Bert Donnes: And then I’ll shift gears to stop hammering that point. I’m just trying to understand the buyback activity in 4Q. Was that cut short due to the merger announcement or would there have been kind of a similar amount, even if you didn’t enter a blackout period? And maybe if you could reconcile that against the cash, free cash flow being technically negative in 4Q, yet you still had some activity?
Nick Dell’Osso: Look, we were really comfortable executing our buyback throughout 2024. Obviously, once we got deep into the merger discussions that activity had to pause. We are not able to restart that activity while we have a pending transaction like the merger out there. So in the future, we’ll be back to buying back stock when we can and look forward to that day. But I’d just remind you that inclusive of buybacks and dividends in 2023, we had a 8% return to equity, pretty robust, and we felt good about that number. And I guess it’s a fair statement to say that if we weren’t engaged in those discussions we probably would have continued to buy some stock through the end of the year.
Operator: And our next question comes from Doug Leggate with Bank of America.
Doug Leggate: Nick, the markets just opened, the gas stocks are all up, gas prices are up 17%. I just want to see strong message and taking leadership like based on how to navigate this is something I think the rest of the industry could pay attention to. So well done on that. My question is two things kind of related. First, you are still spending $1.3 billion this year. But the way I look at it is — or the way you look at it, I should say, you’re putting in place by the end of the year, a Bcf a day of spare capacity about a 30% decline. If I simplistically add those two numbers together, the exit rate, call it, 2.2 plus 1 Bcf, you’re pretty much back to your maintenance kind of level, but you’re doing it — or production, but you’re doing it with a substantially lower capital number 1.3 versus what you tell us is 1.5 to 1.6. What am I missing?
Josh Viets: Doug, I mean I think the key element to that is in order to then to sustain that, I mean — and again, assuming all of the production comes on in the fourth quarter and you’re back at that 3.2 to 3.3 level, we need to get back on a pretty normal cadence of maintenance activity, which includes completing, say, 15 to 20 wells a month and then ultimately getting back to having five and four rigs between the Haynesville and Marcellus. So the key there is we can add the production back and then we need to be deploying the capital at a maintenance level in order to support that going forward.
Doug Leggate: So we shouldn’t think that there’s an implicit reset in sustaining capital now that the Eagle Ford has gone.
Josh Viets: No, we don’t see that.
Doug Leggate: My follow up is…
Nick Dell’Osso: I would add, Doug, we did say in our opening comments that we’re continuing to see some good capital efficiencies across the assets. We had record wells drilled in both the Marcellus and Haynesville. We continue to focus on capital efficiencies across our assets and generally, we find that these times when you reduce activity or when you make real progress. And so we’re looking forward to 2024 being another very strong year from a capital efficiency standpoint, continuing to improve our pace of drilling, our cost per stage of completions and our overall effectiveness at bringing wells online for the maximum productivity for that given location at the lowest possible cost.
Doug Leggate: And obviously, I know you don’t want to talk about Southwestern, but presumably, this would be the strategy for the combined company. Fair point?
Nick Dell’Osso: Well, I mean, again, when we think about the decisions we’re making for capital allocation for this year, it has nothing to do with our merger. This is just simply looking at the productive capacity we have today, the market conditions we see in front of us, making the best decisions we can make for our shareholders. Now the concept that a company with a very strong balance sheet and a large production base can basically use the turn-in-line cadence available to us much the way that we would use storage if there was more storage available in the market is a strategy that I think could be deployed in the future and we would look forward to considering those opportunities. But our hope is that by the time you get to 2025, you have a step change in demand.
We see growing demand for gas. We will be in a position to continue to deliver the most efficient, lowest cost gas we can to the market as quickly as we possibly can to a market that needs it. We think that’s the more likely future for us.
Doug Leggate: My follow-up is a quick one. Again, to the extent you can speak to this, Nick. You haven’t had an FTC request, a second FTC request, I should say. You’re still talking notionally about second quarter close. If we look at everything else going on in the market, one would assume that you’re probably going to get a second FTC request. My question is, does that have any impact on integration planning or does that go ahead anyway?
Nick Dell’Osso: No, we’re well into the weeds of integration planning at this point. We have a tremendous amount to work on, very busy. We have teams that have been set up and working through how to think about a pro forma organizational structure, all the business processes, all the IT systems, all of the things that you plan for. We will be ready for a quick close. We can continue to work on things from an integration standpoint. If it takes longer, we won’t let that distract us or bother us in any way. We’re well into the work required for a successful integration.
Operator: And our next question today comes from Paul Diamond with Citi.
Paul Diamond: Just a quick one on the kind of more of the operational side of those deferred TILs. How should we think about any potential movement just on the type curves, whether it’s increased pressure bleed or maybe increased saturation. Do you guys anticipate those type curves looking any different from just normally completed wells and normally tied wells?
Josh Viets: No, we don’t. We’ve been operating these assets for well over a decade. And so we have a lot of experience being in a situation where we had to defer completions and in this case, defer TILs. And actually, through the years, we’ve seen some benefits to this where we simply see the water and dive into the reservoir. And so as we start to reactivate the production, we see similar gas productivity but less water production which, of course, is beneficial from an operating cost standpoint. So no, we do not anticipate any change to type curves.
Paul Diamond: And just kind of circling back on one of the comments from the prepared remarks, just talked about a 70% well cost improvement in Marcellus. Just wanted to see how you were thinking about the progression of that, whether there’s more meat on the bone or I guess how much — what your guys’ internal target is for how much more you can improve things out there?
Josh Viets: I mean, the teams have done an unbelievable job this year really across the whole company, capturing efficiencies. We quoted there a 40% improvement in our footage per day. On top of that, starting in the fourth quarter, we are starting to see some deflationary elements start to show up in the cost with the biggest mover being on the OCTG side, which has come off for us around 40%. So we do think there’s some tailwind coming into the year. We guided at the end of last year to around a 5% to 7% deflation from kind of year-over-year levels. We still feel pretty good about that right now. We’re anticipating the Marcellus to be around 10% year-over-year cost improvements, which is a combination of deflation, extended laterals, which were going to be up about 15% or so and just execution efficiencies that we see showing up in the system. And my expectation is we continue to get better as well and we start to see costs beyond that 10% that I’ve quoted here.
Operator: Our next question comes from Michael Scialla at Stephens.
Michael Scialla: Nick, you mentioned you probably wouldn’t bring back the 1 Bcf per day in any given quarter. But if you do get the step change in demand that you’re anticipating, how quickly could you bring that Bcf per day online? Does it take a full quarter or is it something less than that? And are there any infill constraints or anything that you need to be thinking about there?
Josh Viets: There’s going to be some operational considerations as we start to reactivate the production. It’s just simply logistics planning around managing gas, coming into gas gathering systems and water. And so we think that over the course of weeks, if not months or a quarter, it’s over a matter of weeks, so say, month. We think we can start to reactivate that production. But I’d just remind you, we’re obviously going to be monitoring the markets in each of the basins, though they are very different, they have different market dynamics. And so it could be that we start to phase in TILs in one area and not the other with that may be lagging behind. And so I think there’s just a number of considerations. But the teams are well prepared to manage this type of activity and anxious to see what they do with it.
Michael Scialla: And just a follow-up to that. With the reduction in volumes you have, are there any commitments with momentum or any other pipelines that will come into play that you need to keep an eye on?
Mohit Singh: So the way you should think about momentum pipeline, the volumes that we have committed there, which is 700 million a day, is essentially volumes that we would read out from existing pipelines. So this is not a volume that we are growing into and that’s just altering the flow path and moving volumes around on the pipeline network. So it doesn’t really constrain us or put any restrictions on us with regards to how we grow it. So you shouldn’t really worry about that constraint.
Operator: And our next question comes from Ati Modak with Goldman Sachs.
Ati Modak: Just curious if you can provide any color on how you are thinking about the deleveraging plan given where the strip is, and what that means for free cash flow this year? I know you have cash on the balance sheet. But is there a minimum cash you would like to retain through the year as you go paying down debt?
Nick Dell’Osso: I’ll start and then Mohit may have more to add here. I just would reiterate that as a stand-alone company, we don’t have a debt reduction target. And so as we think about our 2024 plan, we’re very, very comfortable with all of the decisions we’re making and the very strong balance sheet we have, frankly, with and without these decisions being made. That said, pro forma for the close we will be very focused on debt reduction. One of the reasons we find ourselves in the position we’re in today, which is to be able to be a very efficient consolidator, in a merger context with Southwestern, to be able to have the capital flexibility we’re showing with how we’re directing our production cadence this year, all relates to having a very strong balance sheet.
It will be a top priority of this company to maintain a strong balance sheet through these cycles. And we see that being absolutely front and center for our strategy and something we expect to deliver on regardless of the market conditions.
Mohit Singh: The only thing I would add to that is coupled with a very strong hedge book and $1.1 billion of cash that we have on hand, it’s a pretty strong balance sheet. So from a leverage point of view, we feel pretty comfortable. And then when you start looking at the maturity profile of the debt that we have also, so there’s no near-term maturities, which are coming up. So as a stand-alone company, we are pretty comfortable with where we are. And as Nick said, once we are post close with Southwestern then we’ll have a slightly different approach.
Ati Modak: And then with the activity and production guidance you’ve given, how should we think about the cadence of production through the rest of the year? It sounds like it could be a steady quarterly reduction, but any color you can provide there if it’s going to be a step change or steady? And then also help us understand what the cadence is between the Appalachia and the Haynesville assets?
Josh Viets: Maybe just kind of address the second question first. Really, at this point, that’s just undetermined. Again, there’s different market dynamics between each areas. Each of the assets have different cost structures that’s going to guide that ultimate decision on how we restart tilting wells or activating completions. As far as the production cadence, again, we stated that we’ll have 30 to 40 turn-in-lines for the year. We’ve already turned in line 25 of those. And so as a result, we are anticipating quarter-over-quarter decline. And as we look at kind of Q4 of ’23 to Q4 ’24, we see that equating at a corporate level to just under 30% with Haynesville being slightly above that and Marcellus being slightly under 30%. So it will be a pretty steady decline.
Operator: And our final question today comes from Phillips Johnston with Capital One.
Phillips Johnston: I appreciate your comments, you can’t really speak for Southwestern. Just wondering from a housekeeping perspective when you guys plan to provide pro forma guidance that includes the impact of the deal. Is that a — is the timing there probably around when it closes?
Nick Dell’Osso: I think that’s a good safe assumption, Phillips.
Phillips Johnston: And then, Nick, I’d be curious to hear your high level thoughts just on the administrations all on the LNG front and what you think that might mean for the long-term gas market?
Nick Dell’Osso: We are still really optimistic on the long-term gas market. And that’s just based on the underlying view that natural gas is the most efficient answer to energy supply challenges around the world. Those supply challenges come from shortages or limited access to energy broadly, they come from climate concerns, they come from political and stability concerns. And natural gas is really the best answer, especially natural gas in the US is the best answer to all of those challenges. As a result, we think that the administration will ultimately find a very strong answer as they review the need for permitting approvals here. We expect that, that will be seen positively as we see it and we expect this will move on in due time.
I think it’s unfortunate. I think it’s not good for those parts of the economy that need incremental energy and need it as quickly as they can get it. This pause will slow things down a little, which is unfortunate and not great for those that are seeking incremental gas. But we have confidence that the merits of LNG export from the US will be seen by all and that approvals will be taken back up again in the future.
Operator: Thank you. And this concludes our question-and-answer session. I’d like to turn the conference back over to the management team for any closing remarks.
Nick Dell’Osso: Okay. Thanks, Rocco. Really appreciate everybody’s time today. We know that our approach for 2024 is a little bit different than we’ve been able to do in the past as a company and that we think we’ve seen from others. We think it very much addresses the challenge that is seen in the market today, which is a near-term oversupply and a long-term very structurally positive natural gas market. We’re excited about the position we’re in. We look forward to the ultimate aligning of supply and demand in the market and a recovery for natural gas broadly associated with that alignment. And we think we’re really well positioned for that. So look forward to continuing to discuss this with all of you. We’ll be out on the road at a number of different conferences and events in the next week to two weeks, and look forward to engaging throughout the year. Thanks very much for your time again today, and we’ll talk soon.
Operator: Thank you. This concludes today’s conference call. We thank you all for attending today’s presentation. You may now disconnect your lines, and have a wonderful day.
