arnold, their IR group here as well. Anybody—Josh said he's open for questions from the audience too, so if anybody wants to interrupt, please do with any questions you have. I'm going to start, Josh. You guys have had a pretty good handle on the macro, obviously very important for you, a Natural Gas-focused company. I want to just get your latest thoughts. We've had a little bit of a surprise, maybe at least to us, for the amount of production that's come online this year, but nonetheless, gas prices have started to move up. I want to get your outlook for this upcoming year and then maybe a little bit longer term, the next three years. Yeah, sure. I mean, I think we remain pretty constructive on the Natural Gas macro. There's, of course, a lot going on. I think in the near term, we're all very much tied into weather. I think weather and the forecast that we see in the near term has created quite a bit of volatility in the gas markets. If you were to go back to the end of September, we've seen about a $0.65 move in the December contract, and that's largely trading around weather outlooks. We think weather will continue to play a pretty big factor heading into 2026. Obviously, December will be pretty important. I think anytime you get a cold spell where you see high residential usage in December, that can really start to disrupt the Natural Gas markets, even as we sit here today with about 170 BCF surplus in storage. That is a really important marker. Weather models are definitely trending cooler in December, which we see as a constructive sign. It's important to note that as we talk about our production as well, we're very much focused on shaping our production through the fourth quarter in concert with that demand. We continue to remain on track with that. Production in the U.S. obviously is another factor that we pay pretty close attention to. Here we sit at about 108 BCF a day across the U.S. If you kind of think about that in the context of where rig counts have been, we really haven't seen any meaningful rig count additions across the U.S. gas basins with permitting activity being moderated. I think that's simply a function that, as an industry, of course, I think Expand is leading the pack on this, which is just simply doing more with less or simply drilling wells faster where you're able to generate more production per rig unit than what we've seen in the past. That's something that we continue to monitor quite closely. As we look out, really, I think across 2026, obviously, winter weather, how that plays out will be important to create an initial view on how tight the market gets next year. The fact that you can't ignore is that year over year, 2025 to 2026, we expect 4 BCF a day of incremental demand from LNG in the year. That will play a really big role for next year. The next big facility that will come online is Golden Pass. I think the latest news on Golden Pass is that we expect that to start up sometime, take its first cargo in the February time period. That will help support that 4 BCF a day of year-over-year growth. Again, it is a little bit of a story of weather here in the near term, but over the long run, we think the LNG demand growth really will help tighten up the markets throughout the course of the year. I want to talk about your return of capital. You've really been a little bit more focused since the Southwestern acquisition or merger on the balance sheet. Looks by our numbers, you're going to have more than $1 billion of free cash flow next year versus this year. And you've reduced debt by net debt at least by more than $1 billion this year. I guess any change in the allocation or the framework for returning capital to shareholders as you look into 2026? Yeah, we fundamentally believe that having a strong balance sheet is imperative for us, especially within the industry that we work in where you're going to continually see volatility in the commodity. Again, despite this constructive outlook, volatility will be there, and it may even be more extreme than what we've seen in the past. With the announcement of the merger and when it closed in October of last year, we set some targets for ourselves, which was to get below one times leverage and also $1.1 billion of debt retirement. We further enhanced that in the middle of the year where within our capital return framework, we initially said we would reduce net debt by $500 million. We've increased that by $500 million to $1 billion now for the full year. As we think about Capital Allocation heading into 2026, we would anticipate that our net debt reduction target is at least $1 billion, if not higher. We continue to prioritize Capital Allocation to the balance sheet. The way that we think about it is as we find ourselves in a cycle that we are in today where the markets are quite constructive, we are generating a lot of free cash flow, we would be happy to take our balance sheet to a point where we actually have negative net debt. What we think that would position us to do is if we find ourselves in a bearish cycle for a sustained period of time, that really would create a lot of flexibility for us to allocate capital in a way that would create value for shareholders through cycles. I think as an industry, that's really where we've been challenged through times is that inability to, through cycle, generate return for a shareholder. As we build this balance sheet capacity, our focus is going to be in those down cycles to be in a position to buy back shares if that were the opportunity. That is something that we think is going to be a distinct advantage for us and a reason why we haven't been specific about an exact target of how low we want leverage to be. Again, we could see that leverage floating below zero for a period of time and then allowing the balance sheet to balloon to a certain extent as we find ourselves in poor points in the cycle. If you did have that downturn, say weather didn't show up this winter, prices reverse on us, we'd end up with a low two handle or something in the mid-twos, you would be in position to buy back shares at that point. What would happen to the capital program? Because you're planning on growing now, how much would you scale that back or how would you scale that back? Yeah, it's a great question. I mean, one of the things we love about our business is the flexibility that it offers us. It's easy to tell stories when you've done something before. I guess what I would go back to is how we talked about Productive Capacity in 2024, where we continued to drill wells through the cycle, but we materially pulled back on our Completion Activity in the year to start building ducks. We started putting on hold the turn in line of new wells. When we exited 2024, coming into a more constructive 2025, at that point in time, we had roughly 70 wells for TILs, around a BCF a day of Productive Capacity on the sideline to be able to produce that volume into a market where it was indicating that demand is there and the supply is needed. As I think about if 2026 were to be a little bit soft for us, we're always going to be mindful of what is the next, not just month, but it's the next year or maybe even two years. We would absolutely be thinking about the building of Productive Capacity similar to how we managed in 2024. I would just maybe add to that, if we saw that over the long run, so think about like a three to five-year time horizon where the markets were materially changing enough that we had to reset our views on Mid-Cycle Price, that would, of course, lead to a little bit more drastic action in how we think about our capital program. If you didn't have that, it's more ducks and maybe. Deferred tills. Deferred tills. TILs in lines, yeah. If it was a change in the Mid-Cycle Price for whatever reason, then you'd actually think about. That's exactly right. When you look at our business today, we've provided soft guidance for 2026, and we've pegged our production number at 7.5 BCF a day. We've tried to simplify the way in which we communicate our Capital Allocation. 7.5 BCF a day at a $3.50-$4 Mid-Cycle Price, we believe generates the maximum amount of free cash flow for the business. That's what we're simply trying to optimize around. If that view on Mid-Cycle Price changes, we would effectively go and reset what we thought that optimal production level was to get the best free cash flow outcome. We'll talk about that. The Haynesville, you've seen some massive capital efficiencies there over the past year, 18 months. It seems like, and correct me if I'm wrong, most of them at this point have been kind of on the drilling side. As you look forward, if I heard correctly, it sounds like you anticipate more of them maybe coming on the completion side. What changes are you looking on the completion side? I guess just if you can talk in general on what has transpired and then what you see as the best opportunity to take the—I'm curious on the completion side, if you're looking at lowering the prop, and you've certainly used less prop than Southwestern has there, but is that part of the recipe going forward as well? Yeah, we've made a ton of progress in the Haynesville. Of course, underpinning the merger with Southwestern was what we thought we could do with the cost structure in the Haynesville. We started out with $400 million a year synergy that we would deliver over a three-year time period. That's now $600 million per annum, and we'll do that by year two. Bigger synergy target, we're delivering it faster. Again, predominantly, we're seeing those benefits show up in the Haynesville. In fact, right now, when we look at our Haynesville business, we see that business unit level break even at less than $2.75. If you were to go out and benchmark that against any other peer in the basin, nobody can really compete with that in addition to the overall depth of inventory. We truly see ourselves as the premier and differentiated operator within that basin. Specifically in terms of where are we seeing these efficiencies show up, clearly it has been on the drilling side. That has been an amazing story for us. Again, it was underpinning our synergy target. We thought $400 million a year, a relatively modest improvement in 2025 was achievable, but I would say we have exceeded all expectations in terms of it. We think we will continue to see Drilling Efficiency improvements. Every bat that we take, we learn something new, and we continue to refine our drilling procedures to achieve greater efficiencies. On the completion side, that has been a story this year as well, and we expect it to be a story going into 2026. I would say probably the biggest mover that we've seen on the completion side is simply changing the way at which we procure our sand. As we were working throughout 2024, one of the things that we were finding, we just kept getting better and better how fast we were completing wells. You are reliant upon third parties to truck in sand to support that operations. We were finding they were struggling keeping up with the demand that we have. It was at that time we started evaluating additional sources or different sources of sand. We are one of the few companies, maybe the only company operator in the basin today that directly sources from an Expand Energy operated sand mine. We made an investment in a sand mine there. That investment will pay out. It was a little over $30 million. It'll pay out in roughly a year. That equates to around a $50 per foot improvement in a horizontal well cost. We were able to ramp that up earlier in the year. We were deploying it across part of our frac crew fleet that we run, which is around four frac crews. Over time, we'll be able to continue to deploy our sand from our own sand mine to the rest of the frac crew fleet. That will generate additional savings in time. What's interesting about your question, you specifically asked, would we be reducing Proppant Intensity? We've seen a 25% reduction in well cost if you go back to 2023. This year, compared to 2024, we've actually increased our Proppant Intensity by 10% while still delivering over roughly a 15% reduction in overall well cost. We think economically that is a fantastic answer. I can pump bigger frac jobs, do it for less cost, and generate more production. That's why you start seeing the Capital Efficiency improvements that we've demonstrated, where this year we've been able to cut $150 million out of our capital budget. Heading into 2026, you may recall that initially we said we'd produce 7.5 BCF a day in 2026 for $3 billion. We'll now produce 7.5 BCF a day at $2.85 billion. Oh, by the way, that's inclusive of the capital that we'll deploy into our new East Texas asset to appraise that program. Our maintenance CapEx is below $2.85 billion right now, which again is coming from a lot of the operational and cost improvements that I've just described. It's a great story all the way around. I wanted to ask on the Western Haynesville, you've obviously got, as you mentioned, and I think the data backs it up pretty clearly, you've got as good a Haynesville wells or better than anybody else in the basin, depth of inventory. Why the need to go add to that? How do you view this Western Haynesville, an area that hasn't been drilled before? Is it something you're really counting on, or is it more of a kind of a free option? If this works, we've got some upside here. Yeah, well, nothing's free, first of all, but it is absolutely. A cheap option. Yeah, it's a low-cost option. It's something that we've actually been working for a couple of years. We actually started taking leases in the 2023 timeframe. We had pretty good data sets in the region, obviously watching competitor wells to help prove up a concept. At the time, we were looking at a prospect area that we liked. It looked less complex structurally, but it was 40 miles away from the closest producing well. We started slowly building position. We drilled a vertical well late in 2024, doing that under another company's name to ensure we protected the confidentiality of it and keep pressure off of leasing in the area. That vertical well was very successful. It proved the presence of a really good quality shale. That allowed us in early 2025 to really start more aggressively taking a lease position there. Ultimately, we've ended up with a little over 75,000 acres that we've put together for less than $180 million. To your question, we do like this is a low-cost entry. We are a depleting business by nature. We think when you have opportunities to bring in low-cost inventory into the portfolio, you should be thinking about doing that. Roughly $800,000 a location if we assume 200 wells could be drilled in this acreage position. Roughly $800,000 an acre. If you compare that to recent transactions in the Haynesville, $3 million-$4 million a location. We absolutely see this as a low-cost entry and something that we think will serve as a growth option for the company in the future. What's great about this East Texas position is it also provides us with access to new consumer markets. It is proximal to the Dallas Metroplex area where we see growing demand. You still have access being east of Houston, east of Dallas into the LNG corridor. It gives us another market to potentially exploit with our product. Over time, my expectation is I can think about this as an alternative to investments in our existing business as well as we work down cost and the overall economics get competitive with the rest of the inventory. With time, we would expect this to be not just a growth option, but also one that could compete for capital within the existing portfolio. What I am so excited about, and I think is differentiating, we could go add this low-cost option with no pressure to go develop it. It is simply because we have 20 years of inventory in Louisiana of the best acreage that is still available. I could take my time and be very patient and methodical about how I invest and appraise the asset before I ever need it. That, we think, again, is just a fantastic position to be in. Maybe without getting into too much detail, but at least at a high level, I think you said on third quarter call, it shared some characteristics with your legacy assets, at least in that Nacogdoches Fault Zone area. Maybe compare and contrast the new area with your legacy assets. Yeah, most will know that we have a ton of history in the basin. We've been in the Haynesville for well over 15 years. We have a lot of operational and technical experience. Over the last several years, in a more material way, we've been developing the area that we refer to as the NFC or the Nacogdoches Fault Zone. That is one of the deepest, hottest areas in the play, maybe outside of the Shelby Trough. You're developing down around 12,000 ft, and you have bottom hole temperatures that are 370 plus degrees Fahrenheit. We are clearly the most efficient operator within that part of the play. We felt very comfortable being able to take those learnings of developing deep, high pressure, high temperature resources and take that expertise into East Texas. The similarities are that it's highly prolific shale. It's going to be overpressured. It's going to be hot, but you're about 5,000 ft deeper in our East Texas position. We believe the reservoir is going to be down around 17,000 ft. Again, we definitely believe there's a lot of learnings that we can take and apply it into this new part of the play. Is that Shelby Trough you mentioned, is that a better analogy in terms of depth and pressure and temperature? It's a good analogy is what I would say. Yeah. Again, the NFC has characteristics that we deem to be pretty dang similar. Again, we're delivering wells there today in the NFC that are around $1,500 per ft. What I like to talk about with the teams, if today you believe that other operators are developing this Western Haynesville at around $3,000 a foot, if I'm going 5,000 ft deeper, you shouldn't be spending twice the amount of capital to do so. We have really high expectations that we'll be able to bring down those costs, move the inventory lower on the cost curve, and make it competitive with existing inventory over time. You mentioned the new assets do have proximity to the Dallas Metroplex. A lot going on there on the marketing side. I wanted to touch on what Nick said on your call, you want to be more than just a company with some deals on the marketing side. You're really the biggest gas producer in the country, and you're far and away or not close to being the biggest marketer. Maybe give us an update on some of the things you're doing on the marketing side. Yeah, sure. We've been very active. Of course, something we talked about at the transaction announcement, but I'd also just remind you that there was never any contemplation of merger synergies associated with our marketing commercial business. We simply see this as an opportunity and maybe better described as future upside to our earnings growth. The way I would simply describe it is there's really three key pillars within the marketing commercial organization that I think are important for folks to understand is one, how do I achieve a higher price for the product that I'm producing through my equity volumes? That's a goal. Utilizing my infrastructure, using the multi-basin production that we currently have, and being able to redirect flows on a day-to-day basis to get a better price and flowing into premium markets on any given day or any given month. The second pillar that I'd want to point out is how do I facilitate new demand with my physical volumes? I would love to talk more about our LCM, our Lake Charles Methanol deal, but that is a perfect example of how our asset base, the depth of the inventory, the quality of the inventory that we have to produce can really be used to facilitate new demand. The third thing I would just mention that we want to accomplish within our marketing commercial business is how do I reduce volatility in my cash flows? The way you can think about that simply put is something like LCM where you can go out and achieve a premium on a NYMEX price, or maybe in time there's a fixed price sales agreement that you put in place. Something that raises the floor of your cash flow while not capping the upside is the ultimate goal of that business. Again, I think the LCM deal is a great example of what we are thinking about and the opportunities in front of us. Can you maybe just expand on the LCM deal, talk about the opportunity set for, I imagine, more industrial type of opportunities like that out there? Can you quantify those at all, similar size to what you just did with them? Why would, I guess, an industrial customer be willing to do a deal with you at a premium to NYMEX? Why would they not just buy the gas in the market at a discount to Henry Hub? Yeah, it's a good question. I guess maybe where I would start is, are there more deals out there? As we look at the demand fundamentals across the U.S., and maybe focusing specifically in the Louisiana and kind of East Texas area, we see around 11 BCF a day of incremental demand growth occurring between now and 2030. Of that 11, a little more than 2 BCF a day we expect to come specifically from industrial users. We think we are perfectly positioned with our asset base, again, the deep, high-quality inventory to facilitate those conversations. As the largest producer in the region, we would absolutely expect new customers to be lining up at our door talking about how we can facilitate their new demand. You asked the question, why would LCM come to you and offer a premium to an NYMEX? I think there's a few reasons. Back to where I started with the demand picture. If you're developing a similar view to us that I'm in a region with growing demand, that historical strategy of just simply placing my assets next to a liquid hub, simply allowing my input costs to flex with price, we think that dynamic is evolving. It's changing in a way where customers are really starting to think a little bit more holistically about the surety of supply. Again, that's all with the backdrop of demand increasing. I think the other thing that's a little bit different about the LCM deal, and again, that we think is differentiated, is not only do you have this new demand source with a new customer, but they have guaranteed offtake of taking their refined product, in this case, Blue methanol, to a couple investment-grade customers overseas. They see customers on the other side that they've committed to providing methanol, and they simply need to de-risk their overall economics by ensuring they have that supply. The other aspect that I think is important that we can't lose sight on is all of our gas in the Haynesville has been graded as responsibly sourced. Actually, just here in the last couple of weeks, we've gotten reassessed by MIQ with our asset receiving an A grade there. People are still interested in high quality, low cost of supply, low carbon feedstock. That's exactly what we're able to provide them. That's why it commands premium and they're willing to pay for it. It's essentially kind of an insurance policy. That's it. Again, we think that story will continue to evolve over time. Pause there and see if there are any questions from anybody. I can keep going here. You've got your deal with Gunvor gives you some exposure to Asian prices. I guess as you look at your portfolio in front of you, do you want more exposure to international markets? Should we expect more deals kind of like the Gunvor with a marketer type? I know you've talked in the past about making a trip over to Asia, talking with some potential end users there. What would a future deal that gives you exposure to international markets look like? Yeah, of course, we're excited about the Delfin Gunvor deal. It's relatively modest in size. It's 500,000 tons per year. It will start up later in the decade. There's a tolling agreement there wherein we're selling the product on the export side of their ship to Gunvor. That's a decent model, but we are actively out in the markets, again, with international counterparties and talking to them about deal structures that we think satisfy their requirements as a consumer while meeting our benefits as a producer. Much like the LCM deal, if you can connect and vertically integrate across the supplier to an industrial user or a liquefaction entity and then tie that to an end consumer, and you have all of that locked up, we think that's a fantastic answer and helps de-risk the overall investment for the company. I talked about earlier, one of our goals is to reduce volatility. If I just go out today and announce a new tolling agreement without any real clarity on where that purchased LNG is going to go, you're going to look at that and simply, all I can really do here is model that as a liability. It's just an expense. It's a toll. We think being patient here and really work on developing customer relationships across that entire value chain is going to be really important for us. We are going to be slow. We are going to be methodical. We are very much interested in linking more of our commodity that we produce, specifically our equity production, to international pricing. We think it's going to serve us well to be patient and truly present options that look at the entire value chain. You've got a relatively new hire there with your EVP of Marketing as well. Looks like that's going to position you to obviously help with that whole endeavor. Yeah, that's right. I mean, one of the things that I think is so important to recognize is that so much of the time we spend is simply building customer relationships. We have that today. We're actually the largest seller of Natural Gas into the LNG corridor today. We sell about 2 BCF a day. Granted, it's going to be tied back to a Henry Hub price, but we sell 2 BCF a day into liquefaction facilities today. That in itself creates a relationship with the liquefiers. We think that's beneficial to us. They're going to call us first when they're needing new supply. The same could be said. We have a fantastic team. Dan Turco, of course, leads that organization. Given his prior experience trading LNG in international markets, he has been able to bring some of those international customers to the table. We think that, again, provides a strategic advantage for us. I'll be remiss if I didn't bring up the inbasin opportunities for helping supply power. I know a lot of your competitors have talked about it. You saw Google do a deal here in the Midwest for clean carbon power. I guess anything there that we can look forward to that you're working on? Yeah, we have a number of conversations that are ongoing. Really, our goal is to be able to provide that comprehensive power solution. Finding somebody who understands power generation and matching up with our advantaged supply of Natural Gas and then being able to present that option to a hyperscaler. There are a number of conversations that are going on. Again, we need to make sure that the economics work for both sides. We are anxious, but I would say we do not feel rushed. Again, back to our goals of getting a better price for our product, reducing volatility, and creating demand. It has to really check all those boxes for us to feel good about signing up to any type of long-term supply agreement. I know that NG3 Pipeline is in service now. You have an equity ownership in that. Is that something that makes sense to keep inside of Expand? Or are you having conversations about potentially monetizing that? We're really happy with our investment. We believe getting gas down into the Gillis hub is going to be a strategic advantage, ultimately receiving a premium as LNG continues to increase. Today, we're moving about 1.2-1.3 BCF a day through the pipe. Around 700 million of that, or roughly half, is our own equity production. That pipe will ultimately ramp up to about 1.7 BCF a day. I would say that we're in no rush. Clearly, that option is there. I think we've proven over time to be stewards of capital and stewards of our assets. If somebody showed up at the door with something that we just couldn't pass up, we're going to listen to that conversation. Financially, the balance sheet's in a great spot, and we feel no pressure to look at an opportunity to monetize that right now. We love the investment. We think there's a ton of value with it, and we only expect that value to increase over time. I know at one point, and I lost track of it, maybe it was tied to there was a carbon capture idea around that. Is that taking place? Yeah. We have shifted strategies a bit there as we kind of assessed options. The facility where the pipe terminates does extract the CO2. We have put an agreement in place with the counterparty that has a local CO2 infrastructure that runs by the facility that essentially sells them the CO2, where we pay a relatively modest service fee to them to take the CO2. In return, we get a part of the credit that they are generating through a 45Q tax credit. That gets then credited back into the NG3 entity, which then, of course, with our equity stake, we then benefit from that. I guess the benefit not just being the 45Q, but does that help you with your, you mentioned the rating. That's exactly, yeah, that's exactly it. Gotcha. We haven't really touched on the Appalachian assets at all. Anything there that you would highlight? I mean, obviously, you have great assets there. I know there's been some concern about Appalachia getting a little bit long in the tooth. You can say that about pretty much every basin. How do you feel like you clearly, I think, got the best Haynesville wells and the greatest depth there? Where do you think you rank with your peers in Appalachia? Yeah, I mean, we think there's a lot of running room there. One of the things we announced on the last quarterly call was a $57 million transaction to acquire leasehold in Southwest Appalachia, so in and around Monroe County, Ohio. We are pretty excited about the kind of emerging, as you think about the Marcellus kind of shifting west. We think there's a lot of upside with that play. Clearly, you've seen degradation in your productivity per foot measures in places like the Northeast app. That's really just a function that we saw this great opportunity within the upper Marcellus to start developing that. We love the economics. Though the productivity per foot is lower, you're able to drill longer laterals because it's less developed. Of course, when you drill longer laterals, there's a direct correlation to your cost per foot. Each incremental foot you drill in a lateral is cheaper than the last foot. We've really been able to intermix that. As we've gone from basically 90% lower Marcellus wells to today, it's probably closer to 50/50. Yes, it shows up as degradation within the productivity measure, but still our Northeast Appalachia asset continues to deliver some of the lowest Capital Efficiency in terms of the best Capital Efficiency as anybody else in the entire Appalachia region. With that, Monroe County, Bakersfield, Utica, have any potential there as well? Or is it just really focused on the Marcellus? Yeah, right now, a lot of the Utica is pretty maturely developed in Ohio. And so a lot of what we see as upside is in the Marcellus. Any of the assets over there in Ohio has been a particular area that has been a focus of hyperscalers. You see that as an area that you might want to try and expand in? Is there enough opportunity over there to kind of build around a potential drive for power from data centers? Yeah, I mean, we anticipate anywhere from 3-4 BCF a day of incremental demand being created in basin, a lot of that coming from hyperscalers and power generation. Much like the rest of the portfolio, that's another opportunity for us. The advantage we have is we're having assets co-located in basins with growing demand is a great option for the company. As those opportunities mature, specifically in Appalachia, absolutely. Again, we're one of the largest producers there in the entire Appalachia region. Any hyperscaler or power developer is going to be interested in talking to Expand to supply their power generation facilities. Run through my questions. Anybody else have any?