Q3 2025 Earnings Call Transcript

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 peers -- 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 in 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 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 LEAP pipeline into Gillis. And where customers are looking for that security of 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 go 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 of bottlenecks 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. More importantly, you've dropped your sustaining capital by, it looks 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 innings are you in, if you like, in terms of the marketing uplift?

And if you can quantify how do you see your realization has been impacted by that, that would be great. So those are 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 at 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 billion to $2.9 billion 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 in your 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 it 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 this 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 in 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 that, 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 -- of value chain creation.

In LCM, for example, we hit a majority of these elements. And we have a tons 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 App was purely opportunistic.

That's clearly highly synergistic with our existing acreage position. It allows us to extend lateral lengths, almost more than double lateral lengths, 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 want to 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 1.5 decades of experience here. And so we've been very thoughtful about integrating new production data as 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 NFZ 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 is carrying some level of uncertainty with it. And I think that really goes for 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, we'll 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 it 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 completing of the wells?

And you kind of mentioned in your earlier remarks that you think you're doing wells 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 at 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 two 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, it's 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 pieces, 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.

Yes. 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 backwardates pretty decently as you get it from '28 to 2030, and I know there's less liquidity.

So I'm guessing 8 quarters rolling forward is 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. Collars 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 consistently add to that position.

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

First, 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.

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 Bcfe 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've 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 the year 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 breakevens 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 is 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 two, 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. I mean 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. 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 that 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 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 becoming to your overall program in what time frame?

Yes, David. So for next year, the soft guide that we've provided of $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 just 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.

It was 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, heritage Chesapeake and heritage Southwestern, where they have a long-standing relationship with the principles of this project, ex-Cheniere guys. 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 give them 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 opposed 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 Annis 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 leaning 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 up 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 Nacogdoches fault zone, I wanted to get a sense of how similar your position in the Western Haynesville is to the NFZ just in terms of depth and temperature. And do you believe your experience operating in the highest geopressured area of the legacy Haynesville positions 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 there be learnings, absolutely.

Currently, when we think about how we're developing the NFZ 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 complexities and stuff out there. Do you -- what other kind of facets are important for us to focus on?

And then 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, of course, the 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 buildup in and around that position, but nothing material. Again, 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've 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 are very thoughtful about where we want it 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 and 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 NFZ, 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 sand 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 an 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.

As you 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?

Yes. 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 out 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.