Good day and welcome to the Expand Energy 2024 Fourth Quarter and Full Year Teleconference. At this time, all participants are in a listen-only mode. 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, Lisa. Good morning, everyone, and thank you for joining our call today to discuss Expand's 2024 fourth quarter and full year financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday. During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections, and future performance, and the assumption underlying such statements. Please also note there are a number of factors that will cause actual results to materially differ from our forward-looking statement, including the factors identified and discussed in our press release yesterday and in other SEC filings. Please also recognize that except as 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 measures which help facilitate comparisons across periods and with peers. For any non-GAAP measure, there is a reconciliation on our website. With me today on the call are Nick Dell'Osso, Mohit Singh, Josh Viets, and Dan Turco, our new EVP of Marketing & Commercial. 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 turn the teleconference over to Nick.

Good morning and thank you for joining our call today. The world's need for energy continues to grow with our attractive market-connected portfolio, resilient financial foundation, and peer-leading returns. Expand Energy was created specifically to better respond to this growing demand and yield stronger returns for shareholders in times of volatility. Our productive capacity strategy uniquely positions us to not simply react, but to capitalize on the dynamic market we see today. As our 2025 capital and operating plan demonstrates, this is exactly what we are doing. Benefiting from a powerful combination of premium rock returns and runway across our portfolio, access to advantaged markets, and some of the most capital-efficient operations in the industry, we've enhanced our outlook for 2025. We continue to benefit from the tailwind of our 2024 productive capacity strategy and now expect to produce approximately 7.1 Bcf per day for a capital investment of approximately $2.7 billion. As market fundamentals continue to improve the outlook for natural gas, we are electing to invest an incremental $300 million to build approximately 300 million cubic feet per day of additional productive capacity. This will allow us to efficiently deliver 7.5 Bcf per day in 2026 should market conditions warrant. We believe this level of production optimizes free cash flow at mid-cycle prices. Since we won't pull the trigger on this incremental capacity until mid-year, we have time to watch the market and we'll have the flexibility to adjust as necessary. Successful integration has further strengthened our outlook. We continue to capture significant capital and operating efficiencies, rapidly accelerating the achievement of our annual synergies. We now expect to achieve approximately $400 million of our annual synergy target in 2025 and to capture the entire $500 million target by year-end 2026. I am especially encouraged to see the 20% plus improvement we are delivering in our Haynesville drilling performance. In the fourth quarter alone, we cut nearly nine days and $1.5 million in cost per well from Southwestern's legacy drilling performance. The definition of synergy success is clear: achieving capital and operating efficiencies that result in spending less while producing more, which is exactly what we're doing. Our resilient financial foundation and peer-leading returns program are two areas which also further differentiate our company. At today's prices, we expect to end 2025 with less than $4.5 billion in net debt. Our debut $750 million investment grade issuance set a record spread for an energy rising star at 132 basis points over 10-year treasuries and cleared all near-term maturities through 2029. Our enhanced capital return framework is designed to efficiently return cash to shareholders and reduce net debt. After paying our $2.30 per share dividend, we expect to allocate $500 million to debt reduction in 2025. Given our strong free cash flow outlook, we expect to have additional cash available to allocate to a combination of variable dividend share repurchases and the balance sheet. Turning to our marketing program, we see great opportunity to capitalize on our position as the nation's largest natural gas producer. There is greater than 11 Bcf per day of LNG capacity under construction and the domestic power market continues to grow in support of data centers and rising consumer demand. We have the assets, balance sheet, and capital-efficient operations to help meet this new demand. I'm pleased to welcome Dan Turco to our team to lead this effort. Dan has extensive experience creating value for marketing and trading programs and will help us realize the benefit of our advantaged position. The marketing program has already seen the value of our combined portfolio. Our team worked extremely hard from the date of close to fully integrate our marketing and transportation portfolio by January 1st of this year, allowing us to optimize the flow of volumes across pipes, increasing the value for our gas and reducing costs. Looking forward to 2026, once the NG3 pipe is online, approximately 75% of our marketed volumes are expected to reach strategic markets including 2.5 Bcf per day directly to the growing LNG corridor. Expand's powerful combination of an attractive connected portfolio, a peer-leading returns program, and resilient financial foundation is distinct among natural gas producers. Today's market provides a unique opportunity for our company, and we look forward to expanding opportunity for our shareholders in the year ahead. Operator will now take questions.

Thank you. Our first question will come from the line of Matt Portillo of TPH. Your line is open.

Good morning Nick and team.

Hey Matt.

Just a quick question. Slide 9 is very helpful, laying out your thoughts on maximizing free cash flow at mid-cycle pricing. Just curious maybe if you could speak to that slide. And specifically if we're in kind of a $3.50 to $4 world, should we be thinking about kind of your productive capacity once you get to the 7.5 Bcf in 2026 to hold around 7.5? Or do you think you could continue to see growth from that point forward?

I'm glad you asked about this slide, Matt. It’s important for us to communicate our approach to capital allocation for the year and beyond. We discuss the proper setup for our business, and this slide effectively illustrates our thinking. It begins with a macro perspective, which will guide our capital allocation decisions. We'll continuously assess the market over a 2-3 year horizon, particularly focusing on mid-cycle prices. Currently, we estimate those prices at $3.50 to $4 per Mcf at Henry Hub. The table below shows a cash flow generation heat map, which balances production levels against price levels to identify our business's optimization point. In a strong market, increasing volumes can feel favorable, but there is an optimal production level reflecting the macro environment. This slide emphasizes that production can be excessive or insufficient at any price point. With our target of $3.50 to $4, we find ourselves in a good position at 7.5 Bcf per day. We also provide parameters that would necessitate a long-term macro view shift in order to increase our target production. We use the term "targeted" as well as "mid-cycle" because short-term volatility could lead us to reduce volumes or activity as we did in 2024. There are instances where we might want to ramp up capacity in response to temporary events. For our mid-cycle planning, we base our production levels on the prices under consideration. At the moment, we're focusing on $3.50 to $4 pricing with a production expectation of 7.5 Bcf per day. Interestingly, our price assessment is lower than the 2025 and 2026 market projections. We're conservative in our pricing assumptions and believe that prices currently above the industry’s marginal break-evens will attract additional supply over time, which will become increasingly competitive as international supply enters the market. The latter half of this decade will see more LNG capacity globally, enhancing competition with U.S. Gulf Coast production. Evaluating the market over multiple years aligns with our view of a reasonable pricing range of $3.50 to $4. This shapes our business strategy, influencing our optimal production and capital expenditure, which drives cash flow. Additionally, we're providing details on this slide, particularly the maintenance capital needed for each production level. Many assumptions underlie these projections and will be revised as necessary. We’re currently using our assumptions on well costs and productivity, while our team remains committed to improving capital efficiency. We will continue to update our projections, but believe this framework serves us well.

Perfect. And then maybe just a follow-up. You mentioned LNG. I was just curious if you can maybe touch on your updated thoughts on the marketing strategy? I know it's a diversification for you all. And there's obviously some puts and takes and views on global incremental supply versus demand over the next few years. So just curious, how you guys are thinking about the LNG market and your strategy moving forward?

Yes. Another great question. So again, we're excited about what's happening with the incremental LNG export capacity on the Gulf Coast and how we're positioned relative to that. We think we are uniquely positioned to that, one, just given the scale of production that we have proximate to those assets in the Haynesville, but then also, we have a really nice transportation portfolio that allows us to move 2.5 Bcf a day by the end of this year to Gillis. We moved another 2 Bcf a day over towards Perryville, which then can flow south towards the Eastern facilities like Plaquemines. We have a lot of connectivity to these projects. We have a great relationship with a lot of the liquefiers themselves as well as the off-takers, and we have regular communication with all of them about what their needs are and how we should think about being prepared to supply gas. So we really like our position. As you know, we have announced a supply agreement going through the Delfin facility. We think there's more that we can do around LNG in the future. But I would say we're really focused on ensuring that as we take on any incremental LNG projects, we're thinking hard about how we can do a couple of things. One, ensure that it provides a diversified revenue source for us, connecting us to markets that we wouldn't otherwise be connected to that have diverse and different characteristics than Henry Hub. We think that's important. And then exposing us to revenue opportunities that, again, help to generate higher levels of cash flow through cycles for our business. I think as we think about our business today, we are in the Haynesville, which is a really important geographic diversity for us, being proximate to markets and being able to grow. We need to show higher revenue to prove out the value of that geographic diversification.

Thank you.

Thank you. One moment for the next question. And our next question will be coming from the line of Doug Leggate of Wolfe Research. Your line is open.

Hi, good morning everyone. Thanks for taking my questions. Nick, I have two questions if that's alright. The synergy number seems to be evolving a bit quicker than you initially expected. When you announced the deal back in January of last year, you mentioned a two-year timeline for building a marketing business, and you've recently made a high-profile hire. Could you provide an updated outlook on the timing for achieving your goals and perhaps quantify that number? Is it around 2.5 Bcf a year? What are your expectations regarding that, like is it $0.10 or $0.20? I'm curious about the ambition since it seems many people may not have that in their projections right now. That's my first question. I have a quick follow-up after this.

Yes. Thanks, Doug. We're really excited about what is in front of us from a marketing perspective. And you're right, we have made a really important hire for our team. And we're looking forward to building out our business in a way that takes better advantage of the scale of production that we have as well as the transportation portfolio we have today. Traditionally, both Chesapeake and Southwestern marketed gas in a relatively close to wellhead fashion. We do have a lot of transportation, but we are, for the most part, selling gas to the nearest purchaser at the terminus of that transportation, whether that's off the gathering system or if it's further downstream. And we haven't engaged in a lot of optimization, which generally, larger companies do. We think there's quite a bit of value in the domestic optimization of how we sell our gas. And we're looking forward to building out the processes and the capabilities to do that. We know how to do it. We have the talent to do it. We need to build systems, processes, and certainly need to build a risk framework to ensure that we do it properly. But in doing that, we think we can add pretty meaningful value to our business and increase our netbacks to our equity production, certainly by a few pennies on that domestic optimization alone. And then the longer-term value opportunity is, of course, around new commercial relationships that could be more interesting. And those could be in the form of power deals, industrial deals, LNG deals, long-term buyers of gas that seek certainty of supply and potentially seek some certainty of cost. We think there's quite a bit of opportunity in a market that looks like it will increasingly have challenges of getting the right amount of gas to the right markets at the right time. We think we're well positioned to help solve those challenges.

So just to be clear, is that a $400 million annual business? Or is that an exaggeration? I do know the number you mentioned regarding the marketing model. I'm thinking $0.15.

I think we're going to hold off on giving you an exact number today, Doug. We're going to continue to build out this business plan. We're going to hold off on giving the exact number today, but we think it's certainly meaningful. And we're pretty excited about what's in front of us.

Got it. My follow-up is that you've mentioned having over 20 years of inventory. It seems like in the past, you indicated that Southwestern and Chesapeake had a 15-year backlog. Considering you're indicating that you can sustain this with $3 billion of capital and 7.5 Bcf a day, it looks like you're simplifying things for everyone to understand the value proposition. My question is about the commingling of Bossier, Haynesville Upper, and Lower Marcellus. What is extending the inventory? How do the relative economics of the portfolio today compare to what you were observing previously? I had the impression that Bossier and Haynesville had quite different returns, but now they're both included in the discussion. If you could clarify whether that 20 years is an apples-to-apples comparison, that would be very helpful.

Yes. Essentially, it's about the productive life of the assets we currently generate. Bossier and Upper Marcellus are included in this. We are actively minimizing risks across all aspects of these plays, especially those with fewer producing wells compared to the more traditional Haynesville or Lower Marcellus zones. Our team has effectively added value to these locations over the past couple of years. Each time we enhance these locations, we can classify more of them as productive in our inventory and visual representations. Additionally, as we integrate these two companies, we believe we'll achieve greater efficiency and effectiveness by leveraging the capital efficiency of our operations. We will operate fewer rigs than each company previously did individually, which extends the productive life and development timeline. We are also focused on converting more of our acreage to productive status, which allows us to expand with additional adjacent acreage around our plays.

Thanks a lot for the answers.

Thank you. One moment for the next question. And our next question will be coming from the line of Scott Hanold of RBC. Your line is open.

Yes, good morning. Let's continue discussing that topic. Specifically regarding the Upper Marcellus and Bossier, can you share what percentage of activity is expected over the next couple of years? Additionally, could you provide insights on the relative economics of those areas compared to others? Are there any factors that might enhance those economics and bring them closer to the Haynesville or Lower Marcellus?

Yes, good morning Scott, this is Josh. First on the split, we do provide a slide in the deck on Slide 35 that provides the breakdown for the number of TILs. But you'll notice in the Haynesville, we are going to be slightly heavier weighted towards the Haynesville wells. So it's probably closer to 60% to 65%. And in the Northeast with the Upper and Lower, it's probably closer to maybe 45% lower and the rest will be Upper. And so on the comparative economics, one of the things I would just say, and I'll maybe start with the Haynesville specifically, both reservoirs offer tremendous potential from a return standpoint. And we like the productivity that we see in each. The Bossier tends to be just a little bit more expensive on the completion side, but also recognize it's shallower. So drilling costs are a little bit less. We find productivity to be fantastic across both, I would say, somewhat equitable. The Upper and the Lower, we've talked about for some time, the fact that we do see lower productivity on a per foot basis in the Upper. But the ways we find to enhance the economics of that, which is really the ultimate goal, is by extending lateral lengths. And because it's less developed, we have opportunities to drill longer laterals, which we've been doing year-over-year. We've also really been investing in analytics and looking opportunities to enhance the way at which we complete these wells. And so the combination, the longer laterals, the enhanced completion designs, we've talked about hybrid wells in the past as another mechanism at which we could really boost up the profitability of the upper wells where we combine, let's say, a 10,000-foot section of upper with 5,000 feet of lower reservoir. That all helps to normalize our returns across the Marcellus play.

Thank you for the context. As a follow-up, I’d like to discuss the planned increase in productive capacity through 2026. It's interesting that you're distinguishing between productive capacity and regular growth. This suggests there are options available if market demand falls short. Can you provide insight into what happens in the latter half of 2025, especially as we approach the winter, which is always a crucial period for the gas market? If you begin to develop this productive capacity in your wells and the winter underperforms, what will be the implications for 2026 after investing that additional $300 million?

Sorry, my mute didn't come off. I'm going to start over. Yes, we're really pleased with the flexibility we exhibited in our business in 2024, and we think it would set up really similarly. So we're going to build this productive capacity coming into the end of this year, it will be ready to be turned in line in 2026. And if the market is not there, then it would we would likely have a response to that that would be some combination of either holding back the turn-in lines or curtailing volumes to alleviate pressure on the market. But I would back up even further than that. And let's say that we see that as we come through this year, the macro conditions change in some unforeseen way and the market doesn't look as strong in 2026 or 2027, then we'll change our capital allocation as well. We've proven, I think, several times over, the flexibility we have there and the willingness to try and be responsive and in front of market conditions to be efficient with our capital relative to where we are in the cycle. So we maintain a ton of flexibility in our business. And this is what we think is the right planning step for today, and we're very prepared for both increasing capital or decreasing capital as conditions warrant.

Thank you for that.

Thank you. One moment for the next question. And our next question will be coming from the line of Devin McDermott of Morgan Stanley. Your line is open.

Hey good morning. Thanks for taking my questions. So I wanted to dive in first on the 2025 activity in a little bit more detail, I definitely agree with the constructive outlook for gas prices this year. Looking back about a month ago, we were flirting with $2 on Henry Hub. So I was wondering if you could talk a bit more about the decision process to pull forward the deferred TILs and then also give a little bit more color on the cadence of that productive capacity throughout this year. I know you have the 1Q guide and the full year number, but how are you thinking about the volume trajectory as we move through 2025 for the business?

Yes, those are good questions, Devin. I want to revisit how we envision the macro environment and our 2 to 3-year price range, which we have set between $3.50 and $4. This takes into account the dynamics of supply and demand and all market factors influencing these over the coming years. On the supply side, we consider how many rigs are operational, the number of wells completed, their productivity, and the new pipeline capacity coming online, especially from areas like the Permian. All of this helps us develop a comprehensive understanding of market supply. On the demand side, we will closely monitor trends in power generation and the industrial demand driving that growth. A key factor we're focusing on now is the enhancement of LNG export capacity, requiring us to not only evaluate the overall capacity but also the anticipated utilization rates, which we expect to start off high but may decrease to less than full capacity in the coming years as new projects are launched. Incorporating all these elements informs our long-term outlook. It's also crucial to consider storage levels in our analysis. We maintain a positive long-term perspective, but with recent cold weather, storage has decreased significantly, pushing the market to seek additional supply sooner to prevent low storage levels. Our multi-year outlook hasn’t changed; however, the timing for additional supply demand has accelerated due to this cold winter. We believe it’s vital to uphold a long-term, multi-season perspective to avoid being swayed by short-term price fluctuations. It's also important for us to remain flexible in evaluating our assumptions over time. I'll have Josh elaborate on our production trajectory for this year and into next year since we've carefully considered this in relation to our deferred TIL strategy.

Yes, Devin, we started to see some strengthening fundamentals as we were ending the year. We began to bring online some of the deferred TILs at the end of December. In the fourth quarter, we brought on about 40 wells, with roughly 25 of those being technically deferred TILs. It's important to note that these 25 wells could have been brought online in a $2 gas price environment, but we instead were able to bring them on in a strong environment with approximately $4 gas. We feel good about that decision. As we move into the first quarter, fundamentals remain strong. We've observed relatively robust LNG feed gas pools, which we believe is contributing to tighter storage. For the first quarter, we're expecting to bring on around 90 wells into the markets. To give you some perspective, we've guided to a production number of 675 for Q1. We expect to grow from just over 6.4 Bcf a day at the end of December to around 7 Bcf a day by the end of March. This short cycle market response to production is what we've created here. With the deployment of our deferred TILs expected to be fully utilized by the first half of this year, we anticipate reaching a production level between 7 and 7.1 Bcf a day heading into the second quarter. We expect to maintain that production level as we finish the year, positioning us to benefit from the productive capacity that will build during this up cycle as we look to conclude 2025.

Got it. That's really helpful. And my follow-up is on that productive capacity. Slide 8 has the building blocks of capital and also some breakdown of where that incremental $300 million of spending would go. And I think it's notable that it's actually split across Appalachia and the Haynesville; you have some going to each of your core assets. So I was wondering if you could just talk a bit more about how you think about allocating growth capital across the different assets in your portfolio? And maybe as part of that, if you could just address the takeaway situation in Northeast Pennsylvania and how much room there actually is to boost volumes there?

Yes. So we think about allocating capital across these assets, just as you alluded to in your question. Our ability to grow is primarily in the Haynesville. In Appalachia, the capital that's coming in there is really in recognition of what the existing capacity is and bringing production up to those capacity levels. We know where we've been able to produce successfully in the past, and we're not going to attempt to go beyond that. So the growth capital that you really see is more about the Haynesville. I just want to remind everybody that we do sit right adjacent to the LNG growth corridor and have 2.5 Bcf a day by the end of this year of capacity to deliver to Gillis. So as you think about where that LNG gas is going to come from, it's going to primarily be sourced from Gillis. We have the LEAP pipeline and the NG3 pipeline and in aggregate, that's 2.5 Bcf a day that gets delivered right to the source of growing demand. And so the incremental volumes that we really think about here as we increase our volume profile into 2026 are focused on meeting that growing demand. This is not delivering volumes into a static environment.

Makes sense. Thanks so much.

Thank you. One moment for the next question. And our next question will be coming from the line of Neil Mehta of GS. Your line is open.

Hi, it's Neil Mehta here. Can you hear me okay?

Yes, sir.

All right, Nick. I just wanted to spend some time just talking about return of capital and capital allocation and those 3 tranches that you outlined in the deck and your objective here in 2025 as you transition from delevering to focusing potentially on shrinking your share count too?

Sure. We're pretty happy with the cash flow profile that's in front of us for the next couple of years. One, we've prioritized that pay down. And you can see that really clearly in that waterfall. We've put in place a $500 million debt pay down goal for the year. That's on top of the fact that we retired the outstanding revolving credit facility that was Southwestern's at the close. We've paid down $389 million of bonds that were maturing in January. And then we've done another refinancing, of course, with our first investment-grade issuance that allowed us to push out some maturities. So we have a really good runway in front of us to retire debt and a lot of cash flow to do it. So that $500 million out of our free cash flow will flow towards debt paydown as well as we have a little bit of incremental proceeds from the Eagle Ford sales that will come to us in deferred proceeds in 2025, that will go towards debt paydown as well. So we're taking a pretty good swipe at the balance sheet. We're going to end the year with less than $4.5 billion of net debt based on the recent strip. So we feel pretty good about that. That will obviously be well under one times EBITDA with prices around where they are. I would also remind you that that $500 million is a target that we'll set each year. So next year, we will have another debt paydown target. And what we've attempted to do with this framework is allow for a good balance of ensuring that our balance sheet stays very, very strong. It's, as you know, with the history of our company and the way we've been able to bring assets into the portfolio that have been very accretive to our overall returns profile, we believe you need to have a very strong balance sheet to do that. So we're going to continue to have a really strong balance sheet. You need a strong balance sheet to allocate your capital efficiently and maintain the flexibility to allow production to decrease and increase as we've done over the last year. And that balance sheet strength is such an important part of how we think about our competitive position in the market that it will stay front of mind for us and be protected. And then beyond that, though, we're going to generate a lot of excess free cash flow. We think that that needs to be returned to shareholders in a pretty significant proportion. So that remaining tranche then, we have the flexibility to return to shareholders, 75% of it either in the form of buybacks or variable dividends. We will use that flexibility to be thoughtful about the most efficient way to do that for shareholders. Over the last couple of years, you've seen us use both. I wouldn't be surprised if we continue to use both.

Yes. Nick, and that kind of brings us to the follow-up, which is you guys have done a great job of hedging the wedge or taking advantage of the constructive forward gas curve. Can you just talk about how you're thinking about the hedging strategy on a go forward? Does hedge the wedge still makes sense? Or have you gotten to an optimal level at this point? And just how you're thinking about that part of risk management?

Yes. Our hedging strategy, we feel like has worked really well for us. We had a really nice offset to the low prices last year that supported our cash flow. And despite the fact that gas averaged for the year about $2.26, we ended the year with a nearly neutral free cash flow position that's really largely supported by our hedges. In 2025, as prices have run quite a bit, our hedge losses are a fraction of what that gain was last year. And that's a function of the fact that we've hedged, we think, on a rolling basis that has really made sense so that we have exposure to the right prices in the market that we're setting the appropriate floors. And we've been able to use a fair amount of collars as we approached the start of 2025. We like the approach. We like having roughly 50% to 60% of the first year hedged and then less in the second year and continuing to lag into those hedges over time. We also would acknowledge that in recent weeks, as prices have been a lot stronger, we're not afraid to shift for near-term prices more towards swaps. You're elevating the floor of your locked-in price, and you're also willing to move to the higher end of your ranges of targeted levels of hedges. We see prices in 2025 that, like I noted a few minutes ago, are well above the marginal break-evens in the industry. And when you see that, you want to hedge more, and you want to go ahead and lock in those prices. So that's what we'll continue to do.

Thanks, Nick.

Thank you. One moment for the next question, please. And our next question will be coming from the line of John Freeman of Raymond James. Your line is open.

Good morning, thank you. My first question is a follow-up on an earlier discussion. Josh, when you discussed the accelerated pull forward on the deferred TILs, I wanted to clarify the model since you mentioned that all the TILs are expected to be exhausted in the first half of the year. I believe the plan estimates that around 85% of the DUCs will be completed this year as well. Can you provide the status of the deferred TILs and the DUCs at year-end?

Yes. So because we started bringing on wells in the back end of the quarter, which was about 25 that's deferred TILs, that left us with about 55 to 60 deferred TILs at year-end and between 50 and 60 DUCs at year-end. And just one comment I would make on the DUCs is that we have assumed a somewhat ratable activation of the DUCs across the year. And of course, there's a capital amount that comes along with that. One of the things we really like about the plan is just to retain the flexibility that we have. And we have this option to actually accelerate the completion of the DUCs that creates more flexibility in the year from a production standpoint while holding capital flat. And so though we'll have activated over all of our deferred TILs, we still feel like we've retained flexibility with the DUCs throughout the calendar year.

That's great. And my follow-up, when looking at that Slide 9, it would appear that going from kind of 7.5 Bcf a day to call it, 8 plus Bcf a day, it looks like just trying to back into what you've got for the CapEx, that it doesn't look like there's like a material kind of increase that's needed on the infrastructure spend. It looks like you'll can handle that without any big step change on that front. Is that the right read on that?

Yes, that is the right read. What you need to remember is just where both companies were operating prior to the deal announcement at the end of 2023. And so we have adequate offtake, the infrastructure, both in the field and with the transport is capable. And so effectively with what we're doing right now, we're restoring volumes. And then the productive capacity that we'll build will essentially continue down a path to get us to a spot where we're just more fully utilizing the infrastructure that we have access to.

Got it. Thank you.

Thank you. One moment for the next question. And our next question will be coming from the line of Paul Diamond of Citi. Your line is open.

Apologies, the line cut out there for a second. Good morning, thanks for taking the call. I wanted to discuss Slide 15. You mentioned making good progress on the drilling activity. I'm curious if there are any opportunities or what the timing for that might be. How much potential is still available?

Yes. We still believe there is significant potential for improvements. This slide on Slide 15 focuses on the Haynesville, and I want to express how pleased we are with the progress the team has made during our diligence process with the transaction. We had a clear understanding of the gaps in terms of days, and we used our integration planning time to break that down into well segments. This allowed us to achieve over a 20% improvement in our footage per day and a 20% reduction in costs just in the first quarter. To your question, we will continue to make improvements. Based on discussions with the teams, we know there are additional opportunities, and I am already seeing progress flowing into the first quarter. We feel confident about our trajectory. I also want to mention that while we focused this discussion on the Haynesville, we recently drilled a 5.5-mile lateral in West Virginia in just over 5 days with a single bit run. This type of progress demonstrates that there are opportunities that can translate into additional synergies in other areas. We definitely believe there is still room for improvement and are very excited about what lies ahead.

Understood. And just 1 quick follow-up. Thinking about the rig adds in the second half. How should we think about the timing and cadence? Or is that purely reactive? Or is there a plan for July 1 and then October 1? Just kind of how to think about the timing there?

Yes, Paul, I'll lay that out for you. The rig adds are premised across the second half of the year. What we're looking at right now is that we'd add a couple of rigs in the third quarter. Those would be destined for the Haynesville and Northeast App. Then in the fourth quarter, we would expect to add a rig in Southwest App and then the ninth rig in the Haynesville.

Understood. Appreciate the clarity. I'll leave it there.

Thank you. One moment for the next question. And the next question will be coming from the line of Charles Meade of Johnson Rice. Your line is open.

Good morning, Nick, to you and Josh and the rest of the Expand team there.

Hey Charles.

Nick, I wanted to ask about the graph on the left side of Page 10. My first impression is that it reminds me of my son's high school trigonometry homework. It seems like whoever created this slide might have been looking at something similar recently. However, I believe this is trying to explain the dynamics around the baseline scenario outlined on Page 9. If that's accurate, my interpretation is that you intend to increase CapEx when you're under-producing, likely when prices are low, and to maximize CapEx and begin to reduce it when prices rise. Could you help clarify this dynamic you've presented?

Yes. You're talking about our attempt to be countercyclical. And generally, I would agree with you. I would say that it's not going to be quite as simple as you just described. But generally, this is a look at how we would attempt to be responsive to market conditions in a way that is faster than the cycles of capital will typically allow you to be in this industry. If we go put capital to work in this industry today, it takes us a couple of years to bring production online and then earn a return on that production. From the point of what you make the decision until the time at which you have the return of capital in the bank from that decision, it's a couple of years. So what you really want is a business that's much more flexible in a market that has conditions to change much faster than that cycle of capital. This is really meant to describe how we would achieve that. We are very willing to allow production to fall in the near term. And then as you bring production back to move above a targeted midpoint when prices are there to support that. And so what you should think about is you accelerate and decelerate capital if you want to move that middle dashed line. But you move above and below that dashed line based on the near-term conditions in the market.

That is helpful, Nick. That adds to my understanding. And then one other thing, Nick, as a follow-up. Twice now, I think you've mentioned marginal breakeven for the industry. Can you share what you think that is and where Expand sits vis-a-vis the industry on that marginal breakeven?

Sure. I believe we can determine a specific number in a supply model for the marginal breakeven point, although everyone may have a slightly different perspective. We estimate that number to be around the mid-3s, and we view ourselves as being on the lower end of that range. This is due to our substantial inventory at very low costs in the Marcellus region, as well as our lower-cost inventory in the Haynesville compared to some competitors. We are benefiting from ongoing development in the core of the Haynesville and have the best capital efficiency in that area, which we have illustrated in our presentation. This positions us advantageously relative to the industry's marginal breakeven. Understanding this is crucial because companies need to be aware of their standing when responding to supply and demand signals. If you're on the higher end of the marginal breakeven, you shouldn't be the first to react, but we don't find ourselves in that situation. We are positioned close to increasing demand, and within that zone, we have the most capital-efficient assets. Therefore, we are confident in our competitive position.

Thanks, Nick.

Thanks, Charles.

Thank you. One moment for the next question, please. And our next question will be coming from the line of Zach Parham of JPMorgan. Your line is open.

Thanks for taking my questions. First, Josh, you mentioned some meat on the bone left on driving D&C costs lower. Have you built any of those incremental D&C declines into the CapEx budget? I mean, you've been consistently coming in at the low end or below on CapEx over the last several quarters. So just trying to get a sense on if that trend could be set to continue?

Yes. So what I would say is that for the $400 million of synergy, that does account for additional improvements. But I do believe and I have an expectation that we continue to find opportunities to enhance efficiencies through the year. And if realized, will create upside to the capital needed to execute our 2025 program.

Zach, I'd like to add that as we consider our synergies over time, which relates to a question Doug raised at the start of the call, we've pinpointed $500 million in synergies clearly connected to this merger. One reason for combining businesses like this is the increasing opportunities to enhance our operations every day. Over time, distinguishing between synergies directly linked to the merger and ongoing business improvements will become increasingly ambiguous after closing. We will hold ourselves accountable for that initial $500 million, and we will continue to enhance our business daily.

That's helpful information. I wanted to follow up on a few earlier questions. You mentioned anchoring to the 7.5 Bcf a day level in 2026, which is based on a mid-cycle price of $3.50 as shown in the slide. Regarding the future strips above that level, do you foresee any scenarios where you might increase production beyond the 7.5 Bcf a day level in 2026? I'm trying to understand how flexible you can be in terms of adjusting production both upward and downward.

You certainly could go higher, Zach. I think it would take underwriting a price above $4. If you look at that heat map chart, you can see that for us to be comfortable targeting a price above or targeting a level of production above 7.5 Bcf a day, you probably want to be underwriting a price, meaning you have confidence in a forward look for 2 years to 3 years that's $4 or higher. Not quite where we are today. The dynamics for the gas market are super constructive, and we feel really good about the near term here. But we also know that, like I mentioned earlier, these prices will elicit a supply response. And so we want to make sure we're not getting in front of that, and we're thinking through that and prepared for how that dynamic will evolve over time. Our market never responds perfectly and is always overreacting to one side or the other. But given the lack of rig count increase that we've seen as we've gone through this winter, we do think that the supply response should be a bit more muted this time than what we've seen in some past cycles. And we think that's a really encouraging sign for the health of the market longer term. Now if any of those dynamics change and you see that the look out into 2026, 2027, 2028 maintains a more constructive dynamic of supply and demand, then yes, we could underwrite a higher price. I think the most likely thing that would drive that would be if we felt that the utilization of LNG on the Gulf Coast would remain at or near 100%, meaning that demand for LNG around the globe maintained a strong pull on U.S. supply through that entire period. We need to see that evolve. We're not quite there today. The power growth demand story in the U.S. is another angle that could surprise to the upside. You'd have to see a real acceleration in how those plants are built, where they're built, and our ability to supply gas to them. We really like our position for the power demand growth story in the U.S. because we are regionally diversified because we have access to infrastructure that can allow us to grow. So there's a good news story around all of those things. But we want to see that play out before we would underwrite a higher price. I'm using the word underwrite very intentionally, right? We think about making a multi-year investment decision, and we think about it as an underwriting decision that should have an appropriate level of conservatism to it and be prepared to capture upside when it's available to us.

Thanks, Nick. That makes a lot of sense.

Thank you. And our last question will be coming from the line of Bert Donnes of Truist. Your line is open.

Hey good morning guys, thanks. On potential data center agreements, maybe what are your thoughts on how involved you need to be in the project? I guess where on the spectrum do you fall if maybe all the way on 1 side is you need to be a part of the upfront spend or maybe all the way on the other side where you just provide the gas and get a fixed price or a premium? And do you think there's room for a consortium of names to provide the gas supply? Or should it be more siloed with each producer having kind of their own individual agreement?

Those are good questions, Bert. I don't think they're completely known yet. We're open to all commercial structures associated with the creation and support of long-term demand for our industry. What we like about those projects is that they do represent long-term structural demand, really sticky, not weather-driven, short-term events. So we're open to supporting that in a number of different ways, but we are also very cognizant of our cost of capital and what would be efficient for our shareholders for us to invest. So I don't know that we need to invest capital in the infrastructure. But under the right economic scenarios, would we? Sure. We do definitely focus on what it means from a bottom line standpoint for the gas that we sell and the opportunity that we have to create a total return on our activities. As to whether or not we can do supply agreements like that on our own or you need a consortium, given our scale of supply, investment-grade balance sheet, and our ability to deliver gas to a number of different places, we think we're perfectly capable of doing things like that on our own, maybe even uniquely so. And at the same time, if there's a series of plants or a series of customers that want to have gas for multiple locations or want some diversity of supply, we can work with others on that as well. But we do think we're well situated to be a sole supplier for certain projects.

Got you. Very clear. And then just shifting gears a little bit. You outlined most of the potential growth in the productive capacity scenario would come from the Haynesville, but I assume maybe some growth happens in Appalachia at higher prices? And a few of your peers outlined growth plans in Appalachia that I think assume in-basin demand is going to materialize. But could you maybe talk about if you're seeing availability of transportation pickups? I mean, are there roll-offs of other operators that aren't growing? Or just maybe how you think about if there is Appalachian growth, where do those incremental volumes head? Thanks.

Another good question, Bert. I think there's a little bit of all of that, not maybe in huge size. So there's always a little bit of roll-off from others as the basins mature. When that happens, we're really well positioned, should we want it to take advantage. There's definitely some in-basin demand growth. And like I said, we're in the middle of a lot of those conversations to try to help encourage that. There's discussion of new infrastructure, and you've seen some of that in the press lately, and we're going to pay really close attention to that. And if those projects make sense, we'll be a part of that as well. The assets that we have in Appalachia, particularly our Northeast Pennsylvania position, is the most economic gas in the United States. Any opportunity that we have to deliver more of that into a constructive market with durable demand, you should expect we will seek and achieve. So those things are hard to make happen or they would have happened several times over, but there's probably a better opportunity to see those things happen today than there has been in quite a long time.

Thanks, Nick.

Thank you. And that does conclude today's Q&A session. I would like to turn the call over to Nick for closing remarks. Please go ahead.

Thanks, everybody, for joining the call today. We're really excited about what 2025 and 2026 has in store for us. The market has been volatile, and we are better prepared for that volatility, we think, than just about anybody else out there. We look forward to using that preparation and flexibility in our business to create incremental and attractive returns for shareholders. We'll all be on the road quite a bit over the next few weeks. And so probably see several of you out on the conference circuit and look forward to engaging with everybody. Talk to you soon. Thanks.

This does conclude today's teleconference. Thank you so much for joining. You may all disconnect.