Expand Energy - Earnings Call - Q1 2025
April 30, 2025
Executive Summary
- Q1 2025 delivered strong operational and cash flow performance: net cash from operating activities of $1.10B, Adjusted EPS of $2.02, and Adjusted EBITDAX of $1.40B, while GAAP EPS was a loss of $1.06 driven by unrealized hedge losses.
- Revenue (sales excluding hedge mark-to-market) was $3.21B, a significant beat versus consensus; Adjusted EPS also beat Street estimates. GAAP revenue (including derivatives) was $2.20B. Consensus comparisons detailed below (Values retrieved from S&P Global)*.
- Production averaged 6.79 Bcfe/d (92% natural gas). Management reaffirmed synergy capture (~$400M in 2025; $500M by YE 2026) and base dividend ($0.575), and highlighted S&P 500 inclusion and IG ratings across agencies as balance sheet catalysts.
- Key stock-relevant narrative: optionality to increase or defer volumes via “productive capacity” strategy, disciplined hedging (added ~740 Bcf floors/ceilings), and proximity to LNG ramp via NG3/LEAP into Gillis positioning realizations/margins constructively for 2025–2026.
What Went Well and What Went Wrong
What Went Well
- Strong free cash flow and Adjusted EPS: $1.10B CFO and $2.02 Adjusted EPS underscore robust cash generation despite volatile gas markets; Adjusted EBITDAX reached $1.395B.
- Operational execution: 11 rigs, 46 wells drilled, 89 TILs; the team delivered record drilling footage/day across all business units and achieved 6.79 Bcfe/d net production (92% gas).
- Strategic positioning and synergy trajectory: On track for ~$400M synergies in 2025 and $500M by YE 2026; S&P 500 addition and uniform IG ratings enhance capital access. CEO: “Overcoming market volatility requires a resilient financial foundation… and low cost, efficient operations, all hallmarks of our strategy”.
What Went Wrong
- GAAP loss driven by hedge marks: Unrealized derivative losses of $1.014B pushed GAAP net loss to $249M (–$1.06 diluted EPS) despite strong operating outcomes.
- Elevated DD&A and gathering/processing costs: DD&A of $711M and GP&T of $563M impacted GAAP profitability; marketing expenses were $919M given portfolio scale.
- Tariff risk to 2026 OCTG costs: Management expects muted near-term impact due to domestic sourcing and contracting through Q3, but notes potential 2026 reset if tariffs persist, prompting continued cost mitigation focus.
Transcript
Speaker 6
Good day and welcome to the Expand Energy 2025 first quarter earnings teleconference. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during this session, you'll need to press star 11 on your telephone. If your question has been answered and you'd like to remove yourself from the queue, simply press star 11 again. Please note that this event is being recorded. I would now like to turn the conference over to Chris Ayers, Vice President, Investor Relations and Special Projects. Please go ahead.
Speaker 7
Thank you, Jonathan. Good morning, everyone, and thank you for joining our call today to discuss Expand Energy's 2025 first quarter financial and operating results. Hopefully, you've had a chance to review the press release and updated presentation we posted to our website yesterday. During this morning's call, we'll 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 also 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 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 will help facilitate comparison across periods with peers. For any non-GAAP measures, there is a reconciliation that can be found on our website. With me on the call today are Nick Dell'Osso, Mohit Singh, Josh Viets, and Dan Turco. Nick will give a brief overview of our results, and then we will open up the teleconference for Q&A. Thank you again, and now I turn the conference over to Nick.
Speaker 1
Good morning. Thank you all for joining our call today. Recent market volatility has reinforced the importance of our strategy. The steps we took over the last year to build scale and the best gas assets, lower our costs through merger synergies, strengthen our capital structure, and invest in our marketing business have successfully reduced the impact of market volatility in our company. Overcoming market volatility requires a resilient financial foundation, a deep market-connected portfolio, and low-cost, efficient operations, all hallmarks of our company and strategy. In addition, we planned for and allocated capital around a mid-cycle gas price of $3.50-$4. While markets have been volatile, this pricing is still consistent with the forward strip, and our view has not changed.
While spot prices may be lower today, the macro fundamentals for natural gas remain very constructive, with growing LNG and data center demand setting up the market for a strong 2026 and steady rig count for lower 48 activity, implying a stable, not growing production. Against today's macro backdrop, we've continued to safely and efficiently execute our business. Our integration efforts remain on track, and we expect to achieve approximately $400 million in synergies in 2025 and $500 million by year-end 2026. Since close, we've eliminated approximately $1 billion in gross debt, including approximately $440 million in the first quarter. In March, we joined the S&P 500 index, and we were recently upgraded to investment grade by Moody's, which means we have now achieved investment grade ratings by all of the agencies.
These important milestones further demonstrate the strength of our company and the value of combining Chesapeake and Southwestern to create Expand Energy. While both companies have achieved these results individually, I'm confident we greatly accelerated the timing through our combination. I am proud of the way our team has come together and embraced the role we play in answering the call to deliver affordable, reliable, lower-carbon energy to markets in need. We also continue to benefit from the tailwind of our productive capacity strategy that has provided our business. Building productive capacity allowed us to efficiently increase volumes as demand grew. To put our strategy in context, over the first 12 months, volumes from our productive capacity wells will generate approximately $225 million more in free cash flow compared to if we had elected to turn the wells in line last year.
We expect to exit 2025 at approximately 7.2 BCFE per day, turning in line substantially all productive capacity built in 2024. As we look towards 2026, we are well-positioned to deliver returns for our shareholders. We expect to see a significant inflection in our free cash flow next year on top of the very strong year we're having in 2025, while growing our production to 7.5 BCF a day. This will allow us to return a significant amount of capital to shareholders. Sound capital allocation and prudent hedging will reduce risks and underpin our free cash flow. We look forward to continuing to update you on our progress, and the operator will now turn the call over for questions.
Speaker 6
Certainly. Our first question for today comes from the line of Neil Mehta from Goldman Sachs. Your question, please.
Speaker 5
Yeah, good morning, Nick, Mohit, and team. I appreciate all the comments here today. I'd love your updated thoughts around hedging. You guys did layer in a lot of those hedges for 2026. Just talk about the way you're thinking about the plan going forward and why you elected to do that.
Speaker 16
Good morning, Neil. This is Mohit. I'll take that question. As you've seen us in the past, we will continue our disciplined approach towards hedging, and we view that as just our way of managing the commodity price, the risk that's embedded in there. It allows us to capitalize on the volatility that we see in the commodity prices and to increase the downside protection at attractive levels while retaining some of the upside participation. One stat that I will mention to you is, since the start of the year, we have added about 740 BCF of new hedges of various tenors into Q1 2027, with the average floor price of $3.75 and an average ceiling of $5.10. This has worked really well for us in the past.
As another testament to the strength of the program, last year, we recognized $1.6 billion of hedge gains in a soft price environment. We know the program works. Going forward, it remains unchanged, and you'll continue to see us be disciplined about layering in more hedges as we see prices strengthen both in the near term and at the back end of the curve.
Speaker 5
Yeah, thank you. Nick, the follow-up is just on your perspective on the gas commodity. We have had a pretty dramatic move in the front. The backs have been pretty well-bid still, but in the front, do you think that is supply or demand? Maybe just talk about your perspective on balance of the year and how we progress from here.
Speaker 1
Yeah, absolutely. The front has been volatile. It's been interesting to watch. We've seen supply be a bit robust through the first part of the year. That's, I think, a function of the fact that we and some others had some deferred activity that we brought online into the cold winter that we had this year, creating some flush production. The incremental demand allows all of that deferred activity to flow at full rate. I think you had a pretty strong production start to the year. In addition to that, it was very cold initially in January, and then February and March were a bit more normal. April has been pretty under historic demand levels. I think you've seen a combination of supply be strong, demand be light.
I want to just remind you, though, that the way we think about it is the near-term volatility is something that we plan to absorb within the way that we think about capital allocation. We spent a lot of time on the last call talking about capital allocation, utilizing a two- to three-year forward look of mid-cycle prices, knowing that in the near term, cycles will drive prices higher and lower than that mid-cycle price. I think that's exactly what we've seen, and we feel really good about all of the fundamentals that drive our mid-cycle price expectations and our price expectations broadly for 2025, 2026, 2027 that still support exactly the same way we've set up our business.
Speaker 5
Makes a lot of sense. Thanks, Nick.
Speaker 6
Thank you. Our next question comes from the line of Doug Leggett from Wolf Research. Your question, please.
Speaker 15
Thanks. Good morning, everyone. Nick, I wonder if I could follow up on that. I mean, just looking at the hedge range, I think you and I have talked in the past, and I'm sure others, about the increased volatility of this market. And you've got like a 50% spread on these hedges just as a matter of record. My question is, navigating that, you've talked about lowering your break-even for the portfolio. Where is that today? Where do you think it can get to during this period? Obviously, there's a lot that goes into that, the synergies, the incremental delivery of those synergies, the marketing uplift in margins, and so on. I'm just wondering if you could talk to us about the trajectory for your break-even as you pay down debt.
Speaker 1
Yeah, it's a great question, Doug, and it's absolutely what we think about every day around here. Our break-evens today, as we begin to realize the synergies of the merger, have moved a little bit below $3. We think they're going to continue to drive lower, and we're focused every day on driving them lower through the remainder of realizing the synergies of the transaction, as well as further efficiencies that we're going to drive through our business.
Speaker 15
Just for clarity, Nick, is that the current spending level, or is that maintenance capital spending level?
Speaker 1
They're pretty close to the same number, right? I mean, our current spending level is where we expect to hold production, so they're the same thing.
Speaker 15
Okay, great stuff. My follow-up is a marketing question, I'm afraid. I know I tried this last quarter, but you recently had a trip out to Asia. I know you're looking at outlets all over the place, I guess, for your gas. There's a biggest gas producer now in the U.S., but I'm curious if you're ready to offer any kind of insight as to what impact that can have on realized prices for you guys and to the extent you can share what that LNG potential supply might look like for Expand going forward into U.S. LNG facilities.
Speaker 16
Hey, good morning, Doug. This is Dan. I'll take that question. On the LNG side, as you'd expect, a company of our size now, after the merger and scale, we've been in a lot of conversations about potentially entering the LNG business. In the reference, we've been out in Asia lately, talking to numerous opportunities. I think where we're currently situated, and especially in the Haynesville, we're well-positioned to grow that value chain, and we're in numerous conversations at the moment at various stages of the projects. I'm not going to comment on anything that's commercially sensitive, but I think there is value there for us to either sell into those projects or even go further downstream to expand our value chain and look for more upside.
The key in this is to have the right risk-reward balance as we get into that and make sure that intrinsically we're in the money on what we're doing and try to capture that extrinsic upside after. Again, early conversations in various stages at the moment. I don't want to comment beyond that.
Speaker 15
Good to hear you on the call, Dan. Thanks so much.
Speaker 1
Thank you.
Speaker 6
Thank you. Our next question comes from the line of Zach Parham from JPMorgan. Your question, please.
Speaker 8
Hey, thanks for taking my question. I wanted to ask on the cash return program. In this first six-month period of the new framework, you're going to have some free cash flow that falls into tranche three. Could you give some detail on how you're thinking about cash return from that bucket? Do you plan to be active buying back the stock, or will you lean more towards the variable dividend, or maybe a combination of both?
Speaker 1
Yeah, thanks, Zach. We are really pleased with our return framework. We think it is set up well for this year. We are just getting into the point at which we will start to determine now how that tranche three will be applied, and we will be thinking about that over the coming weeks. I think Mohit may have some more to add here.
Speaker 16
Yeah, Zach, the things I will add is we view a strong balance sheet as a competitive advantage, and that's something that we will continue to focus on. We remain very pleased with the progress we have made so far in terms of paying down around $1 billion of gross debt. That is very close to the target we had set for ourselves of $1.1 billion by end of 2025. The last thing I'll say to you is, if you look at our historical track record, we have returned about $3.7 billion to our investors through a combination of base dividends, variable dividends, and buybacks. That should demonstrate our unwavering commitment to return cash back to the shareholders. As tranche three gets waterfalled into at current prices, you should expect us to be active in the market if the stock is trading in the right levels.
Speaker 8
Thanks. My follow-up, I wanted to ask on Haynesville activity levels. In the slides, you show you're up to four frac crews there. That compares to the prior disclosure that had indicated you'd average three crews for the year. Can you talk about what's changed from an operational perspective? Have you pulled forward a little bit of activity, just given some higher pricing? Just curious what's changed in the operational plans there.
Speaker 5
Yeah, really, Zach, I would say we're on track with the plan that we laid out back in February. We knew coming into the year carrying a higher level of DUCs than maybe we have historically, that there'd be an opportunity to work down that inventory. Really, the expectation is across this quarter and maybe carry a month or so into Q3 that we'll run a fourth frac crew. That is going to average between three and three and a half for the full year. Again, that's really in line with how we saw the setup for the full year, where we saw the earlier part of the year really focused on the deferred TIL activation. As we've worked through that backlog of inventory, we're really now turning our attention to the DUCs.
Speaker 8
Thanks, Josh.
Speaker 6
Thank you. Our next question comes from the line of Devin McDermott from Morgan Stanley. Your question, please.
Speaker 20
Hey, good morning. Thanks for taking my questions. You had a slide in the deck, I believe it is slide eight, just highlighting some of the trends you are seeing on well cost and the fact that there is no material impact from tariffs. I just wonder if you would just talk through in a bit more detail some of the different buckets there, the trends you are seeing, and how the overall number, that 0-2% deflation, compares versus your expectations going into this year.
Speaker 5
Yeah, good morning. It's Josh. Yeah, we've obviously seen some weakness coming into the year in terms of the OFS market and just in conjunction with the merger, creating more scale within the basins that we operate in. We've been successful at renegotiating some key contracts, and that's given a little bit of a tailwind. Of course, that's something we were well aware of when we issued guidance in February. That all is embedded in the plan. As we look forward and look out to the rest of the year, and specifically around tariffs, there's clearly going to be a little bit of pressure that shows up associated with tariffs. In our business, that is going to show up within our casing cost. Now, I think a couple of things that are important to know. One is roughly 80% of our casing is sourced domestically.
There is some level of insulation, but we know as imports cost rise, that will likely kind of bleed into some of the domestic cost as well. Another important point is the simple fact that the majority of our casing is contracted through the third quarter. The exposure to those tariff-related impacts are somewhat muted. Really, when you add all those things together, that has led us to a spot to where we would expect costs from 2024 to 2025 to be flat to slightly down. We'll continue to work with our service providers. We have some really great relationships that we manage. That's going to be a focus for us going forward.
Of course, I think a spot that maybe creates a little bit of a tailwind for us as well is just really, I think, the outlook in the oil or basins, specifically within the Permian. If we see any material pullback in activity there, I think you could expect some additional deflation showing up across our business.
Speaker 20
Got it. Okay. That's really helpful. I wanted to step back and, Nick, ask you a higher-level strategy question. One of your peers recently announced a bolt-on transaction in Appalachia, and you highlighted the success of the Chesapeake-Southwestern merger and some of your repaired margins. It's very evident in the operating results over the last few quarters as well. I'd imagine that given the quality of the portfolio that you have, it's a fairly high bar for further deals or further M&A. I wanted to get your high-level views on further industry consolidation, the role you see Expand playing in that, and what kind of key financial or strategic metrics you would look at in evaluating any potential opportunities going forward.
Speaker 1
Yeah. Hey, Devin. You're right. We just completed a really big merger. We have our hands full realizing the remainder of the synergies there. It's going great, but it takes a ton of work, and we're very, very focused on that. Going forward, we'll continue to pay attention to things that are out there. That's part of our job. We're going to remain grounded on our non-negotiables when we think about additional deals. There are probably things that will look attractive to us at some point in the future. I can't predict when, and I can't predict exactly what, but I can predict that they will meet our non-negotiables.
Speaker 20
Understood. Thank you.
Speaker 6
Thank you. Our next question comes from the line of Nitin Kumar from Mizuho. Your question, please.
Speaker 16
Hey, good morning, guys. Nick, I wanted to maybe touch on there's been some discussion from the president about the Constitution Pipeline. As one of the larger producers in the Northeast, Marcellus, you are positioned to be benefiting from that. Could you maybe talk a little bit about what you think the chances are of that pipeline being built? What might the timeline or the commitment required look like? Just generally, are you seeing other opportunities for expanded demand for gas within the Appalachia?
Speaker 7
Hey, Nitin, this is Dan. I'll take that question. As you said, it's good to see infrastructure being discussed, the build-out, whether it be pipelines, compression storage, power, these data centers. More broadly, I'd add that it's good to see active discussions around the permitting and regular process in certain jurisdictions to try to streamline some of that. Appalachia has this clear need for takeaway, and we're supportive of these discussions. I know Williams is currently working hard at the specifics, and we're going to take a hard look at it when we have more details. As it stands, yes, still early days, but could be beneficial to our portfolio. We'll look at the cost-benefit of getting in that pipeline. You mentioned the power demand. We've seen a lot of that.
We are in active discussions in Appalachia with many power demand producers and data centers as well, various stages. Again, will not get into any specific commercial discussions there, but in general, good to see the build-out and the discussions happening, and we are going to look hard at these opportunities.
Speaker 16
Great. Thanks for the color, Dan. My follow-up is just on the cadence of spending. First quarter came in just a little bit below your expectation, but good to see that momentum. You talked about deflation here. You have maintained your full-year target. Maybe this one might be for Josh, but what is the cadence of the deferred tills, the DUCs, and at what point do you expect to start seeing the spending on the productive capacity for 2026?
Speaker 5
Yeah. First of all, I mean, I think it was a really good quarter for us operationally. There was a ton of activity for us, bringing on just under 90 wells in the quarter. I would also just note that from a drilling execution standpoint, we continue to perform at a really high level. We had record quarters from a footage per day perspective in both the Haynesville and in Northeast Appalachia while drilling the longest lateral ever in our Southwest asset at over 25,000 feet. Really pleased with the way the operations are going. In the Q1 number, there is definitely an impact of seasonality operations within there. We tend to do a little bit less planned maintenance work. Our work over spend is always going to be a little bit less, which is impacting us both in terms of the production expense and capital side as well.
You'll start to see some of that expense and capital rolling into the second quarter. As I mentioned earlier in a prior question, we're also adding a fourth frac crew in Haynesville for a short period of time, which again is allowing us to start to draw down the DUC inventory that we built up last year. As we look forward into the second half of the year, that's really where you start to see the productive capacity CapEx show up. We've talked about the incremental $300 million there. That will really be kicked off with the addition of an eighth rig in the July timeframe. With expectations, we'll be adding rigs in both Northeast Appalachia and Southwest Appalachia in kind of the fall timeframe.
That will get us on plane to exit the year at around 7.2 BCF a day and spending roughly $3 billion a year in total for 2025.
Speaker 16
Great. Thanks for the color, guys.
Speaker 6
Thank you. Our next question comes from the line of John Friedman from Raymond James. Your question, please.
Speaker 14
Thanks. Good morning. Just a question as the Haynesville gets ramped over the next few years. Is there any sort of additional either infrastructure or just sort of non-DNC spending that we should be aware of? Or does that sort of percentage of total capital in the Haynesville for non-DNC stay at a similar sort of rate?
Speaker 1
There's nothing planned right now for non-DNC infrastructure in the Haynesville, John. We had an opportunity a couple of years ago to participate in the NG3 pipe. That capital has really all been spent now. The pipe should come online at the end of this year. It's a great project. We're really happy to be in that. There's nothing else that's in front of us today. I think we loved that opportunity. If something else like that came along that offered us great access to an attractive market, we could choose to do something like that again, but there's nothing in front of us today that represents that.
Speaker 14
Got it. Just the follow-up for me on y'all have obviously done a really good job of making progress on the synergy capture. Just sort of looking at the slide that y'all have got in your deck in slide six, is it fair to say that it looks like everything that y'all have kind of needed to achieve on a run rate basis is kind of there with the company-owned sand mine, the lower financing cost, the completion design, all that stuff that was in that additional synergy bucket is sort of basically in place. Now it's just a matter of just continuing that run rate to achieve the $500 million by year-end 2026. Is there something else that I'm missing that's yet to be in place?
Speaker 5
No, really, John, I'd say we're on track. We feel really good about how the integration has gone. The teams are performing at a really high level. We've had another really great quarter of drilling in the Haynesville, which has just given us even more confidence in our ability to deliver the synergy there. Yeah, I would say at this point, we're on track for the $400 million synergy delivery by year-end 2025 and $500 million by the end of next year.
Speaker 14
Thanks. Appreciate it.
Speaker 6
Thank you. Our next question comes from the line of Keely Ackerman from Bank of America. Your question, please.
Speaker 19
Hey, good morning, guys. I want to ask about the Haynesville guidance. Can you kind of give us a sense of where Haynesville gas production is in real time, i.e., what it is today or perhaps at the end of March? If the message is that you're getting to 2.95 BCF a day in 2Q and holding flat, I guess the nuance there is that the Haynesville's largest producer isn't growing very much for the rest of the year, and that's constructive for second half 2025 balances. You also mentioned that the NG3 pipe is coming on at the end of the year, and you have capacity on it. I am kind of wondering how that gets filled.
Speaker 1
Yeah. Hey, Keely. Good question. That's exactly right that we're going to reach that level of production during the second quarter, and it will flatten out for the rest of the year without any incremental growth until we get into 2026. That said, we are planning a redirect of volumes into the NG3 pipe. We have a lot of production around the basin. A lot of it flows through IT today, intermittent transport today, or interruptible transport today. We have a lot of flexibility in where we deliver our volumes. We actually look forward to optimizing that flexibility through the work of Dan's team going forward to increase realized prices.
Speaker 19
Got it. I appreciate that. Next, I'd like to go to operating expenses versus our estimate. That's where the beat was in this quarter. We were kind of expecting a certain cadence for unit costs that starts high and trends lower as you grow volumes. In one Q, you're already at the low end. Kind of wondering how that trends from here.
Speaker 5
Yeah, this is Josh. We do expect spend on an absolute basis to increase as we get into the later spring and summer months. As I mentioned earlier, we just really peel back some of our planned maintenance activities and work over expenses in the first quarter. As production will pick up into the second quarter relative to Q1, it is just a simple fact that our absolute spend is moving up in concert with that. There are clearly some things that we see that are going well within our production expense, but it is still really early in the year. We want to kind of get another quarter under our belt. At this point, we feel pretty good about the guide that we have offered.
Speaker 19
Thanks for taking my questions, guys.
Speaker 6
Thank you. Our next question comes from the line of Philip Yongworth from BMO. Your question, please.
Speaker 4
Thanks. Good morning. When you think about your $3.50 to $4 mid-cycle view, just with the lower crude price, I was wondering how associated gas plays into your outlook. Generally, what level of oil production does that assume from the lower 48? If we undershoot that over the next couple of years, how would you think about upside in terms of incremental call in the Haynesville?
Speaker 1
Associated gas is a pretty complicated model, as you guys know, because from the Permian, you have had growing volumes, but then you also have an increasing GOR. Our approach to modeling Permian gas over the last couple of years has been really simple. Model the pipeline capacity that's coming online, and it will be filled. That has held true. I think that's still going to be true for a bit. We're going to continue to see increasing GOR. We saw how quickly Matterhorn filled, even though it did not appear that there were a lot of DUCs in the basin leading into that. I think just the basin continues to prove that associated gas is available when pipeline capacity is available. That said, if we see a material pullback in rig count in the Permian, that will change.
That could be a really interesting development for the dynamics of lower 48 supply. We are just going to have to watch that. There are a lot of predictions out there right now of cuts to rigs in the Permian. We have seen anything from 20-50, but we have not seen a lot of specific plans just yet. We are going to be watching that really closely.
Speaker 19
Great. Thanks. You had really strong realizations across the board, but did want to ask about the Haynesville specifically and just your medium-term outlook there for differentials or netbacks, just with several new pipes starting up in the play, including your NG3 pipe, LNG ramping, supply being slow to respond. Maybe with that, any update on the gas marketing and trading efforts that you've established over the last year?
Speaker 1
Yeah. I think really what you're touching on there, Phil, is just the dynamics of the overall market, the bigger fundamental trends, which is that demand is growing and growing pretty rapidly, particularly along the Gulf Coast as all this LNG capacity comes online. We love the fact that we have 2.5 BCF a day of capacity that's going to be available to deliver gas to Gillis. We also like the fact that we still maintain quite a bit of capacity at Perryville. The opportunities there to think about how we most effectively supply the markets that need the gas is pretty interesting. I think there's going to be a lot that plays out there.
With Haynesville starting off here in a position where it doesn't look like it's growing rapidly into this demand growth, I think it does set up for a pretty constructive environment for our business.
Speaker 19
Great. Thanks, guys.
Speaker 6
Thank you. Our next question comes from the line of Scott Hanold from RBC. Your question, please.
Speaker 0
Yeah. Thanks, all. Hey, look, y'all have a plan to start spending the $300 million of growth capital in the second half of the year. Can you give me a sense, given the volatility in just sort of the broad macro environment, how do you think about the optionality of doing that or not? If the gas market does break down, would you go ahead and spend that and build to that productive capacity, or would you defer the spending to next year? I guess the third option is, do you spend it this year and just build a deferred kind of till backlog? Just which one of those options would you kind of evaluate doing if the macro remains uncertain and prices come down a bit?
Speaker 1
Yeah. It's a great question, Scott. I will go back to, again, the framework that we put out last quarter, which is to really think about how the longer-term mid-cycle pricing works. The decision to spend money is really around that. The decision to produce gas is different. The decision to produce gas is much more around the immediate market conditions that we see at any given time. What you're describing is really a repeat of conditions that we saw last year, which would be a weak near-term gas market with decent long-term fundamentals. In that case, I think we continue to spend capital and potentially pull back on production if there's a weak price. We can pull back on production by curtailing flowing volumes today or deferring turn-in lines. We did both last year.
I think we have a track record of being very responsive and not oversupplying a market that does not need gas. That said, if the longer-term trends change, if the fundamentals change in some way, then you change your capital program. We really think about those things as very separate decisions. That flexibility that we have built into our business, built into our decision-making, and that we manage risk around through hedging and through how we allocate our capital, we think is a real positive evolution for the way we run our business and a strategic advantage that we can manage given our strong balance sheet, our approach to hedging, our ability to deliver gas out of several different areas of the country through a lot of different pipes.
We have the flexibility to grow production when we choose to and to pull back and manage that pullback across a lot of areas without incurring onerous fees.
Speaker 0
No, that's really good. I like the way that's laid out. My follow-up question is going to go back to one of the earlier questions on tranche three as you move into that. I understand, obviously, you're not going to give us exact color on how you're going to return that cash. Can you give me a sense of, with your discussion with investors, how do they view the variable dividend? We've seen a lot of this sector kind of back away from variables in favor of buybacks. Can you give us your general view on the value in the variables? Do you think your investors or just broadly investors would welcome that?
Speaker 14
Hey, Scott, this is Chris Ayers. I'll take this one. We actually see a pretty solid response to both buybacks and variable dividends. The benefit of the variable dividend is it de-risks the investor's investment. That is unilateral across the board in terms of receptivity of that embedded TSR through a cycle. If you look at our history as a company with the variable dividends that we've paid out, that has made up a solid portion of our TSR, regardless of how the equity price traded down or up with the gas price. Now, going forward, we would expect it to be a combination of both, as Nick talked about, with the variable dividends and buybacks. We see benefit in being able to have that through-cycle repurchasing power that buybacks bring for our business and being able to drive that per-share accretion.
We do see across our investor base, though, a belief in the support that a variable dividend provides for our TSR. Part of the reason why we'll look to combine both variable dividends and buybacks through a cycle.
Speaker 0
Thank you for that.
Speaker 6
Thank you. Our next question comes from the line of Matthew Portillo from TPH. Your question, please.
Speaker 2
Good morning, all. Just one question on my end. I was curious if you might be able to talk a little bit about the Utica, just your acreage prospectivity. I think you guys have about five wells planned to TIL there this year and kind of what you're looking for from a resource unlock perspective.
Speaker 5
Yeah. Good morning, Matt. We remain active in the Utica. We see the prospectivity of it, as well as really thinking about extending the limits of the Marcellus as well as you move further west into Ohio. We have pretty active leasing programs there to help shore up additional inventory. That'll continue to be a focus for us and the teams moving forward.
Speaker 2
Perfect. Thank you.
Speaker 6
Thank you. Our next question comes from the line of Jeff Jay from Daniel Energy Partners. Your question, please.
Speaker 12
Hi. I guess I was thinking about, and I really appreciate the color on the tariff impact on spend. I guess my question is, if these tariffs persist as they kind of stand today, would you expect a step change in costs in 2026 as your contracted materials roll over?
Speaker 5
If you want to think about the single sector of OCTG, I think there is the potential for those costs to reset into 2026. Just as a reminder, there are just so many other market dynamics that have the potential to impact costs, largely activity that we see occurring across the lower 48 and specifically in the Permian. In addition to that, we continue to invest in our business and things like a company-operated sand mine, water infrastructure that we have in our back pocket to offset any potential cost increase in the future.
Speaker 1
Hey, Jeff, this is Nick. One way I think about this is that certain raw materials like steel are going to be pressured up if the tariff situation continues. We are also seeing that that is driving oil prices lower. That is going to drive activity lower across the industry. You have certain raw materials going up and then service costs coming down, just kind of summarizing what Josh said. Those two are obviously connected to each other and work opposite of each other.
Speaker 12
Yeah, that makes sense. All right. Thank you.
Speaker 6
Thank you. Our next question comes from the line of Michael Shala from Stephens. Your question, please.
Speaker 13
Morning, everybody. Nick, you mentioned you expect free cash flow inflection next year, which is interesting given how capital-efficient 2025 is with the return of the deferred tills and the DUCs. Can you talk about the drivers for that inflection next year? Is it primarily due to just the way the strip price is, or how much of that depends on further efficiency gains?
Speaker 1
Yeah. No, the efficiency gains will come from the final realization of our synergies. There definitely is some. We are excited about that. The biggest driver is that we will be getting up to the production levels of 7.5 BCF a day that we are targeting. That is a pretty good gearing factor as you go into a higher-priced environment. Of course, we are hedging that higher-priced environment every day. You saw how much we hedged in the first quarter when prices were robust. We will continue to look for those opportunities.
Speaker 13
Got it. You have talked about the tariffs from a cost perspective. I am wondering if you could talk more broadly, just from a high level, how you think about that potentially impacting LNG markets and is that having any impact on your discussions on your gas marketing efforts?
Speaker 21
Hey, Mike. This is Dan. On the LNG front, if you're talking about online capacity today, we don't really see any issue coming from the tariffs. I mean, China had implemented tariffs, I think, in February, and you see reoptimization of cargoes around the world just to place all those cargoes in the market. I mean, we've seen no slowdown in the construction of facilities currently online. We've seen no slowdown in the conversations we've had with potential new LNG capacity online. Really, in the near midterm, we don't really see a challenge. Yeah, there may be, as Nick said, on the upstream side, there may be a cost challenge coming to some of these projects, but really no slowdown we've seen.
Speaker 13
Appreciate it. Thank you.
Speaker 6
Thank you. Our next question comes from the line of Leo Mariani from Roth. Your question, please.
Speaker 18
Yeah. I wanted to follow up a little bit on sort of price synergies. You guys talked a lot about this when the Chesapeake-Southwestern merger was announced. You certainly mentioned that you're engaged in a lot of discussions. You hit your investment-grade ratings. Clearly, production is up. I know you can't comment on specific projects, but maybe just talk about your kind of level of confidence on getting some of these gas-price-related synergies today versus when you announced the Chesapeake-Southwestern merger.
Speaker 21
Hey, Leo, I'll take that question as well. I'm quite excited about this opportunity that we had to create something unique for this company in terms of optimizing our portfolio. It's early days with this new MSC organization, but the team has actually done quite a bit so far. I mean, bringing the two portfolios together in 90 days was a pretty impressive feat. They've already had some early wins by connecting the portfolio across EFT and getting some optimization value. Going forward, we're going to try to do more of this at scale, right? Just continue to optimize our portfolio. Something that Nick talked about in the Haynesville, where we have the NG-3 pipeline coming on, gives us a lot of daily optionality. I'm really excited about what we can do.
We have had some recent hires come on board to increase our capacity to do so and also our capabilities. Going forward, I'm quite confident about our ability to make more money and more margin through this new organization we're creating.
Speaker 18
Okay. Appreciate that. Just on the operational side, obviously, you guys had really good success here in the first quarter. Certainly got kind of more than kind of a quarter of the TILs done here in the quarter. Sounds like you're bringing on another frac crew as well in the Haynesville and QQ. It feels like the ops are a little bit ahead of schedule. Just wanted to kind of take your temperature on the ops side here. To the extent that you continue to execute well operationally, could we see a few more TILs than you've guided to here in 2025, or would you guys likely maybe choose to kind of save some CapEx towards the back end of the year for "budget exhaustion"?
Speaker 10
Yeah. First of all, Leo, we have had a good start to the year and really pleased with the overall operational performance. Right now, we really remain focused on creating as efficient a business as we can. As we talked about on the last call, it's really about getting our business up to that seven and a half BCF a day mark. If we're able to achieve that through less activity, i.e., fewer drilling rigs because we're drilling faster, that's likely the path that we would end up taking. We feel good about the plan that we've laid out and remain on track to deliver that guidance.
Speaker 18
Okay. Thanks.
Speaker 6
Thank you. Our next question comes from the line of Betty Jiang from Barclays. Your question, please.
Speaker 17
Good morning. I just have one clarification question on the return framework. How to think about determining the available cash flow for cash return for the rest of the year. Your target provided last quarter was $500 million broken into two $250 million tranches per each fiscal half year, with the $468 million that was done in Q1. Do you see that meeting your first half requirement, or that's effectively completing most of your requirement for the year?
Speaker 21
Yeah, Betty, this is Mohit. The way, if you go back to when we unveiled the program, we set it up as two evaluation periods. The first evaluation period is the first half of the year. You really need to look at the first quarter and the second quarter together. That is the way we have been viewing it. As Nick previously signaled, at current commodity prices, we see enough free cash flow to be able to service tranche one, which is the base dividend. We have made good progress on tranche two, which is net debt reduction. We do expect some free cash flow to go into tranche three, which is where we will have some discretion on how much to put towards variable versus buyback, the 75% that is allocated to it. Hopefully that helps.
The way you should think about it is in terms of the evaluation periods.
Speaker 1
Yeah. As to the pace, Betty, I would just note that we had a piece of debt that matured in January. That drove the pace there for the first part of the year.
Speaker 17
Got it. Second half will still get reevaluated separately?
Speaker 21
That's right.
Speaker 17
Okay. Great. Thank you.
Speaker 6
Thank you. Our next question comes from the line of Paul Diamond from Citi. Your question, please.
Speaker 9
Thank you. Good morning, all. Thanks for taking my call. Just a quick one talking about kind of the synergy outlook. You have done a pretty good job on both the OpEx and capital side of kind of progressing towards that $400 million per annum by year-end. Seems to be a bit more chunky. Just wanted to get an idea if we should think about that more kind of like step changes along the way, or should it be more thought of as linear going forward?
Speaker 1
Yeah. Hey, Paul. It's Nick. The way I think about that is we're really pleased with what we've accomplished so far. If you think about the drilling and completion synergies, we're seeing the full element of synergies achieved with the individual wells that we're drilling today. In order for us to achieve the aggregate dollar amount of synergies projected for the year, we have to drill all the wells in the program for the year. I would say we are complete in terms of our ability to capture the synergies, and now we just have to execute our plan to complete capturing them. Does that answer your question?
Speaker 9
No, it makes perfect sense. Appreciate the time. I'll leave it there.
Speaker 6
Thank you. Our next question comes from the line of Kevin McCurdy from Pickering Energy Partners. Your question, please.
Speaker 11
Hey, good morning. I have another question on the marketing side. Slide 13 of your deck details your marketing contracts and talks about a BCF a day of going to Gillis and in 4Q25. Do you have any color or expectations for how that market at Gillis is shaping up and how that could impact your margins?
Speaker 21
Hey, Kevin. Thanks for the question. This is Dan. Yeah, we're excited about that capacity coming online that Nick talked about that gets us down to Gillis. Really, we're excited because the real growth we're seeing down there with the growth in LNG under construction, right? You have Plaquemines ramping up right in our backyard. You have Golden Pass that we hope to come online in 2026. You have just recent announcements from Woodside on Louisiana LNG that's going to bring more demand to that market over time. We are expecting that market to be quite a premium market and basis to increase there. Not only there, but across the Haynesville, as there's going to be a pull across in total Haynesville to bring gas to that area of demand.
Speaker 11
Great. It sounds like positive for margins. Maybe for a second question to ask a different way on the CapEx trajectory. You came in low in the first quarter. The guidance points to step up in 2Q. Any color that you can share on the expectations for the back half of the year as it compares to Q1 and Q2 for CapEx?
Speaker 10
Yeah. We would expect the trajectory through the third and fourth quarter to be relatively in line with where our Q2 CapEx is.
Speaker 11
Great. Thank you.
Speaker 6
Thank you. Our final question for today comes from the line of Charles Meade from Johnson Rice. Your question, please.
Speaker 3
Good morning, Nick, to you and your team there. You guys have really had a murderer's row Q&A lineup this morning. I am impressed, and thanks for taking the time. I just have one short question on TILs. I think it will be a short question. Have you guys seen anything that surprised you, either positive or negatively, as you brought on these deferred TILs that were kind of sitting bottled up for whether two, three, four months? Is there any kind of difference in that answer, variation between what you have seen in the Haynesville, Southwest App, or Northeast App?
Speaker 10
Yeah. Thanks for the question, Charles. Really, I've been incredibly pleased with what we've seen today. I mean, first of all, if you just think about the amount of activity that we've been managing. In fact, if you were to go back to the fourth quarter, we've now brought on 130 wells over the last two quarters. The teams have just done a phenomenal job managing a lot of activity in a short amount of time. The well performance that we see, it looks undisturbed from anything that we would expect if you were to bring these wells online with normal cadence. You were always going to expect to see some level of variability depending on the types of wells we bring online, so upper versus lower or the various parts of the Haynesville where productivity can vary as you move from north to south.
Just really pleased with the overall execution of our productive capacity strategy.
Speaker 3
That's great detail. Thanks, Josh.
Speaker 6
Thank you. 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.
Speaker 1
Thanks, everybody, for your time today. Look forward to seeing everybody out on the road as we get out and meet with investors. As usual, you can reach out to our team with any other questions, and we'll look forward to seeing you guys around the first week of August for next quarter's results. Thanks.
Speaker 6
Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.