EXE - NASDAQ

Good day. And welcome to the Chesapeake Energy Fourth Quarter and Full Year 2023 Results Conference Call [Operator Instructions]. Please note today's event is being recorded. I'd now like to turn the conference over to Chris Ayres, Vice President, Investor Relations and Treasurer. Please go ahead.

Thank you, Rocco. Good morning, everyone. And thank you for joining our call today to discuss Chesapeake's fourth quarter and full year 2023 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 Web site yesterday. During this morning's call, we will be making forward-looking statements, which consists 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 there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our press release and the other SEC filings. Please also recognize that as except required by applicable law, we undertake no duty to update any forward-looking statements and you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure, which can be found on our Web site. With me today on the call today are Nick Dell'Osso, Mohit Singh, and Josh Viets. Nick will give a brief overview of our results, and then we will open up the teleconference to Q&A. So with that, thank you again. And I'll now turn the conference over to Nick.

Good morning. And thank you for joining our call. We continue to execute on our strategic pillars in 2023, proving we’re a company built to deliver sustainable value to shareholders through cycles. The Marcellus team had another strong year with well cost improving 17% since Q1. We increased our footage drilled per day by 40% and drilled nine of the 10 longest laterals in our history in the basin. In the Haynesville, we delivered strong production performance throughout the year, benefiting from improved gathering system hydraulics while our drilling performance continues to outpace our peers in the most difficult drilling environment in the Lower 48. Importantly, we accomplished these operational milestones while improving our total recordable incident rate by 40% to an industry leading 0.14 injury rate. Additional highlights for the year include; returning approximately $840 million to shareholders via dividends and buybacks; advancing our path to be LNG ready by securing HOAs up to 3 million tonnes per annum linked to JKM and recently signing an LNG sales and purchase agreement with Delfin and Gunvor for long-term liquefaction offtake; completing our Eagle Ford exit for a total consideration of greater than $3.5 billion and receiving credit upgrades from all three agencies and exiting the year with a cash balance of approximately $1.1 billion. Turning our attention to 2024. We started the year by announcing our shareholder value driven merger with Southwestern. Our combined company will accelerate America's energy reach by accessing more markets, effectively mitigating price volatility and ultimately increasing the revenue per unit of the product we sell. We are very encouraged about the growth and long-term demand for natural gas, the affordable, reliable, lower carbon energy the world needs. Today, the market is clearly oversupplied. In addition, we see capital supply cycles that can take 12 to 18 months to evolve while demand fluctuates quarterly. While we will benefit from a strong hedge position, we are responding accordingly with our 2024 capital and operational plan. First, we are reducing capital by nearly 20% and production approximately 15% from the preliminary outlook we provided last quarter. Under our revised capital program, we plan to limit our turn-in-line count to 30 to 40 wells with the majority having already occurred in January and February, drop two frac crews, leaving one frac crew in each basin and drop two rigs, resulting in four rigs in the Haynesville beginning in March and three rigs in the Marcellus beginning midyear. We believe limiting turn-in-lines and building DUCs is the prudent response to today's market. Doing so will shorten our cycle of supply to appropriately and effectively meet market demand. This results in shorter cycle capital efficient decisions that will ultimately offer incremental capacity of up to 1 Bcf per day by the fourth quarter, ensuring we have ample supply to provide customers when demand recovers. Ultimately, our plan is designed to maintain productive capacity which positions us to quickly return to over 3 Bcf per day with minimal incremental capital investment. We will be prudent in our approach, bringing production back online efficiently as consumer demand warrants. Overall, our 2024 program demonstrates Chesapeake's continued focus on capital discipline, operational efficiency and free cash flow generation, while building the capacity to consistently deliver for consumers and shareholders through all demand cycles. Simply put, Chesapeake is built for the volatility we are experiencing today and our strategy is positioning the company to thrive as the market rebalances into 2025. We have the portfolio, balance sheet and demonstrated operational track record to continue driving capital efficiencies, maximizing returns and reducing risk. I look forward to updating you on our progress throughout the year. And we're now pleased to address your questions.

[Operator Instructions] Today's first question comes from Josh Silverstein with UBS.

So I wanted to start just on the game plan that you guys have outlined here. The 1 Bcf a day reduction in this plan, was this a function of the base declines that you have with the lower rig count or asked another way, what are the other kind of iterations that you guys came up with for the outlook?

So I want you to think about the production decline that we're seeing today as a function of the base decline, because what we're really doing is we're just stopping turn-in-line wells that we have had in progress. And the reason we're doing that is that we see that the market is oversupplied right now. CapEx reductions that we and anybody else in the industry take on have an impact to production several months out as long as 12 months out. And we need to -- for our business, we believe the right answer is to reduce production today. The market is oversupplied today, the value that you would receive for turn-in-line wells today reflects the fact that the market is oversupplied. And so we think we should hold on to that productive capacity and then turn it in line when there is greater demand and when the market is not oversupplied. This allows us to be responsive quickly. And so that that amount of production that we've quoted is really just to give you a sense of how much productive capacity we would build up to be responsive to the market as the demand is there by the end of this year. We quoted it as a Bcf a day if all of those wells were turned in line in one quarter. Now that's probably not a very realistic answer. We would probably layer those in. We would assume that demand would come back in some measured fashion and therefore, we could return production in a measured fashion. But that would be the aggregate volume that would be sitting and ready to respond.

And then just given the volatility in natural gas prices you've seen over the past couple of years, do you think you'd want to operate with a backlog of wells going forward? This way you could respond to the changes in price environment, your balance sheet and interest rates can afford that. So I'm curious how you're thinking about operating going forward?

I think the fact that we feel comfortable pausing -- turn-in lines and slowing completions activity, slowing drilling activity to match that cadence should be considered as we would also be comfortable accelerating those cycle times in the future when needed. Really, all we're doing here is we're extending cycle times of past capital that's been deployed. We would have the flexibility to increase those cycle times in the future if market conditions warranted and deliver more production on a shorter period of time relative to the dollars that we're spending. So we like the flexibility in our business. And then at some point, if the market proved to continue to be undersupplied in the future, you could add capital and grow your productive capacity beyond where we sit today. But this change is really designed to maintain productive capacity in that neighborhood of 3.2 Bcf a day, you should consider maintenance capital of $1.5 billion to $1.6 billion around that level of production. All of that remains unchanged for the business that we're presenting to the market today. We're just allowing cycle times to expand out, allowing our base decline to reduce the oversupply that we see today, which would cause us to receive a very low price for our gas. And to hold on to that production for a time when the market needs it better and we can better deliver it where customers need the gas.

Our next question today comes from Charles Meade with Johnson Rice.

I want to actually continue along that kind of line of questioning. And you've already given us a lot of insight here, but this -- what you're laying out here is a new approach from what we've seen or at least from what I've seen over the last several years in the industry, not just building DUCs but also building TILs. And I'm wondering if you can elaborate a bit on -- recognize that this is a little bit terra incognita, but elaborate a bit on how you're thinking of the sequence of spending money on DUCs versus bringing TILs online. And I can think of at least a couple of different ways it might go. I don't expect you'll give us a price at which you act, but maybe you'll surprise me on that. But I could imagine one scenario where you would just -- when you got to the price you wanted you would just bring your TILs online and then you backfill with the DUCs. But I could also imagine the scenario where you guys are still running a completion crew and you don't want to bring wells online, and so you actually work down that DUC inventory ahead of time. So can you just elaborate a bit on how you're dealing with these kind of novel pieces that you now have on the board?

I'll start and Josh may have something to add here. But the way we're thinking about this, Charles, is we will be paying very close attention to the underlying fundamentals, the underlying supply and demand situation in the market. And we'll try to bring gas online when we see that there is demand that needs the gas. Today, we are filling storage or not drawing from storage at the levels consistent with the past, which is setting us up to have pretty full storage going into the next storage season next fall. And so we can see very clearly that the market has more supply today than there is demand on an annualized basis. And so we think we should hold back our supply to better meet that demand in the future. We know that demand will grow in the future. We have confidence in that and we believe we should be more efficient with the capital we have spent, the wells that we have in cycle and the wells that we will continue to have in cycle. And so this really is about making sure that we are continuing a business from a capital perspective that is efficient at drilling wells, is efficient at delivering productive capacity, but that we can then have the flexibility to hold that production for the times that it's better needed. I want to reiterate that we are pretty optimistic about the future for gas markets and this allows us to better deliver production when it's needed, where it's needed into those markets as demand is present and ready for it.

I think just the other thing I would comment on is we're going to be very prudent around how we activate production. And the optionality that we like about the deferred TILs is that it gives us an immediate response when we see that structural change in the gas markets. And so we would anticipate that we would start to activate the TILs and then we would likely soon after begin starting to activate some of the DUCs. But one thing to keep in mind is that any production associated with those deferred completions is effectively going to lag by a quarter. And so we do see that as effectively starting to backfill the TILs that we're starting to activate in the prior quarter. So we really like the cadence that is set up by this. And again, we think it offers quite a bit of flexibility for us going forward.

And then my follow-up, it looks like to us like on a pro forma basis, like 20% decline, '24 versus '23, and that's a little bit higher than I would have guessed. And Nick, you may have given part of the answer already with the majority of your TILs for the year already haven't happened. But I'm wondering, is there also perhaps some kind of elective production restriction in there maybe through deferred midstream projects, or is there anything else that is contributing to that decline beyond just the pause in TILs?

No, really the decline is being by the deferred TILs. You have a material amount of production that we're simply choosing not to enter into the system. And so that is ultimately what's leading the decline. And so what you see on a year-over-year basis or if you want to think about it from Q4 to Q4 is effectively the underlying base decline of the assets that we operate today.

And our next question comes from Matt Portillo with TPH.

Maybe Nick, just starting out at a high level, I just wanted to come back to the philosophical view on the capital allocation cut here. Looking at your hedge book that you have in place, it looks like your breakeven could have been justified on maintenance capital at a very low gas price in 2024, and you've obviously taken a very decisive step here to help correct the market from an oversupply perspective. Just curious how the team arrived at that decision and how this may kind of play out in regards to your views on return on capital and how you might think about adding back to the market in '25 and '26 as it relates to production?

Let me start by saying we don't view this change as something that we are attempting to fix the market. We view this as what we think is prudent to manage our assets, our ability to generate cash flow for our shareholders, and that's really how we think about this, one company is not positioned to fix the market. And so we're really thinking just about what makes sense for our company and our shareholders each day. From a hedge perspective, we always separate hedges from the decision to deploy capital. Hedges are really about how you've deployed capital historically, there are financial protection, they're available to you for paper gains and losses. And there's no need to mentally tie hedges to the production that we deliver to market each and every day. So said in another way, because you have hedges should not divorce you from paying attention to supply demand fundamentals that are in front of you and impacting the price you receive for your physical product that you sell every day. And so the decision that we've made today is 100% about having a productive capacity that we have spent money on throughout 2023, looking at the market today, recognizing that the market is pretty clearly telling us that it doesn't need our gas today and knowing that we have the flexibility to hold off on delivering that gas to the market until such time that there is higher demand. So we're happy to do that. We did run a lot of different scenarios and thought about different changes to the capital program. We certainly thought about reducing the capital program in a more significant manner than we are here today. And what that really results in is bigger changes to 2025 production. And we don't believe that's prudent given the fundamentals that we see today. We expect there to still be a step change in demand in 2025 as incremental LNG capacity comes online, as the market continues to grow for natural gas domestically. We also think the supply dynamics would be better by 2025. Remember that there's a lot of capital cut across the industry last summer. And the results of those capital changes just haven't shown up yet. That's why I referenced in my opening comments that we see the cycle of capital and supply being as long as 12 to 18 months. Think about the fact that this past fall is when we really saw maximum supply to the market, we're really still seeing it today. And the CapEx increases associated with that supply response started in the fall of -- well, really in the summer of 2022 and carried through the beginning of 2023 with the big reductions in capital not occurring until the summer of 2023. So the lag time of CapEx decisions is very long. And what we're really attempting to do is be responsive to the market conditions that we see in front of us today knowing that a capital decision has a much longer time to take effect. So stopping, turn-in-line wells has an immediate impact on the economics that we see for our resource.

And then maybe as a follow-up question for Josh. Just curious how we should be thinking about the outlook for 2025? I know it's still a long ways off. But trying to think through how long it might take you to get back to more of a maintenance program as it relates to your rigs and your frac fleets? And then effectively, is it still fair to think about the timing being from about six months from when a rig hits the ground to when we should be expecting production to turn-in-line? I know you've got, obviously, the deferred TILs. But just thinking about kind of the base program, how that might progress over the next 12 to 18 months and what we need to see maybe fundamentally to start to pick back up towards the maintenance level on the base program?

First of all, I mean, we clearly are looking for structural shifts in the demand side of the equation for us to be thinking about getting back up to some maintenance level of activity. But I think the way, again, that we would likely start to phase in activity is starting to activate our deferred TILs first. We then begin to activate our incremental frac crews, which would take us to a total of four frac crews across our business today, and then in the way we would think about any additional rig additions. So again, as we go down from five to four rigs in the Haynesville and then from four to three in the Marcellus is as we start to deplete the deferred completion inventory down to something that we would consider to be a more normal working level, we would then start to bring those rigs back. And you're absolutely right. As far as kind of a typical cycle time, you are looking at roughly six months from the time you add a rig to actually start seeing any meaningful production impact from those rigs.

And our next question comes from Nitin Kumar with Mizuho.

I guess I want to start off, Nick, and just as you came up with this framework, to us, it looks like you're maintaining the balance between the Appalachia and the Haynesville, both of them are declining roughly about the same percentages and the mix stays the same. Would it not have -- why that sort of allocation across the two assets, would it have been maybe better to reduce the Haynesville a little bit faster? Just any color around that.

Well, just keep in mind that pricing is different in both of the assets. And so certainly today when the market is oversupplied, you're receiving quite a low value for gas and the Marcellus storage is quite full in the Northeast. And so we do see it prudent to reduce turn-in-lines in both basins to what is something pretty close to zero for the rest of the year. Good news is we can change that quickly if the market changes and shows us that the gas is needed and we can change that by region, if there is a shortfall or improved market in the Northeast, we can change that separate and apart from the Haynesville. So we maintain full flexibility but we just see pretty similar market conditions in both places right now.

And then for my follow-up, you mentioned that one company cannot fix the market, but you're about to become much bigger somewhere in the second quarter. The size of this deferred TIL inventory that you're holding, I know you can't comment on Southwestern's plans. But is this the right size for just Chesapeake or do you think this could be the right size for a combined company down the road?

We're just thinking about Chesapeake here.

And our next question comes from Bert Donnes with Truist Securities.

I just wanted to follow up and clarify one of your previous comments. Is there a limit to the amount of DUCs you would build if we see a prolonged down cycle, maybe the 1 Bcf is kind of the limit maybe like that amount as you saved up ammo or would you start dropping rigs immediately in ‘25 if we saw sustained down cycle?

That was part of our rationale for why we wanted to start taking rigs out now. You get to a certain point with DUC inventory where it simply starts to look and feel like inefficient use of capital. And so that's why we'll be dropping a rig next month in the Haynesville and then another rig in the Marcellus in July. So that is absolutely a consideration for us as we think about the allocation of capital to rigs and frac crews.

And was it a DUC limit or was the amount of production, the limit? It just seemed like a nice clean number at 1 Bcf. So I didn't know if that was kind of the solver for it or whether it was how many -- the way your rig frac crew would play out?

I mean we clearly looked at both. But we really just tried to balance what we thought was a meaningful amount of production that we could activate with an efficient use of capital going forward. So there was simply a balance that we try to strike between the two.

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?

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.

And our next question comes from Doug Leggate with Bank of America.

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?

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.

So we shouldn't think that there's an implicit reset in sustaining capital now that the Eagle Ford has gone.

No, we don't see that.

My follow up is…

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.

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?

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.

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?

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.

And our next question today comes from Paul Diamond with Citi.

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?

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.

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?

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.

Our next question comes from Michael Scialla at Stephens.

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?

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.

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?

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.

And our next question comes from Ati Modak with Goldman Sachs.

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?

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.

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.

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?

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.

And our final question today comes from Phillips Johnston with Capital One.

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?

I think that's a good safe assumption, Phillips.

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?

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.

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.

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.