Expand Energy Corporation (NASDAQ:EXE) Q3 2024 Earnings Call Transcript

Expand Energy Corporation (NASDAQ:EXE) Q3 2024 Earnings Call Transcript October 30, 2024

Operator: Thank you for standing by and welcome to the Expand Energy Corporation’s Third Quarter 2024 Earnings Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [Operator Instructions]. As a reminder, today’s program is being recorded. And now I’d like to introduce your host for today’s program, Christopher Ayers, Vice President, Investor Relations. Please go ahead, sir.

Christopher Ayers: Thanks, Jonathan. Good morning, everyone, and thank you for joining our call to discuss Expand Energy’s third quarter 2024 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 can neither be confirmed by reference to existing information, including statements regarding our goals, beliefs, 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 differ materially 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 financial measures which help facilitate comparisons across periods and with peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure and can be found on our website. With me today on the call are Nick Dell’Osso, Mohit Singh, and Josh Viets. Nick will give a brief overview of our results, and then we’ll open up the teleconference to Q&A. So, with that, thank you again and turn the time over to Nick.

Nick Dell’Osso: Good morning and thank you for joining Expand Energy’s first earnings call. This is an exciting time for our company, and I look forward to briefly highlighting our third quarter results and providing our preliminary outlook for 2025. The integration of our two companies is off to a great start. Through the first month, we’ve seen plenty of accomplishments and are ahead of schedule with our integration plans. Our early success is a testament to the quality of our employees and their commitment to making Expand Energy a leading energy producer. For the two standalone companies, we see significant momentum heading into 2025 with solid third quarter results, delivering impressive operational gains which will enhance future margins and profitability.

A few notable achievements from the quarter include the combined company produced 6.75 BCFE per day while continuing to build productive capacity through our deferred completions and turning lines. Legacy Chesapeake drilling operations delivered record quarterly feed per day in the Haynesville and Northeast Appalachia, while the company also set monthly and quarterly completion records for total hours pumped in Northeast Appalachia. Not to be outdone, Legacy Southwestern drilled a 25,191-foot lateral in Southwest Appalachia, a record lateral length for a lower 48 onshore well. Now I’d like to talk about why we are so excited about what this company will deliver for our shareholders and energy consumers alike starting with 2025. Our preliminary capital and operational plans illustrate the powerful combination of Expand Energy and our outlook for enhanced operational efficiencies.

We are truly better together with a portfolio that will be more competitive and resilient in all price cycles. Our preliminary outlook for 2025 includes approximately $2.7 billion of total capital to deliver an average of 7 BCFE per day. Compared to Chesapeake’s standalone maintenance level, this represents a 120% increase in production with only an 80% increase in capital. Our strong outlook will be driven by the achievement of our synergies and capturing significant capital and operating efficiencies. I recognize many companies promise synergies. For us, the definition of success is clear. It’s all about capital and operating efficiencies resulting in spending less while producing more. In 2025, our capital efficiency should benefit from the deferred activity we built during 2024.

Importantly, however, we expect this capital efficiency ratio to hold as our synergy realization builds and operating efficiencies continue to deliver higher value for every dollar spent. This ensures we deliver better financial performance during down cycles and more free cash flow during periods of higher prices. Our competence in our preliminary plan is based on our early integration wins, which have positioned us to raise our expected annual synergies target by 25% to $500 million. The extended period between deal announcement and close allowed us to hit the ground running. In the initial weeks of Expand Energy, we have already successfully drilled telemetry data from all drilling rigs, successfully streamed drilling telemetry data from all drilling rigs to our drilling ops center, allowing real-time optimization, redirected legacy Southwestern produced water to owned water disposal assets, saving $1 per barrel, and implemented a new org structure to ensure Expand Energy is comprised of the best talent while capturing the best work processes from both organizations.

Given our strong start, we expect to achieve approximately $225 million in synergies, which is more than 50% of our original synergy target next year and are well on our way to achieving the full $500 million annual target by year end 2027. Our strategy to build productive capacity will also provide a strong tailwind into 2025. We’re on track to build approximately 80 deferred tills and up to one BCF per day of short cycle capacity by year-end. We will be prudent in turning production online and ready to rapidly respond to market condition when pricing improves. Ultimately, while we don’t know exactly how prices will respond, we do expect market volatility to continue. Expand Energy was built to deliver through cycles, and our hedge-to-wedge strategy provides great confidence in our financial outlook as we benefit from attractive collars and ceilings that are priced well into the $4 per MMBtu range.

Simply put, we have effectively protected our 2025 program from a prolonged down cycle while ensuring we can still capture significant upside value in periods of higher prices. While our powerful portfolio and efficient operations are keys to our sustainable success, so too is our resilient balance sheet and capital returns program. We achieved an investment-grade credit rating upon close, allowing us to transition our RBL to unsecured, eliminate financing costs, and ultimately access capital at more attractive rates. Our investment-grade rating strengthens our position with counterparties as we continue to execute our LNG-ready strategy and supply power to domestic markets in need. We understand the importance of a strong balance sheet and peer-leading shareholder returns, both hallmarks of legacy Chesapeake since our restructuring.

To ensure financial strength remains a pillar of Expand Energy, we are enhancing our capital return framework to reduce net debt while maintaining an attractive capital return to shareholders. Our new framework prioritizes the base dividend and debt reduction while including a $1 billion share repurchase authorization and the opportunity for future variable dividends when market conditions warrant. I have said before, the world is short energy. As the largest domestic producer of natural gas with an advantage portfolio, resilient financial foundation, and geographically diverse assets, we are built to answer the call of increased domestic and international demand, as well as thrive in the volatility that will naturally follow this rapidly evolving market.

In doing so, we are primed to expand opportunity for all stakeholders. I look forward to updating you on our progress, and we’re now pleased to address your questions.

Q&A Session

Operator: Certainly. And our first question comes from the line of Kevin McCurdy from Pickering Energy Partners. Your question, please.

Kevin McCurdy: My first question is on the capital costs. I think the outlook for $2.7 billion in 2025 was lower than expected. My question is, how did the $225 million in synergies in 2025 compare to your original target? And what else are you seeing on the well costs in your legacy assets? It looks like quarterly production came in, or quarterly CapEx came in lower than expected again this quarter.

Nick Dell’Osso: Yes, I’ll just start by noting that the $225 million increase is a combination of a few things. It is heavy on the capital side, though. I’ll let Josh give you the specifics.

Josh Viets: Yes. Hey, Kevin. On the $225 million, about $75 million of that’s going to be attributed to CapEx. But just as a comparison to where we started, one of the things that we had talked about with the $400 million, which is what we described at the transaction rollout, is that $400 would be delivered about a third, a third, a third. So cumulative building over a three-year time period. So you’re talking about almost a $100 million increase in year one as far as what we’re able to deliver from a synergy standpoint. Your second question, just in regards to well cost trends, you’re really just incredibly pleased with the execution performance that we’ve seen. Nick referenced a couple of the highlights for the quarter, record pumping month within our Northeast app.

We’ve seen record footage per day really across the entire company, including one of the more challenging places to drill in the NFC of the Haynesville, where we averaged just under 900 feet a day, which again is a record for the company. And then of course, we have seen some deflationary elements show up as well, and that’s really carrying on into the fourth quarter. And we expect to see a little bit more market softness heading into the first quarter and all that’s been accounted for within the current plan.

Kevin McCurdy: Great. And my follow-up is on OpEx, and I know you don’t have all the details yet on 2025, but just curious if the 4Q OpEx guidance is a good starting point for next year, or is there anything else that you’ve identified synergies on the OpEx side in the near term?

Josh Viets: Yes. I think the Q4 number is relatively good as far as where we’ve pegged the range there. We will start to see a little more synergy show up specifically on the water disposal side of the business in the Haynesville. And then of course, the plan that we’ve rolled out, we’ve shown production modestly growing through the course of the year. But the Q4 number and the guide that we’ve offered there is a relatively good starting point for you.

Kevin McCurdy: Thank you, and congratulations on closing the deal.

Operator: Thank you. And our next question comes from the line of Doug Leggate from Wolfe Research. Your question please.

Doug Leggate: I guess, Nick, first of all, I’ll also add my congratulations to the synergy uptake, but forgive me for this one. I guess we’re never happy with synergy targets because they tend to be risked at the outset. You obviously never want to put a number out that you can’t deliver. So I guess my question is that, are you done in terms of your view of what you think the merger can deliver? There are a lot of things discussed when we went to the Haynesville with you last year in terms of what you could do differently. Obviously, you’ve got a chance to potentially refinance some of the higher cost debt, although the debt maturity side looks pretty attractive. There’s a lot of things that you could take off, a bunch of different things. So I guess my question is, how have you risked the delivery of the synergies? How would you characterize the medium-term outlook? Where are we going to be sitting this time next year in terms of how this target looks?

Nick Dell’Osso: Frankly, I love that question, Doug. So to directly answer the question, are we done? I certainly hope not. We are pretty methodical and deliberate about how we determine what we’re going to consider a synergy, how we’re going to project it, and ensure that it is tangible and quantitative in nature. That said, this is now a huge portfolio of assets with tons of opportunity in it. And the opportunity exists across the entire portfolio. As you think about all of the learnings that come together from operating across both legacy companies’ portfolios, you think about the talent and the teams that come together, you think about the number of rigs that we’re running, the number of acres that we’re maintaining on a daily basis, the operating platform that we will manage.

And then in addition to that, as you noted, the balance sheet implications of this larger, stronger organization. There’s a lot of things for us to do here. And we believe that scale can offer a lot of really significant opportunities. We’ve captured a good many of those in our synergy projection. We’ve been able to increase it today because we had a good long time period to plan for closing. And we were able to gain confidence in some things that we thought were potential, but we now consider to be absolutely part of our plan. I would love for us to continue to add to that number over time. But in order for us to do that and call something a synergy, it’s going to have to meet the same criteria that we’ve put into calling the $500 million that you see in our model today as synergies.

And it’s a reasonably high bar and a high bar for a good reason. We want to be able to deliver something that we have great confidence that we can deliver and that we can prove when we call something a synergy like this. The last thing I would say is keep in mind, Legacy Chesapeake did two acquisitions over the last couple of years. Legacy Southwestern did three over the last three or four years as well. So we have a lot of practice at bringing together operating teams, creating synergies, tracking them, and understanding what is possible and what’s not. And so I think our track record here is something that we’re going to rely on. And the learning history is important to us as we think about how we have confidence and what’s in front of us and knowing that we can deliver on the numbers that we’re providing.

Doug Leggate: Very cool answer, Nick. I guess you’re right. The track record, the history, and the experience you’ve got of integration is something that I don’t think all of us should forget. My follow-up is kind of a macro question. We ask you this question a lot, but on slide 10, you’ve laid out the cadence potentially of bringing back production. I’ll be blunt. I think there is some skepticism on the capital efficiency benefits you’re getting from drilling wells, not completely not bringing them online. So I wonder if I could ask you to speak to your confidence in the 2.7, 2.8 sustaining capital. And more importantly, what are the conditions under which you would not bring back this production in 2025?

Nick Dell’Osso: Another great question. So first, our confidence in it is very, very high. And it’s not just confidence in the 2.7 for 2025. We gave you, in addition to that, another slide in the deck where we show you a 2027 look, which is an opportunity for us to show you what our capital efficiency looks like when all of the tailwind of the deferred activity from 2024 has rolled completely through the system. And what happens is that you have capital efficiency benefit from the deferred activity in 2025. As that capital efficiency winds down from that tailwind, that efficiency is replaced with the synergies associated with our cost reductions from the merger. And so we think that the ratio, effectively, of CapEx to production that you see in 2025 is sustainable going forward.

Now, what could cause us not to do it? Lots of things. We have complete control over, to reference the same slide, slide 10, there is a wedge of production on those slides, on that slide, that shows in a light blue color that represents the volumes from the deferred activity. That’s completely at our control as to whether or not we bring that online. And if prices are soft as we come through winter and if we have congestion in storage and the supply-demand fundamentals are weaker than the forward strip would indicate today, then these volumes don’t need to come online, and we can moderate this accordingly. So we have a lot of control over this and a lot of confidence in our ability to deliver on it. And we have a lot of confidence in our ability to hold this capital efficiency into the future.

Operator: Thank you. And our next question comes from the line of Matthew Portillo from TPH. Your question, please.

Matthew Portillo: Just a quick question around the opportunities for additional optimization, as you mentioned, maybe a bit longer dated, but curious on the midstream side, specifically thinking about maybe some of your contracts in the Northeast, but also in the Haynesville. Do you guys see any opportunity over the next few years to optimize your midstream and marketing side of the business?

Mohit Singh: Good morning, Matt. This is Mohit. That’s a great question as well. Just a reminder, we closed the transaction on October 1, so fast forward 30 days. So still very early days. Right now, if you look at the state of the business, we are operating two marketing books, but we do have plans to combine the books come January 1, 2025, and continue to flesh out what marketing synergies that we are expecting to get a little bit more specific around what we are doing around M&T integration. As I mentioned, joining the trade books, name updates in the contracts and ASB consolidation, ETRM back office integration. The high-level answer to your question is we are beginning to optimize flows. We are trying to get more of our production to premium markets, and we are beginning to have some early wins.

If you start looking in Northeast app, there’s a certain amount of equity gas that we were able to move from Chesapeake production and move it into some FT that SWN had, which was idle. In Haynesville, we have utilized some of the SWN FT to move Chesapeake equity gas to more premium markets using some specific pipes that we had access to. Similarly, we are in Southwest app using the Southwest app firm capacity to fill Chesapeake legacy pool sales. So all those are early wins. We are super excited at this point of time. Over time, as we bring the two trade books together and integrate the two businesses together, then we’ll share some more details around that.

Matthew Portillo: Great. Then maybe just as a follow-up on drilling and completion, I know you all had highlighted really the opportunity to drive down costs at the drill bit given faster cycle times, specifically in the Haynesville. But I was curious if you landed on a fluid loading design there. I think there was a bit of a difference in how you all historically at Chesapeake looked at fluid loading versus how maybe Southwestern looked at it and if that’s been incorporated into your outlook in 2025 and beyond in terms of cost savings.

Josh Viets: Good morning, Matt. Yeah, we absolutely did. I guess maybe to go back to our original synergy target, the $400 million a year, $130 million of that was attributed to what we described as drilling and completion synergies, but that was really entirely tied to drilling improvements. The reasons we decided to not at the time include any completion synergies is we just know how sensitive completion designs are to productivity and therefore wealth economics. And so we really wanted to take our time, which we have now done through the integration planning process, to be able to combine the two companies’ data sets, assess the implications of various design changes and its impact to productivity and therefore wealth economics.

And as we’ve come out now with an incremental $100 million, we have now included some synergies that we see associated with completion designs and some of the components of that. You mentioned fluid intensity. We will be dialing back fluid intensity a little bit, but on the flip side, we’ll be increasing profit intensity we expect in the Haynesville going forward. In addition, there are some savings we can realize by changing the perforation design as well, such as increasing our stage links and using an extreme limited entry completion design. So these are all things that the combined teams with these new data sets that we can look at in its entirety really start to think about how we optimize the program going forward. So to Nick’s earlier point, we’re not done and we think as the teams continue to work together, we’ll be able to push synergies even higher.

Operator: Thank you. Our next question comes from the line of [Kaylee Ackermann] [ph]. Your question, please, from Bank of America.

Unidentified Analyst: This question also goes to the capital budget and maybe the optics of it. I’m wondering if you can remind us how Capital Southwestern was capitalizing and then maybe offer some soft guide for interest expense in 2025. The rub here is that you guys have done a great job in grinding down that capital number, and I guess some are just trying to bridge from a previous reference point.

Nick Dell’Osso: Yes. Hey, Kaylie, I’ll start with that. Let’s start with the capitalization. We’ll be able to give you full details on how things were capitalized and what they look like under our program as we give full guidance next year. But it’s not a huge number that comes out of CapEx. It’s in the, I would say, mid to low single-digit percentages of the capital number. So then on the next point about interest expense, our weighted average cost of interest is going to be in the 5.7 to 5.8 range. And so you can take that across the debt stack and come up with a pretty good number there.

Unidentified Analyst: Got it. I appreciate that. My second one is just more housekeeping. Can you remind us how much production capacity that you currently have curtailed by basin and maybe offer any insights as to where you think the industry is? And I’ll leave it there. Thanks.

Josh Viets: Yes. Good morning. So for us internally, today we have around 200 million cubic feet a day of net gas that’s curtailed, and that’s pretty evenly split across the Haynesville and the Northeast. That 200 million a day, that’s really something that we look at day in and day out and just understanding how market conditions are going to be moving by the day and by the week, just given local changes in demand. And so that’s a pretty fluid number. And just like we’ve been in the past, we’ll be responsive to market conditions. You asked about the industry number. That’s, I would say, a little bit harder to peg down, and it’s probably something we’ve shied away from commenting on directly just because we don’t have direct access to individual companies’ data.

Operator: Thank you. And our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please.

Neil Mehta: So first question is just the Enhanced Capital Returns Framework, slide 13. Maybe you could spend some time talking about, as you evaluated all the different strategies about allocating and returning capital, why did you optimize towards this design? And how should investors be thinking about the cadence of capital returns as we get into 2025, now that you have a little more visibility through the hedging program? Thanks.

Mohit Singh: Yes. Thanks for that question, Neil. This is Mohit. Let me start by first acknowledging that the two things that we are trying to address with this framework, one is, as you said, returning cash back to the shareholders. And number two would be reducing our net debt. So when we look at the framework that you outlined or referenced on Slide 13, the first tranche of free cash flow, what we are doing is retreating our commitment to the base dividend, which we deem as sacrosanct. So that is not changing. That will be roughly $500 million per annum. The next tranche of free cash flow, if there’s any, we acknowledge that the prior framework did not do enough to bring consistent and annual deleveraging efforts into place.

So we are trying to use the Tranche 2 of free cash flow towards net debt reduction, which essentially formalizes the debt pay down. Post the merger, we have inherited the SWN debt, so we need to have a formal plan for paying down that debt. And finally, in Tranche 3, which will be any remaining free cash flow, what we are trying to do is provide a higher portion, which is 75% of that Tranche 3, as opposed to 50% before, of the remaining free cash flow, which will go towards additional returns to equity in the form of either buybacks or a variable dividend, which we will determine based on market condition. So in summary, we see this enhanced framework as a strong way to reassure shareholders that we are committed to net debt pay down while continuing to deliver shareholder assurance.

Neil Mehta: Thanks, Mo. And just a follow-up on the macro. Nick, you’ve talked about your view of mid-cycle over the years. I’d be just curious how you think about the moving pieces here as we go through ’25 and ’26. You’ve got obviously a huge LNG ramp as we go through ’26, but you’ve got global capacity on the other side. And we’re seeing power demand really surprised to the upside, but there’s a lot of spare capacity. So it feels like there are a lot of moving pieces. Curious on your views and has this enthusiasm around AI and power demand changed your view of mid-cycle to the upside at all?

Nick Dell’Osso: Yes, good question, Neil. So I would say, first thing, I very much agree there’s a lot of moving pieces. And what that means to us is there will be volatility. I think you touched on the key moving pieces, which are that LNG demand or LNG export capacity is growing rapidly. Exactly how that demand manifests itself with a call on U.S. gas as a function of demand internationally as well as competing supply internationally, those two things will continue to move around. Demand domestically is clearly growing and growing faster than I think a lot of models were predicting, I’ll say, one to two years ago in the form of power generation. So that’s a pretty encouraging sign. A lot of the power gen around AI is going to take several more years to develop.

And so we expect that trend to be structural and long-term and provide a pretty important tailwind. The only other thing I would comment on in that macro picture is that currently and continuing through, we believe, at least most of 2025, we’re going to see supply be flat to down. Right now, at this very current moment, you’ve seen supply tick up over the last actually just few days, but through October, end of October, it’s pretty common to see volumes tick up as people have managed their capital allocation for the year to bring more volumes on during the winter. It’s something I think the industry has done a better job of aligning production with demand around winter weather. So that’s not a surprising trend to see. But if you think about the rig count that we have for gas in the lower 48, it’s down quite a bit, and it’s not positioned to grow.

The only offset being Permian will grow as Permian has capacity in transportation. We saw the Matterhorn pipeline come online in October. It is filling up. It is not quite full yet. So we will see that capacity fill over the next several weeks and maybe months. And then after that, I think you see limited growth in the Permian until the next big pipe comes online. And you see the capital allocation around dry gas and rich gas areas driving production to be flat to down. And we don’t see a rig count change in the immediate future, given that the forward strip really doesn’t encourage growth for anything that has a break-even anywhere around $3. You’re kind of right there. So I think you’re seeing the industry show some discipline around how we allocate capital and learning from cycles and the trend that we believe we’re observing is that supply is going to be flat to down and probably remain that way until you see a rig count change, which then has quite a lag time to it.

So the dynamics for supply-demand fundamentals for gas are very strong. We are terrible predictors about when that shows up. Winter weather will have a huge impact on the timing of when supply and demand come together to change the character of the strip, but we definitely see it changing sometime in the relatively near future.

Operator: Thank you. And our next question comes from the line of Nitin Kumar from Mizuho. Your question, please. You might have your phone on mute.

Nitin Kumar: Obviously, there’s a lot of things we’re trying to unpack with the long-term efficiencies here. So sorry to ask this, but in 2025, you’ve said $2.7 billion. And I think, Nick, you mentioned long-term in 2027 when all the synergies are under your belt, it’s about $2.8. Can you help us bridge the gap in 2026? You should still have some DUCs by our math, but also you should probably be adding activity. So how does capital trend between 2025 and 2026 and 2027?

Josh Viets: Well, yes, it’s a good question, Nitin. I’ll take that. Clearly, we’re going to have some benefits heading into 2026 from the DUCs as you indicated. And so, of course, we’ll be drawing down that DUC capacity as we head to the end of the year. So you are leveraging some of that productive capacity even in 2026. As you mentioned, we’ll be adding some activity back. And in fact, included in the 2025 plan, we start adding back a little bit of rig activity, which is accounted for in the $2.7 billion. So you’re going to be exiting 2025 at around 12 rigs. So you are assuming a little bit higher activity. But I think the other key thing to remember is that the synergy realization increases as well going into 2026. And so our expectation for the 26 capital would be that we’re in line with the $2.7 billion, maybe even just slightly below, given the realization pace for synergies.

Nitin Kumar: Great. Thanks for that color. The second part I want to maybe talk about is marketing. When you announced the deal with Southwestern, you had talked about the expanded scale of the company and you got the investment grade. So maybe if you can give us a little color on how the efforts to market gas to more premium price points is going. And specifically, the market’s focused on direct supply to AI data centers and power generation. Any thoughts on sort of how that market’s shaping up?

Mohit Singh: Yes, Nitin, good morning. Mohit here. Thanks for those questions. I’ll take the first one first. As I said earlier, on the M&T side, we are beginning to optimize flow to premium markets. And we’ve had some early wins, which I outlined earlier in the call. You should remember that marketing is one side of the business where due to commercial sensitivity, we could not truly get into the contractual details until the merger had closed. So we are still in the early innings. It’s October 1, the merger closed, and we are going through all the contracts and figuring out where the optimization lies. But very encouraged by the early wins that we have had on that front. On the other part of your question, which is around the AI data center power demand, so again, those conversations have been happening in the background and we are in the process of consolidating the efforts that Legacy Southwestern was doing on its end and what Legacy Chesapeake was doing on our end.

It’s fair to say there’s lots of interest from all the different stakeholders involved in that value chain, whether it’s developers, whether it’s power generation companies, whether it’s end users, and obviously the midstream and the upstream suppliers. So trying to bring the consortium together, we are having tons of conversations with all the right stakeholders, and these things take a little bit of time, but we remain very encouraged and very engaged with all the right stakeholders.

Nick Dell’Osso: Hey, Nitin. And let me just add that one of the things we really like about our portfolio is the geographic diversity that allows us to be responsive to both of these really significant trends in demand in the industry, which is growing LNG export capacity as well as growing domestic power generation, and having gas across both northeast Pennsylvania and West Virginia, Ohio areas of Appalachia, and then also proximity to the Gulf Coast with the Haynesville. We’re really uniquely positioned to respond to both. Our Haynesville gas can go directly south, it can move east. Obviously, Appalachia has its various outlets that move gas south, southeast, and then some gas that can get west as well. So we really like the setup of this business and the scale of production that we have and our ability to meet multiple markets from a company that has the financial strength to create the customer relationships for very long periods of time.

Operator: Thank you. And our next question comes from the line of Josh Silverstein from UBS. Your question, please.

Josh Silverstein: So you showed a pretty big step change in capital efficiency on the pro forma outlook, but you also were seeing this in the standalone company. I’m curious where the bigger step change in efficiency is, whether that’s in the Haynesville or the Marcellus?

Josh Viets: Yes. It’s a good question, Josh. I mean, I would say it’s pretty equitable between the two. I think both of our operating teams in those areas have done a tremendous job this year. And so we’re seeing both operational efficiencies as well as, in conjunction with their supply chain teams, capturing deflation. And so I think it’s equitable, and my expectation is we continue to see these step changes through time as well.

Josh Silverstein: Got it. And then looking back at the standalone companies before the merger, you guys had the capacity to produce over eight bcfe per day. The outlook for next year is seven. Do you see a scenario longer term where you get back to that level? Does that all come from the Haynesville, because there’s more growth there? I’m just curious how you think about the longer term production profile of the company.

Nick Dell’Osso: Yes. Hey, Josh, it’s a great question. We love the fact that this portfolio has the capacity to grow. And obviously, if there’s growth volumes, it’ll primarily come from the Haynesville. But we do have curtailed capacity across the Appalachian region right now as well. So some of that volume can come back, and then true growth can come from the Haynesville. Choosing to be at seven BCF a day in 2025 is exactly that. It’s a choice. And how and when we decide to bring volumes back is going to be directly informed by the macro conditions and seeing the market have a call for the gas that we can produce. And we expect that to happen. But we also expect there to be continued volatility. So what we’ve liked about what we did in 2024 is that we use the strengths of the company, which is our capital efficiency and our balance sheet strength, to allow for a continued efficient development capital program that did not necessarily have to tie to the immediate delivery of volumes associated with that so that we can better time the delivery of volumes to the market needs without having to ramp our capital program up and down too severely.

We expect to be able to continue that kind of decision making in the new company in the combined portfolio. And frankly, we expect to be able to do it better because scale helps, balance sheet strength helps, and you have to have an active hedging program. All of those things get better with our size and with our efficiencies of the synergies that we’re bringing together. So it’s a choice. We can ramp when and as needed. And we can ramp down when and as needed. And we have the complete flexibility to do that. And I think we’ve shown a willingness to do that probably beyond what anybody else has shown.

Josh Viets: Yes, Josh, I’ll just add on to that a little bit. I just want to kind of reinforce the production profile that we show on Slide 10. We’ve always said we want to be incredibly responsive to market conditions, and we think the plan that we’ve laid out does that. We’ll be at our low point in production at around 6.4 BCF a day equivalent in Q4. And then as we begin to activate the deferred tilts, we start to activate the DUCs, we do see a pretty steady growth trajectory throughout 2025. And of course, this is all kind of predicated on our view of the market today. But most importantly, just want to point out as we’re exiting 2025, we anticipate being above 7 BCF a day, we’ll be around 7.2. And you know, that’s a number that not saying we’re going to hold that flat, but it’s really just pointing to the fact that we do have some underlying growth occurring.

And we think it matches fairly well, the demand trends that we see showing up throughout the course of the next 12 months.

Operator: Thank you. And our next question comes from the line of Charles Meade from Johnson Rice. Your question, please.

Charles Meade: Nick, I want to go back to, you’ve talked a lot, you’ve got a lot of questions on the capital efficiency and the progression. And it makes sense because as positive as your ’25 guide is for CapEx, I think that the bigger surprise to me, and I think to a lot of people is the 2.8 number for 2006. I wanted to ask you, maybe ask you a question along these lines, but from a different angle. If I look at Slide nine, and this goes back to a comment you made earlier in the year, where you talked about ’24 investing in working capital. And if I look at that, I look at your DUC and your tilt count there for 4Q, I recognize those are gross numbers, but it looks to me like you kind of have up, on a net basis of working capital, kind of unproductive working capital or investment of working capital, about 800 million at year end.

And so, maybe you roll off 500 of that in ’25, and another 300 million in ’26, as you know, you talked about, I think Josh talked about this earlier, where you get the benefit of the tilts in ’25 and the DUCs in ’26. But still, even though you’re rolling in synergies, still, at least to me, in this framework, it looks like your longer term sustainable CapEx is actually something north of 2.8, more like 2.9 or 3. So is that a fair framework? And if it is, what am I missing there?

Josh Viets: Well, yes. Hey, Charles, I’ll take that. One of the things I just need to remind folks is that we have layered in synergies. And it’s just important that as we work out throughout 2027, that those synergies start to show up in a more way, a more heavy way. And though the synergy today is going to be probably more geared towards, the P&L, specifically G&A, as you work out over the next three years, you become more efficient from a capital standpoint. And it’s really those capital efficiencies that start to help and support the 2.8 number that we’ve rolled out yesterday.

Charles Meade: Okay. Okay. Thank you for that, Josh. And then one other question. There was a transaction announced this morning on Northeast Marcellus, where you guys are an operator. And to me, that looked like a pretty attractive price to the seller. But I’m sure you guys were paying attention. But I wondered if you could just offer any comment on how involved you were in the process or whether or your thoughts on the valuation or anything you’d like to share there.

Nick Dell’Osso: No, we don’t really have anything to add to that. Obviously, we’ve been pretty focused on getting this merger closed and working on delivering the synergies that are in front of us today, which is our top priority.

Operator: Thank you. And our next question comes from the line of Leo Mariani from ROTH. Your question, please.

Leo Mariani: I just wanted to follow up a little bit on the comments around maintenance CapEx here. So I think you guys are kind of saying that the 2.8 billion is more kind of related to the 7 bcfe per day here. I wanted to see if maybe we could get any kind of sensitivity around that. For example, if the production eventually grows to something more like 7.5 bcfe a day, would you have a maintenance CapEx level kind of associated with that?

Nick Dell’Osso: Yes. We’re going to hold off on giving anybody an exact number to tie to what future production profiles would look like. Obviously, if you’re going to grow volumes up to 7.5 BCF a day, you’d spend a little bit more. But we still think it should be in the neighborhood of 3 billion-ish, all else equal. Of course, when you get to that point, probably all else will not be equal. So it’s really hard for us to give you an exact number. But the efficiency here holds, and we’re really pleased with how it sets up. And we know we have the ability to grow this production profile when and how we choose.

Leo Mariani: Okay. I appreciate that. And I just wanted to ask you guys on the debt reduction target. So I think you guys are talking about a 1.1 billion debt reduction by the end of 2025. I’m just curious, does that number include, I think Southwestern had around a $500 million revolver balance, I think you guys paid off roughly at the close of the deal. I’m just trying to get a sense if that’s included in the 1.1, which I guess would imply maybe an additional $600 million next year. Just trying to understand how the debt gets paid down here.

Mohit Singh: Yes, thanks for that question, Leo. This is Mohit. So let me give you a walk. From the Chesapeake side, we had roughly a billion dollars of cash on hand. You’re correct that Southwestern at closing had $585 million drawn on the revolver. And that was all repaid in full and that credit facility has been retired and paid off. We also inherited $126 million of cash that Southwestern had on the balance sheet. So that also comes into play. When you think about forecasting what will happen into 4Q, we’ll pay the employee severance costs, we’ll pay the transaction costs, we’ll pay the dividend, which is paid out in 4Q. And when you factor all of that in, we predict that we’ll end the year of 2024 with roughly $200 to $300 million of cash in hand.

To your other point, we have the SWN 5.7% note coming due in January 2025, so it’s redeemable at par. We’ll utilize some of the cash on hand to redeem it at par somewhere along the course. But the good number to keep in mind would be $200 million to $300 million of cash end of the year.

Operator: Thank you. And our next question comes from the line of Michael Scialla from Stephens. Your question, please.

Michael Scialla: I wanted to see how the ’25 plan might change in a downside case if we had a mild winter, market remained oversupplied. Would you hold off on bringing the deferred tilts back online, or how do you weigh that against holding off on spending the capital on the DUCs?

Nick Dell’Osso: Yes, we’d certainly look to hold back on volumes in one way or another, either by spending less money in 2025 or holding back on the deferred activity from 2024, probably some combination thereof. What we don’t want to do is continue to add to our deferred activity balance. So if we are not wanting to see volumes increase from these levels, we’ll be pulling back capital at the same time. But now we have tons of flexibility and ready to be completely responsive to the market.

Josh Viets: Yes, and, Michael, I’ll just maybe add on to that. The other thing that the plan is reflecting is we’re going from 12 to 10 rigs in the first quarter of the year. And, again, that decision is really around the fact that we feel the productive capacity that we’ve built is just simply adequate, and we don’t want to add on to that. And so as we work down the DUC inventory throughout the course of the year, what we’d assumed in the plan and included in the $2.7 billion is starting to add rigs back in the second half of the year. And, of course, in a weaker environment, we would just simply choose not to add those rigs back.

Michael Scialla: That makes sense. Okay. And then, Mohit, you walked us through Slide 13 on the new Enhanced Capital Returns Framework. I wanted to see, as things stand right now, how you’re thinking about buyback versus variable dividend, just given where the stock price is today.

Mohit Singh: Yes, thanks for that question, Mike. That’s something that we constantly monitor. You can imagine we were restricted until the transaction closed. But now that that’s behind us, that’s something that we constantly, as I said, re-evaluate. You should think of it in terms of where we are in the cycle, right? So if you are in the up cycle, the prices are higher, the business is generating a lot more free cash flow. And we like the variable dividend in that scenario because it introduces some element of rigor and discipline in terms of distributions back to the shareholders. And conversely, when you’re in the down part of the cycle, which is where you can expect there to be some dislocation in the stock price versus where we think the intrinsic value is, then maybe that’s the time to be more proactive on the buyback.

When you put the two things together in an up cycle, maybe you’re doing more variable dividends. In a down cycle, maybe you’re doing more buybacks. And blended between the two of them, you’re kind of delivering something which is less volatile and more even for the investors. But that’s roughly how we think about it. There’s obviously quite a bit more detail around it, but that’s how I would describe it at a high level.

Operator: Thank you. And our next question comes from the line of Geoff Jay from Daniel Energy Partners. Your question, please.

Geoff Jay: My question is kind of on the 2.8 maintenance CapEx that you threw out there. What sort of activity level does that contemplate in terms of rig count? In other words, I know you’re going to 10 in the first quarter. You take it back to 12 fourth quarter. Does that 2.8 contemplate like 12 or you go back to the 14 you had in the third quarter, just kind of trying to understand what the initial thought there is?

Josh Viets: Yes, Geoff. We would expect that 2.8 billion number that we’d be averaging in and around the 12 rigs.

Geoff Jay: Okay, great. And then maybe to take the inverse of some of the other questions, what would you have to see in terms of market conditions or future strip to bring back those two rigs you’re dropping quicker?

Nick Dell’Osso: Well, I think it’s just all about the fundamentals, Geoff. I mean, we’ve talked all year about how we have looked at the decision to defer turning lines and defer completions and pointing to the fact that it’s not just about a price on the screen. It’s about really looking at a number of different measures that we think are indicative of the underlying fundamentals of the market. We really want to see that the market needs an incremental volume. And when we believe that the market needs incremental volume, then we believe that bringing volume back should provide a more sustainable economic benefit to us. What we don’t want to do is see a very short-term spike in price, respond to that, try to bring activity back, know that there’s a much longer lag time and destroy capital in the process. So we’re really looking for the structural need for supply to be called for, and then we’ll bring activity back when we see that.

Operator: Thank you. And our final question for today comes from the line of Phillips Johnston from Capital One Securities. Your question, please.

Phillips Johnston: Just one for me to follow up for Mohit, just on the new return of capital framework and really the tranche to net debt reduction component. I think you noted the idea is to pay down $500 million annually, not just next year, but also kind of going forward as well. Should we think about the $4.5 billion net debt level target and the sub one times leverage ratio target? That’s kind of the point where you would sort of tilt the mix more towards return to shareholders once those are achieved, or would you continue to ratchet down debt with $500 million a year per year of debt payout?

Mohit Singh: Yes, thanks for that question, Phillips. So just as a reminder, the 500 number that we have laid out, that’s for 2025. That’s the number that we intend to re-peg every year. So it could be different in 2026, but at the very least, our game plan is to get the absolute debt level down to $4.5 billion, as you pointed out. And just as a reminder, the way we view that is trying to get our gearing to one turn, so at mid-cycle pricing. So think of $3 per MCF gas price. At that point, business generates around $4.5 billion of EBITDA. So we are thinking of that’s where it pegs the $4.5 billion of debt target that we have. The comfort I would give you is, we are trying to strike the right balance between trying to get cash back to the shareholders, and hence the earlier comment about them deeming the base dividend as sacrosanct, but then also prioritizing debt paydown, which is extremely important given that we have the pro forma company has higher debt than Legacy Chesapeake did.

So we need to address the debt stack that’s in front of us. And with this new framework, I think we are addressing both of those two drivers and would like to reassure the shareholders and our creditors as well that both things are a priority for us.

Operator: Thank you. This does conclude the question-and-answer session of today’s program. I’d now like to hand the program back to Nick Dell’Osso for any further remarks.

Nick Dell’Osso: Well, thanks very much. I appreciate everybody taking the time to dial in this morning. Obviously, we’ve got a lot to talk about, and we’ll be around to answer any questions anybody has as follow-ups, and we’ll be out on the road over the coming weeks to meet with many of you all in person. We could be more excited about the way that the market is setting up for Expand Energy as we get into the end of 2024 and 2025. We have our hands full with integration and achieving these synergies, but the path to do all of that, we believe, is very clear, and we’re ready to go. So I look forward to giving you guys updates on our progress as we get through next year and seeing you all out on the road. Thanks very much.

Operator: Thank you, ladies and gentlemen, for your participation at today’s conference. This does conclude the program. You may now disconnect. Good day.