Expand Energy - Q1 2023

Transcript

Operator (participant)

Good morning, welcome to the Chesapeake Energy first quarter 2023 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your telephone keypad. To withdraw your question, please press star then two. 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 (VP of Investor Relations and Treasurer)

Thank you, Andrea. Good morning, everyone, 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 as accept is required by applicable law, we undertake no duty to update any forward-looking statements. 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 measure 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. With that, thank you again, and now turn it over to Nick.

Nick Dell'Osso (President and CEO)

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 delivers 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 IP90s having improved about 8% from 2022, benefiting from new gas gathering offloads and incremental treating capacity put in place in 2022.

CapEx was slightly ahead of expectations on the heels of very strong execution from our drilling and completion teams, where we drilled three of the five 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. We've deployed a continuous pumping well head technology that enabled our teams to pump a record 36 consecutive hours on a Haynesville frack. 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. Market volatility continues to be top of mind for investors, we're very pleased with our position at this point in the year. 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 two initial Eagle Ford sales for $2.8 billion. As of April 30th, 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 now sit one notch below investment grade with Fitch, who attributed the strength of our scale, conservative financial policy, and cash optionality as 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 frack 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.

Operator (participant)

We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you are using a speaker phone, please pick up your handset before pressing the key. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble the roster. Our first question comes from Doug Leggate of Bank of America. Please go ahead.

Doug Leggate (Managing Director and Head of US Oil and Gas)

Well, thank you. Good morning, everyone, and I appreciate you getting me on the call. Nick, I wanna ask you first about your comments in the prepared remarks, or actually in your press release about being prepared to adjust the activity. Then you just talked about you've kept your guidance and your CapEx guidance unchanged. 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. If you could walk us through that. Maybe an add on to that, what are you seeing in your non-operated activity as well? Is there any sign of things slowing down, particularly in the end zone? I've got a follow-up, please.

Nick Dell'Osso (President and CEO)

Sure, Doug. Thanks for the question. You know, 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 gonna 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. If the activity reductions that are predicted throughout the market come through, we think 2024 should follow the contango that's there. You know, maybe not perfectly, but it should be certainly more constructive than this year. We wanna 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. You know, more importantly, we have a lot of decisions we can make every time we go to turn in line a well as to whether or not it makes sense to turn that well in line or defer it. Now, 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 gonna do some maintenance that we are choosing to do now in the Haynesville that will take a little production offline for two months. You know, these are all things that are really prudent decisions to do during a low price environment. We'll keep making decisions like that. This is where, again, I think the financial flexibility we have is a real strength, and we plan to lean in on it and use it. 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 on turning them in line. Having the activity completed, we can rely on the contango of the curve to make those decisions positive from an NPV standpoint.

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. As we see the longer-term curve, you know, looking more positive, we wanna keep activity where it is, so we maintain that productive capacity. I'll ask Josh to comment on what we're seeing from a non-op perspective.

Josh Viets (EVP and COO)

Yeah, good morning, Doug. 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, you know, seeing as many as 25 proposals kinda come through the door through the first quarter. Quarter to date, you know, we're seeing maybe 10% of that same level. 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 spent already in the first quarter.

Doug Leggate (Managing Director and Head of US Oil and Gas)

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

Josh Viets (EVP and COO)

Yeah. We think that we've seen roughly 10 take place to date. Again, year to date, we think we'll probably see another five 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, you know, signaling of notices they're receiving for rig drops. You know, maybe up to 20 rigs in total as we get through the end of the summer. We think a lot of that is just, you know, operators providing notices and then attempting to fulfill the obligations associated with any contract they may have had. That's why we see maybe a little bit of a delay here.

Doug Leggate (Managing Director and Head of US Oil and Gas)

Great. Thank you for that. My follow-up is a quick one. Nick, you know, congrats, first of all, on getting the cash from the door on the Eagle Ford. 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 wanna 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. Thanks.

Nick Dell'Osso (President and CEO)

Good question, Doug. We're pretty happy with the pace that we've achieved so far. You know, we came out with originally a $1 billion-dollar buyback. We upped it 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 transactions. You've seen an incremental 1 million shares bought since our last call. You know, 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 timeframe, but I would not expect it to necessarily be ratable. It doesn't need to be ratable. We expect to have an ongoing program, and we think we'll have opportunities to be more aggressive at times.

You know, we'll try to, again, lean into that flexibility we've provided ourselves. You know, 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, you know, how and when to address that. You know, 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.

Doug Leggate (Managing Director and Head of US Oil and Gas)

Appreciate the answers, guys. Thanks so much.

Operator (participant)

The next question comes from Scott Hanold of RBC Capital Markets. Please go ahead.

Scott Hanold (Managing Director of Energy and Research)

Yeah, thanks. If I can just tag along a little bit on that last commentary. I mean, your cash balance has ballooned, you know, pretty nicely here, and I appreciate that optionality, that, you know, to be opportunistic. Just out of curiosity, do you see any, you know, opportunities to use that cash for any kind of M&A or bolt-on acquisitions at this point in time? If, you know, with, you know, obviously the private companies, you know, 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 (President and CEO)

Good question, Scott. You know, I think these are really two very separate questions. We have an authorized buyback. We'll use that buyback. We believe it's important to follow through on what we've 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 any time that we think about doing any sort of an acquisition, we would always think about, is it financeable? If we have the cash, certainly, that makes the cost of financing, you know, 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. You know, what is capital worth in the market today? Yes, you have it, but what's it worth in the market? Does a deal meet your hurdles? 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. That said, it's not a justification for doing a deal. The deal has to stand on its own.

Scott Hanold (Managing Director of Energy and Research)

Okay, that's fair enough. My follow-up question is on the gas macro. I mean, obviously, you talked about the contango in the market, but, you know, we'd be interested 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? Is there a concern the market pivots, you know, bullishly again and you're, you know, kind of caught overhedged?

Nick Dell'Osso (President and CEO)

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. You know, throughout last year, we put in place a lot of trades for 2023 and 2024 and beginning to even put on some trades for 2025, where we've been able to look at some wide collars to capture that volatility in a different way, in a really productive way. We think a continued methodical approach will allow you to protect yourself against what is, you know, inevitably but uncertain timing from downside and inevitably an uncertain timing from upside. We're gonna continue to hedge with a methodical approach.

We think it's been the right answer, and I think it works.

Scott Hanold (Managing Director of Energy and Research)

Okay. Just your view of the gas macro, I'm just kind of curious, do you have a like, what is Chesapeake's position on, you know, the current contango? Do you think it makes sense? Or, you know, what does your crystal ball say?

Nick Dell'Osso (President and CEO)

Yeah, I think the current contango off of a prompt price in the low twos makes a lot of sense. 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. You know, 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. You know, U.S. is gonna bring on a lot of LNG capacity, and we have to be prepared for the volatility that comes with that.

You know, our business should thrive 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. 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 break-evens 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. You do that through lowering your costs and increasing your productivity. We think about both sides of that equation.

You know, 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. The best way to manage it is to stay at the low end of the cost curve.

Scott Hanold (Managing Director of Energy and Research)

Appreciate those comments, Nick. Thanks.

Operator (participant)

The next question comes from Zach Parham of JPMorgan. Please go ahead.

Zach Parham (Executive Director and Equity Research Analyst)

Yeah. Thanks for taking my question. I guess first, just on cost, you talked about some rigs coming off in the Haynesville with expectations that more were gonna drop. Are you starting to see any cost deflation? Maybe any thoughts on what the magnitude of that deflation could be later this year and into 2024?

Josh Viets (EVP and COO)

Yeah. Zach, this is Josh. You know, we're definitely seeing trends that the OFS costs are flattening, with maybe some minor signs starting to develop of declining in certain areas. Of course, a lot of this is just driven by the pullback in activity that we're seeing across, you know, all the U.S. shale gas basins. You know, we're seeing rig counts in that sector down about 10%, relative you know, where we were maybe around the end of this past year. We're also seeing frac crews starting to come out. You know, I think at its peak, you know, Haynesville was around 30. You know, we're anticipating that may drop down to as few as, you know, 20, you know, by the end of this year.

I think it remains to be seen, you know, how does that impact pricing. I think if you listen to some of the service providers, they're indicating, you know, their willingness to relocate some of this equipment out of the gas basins and into areas, you know, such as the Permian. That creates a little bit of uncertainty as how that might impact pricing. But I'd just say the signs are very positive. You know, 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, you know, paying dividends for us right now. But again, we are seeing that some potential upside in the cost structure.

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 (Executive Director and Equity Research Analyst)

Got it. 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. You know, any thoughts on shifting away from the base dividend program in favor of more buybacks?

Nick Dell'Osso (President and CEO)

You know, 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, you know, 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. You know, 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. You know, 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. 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.

Zach Parham (Executive Director and Equity Research Analyst)

Thanks. Yeah.

Operator (participant)

The next question comes from Josh Silverstein of UBS. Please go ahead.

Josh Silverstein (Head of Energy Research)

Yeah. Thanks. Good morning, guys. 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. You know, I know there's a lot of flexibility in the program. You talked about some improved cost and efficiency gains. How are you thinking about kind of sustaining that activity into 2024? Will you have to add that activity back? Can you sustain that, you know, that level of the second half activity pace? Just curious how that looks into next year. Thanks.

Nick Dell'Osso (President and CEO)

Yeah. All else equal, Josh, if we see a good strong market next year, we would add activity back. You know, our program requires.

Somewhere in between four and five rigs to stay flat in the Marcellus and about six rigs to stay flat in the Haynesville. As we dip below that, we know that we are leaning into the concept that the market's oversupplied. That's the right thing to do. At some point when the market is healthy, we wanna be back to a maintenance level, with, you know, the ability to ramp into modest growth when that makes sense. Yeah, we would add back at some point, but we're not there yet. We wanna wait and see how 2024 plays out.

Josh Silverstein (Head of Energy Research)

Got it. 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, you know, well productivity is going and how you think, you know, activity may shift between the two zones going forward knowing that the upper is, you know, a bigger part of the inventory base.

Josh Viets (EVP and COO)

Yeah, Josh. you know 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, you know, probably for the next couple of years, at least. I would say, you know, clearly the upper Marcellus has productivity per foot that is, you know, less than about 20%-25% less than where we've seen the lower historically. Again, you know, we have the opportunities there to extend moderate links, you know, up to 30% more on average. What we tend to focus on when we, you know, try to prioritize our drilling schedule is really, you know, assessing the overall return and capital efficiency.

When you know, take that productivity and you account for the longer laterals, we really see the upper being able to compete, you know, with the bulk of our, you know, remaining lower inventory. We really like the spread that we have today. We've been pleased with the results that we've gotten and, you know, look forward to, you know, continue developing that in conjunction with our remaining lower inventory.

Josh Silverstein (Head of Energy Research)

Great. Thanks, guys.

Operator (participant)

The next question comes from Matt Portillo of TPH. Please go ahead.

Matt Portillo (Partner and Head of Research)

Morning, all. I just have two 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 (EVP and COO)

Yeah, 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 to date. Nick referenced in his prepared comments that we've seen an 8% improvement in our 90-day IPs. 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, you know, one of the reasons that we were a little bit ahead of our guidance in the Haynesville on production is, you know, 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. Again, really, really pleased with the progress that we've made. We're gonna continue to be working that to ensure that, you know, the capacity we have in our midstream space is matching the production we expect from the asset.

Matt Portillo (Partner and Head of Research)

Perfect. 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. Maybe if you could just speak to the basin infrastructure expansion from a takeaway perspective as we progress through 2024 and 2025, 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 (EVP and CFO)

Yeah. Matt, good morning. This is Mohit. On the first part of the question, the punchline is the Momentum project is on track. We are actively engaged with Momentum there in terms of monitoring the progress and everything in terms of securing right of ways and pipes 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, that's still all on track. 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, NG3 being one of them.

Essentially that'll allow production to be picked up at the tailgate of our gathering system in Haynesville and bring it down to Gillis, which is closer to the LNG complex. We know of other projects which are also being built at the same time. 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 happening in conjunction with that is all these different liquefaction facilities are being built. All of that, I think, is what gets us bullish about the natural gas macro. 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.

Matt Portillo (Partner and Head of Research)

Thank you.

Operator (participant)

The next question comes from Nitin Kumar of Mizuho. Please go ahead.

Nitin Kumar (Senior Equity Research Analyst)

Thanks, guys, and thanks for taking my question. I guess I'll start on the Eagle Ford. Congrats on getting the first two packages done. You know, 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? 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 (EVP and CFO)

Well, Nitin, this is Mohit. On the first part of your question, 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. 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 (Senior Equity Research Analyst)

Great. Thanks for that, Mohit. 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? you know, 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. Just a more near-term look on what you're seeing from the LNG guys now.

Nick Dell'Osso (President and CEO)

You know, I don't think we're hearing anything different than you guys hear. 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, you know, plenty of new demand show up in the U.S. as a result, as we move through next year into 25.

Nitin Kumar (Senior Equity Research Analyst)

Great. Thanks for the answers, guys.

Nick Dell'Osso (President and CEO)

Yeah. Thanks, Nitin.

Operator (participant)

The next question comes from Bertrand Donnes of Truist. Please go ahead.

Bertrand Donnes (Managing Director of Energy Equity Research)

Hey. Morning, guys. Just following up on Nick's comments on the potential pivot in production in 2024. It sounded like maybe you're implying that the 2024 production profile could kind of match the strip, you know, currently above $4 at the end of the year. I wanted to clarify, would you still grow if that $4 handle dropped back into the $3s because it's still above your breakevens or if, or if you're looking at that high level as your incentive to grow?

Nick Dell'Osso (President and CEO)

Bertrand, we're looking at all kinds of scenarios for 2024, 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, you know, the full set of information to set our plans for the year. We have a lot of flexibility, all I'm trying to convey is that if prices weaken in 2024, 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. If prices, you know, show the strength and contango that they have or strengthen, we can bring activity back and, you know, put ourselves back in a position to grow as we approach 2025.

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. There's many things that could still happen between now and then that could change those outcomes. We'll watch it closely, and we'll make decisions about how to allocate capital for 2024 as we get closer to the end of the year.

Bertrand Donnes (Managing Director of Energy Equity Research)

That's great color. Thanks. Follow-up. On LNG, I think that, you know, you've indicated before that you do wanna kinda limit your exposure to international pricing, maybe 10%-15% of your total profile. Could you maybe walk through, you know, why you don't feel comfortable with a higher level or why you picked that level?

Nick Dell'Osso (President and CEO)

Well, I think we've said probably 15-20, but, you know, there's not a real magic number within that range. The way that we have come up with that range is we think about the capacity of export that will ultimately be present in the U.S. 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. Could be a little higher, could be a little less, depending on exactly which projects show up.

So we feel like if 15%-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 gonna pull on supply from the U.S. You know, we think that's a good place to start. It's gonna 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, that is meant to be a long-term target. You know, we think it makes sense for now.

As we move through time, if that needs to change, we'll change it.

Bertrand Donnes (Managing Director of Energy Equity Research)

I appreciate that. Thanks.

Operator (participant)

The next question comes from Umang Choudhary of Goldman Sachs. Please go ahead.

Umang Choudhary (VP of Equity Research)

Hi, good morning, and thank you for taking my questions.

Nick Dell'Osso (President and CEO)

Yeah. Good morning, Umang.

Umang Choudhary (VP of Equity Research)

Hey. 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 (EVP and CFO)

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 you know, it all depends on what point you are in the cycle.

Would you trend more closer to the 1 turn net debt to EBITDA when, you know, 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 way we mentally think about it. The max is, as I said, the boundary condition is we certainly don't want to exceed 1 turn net debt to EBITDA. The logic notionally being, if all things go south and we have to shut activity down, then the EBITDA that we are generating allows us to pay it off in 1 year. We tend to think of it more in terms of what the max leverage should be.

Within that 0-1 turn, the optimal would kind of flex through the cycles.

Umang Choudhary (VP of Equity Research)

Very helpful. Thank you. Also another point which we, which Nick made earlier was around reducing the free cash flow breakeven for the company, right? To position it both for the upcycle 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 (President and CEO)

I would say it's just more of what we've continued to do, Umang. We've, you know, continued to work on longer laterals. We've continued to work on how we target locations within the field. We've continued to work on the efficiency of our completions, the efficiency of the drill bit. Every bit of that matters. 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 (EVP and COO)

Umang, I would just say, you know, our, you know, 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 gonna provide some opportunities to reduce breakevens. We're also, you know, working our water infrastructure really hard in the Haynesville, which has a pretty material impact to our overall operating margins there. Those are, you know, just a couple points that I would just add on to that.

Umang Choudhary (VP of Equity Research)

Thank you. Thank you so much.

Josh Viets (EVP and COO)

The next question comes from Paul Diamond of Citi. Please go ahead.

Paul Diamond (Equity Research Analyst)

Thank you, and good morning. Thanks for taking my calls. Just a quick question. You talked about some of the operational efficiency improvements in Southern Haynesville that you guys have seen recently. I just wanted to get my head around. Should we think of those as progressing, you know, further along a linear track? Or I guess how much meat do you see still on the bone there?

Josh Viets (EVP and COO)

Yeah, Paul. I mean, those are, I would say, just continuing to progress along a linear track. I mean, we've been operating in the Haynesville and the Marcellus for, you know, well over a decade. I think the big step changes, you know, have been made. It's really about just incremental improvements and continuing to chip away, you know, at efficiencies. You know, part of that is, you know, as I mentioned earlier, you know, upgrading, you know, our service providers, you know, when we can. But our teams are, you know, engaged in looking at the lowest level of detail around how we drill our wells, you know, faster, cheaper, safer. The same thing could be said on the completion front.

It's a daily discussion about, you know, how do we make our business more efficient, than it was yesterday.

Paul Diamond (Equity Research Analyst)

No. Understood. Thanks. Just one quick follow-up more talking about, you know, longer term, it's, you know, the split between the 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 risks or other infrastructure, or is that pretty locked in?

Josh Viets (EVP and COO)

You know, 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 gonna be stronger in the Marcellus, you know, given the strength of our position there. I would just maybe point to, you know, our decision earlier in the year to pull out a frac crew in the Marcellus. You know, one of the reasons we did that is we were seeing, you know, the setup of a weakening demand situation, you know, through the end of the first quarter and into the second quarter, and we simply didn't wanna be completing wells and then turning them line and into that weaker environment. We'll actually see ourselves down a little bit on TILs in the second quarter.

I think we'll end up with, you know, somewhere around 13 TILs coming in line. That's just simply to acknowledge that, you know, that market will be weaker in that period of time. That doesn't necessarily represent a long-term view. Just a short term impact due to local market conditions.

Mohit Singh (EVP and CFO)

I think the only thing I would add to that, Paul, is you should think of Marcellus as kind of the base load 'cause we maximize capital allocation to it. That is our best asset. 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.

Nick Dell'Osso (President and CEO)

Understood. Makes perfect sense. Thanks for your time.

Operator (participant)

The next question comes from Noel Parks of Tuohy Brothers. Please go ahead.

Noel Parks (Managing Director of CleanTech and E&P)

Hi. Good morning.

Nick Dell'Osso (President and CEO)

Morning.

Noel Parks (Managing Director of CleanTech and E&P)

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? I was thinking about that in the context of sort of, if service costs, even with a little bit of relief on inflation, if they stay high, if, you know, sort of the rig and frac 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. I just wanted to check on that.

As far as you can tell, still no signs of any relief on sort of the overall equipment capacity front.

Josh Viets (EVP and COO)

Yeah, Noel. I mean, clearly through the end of last year, you know, we saw, you know, really high utilization rates of, you know, the high spec rigs and frac fleets. You know, as we're out, you know, talking to service providers, you know, we're not seeing any strong signals of them in deploying capital into new equipment. Where 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. You know, they are starting to realize the operational efficiencies and cost efficiencies associated with those. We are seeing some of those start to come out into the market. In most cases, when they bring that in, that means they're retiring a less efficient, older piece of equipment.

Generally the diesel fuel units. I think, you know, as that overall capacity across the service sector remains tight, I do think that, you know, can potentially, you know, longer term, you know, create a little bit of a headwind for us from a service cost standpoint. That's why we remain so focused on partnering with the best service providers in the industry, to help, you know, drive additional operation efficiencies, which, you know, in turn offsets any future inflation that we could see.

Noel Parks (Managing Director of CleanTech and E&P)

Great. Thanks. Just wonder, you know, 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 from the Permian, in terms of, well, I guess, you know, supply to the Gulf or in terms of what impact that might have on sort of longer term LNG?

Nick Dell'Osso (President and CEO)

Generally, Noel, you know, we think with oil prices remaining constructive, the pipes that are built from the Permian to the east are gonna be full. That's kinda how we think about how to model associated gas.

Noel Parks (Managing Director of CleanTech and E&P)

Okay, fair enough. Thanks a lot.

Operator (participant)

The next question comes from Subash Chandra of Benchmark. Please go ahead.

Subash Chandra (Energy Research Analyst)

Thanks. Good morning, everyone. Just a follow-up. Good morning. Follow-up on the Haynesville rig view. You know, 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, you know, whether summer materializes, all that macro stuff that could pressure prices in the third quarter, for instance, then we could see another leg down. You know, specific to Chesapeake , what is your willingness to incur any, you know, early contract termination penalties to accelerate, you know, rig drops on your end?

Nick Dell'Osso (President and CEO)

All good questions, Subash. I think further drops than what are currently projected are gonna be reliant on the 2024 and beyond curve moving. I don't think you're gonna see rig drops come from just a summer crash of prices. Should that happen, should we hit a wall of storage going into November 1st and late summer, fall prices really fall on the front months. You know, if the longer term curve holds up, I don't think you see rig changes. If the longer term curve moves down, I think you do see rig changes. As far as our willingness to, you know, 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, you know, we have a staggered, set of contracts. We try to maintain flexibility where, you could make decisions like that and not incur penalties that would be cumbersome.

Subash Chandra (Energy Research Analyst)

Okay. Thanks for that. Nick, I guess on a, you know, some classification on the LNG ready, you know, strategy, because it seems like you have, you know, ample coverage of your current LNG direct LNG exposure. That, I think reading between the lines, you know, LNG ready does not mean maintenance, it means some level of growth. Does that mean, you know, a willingness or desire to have more direct exposure? I think you've sort of said that, you know, you'd like a bit more but maybe not a lot more. You know, I guess boiling the question down, like you have more than enough local production to satisfy, you know, your LNG exposure. Why growth at all, I guess?

Nick Dell'Osso (President and CEO)

I think we've been pretty clear and consistent in our message that we're comfortable with 15%-20% of our total gas production as a company being priced under international prices. The concept of being LNG ready means that we wanna be connected to the right infrastructure, have the contracts in place, and then as the US market grows from a, you know, approximately 100, 101 BCF market today to 110 over the next few years and eventually towards 115 or 120, we wanna be in a position to help supply that growth. That, you know, the decision around growing is far out in the future.

You know, 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.

Subash Chandra (Energy Research Analyst)

Okay. Thank you. Yeah, I appreciate that clarification. Thank you.

Operator (participant)

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 (President and CEO)

Thanks again. Thanks everybody again for the time this morning. You know, again, we're looking forward to the second half of the year here. As we go through these summer months, there's gonna 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 (participant)

The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.