Q2 2025 Earnings Call Transcript

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?

Executive Vice President of Marketing & Commercial 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.