Expand Energy Aktie

Good day, and welcome to Expand Energy 2026 First Quarter Earnings Teleconference. [Operator Instructions] Please note that this event is being recorded.

I would now like to hand the conference over to Brittany Raiford, Vice President, Treasurer and Investor Relations. Please go ahead.

Good morning, everyone, and thank you for joining our call to discuss Expand Energy's 2026 First Quarter Financial and Operating Results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday.

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our press release yesterday and in other SEC filings.

Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure that can be found on our website.

With me on the call today are Mike Wichterich, Josh Viets, Marcel Teunissen and Dan Turco. Mike will give a brief overview of our results, and then we will open up the teleconference to Q&A.

So with that, thank you again. I will now turn the teleconference over to Mike.

Thanks, Brittany. Good morning, and thank you for joining our call. The team delivered another solid quarter. Honestly, they make great execution look easy. Over the past 2.5 months, I've had the opportunity to work with our team and spend time with our customers, speak to potential domestic and international counterparties.

I got to tell you, I'm more optimistic today about our industry and company than ever. There's no disputing our industry is in the midst of a major demand growth. The big 3 drivers of demand, AI power, the reshoring of heavy industry and global LNG growth are converging to make the future bright for natural gas. All of this was happening even before the recent events of the Middle East. So now in addition to structural demand growth, energy security has pushed the U.S. natural gas to the forefront. Expand is uniquely positioned to take advantage of these events. Simply put, we have positioned ourselves to be in the right place at the right time.

For example, our Gulf Coast assets sit at the epicenter of LNG. In fact, our largest customers today are LNG facilities, and there is an increasing recognition of the strength and competitive advantage of our Haynesville position. According to third-party reports, today, we own 72% of the lowest breakeven inventory in the basin, allowing us to deliver certified natural gas directly to LNG facilities with minimal risk of basis floods. Fundamentally, we see LNG as a natural extension of our business.

Demand in the region is not just LNG, AI-driven power and industrial demand is rapidly growing in the region. When you combine structural demand growth and energy security, we believe the Gulf Coast is well positioned to become a premium priced market. Our Appalachia assets sit at the core of AI power demand. We believe the Northeast will soon see demand growth of 4 to 6 Bcf per day. In-basin demand growth will unlock pipeline-constrained production. We're also seeing a renewed optimism to build infrastructure to serve more Americans in the Northeast and Southeast markets. In-basin demand growth, combined with new infrastructure will unleash our low-cost inventory and create substantial value for both Expand and our shareholders.

Now let's turn our attention to the first quarter. Financially, we did well. We generated $1.7 billion of free cash flow, inclusive of working capital inflows. True to our word, our strong cash flows were used to reduce gross debt by $1.3 billion and returned over $290 million to our shareholders through base dividends and buybacks. Operationally, like our peers, we kept Appalachia assets running with an impressive 98% uptime during Winter Storm Fern. Our Gulf Coast assets were impacted by the storm, resulting in some shifting of CapEx from first quarter to second quarter.

Importantly, our full year production and capital guidance are unchanged. A lot of you and frankly, a lot of our peers are anxious to hear about our progress in the Western Haynesville. Early production results from our first well have been encouraging. We are pleased with our execution and cost competitiveness on the well and have more wells planned this year. So stay tuned.

Last year, we made tremendous operational improvements, but we see room for continuing operational improvements across the portfolio and are excited about the early impact of machine learning and AI is having on lowering costs, enhancing well productivity. I see this as our own self-help program.

Marketing and commercial has been our primary focus for the quarter. As promised, we have attacked this opportunity with discipline and urgency. The time is now for us to improve our margins, grow cash flow per share. Our goal this year was to increase the number of commercial opportunities evaluated to ensure that we are achieving the best risk-adjusted returns for our shareholders. I'm happy to say we've made great progress on this front.

On our last call, we stated the size and the price of this effort is about $0.20 of margin improvement, which equates to approximately $500 million of repeatable incremental free cash flow per year. We do not believe that we have to swing for the fence searching for one transformational deal. We will be disciplined and create value by stacking singles and doubles across 3 general categories: First, reaching premium markets. Our expansive footprint across 3 different operating areas gives us access to more customers and options to optimize our flows. To be clear, we are changing our mindset to be a more customer solutions-focused company. In the past 6 months, we've added the combined 0.5 Bcfd of term sales and firm transportation to end users, extending our reach to premium markets.

Second, monetizing volatility. In the first quarter alone, we generated nearly $90 million of incremental value, a great example of how we can capture and monetize the volatility we see in the market. While this was primarily driven by unique events, these are the types of gains we're looking to achieve more sustainably. Finally, facilitating and capturing new demand. Today, we announced a new offtake SPA with Delfin LNG for 1.15 million tons per year, extending our market reach to global demand centers. We see great value in this transaction as it's bigger, reaches market sooner and cheaper compared to our previous agreement, which has been terminated.

Our LNG strategy will be dynamic and shaped by the economic merits of each agreement, partnership or joint venture. We will take a portfolio approach, continuing to add to our LNG opportunities over the next several years with different types of contracts. In parallel, we'll continue to pursue opportunities to broaden our power sector customer base, supplying natural gas to a growing number of power generators, load serving utilities and increasing our exposure to data centers and hyperscalers.

We have no doubt that Expand is built for this moment. Why? We're the largest natural gas producer in North America. Counterparties want to do business with someone who's going to be around for the next 20 years. The depth of our portfolio, combined with our investment-grade balance sheet, provide that confidence. We are in the right place at the right time. Nearly 90% of expected U.S. demand growth can be served by our assets.

Lastly, we have a team that can execute. We reset the economics of our Haynesville position last year. And today, we continue to see opportunities to extract more value from every dollar of capital we deploy across our portfolio.

Before we take your questions, I would like to take a moment to thank Brittany for her service as Interim CFO. She did a terrific job. I'd also like to welcome Marcel Teunissen to the team as Executive Vice President and CFO. Marcel is the kind of leader who can elevate our entire organization. He brings deep experience that aligns perfectly with the opportunities we've highlighted today. I'd also like to note our CEO search is progressing well and remains on target for the time line I presented on our last call. However, the team is not waiting around. The Board and management team are fully aligned. We are executing our plan today, and we see numerous paths to reaching more markets and improving our margin. Thank you.

Operator, please open the line for questions.

[Operator Instructions] Our first question comes from the line of Matthew Portillo with TPH.

I wanted to start out on LNG. Could you perhaps discuss why the Delfin LNG project was attractive to Expand? And then maybe more broadly, could you talk about your thoughts on the global gas market as it relates to supply-demand balances and how this might play into your LNG marketing portfolio from a time-to-market perspective?

Great. Thanks, Matt. This is Mike. Number one, our LNG strategy is really an extension of our Haynesville. We think about it more broadly than I believe most, which is we think about, first, delivering gas to Gillis, which we think will ultimately be a premium market because it's connected to all the LNG facilities. In fact, LNG facilities are our biggest customers today.

When we start to think about on the water, of course, LNG, we think about that as international pricing. We want exposure to the prices, whether it be JKM or TTF or others. Delfin is the start, and we'll call it a foundational sort of contract in order to sort of to capture the LNG market opportunity and the premium pricing. It kind of flows into our bigger marketing plan. When I think about the 3 different sort of categories, we want to be in premium markets. We think LNG will do that as we move into Europe and Asia.

Two, of course, volatility. It's a different volatility sort of shape than our Henry Hub exposure. And then, of course, new demand, that's a new facility that's getting built. And so it is actually helping new demand in the area. And in fact, that gas will come from both Sabine Pass and Calcasieu Pass.

Dan, why don't you tell them a little bit more about the details?

Yes. Thanks, Matt. So as you know, we originally had an agreement with Delfin in Vessel 2, and we had this opportunity where our conditions precedent date passed and we terminated that contract. And as Mike said, we believe in the global LNG demand here. And so we had the opportunity to look at Vessel 1 and take out a larger position. And important to that is we terminated the back-to-back contract as well.

So as Mike alluded to, this gives us all the integrated strategy that we're trying to do, facilitate that new demand through that SPA, reach premium markets, get that asymmetry and importantly, have some of the control on the water, either ourselves or through long-term partnerships where we can create more value and take a portfolio approach to our supply position and our sales position downstream, offer different terms and tenures of sales and also different indexations.

The other important aspect I'd point out here is we're trying to integrate this through our value chain. So we have a long-term partnership with Delfin. We're negotiating with them right now to be the gas supply manager. So we're integrating it right through our value chain. That differentiates us and brings more value to us, and we think brings more value to the customers. We're able to offer different solutions.

Great. And then maybe as a follow-up on the marketing side. If we look out over the medium term, at least to us, it feels like it might be a bit of a challenge given the inventory exhaustion for smaller producers around the Gulf Coast to maintain a supply level that can keep up with demand growth over the next few decades. And I was just curious if you see an evolution in Gulf Coast supply-demand balances? And specifically, do you think we need to see more pipeline capacity coming out of the Northeast to help bolster supply on the Gulf Coast over the medium to long term?

It's Mike again. Generally, we agree. We agree. We have a lot of demand coming to a very small area that's, of course, near our Haynesville asset. So we feel pretty well positioned, and we're fortunate to have a deeper inventory than most. And so we'll be able to go a lot longer than everyone else.

Long term, when you start thinking about 20-year contracts, of course, you need to find other supply in different basins. That, of course, can come from the Northeast. We're always worried about, can it be done or not should it be done. We definitely think it should be done. So more gas will have to come from Appalachia. And of course, we'll benefit from that on our own assets. And of course, everyone knows that there's going to be more gas that's coming from the Permian as well.

Our next question comes from the line of Doug Leggate with Wolfe Research.

Marcel, I welcome, first of all, I wonder if I could take advantage of this being your first call. You obviously joined from a retail company, but you have a tenure at Shell, long tenure with Shell before that. So I wonder if you could maybe just share with us why did you take this position? What do you think you bring to the table? And if I may, on that last point, we know Mike is very keen on getting the breakeven down and marketing is a big part of that. So I wonder if you could share your thoughts on how you think you fit into that strategy.

And I guess my follow-up is on one of my favorite topics, which is cash return on balance sheet. You appear to have inherited a pretty stellar balance sheet in the first quarter. My question is, when you think about hedging, when you think about volatility, what is the right capital structure in terms of balancing things like cash returns versus continuing to delever?

Great. Thank you, Doug. Thank you for the question. It's a pretty long one. So it's good to get out there. So maybe just by way of...

Part A and Part B.

Yes. Okay. I'll take them all. So my -- just by way of my background, so I've been in the energy sector for almost 3 decades, and I've worked in the upstream, the midstream, the downstream on the oil side, the gas side and also in every part of the world, so bring an international perspective on that. And I've done finance jobs, obviously, but also commercial corporate development strategy jobs and operations.

The last 5 years, as you mentioned, I've been in the Canadian downstream company, really on the customer demand side, working on optimizing the integrated margin, capital allocation and the likes. And prior to that, I spent almost 25 years at Shell, which the last many years on Shell's integrated gas business. So that's how I kind of come to the job.

And then to Expand, I think most of it has been said by Mike, right? I think the Expand platform is just incredible in terms of its size, in terms of its positioning here within the U.S. And it's at a time that the energy market is really both in the U.S. and globally is going to transform fundamentally, and we're well positioned.

And then you look at the strategy, where we are we want to capture more value by being integrated into that value chain. And that's where I bring a lot of kind of experience and background. And so I'm excited about the opportunity and what we can do here with the team, incredible people and as I said, incredible business and platform to kind of grow from. So that's kind of the background and why I joined and the opportunity I've seen.

In terms of breakeven prices, right, you asked the question, what I believe around breakeven prices. We are kind of leading there within the industry. We're well below $3 now on a breakeven price. And that breakeven price by capturing margin will just create more value for our shareholders when we do that. So we'll continue to work on the cost side, as Mike also alluded to, with Josh and his team, but also by capturing more of that upside on the margin, we will just improve our relative position even further. So that's an important part.

The balance sheet, we made incredible progress on the balance sheet. And the way I look at that, it's important for us to be investment grade. We're a big company. We are a counterparty. People need to be able to rely on us. And of course, we're in a very cyclical business. So we want to be investment grade, not just in the good times, but through cycle, and that's important. You've seen after Q1 that we now have peer-leading kind of leverage. And we reduced most of the free cash flow we generated in the first quarter to reduce our gross debt and of course, to put some additional cash on the balance sheet as well. And going forward, this continued -- our strategy continues to be anchored on that balance sheet as we think of the opportunities that we have.

Having said that, I think given the allocation of free cash in the first quarter and the progress that we made relative to what we laid out at the start of the year, we can rebalance a little bit the pace of that and also kind of lean a bit more on the -- and shift that kind of balance to shareholder returns in the form of buyback. So that's kind of how we think through this.

Let me pause there and let the -- Doug, there was a part of the question that I...

No, I think you've given -- I just want to -- maybe just on that last point. So at the end of the day, your breakeven is still above where the gas price is right now. So is share buybacks more of a -- I mean, do you think about that as opportunistic? Do you think about it as ratable? Or when you're theoretically at a gas price, which is burning cash, by definition, below breakeven, is now the right time to buy back your stock? Or is now the right time to put cash on the balance sheet? I'm just trying to understand where buybacks sit in the seriatim of priorities?

Yes. So I think we do both, right? And we can walk and chew gum. We're still generating cash. Of course, our hedging program means we are realizing prices well above what you see in the spot market at the moment as well. So I think that's important. And think of our buyback program as opportunistic, right, relative for the value we can get in buying back. So it's a capital allocation question, and it's a balancing act, and I think you highlight that well.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

Maybe start off with an operational question. You guys made tremendous progress on well cost last year. CapEx also came in lower in the first quarter, but you also had kind of lower turn-in lines. I wonder if you had any comments on leading-edge well costs. Are you still making progress on efficiencies? And maybe any comments on increased competition for services or higher prices you're seeing out there?

Kevin, yes, we continue to make progress on our operational efficiencies. Just not just in the last couple of weeks, we've drilled the fastest well ever within our Utica program in Southwest Appalachia. So the teams continue to do a phenomenal job in finding ways to unlock new value. I think we'll continue to see those strides. An area of focus right now is for us perfecting how we drill our 3-mile laterals in the Haynesville. And so I still see upside there.

As far as pressure on services, of course, we've seen an uptick in rig counts in the Haynesville. We really haven't seen the impacts of that show up in our business yet. Our costs have been stable, I would say, outside of some near-term inflation around diesel prices, which is largely tied to the conflict in Iran. But beyond that, I would say the cost structures have been relatively stable.

Great. Appreciate that detail. And then maybe for my second question, I'll move to the Western Haynesville. And I realize that program is still pretty early. But is there anything you can share with us on what you saw in the first well in terms of where you think well costs are going to go, where you think you can take your expertise from the legacy Haynesville and translate it over to the Western Haynesville? And any thoughts on production on the first well?

Yes. So the well has been online for the last couple of months now, came online in early March. And so we're still monitoring well performance there. I would say we've been very pleased with what we've seen to date. We liked what we saw when we initially drilled the pilot well there. So we knew we were getting into a really good overpressured reservoir there. But again, it's still early. We want to be methodical about how we appraise those results.

We've also, just here recently in the last week, spud our second well, about 50 miles to the north of our first producing well. And I do think on the cost side that I have every expectation that we will continue to work ourselves down the cost curve. We're by far the most efficient operator in the Haynesville. We've built up a lot of history drilling deep hot wells in the southern part of the Louisiana core. So of course, we're going several thousand feet deeper, but there's a lot of learnings that we can translate into the Western Haynesville position.

In fact, when we just look at our first well that we drilled in the area last year, we're already on the lower end of the cost curve relative to what we've seen from competitors. And again, that's on one well. And I have every expectation that we'll continue to leverage those learnings and continue to work ourselves down the cost curve.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

Marcel, congratulations and looking forward to working with you again. And Mike, you gave us a little bit of an update on the CEO process. It sounds like you're tracking for a Q3 or Q4 event. But just any mark-to-market on how you're progressing through it, how you're attacking this process and what you're looking for and timing?

I like the way you said that, mark-to-market. Look, number one, the team is not waiting for a new CEO. I think you should see from our behavior and our quarter results here and efforts on marketing that there's no waiting for a CEO to show up before we do something. So #1 job is just to continue to create value for our shareholders.

With that, of course, we're looking for our leader, and we still expect to be on the same time. The mark-to-market, I'd say, is still kind of at the money on my 6-month sort of prediction of when this person would show up. We don't think that we'll find the perfect person. We think we're trying to build the perfect team.

And so with that team, you'll hear about Marcel's background. Of course, we have marketing with Dan and Josh. And so we're thinking it very holistically. We expect to have an energy person, not someone from Starbucks or Chipotle to come into this job, something more closer to our business. But on path on strategy, I think that's fine. And now today, it's just about execution that we continue until this person's arrival.

Okay. That's really helpful. And then just a follow-up on the hedge-to-wedge strategy. You have a good slide in the deck just talking about how volatile the gas environment has been. We've been living in this $2 to $6 range. Obviously, in the shoulder, we're below the midpoint of that range. And so the hedging strategy has worked out pretty well for you guys. But you have some competitors out there that are running a much more unhedged program. As you guys think about the balance sheet being where it is, what's the right approach to hedge the wedge? And just while we're talking about hedging, just any comments on the gas macro broadly as we set up for '26?

Well, thanks, Neil, and good to hear your voice and looking forward to working with you. It's Marcel here. Let me answer the question on hedging and then I'll pass it on the macro back to Mike. So coming in from the outside, and obviously, risk management is a critical part of how we manage the business. So -- and I've studied the hedge the wedge program and all of that, and it is the right approach for our company. And I think if you look at it, really the volatility of the market, which you point out, is just much faster than how we can plan for capital. So by hedging the wedge, we really create that kind of -- we protect the downside while we preserve the upside. And that creates consistency in the cash flow generation as well as predictable returns.

So for where we are with the balance sheet as well, I think it's the right approach. It's not a static approach, and you've actually seen that in the first quarter, right? So we kind of lay out what we want to do and then we optimize around that position in a way, not in a speculative way, but really from an approach of risk management and then optimization. And I think the last thing I would say is that being the largest player in the market, we have a lot of information on what is moving around there. And that allows us to just capture a bit more, make the program more efficient, and you can expect that we continue to do that.

Yes. On the macro front, when we think strategy, we don't think this year. It's like trying to predict the weather, of course, and even next year. We're thinking much longer term. We think the large macro program -- macro demand is sort of amazing. Generally, think that, that macro shows up bigger in the Gulf Coast before the Appalachia because LNG is on the schedule that you can see, you can see massive sort of growth in Calcasieu Pass and Sabine Pass. So I think that will be a premium market. That's not to say Appalachia won't get its fair share with AI demand in power generation, but definitely feels like Gulf Coast is positioned to be impacted first.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

I'd like to kind of go to some of the commercial stuff you all laid out in Slide 8 on your presentation deck. It seems like you defined what the LNG, the industrial side, the power side as catalyst. How do you think about the ideal allocation reaching to those various end users? And do you think one area is under -- I guess, underlooked by other companies? It feels like industrial is an opportunity you all have that I don't hear others talking about as much.

Yes. I mean I think about it in timing more than anything. I think the Gulf Coast, when I think about what's going to show up, LNG is going to show up first. That makes the Haynesville particularly valuable. What people are missing, of course, is the rest of the world, international actually are much, much more optimistic about the demand, the world demand and the need for LNG. And so if we overperform, I feel like it will be in that area.

When we get to industrial, industrial will come, but those are always big projects. We haven't seen the FIDs yet like we see on LNG. Power is just all over. I mean it's every -- whether it be in Louisiana or Texas or in Appalachia, we're seeing tremendous sort of discussion about power. But when that generation equipment comes on is a little bit TBD. And so we feel like that's secondary right now. It's not that we're not chasing it. We chase it every day. But LNG is here. And so you can plan for it and you can start building your asset to serve it.

And when you think about the LNG opportunity, obviously, you signed the Delfin agreement. But given what's happened in the global LNG market right now, how competitive is it? Is it tough to be able to contract in this market given the heightened nature of it? It's -- my analogy would be, if your house is on fire, that's not the time you call your insurance agent for more coverage, right? So how is that LNG market? Can you actually get things done?

This is Dan. In terms of contracting on the -- I'll talk about it on the supply side and the sales side, right? On the supply side, this Delfin contract is a long-term SPA. So that's priced at a cost of liquefaction. So it's easy to get those kind of deals done at the moment. There's a few more in the market that are available that we're looking at.

And then on the sales side, this is, again, a longer-term business, driven by long-term relationships. LNG doesn't trade like really any other market in the world. It's really driven by long-term relationships, fundamentally underpinned by long-term contracts. And we've been in discussions with counterparties already on how we could end up supplying them, supplying them different. So in the real near term, yes, the markets are priced to perfection. So if you're going to get a short-term strip in this year, you're going to have to pay up for it on U.S. Gulf Coast, but we're setting up this business for the long term. So we expect to add supply positions and have a sales portfolio on the other end where we can market differently and a mix and a real portfolio approach to longer-term contracts and shorter-term contracts and spot exposure.

Our next question comes from the line of John Freeman with Raymond James.

I want to go back on the marketing side on that Slide 13 that you have got where you sort of -- you show sort of the 3-pronged sort of strategy to achieve this $0.20 uplift. And the first one, facilitating and capturing new demand like Delfin is obviously, longer term, back-end weighted, these are 4, 5 years or more until you sort of get to realize those versus the other 2, which are already underway, the premium markets and the monetizing volatility where you're just trying to kind of ratably expand those. I'm curious like the ultimate price, the $0.20 kind of uplift, like how much of that can you all achieve with just those other 2 kind of buckets, the premium markets and the monetizing volatility?

Of course, it doesn't matter where it comes from. And ultimately, our ability to execute will determine exactly where it is. In our view today, we think this is about 50-50. 50% on facilitating and capturing new demand and 50% on the other 2 categories. Between those categories, they're a little bit intermingled. So exactly how they're broken out, we don't, and we don't think about it that way necessarily because they're often combined. But think about the bottom 2 of those things is sort of near term and about half and the top -- the very top one, about half and a little bit longer.

That's great. And then the -- you'll remove the heat map slide in the presentation this time. I'm just making sure there's nothing's changed in the way that you all sort of think about that relationship between kind of production, CapEx and the natural gas prices.

Yes, John, this is Josh. That's right. I mean it's not in the deck, but it's absolutely helping us formulate our views on production and therefore, CapEx, and it all centers around taking a 3- to 5-year view on a mid-cycle price. And of course, there's been a lot of volatility. Mike talked about this earlier in the near-term gas markets. But as we think about the business over the next couple of years, we think delivering that 7.5 Bcf a day, given the current price outlook makes sense. If we see those fundamentals change, of course, like we've done in the past, we'll be responsive to those changing market conditions.

Our next question comes from the line of Zach Parham with JPMorgan.

Maybe just to follow up on John's question. Are you starting to think about your activity levels changing at all where current natural gas prices are? The '27 strips falling to below $3.60. Are we getting closer to a price where you would consider moderating some activity or at least maybe building some deferred productive capacity as you've done in the past?

Yes. We're obviously looking where the strip is landing and we'll always be responsive to pricing. That plan that we laid out and as the heat map that was referenced earlier is predicated on that $3.50 to $4 price range. Of course, we're still in that today, but we're not stuck to it. And so just like we've done in the past, 2024 and 2025 was a great example of this. Our toolkit is there, and we know how to leverage flexible operations. And if we see markets soften further, we'll absolutely be in a position to defer turn-in lines, slow down our completion activities as we see those as the best measures to better align our production with price.

And my follow-up, just on the balance sheet and how you're thinking about capital allocation. You paid down $1.3 billion in debt in April. That meets your commitment to reduce debt by at least $1 billion this year. How do you think about allocating the incremental free cash flow after the dividend for the remainder of the year? Should we think about that going mostly to buybacks at this point?

I think the way that we look at it is that having achieved the goal that we set out at the start of the year, we can now look at rebalancing that allocation, whereas in Q1, it went primarily to debt reduction, right? In the rest of the year, we can rebalance that with share buybacks and shareholder distributions.

Our next question comes from the line of Phillip Jungwirth with BMO.

Can you come back to the Delfin gas supply manager comment from earlier in the call? Just what all does this entail? Does this imply that you'd look to take additional offtake from the project? And if you look at other LNG opportunities, what all goes into the assessment as to whether that's an ideal project for Expand to participate in to partner with?

Phillip, the gas supply manager, that's something that's under negotiation with Delfin at the moment, and that's supply from upstream where we would be managing all the gas into the facility, managing that capacity. It sets up naturally for us given our footprint and how we -- our growth in what we're doing versus Delfin building out that capability on their own. So it's kind of a win-win for both of us. So it's the opportunity to supply to them and to manage the capacity into the facility.

And then we're creating a long-term partnership. They're looking to do other vessels later on. And again, we'd be in the mix of supplying -- supporting that new demand, getting after our strategy of facilitating and capturing new demand.

And then when we look at all the other projects, we're looking at similar aspects. We like the integration through our Haynesville asset. We think we're well positioned to be able to supply to these facilities. We already are supplying around 2 Bcfd to these facilities. So we have conversations with them. And then we look at all these projects in terms of value and economic risk, and we believe in the long-term demand, both in the U.S. Gulf Coast and globally in LNG. So we're going to look at all these projects individually in terms of the economic merit. But essentially, we're trying to build a well-interconnected portfolio on our upstream and through to the LNG market.

Okay. That's great. And then can you talk about what kind of role you see expand playing in the Northeast for new power demand projects? And you clearly have a dominant position in the Haynesville, but there are certainly larger competitors up there in Appalachia. So just how do you see the opportunities for expand here versus the Gulf Coast considering the different competitive dynamics?

Yes. Thanks for that question. This is Mike. In general, when I think about the Appalachia, I think about it in 2 buckets because we have Northeast PA, which we actually are dominant in that particular area, and that's where our competitive advantage is on power generation, which is actually PJM, and that's the right market for it. And so we're definitely in negotiations and discussions with power providers in that area in particular. And again, we feel like we have a competitive advantage there.

In Southwest App, still location is to the western side of that. And so we think we can be competitive on that side of the basin as some of our other competitors are further east. But the overall strategy is to focus on where we're the best. And so we're thinking about Northeast PA in that market.

Our next question comes from the line of Neal Dingmann with William Blair.

My first question is just, Mike, simply on your strategy. I'm just wondering specifically, I know you've mentioned really taking a full integration focus. And I'm just wondering, could you give some details of what specific transactions make the most sense in the coming months? Would it be just simply like those of the Delfin agreement? Or maybe what else should be looking for as part of your strategy?

Sure, sure. We're a producer. And as a producer, we think of 2 things: sell more gas at higher prices. And so that's what we do. And so our focus is really pushing towards new demand and better pricing, and therefore, we're focused on our marketing. That's -- we think the time is now. That's where the opportunity is.

And so number one, we want to sort of continue to look at the LNG value chain and push that because it's near term, and it's close. And of course, we can actually provide our actual gas in the Haynesville. I like -- I think the word you just used interconnectivity, I really like that, Dan. So that's sort of the first deal. But doesn't mean we are competing heavily, of course, for power generation in Northeast PA, like I already mentioned.

Got it. And then just on the -- my second question, just on the incremental free cash flow and the $0.20 [ NIM ] that you continue to throw out there to capture. Am I correct on thinking this is still -- I mean, what are you thinking around timing around that? Is it a couple of years? Or could it be even longer if some of the agreements are not FID-ed? Or how should we think about the schedule of this?

Yes. Like we just talked about, we think about it in 2 general buckets. We have 3 categories, but 2 general buckets. We have our near-term bucket that's happening now. I mean that's what you're seeing in our marketing that we just saw this quarter in the $90 million. And so that is the now answer. Let's chase, of course, long term, LNG, power, those are 3 years. And so -- but we have a lot of value to capture and to execute in this moment here in time.

Our next question comes from the line of Charles Meade with Johnson Rice.

My first question, I think, is probably for Josh, but you guys will fill it as you choose. It's specifically about the cadence of CapEx and activity in '26. If we look at your 2Q, volumes are essentially going to be flat and CapEx is up. And I'm curious, is that just some activity sliding from 1Q into 2Q? And -- or is that -- is perhaps already -- does that reflect some decisions you've already made to maybe defer TILs or build some DUCs in 2Q as that's the low part of the curve for '26?

Yes. Charles, thanks for the question. Q2 will end up being the high point of our CapEx for the year. Just the way the program was set up, it is a little bit more front-end loaded. D&C activity is going to be just slightly higher in Q2 relative to the second half of the year. We'll actually have a couple of rigs across the Appalachia region coming out in the second half of the year. So that will leave CapEx just a little bit lower.

And the other artifact in Q2 is just on our non-D&C CapEx, which shows up in the guide. That's a little bit higher than what we'll see in other quarters in the year. That's really just timing of our leasehold acquisition program. We have several things that have been in the works over the first quarter of the year. We expect those to close in Q2.

And then also Q1 tends to be a little bit lighter with our capital workovers just because of the weather conditions where as we get into the spring, it's much more favorable. So workover activity also picks up in Q2. But again, as we get into the second half of the year, activity will moderate just slightly. Production will grow modestly across Q3 and Q4, again, assuming the market is there. But really, I think the main thing there is we are in a position where we expect to deliver 7.5 Bcf a day at $2.85 billion of CapEx.

Got it. And then, Mike, my follow-up is probably for you, and it's really about your financial approach to pushing further down the value chain with these commercial opportunities. It looks to me that for the most part, what you guys have done is decided to sign up for capacity or transport rather than take equity stakes in projects. But an exception to that seems to be your approach to storage where you guys actually have spent money to get equity stakes in those facilities. So can you kind of tell us about how you evaluate looking at signing up for capacity versus buying equity stakes and if that approach is either changing over time or changes between the kinds of opportunities you're looking at?

Sure, sure. Happy to take the question. Thank you. Generally speaking, we think about our capital allocation from a sort of a disciplined financial view. And then we think about it long term. Our first goal is always sell more gas, higher prices. I want to repeat that about 10 times. So we're on the same page.

But when you think about how to facilitate that, how do we facilitate it? We facilitated with NG3, our ownership there because we wanted to move more gas to Gillis. We thought about it in FT to move our gas further east into the Southeast market. We think about it on a long-term value accretion basis, and that's our first threshold. Well, first is strategic, then discipline on financials.

So when we think about any sort of capital that's not in, we'll call it, a commitment side, it's got to be accretive, and that's long-term accretive. So I don't think we've changed our opinion on how we think about value. We have our nonnegotiables that's still in place today. So we will act when we can achieve our strategic goals and certainly create long-term value.

Ladies and gentlemen, due to the interest of time, I would now like to turn the call back over to Mike for closing remarks.

Well, thank you, everyone, for joining our call. I'd like to leave you with 3 things today: Number one, our industry has experienced unprecedented structural demand growth. We are excited about the future as I'm sure you are. Second, we are in the right place at the right time. Our assets are reaching 90% of the expected demand growth in this country, and our Haynesville is sitting on the epicenter of growth because of the LNG market. We think we are at the best position to take advantage of that. And third, our strategy is clear. We are not waiting for a new CEO to show up before we act. We are acting now, we are chasing value now. So we look forward to updating you about the progress, and thanks for joining the call.

Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect.

Next presenting company, we're going to do this in kind of a fireside chat sort of format. We have Expand Energy, which is the largest U.S. natural gas producer. And with us today on behalf of Expand is the Chief Operating Officer, Josh Viets. So Josh and I are just going to have a fireside chat here. And if there's any questions, we can field those as well.

So maybe, Josh, just for those that aren't as familiar with Expand, maybe just give a brief overview of the company, the assets.

Yes. So Expand Energy came to existence through the combination of Chesapeake Energy and Southwestern Energy merged in 2024. So we've been in existence now for approaching 18 months. Both companies have a long history within the U.S. shale, both being pioneers in the case of developing unconventional gas reservoir. Today, we are the largest producer of natural gas in the country. We produce about 7.5 Bcf a day of natural gas on a net basis. On a gross basis, we produce roughly 10% of the country's natural gas supply.

One of the unique advantages of the company is we do own assets across the 2 most prominent natural gas basins in the Lower 48. That's the Haynesville Shale and the Appalachia Basin that spans from Eastern Ohio up to Northeastern Pennsylvania. We think that's a unique advantage for the company. And that's really just because there's different demand dynamics that are existing in both places.

We also have an investment-grade balance sheet, and we're currently in the S&P 500. We think that investment-grade balance sheet is incredibly important. And combined with low leverage, that's less than 1x. We think those attributes are going to be incredibly important for us to capture opportunities going forward as we look for opportunities to further integrate our production, our wellhead volumes down into the downstream market.

So I know the Raymond James view, we're obviously quite constructive on natural gas. Our view is that as you get the kind of AI-driven load growth, the big ramp in LNG exports, the Haynesville is basically kind of the swing basin on the supply side to meet that, the load growth and the export ramp. And with you all being the largest producer in the Haynesville, sort of the de facto kind of swing producer, if you will. You have got a slide that I think is quite helpful that, yes, we could probably pull up. I kind of call like your heat map kind of strategy on sort of kind of the -- when it makes sense for you all based on the gas strip to either hit the accelerator or the brakes. Just maybe kind of walk investors through how you all think about sort of your role as that swing producer.

Yes. I mean, first of all, I think we think it's incredibly important that we can create clarity to the markets on how we're going to choose to allocate capital back into our business. One of the unique advantages that Expand Energy has is our ability to grow production. But of course, we want the production to be grown in times where there's been structural changes in the supply-demand fundamentals. And so John was alluding to the fact that we are living in this era of demand increases. And it's coming through 3 places: it's LNG growth; it's power demand, which is largely being generated through the expansion of computing; and then there's industrial demand that's also growing. Probably gets less talked about, but it's a real factor.

And so when we think about capital allocation with the business, it has to be grounded in fundamentals. And ultimately, when you work your fundamentals, you're trying to arrive at a price. And so one of the things that we talk a lot about is our view on a mid-cycle price. And that's really where this heat map starts. Our view on mid-cycle price, which is bolded there in the center of the chart, is $3.50 to $4. And we think that is not necessarily -- shouldn't be skewed as this is what we think the next 2- or 3-year strip will play out. But you should think about that as that's the price that we're willing to underwrite our capital program on. And so that's really the first key input to how we think about it.

So to John's question, well, you guys are the swing producer. Demand is increasing. Therefore, you should consider adding production. What we would say is, well, let's first take a step back and take that renewed view. Is the price signals that we're seeing today, are they transitory or do we expect them to be durable? And for those durable changes, we would expect that, yes, in those scenarios, we would have the potential to produce more. Today, and as we look out over the next, call it, 3 to 5 years, we think that band of $3.50 to $4 is the right view to underwrite the capital program. And so the output of that ultimately then becomes the amount of production that we think is appropriate to introduce into the market. So for us in 2026, that's 7.5 Bcf a day. And then we know what the sustaining CapEx is in order to support that production profile. So that for us on a maintenance basis is just under $2.8 billion.

So this is something that we look at regularly, but we're very careful not to allow some transitory effect. So think about Winter Storm Fern, prices ran on the prompt basis to $7 for the month of February. Those aren't going to be the types of signals that we're thinking about resetting a price because it's really about what's happening 1, 2 and 3 years out that we need to understand to see how those supply-demand balances shift to ultimately repeg our view on mid-cycle price.

Over the past year, you've been able to lower the breakeven gas price in the Haynesville by about 15%. Some of that through like vertical integration efforts. Just maybe speak to that and any other levers you see to be able to keep moving that lower.

Yes. It's been a phenomenal year for the company. I've been in the industry for 25 years, and I've never seen an individual business unit or entity move by as much as we've seen in terms of the breakeven improvements within the asset. Really, it was -- at the forefront of this was, of course, the merger. We had both companies operating in the Haynesville at the time, both running relatively healthy programs. But one of the opportunities that we saw very early on was an ability to normalize the drilling performance between the 2 companies. And one of the things we probably underestimated is oftentimes you put 2 companies together, you see one has a higher cost and you say, "Well, I'm just going to take that higher cost company and bring it in line with where the other company is." Well, we did that, and then we did a little bit more because what you don't recognize is when you take best practices from both companies, 1 plus 1 doesn't equal 2, it's going to equal something like 2.5. And that's what we realized in that time.

So one of the biggest movements that we saw within our capital improvements, where we've reduced our well cost by 13%. In a single year, we increased our drilling efficiency by over 30%. It's just a phenomenal outcome, again, to put 2 big companies together and be able to generate those types of outcomes so quickly.

And so I think the obvious question is, well, how did that happen? It's really easy to go change the well design, so a casing program or your bit selection. It's another thing to go change how you drill. And that's what I would tell you, is those savings came how we drill wells. It's about the integration of our engineering, our analysts, our drilling contractors, the company men on site working together to go drive a faster optimization of drilling parameters. So really a credit to the organization for that. So again, a 30% reduction in our drilling times in the most complex basin in the U.S.

The other factor was, and John alluded to this, so we made an investment back in 2024 to go develop our own sand source. And that had 2 real key benefits. One is the sand source was more proximal to our operations. So we're able to shorten the trucking time to get the sand from the mine to our well sites. And then also, it's just simply a lower input cost. We can extract it at a lower cost than what somebody else could because you're clipping the margin away from the supplier. So what that ultimately translated to is the input cost for our sand was reduced by 40%. And the proppant we buy to put down in the wells with the hydraulic fracturing process is one of the larger input costs into the completion. So it's great that I can lower my input cost. But actually, what's really exciting is when I lower my input cost, I can actually pump more of that product, so I can increase my proppant intensity, which then translates to higher production. So during this time, we also increased our proppant intensity by roughly 20%.

And so this trend that you see on the chart on the left is showing well productivity, and it's looking at a 12-month cumulative production per lateral foot of horizontal well. And this trend that you see there with a roughly 11% improvement over the last 5 years, this is a trend that definitely bucks the trends that we're seeing across the broader shale plays. So much of the narrative is really centered around the degradation of inventory that's occurring. And so by reconfiguring our economics through smart vertical integration, we've been able to reset the narrative around production. So this isn't just about cost reduction. This is also about production improvements, which is enhancing, of course, our well returns and our overall capital efficiency for the business.

And the last piece I would mention is we also saw year-over-year an 8% reduction in our production expense in the field. And again, when you take 2 companies together, both of us have large development programs, both have a lot of water to manage, be able to go and invest in water infrastructure, reconfigure how we go and haul water from a location to a disposal site also turned up in a really big way. And those 2 things combined the 13% reduction in capital cost, the increase in production from the new wells, combined with the lower production expense is ultimately what contributed to this 15% improvement in our breakeven.

You've got, by far, the deepest inventory in the Haynesville, a couple of decades plus. But you all have recently put together a pretty big acreage position in the Western Haynesville, set aside some of your capital to try to delineate that field. Maybe just speak to that decision and what kind of makes you excited about the Western Haynesville.

Yes. We think organically building acreage positions is incredibly valuable for the company. When you look at over the last year, some of the transactions in the Haynesville specifically, you'll see that on a per location basis, transactions are occurring at $3 million to $4 million per location. That's pretty high if you look back over the cycles of natural gas plays. And so those are things that we would look at, but simply, they just don't make sense. We prefer to be countercyclical when we think about acquiring existing assets.

But in the case of the Western Haynesville, that was a play that we actually started evaluating back in the 2023 time frame. And when we started building our acreage position late in '23 and into 2024, we were 40 miles away from the closest producing well. We had seismic data that covered the area. We noticed that was less structurally complex than what we see as you go further west into the far western parts of the Haynesville where most of the activity has been concentrated. And so very quietly, we were able to aggregate a relatively modest acreage position, drill a vertical well, prove the presence of the reservoir and the prospectivity of it. And then with that vertical well result, we were able to go then build very quietly a 75,000-acre position. So now here we are with roughly 200 wells of inventory that we've now acquired at less than $1 million a location. So again, $1 million -- less than $1 million location versus $3 million to $4 million. And so we just absolutely love the upside that comes with that, and we like the ability to go generate a full cycle return through that organic leasing and exploration effort.

So the other great thing for us, again, this highly prospective area. A company like ours that has 20 years of inventory in the Haynesville, we don't have to have this play contribute right off the bat. So in other words, we can be very methodical about how we appraise the asset, how we think about infrastructure being built into the play. And then as costs come down in the play, we will look to integrate that into our existing program or kind of back to the discussion on how we think about mid-cycle price, if mid-cycle price moved up with higher demand and that was calling for more production, that now serves as another growth engine for the company. So we really like the way that we've been able to position ourselves in that part of the play.

We've seen the Haynesville rig count has gone from 30 rigs to roughly 50 rigs over the last 12 months. Given -- in our estimation, we probably need to add another 25 rigs or so from here in the Haynesville to get what we think is the supply growth needed to meet that AI-driven load growth, the export ramp. Given that only you all and maybe one other company have any meaningful inventory in the Haynesville, at least of higher-quality rock, the core Tier 1 stuff that works in a $3-ish environment, like how do you see that playing out? As the rig count goes up and a lot of these operators are already running out of their best rock, just kind of how do you see that playing out?

Yes. I mean I think what it's pointing to is there's going to have to be a higher price in order to get enough gas into the markets to support the longer-term demand. And I think that just puts us at more of an advantage. We control roughly 40% of the inventory within the Haynesville. We, by far, have the lowest breakeven. We have over 20 years of inventory remaining. And if we kind of go back to the conversation earlier about the breakeven improvements, just in the last year, we've added 5 years of inventory that breakeven below -- has a breakeven below $3.50.

And the other thing to just keep in mind, we included a slide in our investor deck at the end, and hope we can flip ahead to that slide, but not all rigs in the Haynesville are created equal. So one of the things that's really interesting, when we combine the increased drilling efficiency within our business, combined with the premier acreage position that we command, when you compare our rigs to the average industry rig over a 2-year time period, our rigs will generate 50% more production than the average industry rig. So in other words, what you should be paying attention to is when Expand starts adding rigs because that's really where you would start to see, I think, some acceleration of supply in the region and less so when you see some of the smaller operators, who are developing less quality acreage with a very limited inventory life.

And so I think what we see right now is going to be a pretty modest supply impact. And again, I think our belief is in order to meet the demand growth, -- so think about this, 10 Bcf a day is going to be needed just to support the anticipated under construction LNG facilities in the U.S. Gulf Coast over the next 3 to 4 years. So there is a call on gas, and we think ultimately, a higher price is going to be needed to support it given where inventory sits today.

Given the fact that you've got peers that are pretty inventory constrained, you've got inventory that at least some of it you may not get to for 15, 20 years. I mean, is there some calculus you're walking through that says, "Well, if that acreage is more valuable to some of my peers and I'm not going to get around and drilling it for a while, that maybe some of that might be a divestiture."

Yes. We really take great pride on being good active portfolio managers. I mean just over the last 4 years, we've divested out of the Powder River position. That was inventory that wasn't competing for capital. We sold out of our Eagle Ford position. That capital wasn't competing there. It was simply higher on the cost curve than what we had in the rest of the portfolio. And so we're constantly looking at our inventory and assessing what's going to compete and what's not over some time period. And if we find ourselves in a market that's constructive, I think those are the things that we have to always consider.

Recently, you all had -- you made the decision to move the executive suite to Houston from Oklahoma City. There's been some management changes. There's been a lot bigger focus on sort of I think the way you all talk about just this price that you want to get, of like this $0.20 uplift for the gas price that you're selling, more deals like what you did, the long-term supply agreement with Lake Charles on the methanol side. Just speak to that, like this price that you all are trying to get and this push to do more and more of these long-term agreements.

Yes, sure. I mean I think you have to kind of think about the evolution of the company, going back to the start of when Chesapeake and Southwestern merged. I mean, for me, with the rest of the executive team, at that point in time, the catalyst for growth was really centered around the delivery of synergies. We've achieved that. That's gone. So what's next? And that's really what John is alluding to, is we do believe the next catalyst for earnings growth is going to come from our marketing and commercial bussiness.

And I think the way I like to think about the opportunity in front of us and how value gets created, for one, we need to be able to move our gas into premium markets. We need access to the infrastructure. We need the commercial agreements to access premium markets to get a better price than we do today. Second, we need to be able to facilitate and capture new demand. And I think the Lake Charles Methanol agreement is just a fantastic example of how that can be done. So there, we had existing relationships. It was going to be along the U.S. Gulf Coast, so proximal to our operations.

We had taken out capacity on a pipe called NG3. So we had 2.5 Bcf a day of gas moving south into the Gillis area. We have 20 years of inventory, so we can backstop any commercial agreement that was in place. And we have a counterparty with committed offtake to take blue methanol from the U.S. Gulf Coast into the international domain. And so that was the type of marriage that we saw. And our goal is to be able to emulate that time and time and again. So again, facilitating and capturing new demand.

And then the third thing is about monetizing volatility. And so we have a 5 Bcf storage assets in play. We have an active hedging program. And so I think being able to use the information that we have. We market 10 Bcf a day of natural gas. So we should always have some of the best information on natural gas flows than anybody. And so using that information to our advantage to actively hedge and to be able to generate value from that, we think, is incredibly important. So again, accessing premium markets, facilitating capturing new demand and monetizing volatility is really what our M&C strategy is focused on.

And for us, some of the changes that we've seen is really about us doubling down. It's really being more -- not necessarily more aggressive but a higher sense of urgency to increase the deal flow. This is an incredibly competitive environment. We expect natural gas demand to increase over 25% over the next 5 years. And so the market is moving very quickly. And so being closer to the customer, closer to counterparties, which we believe those counterparties exist in Houston. Our marketing and commercial, our internal team is already in Houston. So having the executive team close to this group only increases the chance. And again, it's a sign of urgency that we have about capturing this opportunity and the aspirational goal of a $0.20 improvement to our free cash flow margin, we think, is what's going to be the next catalyst for earnings growth for the company.

You talked about like not all rig adds in the Haynesville are created equal. That probably speaks to why Haynesville is a basin, we've seen kind of production kind of flatten out here in the last several months despite the rigs getting added. The other interesting dynamic is that where a lot of the rigs have been getting added recently is on the Texas side of the play, and there may be a lot of people aren't aware that we have a lot of interesting pipeline dynamics we're trying to get gas from Texas side and Louisiana side. And when you marry that up with where a lot of these LNG plants are coming online, a lot of this gas, we need to try to move it east across the Texas-Louisiana border. So maybe just talk about the dynamics there and how you all are situated to deal with it.

Yes. And I guess for that question, I'd even go further west, and it's into the Permian because I think the Permian is also going to be a key component to solving the supply-demand balance longer term. And so I think you would expect that each year, you'll have 2 to 3 Bcf a day of new Permian pipe capacity coming on. And it's going to be chunky at times. But one of the issues with the Permian takeaway is where that gas is landing. And so you really have 3 primary centers. It's going to be the Dallas-Fort Worth area. We have a new pipe coming on later in the year that's taking gas to an area south of the Dallas-Fort Worth Metroplex. We have going it down -- further down south to Aquadose. And then lastly, you have Katy, so on the west side of Houston.

So that is probably one of the single biggest sources of natural gas growth, and John talked about East Texas. But there are infrastructure constraints that will limit the ability of that gas egressing out west of Houston, south of Dallas and getting that into the LNG corridor. If you think about like the Sabine Pass area. And so that infrastructure problem will eventually get solved in our minds, but it's absolutely going to take some time. And that just creates a unique advantage for a company like ours that's producing the 3.5 to 4 Bcf a day in the Haynesville region today to be able to access these premium markets as basis tightens, and we think that's a great answer for our shareholders.

There's recently been some pretty big M&A transactions in both of your operating bases, with the Haynesville and Appalachia. Just maybe speak to kind of how you all evaluate M&A, just anything on that topic.

Yes. I think we have a good track record that we've built up over the last 4 years. And one of the guiding principles that we have is we refer to it as our M&A nonnegotiables. And so we're absolutely going to look at every deal that's in our backyard. We think that's just simply prudent to do that, to understand the markets and how things are trading. But these M&A nonnegotiables will continue to underpin our decision-making.

And so we're simply -- we're not going to overpay for assets. So earlier in the conversation, I referenced $3 million to $4 million a location as we saw Asian buyers coming into the Haynesville. We think that's overpaying. So we need to avoid doing that. Instead, we're focusing on organic addition. We're not going to stress our balance sheet. So we think we've learned those lessons, painful lessons, over time. So today, we run the company at well under 1x leverage, and we're not going to go do a transaction that stresses that. The deal needs to be accretive on all financial metrics. We think that's the obligation that we have to the shareholder to avoid any form of material dilution.

And so these are the things that are going to continue to underpin us and I think maintain the discipline and the reputation that we've earned as a management team to be active stewards of our portfolio and timing transactions that create value for shareholders. And you look at the Southwestern transaction, you had 2 acreage positions that were juxtaposed one another, and we can go create $600 million a year on a run rate basis of incremental free cash flow. That's the type of transactions that shareholders should look for us to continue to look for.

Do we have any questions from the audience?

Yes, go ahead.

Repeat the question, too, just...

Yes. So the question was, as we're contemplating power deals that may be tied to AI, what are some of the considerations that counterparties might have as they're having conversations?

So I think, one is, it's around the proximity to supply, and it's the durability of supply. And I think those are boxes that we check. Being in multi-basins gives us more flexibility on the number of counterparties that we can interact with and having 20 years of inventory, given the scale of production that we maintain, provides that question of durability.

The other thing that as a power producer and if you're a hyperscaler, you need is land. One of the things that we've gotten really good at over time, is we have lots of relationships with landowners because we've been drilling wells for 2 decades -- 2-plus decades now. And so we hope the combination of those types of skill sets can marry up with the power producer and the hyperscaler over time. Yes.

So the question was, is this something that we would expect to see over the next 12 months?

We have active dialogues going on. And so our expectation is as we're really doubling down within our marketing and commercial business, accessing power, accessing industrial, accessing the LNG infrastructure are all the types of transactions that we're going to maintain a high level of focus on.

Any other questions?

Yes, go ahead.

Yes. So the question was just to share a little bit more information on Nick Dell'Osso leaving, the timing of the new executives coming in, which includes CFO, CEO. And then I think the specific to me.

So maybe I'll -- yes, I'll work my way backwards. So as part of the change, one of the things that we decided to do is we want to avoid the disruption to our operating teams. And so 80% of the company's corporate staff that supports the traditional E&P business is located in Oklahoma City. I believe, the Board believes that, that's going incredibly well. We've made a ton of progress over the last year, and so we don't want to disrupt that. So my role, the team will stay in Oklahoma City.

As far as the timing goes, we expect this process for the CEO specifically to take 6 to 9 months. And so Mike Wistrich, who's our Chairman, is coming in -- has come in as the interim CEO, and he'll help lead the search process while leading the day-to-day dealing of the company. The CFO's search has been going on, obviously, for a little bit longer. And so we hope that, that announcement would come sooner rather than later. So we expect that announcement to be ahead of the announcement of a new CEO.

And then just on your question with Nick, I mean, this was really about not necessarily a disagreement of strategy. It was really about the tactics of how that strategy is executed upon. And that was included the need to be in Houston, closer to counterparties, supporting directly the M&C organization. And that was a situation where, unfortunately, Nick wasn't in a position to be able to support that relocation. And so that's where we find ourselves today.

I think that's to be decided. The Board is running the search process. And so we want to make sure we understand what that market looks like. We want high-quality candidates that can come in and lead the strategy that we've laid out.

I think we're out of time. Josh will be available in the breakout room. Please join me in thanking him for presenting.

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Expand Energy Corporation Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.

At this time, I would like to turn the conference over to Mr. Colby Arnold. Sir, please begin.

Thank you, Howard. Good morning, everyone, and thank you for joining our call today to discuss Expand Energy's 2025 Fourth Quarter and Full Year Financial and Operating Results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday.

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our press release yesterday and in other SEC filings.

Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measure and can be found on our website.

With me on the call today are Mike Wichterich, Josh Viets, Dan Turco and Brittany Raiford. Mike will give a brief overview of our results, and then we will open up the teleconference to Q&A. So with that, thank you again.

And I will now turn the teleconference over to Mike.

Thanks, Colby, and good morning. I'd like to start out by talking about 2025. I think we had a really phenomenal execution year I mean we have 15% reduction in our [indiscernible] in the Haynesville. That is very difficult to do. The team should be sort of congratulated on that. It's sort of phenomenal. It doesn't just help our reinvestment rate. It also helps our inventory. You'll notice in the deck, we've moved locations over to the left, getting closer to lower breakeven, I think that is really a tribute to the team. When we did the Southwestern merger, we focused on reducing debt.

We're fulfilling that promise this year. We've reduced debt, but we also returned a lot of money to our shareholders, and we continue to think that's a good way for the company to continue. Volatility. Look, we're seeing volatility in gas prices today. You've seen it all quarter, we believe in hedging. And our hedging program has been effective. We have $200 million in gains this year. But I mean just look at today's prices, and we're glad we have them, you'll see we're very active this quarter. What I like about the 15% breakevens in the Haynesville is you know they're real and they know they're real because when we talk about '26, we've reduced our maintenance capital that absolutely is a proof positive that the team is working, and it's working well. '26, we'll continue to do our buydown of debt.

We'll also consider shareholder returns, as we always have. Big news, of course, is the change that we made last week. That is really a reflection of the changing natural gas business. We believe the world has fundamentally changed in natural gas. We're seeing a tremendous growth in demand. We're seeing 35% to 40% in the next 5 years. This move is absolutely trying to address that reality. Today, our marketing business, while we think about it is in sort of 3 buckets, the first bucket that we consider is how do we get our gas to premium markets. This has been a goal for the company from the very beginning of last year, when we started in Chesapeake in 2021, we had our goal of moving these numbers. It was -- at the time, we're almost all in-basin sales. Today, we're close to 50%. We feel good progress has been made. The second leg of marketing is we need to take care of volatility. We live in a very volatile gas market.

We know that. And so by hedging, by doing storage transactions, this helps us help us in the low price environment. which we always are concerned about. It's about discipline. Hedging is about that. Our third, which we have not made as much progress, and we're disappointed in and we expect to do better is we need to capture and facilitate new demand. We need to get our fair share of this market. Our team has done some good stuff. We saw the LCM deal this year, but we have not done enough. And we're sort of taking that challenge. And that is really some of the fundamental reasons why we're moving to Houston. In order to participate in that market, you can see you have to sort of compete on our trading side of our business or our marketing side. We're not the only ones who are saying this. I mean you see wellhead to water, you see wellhead to watts.

We have to think beyond the wellbore. We have to say it's not good enough anymore to just drill great wells, we have to compete on the marketing side of our business. What is the size of the prize, been asked many times about that. I think the size of the prize we're chasing is $0.20. We're looking for improved realizations across our business. We think that will make us competitive and a better energy company. These changes, as all changes, you have some things that are unfortunate. Obviously, our senior leadership has changed. That does not change our mission. It does not change our strategy, but what you're seeing is a change in tactics and focus that we have a new business, we have to spend time on that business. It's not changing. Our operations have been great.

Look at the results. We're not changing our leadership. We're not changing our regular location. We plan to stay in Oklahoma City with our ops team. Josh is still leading that group, and we don't expect to have changes there because, frankly, it works. And so we don't do things that don't work. So when you think about us, our sort of mantra is our foundation is in place. Our strategy is clear, opportunity set is huge. It is time for us to act. And so we're talking about urgency, we're talking about competitiveness. And so all we need to do to be successful is execute. So with that, we'd like to turn it over to questions.

[Operator Instructions] Our first question or comment comes from the line of Neil Mehta from Goldman Sachs.

Mike, I appreciate some of the color that you provided around management change. Maybe you can talk about the characteristics you and the Board are looking for in that next CEO? And any thoughts on timing, how long you think the search could take?

Thank you for the question. We're looking for a leader who has a bigger view of energy. It will be an energy person, but someone who's going to continue our mission look beyond the wellhead. That is someone who thinks about the whole value chain, including we need to get closer to customers, not just here in the U.S., when you get customers closer to customers in Europe. So it's someone who's sort of a bigger view of the energy industry at a whole. .

How long does it take? Well, we've done the search before for CEO. It took about 6 months. This is a bigger, more complicated company. I wouldn't be surprised if it went to 9 months. But call it 6 is sort of the goal. I will tell you, I'm committed to find the right person. I will be here until that occurs.

Okay. That's really helpful. And then as you talk about marketing, can you talk about the quantification of the uplift to cash flow or realizations that you think could happen. If you optimize the commercial side of the business and one case study could be firm, did you guys capture all the upside that you think you could have in that event? And have you had a more robust marketing effort, do you feel like you would have done even better?

Well, I think all energy companies and gas companies are moving towards more marketing because we can no longer give away margin to the guys in between us, the marketers. So number one, our first goal is premium markets. We're starting to see a little bit of results this year on that. I expect that to be the near-term catalyst for us to increase our realizations across our portfolio. That will move into I think volatility, I mean, especially when prices are low, storage is phenomenal, volatility is high storage.

It will be very helpful moving our gas to premium markets, whether it be Gilles or to Perryville has been very helpful. Those are sort of the near-term sort of ways to help our margins right away to go get that $0.20 a little bit longer, let's call it, 3 to 5 years. We have to do more LCM deals. I mean to facilitate demand generally, that has to do with building something building a plant, building a facility of some sort, so they take a little bit longer, but that is really the future. We're really fighting for years 3 to 5. Again, goal is $0.20 improved realization is obviously very material to our margin, and we think we can make it there.

About $500 million in EBITDA, right? .

That's what we're talking about.

Yes. And then just on -- you asked about Winter Storm firm. I mean I think your question around what are you going to be able to do with the integration of the operations that we have with the marketing and commercial business. And all those things have to work in tandem. But I think just talk about that entire value chain and starting with the operations those operations have to hold up when you have these types of weather events. And of course, it really is going to depend on the type of weather that we incur in the Northeast, really across our entire Appalachian region, the operations held up incredibly well and performed incredibly strong through the weather events. .

In the -- in fact, the other thing I'd just point out in Northeast Pennsylvania, we are actually peaking out on our production levels as we headed into January. So again, just thinking about the flexibility of our business there. In the Haynesville, that was a little bit different of a challenge. We had over an inch of eyes accumulate on roads and that simply was detrimental to the power infrastructure as well as our ability to manage water across the asset. So definitely a little bit of a different situation there that had some impact on our volumes across that time period. But we absolutely know that in order for us to realize these aspirations, the entire value chain has to work, and that includes our operations that has to include our marketing and commercial business and it also implies that we have to gain additional access to infrastructure further down the value chain.

Our next question comment comes from the line of Matthew Portillo from TPH.

Maybe just a follow-up on the marketing front. It feels like -- I know you laid out in your slide deck, but it feels like there's been a pretty significant shift in a constructive way in the supply-demand balances for natural gas on the Gulf Coast? I was curious if you might be able to discuss at a high level how you think the demand dynamics have been changing? And if there's any shift in your conversations for contract tenor but also pricing dynamics for offtake agreements, whether it be LNG players, utilities or industrial consumers around Louisiana and Texas?

I'll start and let Dan finish. Really high level, we're definitely seeing the Gulf Coast be very active. It is a unique area. Of course, it's 50% of our production where it is. We're seeing gas oil and gas demand. We're seeing that end-use customers want to be closer to wellhead and so we think that is going to go into our favor. And you can see others talking about this as well. We're not the only ones. In the Northeast, of course, that's a power market. And it's a little different. It's actually having some -- of course, with Virginia and the data centers built, it's a little bit different market. I generally think that there's more diversity in the Gulf Coast. But Dan, you should add additional color.

Yes. Thanks, Matt. I think you've noted the Gulf Coast is a place where we're seeing growing demand. If you look at the entire United States, we're seeing about 25 billion cubic feet a day of gas demand coming online. A lot of that, half of that is coming from the LNG, and that sits right in our backyard right where our Haynesville asset is and right where our pipeline capacity gets down to Gilles. And somebody asked me the day how do I feel about this market? I said I've been around this a for like 25 years. And the first time we're getting tons of inbounds, people looking for that security supply that you referenced. So the team is out there working on all these deals, trying to do something better.

As Mike pointed out, these opportunities that is huge, and we're accelerating what we're trying to do here and grow and further expand down the value chain. And where we're set up our Haynesville asset deals and that demand is quite unique for us. Not only we the outside of the board, the Texas side of the border is growing as well. There's a unique aspect going on between Texas and Louisiana, just with the amount of demand growth. People talk about the Permian a lot, the Permian will grow into these markets. But of course, Texas is growing substantially as well as Louisiana and the ability to get from interstate pipelines across the board to meet that demand is also a little bit challenged. So we're set up quite well here to go and capture all this demand.

Great. And then maybe a question for Josh. One thing we've noticed on the macro side is the industry has continued to accelerate kind of the rig count in the Haynesville, but more of those rigs are making their way to East Texas. And then in the core of the basin, some of your peers are starting to face degradation on their well results. I guess, Josh, as we look at your well data and then also, I guess, the slide you laid out on Page 12. Just curious how you think about expands productivity trends in the Haynesville over the next few years and how that might contrast to the industry as a whole.

Yes. Thanks for the question, Matt. I mean, the reality is the inventory that we carry in the Haynesville is just simply unmatched. It's both in terms of depth and quality you see that show up in a number of different spots. And then you combine that with what is a 15-plus year history of operating the basin. And so that simply leads to operational excellence. And at the end of the day, that's going to show up in the breakeven of our inventory. We're just in the 1 year alone, we've been able to add the 5 years of inventory below $3.50. And so yes, though, we've seen roughly 10 rigs added to the Haynesville. Those 10 rigs that are being added by no means you can make any comparison to a rig that we might choose to add.

In fact, if you referenced Slide 30, we characterize there what, over a 2-year time period of production of our rigs able to generate relative to an average rig in the industry. So the things that we're continuing to be focused on, of course, is operational excellence and continuing to manage the way at which we drill our wells. And that's primarily around how we manage temperature. And then the other differentiator for us is, of course, how we source sand and not only that is lowering the input cost, but it's simply allowing us to optimize a better economic outcome by increasing proppant intensity and driving our well productivity higher, that's not about IPs. I'll just note that's really about changing the decline parameters of the well, which again translates to value at the end of the day.

Our next question or comment comes from the line of Doug Leggate from Wolfe Research.

I wonder if I could ask 2 quick things to the extent you're able to answer them. There's a lot of focus, obviously, on your breakeven. When you and I have chatted, it's been -- it's almost like you're kind of laser-focused on how you get this breakeven down. Some of your peers have obviously taken different routes on this, whether it be greater liquids mix, introducing midstream deleveraging. I'm wondering, to the extent you can share your vision for how to expand gets that breakeven down given the proportion of [indiscernible] my first one. My second one is you've called the 2029 bonds and [indiscernible] obviously, I'm wondering if this is defining a different priority for the use of cash in terms of balance sheet over buybacks, and I'll leave it there.

Great. Thanks, Doug. A couple of things. I do think we focus a lot of breakevens, but we also need to focus on our total financial picture, including earnings per share. Obviously, we're making a big debt in our debt. We think that actually helps. That's one way to do it. But we're also thinking about marketing. It's a top line. We have to have the margin get better. And so I think we are trying to squeeze this number anyway. We're fighting for pennies. We know we're fighting for pennies as an industry. And so you sort of have to use the whole tool chest to get that done. So between debt reductions between -- I think you've noticed the last couple of years, we've made pretty good synergy adjustments and like G&A and not just our business.

And so we hope marketing will be the next leg of that as far as paying down debt versus buyback shares, of course, we like to do both. We've done both this year. We continue to do both. But we're in a very volatile commodity business. And with that, having a nonnegotiable of a fantastic balance sheet comes first. And so that's why you're seeing our priority to pay down debt. I think we'll lean into that. We'd like to be a little bit less prescriptive on our buybacks. I think it's a terrible policy to tell the market exactly when we're buying back shares and when we're not, we want to be smart about it. So -- but first deal is balance sheet first. And so that's why you'll see us focus on that. And I think that's also, again, great for EPS, which is important.

Mike, I could just add a quick follow-up there. I wonder does M&A come into the picture here in terms of resetting that breakeven, again, midstream and liquids is kind of what I'm driving out here. What would you say to that?

Well, I'd say we're very actively look at every potential party in the basins that we operate, and some of those have liquids. But the more important part of that question is you have to have discipline, I'd say this year, we looked at a lot of transactions, and we passed on a lot because it starts with our nonnegotiables. Our nonnegotiables is balance sheet, it's accretion. And sometimes this year, gas price was pretty high, and so those deals weren't that attractive. But we asking about liquids and helping margin? Is that a possible answer? It is. It is. .

Our next question or comment comes from the line of Kevin MacCurdy from Pickering Energy Partners.

I wanted to ask about your maintenance CapEx and specifically Slide 6. It looks like there were some improvements to your maintenance capital compared to last quarter, although the guidance didn't change, if I'm reading that correctly. I also noticed that there are 3 production levels bolded on the left-hand side there, 7.25 Bcf to 7.75, a range a little bit wider than your 2026 guidance. Is there anything to read in that as well?

Yes, Kevin. I mean, I think the first thing is, I think, just to reemphasize the improvement that we've seen in our maintenance CapEx. I mean, if you go back to a year ago and look at this slide, it would have been $225 million higher to deliver the 7.5 Bcf a day. So first, I think just acknowledging that the business has gotten stronger, and that's reflected here. So you will see that our program does have the ability to still be incredibly efficient from a free cash flow generation standpoint, up to 7.75 Bcf a day. But one of the things that I just -- I think is incredibly important to recall and really what is underwriting this slide, had a view on mid-cycle price. And that view of mid-cycle price remains unchanged from $3.50 to $4, $0.50 for us is a pretty big range.

And so one of the things we really want to continue to be focused on is maintaining a level of flexibility in the business and therefore, how much we produce in any given month or across a given year based upon how we see those prices trend. And so in certain instances that might cause us to push volumes a little bit higher. But as we see the market maybe turn a little bit bearish, whether that's shorter term or even longer term, we want to have the ability to flex those volumes.

And for my second question, your budget outlined $75 million for the Western Haynesville this year. Can you talk a little bit about how that program progress when you'll be drilling and what you're looking for in results?

Yes, Kevin, Josh -- this is Josh again. On that, we have roughly 2.5 wells scheduled. There's a little bit of carry in and carry out capital to take place across the year. We've just finished drilling the first well. That was a horizontal well. Those operations went incredibly well. In fact, when we benchmark our performance, both in terms of days and cost we're at the very low end of what we've seen from some of the bigger competitors in the Western Haynesville. So feel really good about that. That well is being completed as we speak, and we expect first production sometime in late Q1, early Q2.

Really there, we're obviously going to be interested in longer-term decline parameters there. We know the reservoir is there. We know it's highly saturated with overpressure gas but understanding those the client characteristics will be really important. For the rest of the year, we have, again, roughly 2 additional wells that we plan to drill, and those are really going to be centered around helping us appraise kind of the full extent of the acreage position that we put together there.

Our next question or comment comes from the line of Scott Hanold from RBC Capital Markets.

Yes. I'd like to maybe key off something, Mike, you had said in your overview. And one of the things you kind of mentioned is that you want to look to just can't give away margin to the middlemen. And as you step back and think about that, would that also contemplate looking at more of an integrated operations such as going out and actually owning midstream to be more integrated? Does that help the effort? Is that a possible avenue you'd be willing to look at?

Yes. I think, generally speaking, we're focused more on partnerships with midstream companies. We are looking at stuff like momentum that we've done in the past. We're looking in actually LCM deal has a momentum component on it. So I imagine this is more partnerships. We have to get our gas to premium markets. It's unrealistic to think we're not going to have to deal with some sort of transportation to get there. We'd like to be part of that equation. So I think it's that more than just going out and buying gathering systems. I'm not sure that would be really helpful for us. So we have to get to end-use customers. So yes, integrated, but maybe think about that in a partnership point.

Okay. Understood. Appreciate the context. And then if I could ask on cash taxes, surprised that the minimum model cash tax that you're looking at this year, can you give us a sense of what drove that? Is that part of the OBA from last year? And do you have any kind of visibility over the next couple of years where that cash tax rate might go?

Yes, Scott, this is Brittany. So you're absolutely right. It is the benefit of the BBB, and we saw that last year and seeing the benefit of it this year. So we do expect to be a full cash taxpayer probably in the back part of the decade. And so I'd expect us to step our cash tax increase throughout the next couple of years to be a full cash taxpayer probably later -- closer to 2030.

Our next question or comment comes from the line of Zach Parham from JPMorgan.

I wanted to follow up on Matt's question earlier. In the slide deck, you highlighted an increase in your first year [indiscernible] that you expect from the Haynesville in 2026. Can you talk about that a little bit what drove that expected increase? And if you see that as sustainable going forward?

Yes, it's a sustainable absolutely. Again, you can tie back to my earlier comments, we've really been able to reset the economics of the Haynesville with improvements in drilling efficiency, self-sourcing our own sand and we've been able to drive this higher productivity largely through enhancing the completion designs. On the call, during the third quarter, I talked about at the merger onset, we came together, we put together what we've referred to as our Gen 1 completion design we're already now progressing to what's considered our Gen 3 completion design and seen really improved results from that. And so we expect that this type of trend that you're seeing continues forward.

And again, I'll just kind of bring it back to we have an unmatched inventory quality and depth in the Haynesville. And that, combined with our history in the basin, there's a good reason why we're delivering these outsized results relative to peers.

And then my follow-up just on D&C costs in the Haynesville. You have done a lot to bring down costs over the last several years. You've got a slight reduction in your numbers for 2026. But can you talk about your ability to potentially drive that number even while we're going forward?

Yes, pretty -- my expectation is pretty high for the organization, our ability to do that. We continue to find opportunities to improve tool reliability, the bigger issues you find in the Haynesville is temperature. And so we continue to partner with some of our midstream -- I'm sorry, our service providers to increase tool reliability. In addition, we're seeing some pretty significant advancements with artificial intelligence to help us refine in a more optimal way or well designed, but more importantly, a faster real-time optimization of drilling parameters. And we think those 2 items there are really going to allow us to unlock further savings from a D&C standpoint.

Our next question or comment comes from the line of Josh Silverstein from UBS.

Mike, you talked about the challenge to get expanded volumes to the demand growth areas. Can you just talk about what the biggest challenges are in doing so? Is it getting the customer actually just agree to supply as price concerns or inventory duration? I'm just curious.

Yes. Well, there's sort of 2 challenges for our team. And one is on us and one is just the facts of the world. The first is our team needs to be more aggressive to review more transactions or potential transactions. We'll build more generators will add to the team to be in the room more often, a big part of moving to Houston is to be in that room. And so we have to get out of our own way. The other side is just real, which is you need to get your gas to them physically. And so you always are thinking about transportation, how to get it there, how to service those clients.

And that gives advantages to companies, frankly, like Williams, who have been connected to them for a generation. We have to compete by having assured production that they do not have and so that's our competitive advantage, but we definitely have to -- we have to partner. That's why we want to partner with midstream companies because that's the biggest thing to overcome.

Got it. And then you talked about trying to get an incremental $0.20 of realizations or margins there. What's the cost in there because you're going to have to start to build out a bit more is this going to cost you more upfront to then have benefits later? Just some sort of sense of [indiscernible]

Yes. That's a great question. And the first thing is we talk about our culture of discipline. We talk about rate of return. We think of ourselves as how do you grow long-term shareholder value, and that means you have to talk about the cost as well. So generally speaking, we have the lowest sort of returns are going to be on -- or not the lowest returns, the lowest dollar change will be on just trading to premium markets. Those will turn into commitments at FT. Those are not debt necessarily, but let's call it commitments.

Everything else -- if we have to put more capital to work or risk our balance sheet has to have a higher rate of return, it has to have a bigger payout because we are returns. And so do I think we'll probably spend some money over the next 3 to 5 years? Undoubtedly. Undoubtedly we have to, but we'll put it in context of our rate of return framework. We have to have a decent [indiscernible] in our program. And so these things will have to have discipline around that.

Our next question or comment comes from the line of John Freeman from Raymond James.

It was nice to see the Haynesville productivity improvements continue, but it does look like the upside on production in the quarter was actually from the Appalachia region, maybe I don't know if it's quicker turn in line, but just any color you could provide on that relative to all the guide for the quarter.

Yes. So John, this is Josh. I mean just to address that. Really, that's really about our returning our production from curtailments in the fourth quarter. That was a big piece of it coming to the end of the year. And of course, most of those curtailments would have been taking place across Northeast Appalachia. And then, of course, in Q1, we would have had a little bit more weather-related downtime in the Haynesville as a result of winter storm Fern where we, again, saw roughly an inch I show up at the end of -- into January. So that had some modest amount of impacts. And -- but across the full course of the year, we do anticipate to be averaging in and around the 7.5 Bcf a day.

Got it. And then Mike, sorry to belabor the marketing topic, but just it seems like -- and I don't want to put words in your mouth, but you're a lot more focused. It appears on sort of the LCM type agreements as opposed to maybe like long-term sort of LNG supply agreements? Is that like a fair characterization?

I don't think that's fair. I think we're looking at both. We're looking at both. We're chasing margin. We have to participate in the value chain of downstream of us. That's definitely LNG. That's definitely manufacturing, it's power. I think it's all -- and so all of the above, I just want to be more aggressive because they get in the room. We have to hustle. It's a competitive space. I mean it's a super competitive space. We'll have to focus.

Our next question or comment comes from the line of Neal Dingmann from William Blair.

My question [indiscernible] a little bit last night was on your upstream position. Just looking at your share price, it certainly doesn't seem to me that you all are getting credit for the massive -- what is it, 2 million-plus acres position on top of your material production. So I'm just wondering, is there something you all would consider doing with -- I don't know if it's either monetizing a bit of the inventory or drilling carry to something somebody or something to unlock some of this value given it just seems like given that sizable position your investors are just not recognizing this?

Well, first of all, thank you for saying that we're not getting full credit. We would love to get full credit. We hope you all are paying attention. We think we have a good business. Generally speaking, we -- we're not actively looking to do what you're talking about, but I would say it's always on the table. It has to be -- just to say no for the sake of no is the wrong answer. If we see something that's attractive and part of our portfolio that someone wants to overpay, we're a public company, that could happen in any day, and so nothing is off the table. But I don't think we're actively doing it right now.

Makes sense. And then just secondly, look like on the guide you're going to run about the same rig count, do you assume -- I'm just wondering if you're running as you continue to have the efficiencies that you've recently seen would you see yourself potentially, let's say, you are running ahead of schedule by, I don't know, second, third quarter. Would you pull back on the rig count and just sort of continue to bank that free cash flow? Or would you continue to potentially boost the production a little more than suggested?

Well, I mean, I think, Neal, we'd have to take a look at the fundamentals and understanding where supply-demand balances sit. We really take rate pride in maintaining a high level of flexibility within our business we've noted today that we see this business being efficient up to that 7.75 Bcf a day number. But at this point in time, we feel really good about the program that we've laid out, delivering the 7.5 Bcf a day at the $2.85 billion of CapEx. And until the market fundamentals start to shore up -- that's the plan that we expect to execute this year. .

Our next question or comment comes from the line of Charles Meade from Johnson Rice.

I'd like to ask a question about maybe drilling down on one piece of the -- of your marketing push. And that's on storage. You guys, in your presentation, say you're at -- you have 5 Bcf of storage as you own now. Can you talk about the nature of those assets and what the trajectory has been for building that position? And is storage an area that you expect to be, I guess, competitive in acquiring more?

Charles, this is Dan. I'll take that question. This year, we added about 3.5 Bcf of storage in the last quarter here to our 1.5% we already had. So we like the storage, and we look it for many reasons, right? You go back to our M&C strategy. One of the key components is managing volatility. This market is highly volatile as we've seen over the last few months, not only from like [indiscernible], but geography movement. So we're actively using that storage. We like that storage, and we've made money on it already, and we plan on turning that storage a lot more.

We would like to grow that store's position, but it is a very competitive market. the total demand of this market has grown substantially and storage has not caught up. That's why you're seeing a lot of volatility. So it's highly competitive to actually get more capacity, but we continue to actively look at it and back to our disciplined approach here, we're only going to take that capacity we feel it's going to make us value and help us manage that volatility and create more margin ultimately.

Got it. And then if I could ask a question about the West Virginia and Utica. You guys also in your presentation talking about bringing the potential of bringing some Ohio Utica development concepts towards West Virginia and a lot of upside there. Can you elaborate on what that is and how big the upside might be?

Yes, Charles, I mean, we're pretty excited about our [indiscernible] program. I mean the reality is there's not been a lot of Utica development as you move across to Ohio River, and I can assure you the geology does not stop at the river. And so we think there's quite a bit of upside with that. It's something that the teams have been working for some time. It's just really about kind of getting into the right environment which that inventory development makes sense.

There will be some infrastructure requirements to be able to process it. But it's something that we think we can take some of the learnings that we built up of drilling deeper gas wells in the Haynesville and leverage those learnings in the Utica and expect it to be a highly profitable part of the business going forward.

Our next question comment comes from the line of Mr. Phillip Jungwirth from BMO.

With the NGI pipeline now flowing volumes, can you talk through how this will benefit expand this year also as Golden Pass starts up? And is there a benefit to maintaining ownership in the project long term or at least through a potential expansion?

Phillip, this is Dan. I'll talk about the market dynamics. So yes, NGI came out in October last year, and that's providing us just, again, more market optionality, and that's bringing our guests to Gillis, which over time is going to be a pretty premium market. At the moment, we're getting about even on where we are and the capacity payments we get and the uplift we're getting. But over time, back to the structural demand of this market, LNG is growing significantly, and we see Gillis become an even more premium so it's providing us 2 things. It's getting us to premium wholesale market and is providing us market optionality where we can move between Gillis and Perryville on any given day.

Okay. Great. And then besides the capacity going to Gillis, you also have 2 Bs a day going to Perryville. So it's further away from the LNG corridor. So can you just talk about the advantages of selling gas to the hub? And how would the go-forward marketing strategy tailored here versus volumes going to Gillis?

Yes. Perryville is also a great -- there's a strong pull from the utilities down in the Southeast. A lot of that's come from the dynamics of Gillis, more gas is being redirected to Gillis for the LNG demand and the historic gas that would come across over to Perryville has been less. And there's more demand that's going to be taken away from Perryville. There's I think BCF of new pipeline capacity coming online, pulling further down to the Southeast. So this market is also a premium and a lot of utilities are looking for that longer-term reliable supply. So our advantage here is actually the ability to go to both markets, not only structurally selling to these markets, but any given day, being able to move molecules between the 2 markets.

If we sell down in Gillis and the Perryville market changes, we can buy back that position at Gillis or buy gas into that position and move gas [indiscernible]. And we've been doing this quite a lot, and I'm quite proud of the team on how they're to capture that optionality value, and we're just going to continue doing more than.

Our next question or comment comes from the line of Betty Jiang from Barclays.

Mike, completely with you on the scale of the marketing opportunity and sort of the need to think older. I'm just curious on your $0.20 uplift that you talked about. Just how you came up with that target? And do you see that as a reasonably achievable number? Or it's more of a stretch goal for the organization?

I don't think it's a stretch. Let's just start with that. I think it's something that we'll have to be aggressive to do. It's something that we'll have to invest time and energy into but I don't think it's a stretch. We'll definitely have to pull all 3 of our levers. Lever 1 is premium markets, too. We need to work on our storage. And three, we're going to have to participate in the value chain beyond the wellbore, and that means LNG or industrial.

And so I don't think that. I think this will be a big part of our business going forward. And I also think that will help our breakeven -- that will help our downside protection because those tend to be a bit more fixed -- closer to a fixed fee concept, if you think about it. So I don't think it's a stretch. I sure hope that we make it really quick, so that you all can be comfortable and then I hope to expand that over time.

Great. No, that makes sense. And a lot -- definitely a lot of opportunity to fill in the hopper. My follow-up is on M&A. A lot of talk already on the Gulf Coast, but we have also seen just rising deal-making Appalachia. What's your appetite for M&A in the Northeast? Is there a value to having more in-basin exposure in order to capture that growing power opportunity of north?

Yes. I think M&A has been something that we've done a lot of over the past 5 years. You can see, I think we've done over $15 billion of transactions. So it's in our DNA to continue to look at everything. And Appalachia course and the liquids concept that you all mentioned earlier, of course. The question is, can you do a discipline. Can you do it to protect the balance sheet? Can you do it with the nonnegotiable? This year, we weren't able to. I mean some of these deals went for premium prices that we didn't think were fair value. So the answer is we'll look at everything in our basins. Of course, that's our job. But M&A is a tricky market. You kind of have to think about your base business first. So -- and we'll do that. .

Our next question or comment comes from the line of Kalei Akamine from Bank of America.

Mike, going back to your comments about marketing, you expressed the desire to be more commercial around your volumes. When you look at your portfolio, I'm curious how much gas you're asking to long-term sales agreements, trying to get a sense of how much flexibility you have in the portfolio to ship gas to higher value markets. And is it fair to think that the more flexible molecules in that portfolio is in the Haynesville?

I think it's 2 things. You're right to point out, of course, that we make commitments every day and some of those commitments would have to be rolled off. I don't think we have a set number in my mind exactly and Dan may be able to answer that question. But I do think the Gulf Coast is where we can build. It's where we can grow. We could add volumes to there. And so to the extent we get demand, more demand, we can increase production to fulfill that demand. And so I think that's always a great answer. In Appalachia, you have less ability to do that, and we're talking about growing there, but the Gulf Coast is where it is.

And we feel it's our competitive advantage. I mean we have 3 basins. Everyone else has one. We have a bigger market area. We have to take advantage of it, but the ability to grow and frankly, strength the Haynesville gives us a lot of marketing opportunities.

I would just add that we do stage those commitments. And on Page 19, we laid out a couple of commitments we just made, right? And over a 5-year time, we have commitments that go up 15 years, but over a 5-year time frame, it's really we're looking at doing a lot of our sales we just added a couple of sales to premium markets here. So these aren't the big deals that we're going to announce, but these are the singles and doubles that we're doing every day, adding more sales to end users and just getting that premium uplift. And the sale becomes an asset as well, as I pointed out in the last point here is if you make a sale and markets move, you can still fulfill that sale with other gas and move your molecule to higher-priced markets.

So there's a double combination here of market and capturing the volatility.

I appreciate that. The second question is on the LNG exposure. [indiscernible] desire was for exposure to be somewhere between 15% and 20% post-merger, that commentary shifted a bit. What does desired exposure would like to be? Is it a quarter of gas? Is it 1/3? And do you think it's necessary to physically match the molecule what the wellhead to take away on the water? Or is there some synthetic way that you could go about it?

Yes, Kalei, great question. And I'll start and Dan can jump in here as well. that commitment that Chesapeake had made prior to close, the 15% to 20% on LNG. If you think about it, really, the gas markets have changed quite a bit since then. Back then, we probably weren't talking near as much about power and industrial demand growth. And so really, when you think about it, and we've mentioned this several times, we're interested in reaching premium markets. We're agnostic really to exactly what those premium markets are. We think the opportunity set is broad. And so we're going to look for the highest return way for us to diversify our sales exposure. So we're not going to be overly prescriptive on exactly how much we want to go to LNG.

Our next question comes from the line of Leo Mariani from ROTH.

Let's talk about this a lot, but just on the goal of the $0.20 uplift on gas. Is there kind of a rough time frame for that? And you kind of mentioned trying to get some deals kind of over 3 to 5 years. I'm just trying to get a sense if that's kind of like a 5-year goal. Any other color on that?

I would say, yes, it's 3% to 5%. And I'm giving 5 to give us some room. I certainly hope to make that in 3, 3.5. And so we want to be aggressive here.

Okay. And then just following up on the buyback. You guys kind of spoke about this I don't want to put words in your mouth, but it sounds as if it's really going to be times of dislocation in the stock and the priority is really going to be just to make this balance sheet even more rock solid here.

Agreed. We totally agree with your statement right there. .

Our next question or comment comes from the line of John Annis from Texas Capital.

For my first one, you noted around 20% of the 2025 TIL succeeded 1 Bcf per 1,000 foot and you expect that to rise above 30% in 2026. I wanted to get a sense of what's different about those top-performing wells? Is it geology, lateral placement, completion intensity or some combination and then is there a ceiling on how high that percentage can go given your acreage mix?

Yes. I mean it's definitely a mix, John. Completion design is really going to be the biggest driver for us moving forward. But clearly, where you drill is going to matter as well. So typically, we see the best performing wells in the southern part of our acreage position within the NFC. And so you are going to be limited in the number of wells you can drill in any one gathering system. You'll just simply hit capacity constraints. .

So yes, to answer your question, there would be some constraints. But we just see continued upside across the entire acreage position we've had a lot of success this year, drilling 3-mile laterals. So we're going to continue to get better and see a bigger portion of that going up going forward. And as I mentioned earlier in the call, I don't think we've reached what we really deemed to be optimal from a completion design standpoint. And again, we continue to reset those economics as a result of having access to a cheaper sand source.

Makes sense. For my follow-up, you mentioned supplying microgrid solutions in Appalachia with flexible volume contracts -- how large is this opportunity today? And how would you compare the attractiveness of these smaller volume deals with some of the larger supply commitments announced in the basin?

John, thanks for the question. Yes, we went live with this microgrid solution. It's relatively small, to be fair. But we're excited about these because a bunch of these small deals adds up, and this actually commands up quite a premium by having a reservation fee behind our gather system where this micro solution can pull volume for us and capturing a higher price. So we're getting to dual effect here of a reservation fee and a higher price. It's small, but these singles are going to add up over time. And we're going to do a lot more of these types of deals.

Great. Thank you everyone for their questions today. We want you to ask tough questions. We want to be responsive to it. So thank you for them. I'd like to close with just a few sort of big picture comments. Number one, our execution has been amazingly solid. That is our foundation. We are not changing in. We expect it to continue, and we continue to expect our teams to perform better in the future. Two, we are definitely thinking beyond the wellbore.

Obviously, we've talked a lot about marketing today. That is actually not a strategy change. We had that strategy. What we're talking about changing today is urgency, attention, discipline. We want to be more aggressive, but always know that we are rate of return and build [indiscernible] value, you have to have that. Third, the opportunity is huge. We see it. We finally feel like [indiscernible] has got this moment, we want to take advantage of it. The demand is amazing. And then now it's just time for us to sort of not talk and execute. And so that is our focus here at the company and will continue. So with that, I think that's the end of our call and hope you have a good day.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may now disconnect. Everyone, have a wonderful day. Speakers, stand by.

All right. 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 macro.

Great. Thanks. Well, listen, we really appreciate everybody's time today, and thank you all for being here. So the 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 is 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 '26, '27, second half of this decade are set up great, and we think there's a great ramp for Expand Energy.

Sam?

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 '25, 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. And our analysis would have suggested that you would have seen modest growth away from that. And instead, we saw pretty significant growth. And 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 and what that we think was driven by is that Appalachia, of course, is a function of its local demand. And so local demand was higher. And when local demand goes up, you see production able to elevate because it sits sort of behind pressure there within the basin. So that's pretty explainable too.

But overall, on balance, I would say, yes, we were surprised. And the question, I think, for us coming into this year is how sustainable is that at the current price deck? And 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. And it did that because there was a view of structural demand growth coming, the need for supply growth, and that signal was effective. And 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 and we're not upset about where the forward strip is for '26 and '27 relative to the business we planned for.

We've continued to talk about mid-cycle price expectations of $3.50 to $4. It's right where we are when you look at the '26 and '27 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 can 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 yes, 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?

Well, 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. And everybody was motivated to do that. It was a very clear short-term signal that I believe the market reacted strongly too.

I would also note that in general, the industry has done a better job of timing. It's turn-in-lines on an annual basis around the fourth quarter. And so we -- for the last couple of years, you have seen the industry do a better job of creating its -- lot of turn-in-lines or the pop 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 breakeven 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 then 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 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 over reported? Is demand under reported? We think all of those numbers end up being a little bit fuzzy on intrastate 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 '26 and '27, 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 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 Harry 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 the 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. [ Damian ] 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 what 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, but 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 don't believe it is a -- I think it's a trend that will be absorbed.

And one last one for me and along those lines. When we look at -- even without including additional Russian gas, our base case is that global LNG supply is going to grow enough that we see ex U.S. balances becoming overwhelmed by '28, '29. So we do see the turn back of U.S. LNG as more likely than not in those periods in early '28 and early '29. 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 that -- 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, 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 8 quarters forward? And is the market still giving you the signal to be ratable with that?

Yes. 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 the 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 2 to 3 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 2- to 3-year cycle of capital allocation. That just tells you, by definition, you should be hedging your near-term price exposure.

If you want to look 3 years out and have a different view for price, great, change of 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 each 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 event 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 yes, 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.

And you've been very clear that $3.50 to $4 is the right range for you. And 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 as you -- you have a different -- 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 '26 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?

Yes, 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 is 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 your -- 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 attract 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 to $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 to $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 like 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. People that are -- especially people that are relatively new entrants or managing an international portfolio of exposure where they're short U.S. 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 million to $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 $1 million 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 have -- we're in the process of drilling our first well -- our first horizontal well. And 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 NFZ, on the Louisiana side, we have a large position there, and we are far and away the low-cost operator in that area. So 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 will take us a little bit of time, though, to know what we really own.

And 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 looks 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 think -- 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 in to those transactions, the 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. And 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, and 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 is pretty high on the cost of supply curve. So can you lay some the market concerns that might be there?

Well, 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 NFZ, 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 on -- in this asset as well. We have a lot of experience around the technologies that helps 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 other -- 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 are some changes in rules with things like constitution. Just your view of can basis get better? Or is this something that we're going to be living with for a long time?

Well, I do think basis can get better. I mean I think you have such an increase or -- I wouldn't even say increase, let's 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 do -- would be fighting for that space to do the same thing. So it will be a market share rate 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 continue -- 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 a day 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? And if that's not enough, what would you see as the next best thing to be developed in the U.S.?

So let's -- what are we talking about for Haynesville. To me, when I think about Haynesville, I think of the traditional core of Haynesville is 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 8, 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 breakeven locations are in the U.S. and what the cost is required to activate those breakeven locations. And so I think for us, sitting in the Haynesville with 15 to 20 years of inventory that is breakeven at $2.75 today for us, we sit in a great place to see our margins grow while the marginal breakeven of the industry moves into other plays. We're very pleased with that set up. We do not think the 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.

And as we go along that supply curve to more expensive areas that 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 to $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.

Yes, that makes sense. Thank you, Nick.

Thank you, Nick. Great conversation. We appreciate you taking the time.

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. And 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, 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. And I want to get your outlook for this upcoming year and then maybe a little bit longer term in the next 3years?

Yes, sure. I mean, I think we remain pretty constructive on the natural gas macro. There's, of course, a lot going on. And I think in the near term, I think 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.

So we think weather will continue to play a pretty big factor heading into 2026. Obviously, December will be pretty important. I think any time 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. So 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. So we continue to remain on track with that.

Production in the U.S., obviously, is another factor that we pay pretty close attention to. And here, we sit at about 108 Bcf a day across the U.S. And 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 Permian 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. We're able to generate more production per rig unit than what we've seen in the past. So 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. But the fact that you can't ignore is that year-over-year '25 to '26, we expect 4 Bcf a day of incremental demand from LNG in the year. And so 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. So that will help support that 4 Bcf a day of year-over-year growth. So 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.

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. It 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 '26?

Yes. 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 continue to see volatility in the commodity. And again, despite this constructive outlook, volatility will be there, and it may even be more extreme than what we've seen in the past.

And so 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 1x 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.

And 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. And so we continue to prioritize capital allocation to the balance sheet. And the way that we think about it is as we find ourselves in a cycle that we're in today where the markets are quite constructive, we're 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.

And what we think that would position us to do is if we find ourselves in a bear 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. And I think as an industry, that's really where we've been challenged through times is that inability to through cycle, generate return for our shareholder.

So 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. And so that's something that we think is going to be a distinct advantage for us and the 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 0 for a period of time and 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 end up with a low 2 handle or something in the mid-2s 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?

Yes, it's a great question. I mean one of the things we love about our business is the flexibility that it offers us. And it's easy to tell stories when you've done something before. And I guess what I would go back to is how we talked about productive capacity in 2024, where we continue to drill wells through the cycle, but we materially pulled back on our completion activity in the year to start building DUCs. We started putting on hold the turn-in line of new wells.

And so when we exited 2024 coming into a more constructive 2025, at that point in time, we had roughly 70 wells for subject for TILs around 1 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.

And so 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 2 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 3- to 5-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.

So if you didn't have that, it's more DUCs and maybe...

Deferred TILs, mines, yes.

Deferred TILs. But if it was a change in the mid-cycle price for whatever reason, then you actually think about it. I think some rigs.

That's exactly right. And 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 at which we communicate our capital allocation. 7.5 Bcf a day at a $3.50 to $4 mid-cycle price, we believe generates the maximum amount of free cash flow for the business. So that's what we're simply trying to optimize around. And again, 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.

I want to talk about the Haynesville. You've seen some massive capital efficiencies there over the past year or 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. But 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? Well, I guess just if you could 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 proppant, you've certainly used less proppant than Southwestern has there, but is that part of the recipe going forward as well?

Yes. We've made a ton of progress in the Haynesville. And of course, underpinning the merger with Southwestern was what we thought we could do with the cost structure in the Haynesville. And we started out with $400 million a year synergy that we would deliver over a 3-year time period. That's now $600 million per annum, and we'll do that by year 2. So bigger synergy target. We're delivering it faster. Again, predominantly, we're seeing those benefits show up in the Haynesville.

And In fact, right now, when we look at our Haynesville business, we see that business unit level breakeven at less than $2.75. And 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. So 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. And that's been an amazing story for us. Again, it was underpinning our synergy target. We thought $400 million a year, a relatively modest improvement in '25 was achievable. But I would say we've exceeded all expectations in terms of it. We think we'll continue to see drilling efficiency improvements. Every path that we take, we learned 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. And so you're reliant upon third parties to truck in sand to support that operation. And we were finding they were struggling keeping up with the demand that we have.

And so it was at that time, we started evaluating additional sources or different sources of sand. And we're one of the few companies, maybe the only company operator in the basin today that directly sources from an Expand Energy-operated sand mine. So we made an investment in a sand mine there. That investment will pay out. It was a little over $30 million. It will pay out in roughly a year. And that equates to around a $50 per foot improvement in a horizontal well cost.

So 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 4 frac crews. And so 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. So that will generate additional savings in time.

What's interesting about your question, you specifically asked, would be reducing proppant intensity. So 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.

So 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 and 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. And oh, by the way, that's inclusive of the capital that we'll deploy into our new East Texas asset to appraise that program. So 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. So 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, the depth of inventory, why the need to go add to that? And how do you view this Western Haynesville is 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.

Yes. Well, nothing is free, first of all, but it's absolutely cheap option. Yes, it's a low-cost option. And so it's something that we've actually been working for a couple of years. We actually started taking leases in the 2023 time frame. We have pretty good data sets in the region, obviously, watching competitor wells to help prove up a concept. At the time, though, 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.

And so we started slowly building position. We drilled a vertical well late in '24, 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 well was -- vertical well was very successful that proved the presence of a really good quality shale. And that allowed us in early '25 to really start more aggressively taking a lease position there. And ultimately, we've ended up with a little over 75,000 acres that we've put together for less than $100 million.

So to your question, we do like. This is a low-cost entry. We are a depleting business by nature. And we think when you have opportunities to bring in low-cost inventory into the portfolio, you should be thinking about doing that. So roughly $800,000 a location if we assume 200 wells could be drilled in this acreage position. So roughly $800,000 an acre. If you compare that to recent transactions in the Haynesville, $3 million to $4 million a location. So 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. So it's proximal to the Dallas Metroplex area, where we see growing demand. You still have access being east of Houston, east of Dallas and to the LNG corridor. And so it gives us another market to potentially exploit with our product.

Now 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. So 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'm so excited about, and I think is differentiating, we could go add this low-cost option with no pressure to go develop it. And it's simply because we have 20 years of inventory in Louisiana of the best acreage that's still available, and I could take my time and be very patient and methodical about how I invest and appraise the asset before I ever need it. And 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 the 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.

Yes. Most will know that we have a ton of history in the basin. We've been in the Haynesville for well over 15 years. So 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 NFZ or the Nacogdoches fault zone. That is one of the deepest, hottest areas in the play, maybe outside of the Shelby Trough.

And so you're developing down around 12,000 feet, you have bottom hole temperatures that are 370-plus degrees Fahrenheit. And we are clearly the most efficient operator within that part of the play. And so 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.

And so 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 feet deeper in our East Texas position. So we believe the reservoir is going to be down around 17,000 feet. But 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? Is it in terms of depth and pressure and temperature?

It's a good analogy is what I would say, yes. But again, the NFZ has characteristics that we would deem to be pretty dang similar. And again, we're delivering wells there today in the NFZ that are around $1,500 per foot. And so what I'd 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 feet deeper, you shouldn't be spending twice the amount of capital to do so.

So we have really high expectations that we'll be able to bring those down those costs, move the inventory lower on the cost curve and to again, make it competitive with existing inventory over time.

You mentioned the new assets to have proximity to the Dallas metro complex. A lot going on there on the marketing side. I want to touch on 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. So maybe give us an update on some of the things you're doing on the marketing side.

Yes, 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 and commercial business. So we simply see this as an opportunity and maybe better described as future upside to our earnings growth. And so the way I would simply describe it is there's really 3 key pillars within the marketing and 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. So 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 want to point out is how do I facilitate new demand with my physical volumes. And 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. And the third thing I would just mention that we want to accomplish within our market and commercial business is how do I reduce volatility in my cash flows.

And so the way you can think about that simply put is something again like 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. But something that raises the floor of your cash flow while not capping the upside is the ultimate goal of that business. And 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 -- are there -- 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? And why would, I guess, an industrial customer be willing to do a deal with you at a premium to NYMEX? Why wouldn't they just buy the gas in the market at a discount to Henry Hub?

Yes, it's a good question. And 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. So of that 11, a little more than 2 Bcf a day, we expect to come specifically from industrial users.

So we think we are perfectly positioned with our asset base, again, the deep high-quality inventory to facilitate those conversations. And 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.

Now you asked the question, why would LCM come to you and offer a premium to an NYMEX? Well, 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 cost to flex with price. We think that dynamic is evolving, and it's changing in a way where customers are really starting to think a little bit more holistically about the surety of supply. And 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 the refined product, in this case, blue methanol to a couple investment-grade customers overseas. So they see customers on the other side, but they've committed to providing methanol, and they simply need to derisk 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. And actually, just here in the last couple of weeks, we've gotten reassessed by NIQ with our asset receiving an A grade there. So people are still interested in high-quality, low cost of supply, low-carbon feedstock, and that's exactly what we're able to provide them.

So 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. And again, we think that story will continue to evolve over time.

I'll 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? And should we expect more deals kind of like the Gunvor with a marketer type? Or 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?

Yes. Of course, we're excited about the Delfin-Gunvor deal. It's relatively modest in size. It's 0.5 million tons per year. It will start up later in the decade, and there's a tolling agreement there where within we're selling the product on the export side of their ship to Gunvor. So 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 satisfies their requirements as a consumer while meeting our benefits as a producer.

And 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 derisk the overall investment for the company.

I talked about earlier, one of our goals is to reduce volatility. Well, 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. And so 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. So we're going to be slow. We're 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. But 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 new -- relatively new hire there with your EVP of Marketing as well. It looks like that's going to position you to obviously help with that whole endeavor.

Yes, that's right. I mean one of the things that I think is so important to recognize that so much of what 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, and we have a fantastic team. Dan Turco, of course, leads that organization. But given his prior experience, trading LNG in international markets, he has been able to bring some of those international customers to the table. And we think that, again, provides a strategic advantage for us.

I'd be remiss if I didn't bring up the in-basin opportunities for helping supply power. I know a lot of your competitors have talked about it. We saw Google do a deal here in the Midwest for carbon -- clean carbon power I guess, anything there that we can look forward to that you're working on?

Yes. We have a number of conversations that are ongoing. And really, our goal is to be able to provide that comprehensive power solution. So finding somebody who understands power generation and matching up with our advantaged supply of natural gas and then be able to present that option to a hyperscaler.

So there's a number of conversations that are going on. Again, we need to make sure that the economics work for both sides. But we're anxious, but I would say we don't feel rushed. Again, back to our goals of getting a better product, price for our product, reducing volatility and creating demand. It has to really check all of those boxes for us to feel good about signing up to any type of long-term supply agreement.

Noted. 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?

Well, 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 to 1.3 Bcf a day through the pipe, around $700 million of that or roughly half is our own equity production. With 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. And if somebody showed up at the door with something that we just couldn't pass up, we're going to listen to that conversation. But financially, the balance sheet is in a great spot, and we feel no pressure to look at an opportunity to monetize that right now. So we love the investment. We think there's a ton of value with it, and we only expect that value to increase over time.

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? Is that...

So we've shifted strategies a bit there as we kind of assessed options. So the facility where the pipe terminates does extract the CO2. And we've put an agreement in place with the counterparty that has a local CO2 infrastructure that runs by the facility that essentially sell 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're generating through a 45Q tax credit. So 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 you got.

That's exact. Yes, that's exactly it.

Got you. We haven't really touched on the Appalachian assets at all. Anything there that you would highlight? I mean, you obviously 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. But 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?

Yes. 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 -- and around Monroe County, Ohio. And so we're pretty excited about the kind of emerging as you think about the Marcellus kind of shifting west. So we think there's a lot of upside with that play. Clearly, we -- you've seen degradation in your productivity per foot measures in places like the Northeast App. And that's really just a function that we saw this great opportunity within the Upper Marcellus to start developing that.

We love the economics. It was -- though the productivity per foot is lower, you're able to drill longer laterals because it's less developed. And 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. And so we've really been able to intermix that. And so 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 best capital efficiency as anybody else in the entire Appalachia region.

With that Monroe County acreage, Utica have any potential there as well? Is it just really a focus on the Marcellus?

Yes. Right now, it's -- a lot of the -- the Utica is pretty maturely developed in Ohio. And so a lot of what we see as upside is in the Marcellus.

And any of the assets over there? I know Ohio has been a particular area that has been a focus of hyperscalers. Do 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?

Yes. I mean we anticipate anywhere from 3 to 4 Bcf a day of incremental demand being created in basin, a lot of that coming from hyperscalers and power generation. And so much like the rest of the portfolio, that's another opportunity for us. That's the advantage we have is we're having assets co-located in basins with growing demand is a great option for the company. And so as those opportunities mature, specifically in Appalachia, absolutely. Again, we're one of the largest producers there in the entire Appalachia region. And so any hyperscaler or power developer is going to be interested in talking to expand to supply their power generation facilities.

Done through my questions. Anybody else have any? Going once, going twice. Well, Josh, thanks. Really appreciate your time.

Okay. All right. Thank you, Mike.

Good day, and welcome to the Expand Energy 2025 Third Quarter Earnings Teleconference. [Operator Instructions] Please note this event is being recorded.

I would now like to turn the conference over to Colby Arnold, Manager, Investor Relations. Please go ahead.

Thank you, Jonathan. Good morning, everyone, and thank you for joining our call today to discuss Expand Energy's 2025 third quarter financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday.

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including factors identified and discussed in our press release yesterday and in other SEC filings. Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods with peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure, and it can be found on our website.

With me on the call today are Nick Dell'Osso, Josh Viets, Dan Turco and Brittany Raiford, Nick will give a brief overview of our results, and then we will open up the teleconference to Q&A.

So with that, thank you again, and I will now turn the teleconference over to Nick.

Good morning, and thank you for joining our call. The third quarter marked the first year of Expand Energy. I'm extremely proud of the way our team has come together to collectively drive long-term value through safely reducing costs and efficiently developing our advantaged geographically diverse portfolio. As we demonstrated this quarter, our business continues to deliver and outperform every expectation pegged at merger onset. While there are many ways to measure synergies and their impact, we are clearly spending less for more production, which is the ultimate definition of efficiency.

Nowhere is this more evident than in our Haynesville position, which has seen a meaningful step change in both efficiency and performance, enhancing the value of our 20-year plus years of inventory. Today, we can deliver with 7 rigs, the same production, it took 13 rigs to deliver in 2023. Since then, we have reduced well costs by greater than 25%, and year-to-date, our costs are 30% lower than peers based on third-party well proposals. Importantly, our optimized development and completion design continues to lead to improved productivity.

Since 2022, our average well productivity was approximately 40% greater than the basin average, a trend we expect to continue. These efficiency gains are sustainable and deliver significant improvement to our breakevens, which today average less than $2.75 across the basin.

We have also used our low-cost advantage to attractively -- to add attractively priced acreage to our portfolio, giving us an option to develop volumes in East Texas and reach additional markets. Through the innovative efforts of our team, we are seeing success stories like this across our business, resulting in us delivering 50% more synergies than our original target. These meaningful efficiency gains and savings have greatly strengthened our underlying business and resulting cash flows. Since close, we've eliminated $1.2 billion in gross debt and returned nearly $850 million to shareholders.

We now expect to spend $150 million less to deliver 50 million cubic feet per day more of production in 2025 compared to our beginning of the year guidance. These efficiencies will carry forward to 2026, where should market conditions warrant, we are prepared to deliver 7.5 Bcf per day of production for approximately the same CapEx spent in 2025.

Looking ahead, we see significant opportunity to expand the value of natural gas by connecting our global scale to growing markets. Consumers need affordable, reliable, lower carbon energy and natural gas will play the largest and most crucial role been answering that call. By the end of the decade, natural gas demand is expected to grow 20% driven by LNG, power and industrial growth. Expand sits in an advantaged position today. our diverse asset portfolio across 2 premier gas basins with 20 years of inventory, proven operational performance, unique market connectivity and investment-grade balance sheet are clear differentiators as we look to serve customers eager to secure reliable and flexible supply.

This is especially true along the Gulf Coast, where there is increasing competition for supply and lower carbon molecules. With NG3 now online, we can track our production from the wellhead to the end user and offer a responsibly sourced, differentiated lower carbon gas, something our counterparties value greatly as was the case with Lake Charles Methanol supply agreement we announced yesterday at a premium to NYMEX.

Expand will serve as the sole supplier to this new build industrial facility, which is expected to commence operations in 2030 with global investment-grade offtake already secured. Importantly, we believe this agreement demonstrates our differentiated path to strategically connect our molecules to the highest growth markets at a premium price.

This announcement is also a great example of the evolution of our marketing strategy from value protection to value creation. We are intentionally enhancing our marketing and commercial organization to capitalize on our unique position as North America's largest natural gas producer. We see this organization as more than a few commercial transactions, but an opportunity to drive long-term value from our integrated well-connected portfolio.

As consumer demand grows, we will be positioned to provide reliable and flexible supply to meet that demand. We have the assets, scale and capital structure to be patient. Our experienced team will continue to ensure we are achieving the best long-term risk-adjusted returns possible in any agreement we enter. We are ready to answer the call of growing demand we see ahead, and we look forward to updating you on our progress.

We'll now turn the call over to Q&A.

And our first question for today comes from the line of Matt Portillo from TPH.

I wanted to start out on a question that may be focused a bit more on the medium term with the outlook on Page 9. Just curious if you might be able to speak to the evolution of gas demand you're seeing regionally around Texas, Louisiana and Arizona, and if your downstream counterparties are starting to realize the value producers like yourself, might be bringing to the table for contracts that will require 10 to 15 years of coverage. I guess to us, it seems like there might be an interesting supply-demand imbalance emerging on the Gulf Coast with the lack of material long-haul pipeline capacity from the Northeast and dwindling inventory from smaller privates in basins like the Haynesville but curious on your thoughts around the regional dynamics.

Yes. Great question, Matt. I'll start, and I'm sure Dan will have more to add here. Slide 9 is a new slide, our team created this quarter, and we really like it. It shows the current demand and then the expected growth in demand in each of the interesting growing submarkets of the U.S. And so what we've created here is a way to think about where demand is growing along the Gulf Coast, including onshore Louisiana as well as LNG in Appalachia and then in other key markets like the Southeast and Florida.

And I think you're right to point out that as demand for gas is growing and growing in a really tangible way, we have more insight into how gas demand is growing right now than we've had in a very long time. These projects are multiyear projects. They require billions of dollars of capital, and you can see it coming. And so we can plan for this and we can be ready to help work with our customers to deliver the solutions that they need. I think this is a great -- the Lake Charles Methanol transaction we announced here is a great case study for how this works.

And is evidence of exactly what you just described. This is a project that Lake Charles Methanol is going to be a new demand facility built along with the offtake customers supporting the facility, so requesting the methanol product, it's in need around the world. That offtake has been fully subscribed. They need to lock down the economics of the project to go out and get the project FID-ed. The supply of gas is a really important element of that. They look to us with our depth of supply and inventory to drill, our ability to bring large volumes to South Louisiana, and then for those volumes to have a low carbon intensity. And they were wanting to lock that up for 15 years. And so we were in a position to accommodate that.

I think this idea that gas demand, especially new gas demand growth needs to have clarity as to where the supply will come from. The depth of that supply, the characteristics of it, the credit quality of the counterparty providing it, all of those things need to come together in a bundled solution that we're uniquely positioned to do in this transaction, and we believe we'll be in a unique position to do across many transactions in the future. So it's a good example of what we think is plenty to come.

Matt, you hit on an interesting dynamic at the start of your question that I'll just add to you is that demand is growing in South Louisiana and our portfolio sets up well, especially where our asset base is, as Nick talked about, and our capacity to get there. And you said, where is the supply coming from and the challenge from associated basins. And we agree that there's going to be a lot of supply that comes out of associated basin, especially the Permian. But as you see pipelines being developed, the terminus of those pipelines end up in Texas.

And so getting across that border from Texas, Louisiana is a bit of a challenge. It will happen, but it takes a longer time, obviously, with interstate pipelines, it's a longer build to get across that border. And so we set up quite nice to where our demand ends at the end of our NG3 and [indiscernible] pipeline into Gillis. And where customers are looking for that security supply, as Nick touched about. So it is an interesting dynamic about where demand is growing and how it's actually going to get supplied from the different regions across the basins.

Great. And then just as a quick follow-up. Nick, curious if you might be willing to comment on your views around the evolution of mid-cycle gas prices. I guess specifically, as we kind of look at the Haynesville or regionally in Louisiana, you're projecting about 11 Bcf a day of demand growth regionally. And I think most forecasts even with really robust gas prices, I expect maybe the Haynesville can grow 6 to 8 Bcf before starting to face some pretty significant inventory challenges. So you all are kind of in a unique position given the depth of your inventory.

I guess, bringing this back to Slide 7, you highlight kind of maximizing free cash flow at a kind of 8.25 Bcf a day production level would require kind of a $4.50 gas price over the medium term. But I think if you all keep pace with the Haynesville growth moving forward, your corporate production would be in excess of that.

So Nick, maybe just specifically curious as you get more comfort around this regional demand growth trend and the Haynesville being part of the production engine that meets that demand. How do you think about the mid-cycle gas price? And is that right-hand side of the chart kind of closer to that $4.50 level, a good place to be thinking about? Or are there other factors that are involved?

Yes, it's a great question, Matt. At this point, we're still focused actually on the columns of the chart that we've highlighted there, $3.50 to $4, centering on $3.75. There's so many unknowns to how this will all evolve and we think taking a measured approach to how we set up our supply in the context of the broader U.S. market that is now increasingly connected to the global market is the right answer. I do believe that over time that our view of mid-cycle prices can go higher. I don't think we're quite there yet. I think there's a lot to still happen with the timing of how this demand will grow.

You'll see some of the numbers that are on this Slide 9 that we put out today are a bit more conservative than many other forecasters in the market. We're pretty -- I would say, I guess, conservative is the right word around how we think about the pace at which this demand will grow. I think it's important to note, though, that when we talk about all of this stuff, this slide is framing between now and 2030, 2030 being the end of the decade is a point in time that the market has become focused on we don't believe demand growth stops in 2030 by any stretch. And so our view relative to some of the other more aggressive views of demand growth is really a difference in timing more than it is anything. There's a lot [indiscernible] to create all of this demand growth.

And so we think while it is big, it is very meaningful and there will be supply constraints to deliver to certain of these markets at certain times, there's going to be a lot of volatility around it. And we're ready for that volatility. I think our business is uniquely positioned with the geographic diversity we have with our approach to being willing and proven to modulate supply up and down. We're -- again, really ready to take on the challenge of this volatility and help our customers have the surety of supply that they need with the characteristics of supply they expect.

And our next question comes from the line of Doug Leggate from Wolfe Research.

Nick, I wonder if I could hit two things. First of all, there's been a lot of moving parts, obviously, in the cash flow capacity of the portfolio. So I'm really focused on where you think your breakeven is trending with the continued synergy delivery. And more importantly, you've dropped your sustaining capital by, it was like $150 million, which that alone is pretty meaningful in your stock. So where do you see your breakeven today? Where do you see it trending?

And I guess my follow-up, forgive me for this, I kind of asked it fairly regularly, but you've given a lot of insight into the role or the impact that Dan and his team are having. Where would you see the -- what kind of [indiscernible] are you and if you like, in terms of the marketing uplift? And if you can quantify how do you see your realizations been impacted by that big rate. So those was my two, please.

Okay. Great. I love talking about this, obviously, Doug. So the capital efficiency that our business is showcasing right now is tremendous. And we're beating our own expectations, beating the synergy goals we laid out the onset of the merger and then, again, making faster progress towards reducing costs and increasing productivity across our entire portfolio. That's driving our breakevens lower.

Importantly, we're talking about this morning the fact that our 2026 setup looks even better. We had said at the beginning of this year that we wanted to set up our productive capacity for 2026 to be 7.5 Bcf a day. That is what we are positioned to deliver. We can hold that level of production through 2026 and going forward with a very similar CapEx profile to what we have this year. So $2.8 million to $2.9 million in CapEx is the right way to think about what we're setting up for in 2026.

Now lots of things could change between now and when we actually go through '26. So what we determine is the right level of activity and the right level of production based on market conditions will undoubtedly change, and that's the flexibility that we've been excited to build into our business and embrace. But that capital efficiency is what we want to highlight by showing that we can deliver that level of production with about the same amount of CapEx that we had this year.

So what that means is that these improvements in our cost structure alongside the productivity are sustaining, and we're going to hold those going forward. We're pretty excited about all of that.

As to your question about what inning we're in with how we're seeing the uplift of marketing. I guess I would say we're still in pre-game warm-ups to keep the analogy going with baseball here. This is a very newly emerging part of our business that we are putting resources behind and giving a mandate to this team that is a highly effective team that we can let go out and create more value than historically they've been positioned to do inside of a company that was of lower scale and not investment grade. So with the tools that this company has now around what is a talented organization, we can go out and do so much more. And this Lake Charles Methanol transaction is the first example.

Nick, can I pin you down just on one specific, are you under $3 now breakeven?

Yes, Doug, we are. We've made a ton of progress on our breakeven. Of course, the merger was really a key catalyst for that. But we think if we were to go back kind of premerger in 2024 to where we are as we see the setup for 2026, we're over $0.15 improvement in a breakeven and sitting well below $3.

And our next question comes from the line of Betty Jiang from Barclays.

I really appreciate all the color that you're laying out, Slide 9 and 10 on just growing the gas marketing opportunity. If I can just ask about what is specifically means for your gas realization over time. The methanol deal is obviously helping in the 2030s and beyond. But the opportunities that you see, do you see your gas realization and depth just narrowing over time as you start capturing all these opportunities?

Yes, Betty, it's a great question. We do expect to add a lot of margin through our marketing business. There's so many elements of this, and Dan will add to my answer here, but we'll optimize the delivery of every molecule that we sell today across our extensive firm transportation portfolio and all the markets we reach, we'll aggregate supply and create value off that aggregation. And we'll continue to connect to customers that need surety of supply and work with them around the reliability and flexibility that they require. I think you get paid for the combination of all of those things that we bring to the table.

Betty, thanks for that question. I'd just add to the two elements we're really focused on right now is that optimization that Nick talked about. The team has already done a great job this year of being able to optimize our portfolio. We start from a great position with our asset base and our transportation portfolio. And our team is being able to optimize across different markets, across geography and across different time with storage and different assets we have to be able to create realizations that are meaningful. We've already taken tens of millions of dollars -- low tens of million dollars and added that to our realizations and just expect to do more over time.

And then that LCM example is a great example of how we can be differentiated, offer customer solutions. You pointed to Slide 10, that gives some of our guiding principles of how we think about these deals and what we're looking to accomplish and different elements of these value chain creation. In LCM, for example, we hit a majority of these elements. And we have a ton of inbounds right now and plenty of conversations going on where we can do a lot more of these deals and create a lot more value for the corporation.

That's great, very exciting developments there. And then my follow-up is just on the M&A side, the resource expansion that you highlighted both the Appalachia and the Western Haynesville. Maybe bigger picture, what are you looking to achieve with these type of bolt-on/small deals, do you see more resource opportunities and similar type of deal to acquire locations at a low cost.

Yes. Betty, this is Josh. I would maybe characterize the two acquisitions of organic leasehold in two different ways. The acquisition in the Southwest [indiscernible] was purely opportunistic. That's clearly highly synergistic with our existing acreage position. It allows us to extend moderate links almost more than double lateral links, which gives us an opportunity to pull forward inventory and simply improve the overall return profile there.

And in the Western Haynesville, that's -- we think about that a little bit differently. That's something we've been studying for a number of years now, and have been very thoughtful about what an entry might look like. We wanted to get in at a low cost. We would ensure there was limited near-term obligations. And we are also looking for a part of the play that we would see as being lower from a geologic complexity standpoint. And we think we've done that with the 75,000-acre position that we've created. And as we think about that going forward, we simply see that as a great option for the company to be able to develop a resource with a tremendous upside in an area where we see growing demand.

And so we'll continue to be mindful of these opportunities as they appear. But of course, we're always going to be sticking to our M&A nonnegotiables with any transaction that we evaluate.

And our next question comes from the line of Kevin MacCurdy from Pickering Energy Partners.

Kind of sticking with the Western Haynesville. I mean, it sounds like you've already drilled a vertical well there, and you did some leasing maybe before this last acquisition. Can you kind of expand on what you saw in that vertical well and what was attractive about this particular area of the Western Haynesville?

Yes. Thanks, Kevin. Happy to address that. We've been, again, studying this for some time. And so we have a pretty extensive data set across the entire region, just given our decades and a half of experience here. And so we've been very thoughtful about integrating new production data that came available from some of the developments further to the West, incorporating that in and calibrating our models. And then with the vertical well, that was, of course, pretty important for us to serve as a good final validation of the resource potential that we saw.

And what we found is a thick, very dense shale reservoir that we think presents tremendous upside. It has a lot of characteristics that we're accustomed to developing in areas like the NSE and our southern portion of the Louisiana play. And that really kind of met all the requirements that we would think about to support future development.

But I would just note though, for the company specifically, this is something that we still see as carrying some level of uncertainty with it. And I think that really goes to the entire Western Haynesville area. Long-term decline is something that we definitely need to monitor. And I think the advantage that we have in the play is that with 20 years of inventory in Louisiana, we can definitely be measured in our approach. We'll drill our first horizontal production well here later in the fourth quarter. But really will need time as we head into 2026 to further assess that.

But again, the resource potential is quite high. We like the option that it creates. And again, given the depth of the inventory, we're going to be very measured in our approach to how we develop going forward.

Great. I appreciate the detail on that. And as a follow-up, kind of moving back to the core Haynesville. And it looks like a lot of the CapEx savings and even outperformance on the production side has come from the Haynesville. What are the most notable differences between your expectations coming into the year on the drilling and the [indiscernible] of the wells. And you kind of mentioned in your earlier remarks that you think you're doing well significantly cheaper than peers. Without giving away your secrets, do you know what you're doing different that is causing that well cost saving?

Well, one of the things that has helped us, of course, is just putting two teams together, where we've been able to leverage the experience of two companies. And I think the drilling improvements that we've experienced over the last year I think, have just exceeded all of our expectations and really a credit to our employees and to our contractors that help support that. And so we continue to make strides. And I would say the most material cost improvements that we've made and where we see differentiated performance is on the drilling side.

But also, I think I would like to talk about completions just for a little bit there because there's really two components to it. Of course, we made an investment in our own sand mine, which I think is a unique opportunity for us because of the scale of program that we run, where we're going to be pretty consistent in running anywhere from 2 to 4 frac crews. And so we can go make that investment. It pays out in just over a year's time and has a material impact on our well cost.

And then when you combine that lower source of sand or lower completion cost, that also now presents an opportunity to where we can be a little bit more thoughtful about our proppant intensity on the wells that we're completing. And so through the merger integration, we knew that the two companies had different approaches to completion design in terms of both fluid and proppant intensity. And so through the integration, we landed on what we would consider kind of our Gen 1 as expand completion design. And we quickly put that into place that merger close. And I would say, even through that Gen 1 design, we've seen improvements in productivity in some of our fourth quarter and first quarter of 2025 TILs. So that's helped contribute.

We've quickly continued to progress that to a Gen 2 design that we implemented in the earlier parts of the year with those wells coming online in the second and third quarter. Those 2 have been outperforming our expectations. And we're already now moving on to the Gen 3, where we continue to see kind of outsized performance from these wells.

So you've seen the productivity trends. We think there's still more upside to be had within that. And we're very excited to be able to talk more about that in the coming quarters.

And our next question comes from the line of Neil Mehta from Goldman Sachs.

Yes. And Nick, great to see the capital efficiency improvement. And that kind of sets up my question for -- as you think about '26, is it fair to say that the CapEx, all else equal, should be relatively flat, '26 versus '25? And what are some moving pieces as you think about the soft guide for next year?

Yes. I think that's exactly the right message, Neil, is that you should think about the same CapEx profile for next year, same dollar amount. The moving piece is, of course, are just going to be the market conditions. So again, one of the things we're really pleased within our business is our willingness and ability to be flexible in how we allocate capital and how we view production within a given year. So we're ready for anything the year throws at us. And obviously, gas markets have been pretty volatile through the summer being pretty soft even through the third quarter. Production has been pretty high.

The '26 setup is different. It looks like we have some pretty significant structural demand growth that should outpace supply for most of the year. But by the end of the year, you've got some Permian pipes coming on in size, and that will again change the dynamic. So we're ready for that volatility and we're ready to be flexible.

Nick, and then the follow-up is just the update on hedge the wedge. The curve looks really good here for 2026 and even into '27. And so how are you thinking about continuing to execute that program and it backwards pretty decently as you get it from '28 to 2030, and I know there's less liquidity. So I'm guessing quarters rolling forward still the right framework, but just your latest thoughts there.

Yes, Neil, this is Brittany. And you're right, we're going to maintain that disciplined approach to commodity risk management that includes layering on those hedge positions over a rolling 8-quarter period. And really, that strategy is focused on adding that downside protection, while also affording significant upside participation. And I think this year is a really great example of the effectiveness of that strategy. If you think about the second and third quarters, we had around $165 million of cash inflows from our hedges. So that's really great to see that downside protection in action.

And as we look to '26, we're about 47% hedged, colors are about 75% of that book. And in '27, we've already initiated our position just under 15% hedged. So even with a bullish outlook, we believe it's prudent to continue to layer on downside protection and the benefit that we have is with our fundamentals team. We have great market insight to proactively manage that book once those positions are layered on. So we're going to lean in when we see opportunities in the market and we consistently add to that position.

And our next question comes from the line of Zach Parham from JPMorgan.

First, I just wanted to follow up on Kevin's question. You took your D&C costs down in the Haynesville and expect those to move even lower in 2026. Can you just talk about the factors pushing those costs lower? Is that mostly efficiency gains that you factored in, in 2026? Or is there some level of OFS deflation built into those numbers?

Zach, really, this is going to be driven by efficiency improvements. As we assess the OFS market and just think about where activity trends are potentially heading in 2026. We would expect the OFS markets to be relatively stable year-over-year from '25 to '26. And so we're really just thinking about how do we continue to strengthen our business improve our operational performance and continue to build upon all the success that we had in 2025.

Josh, and then my follow-up, just on your macro views in general. You've mentioned flexibility and you've got this productive capacity sitting here. As we sit here today, would you expect to be back at 7.5 Bcf a day in January? And maybe just talk about the flexibility you have on when you bring those volumes to market and kind of how you think about that?

Yes. So right now, as we look at the setup, as we exit the year, we do have the ability to be at 7.5 Bcf a day, pretty early in 2026. But like we demonstrated in the past, we're always going to be responsive to market conditions. Our goal is to always be thoughtful about how we shape our production, and that should be in alignment with how we see demand rolling out as well. And so we expect to average 7.5 Bcf a day across 2026, but that doesn't necessarily mean that we're going to simply just be flat as demand pushes higher or if we happen to see market weakness. We're always going to be in a position to exercise flexibility and push volumes higher or be lower. But again, the target for next year across will be 7.5 Bcf a day.

And our next question comes from the line of Charles Meade from Johnson Rice.

I want to ask a question on breakeven and go back to some of the -- I think, your prepared comments. I believe I heard you say in your prepared comments that your -- I think it was your company-wide breakeven now $2.75. And I'm wondering if you could tell me if I heard that correctly. And also maybe remind us what the other important assumptions in that number are? And I'm thinking just to off the top of my head, whether that includes location costs and if there's some minimum threshold return that's baked in that number also.

Charles, this is Josh. So the $2.75 that you referenced is, shows up on Slide 12. Nick did reference this in his prepared comments, but the $2.75 refers specifically to Haynesville. And so think about that as just simply an annual free cash flow breakeven for -- specifically for that asset. So obviously, it would include any corporate items such as the corporate dividend. But what I'd like to maybe just comment there. I mean, obviously, with improved productivity, reducing costs, that's a great combination that's going to pull down breakevens.

Just as a point of reference, if we were to go back to where we initially guided on the company and specifically Haynesville back in February, we would have been sitting probably closer to $3. So we've seen that much improvements in the business. to kind of be able to back out almost a quarter out of our breakeven just across the calendar year of 2025.

Got it. That's great context. Josh, and then maybe this is a follow-up for you perhaps. The Western Haynesville horizontal that you're going to drill in 4Q, can you give us some framework for what success would look like there? What would get you more enthusiastic about the play? And perhaps as a follow-on to the bracket, what we should be thinking about for your activity there in '26?

Yes. I mean, first of all, we need to get this first well on the ground and assess the results before we start thinking about what might else occur in 2026. But to your first question, we've confirmed the geologic model. We have a good understanding of what the subsurface looks like. And so with the well, it's really first about kind of fine-tuning our operations of drilling in this part of the state. And then, of course, primarily, this is really centered around productivity and getting some early time data to kind of assess the overall reservoir performance. But obviously, we'll be monitoring this very closely to help better understand longer term with flow characteristics from the reservoir.

And our next question comes from the line of David Deckelbaum from TD Cowen.

I wanted to just follow up a bit on some of the color and planning around '26. I'm just curious if you could talk to the appraisal program for the Western Haynesville in '26. And really, I guess, how impactful you could see this asset be coming to your overall program in what time frame?

Yes, David. So for next year, the soft guide that we've provided $2.85 billion to deliver the 7.5 Bcf a day is inclusive of the appraisal CapEx that we have planned. So we're not, at this point, getting into the specific details of what all is included in that. But I think it's just important to reiterate that all the appraisal CapEx that we think we need is included in that $2.85 billion. And that really just speaks to the overall improvements that we've seen in capital efficiency through the course of the year.

And I think at this point in time, it's just way too early to be speculating on what might this do to capital going forward. We're really just in the first inning there.

I appreciate that. And then maybe we could revisit this the LCM deal. I know without going into pricing terms, I'm curious just what merits of this deal sort of propelled you or motivated you to sign this one, why this agreement sort of makes sense versus perhaps some others like LNG or power-related contracts, I surmise you're trying to achieve a premium relative to what your forecast might be on 2030, but what was the general thought process or guidelines that you're using right now to sort of engage in some of these offtake agreements?

Yes. Thanks, David. I think Slide 10 is a great slide to lay out how we're thinking about these deals. And for Lake Charles Methanol specifically hit majority of the elements you see on our guiding principles laid across this page, a deal that facilitated new demand and has committed offtake. So a huge win for us. It provides the customer their needs. It provides them reliability and flexibility. The genesis of this relationship is goes back to the heritage companies, [indiscernible] and Heritage Southwestern where they have a long-standing relationship with the principles of this project, [indiscernible]. And so they understand the reliability and the reputation that we bring.

And so they were looking for long-term security of supply. They were looking for a differentiated product. We can deliver the lower carbon intensity score product. And given that flexibility. We have a baseload sale into them, but we also give them a bit of operational flexibility. So we can really manage their supply. So that leads us to achieving that premium price on that deal.

As this deal goes to other deals, we're taking a huge portfolio approach to this. We're looking at LNG deals. We're looking at power deals. We're looking at more industrial deals. But we're really taking it back to these guiding principles and how do they meet and create value for us as a corporation.

So at the moment, we have -- because of our position, because of our portfolio, we have a lot of conversations going on right now. We have something like 20, 25 different conversations going on across the LNG spectrum, across the power spectrum across industry. And again, it comes back to that value creation and then risk reward of any deal we're looking at.

And our next question comes from the line of [ John Ennis from Texas Capital. ]

For my first one, with over 2 Bcf of power and industrial demand growth expected along the Gulf Coast that you highlight on Slide 11. How should we think about the pace of winning further into supply agreements like the one with LCM and the inbound interest you've noted. Just given you're one of the few with meaningful inventory depth in the Haynesville and with egress from Texas to Louisiana potentially constrained are you contemplating potentially being more patient with entering into future deals to let the gas on gas demand further materialize and accrue to your benefit?

Well, we're happy to be patient. And I think we're going to go back to the principles Dan just described in how we think about which deals we want to pursue, which customers we want to align with to provide long-term supply agreements. We're looking for those characteristics, again, that help to deliver a better business for our bottom line, higher revenue, we want lower volatility for our business. We're trying to set customer relationships where we can help provide a service in addition to the commodity that we're providing in that it's uniquely reliable, flexible and we can get paid a premium for that.

When we think about the overall scope here of long-term agreements, this one is attractive to us because it doesn't require any balance sheet commitments and the price is floating. So if you're thinking about doing transactions, where there are balance sheet commitments associated with the transaction or you're changing your price characteristics, whether it be a fixed price or a collar price. You would think about the impacts those have on your portfolio. Those could be very attractive to you as well.

And again, it will be a portfolio approach as to how we think about the balances here. But to put in place a structure like this where you're getting a premium to NYMEX, which, of course, NYMEX being the most liquid natural gas market in the world, we can hedge around that and manage that exposure proactively, we thought was a really good opportunity here.

So we could do more of these. And again, we'll continue to look for transactions that have all the right characteristics, but they won't all look the same. In fact, intentionally, we will have a portfolio approach to this.

Terrific. I appreciate that color. For my follow-up, with your position in the [indiscernible] zone, I wanted to get a sense of how similar your position in the Western Haynesville is to the NFC just in terms of death and temperature. And do you believe your experience operating in the highest geo pressured area of the legacy Haynesville position you to potentially come down the learning curve more quickly.

Yes, John. So there's definitely some similarities. Of course, as we get into the Western Haynesville, the depths will be a little bit deeper from a total vertical depth standpoint. But as far as will the be learnings, absolutely. Currently, when we think about how we're developing the NFC area of our play, just as a point of example, we're drilling completing wells there, $1,500 to $1,600 per foot. And today, if you're thinking about wells in the Western Haynesville at around $3,000, I have every bit of expectation that it doesn't take us 2x the well cost to go develop that part of the asset.

So we will absolutely carry forward those operational learnings. I think there's a lot of things that we can carry forward into this part of the play, which, again, is why we simply believe that we're the right type of operator to be operating in a very complex part of the basin.

And our next question comes from the line of Scott Hanold from RBC Capital Markets.

Just touching base again on the Western Haynesville. Just a couple of questions, just a clarification. Number one, first on -- you spoke about like geological complexity and stuff out there. Do you -- what other kind of facets are important for us to focus on and trying to figure out, like is there a greater position for you to build out there? Or do you think you've got a pocket that you like right now?

Yes, Scott, we feel really good about the position that we've built. I mean with 75,000 net acres -- gross acre position is going to be a little bit larger than that. And so we think there's some opportunities to maybe kind of build up in and around that position, but nothing material. Given our overall inventory depth in the basin, we think this is about the right size for us going forward.

And then to your comments on the geologic complexity, one of the things that we observed through our data sets is there is quite a bit of structural complexity as you move across the play, especially as you move further west you'll get some very steeply deeping beds there that create some complexities in terms of how you drill wells, especially in the lateral section. And so we were very thoughtful about where we wanted to be. We like the area that we've got, that it has much less structural complexity within it. which puts us in a position to simply executing at lower cost while delivering outsized production results.

And my follow-up question is on the Haynesville productivity improvements in the view of seeing it improve yet into 2026. It sounds like some of that is your Gen 1 through -- potentially Gen 3 design. Could you give us a little bit of color on exactly what you're tweaking within that? And also, is there any facet of the expectation of productivity improvements related to where you're targeting within the Haynesville or is it more based on these new generations of completions?

Yes. I mean, first of all, both the Bossier and the Haynesville are very prospective within our acreage position in Louisiana. So we continue to develop both. And especially in the southern portion in and around the NFC both zones are highly prolific. And so yes, we continue to optimize exactly where we land the wells within those zones. But really, what we find to be one of the biggest drivers is just simply how we complete the wells.

And so exactly that recipe, obviously, we're not going to get into that. But I think the biggest factor is we have a very low cost stand source that we're able to rely on going forward. That also allows us to control the deliverability of it in terms of ensuring that we have the right sand at the right time. Historically in the basin, especially as we've gotten more and more efficient with our completions, third parties, their ability to keep up with their needs has definitely been lagging. So we can now control our own destiny. We have a lower supply sand source. We can increase our proppant loading and do so more economically than what others can do in the basin.

And our final question for today comes from the line of John Freeman from Raymond James.

When I was looking at the full year CapEx reduction by another $75 million, the two biggest drivers of that are the $25 million less allocated to the productive capacity build, which you've been pretty clear kind of highlighting the efficiency gains in the Haynesville that drove that, but the other amount was Northeast App that dropped about $25 million, and I know there's some curtailments. And I'm just trying to get understanding if that's sort of timing curtailment-related? Are there efficiency gains? I didn't see anything in the deck on kind of what drove the meaningful Northeast App drop in the budget.

Yes. So I mean, if you just think about kind of seasonality across the United States, I mean the majority of the seasonal demand weakness will show up in the Appalachia region. And so when we think about curtailments, we will tend to prioritize curtailments in the Northeast first. And so that's really what's impacted the Q3 number to kind of project forward into the fourth quarter. We're obviously carrying forward curtailments into the fourth quarter with those being predominantly in the Northeast. So that's, by and large, what's driving that, John.

Okay. And then on the follow-up question. You've obviously made significant progress on debt reduction this year. when I'm looking at next year relative to your capital returns framework that you all have on Slide 14, how should we think about kind of further debt reduction relative to other returns such as buybacks. I guess, said differently, in other words, like would you anticipate a similar amount gets allocated to debt reduction next year in that sort of capital returns framework?

John, it's Nick. So last quarter, we said we were going to prioritize debt pay down for a period of time as we recognize that post merger, our balance sheet is very strong, but we would like to have less debt for the long term. So we're going to continue to do that going into next year. We think we have a lot of momentum to pay down some debt next year, and looking forward to delivering on that.

I would just note that this year, we did -- both retire $1.2 billion of debt and returned $850 million to shareholders. So we are willing and able to do both. We have the financial flexibility to allocate capital towards shareholder returns in size when we choose to do it. And we'll be ready to do that when the right time hits. So I would say stay tuned. We'll be giving more specific answers as we get into next year and see market conditions set up. But we're totally flexible, capable and willing on all fronts.

This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Nick Dell'Osso for any further remarks.

Thank you, guys, for joining the call this morning. We're obviously really pleased with our third quarter results. This puts a great end to the first 12 months of Expand Energy, and we think is such a great setup for where we head next as an organization. The momentum we have around capital efficiency as well as building on our marketing business is very exciting to us. And we think there's an opportunity to create a tremendous amount of value for shareholders going forward and look forward to speaking with you all at each step along the way. Thank you for your time.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.

Good day, and welcome to Expand Energy 2025 Second Quarter Earnings Teleconference. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Chris Ayres, Vice President of Investor Relations and Special Projects. Please go ahead.

Thank you, Carmen. Good morning, everyone, and thank you for joining our call today to discuss Expand's 2025 second quarter financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday.

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements.

Please note there are a number of factors that will cause actual results to differ materially from our forward-looking statements including the factors identified and discussed in our press release yesterday and other SEC filings.

Please also recognize that as except required by law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures, which facilitate comparisons across periods and with peers. For any non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measure, which can be found on our website.

With me on the call today are Nick Dell'Osso, Mohit Singh, Josh Viets and Dan Turco. Nick will give a brief overview of our results, and then we'll open it up for Q&A. So with that, thank you again. Over to you, Nick.

Good morning, and thank you all for joining our call. When we combine Chesapeake and Southwestern to create Expand Energy, we did so with the intention of creating long-term value through reducing costs and developing a deep geographically diverse portfolio serving premium markets.

Our business continues to deliver and outperform every expectation pegged at merger onset. We now expect to recognize approximately a 50% increase to annual synergies realizing $500 million and $600 million in 2025 and 2026, respectively.

Relative to our expectations at the beginning of the year, this directly translates to approximately $425 million more free cash flow in 2025 and $500 million more in 2026 before accounting for NYMEX price changes.

Capturing synergies do not simply happen in a spreadsheet. We're drilling faster and smarter than ever before. Our team's innovative utilization of AI and machine learning is supporting record-breaking performance, as we drill the most productive wells in our collective company's histories.

In Southwest Appalachia, we drilled the longest lateral well and measured depth by a single bit in U.S. land history. In Northeast Appalachia, our team improved its drilled footage per day by 62%. And in the Haynesville, our team improved footage drilled per day by 25%.

Setting individual well records is nice, but delivering actual financial results that highlight these improvements is especially gratifying and is what creates sustainable value. These tremendous efficiency gains, combined with the successful implementation of our productive capacity strategy, has allowed us to hit our production and well count targets with fewer rigs than originally forecasted.

Overall, we've reduced our 2025 capital investments by approximately $100 million, while maintaining production of approximately 7.1 Bcfe per day and building approximately 300 million cubic feet equivalent per day of productive capacity to deploy in 2026 should market conditions warrant.

Simply put, we're spending less while producing more, the very definition of capital-efficient operations. We're encouraged by the long-term demand outlook for our industry, and we're excited about the opportunities provided by our diversified portfolio. We retain operational leverage to the largest gas demand center in North America through our Haynesville position.

Within a 300-mile radius of our assets, there is more than 12 Bcf per day of LNG demand under construction to be in service by 2030. No other operator is better positioned to deliver gas into this demand complex, driving meaningful value creation over time. Next to LNG, power generation is the most attractive growth prospect through the end of the decade, especially for constrained basins like Pennsylvania, where we produce over 5 Bcf gross per day.

Our deep multi-basin portfolio with close access to demand centers and investment-grade balance sheet make us a preferred partner to deliver the energy needed to supply the growing LNG market and support data center power demand. We expect to have a meaningful portion of cash flows linked to lower volatility pricing over time, and we'll continue to assess all opportunities through a simple lens of making us better and creating a more attractive cash flow profile.

We remain actively engaged with many parties today and any agreement we announced, whether LNG or power-related, will be accretive to our shareholders for the long term. In the short term, we expect market volatility to remain a prevailing theme in the space. We view our investment-grade balance sheet as one of our most important strategic assets. Like any asset, we will periodically utilize capital to enhance and fortify its strength to perform through cycles.

Our balance sheet can withstand cycles today, but we believe opportunistically using a portion of near-term cash flows will put us in an even greater position of strength in the future. With our improving cash flow profile, we're electing to increase our 2025 net debt reduction to $1 billion.

In addition, we will be returning $585 million to shareholders in the first half of the year through our quarterly base dividend, variable dividend and share repurchases. Should near-term cash flow ultimately retract, we retain the option to redirect and utilize our balance sheet's current strength to enhance returns. We firmly believe that our attractive and connected portfolio, diverse and agile production and resilient financial foundation equip us to thrive in today's macro landscape.

We look forward to continuing to update you on our progress. And operator, we'll now open the call up for questions.

[Operator Instructions]. And it comes from the line of Scott Hanold with RBC.

Yes. A few of your peers have signed gas contracts related to power growth opportunities. Can you talk about Expand's strategy? And what are your goals that you're looking for in a commercial agreement? And how do you think about the pricing mechanism for that?

Yes. Great question, Scott. So we're really excited about the opportunities in this space, and we have had a lot of conversations with a lot of folks. I would say our goals are really, like I said in my comments, about making our business better. And one of the things we believe we can do with contracts like this is try to reduce the volatility of our cash flow.

So there's a couple of things that you could accomplish with a long-term contract like this. You could achieve just better pricing than you otherwise would expect to receive because you can deliver gas in a way that is more reliable to a location that might be constrained or you can structure something that can be a win for both parties that reduces volatility. All of those things remain on the table and things that we're interested in.

Dan, do you have anything else to add there?

Yes. Thanks for the question, Scott. I'm personally excited about this area because we start with a great footprint. Obviously, we have the size, we have the balance sheet and we have a very interconnected portfolio. And so I'm trying to do multiple things to bring picture value and realizations that I believe are there and truly add bottom line value to our company.

And one is just increasing that optimization at scale. I think Page 13 of our deck did a good job of showing how we are positioned to these premium markets. It's really around Haynesville and LNG focus, but that's also in Appalachia and power.

And as Nick alluded to, we're looking at some of these longer-term tenured deals that provide some more structured terms, again, trying to lower the cash flow volatility, but also participate in the upside.

And then the third thing I'm trying to do with that is make sure it's accretive to that portfolio we already have. So we're building more scale, integration and optionality. So we can do things like move molecules to the best price market on any given day. So it's about getting to premium markets, structuring it to lower that cash flow volatility, but also increasing on any day where we can add just daily optimization value to increase realizations in the bottom line.

Yes. And my follow-up question is still going to be on the same line because I think it's important, obviously, for a lot of gas companies, how they structure these deals going forward to maximize the value to the company. But can you talk about like 2 things here additionally? Number one, I alluded to the fact that a lot of your gas peers have done a few deals here.

Do you feel there's a need to be -- do you have some urgency in signing deals? And then with respect to, again, the commercial side of the agreement, if I look at, like, say, an LNG opportunity, would you be willing to kind of -- how do you want to structure the deal? Would you be willing to sell it to like an end user overseas or to a middleman? How do you see the best way to optimize that price?

Yes, thanks. I would start with -- there is no real urgency, right? We take a long-term look especially at the LNG and this power markets. And there is no set what we wanted to structure. We're looking at everything down the value chain. So we're looking at selling gas domestically and internationally in all kind of different forms. The key to me in all this is, again, the risk reward. And how do we protect the downside and make sure we're participating in the upside.

And again, there's many ways to structure those deals. We can do them, as you said, direct sales. We can do them through partnerships or tolling. But we're looking at a wide lens of these deals at the moment and continue to work and talk with many people at the moment, and we're in different areas and different time frames of those discussions.

Our next question comes from Doug Leggate with Wolfe Research.

So Nick, there's a lot of detail in the report, obviously, to talk about today with synergies and everything else. But I would like to focus, if I may, specifically on cash taxes. I think we've looked at you on a discounted cash flow basis for a very long time. And 70% deferred cash tax is the guidance for 2026, I believe.

My question is, what's the duration of that? Because that strip on our numbers at least that could be pretty material. So any color you can offer on duration and how you get there would be appreciated.

Doug, this is Mohit. I'll take that. The preface, I'll say is, we are very excited about the passage of the Big Bill, which restores incentives for domestic capital investment. So the tax savings that you get they're generally impacted by their function of relative capital spend that we will make.

So with regards to your question around the longevity of that saving, as long as we keep investing at a similar cadence, we forecast bigger tax DD&A due to better tax planning and also the impact of the bill itself. So for all practical purposes, Doug, I would say the duration of the tax savings is fairly long.

I appreciate it, Mohit. I know it's complicated, but I think you've tried to distill it down to a fairly simple message, so thank you for that. My follow-up, Nick, this probably is for you, and it's a question of cash returns. Obviously, there was a variable dividend thrown in this quarter, but you also doubled the net debt reduction.

So my question is, what's your appetite to continue doing that, reducing net debt; or put differently, putting cash on the balance sheet to the obvious benefit of your equity volatility?

Yes. Great question, Doug. And I like the way you phrased that question, right? We do think it's absolutely to the benefit of our equity volatility and our equity holders over time to create a stronger balance sheet. So our appetite to do it really is a function of where we are in the market. We believe that during strong markets, you should be strengthening your balance sheet, and you should be willing to use that to the benefit of shareholders when markets soften.

The most obvious way, of course, is that you're prepared to buy your stock. And we think that right now, we're seeing really nice market conditions that are giving us the opportunity to accelerate the improvement in our balance sheet, relative to probably where we would have modeled it a year ago, and that's a great opportunity for us to create equity value through the reduction of leverage.

We can keep doing that. And we will keep doing that until there is an opportunity to do something better with the cash. But as we all know, that have followed this industry for a long time, a strong balance sheet is one of the most important assets that you'll have and one of the most unique ways that you can position yourself to create lasting value for shareholders through cycles.

Our next question comes from Zach Parham with JPMorgan.

You highlighted some significant increases in footage drilled per day over the last 6 months. Could you give us a little more detail on what's driven those increases? Maybe talk about where you could see those numbers going over the next few quarters? Do you see the ability to continue to increase that footage per day number going forward?

Yes, this is Josh. We've had some just tremendous performance, of course, really just since the merger closed. And I would say a lot of that was, we really prioritized upfront the integration of our data sets across the combined companies and getting all of our rigs coming into a common platform in which we could then assess individual performance of each rig.

And from there, it's really about in connecting the team. And this is a highly collaborative effort for us. It starts with the -- with our contractors, the people on the well site, our engineers, our operation support center and our data scientists, really all working together hand-in-hand to create better outcomes.

And then probably one of the things that continues to mature and maybe to kind of address how we think about upside going forward. It really centers around data analytics. And we've included a slide in the slide deck that talks a little bit about that.

But we have 15 years of history of drilling in a place like the Haynesville and then also in Appalachia. So you think about combining that data set and using AI agents to go out and do the research effectively on your behalf, to be able to provide intelligent insights and provide better opportunities to optimize the assets in real-time.

And we think we're just scratching the surface with where we're at today, and we think we'll continue to find ways at which we improve the parameter optimization that's occurring by the minute. So pretty excited about what we've accomplished. But again, we think there's more to be done in the future.

My follow-up, in the slide deck, you provided an update on Haynesville well productivity that I think clears up some things on the state data. It also looks like you've seen better -- a little bit better productivity year-over-year in 2025. Anything specific you'd highlight that's driving that increase? Do you expect that to continue going forward?

Yes, Zach. There is a little bit of movement between '24 and '25. What that's largely attributed to, of course, prices were pretty weak in '24. You had a relatively smaller data set, but probably one of the biggest drivers to the '24 relative to '25 is just how we think about drawdown in these wells.

In the Haynesville, you have oftentimes over 9,000 psi of flowing wellhead pressure. So really the wells could produce whatever you want them to produce. But in a poor price environment, it simply doesn't make sense to have aggressive drawdown strategies there. So obviously, in a little bit more constructive environment, that's been adapted.

We continue to find opportunities as well to improve our completions. Right now, when we look at kind of relative to '22 and '23, our proppant intensity has moved up by, say, 15% to 20%. And of course, what makes that so economic for us is the fact that we've developed our own sand source as well. So we're able to go outsource cheaper sand, pump a little bit more into the wells. And of course, that starts to show up in the well performance as well.

One moment for our next question, that comes from John Freeman with Raymond James.

The first question, just kind of following up on Zach's question on the footage drilled. Obviously, pretty remarkable improvements in the footage drilled per day across the portfolio, even just from the first quarter. And I'm just trying to get a sense of what's currently baked into your full year guidance. Does that reflect those kind of leading edge 2Q cycle times?

Yes, John, it would. I mean, in fact, we have some expectations that we continue to get better. So we'd have a modest learning curve going forward. But we really expect that, that performance that we've seen in the second quarter carries forward.

Okay. And then just the follow-up question I've got. When I look to kind of revisit that heat map table that you have got on optimizing free cash flow at various gas prices and we look at sort of the meaningful improvement you all have now got on the free cash flow, especially starting next year, both on the lower cost and then the tax and interest savings. And in the response to Doug's question, it does sound like this has got some legs in terms of that uplift on the tax side.

I guess I'm surprised that the kind of the coloring of that chart like hasn't changed at all since the start of the year. And I guess I'm just trying to get a sense for if that includes sort of the uplift, especially on the tax side? And if it does, just what would potentially have to change for that chart to kind of shift at least in terms of that relationship?

Like what would change that would cause a 350 mid-cycle price to point to you all producing something above 7.5 Bs or just -- I'm trying to get a sense of what would maybe cause that chart to shift, if anything?

Yes. That's a great question, John. So what I would point you to is that the colors in the chart are all relative, right? So where are you going to produce the optimum relative to a different price? And then the other point here is what we've done in order to recognize the improvements in our cash flows, we've lowered the maintenance capital at every level.

So that's how you're seeing that show up. And the relative performance of each is reflected in the colors across the prices.

So even though the -- it looks like the cash flow uplift is not like linear in terms of on the tax side, it doesn't necessarily have any change to this chart.

Yes, John, this is Chris. That's the right way to think of it. I mean, put simply, if you were to go on that chart to the $4 column in the 7.5 Bcf a day that light green, that's going to effectively correspond to the 2026 free cash flow of $3.1 billion.

And so there would be a little bit of movement at the lower prices around -- or at the higher prices around what your absolute cash flow is because the tax is nonlinear as you highlight. But as Nick pointed out, it is just kind of relative one to another within the column.

And so the absolute free cash flow has increased, but the relative position of how you optimize production doesn't necessarily move large enough that you would see that on the output.

Our next question comes from Devin McDermott with Morgan Stanley.

So I wanted to ask kind of along a similar lines on capital allocation and optimizing for free cash flow with some of the weakness in Henry Hub over the last month or 2. We're now back below at least on the prime contract below your mid-cycle price range.

So question is more on kind of duration of price. At what point do you start to toggle things or move around within this heat map? What are you looking for as we head into 2026 to kind of reaffirm the constructive view in that 7.5 Bcf a day target you all have on production for next year?

Yes. Great question, Devin. And I think it's obviously timely. We're just not bothered by the volatility that we're seeing here this summer. If you think about where we are in the broader scheme of the year of the macro. Demand is still growing pretty attractively and forward price is at a level that is still well above our mid-cycle.

And again, we think a lot about capital cycles. And so the money we're spending today is all about bringing on production and delivering volumes into the pipe, 12 to 18, 24 months from now. So this kind of volatility we pay attention to because we want to understand the drivers of it, but it doesn't necessarily change our plans in any way.

However, as you know, we have a super flexible business, and we really enjoy being able to use that flexibility, and we think we can create a lot of value by using that flexibility. So as conditions evolve throughout this year, if anything changes relative to what we may see as the prevailing conditions at this point, then we are absolutely ready to make changes to our business and adjust accordingly.

But look, we've got 2 Bcf a day of new LNG capacity coming online, more than 2 Bcf day of new LNG coming online between the rest of Plaquemines, Corpus Christi before the end of the year. And then, of course, you have a return of maintenance and cooler weather that increases capacity there. So just that demand alone is pretty significant. So we feel pretty good about the macro.

Okay. Great. Makes a lot of sense. And then I wanted to come back to the Haynesville and well productivity, I know there's a question on that before. But -- your results are strong. The state data also shows the degradation across other producers in the basin. So I guess my question is more broadly I guess, is the reporting issue unique to expand?

Is it broad across the basin? And what's your views on kind of marginal cost breakeven, Haynesville growth capacity as we kind of head into this tightening market over the next few years in that backdrop?

Yes. So I'll take that. We think this issue is specific to the state of Louisiana. It's not just related to Expand, it's likely impacting several other operators, specifically within the state. we work pretty closely with the agencies there to try to ensure that -- the reporting process is as efficiently as it can be, but they're just a little bit behind there in the office. And so again, we'll continue to work with them to get that addressed.

Really, what we can speak to is the fact that we have this incredibly long-lived durable inventory to go develop within the basin. And I think the strength of our inventory, we see it here in the data sets where we've seen relatively consistent year-over-year performance going all the way back to 2020.

Now I do think that when you look at industry more broadly, you are going to see some level of degradation as you move outside of the core area. Not everybody has the inventory depth that we have. In fact, if you look at who's been adding activity of late, we believe that operator has a relatively short inventory level to go develop.

You'll see well productivity degrade a little bit again as you move to the west over into East Texas as well. And so again, we just think, in general, we would anticipate some level of modest productivity decline as you move outside of the core and especially as you move into some of the more -- for the private operators in the basin.

Yes. Devin, let me just add to that real quickly. I mean just think about that dynamic and the fact that as you move outside the core and the Haynesville needs to grow, the Haynesville needs to grow right now because of the fact that LNG demand is strong and it's going to continue to grow.

Like I commented in my initial comments, there's well over 12 Bcf a day of demand growth showing up within 300 miles of our position. So that call on Haynesville is really significant and is going to continue to drive competitive tension into the supply-demand fundamentals around our assets for some extended period of time here.

And just as a reminder, we deliver gas to a lot of different places from our Haynesville assets. We can go east to Perryville. We can go directly south to Gilles and then there are a number of other offtake points that we can deliver gas to along those routes. So we have a really flexible portfolio that's ready to do this. But clearly, the Haynesville is not going to deliver all 12 Bcf a day of that growth, but it is the closest and best positioned. And so we really like these dynamics.

Our next question comes from Josh Silverstein with UBS.

2Q was challenging from a basis standpoint in both the Haynesville and Appalachia. Can you just give us an update on expectations for second half and maybe going into 2026. I know there's been some start-up of infrastructure in the Haynesville, so how that may impact some of your capital allocation thoughts later on this year and into next year?

Josh, thanks for the question. In terms of basis, we look at structural basis, right? And when I talk about that, it's how these markets clear. So we can talk about Appalachia and the Haynesville. In Appalachia, the supply demand set up, yes, there's going to be weather that's going to change base over time.

But there is a bit of demand coming in basin with potential power generation and pipeline egress. But there's also a lot of supply behind that. So structurally demand is going to grow and the supply is going to catch up with it. So we do see it grinding up a basis over the medium, long term there in Appalachia.

But pivoting to Haynesville on your question specifically, I think, was around how we're going to see the basis come online with NG3 coming online in fourth quarter this year and all that LNG demand that Nick was referring to. So again, coming back to supply/demand, we really see the big demand pull in this area over the long term.

In the short term, quarter, I think you were referring to on NG3, there's not going to be that much of a change. The basis -- when we put production down that line, we also have to pay for that capacity. So it's a bit of a wash, if you will, in terms of the uplift we're going to get and the capacity we're going to see. But over the medium term, again, with that demand pull from LNG, we're expecting an increase in realizations and basis in that area.

And then I want to see if I can also get kind of your views on Lower 48 production in total. We've seen a real big step up recently kind of into that 108, 109 area. Is the expectations that we maybe stay around here? Do we come down or just given some of the rig count increases that we've seen in the Haynesville, there are still expectations of growth going forward into 2026?

Yes. We have been, I guess, a little bit surprised by the upside in the last month or 2 with the prints around 107 depending on what data sources you're looking at. But as we said, that demand is still growing through the balance of the year here with about 4 Bcfd of real LNG capacity coming online with Plaquemines, Corpus and then again, coming out of maintenance and the weather. So we do see that demand coming and there might be a bit of a tick up in production as we go through or remain flat, but we see the demand outpacing that supply.

One moment for our next question, and it comes from Neil Mehta with Goldman Sachs & Company.

Yes. I just want to start on Slide 6, the merger synergies. There's another $100 million here of outperformance. And I think you got 4 bullets that describes some of the pieces there. But could you unpack it, whether it's sand mine stuff or some of the things that you're doing in the Haynesville to help us get some color of what's happening on the ground?

Yes. Neil, this is Josh. Thanks for the question. Yes, the incremental $100 million is really kind of split between our drilling completions activity in the Haynesville, representing roughly half of that, and then the other half is going to be attributed to specifically G&A.

And so maybe just unpack the D&C component. There's a portion of that, which is purely attributed to the fact that we're just simply drilling faster than what we thought we'd be doing at this point in time. So again, just been incredibly pleased with the results. We've demonstrated roughly a 25% improvement in footage per day if you kind of go back to the fourth quarter of last year.

Maybe just 1 thing I'll kind of put out there. In fact, one of the things that we're seeing right now in the Haynesville is our well costs are around $1,300 a foot. So just think about where we've been historically. So just a ton of progress has been made there. And a lot of that, again, is attributed to drilling.

There is a portion of the incremental synergy that's attributed to the sand mine. So we got the sand plant started up in and around the first quarter. We had some expectations around how quickly we could ramp that up and how many frac crews that we could support. We're simply able to support more frac crews than we thought we would be at this point in the year. So that's contributing to some incremental synergies through the course of the year.

On the G&A component, that is largely attributed to non-comp G&A. I think the teams have done a phenomenal job rationalizing our IT cost. You think about things like software, subscriptions and license rationalization that's going to occur. And we've really just not only accelerated those synergies, but the quantum has gone up as well.

And the follow-up is just around hedging strategy. You guys were aggressive in Q1 and -- for locking in '26 and almost at 40% now, and that has kind of aged well. But your perspective as the curve has come off as hard as it has for '26. How do you think about being opportunistic versus ratable in the hedge the wedge strategy?

Neil, this is a great question. You're correct in identifying in Q1, we had signaled that we added 740 Bcf of hedges. Just for comparison, that number for 2Q is about 169 Bcf of hedges. So while our approach and program on hedging is very disciplined and programmatic, but it also takes into account windows of opportunities where we see spike up in volatility, which allows us to further capitalize on that volatility by buying more downside protection through buying those puts.

And also selling calls at a higher price, which are then used to pay for the puts. So most of the hedges that we have layered in are costless collars. And as a point of reference for 2Q, the 169 Bcf of new hedges that I had mentioned, those are of various tenures going into 2Q of 2027 and the weighted average floor price is $3.75, and then sealing is $4.77.

So it still remains above what we deem as our corporate breakevens. And that's what we continue to attempt to do is to try and add more hedges at above our breakeven prices and still retaining some of the upside until the sold calls at $4.77. So overall, the program is working. There will be windows when we'll be more active, as you said, and there will be windows when we will just back away. But the overall structure and -- is still to do it on a rolling 8-quarter basis. And as we roll from 1 quarter to the next, we look at opportunities to add more to it when we can.

Mohit, can I ask one quick follow-up on that, which is the '26 curve has come down, it feels like, in large part of a reflection of production, which is probably running to [indiscernible] higher than most forecasters would have thought. Do you feel like that is structural in the sense that it could shift the way that we should be thinking about the '26 curve or is it just some of this production, which is deferred TILs just coming back at which point we should be less worried about the way that the '26 curve is moving?

Yes. So that's a good follow-up, Neil. The -- we still remain excited about the demand, which is showing up. Nick mentioned about, Plaquemines will add another 1.5 Bcf and then the Corpus Christi will add some more and then obviously, Golden Pass should start taking some gas as well.

So our view is to try and grow into durable demand, and we view LNG demand pull as a durable demand that we'd like to grow our production into. And that's why when you look at the curve out in [ Cal 26 ] it's still close to $4, which is still, I mean, above breakeven. So it's still -- we have to remember, while it has traded off a little bit, these are still pretty healthy prices. And at those prices, our business generates a tremendous amount of free cash flow.

Our next question comes from Kevin MacCurdy with Pickering Energy Partners.

There's some reports out there of assets being marketed in the basins you operate in. And do you feel like your balance sheet and organization are in a spot where you would consider more M&A? And is there any differentiation you see between M&A potential in the Haynesville versus Marcellus?

Kevin, it's Nick. We're just finishing the integration of a very big merger. We have a lot to continue to do to improve upon our business. We're pretty satisfied with who we are today and what we have in front of us. We'll always consider opportunities, but I'd just remind you, we have our nonnegotiables, and they're a pretty high bar. They've worked well for us historically. They'll continue to work well for us, and we're pretty focused on what we've got right now.

I appreciate that answer. And as a follow-up, your guidance includes productive capacity of up to $275 million CapEx this year. Your wording, while I know it's not changed, it seems to leave a little bit of optionality on not spending the full amount. You said earlier in the call that you're not concerned about the long-term macro. But is there anything in the near-term gas markets that would lead you to maybe pull back on that productive spending? And when would you need to make that decision?

Yes. I think we feel pretty good about our plans right now, Kevin. The reason we think about it is productive capacity is that we want to set a plan to be able to execute on it and then have the flexibility to decide how and when to produce those volumes based on the near-term market conditions as those volumes become available.

So it's -- if the conditions change, we would adjust production, not necessarily the capital spend because again, the long-term fundamentals here, we still think are super strong.

One moment for our next question, please, and it comes from Phillips Johnston with Capital One.

I also wanted to ask about M&A. I heard what you said, Nick, in terms of you guys are satisfied with what you have. But looking out over the next few years-or-so, I wanted to get a sense of whether or not you guys would consider Canada as an area to expand your footprint? Or would the AECO discount or any other factor would be something that could generally sort of rule that out?

Yes. Look, we pay attention to all the trends of the industry. There's been a lot written about resource in Canada lately. And obviously, it's gotten a lot of attention. There's a lot of resource there. But frankly, at this point, our nonnegotiables would drive us to feeling like understanding the aboveground economics of those assets today. It's not clear that we would be better off doing something like that. So that's not in our near-term plans.

Okay. And I think the last time you all provided D&C well cost by area within your February presentation. At these new faster drilling speeds, can you just give us a general sense of how much your well costs have fallen in all 3 areas, I guess, relative to the figures that you guys provided back in February?

Yes. Phillips, Josh here. So I referenced the Haynesville cost earlier. When we compare back to the guide, we're probably closer to $1,200 a foot with our Haynesville formation wells, just under $1,500 a foot for Bossier. When we look at the cost relative to the guide in our 2 Appalachia business units, I would say we're within about 5% of where we guided to cost there.

And so really not a material movement. Just given how we forecasted improvements within those 2 basins, the move is just not simply as big. And of course, so much of that simply ties back to the merger synergies with the Haynesville specifically, and of course, those have shown up in a more material way, hence, a little bit lower well cost in the Haynesville.

And our last question comes from the line of Paul Diamond with Citi.

Just a quick question on kind of the larger portfolio dynamics. I guess from a longer-term perspective, how do you think about the right balance between LNG contracts, data center contracts and then just general delivery otherwise?

Yes. That's a great question, Paul. So again, we're really pleased with the fact that our portfolio sits in a place that we can be responsive to all of these elements of growing demand. It's a pretty exciting time for natural gas. I mean you have people recognizing the value that gas plays in the economy, the efficiency that gas creates for the growth in power demand, which is all tied to our growing economy fueled by the innovation associated with AI as well as a lot of other places where the economy is just putting capital to work.

That's obviously a domestic story, but it's also very much an international story connected through the LNG markets. So we're in a place that we can be responsive to all of the above. And I think we're, again, unique in being able to do that. We know that our portfolio has the depth and quality so that we can continue to deliver resource to all of these very attractive, oftentimes constrained markets, constrained either in infrastructure or just constrained by the fact that demand is growing faster than supply.

And so we're well positioned to be responsive to all of these customers. And then we have the financial flexibility and strength to be responsive to create solutions that are effective in how we supply gas and structure contracts in a way that's good for both us as a producer and the customers.

So we really like these dynamics. We don't think it's an either/or in any way. We think, in fact, it is a story for our company of all of the above, and I think we're uniquely positioned to do that.

Understood. Makes perfect sense. Just a quick bookkeeping follow-up. Circling back to Slide 25 and Haynesville productivity. I know you said that they're working with local state agencies in Louisiana, but do you guys have any line of sight on the timing of when that data should be captured accurately? And is it a permanent fix or could this happen again?

Yes, we'd like to think it will be a permanent fix. Again, we work pretty closely with the state agencies. We have a really good relationship. They're working the best they can with the resources they have available to them. We're hoping this gets resolved over the next several months.

But again, it's something that we hope we don't want to deal with again. But nonetheless, we see them as a critical partner for us, and we'll continue to engage in a constructive way.

This concludes our Q&A session, and I will pass it back to Nick Dell'Osso for final remarks.

All right. Well, thanks, everyone, for taking the time to listen to our call today. We'll certainly be available for any follow-up questions. We think the second half of this year is setting up extremely well for Expand, and that, we believe, is just a start towards what 2026-'27 and the rest of the decade will look like.

The dynamics for natural gas are very strong, and we are uniquely positioned to succeed. The creation of Expand Energy is putting us in a position where the benefits of this merger are showing up every day, and they're showing up in our financial results, not just through leading indicators. We're really excited about the future and look forward to continuing to talk to you about all of that in the coming days, weeks, quarters and years. Thank you.

And with that, ladies and gentlemen, we conclude our conference. Thank you all for participating, and you may now disconnect.