Thanks, Joe.
Well, we're going to shift now from the Permian to the Marcellus and the Haynesville, and have a conversation around natural gas. I'm joined by my colleague, Samantha Dart, and of course, you all know Nick, CEO of Expand. We're going to talk first on the Macro, then on the micro, but before that, we're going to turn it over to Nick to make some opening comments. Nick, what do you think is most underappreciated about the story, and what are your key objectives here in 2026? And then we're going to hop right into the Macro.
Great, thanks. Well, listen, we really appreciate everybody's time today, and thank you all for being here. This conference is a great way to start off the year, set the tone for the year, and think about what's in front of us. And for us this year, we think that it's a pretty interesting setup. And I know Sam's going to ask me a lot of questions about Macro in a few minutes. So to avoid getting too far in front of all those questions, I'll just say that we remain pretty constructive on the Macro for gas. It's been beaten up the last couple of days. That's not surprising to us. While we remain pretty constructive on the Macro for gas, we expect there to be a lot of volatility. And that volatility, we think, comes with opportunity.
We think our portfolio is really well positioned for that volatility, and we think our team is set up to take advantage of that opportunity that comes from it. So we think having really low-cost assets in each one of the basins that we operate, having great inventory in each of the basins that we operate, and then having connectivity into the end markets with the customers that we have really positions us for differential performance. And that's how we're trying to position our business and how we've set up our team, our assets, and our strategy going forward. So we're really looking forward to 2026, 2027, second half of this decade are set up great, and we think there's a great ramp for Expand Energy.
All right. Thank you so much for doing this, Nick. And I want to start with the Macro, and I have to ask you about production. We talked about earlier how U.S. natural gas production has been up over 5 bcf a day sequentially over the past 12 months, and Haynesville has been the leader of that with just about 3 bcf a day of sequential growth during that period. Did that number surprise you?
Yes. It did.
How would you break down the drivers? Let's say, in my head, a lot of that comes from that inventory of wells that had been previously drilled, but I'd love to hear from you how you see that breakdown between, say, that and maybe productivity gains as well.
So the first thing I would note is that our company, having curtailed a significant amount of production, curtailed, meaning curtailed actual flow, as well as stalled our turn-in line activity during 2024, had very artificially low production coming into 2025. And we brought on a lot of production. So we were a significant portion of that increase year over year. But that was well planned, well telegraphed, and again, it was a temporary drop in 2024 due to low prices, waiting for the price to recover at the beginning of 2025. It did. We brought that production back as planned. That strategy worked out pretty well for us. When I think about how much incremental production showed up in the market, we were surprised. We knew that Permian had some new pipes coming on. There was some incremental access to the Gulf Coast.
Our analysis would have suggested that you would have seen modest growth away from that. Instead, we saw pretty significant growth. It looks like it came from a lot of places. The Haynesville was part of it, but it did come from other parts of the country as well. There was definitely some incremental production in Appalachia that I don't know if I would say that in and of itself was a surprise. What that we think was driven by is that Appalachia, of course, is a function of its local demand. Local demand was higher. When local demand goes up, you see production able to elevate because it sits sort of behind pressure there within the basin. That's pretty explainable too. Overall, on balance, I would say, yes, we were surprised.
The question, I think, for us coming into this year is, how sustainable is that at the current price tag? When we think about the forward strip that's in front of us today, what we continue to see is that the strip elevated for a portion of 2025, the forward strip elevated for a portion of 2025, even while prompt pricing was relatively weak. It did that because there was a view of structural demand growth coming, the need for supply growth, and that signal was effective. So we've seen supply growth coming through the end of this year. We are seeing the strip moderate now, but we're seeing the strip moderate to what is a really healthy level. We're not upset about where the forward strip is for 2026 and 2027 relative to the business we've planned for.
We've continued to talk about mid-cycle price expectations of $3.50-$4. It's right where we are when you look at the 2026 and 2027 strip. So we're very comfortable with how the market has reacted. And we think in a lot of ways, it's been a bit more rational than past cycles where I'll use early December as a very short-term example. Early December, we saw a spike in pricing, but that spike really didn't change the character of the forward strip in a significant way. And as soon as it got warm, that came back down. And so you really haven't seen the market asking for big changes in capital allocation. And as a result, you've seen rig count grind a little higher, but not move materially. And we all know rig count doesn't mean what it used to mean.
The business continues to get more efficient, and we generate more and more gas and more growth of gas off of the rig count that we have today, but it's still, you need some movement in capital allocation if you want to see volumes grow materially, and we're really not seeing a huge move.
So to drill a little bit more into those two points, one on using up the inventory of wells that had been previously drilled, and then we'll talk about the rig count as well. I would have expected that utilization of inventory to be done by the end of Q3, just given the incredible sequential growth we saw in production in the Haynesville in particular during that time. And yet it kept coming in. And to your point, pricing during Q4 was actually pretty healthy. So the way that at least I rationalized that was, okay, price is pretty good. If you have anything else that you can bring to market, it makes sense to do that. But are we done with that inventory of wells, or this is just going to keep coming?
I think there's an ability of the producer to shrink its cycle time when it wants to, right, when you're motivated to. You add a frac crew, you run harder, and you shrink your cycle time in order to bring volumes on faster. I'm sure that happened in every company during the fourth quarter. Pricing was great. You could get volumes online in the fourth quarter. You did. Everybody was motivated to do that. It was a very clear short-term signal that I believe the market reacted strongly to. I would also note that in general, the industry has done a better job of timing its turn-in lines on an annual basis around the fourth quarter.
And so for the last couple of years, you have seen the industry do a better job of creating its cadence of turn-in lines or the pace of turn-in lines around the fourth quarter. This year, the timing relative to the way the weather worked out brilliantly for that. And I think companies will show some pretty good fourth-quarter numbers as a result. But overall, is it sustainable? Is this level of production relative to the level of rigs that we have running, frac crews that we have running across the industry? Is it sustainable at this price level as we go now into the spring, get into the shoulder months again? I don't know the answer to that question definitively. I would say the efficiency of the industry does continue to surprise us to the upside.
The industry continues to be able to deliver more gas to market with the dollars that are being spent every day. And we think overall, that's great for investors. We think that that means the industry is just more efficient. We think our company is leading the way in that efficiency step change. And I think some of it will be sustainable, but if we continue to have pricing that hangs around $3.50, I just don't think you have a producer that is motivated for growth. I think the marginal break-even for growth in this country is above $3.50.
Got it. Switching gears a little bit from production to demand. From a power demand perspective, how has this impacted what you guys are seeing, and what do you think is already priced in versus underappreciated by the market going forward?
The power demand story is super interesting. What we're seeing here is that weather-adjusted gas burns are pretty good in 2025. Not weather-adjusted, you can see things being a little softer. You definitely saw coal come back with some market share. You saw renewables had a strong year in 2025, but bring it back to the weather-adjusted number, and it's pretty strong, and the only explanation for that is that power is running harder, and the driver of that, of course, is the data center story. We also think that the visibility into that is not the same as it used to be. You have more and more distributed power systems that are functioning pretty effectively at powering data centers. You have more behind-the-meter setups, and so it's a little bit harder to see all of the demand and see all of the supply that flows to it.
We think a lot about is 110 bcf a day, depending on your source. You might call it 110, you might call it 111, you might call it 108. We're looking at something right around 110. Is that the real number of supply right now? Is it potentially a little bit overreported? Is demand underreported? We think all of those numbers end up being a little bit fuzzy on interstate pipes, and we don't have the exact answer to that. But we think the market is not super loose right now. And again, we're pretty happy with the setup as we go into 2026 and 2027, knowing that when it's really warm in January, you're going to have volatility. It's what we have right now. It's pretty warm.
On the point of volatility, and I want to bring this to the international market a little bit and on a couple of different points. One has to do with this internal question of, is Russian gas going to go back to Europe? Is there a peace deal? No peace deal? How do you see that evolving? But more importantly, if there was a peace deal, would you expect that to impact Henry Hub indirectly?
Indirectly, yes, it has to. So from the very beginning of this war, I commented to people that Russian gas is too valuable, too large and too valuable of an economic good to stay in the ground forever. It just won't. So whether that means it's going to flow to the allies of Russia only or it's going to go back to Europe, go back to 2022, I wasn't feeling like anybody had enough visibility into answering where it was going to go. But the fact that it would be in the market, I felt confident that it would come back. And I still feel that's true. I think the likelihood of it being directed, at least partially, back to Europe grows every day. And so I think that will happen.
So then I think you have to just look at the overall supply-demand dynamics and say, well, what's really going on in the way that the world accesses the supply of LNG and cross-border gas flows to understand the balances and what that means for each market, inclusive of Henry Hub. And what we continue to think is a main driver there is the fact that you have pretty robust energy demand growth worldwide. We had the session yesterday afternoon where Arjun talked about it quite a bit. Damien and others have talked about it quite a bit. Long-term structural demand growth for energy is high. Natural gas is the most efficient, most effective way to respond to that long-term demand growth signal. And we feel good about that.
And the way that shows up is that you see the elasticity of demand for LNG functioning a bit differently than you see the elasticity for demand of natural gas, say, onshore in the U.S., where we have a pretty well-connected grid and people access the gas they need on a day-to-day basis, regardless of price. When you have lower prices internationally, you see demand for LNG go up. And one of the important demarcation points is $10 JKM, and then you see another pretty significant increase at $9 JKM. You do see coal switching show up as an important driver of economics. But if you come down to the levels of coal, you still then start to think about what the marginal cost of transportation is. It will have some derivative effect on Henry Hub. It absolutely has to.
But I think it's a trend that will be absorbed.
And one last one from me and along those lines. When we look at it, even without including additional Russian gas, our base case is that global LNG supply is going to grow enough that we see ex-US balances becoming overwhelmed by 2028, 2029. So we do see the turnback of U.S. LNG as more likely than not in those periods, in early 2028 and early 2029. Not forever, but periods of pressure. Do you share that view, and what is your price view in an environment like that?
So the first thing I would say is that we absolutely expect the price of LNG to be cyclical in the same way that the price of natural gas in the U.S. is cyclical. And so when you see growing supply, and we have a lot of supply growth in process right now, you should expect that to show up with a down cycle to price at some point. The supply growth that happens as it comes online is lumpier than demand growth is, and you will always have that lag effect. And so we absolutely believe in that cyclicality. How much it results in shut-ins, volumes, or curtailments of capacity for U.S. LNG is something that we don't have a ton of clarity in at this point.
We know that you have to get below the marginal cost of delivery to make that happen, and that's a pretty low price. But cycles work in a way that you almost always will find the price at which you reduce supply to the market at some point. And the U.S. is one of the markets where you should see some supply moderation over time. And so it won't surprise us if that happens. How long it lasts, I think we're probably on the shorter end because we do think that the demand reacts pretty favorably internationally when you see very low prices? And again, we think that overall demand is just growing structurally. So there's a lot of supply coming. It will be lumpier than the demand growth is. And we will test what it takes to curtail volumes, at least for some period of time.
We don't think it lasts very long.
Thank you.
Thank you, Sam. Nick, let's talk about your hedge-to-wedge strategy, which has proven to be very effective in an environment where the '26 curve has lived above where Spot, I think, potentially is going to realize. So how are you thinking about that strategy where you're hedging eight quarters forward? And is the market still giving you the signal to be ratable with that?
Yeah. That's a great question. So there's a couple of different things I want to comment on here. The first is that why we do what we call Hedge-to-Wedge. And the reason for doing this is really about protecting the capital that we have at risk at any point in time. When you think about the way our business runs, the cycle of capital is a few years. It takes two to three years from the time you decide to drill a well until that well is actually drilled, and then that well comes online and generates enough production to pay it back. And so if you want to be efficient with your capital allocation, you'd like to not react to prices that move inside of that period of time. You make a decision to deploy capital, you'd like to have some certainty of return on that capital.
We know the cycles of gas are shorter. The cycles of gas prices are shorter than the cycles of gas capital allocation. So you see price fluctuate a lot more frequently than the two- to three-year cycle of capital allocation. That just tells you by definition, you should be hedging your nearer-term price exposure. If you want to look three years out and have a different view for price, great, change your capital allocation. That's easy. Cut your capital, grow your capital, respond to prices over the long term. In the near term, you cannot possibly respond with capital allocation in an effective manner. You will always be chasing your tail around trying to time the market with a rig count that can't respond fast enough. So we're big believers in hedging that near-term price risk.
That's why we've chosen that eight-quarter period, and that's why we think about it in a relatively methodical way. Now then, how do we do it from there? Well, a part of that then becomes thinking about instruments that we use. We, over the last couple of years, have been in a position given what the market has offered us to use a lot more collars. And that allows us to maintain a position in the market or express a view around market pricing that demonstrates that we believe that while we should be protecting the downside relative to volatility that can't be forecasted, we should also be maintaining exposure to upside that can't be forecasted in the same way. And we're able to do that with collars in a really attractive fashion.
When we see pricing that either because where it sits on the curve we just think is elevated more, or we see a level of risk around the potential events of volatility to the downside, then we'll lean more into swaps for those periods of time. And we've used both instruments pretty successfully, and we've set ourselves up with a pretty attractive hedge book relative to the forward curve and relative to what we think mid-cycle prices are. So yeah, we absolutely expect to continue to do that. We think it is the right way to manage a business like this. Our goal is to create lower volatility of our cash flows over time. You see that through how we allocate capital. You see that through how we hedge. You see that through how we try to leverage our customer relationships.
You've been very clear that $3.50-$4 is the right range for you. In periods of time where the curve has moved above $4, you've been pretty aggressive in terms of locking it in.
That's right. That's right.
And then you have a couple of different areas where you can allocate capital now. It's not just the Marcellus. You also have the Haynesville. So as you think about the 2026 plan, what's the right mix between the Marcellus and the Haynesville? And can you also comment on the Western Haynesville, which is a new area that you're starting to develop a strategy around?
Yeah, absolutely. So our capital allocation across Marcellus and Haynesville is pretty stable year over year. A couple of reasons for that. One, the Marcellus remains a relatively constrained basin, so there's not an effective way to allocate significantly more capital there and grow volumes. You could grow volumes at these prices in the Marcellus and make an attractive return, but if you could achieve the same pricing, you can't. So your marginal growth volumes would receive a lower in-basin price and would not receive an attractive rate of return. In the Haynesville, we're very comfortable with the volume profile that we have set. Again, it is designed around the mid-cycle price of $3.50-$4.
We've been providing that chart in our investor deck for some time now that really tries to frame for investors how we think about an optimal level of production relative to a view of mid-cycle prices. 7.5 bcf a day when you take our Marcellus volumes that are going to be relatively flat, and then you fill in with Haynesville volumes, optimizes the cash flow creation of our company at a price of $3.50-$4. So we're very comfortable with that. We don't think that changes significantly until we decide that mid-cycle prices are different in our view. So then you asked me about the Western Haynesville. Western Haynesville is pretty exciting. We've been looking at this for quite a while. We made our position there known during our third-quarter earnings call, but it's something that we've been working on for several years.
We've been taking some leases. We've been doing a little bit of science. We had a pilot project there. Really liked what we saw, and then we had an opportunity to acquire a chunky amount of leasehold. What we really like about this is if you think about the A&D market over the last year, a lot of the deals that have been printed have been pretty high value, and that makes sense. In an environment like we had in 2025, where the forward strip for gas is pretty robust, especially people that are relatively new entrants or managing an international portfolio of exposure where they're short US gas, they're willing to pay up to gain entry to this market. We really haven't felt compelled to compete for those transactions at those values.
When you think about the cost of inventory embedded in some of the transactions that were announced in the Haynesville over the last year, it's $3-$4 million per location. What we did in the Western Haynesville is saw an opportunity that we thought the inventory was very attractive relative to other inventory opportunities in the Haynesville today, and yet it was priced at something well under a million dollars per location, given that it's an acreage purchase without production and given that it's in an area that's a little less proven. Now, again, we have some real data there that gives us some confidence in what we're chasing, and we feel good about our ability to execute on this, but it is very early. We're in the process of drilling our first well, our first horizontal well.
What we know about this area is that there is plenty of gas in place. We also know that the cost will be relatively high. It is deep. It is hot. We also know that in the deepest and hottest parts of the play in the MFC on the Louisiana side, we have a large position there, and we are far and away the low-cost operator in that area. We can deploy our learnings from that area into this region, and we believe be a cost leader here as well, acquire inventory at a relatively attractive cost relative to other things that are out there, and we can understand whether or not we have something here that's productive. We're pretty excited about what it looks like to us, and it'll take us a little bit of time, though, to know what we really own.
Yeah. Nick, what does the A&D market look like? Because again, at the strip, your stock trades on our numbers close to a 10% or 11% free cash flow yield. It looks like some of the implied deals that have been done in the private market look like a 7-8% free cash flow yield. So there is a big arbitrage between where the public market is willing to value gas assets versus the private market. Why do you think that is? You alluded to part of that. And have you seen some convergence?
I don't know that we've seen a lot of convergence at this point. I guess I would argue that what you're pointing out suggests that our stock is undervalued, and I think I might agree. Shocking. But I think we do have some folks out there that look at the U.S. market as a place they need to be, and they've been willing to pay up for it. Again, cyclicality, volatility will be the ongoing trend that will always drive this industry. And so we just really don't see the need to play aggressively for assets during a time when prices are relatively robust on the forward curve and people are pricing into those transactions a gas price that is probably above our mid-cycle price, we think, in a lot of those deals. We're just not going to be participants in processes that price that way.
Instead, we'll look for where we think we have a strategic advantage to acquire opportunities to drill wells in the future where we believe we are pricing in assumptions that meet or beat our mid-cycle expectations.
Yep.
Generate an attractive rate of return.
Nick, one last one for me, and I'll turn it to Sam. I think some of the feedback we've gotten on the Western Haynesville is the concern that some of the zones are hot and deep, and there's a view that it's pretty high on the cost of supply curve. So can you lay some of the market concerns that might be there?
It is high cost. There's no question about it. It is higher cost than some other areas. But again, we have assets that are high cost today, and we're able to drill those pretty attractively. In the MFC, which is the higher cost area on the Louisiana side, we sit at about $1,500 a foot for drill completion turn-in line in aggregate. We think we can replicate that kind of advantage, and our peers are significantly higher than that, 20%-25% higher than that in a lot of cases. We think we can replicate that kind of advantage in this asset as well. We have a lot of experience around the technologies that help to operate in deeper, hotter environments. We're deploying those in this area as well.
Again, we're just in the middle of the first well, so early, and we'll allow our results to speak for themselves over time, and we'll find out what we have. But we like the opportunity that's in front of us. We like the entry into this portion of the play, given the strategic advantages that we have, the historic advantages that we have, the data, and the ability to use those tools and technologies around what we've learned in the rest of the play for our benefit to create something pretty attractive here.
One last one for me. Marcellus Basis, it's obviously been a challenge for going on a decade now. In-basin demand should be growing very nicely. We saw it with Homer City, for example, but I think there's going to be a lot of data center development, as Sam was talking about this morning. And then you also wonder about, is there a pathway to evacuate gas out of the Northeast PA area into the Northeast again if there's some changes in rules with things like Constitution? So just your view of, can Basis get better, or is this something that we're going to be living with for a long time?
I do think Basis can get better. I mean, I think you have such an increase or a, I wouldn't even say an increase. I'd say you have a recognition of the demand that is unmet for energy throughout the country today, and that really shows up in the Northeast, where you have much higher energy prices than you have in the rest of the country for no good reason. You have proximity to supply that should give the Northeast quite an advantage, and we just don't see it show up. You are seeing a very slight change in the sentiment around infrastructure and around what it means to have affordable energy in all parts of the country.
A big part of that comes from the fact that you have very large companies that historically the Northeast part of the United States has viewed as good neighbors, good local partners. If you think about the city of Boston being a tech hub, and you think about Amazon, and you think about Google, and you think about companies like this that have had significant investments in markets like Massachusetts and the Northeast for a long time, those companies are absolutely not talking about building data centers in those regions, and if you're a governor in one of those states, you're realizing that Ohio is crushing you. Texas is crushing you. Louisiana is crushing you, and these are real investments for high-tech, really good jobs, and great tax base, more importantly, that are going to other parts of the country, and your citizens are mad about it.
You're mad about it, and that is driving a change in the view of what it means to have access to affordable energy. And so I think that's really productive. I think that's really healthy. I would just note that, again, the returns on the Marcellus drilling are fantastic. And so a little bit like the Permian, where when you see incremental infrastructure built, it gets filled immediately. Same thing will happen in Appalachia. And when it gets filled immediately, then that basis will come back down. So look, even with the weaker basis of the Northeast, the returns are phenomenal. And growing volumes out of the Northeast is something that we would do with access to incremental infrastructure without question, and others would be fighting for that space to do the same thing. So it will be a market share race as that infrastructure gets created.
Thanks, Nick. Sam?
Just one more. I'm curious as to what your view is on Haynesville growth inventory from here. When we look at the potential for U.S. gas demand growth between now and the end of the decade, LNG cycle aside, I agree with you that's going to be temporary. It's going to be relatively short-lived. And at the end of it, we go back to exporting full-on, and we have more export terminals coming on. You put that together with power demand, together with industrial demand, we see something close to 18 Bcf/d or so of additional gas demand over the next few years. And even if Permian is growing, I don't know, 8 to 10, that's not going to be enough to cover for it. So how much more can Haynesville grow? What's the inventory?
If that's not enough, what would you see as the next best thing to be developed in the U.S.?
So what are we talking about for Haynesville? To me, when I think about Haynesville, I think of the traditional core of Haynesville as sort of one area, and then I think of the Western Haynesville, East Texas, as a different element of it. Now, some of that traditional part of Haynesville does extend into East Texas, north of where our Western Haynesville position is today. And I think that area, that traditional Haynesville position, can grow a few more Bcf a day, but it cannot grow eight. Absolutely not. And so that means you will be looking to East Texas. You will be looking to the Mid-Continent. You will be looking to higher-cost assets, which fundamentally changes where the break-even locations are in the U.S. and what the cost is required to activate those break-even locations.
And so I think for us, sitting in the Haynesville with 15-20 years of inventory that is break-even at $2.75 today for us, we sit in a great place to see our margins grow while the marginal break-even of the industry moves into other plays. We're very pleased with that setup. We do not think that Haynesville is capable of fully responding to the demand growth that's in front of us, and we think that just yields a higher margin for our business.
As we go along that supply curve to more expensive areas at the margin, what kind of level do you reckon we're talking about? Around 4, around 5, higher?
It's a sawtooth, right, where you have higher prices that encourage you to activate, and then you get better at that, and it comes back down, but I think you're going to need to see $4-$4.50 to really see that kind of demand growth, really see that supply growth to meet that demand initially, and then you may see, again, more step changes higher as you push higher on that curve.
Yeah. That makes sense. Thank you.
Thank you, Sam. Thank you, Nick. Great conversation. We appreciate you taking the time.
Yeah. Thank you.