Chesapeake Energy Corporation (NASDAQ:CHK) Q1 2023 Earnings Call Transcript

Chesapeake Energy Corporation (NASDAQ:CHK) Q1 2023 Earnings Call Transcript May 3, 2023

Operator: Good morning and welcome to the Chesapeake Energy First Quarter 2023 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Chris Ayres, Vice President of Investor Relations and Treasurer. Please go ahead.

Chris Ayres: Thank you, Andrea. Good morning, everyone and thank you for joining our call today to discuss Chesapeake’s first quarter 2023 financial and operating results. Hopefully, you’ve had a chance to review our press release and the updated materials that we posted to our website yesterday. During this morning’s call, we will be making forward-looking statements which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that 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 yesterday and in other SEC filings.

Please recognize that except as 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 will help facilitate comparisons across periods and with peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measures that can be found on our website. With me 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. I now turn it over to Nick.

Nick Dell’Osso: Good morning and thank you all for joining our call. I’d like to take a few minutes to highlight our strong quarter of execution and some other recent accomplishments and then I’ll get right to your questions. Our year is off to a strong start. We remain focused on executing on our strategic pillars through our disciplined capital program which maximizes returns and deliver sustainable free cash flow to fund our peer-leading dividend and buyback program. Operationally, we turned in line 53 wells, seeing solid productivity in both the Haynesville and Marcellus with Haynesville IP97 having improved about 8% from 2022, benefiting from new gas gathering offloads and incremental treating capacity put in place in 2022.

CapEx is slightly ahead of expectations on the heels of very strong execution from our drilling and completion teams where we drilled 3 of the 5 fastest all-time footage per day wells in the geologically complex southern portion of our Haynesville acreage position. We averaged 690 feet per day in the quarter on this acreage which is 30% faster than our closest offset operator. In addition, we’ve deployed a continuous pumping wellhead technology that enabled our teams to pump a record 36 consecutive hours on a Haynesville frac. In the face of a volatile market, we generated $350 million of free cash flow, about $240 million when adjusted for asset sales which will translate to a total dividend of $1.18 per share for the quarter. When combined with our buyback program, year-to-date, we’ve already returned more than $250 million to shareholders.

We also continue to make important progress on our path to be LNG-ready and connect our production to international markets and pricing. Our Gunvor agreement is a great example of our approach to leverage our operational and financial strengths to capture a meaningful share of the incremental LNG capacity coming online by 2025 and beyond. The agreement will ultimately provide up to 2 million tons of LNG per annum indexed to JKM, an important first step for Chesapeake. As market volatility continues to be top of mind for investors, we’re very pleased with our position at this point in the year. As I’ve said before, Chesapeake is built to thrive in this environment. This starts with the strength of our balance sheet which has only gotten stronger with the closing of our 2 initial Eagle Ford sales for $2.8 billion.

As of April 30, we have $1.2 billion of cash on hand and greater than $3 billion of available liquidity. This cash is available to fund our ongoing buyback program, under which we purchased another 1 million shares since our last call bringing our total buyback under this authorization to greater than $1.1 billion with $850 million remaining. We remain actively engaged with other parties regarding the remainder of our Eagle Ford position which is primarily in the rich gas portion of the play. We’re pleased to have recently received a Fitch credit rating upgrade to BB+ with a positive outlook. We are now at 1 notch below investment grade with Fitch, we attributed the strength of our scale, conservative financial policy and cash optionality is foundational to our continued rating improvement.

Turning to our capital program. As you saw, our capital came in on the low end of guidance as we dropped a rig in the Haynesville and a frac crew in both the Haynesville and Marcellus. Based on the midpoints of our 2Q guidance, we expect D&C capital to decline approximately 10% and natural gas production from the Marcellus and Haynesville to decline approximately 5% quarter-over-quarter. This decline was part of our plan for the year which is why we reiterated our full year capital and production guidance today. We will maintain our disciplined approach to executing our capital program in the year ahead, reducing an additional rig in Haynesville and Marcellus in the third quarter, as previously announced. We believe our financial flexibility is a competitive strength and we intend to use it.

We were built to thrive in all markets, including this low gas price environment and we continue to adjust our program as warranted by market conditions. Despite the current market volatility which we do expect to persist, thanks to the premium rock returns and runway of our portfolio, our best-in-class execution, pristine balance sheet and the added financial flexibility provided by our Eagle Ford asset sales, our confidence in the strength of our long-term outlook remains unchanged. I’d like to now turn the call over to questions.

Q&A Session

Operator: And our first question comes from Doug Leggate of Bank of America.

Doug Leggate: Nick, I want to ask you first about your comments in the prepared remarks or actually in your press release about being prepared to adjust activity. And then you just talked about you’ve kept your guidance and your CapEx guidance unchanged. So can you walk through what it would take for you to make those adjustments? I’m assuming lower activity or perhaps slow things down some, whether it be capital or choking wells or whatever, you could walk us through that? And maybe an add-on to that, what are you seeing in your nonoperated activity as well. Is there any sign of things slowing down, particularly in the Haynesville. I’ve got a follow-up, please.

Nick Dell’Osso: Sure, Doug. Thanks for the question. From an activity perspective, we’re pretty pleased with the way we’re set up right now. We’ve reduced our activity coming out of last year which has allowed production to fall a bit. We know that further activity reductions at this point really are going to have an impact on 2024. And we think it’s a bit premature to make that decision. The contango that’s present in the curve for 2024 looks pretty constructive at the moment. And if the activity reductions that are predicted throughout the market come through, we think 2024 should follow the contango that’s there, maybe not perfectly but it should be certainly more constructive than this year. So we want to maintain our productive capacity for 2024.

Now in the near term, we have a lot of flexibility in how we think about managing our production and managing our exposure to the market. First, of course, we have our hedges in place and they give us a nice cushion. But more importantly, we have a lot of decisions we can make every time we go to turn in line well as to whether or not it makes sense to turn that well in line or defer it. And we haven’t forecasted doing any of that — any further of that than we’ve already done. We’ve done a little bit through the beginnings of the shoulder season. We’ve already seen the need to curtail some volumes. We’re going to do some maintenance that we are choosing to do now in the Haynesville that will take a little production offline for a couple of months.

These are all things that are really prudent decisions to do during a low price environment and we’ll keep making decisions like that. And this is where — and again, I think the financial flexibility we have is a real strength and we plan to lean in on it and use it. And as we go through the summer, if prices are weak and it’s not productive to turn wells in line, we can choose to hold off and turning them in line. But having the activity completed, we can rely on the contango of the curve to make those decisions positive from an NPV standpoint. So in other words, we’re pretty happy with where we sit today. If we saw 2024 or the longer-term curve change its shape and fall off, then we would definitely change activity more. But as we see the longer-term curve looking more positive, we want to keep activity where it is.

So we maintain that productive capacity. I’ll ask Josh to comment on what we’re seeing from an on-off perspective.

Josh Viets: Yes, we are absolutely starting to see some pullback in our third-party well proposals. We saw a little bit of a pickup right at the first of the year. Seen as many as 25 proposals kind of come through the door through the first quarter. Quarter-to-date, we’re seeing maybe 10% of that same level. And also, those partners that we tend to join up with on well proposals, we’re hearing of them pulling back activity. So we do expect to see slowdowns in our non-op activity through the course of the year. It represents a pretty minor part of our program. We have roughly $20 million allocated to that with a good portion of that spend already in the first quarter.

Doug Leggate: Josh, I wonder could you translate that to rig activity? What would you anticipate Haynesville rig drops to look like for the summer?

Josh Viets: Yes. So we think that we’ve seen roughly 10 take place to date, again, year-to-date, we think we’ll probably see another 5 to probably 10 rigs continue to come out. This is just based upon our intel with our non-op partners but also even some of our rig contractors that are signaling of notices they’re receiving for rig drop. So maybe up to 20 rigs in total as we get through the end of the summer. And we think a lot of that is just operators providing notices and then attempting to fulfill the obligations associated with any contract they may have had. So that’s why we see, maybe a little bit of a delay here.

Doug Leggate: Great. My follow-up is a quick one. Nick, you’ve got — congrats, first of all, on getting the cash in the door on the Eagle Ford but you’ve got a sizable amount of your share buyback authorization left. I’m just wondering how you’re thinking about that in terms of use of proceeds, the pacing of when you might want to start using that cash given the environment? And whether, in fact, you might reset that buyback authorization at some point, I’ll leave it there.

Nick Dell’Osso: Yes. Good question, Doug. We’re pretty happy with the pace that we’ve achieved so far. We came out with originally $1 billion buyback. We upped to $2 billion. We’ve completed well over 50% of that authorization now. We started again this year following the closing of the first of the Eagle Ford transaction. You’ve seen an incremental 1 million shares bought since our last call. We don’t want to be in a rush to complete this authorization. We said the authorization runs through the end of the year. So we’re focused on that time frame but I would not expect it to necessarily be ratable. It doesn’t need to be ratable. And so we expect to have an ongoing program and we think we’ll have opportunities to be more aggressive at times.

And so we’ll try to, again, lean into that flexibility we’ve provided ourselves. I think the idea that the company would likely have an ongoing buyback program after this authorization is clearly on our minds. We want to get a little bit further through this and see how the next phase of this goes before we decide how and when to address that. But I think we’ll — we like having an authorization out there. We like having the ability to continue to buy back our shares with free cash flow and I would expect us to continue to do that.

Operator: The next question comes from Scott Hanold of RBC Capital Markets.

Scott Hanold: Yes. If I can just take along a little bit on that last commentary. I mean your cash balance has ballooned pretty nicely here. And I appreciate that optionality that — to be opportunistic. But just out of curiosity, do you see any opportunities to use that cash for any kind of M&A or bolt-on acquisitions at this point in time. If with — obviously, the private companies, taking off their rigs and gas market a little bit weak right now. Is there an opportunity to do some very accretive bolt-on with some of that cash?

Nick Dell’Osso: Good question, Scott. I think these are really 2 very separate questions. We have an authorized buyback. We’ll use that buyback. We believe it’s important to follow through on what we projected. We are pretty proud of our track record of having done that thus far under our buyback. And we think that holds up well relative to the way a lot of other companies talk about and then execute under buybacks. Separate from that, are there opportunities for acquisitions or M&A out there, maybe, they’re hard. I would say they’re hard, especially in a down market where sellers are not wanting to think about the current market conditions and wanting to look forward to an assumed improvement in market conditions. We stay engaged on the A&D front.

We do believe in consolidation. We think there’s value in consolidation when you follow our non-negotiables, so you don’t overpay and you buy good assets where you can have real synergies that are not just theoretical but they’re driven by operational realities in the field. If we can do any of those things, then we’ll absolutely continue to pursue them. I view that as somewhat separate from having cash on the balance sheet because anytime that we think about doing any sort of an acquisition, we would always think about is it financeable. Now if we have the cash, certainly, that makes the cost of financing more clear to us because we know what our cost of capital is rather than having to think about if there is incremental cost to go out and attract new capital, that is an important element of how you should think about whether or not it’s a good decision to deploy capital.

What is capital worth in the market today? Yes, you have it but what’s it worth in the market? And does the deal meet your hurdles. So, I continue to say that having cash around is a fantastic point of flexibility and something that we want to maintain that kind of flexibility in our business, having that liquidity, that cash around. But that said, it’s not a justification for doing a deal. The deal has to stand on its own.

Scott Hanold: Okay, that’s fair enough. And my follow-up question is on the gas macro. I mean, obviously, you talked about the contango in the market but it would be interesting to hear on your thoughts of what you think the gas macro looks like? And how does that form your view of hedging? You did add some hedges but given the contango, why not get more aggressive? Or is there a concern the market pivots bullishly again in your kind of caught overhedged?

Nick Dell’Osso: Well, look, I think we have a pretty methodical hedging program that takes into account all of those things. We know that the market is going to be volatile. We’re encouraged in the shape of the contango relative to where we sit today. But throughout last year, we put in place a lot of trades for ’23 and ’24 and beginning to even put on some trades for ’25, where we’ve been able to look at some wide collars to capture that volatility in a different way, in a really productive way. And we think a continued methodical approach will allow you to protect yourself against what is inevitably but uncertain timing from downside and inevitably an uncertain timing from upside. And so we’re going to continue to hedge with a methodical approach. We think it’s been the right answer and I think it works.

Scott Hanold: Okay. And just your view of the gas market, I’m just kind of curious, do you have a — like what is Chesapeake’s position on the current contango. Do you think it makes sense? Or what does your crystal ball say?

Nick Dell’Osso: Yes. I think the current contango off of a prompt price in the low 2s makes a lot of sense. But I also know that there will be a ton of volatility in the future. I mean we’re excited about the LNG export capacity that’s coming online. That’s going to represent true structural demand growth. But let’s recognize that, that will not just yield a straight up to the right curve. There will be plenty of volatility. These projects are lumpy and so as they come online, they have to have lumpy demand to match to them. There’s plenty of unmet demand internationally right now. But we — the U.S. is going to bring on a lot of LNG capacity and we have to be prepared for the volatility that comes with that. So our business should drive in that environment, where we have assets that are at the lower end of the cost curve and hold up well through these points of volatility.

You can see how we’re holding up this past quarter and how we hold up for the rest of the year at very low prices. So you know that we will hold up well when prices go back up a bit. We’ll continue to work on our cost structure. We’ll continue to try to drive our breakevens lower through our business every day. Our team is motivated to do that. Our team thinks about that every day and our actions drive for those outcomes. And you do that through lowering your costs and increasing your productivity. We think about both sides of that equation. And that, to me, is the most important way that you manage through volatility. Hedging is an important component of how you think about cushioning that volatility. But the best way to manage it is to stay at the low end of the cost curve.

Operator: The next question comes from Zach Parham of JPMorgan.

Zach Parham: I guess first, just on costs. You talked about some rigs coming off in the Haynesville with expectations that we were going to drop. Are you starting to see any cost deflation? And maybe any thoughts on what the magnitude of that deflation could be later this year and into ’24?

Josh Viets: Yes. Zach, this is Josh. We’re definitely seeing trends that the OFS costs are flattening with maybe some minor signs starting to develop declining in certain areas. And of course, a lot of this is just driven by the pullback in activity that we’re seeing across all the U.S. shale gas basins. We’re seeing rig counts in that sector down about 10%. And relative to where we were maybe around the end of this past year. And we’re also seeing frac crews starting to come out. I think at its peak, Haynesville was around 30. We’re anticipating that may drop down to as few as 20 by the end of this year. And I think it remains to be seen how does that impact pricing? I think as you listen to some of the service providers that are indicating their willingness to relocate some of this equipment out of the gas basins and into areas such as the Permian.

So that creates a little bit of uncertainty as how that might impact pricing but I’d just say the signs are very positive. We’re seeing improved operations as well. We’ve kind of used this time as well to upgrade some of our service providers. So that’s paying dividends for us right now. But again, we are seeing that some potential upside in the cost structure. But I would say it’s just probably too early to change anything just yet, just given the uncertainty around timing and just overall materiality of the cost reductions.

Zach Parham: Thanks for that color, Josh. Nick, maybe one for you. We’ve seen some of your E&P peers shift their cash return programs away from variable dividends to focus more on buybacks. Any thoughts on shifting away from the base dividend program in favor of more buybacks.

Nick Dell’Osso: We’ll continue to do what we’re doing right now, Zach. Our free cash flow, obviously, is coming down as we move through this year with lower prices. And so the variable dividends come down with that. We love having the buyback there to continue to use the cash we have to return cash to shareholders. We think it’s worked pretty well so far. We get a lot of varying feedback from investors with some investors really favoring the implied discipline of the dividend, balanced with the buyback. We’re — as I’ve said all along, we’re not dogmatic about any of this and we’ll continue to think about what makes most sense. We’ve liked what we’ve done so far. We think it makes sense to continue it but we’ll continue to monitor it. And if there’s some change in the future that makes sense, we would do it. Otherwise, I’d say we’ll keep doing what we’re doing.

Operator: The next question comes from Josh Silverstein of UBS.

Josh Silverstein: You talked about dropping some activity as planned in both the Haynesville and the Marcellus in 2Q and 3Q which will decline volumes a little bit. I know there’s a lot of flexibility in the program. You talked about some improved cost and efficiency gains. But how are you thinking about kind of sustaining that activity into 2024? Will you have to add that activity back? Can you sustain that level of the second half activity pace. So just curious how that looks into next year?

Nick Dell’Osso: All else equal, Josh, if we see a good strong market next year, we would add activity back. Our program requires somewhere in between 4 and 5 rigs to stay flat in the Marcellus and about 6 rigs to stay flat in the Haynesville. So as we dip below that, we know that we are leaning into the concept that the market is oversupplied. That’s the right thing to do. And at some point, when the market is healthy, we want to be back to a maintenance level with the ability to ramp into modest growth when that makes sense. So yes, we would add back at some point but we’re not there yet. We want to wait and see how 2024 plays out.

Josh Silverstein: Got it. And then as part of the Marcellus program for this year, you have almost roughly a 50-50 split between the upper and lower Marcellus. Just wanted to see how upper Marcellus well productivity is going and how you think activity may shift between the 2 zones going forward, knowing that the upper is a bigger part of the inventory base?

Josh Viets: Yes, Josh, what I’d say on that is, this year, the program is designed to be about 55% lower, 45% upper. We expect that trend to hold true to that probably for the next couple of years, at least. I would say, clearly, the Upper Marcellus has productivity per foot. That is less than about 20% to 25% less than where we’ve seen the year lower historically. But again, we have the opportunities there to extend lateral lengths up to 30% more on average and so what we tend to focus on when we try to our drilling schedule is really assessing the overall return and capital efficiency. And so when you take that productivity and you account for the longer laterals, we really see the upper being able to compete with the bulk of our remaining lower inventory. And so we really like the spread that we have today. We’ve been pleased with the results that we’ve gotten and look forward to continue developing that in conjunction with our remaining lower inventory.

Operator: The next question comes from Matt Portillo of TPH.

Matt Portillo: I just have 2 quick questions on the infrastructure side. Just curious if you could give us an update on infield infrastructure. I know last year, there were quite a few constraints around processing and treating and just curious how you guys feel about the progress of that infrastructure expansion in 2023 and potentially 2024? Just trying to get a better picture of how things are going at the field level.

Josh Viets: Yes. This is Josh. We’ve made a lot of progress on that and have been really pleased with how that’s starting to show up in our production both with our base but also the benefits it’s providing to the TILs that we’ve had today. Nick referenced in his prepared comments that we’ve seen an 8% improvement and our 90-day IPs and we think that’s directly attributable to the fact that we’re seeing lower gathering pressures in the system which is allowing us to more optimally manage our chokes. In addition to that, one of the reasons that we were a little bit ahead of our guidance in the Haynesville on production is as we see third-party maintenance occurring across the field, we have more opportunity now to offload gas into adjacent gathering and treating systems which is minimizing the impacts of those third-party outages.

So again, really, really pleased with the progress that we’ve made. We’re going to continue to be working that to ensure that capacity we have in our midstream space is matching the production we expect from the asset.

Matt Portillo: Perfect. And then as a follow-up to the Haynesville question there, just curious if you could give us an update on the progress around Momentum, how you’re feeling about the project moving forward? And then maybe if you could just speak to the basin infrastructure expansion from a takeaway perspective as it progressed through ’24 and ’25 and what that might mean for basis, especially if we start to see a flattening out of Haynesville growth going into next year.

Mohit Singh: Yes, Matt, this is Mohit. On the first part of your question, so the punch line is the Momentum project is on track. We are actively engaged with the momentum there in terms of monitoring the progress and everything in terms of securing right of ways and pipe and other equipment that’s needed to get the project in service is all on track. As we have previously guided, the in-service date is end of 2024 and that’s still all on track. So pretty pleased with that project and how it’s progressing. On the second part of your question around overall infrastructure build, I think it will continue to develop. When we think about long-haul pipes, several different projects are being built, momentum NGI being one of them, essentially, that will allow production to be picked up at the tailgate of our gathering system in Haynesville and bring it down to Giles which is closer to the LNG complex.

We know of other projects which are also being built at the same time. So at least the good news is in Louisiana there’s — the environment is friendly enough that we think more of those kinds of pipelines can be built. The other thing which is going — which is happening in conjunction with that is all these different liquefaction facilities are being built. So all of that, I think, is what gets us bullish about the natural gas macro. And when we look at the contango, that’s reflecting that. Overall, as Nick said earlier, we are setting up our business to be LNG-ready. And as and when that demand comes through, we’ll be ready to deliver into it.

Operator: The next question comes from Nitin Kumar of Mizuho.

Nitin Kumar: I guess I’ll start on the Eagle Ford, congrats on getting the first 2 packages done. Commodity prices have been a bit volatile and interest rates are rising. Just any thoughts on the progress of the last piece, the rich gas assets? And I think last quarter, you had said that EBITDA with that asset was about $300 million. What’s the estimate now with lower commodity prices?

Mohit Singh: Well, so Nitin, this is Mohit. On the first part of your question, so we remain in active dialogue with the interested parties there. You correctly referenced that commodity prices have seen volatility and then interest rate environment has been equally volatile, so financing market remains challenged. The good news is the buyers that we have been engaged with all throughout the process have been actively in dialogue with us, that bodes well. As we have said all along, we are prepared to hold on to the asset if we don’t get to the right price. So again, all those options are on the table and we are continuing to work through all of that. On the second part of your question around EBITDA for the asset, it’s about $250 million for the year is what we would guide you at this point.

Nitin Kumar: Great. And I guess you’ve talked a little bit about LNG. Nick, you mentioned the contango in the gas curve. Just any thoughts on the current and maybe near-term LNG feed gas demand. Things seem to have slowed down a little bit since Freeport came on towards the end of March. And then there’s been some talk of Golden Pass , maybe pulling some gas earlier than expected. So just a more near-term look on what you’re seeing from the LNG guys now?

Nick Dell’Osso: I don’t think we’re hearing anything different than you guys here but we’re encouraged by what we’re hearing. It sounds like Golden Pass is making great progress. It sounds like Venture Global is making great progress. Again, we don’t have anything proprietary there. We’re encouraged by all of it. Seems like those projects are moving along and hope to have plenty of new demand show up in the U.S. as a result, as we move through next year and into ’25.

Operator: Next question comes from Bertrand Donnes of Truist.

Bertrand Donnes: Just following up on Nick’s comment on the potential pivot in production in ’24. It sounded like maybe you’re implying that the ’24 production profile could kind of match the strip, currently above $4 at the end of the year but I want to clarify would you still grow if that $4 handle dropped back into the 3s because it’s still above your breakevens or if you’re looking at that high level as your incentive to grow .

Nick Dell’Osso: Well, Bert, we’re looking at all kinds of scenarios for 2024 and we’re not ready to give you an exact answer of how we think about allocating capital to the year yet because we don’t have the full set of information to set our plans for the year. We have a lot of flexibility. And all I’m trying to convey is that if prices weaken in ’24, we can either keep activity at a low level where it is today or lower level where it is today and we can lower it further. And if prices show the strength in contango that they have or strengthen, we can bring activity back and put ourselves back in a position to grow as we approach ’25. All I’m really trying to highlight is that we’re encouraged by the contango that we see and we’re encouraged by the changes that we’re seeing in the market that we believe should help to underpin that contango.

Now there’s many things that could still happen between now and then that could change those outcomes. And so we’ll watch it closely and we’ll make decisions about how to allocate capital for ’24 as we get closer to the end of the year.

Bertrand Donnes: Great color. And then, a follow-up. On LNG, I think that you’ve indicated before that you do want to kind of limit your exposure to international pricing maybe 10% to 15% of your total profile. Could you maybe walk through why you don’t feel comfortable with the higher level or why you pick that level?

Nick Dell’Osso: Well, I think we’ve said probably 15 to 20 but there’s not a real magic number within that range. The way that we have come up with that range as we think about the capacity of export that will ultimately be present in the U.S. And today, we would say that should be about 20%-ish of the U.S. market would be — of demand for the U.S. would be represented by LNG export capacity. It could be a little higher, it could be a little less depending on exactly which projects show up. And so we feel like if 15% to 20% of our production is exposed to international pricing, that would match the demand in the U.S. that is exposed to international pricing and that would keep us balanced to the drivers of what’s going to pull on supply from the U.S. So, we’ll — we think that’s a good place to start.

It’s going to take us a while to get there as you’ve seen these contracts move fairly slowly. We’re learning a lot about the way they come together. We’re learning a lot about the players in the industry. We’re really pleased with the progress that we’ve made. We don’t want to be in a rush here. So that is meant to be a long-term target. And we think it makes sense for now. And as we move through time, if that needs to change, we’ll change it.

Operator: The next question comes from Umang Choudhary of Goldman Sachs.

Umang Choudhary: You talked about volatile gas price environment going forward. Gas prices are weak today and obviously, you plan to lean more towards share repurchase more countercyclically but thinking more long term, would love your thoughts around the optimal leverage and cash you would like to have on the balance sheet when prices improve.

Mohit Singh: Yes. I think, Umang, this is Mohit. The way we think about it is the balance sheet is in a pretty pristine condition. We love that. We would love to maintain it that way. The way I’d like you to think about it also is just think of it in terms of what the boundary conditions are. We have publicly and previously said that one turn of net debt to EBITDA is kind of the max that we would want to get to. In terms of what the lower end might be, I mean, a little bit of leverage is good. So it all depends on what point you are in the cycle. So would you trend more closer to the one turn net debt to EBITDA when you’re potentially at the low point in the cycle versus you want to keep the leverage lower when you’re at the high point in the cycle and kind of flexing it through the cycles would be the — we mentally think about it but the max is, as I said, the boundary conditions, we certainly don’t want to exceed one turn net debt to EBITDA and the logic notionally being, if we have — if all things go south and we have to shed activity down then the EBITDA that we are generating allows us to pay it off in 1 year.

So we tend to think of it more in terms of what the max leverage should be. And within that 0 to 1 turn, the optimal would kind of flex through the cycles.

Umang Choudhary: Very helpful. And also another point which Nick made earlier was around reducing the free cash flow breakeven for the company, right, to position it both for the up cycle but also when prices are lower. Beyond your marketing efforts and Be LNG-ready strategy, any areas where you see potential for further improvement of breakevens longer term?

Nick Dell’Osso: I would say it’s just more of what we’ve continued to do, Umang. We’ve continued to work on longer laterals. We’ve continued to work on how we target locations within the field. We continue to work on the efficiency of our completions, the efficiency of the drill bit , every bit of that matters. And that’s something that we’ve tried to make a part of the just everyday thought process around here to drive costs lower, while driving productivity higher. It’s not just about one side of the equation, it’s about both.

Josh Viets: Yes. Umang, I would just say our well cost, we talked a little bit about inflation earlier and really, of course, we’re starting to talk now about deflation. But clearly, that’s a tailwind for us. and is going to provide some opportunities to reduce breakevens. We’re also working our water infrastructure really hard in the Haynesville which has a pretty material impact to our overall operating margins there. And so those are just a couple of points that I would just add on to that.

Operator: The next question comes from Paul Diamond of Citi.

Paul Diamond: Just a quick question. So you talked about some of the operational efficiency improvements in southern that you guys have seen recently. Just wanted to get my head around how you — should we think of those as progressing further along a linear track? Or I guess how much DC is still in the bone there?

Josh Viets: Yes, Paul. I mean, those are, I would say, just continue to progress a linear track. I mean we’ve been operating in the Haynesville and the Marcellus for well over a decade. And so I think the big step changes have been made. And so it’s really about just incremental improvements and we continue to chip away at inefficiencies . Part of that is, as I mentioned earlier, upgrading our service providers when we can. But our teams are engaged in looking at the lowest level of detail around how we drill our wells faster, cheaper, safer and the same thing could be said on the completion front. And so it’s a daily discussion about how do we make our business more efficient than it was yesterday.

Paul Diamond: Understood. And just one quick follow-up, more talking about longer term, the split between Haynesville and Marcellus. Is that something we should think is relatively set in stone? Or is there some potential modularity based on whether it’s takeaway constraints or in basin pricing risk or other infrastructure? Or is that pretty locked in?

Josh Viets: That’s pretty fluid and a lot of it does end up depending on how the gas markets within the respective basins are playing out. I mean clearly, the overall return is going to be stronger in the Marcellus, given the strength of our position there. But I would just maybe point to our decision earlier in the year to pull out a frac crew in the Marcellus. One of the reasons we did that is we were seeing the setup of a weakening demand situation through the end of the first quarter and into the second quarter and we simply didn’t want to be completing wells and then turning them in line into that weaker environment. And so we’ll actually see ourselves down a little bit until in the second quarter. I think we’ll end up with somewhere around 13 tools coming in line.

And again, that’s just simply to acknowledge that, that market will be weaker in that period of time but that doesn’t necessarily represent a long-term view, again, just a short-term impact due to local market conditions.

Mohit Singh: I think the only thing I would add to that, Paul, is you should think of Marcellus as kind of the baseload because we maximize capital allocation to it. That is our best asset. And you should think of Haynesville as the flex engine which allows us to flex up or down depending on what we’re seeing with the prompt pricing.

Operator: The next question comes from Noel Parks of Tuohy Brothers.

Noel Parks: I wanted to check in on something around the service environment. Is it safe to say that there are still no signs out there among the larger service vendors of any appetite for them rolling out additional equipment, new builds and so forth. And I was thinking about that in the context of sort of if service costs even with a little bit of on inflation, if they stay high, if sort of the rig in fact fleets for the industry are relatively static. It seems like that would be an upward pressure on the price that the industry would need to get for gas in order to be able to supply the LNG demands going forward. So I just wanted to check on that as far as you can tell, still no signs of any relief on sort the overall equipment capacity front.

Josh Viets: Yes. No, I mean clearly, through the end of last year, we saw really high utilization rates the high-spec rigs and frac fleets. As we’re out talking to service providers, we’re not seeing any strong signals of them deploying capital into new equipment. But what we are seeing that is, I think I could use maybe the example of the dual fuel or probably even a better example is the e-fleets , they are starting to realize the operational efficiencies and cost efficiencies associated with those. So we are seeing some of those start to come out into the market. But in most cases, when they bring that in, that means they’re retiring less efficient, older piece of equipment, again, generally, the diesel fuel units. So I think as that overall capacity across the service sector remains tight, I do think that can potentially longer term, create a little bit of a headwind for us from a service cost standpoint.

But that’s why we remain so focused on partnering with the best service providers in the industry to help drive additional operational efficiencies which in turn offsets any future inflation that we could see.

Noel Parks: Great. And I just wonder, as we have had a few more months tick by with oil remaining relatively strong and near-term gas struggling a bit. Do you have any updated thoughts on sort of the associated gas piece of the puzzle in the — from the Permian in terms of, I guess, supply to the Gulf or in terms of what impact that might have on sort of longer-term LNG.

Nick Dell’Osso: Generally, Noel, we think with oil prices remaining constructive, the pipes that are built from the Permian to the east are going to be full. That’s kind of how we think about how to model associated gas.

Operator: The next question comes from Subhasish Chandra of Benchmark.

Subhasish Chandra: Just a follow-up — follow-up on the Haynesville rig view. So another 10 through the end of summer. Curious if that’s your current visibility if you think that’s sort of a trough or it’s really dependent on whether summer materializes, all the macro stuff that could pressure prices in the third quarter, for instance and we could see another rig down ? And specific to Chesapeake, what is your willingness to incur any early contract termination penalties to accelerate rig drops on your end?

Nick Dell’Osso: All good questions, Subash. I think further drops than what are currently projected are going to be reliant on the 2024 and beyond curve moving. I don’t think you’re going to see rig drops come from just a summer crash of prices, should that happen — should we hit a well of storage going into November 1 and late summer, fall prices really fall on the front months. But if the longer-term curve holds up, I don’t think you see rig changes. If the longer-term curve moves down, then I think you do see rig changes. As far as our willingness to think about any penalties for reducing rigs that are under contracts, usually, we can navigate that. We can navigate it because we have scale and we have big relationships with our rig providers and we have a staggered set of contracts. And so we try to maintain flexibility where you could make decisions like that and not incur penalties that would be cumbersome.

Subhasish Chandra: Okay. And Nick, I guess, on some clarification on the LNG-ready strategy because it seems like you have ample coverage of your current LNG — direct LNG exposure. So is it — and that — I think reading between the lines, LNG-ready does not mean maintenance, it means some level of growth. So does that mean a willingness or desire to have more direct exposure? Because I think you’ve sort of said that is — you’d like a bit more but maybe not a lot more. But yes, I guess boiling the question down, like you have more than enough local production to satisfy your LNG exposure. So why growth at all?

Nick Dell’Osso: Yes. I think we’ve been pretty clear and consistent in our message that we’re comfortable with 15% to 20% of our total gas production as a company being priced under international prices. The concept of being LNG-ready means that we want to be connected to the right infrastructure, have the contracts in place. And then as the U.S. market grows, from approximately 100, 101 Bcf market today to 110 over the next few years and eventually towards 115 or 120, we want to be in a position to help supply that growth. That — the decision around growing is far out in the future. We want to — the concept of being LNG-ready is to be in a position that if the economics of supplying that growth are attractive, we can choose to do it.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Nick Dell’Osso for any closing remarks.

Nick Dell’Osso: Thanks again. Thanks, everybody, again, for the time this morning. Again, we’re looking forward to the second half of the year here. As we go through the summer months, there’s going to be plenty of volatility in the market and a lot of decisions that we think we have the flexibility to make in our business. We like that flexibility. We intend to use it. And we look forward to continuing to generate good returns for shareholders throughout all of these points of the cycle. Thanks again for your time and we’ll see everybody at conferences and through other engagements over the next couple of months.

Operator: The conference has now concluded. Thank you for attending today’s presentation and you may now disconnect.