Expand Energy Corporation

Good day and welcome to Expand Energy 2025 Second Quarter Earnings Teleconference. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To participate, you will need to press star 1-1 on your telephone. You will then hear a message advising your hand is raised. To withdraw your question, simply press star 1-1 again. Please note, this event is being recorded. I would now like to turn the conference over to Chris Ayers, 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 presentations 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 is except required by law, we undertake no duty to update any forward looking statements and you should not play place undue reliance on such statements. We may also refer to some non gap financial measures which facilitate comparisons across periods and with peers for any non gap measure we use a reconciliation to the nearest corresponding gap measure which can be found on our website. With me on the call today are Nick Delosso, Mohit Singh, Josh Vietz, 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 combined 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 five 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 will 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 announce, 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 will now open the call up for questions.

Thank you so much. And as a reminder, to ask a question, simply press star 11 on your telephone and wait for your name to be announced. To remove yourself, press star 11 again. Please stand by for our first question, please. And it comes from the line of Scott Hanold with RBC. Please proceed.

Yeah, good morning. Thanks. A few of your peers have signed gas contracts related to power growth opportunities. Can you talk about expand 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?

Yeah, 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, you know, 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 flows. So, you know, 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?

Yeah, 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 extra 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 tenor 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 and the bottom line.

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 two 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 have some urgency in signing deals? And then with respect to Again, the commercial side of the agreement, if I look at, say, an LNG opportunity, how do you want to structure the deals? Would you be willing to sell it to an end user overseas or to a middleman? How do you see the best way to optimize that price?

Yeah, thanks. I would start with there is no real urgency, right? We take a long-term look, especially at the LNG and this power market. And there is no set what we want to structure. We're looking at everything down the value chain. So we're looking at selling gas domestically and internationally in all kinds of different forms. The key to me and 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 timeframes of those discussions.

Appreciate that. Thank you.

Thank you. Our next question comes from Doug Leggett with Wolf Research. Please proceed.

Thanks. Good morning, everyone. 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, you know, 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 colour you can offer on duration and how you get there would be appreciated.

Morning, 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 GDNA 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, Moha. 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 the 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?

Yeah, 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 stocks. and we think that you know 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, you know, 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.

Great. Thanks, guys.

Thank you. Our next question comes from Zach Farnham with JP Morgan. Please proceed.

Thanks. You highlighted some significant increases in footage drilled per day over the last six 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. You know, do you see the ability to continue to increase that footage per day number going forward?

Yeah. Good morning, Zach. This is Josh. You know, we've had some just tremendous performance, of course, really just since the merger closed. And I would say a lot of that was, you know, we really prioritized upfront the integration of our data sets, you know, across the combined companies and getting all of our rigs coming into a common platform at which we could then assess, you know, individual performance of each rig. And, you know, from there, it's really about then connecting the team. And, you know, this is a highly collaborative effort for us. It starts with our contractors, the people on the well side, our engineers, our operations support center. and our geoscientists 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 Hainesville and 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.

Thanks, Josh.

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 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?

Yeah, 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, you know, 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. You know, in the Hainesville, 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, you know, 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, you know, improve our completions. You know, right now when we look at, you know, kind of relative to 22 and 23, our profit intensities moved up by, say, 15 to 20%. And, of course, what makes that so economic for us is, uh is is the fact that we've developed our own sand source as well so we're able to go out source cheaper sand pump a little bit more into the wells and of course that starts to show up in the well performance as well thanks josh thank you one moment for our next question that comes from john freeman with raymond james please proceed thank you good morning

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 y'all's four-year guidance. Does that reflect those kind of leading edge 2Q cycle times?

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

Okay. And then just the follow-up question of guide, you know, when I look to kind of revisit that heat map table that you all have got on optimizing free cash flow at various gas prices. And we look at sort of the meaningful improvement y'all have now got on the free cash flow, especially starting next year, both on the lower costs 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 coloring of that chart 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, 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 y'all producing something above 7.5 Bs? I'm trying to get a sense of what would maybe cause that chart to shift, if anything.

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

Yeah, 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.

Appreciate it. Thanks, guys.

Thank you. Our next question comes from Devin McDermott with Morgan Stanley. Please proceed.

Hey, good morning. Thanks for taking my question. I wanted to ask along similar lines on capital allocation and optimizing for free cash flow. With some of the weakness in Henry Hub over the last month or two, we're now back below, at least on the prompt contract, below your mid-cycle price range. The 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 and that seven and a half BCF a day target you all have on production for next year?

Yeah, great question, Devin, and I think it's, you know, 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, you know, forward prices at a level that is still well above our mid-cycle and, you know, 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 is the prevailing conditions at this point then we are absolutely ready to make changes to our business and adjust accordingly but you know look we've got two BCF a day of new LNG capacity coming online, more than two BCF a 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 was a question on that before. But your results are strong. The state data also shows degradation across other producers in the basin. So I guess my question is more broadly, is the reporting issue unique to expand? Is it broad across the basin? And what's your views on kind of marginal costs, break even, changeable growth capacity as we kind of head into this tightening market over the next few years in that backdrop?

Yeah, so I'll take that. You know, 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, you know, try to ensure that The reporting process is as efficient 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. 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, you know, we would anticipate, you know, some level of modest productivity decline as you move outside of the core and especially as you move into some of the more private operators in the basin.

Makes a lot of sense. Thanks so much. Yeah, Devin, let me just add to that real quickly. I mean, just think about that dynamic and the fact that, you know, as you move outside the core and the Hainesville needs to grow, the Hainesville needs to grow right now because of the fact that LNG demand is strong and is 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 Gillis, 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. Makes a lot of sense.

Thanks for all the detail.

Thank you. Our next question comes from Josh Silversane with UBS. Please proceed.

Good morning, guys. Tiki was challenging from a basis standpoint in both the Hainesville 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 startup of infrastructure in the Hainesville, so how that may impact some of your capital allocation thoughts later on this year and into next year. Thanks.

Hey, 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 Hainesville. In Appalachia, The supply-demand setup, yeah, there's going to be weather that's going to change bases 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, yeah, demand is going to grow, and the supply is going to catch up with it. So we do see a grinding up of bases over the medium-long term there in Appalachia. But pivoting to Haynesville, and your question specifically, I think, was around how we're going to see the bases come online with NG3 coming online in the 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, what 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 road count increases that we've seen in the Hainesville, there's still expectations of growth going forward into 2026? Thanks.

Yeah, we have been, I guess, a little bit surprised by the upside in the last month or two 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 four BCFD of real LNG capacity coming online with Blackman's 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.

Thank you. One moment for our next question. And it comes from Neil Meta with Goldman Sachs and Company. Please proceed.

Yeah, good morning, Nick and my team. Just want to start on slide six, the merger synergies. There's another $100 million here of outperformance, and I think you got four bullets that describe 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 Hainesville to help us get some color of what's happening on the ground?

Yeah, hey, Neil, this is Josh. Thanks for the question. Yeah, 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 GNA. And so maybe just unpack the DNC 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 we kind of go back to the fourth quarter of last year, maybe just one thing I'll kind of put out there. In fact, one of the things that we're seeing right now in the Haines Hills are well cost or 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 mines. 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 frat crews that we could support. We're simply able to support more frat 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-com GNA. 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's gone up as well.

Thank you. And the follow-up's 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, good morning. 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 put. So most of the hedges that we have layered in are costless callers. And as a point of reference for 2Q, the 169 BCF new hedges that I mentioned, those are various standards going into 2Q of 2027, and the weighted average floor price is $3.75, and then ceiling is $4.77. So it still remains above what we deem as our corporate break-evens, and that's what we continue to attempt to do is to try and add more hedges above our break-even prices and still retaining some of the upside till 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'll just back away. But the overall structure is still to do it on a rolling eight-quarter basis. And as we roll from one quarter to the next, we look at opportunities to add more to it when we can.

Well, can I ask one quick follow-up on that? The 26 curve has come down, it feels like, in large part a reflection of production, which is, you know, it's probably running a B to a B and a half 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, you know, deferred tills just coming back, at which point we should be less worried about the way that the 26 curve is moving?

Yeah, so that's a good follow-up, Neil. 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 pool 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. All right. Thanks, Mark.

Thank you. Our next question comes from Kevin McCurdy with Pickering Energy Partners. Please proceed.

hey good morning uh 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 could would consider more m a and is there any differentiation you see between m a potential and the haynesville versus marcellus hey kevin it's nick um you know we're uh just finishing the integration of a very big merger um

We have a lot to continue to do to improve upon our business. Uh, we're, we're pretty satisfied with who we are today and what we have in front of us. Um, we'll always consider opportunities, but I just remind you, we have our non-negotiables and they're a pretty high bar. They've worked well for us historically. They'll continue to work well for us. Uh, 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?

Yeah, I think we feel pretty good about our plans right now, Kevin. The reason we think about it as productive capacity is that we want to set a plan, 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 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.

Great. Thanks, Nick.

Thank you. One moment for our next question, please. Nick comes from Phillips Johnston with Capital One. Please proceed.

Hey, thanks for the time. 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 ACO discount or any other factor be something that would generally sort of rule that out?

Yeah, 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 non-negotiables would drive us to feeling like understanding the above-ground 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. Thanks for that, Nick. And I think the last time you all provided D&C well costs by area was in your February presentation. At these new faster drilling speeds, can you just give us a general sense of of how much your well costs have fallen in all three areas, I guess, relative to the figures that you guys provided back in February.

Yeah, Phillips. Josh here. So I referenced the Hainesville cost earlier. When we compare back to the guide, we're probably closer to $1,200 a foot with our Hainesville formation wells, just under $1,500 a foot for Bossier. When we look at the cost relative to the guide in our two Appalachia business units, I would say we're within about 5% of where we guided the cost there. And so really not a material movement, just given how we forecasted improvements within those two basins, the move's just not simply as big. And of course, so much of that simply ties back to the merger synergies with the Hainesville specifically. And of course, those have shown up in a more material way, hence a little bit lower well cost in the Hainesville.

Sounds good. Thanks, guys. Thank you. And our last question comes from the line of Paul Diamond with Citi. Please proceed.

Thank you. Good morning, all. Thanks for taking the call. 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?

Yeah, 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. You have people recognizing the value that gas plays in the economy, the efficiency that gas creates for the growth and 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 think we're uniquely positioned to do that.

Understood. Makes perfect sense. Just a quick bookkeeping follow-up. So going back to slide 25 in Hainesville 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 Hainesville Is the timing of when that data should be captured accurately and is it a permanent fix or could this happen again?

Yeah, we'd like to think it'll be a permanent fix. Again, we work pretty closely with the state agencies. We have a really good relationship. You know, 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. You know, but again, it's something that we hope, you know, we don't have to deal with again. But nonetheless, you know, we see them as a critical partner for us, and we'll continue to engage in a constructive way.

Understood. This is clarity.

And thank you so much. This concludes our Q&A session, and I will pass it back to Nick Delosso 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, 2027, 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. You may now disconnect.