Chesapeake Energy Corporation (NASDAQ:CHK) Q2 2023 Earnings Call Transcript

Chesapeake Energy Corporation (NASDAQ:CHK) Q2 2023 Earnings Call Transcript August 2, 2023

Operator: Good morning, and welcome to the Chesapeake Energy Second Quarter 2023 Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Chris Ayers. Please go ahead.

Chris Ayres: Thank you, Marley. Good morning, everyone, and thank you for joining our call today to discuss Chesapeake’s second quarter 2023 financial and operating results. Hopefully, you’ve had a chance to review our press release and the updated investor presentation that we posted to our 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, there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including factors identified and discussed in our press release yesterday and 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 any undue reliance on such statements. We may also refer to certain non-GAAP financial measures, which help facilitate comparisons across periods with peers. For any non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measure and can be found on our website. With me today on the call are Nick Dell’Osso, Mohit Singh and Josh Viets. Nick will give a brief overview of our results, and then we will open up the teleconference to Q&A. So with that, thank you again and now turn the teleconference over to Nick.

Nick Dell’Osso: Good morning, everyone. Thank you for joining our call. I’ll give a quick highlight of some recent accomplishments, and then we’ll jump to Q&A. We had an outstanding operating results this quarter, and we continue to execute on our strategy and deliver sustainable value to shareholders through cycles. Our performance at the field level remains strong, and I’m pleased that our team continues to find innovative ways to enhance our basin-leading operating performance. We often get asked if the industry has run all of the efficiency opportunities out of the equation. We’ve highlighted some things today that I think show we have several innings to go. To start, we rapidly improved our drilling operations this year behind a combination of data analytics, machine learning, the high grading of our rig fleet and equipment.

These advancements allowed us to drill three of the five fastest Marcellus wells in our history during the second quarter. This included a team best 10,000-foot lateral, which reached a total depth of 17,000 feet in under eight days. We saw equally strong results on the completion side as well. We deployed new equipment and technologies to yield recent company records in both the Marcellus and Haynesville leading to a greater than 20% increase in efficiencies relative to previous zipper frac operations. In addition to our strong drilling and completion performance, the team continues to push the boundary of our development strategy. Our hybrid well design in the Marcellus combined stranded lower Marcellus acreage with accretive Upper Marcellus footage into a single extended wellbore, eliminating the need for multiple vertical sections and reducing surface impact.

The design yields a much more efficient capital spend and greater than $3 million incremental NPV per well. I’m also pleased to see extended laterals in the Upper Marcellus deliver similar per well productivity to the prolific lower while decreasing our drilling cost per foot. Overall, across our entire Marcellus program, our average lateral length in the basin has increased by 70% over the last five years. Moving to the Haynesville. Our effort to optimize our acreage position through acreage trades and growth leasing has converted nearly 105,000-foot lateral locations to 10,000 feet. Resulting in an incremental NPV uplift of between $3 million to $6 million per location. Combination of all of our leasing efforts has increased our working interest on near-term projects by approximately 4%.

Our ongoing effort to debottleneck our midstream systems in the Haynesville is also paying dividends through lower line pressures and higher production. And we have recognized a 70% increase to offload capacity over the last year through expansions and additional offloads. As we continue to optimize our operations in the Haynesville, we’re also importantly progressing with our path to be LNG ready. Our recent Lake Charles agreement – our recent agreement with Lake Charles for liquefaction advances our previously announced agreement with Gunvor to deliver gas for LNG on a JKM linked price exposure. In addition to the impactful innovations, I’m really pleased we can lean on our financial strength this year and allocate capital in a prudent and value-oriented way for shareholders, given the low prices in the current market.

The flexibility is a competitive advantage and enables us to focus on smarter decisions for value creation through cycles. In today’s market, that means voluntarily reducing activity levels and deferring TILs in production in periods of stronger pricing. While our second quarter production reached the high end of our quarterly guidance at approximately 3.7 Bcf per day, Our second half 2023 activity will be approximately one-third lower than our first half as measured by rig spuds, completions and CapEx. As we reduce our, spend on development activities, we continue to buyback shares and have increased our base dividend. In addition to our return program, we are using our strong position to strategically lease acreage. Year-to-date, we have added approximately 10,000 acres in our Marcellus and Haynesville footprint at an average cost of $2,400 per acre and expect more opportunities to add valuable acreage in the second half of the year focused on improving and adding to our inventory length.

We’re doing all of this as we continue on our path to reaching an investment-grade credit rating. Today, our net debt to total cap is about 10%, and we received two recent upgrades from our credit rating agencies. We expect that our balance sheet will be further strengthened through the completion of our Eagle Ford exit, which continues to progress. Our capital allocation strategy prioritizes shareholder returns and has resulted in more than $500 million being returned to shareholders so far this year, while gas prices have fallen significantly. Our approach includes a stable and growing base dividend, which has returned $150 million year-to-date in which we raised 4.5% this quarter. Our procyclical variable dividend, which has returned $185 million year-to-date, and our countercyclical buyback program, which has returned $185 million in share repurchases, including $125 million during the second quarter.

We remain the only large-cap gas company consistently paying a dividend and repurchasing shares in today’s market. Turning our attention to the rest of the year, our approach will not waiver. The underlying strength of our company allows us to remain patient and prudent and that’s exactly what we will be. We’ll continue to make decisions focused on long-term value, which means we will execute on our strategic pillars, maintain our capital discipline and further adjust activity should levels – further adjust activity levels should conditions warrant. And lastly, we’ll remain steadfast in our commitment to maximizing value for shareholders. We’re pleased to address your questions. And so operator, if you’ll open the line.

Q&A Session

Operator: Thank you very much. [Operator Instructions] Our first question comes from Umang Choudhary from Goldman Sachs. Please Umang go ahead.

Umang Choudhary: Good morning. And thank you taking my questions.

Nick Dell’Osso: Good morning, Umang.

Umang Choudhary: Good morning. My first question is really a two-pronged question. First, would love your thoughts around the gas macro. And two, you have talked about contracyclical repurchase risk management through hedging and also maintaining the optionality of a fortress balance sheet, given the volatility of the underlying commodity. How does the macro influence your thoughts around the cadence of share purchase and the extent of hedging?

Nick Dell’Osso: Sure. Those are great questions. I’ll start. So first, from a macro perspective, the supply demand has been pretty challenged this year. We’ve seen the industry respond. We think pretty well through cutting activity. We cut activity. We announced cuts activity early in the year. Those cuts are really showing up now. We deferred TILs even earlier than the activity cuts showed up. So that pulled some gas off or smoothed it out in the year, and we think that’s been helpful. We certainly think it’s been helpful to our own cash flow profile. We’ll continue to make those kinds of decisions as we approach ’24. We think that the market is poised for a recovery from a supply-demand perspective as we have cut through activity levels and we have growing demand in the form of LNG capacity coming online.

What we’re not great at doing, of course, individually or as an industry is predicting the exact timing of that. So, we’ll let the market show us. We don’t expect to be way out in front of a move like that, and we’ll look for some really tangible signs, that things are improving before we bring activity back. And that’s really what I’m getting to when I talk about, our leaning on our financial strength to make those kinds of decisions. I think they’re prudent and smart decisions, and I think you have to have a lot of financial strength to be able to ride through cycles and continue to make prudent decisions without leaning in too hard at times when there’s great uncertainty. We just don’t have to do that. So we feel good about that. From a hedging perspective, we’ve approach hedging with a very methodical view around how to add hedges looking out on a rolling 8-quarter basis.

We’re going to continue to do exactly that. That has served us well. It offers a really nice offset to our cash flows this year. One of the things that you’ll see, of course, is that we have a pretty sizable hedge gain through the rest of the year. That really helps to offset how we think about these changes in activity levels and allow us to smooth them out in a way that is – it reduces the friction cost of those changes in activity. One of the other things I’d point out is that you’ve seen our differentials really get challenged this year, and it’s been pretty tough, particularly in the Northeast. But we have a lot of basis hedges as well. So it’s not just index hedging, it’s basis hedges. And those basis hedges are serving us well as an offset to those differentials.

So, they show up in our realized hedging, and lines on the income statement that there are basis hedges embedded in there in addition to NYMEX. And then lastly, how we think about the buyback cadence, certainly, the macro plays a role in that. We announced our buyback, the increase to our buyback, I guess, about a year ago, and we’re progressing really well with that. We have $725 million remaining. We have quite a lot of cash and we expect to continue to progress against that buyback. We’re going to look for opportunities to accelerate that buyback, into the second half of the year. And ultimately, we’ll finish it when the conditions warrant. But we feel really good about having the flexibility to deploy that cash prudently, and carry out our buyback program as we think maximizes value for shareholders over time.

Umang Choudhary: Very helpful response. Thank you so much, Nick. If I can just add one more in. A lot of interesting things on the operations side of the equation. On Slide 9, you’ve talked about the hybrid well design in Appalachia, combining the lower Marcellus and Upper Marcellus in a single wellbore. Would love your thoughts around the design, your confidence in execution? And how much of the program is it today? And what do you expect going forward?

Josh Viets: Good morning, Umang. So to-date, we’ve executed four of these. And so I would say our confidence in our ability to execute is quite high. I think we’ve proven through the years as a company, our ability to really be innovative with complex well designs. The hybrid well design is an example of that in South Texas, we’ve done U-turn wells we’ve done W-shaped wells. And so, I think our technical and operational teams have really proven that we have the ability to be innovative and capture and create incremental value from these assets that we own. We will execute about five more of these as we work through the back half of this year. As we’ve stated, we have around 50 yet to execute in the program. We’re constantly kind of critiquing our acreage position, the remaining inventory and looking at all opportunities to enhance value from the assets.

So, we’re pretty excited about what we’ve done, and we’re highly confident in our ability to execute, the hybrid well design that we presented to here today.

Nick Dell’Osso: So Umang, if I could just add to that. I mean, if you think about what we talked about both there with the hybrid well design as well as the leasing and trading program in the Haynesville, it’s all around finding more opportunities for longer wells. We know that longer laterals add value to a development program. And as you look back at some of the early developed areas of the play, there’s all kinds of acreage that stranded in there with short laterals remaining. And this is a way for us to go back and add life to some of the really great central core acreage across, these plays by adding in longer later opportunities that otherwise would have been shorter laterals. So, this is a really great development for us, something that we’ll continue to think about ways to bring some of these smaller lateral opportunities, back to the front of the development program, by creating opportunities to drill an ultimately long lateral well.

Umang Choudhary: Great. Makes a lot of sense. Thank you so much.

Operator: And our next question comes from Josh Silverstein from UBS. Josh, please go ahead.

Josh Silverstein: Yes. Thanks. Good morning, guys. Nick, you mentioned the remaining Eagle Ford package is still ongoing with the sale process. Just give an update there? Is this something that you’re just waiting for a higher natural gas price environment to execute on? And then as we’re thinking about shareholder return opportunities here with the balance sheet where it is right now, if this is divested, do all those proceeds go towards the buyback then? Thanks.

Nick Dell’Osso: Yes, hi Josh, we’ve talked all along about how we’re leaning with incremental return programs from the sale towards buybacks. So, I think you can expect that, that’s how we will talk about it once we’re complete with that transaction. But it is an ongoing process. It’s been an interesting process and that we continue to have multiple parties seeking to get to the finish line here. It’s been a challenging year to sell assets. The financing markets have not been super strong. But I think, we’re making good progress and hope to get something done. It’s front of mind for us, obviously.

Josh Silverstein: So thanks. And then in the Haynesville, you come from 7 rigs to 5 rigs. Can you talk about how you’re managing the declines with the lower rig count and what kind of optionality or flexibility you’re leaving in for 2024 if prices don’t stay around the 350 level? Thanks.

Josh Viets: Yes. And so we’re — this is Josh. So we’re right in the middle of dropping rigs. In fact, we’ll go from six to five rigs this week. We are being very thoughtful about our productive capacity. We think it’s important to maintain that just simply to avoid any inefficiencies that will be created as we attempt to rebound into a more constructive commodity price environment. We do think flexibility absolutely matters. And I think that’s what we’re going to maintain as we get into the end of this year. Previously, when we presented our five-year outlook, we presented a case that indicated a sixth rig coming back in January. I would just say that’s something that we’ll continue to monitor. And really, I think we’re going to allow the market to signal that gas supply is needed.

And so we don’t really feel any pressure to get out and front run that. We’re happy for the market conditions to improve, and really pull us back into it. We think the key for us today is just being patient, being flexible, which is ultimately what our assets and our strong balance sheet really affords us to do.

Josh Silverstein: Okay. Thanks guys.

Operator: And we have a question now from Doug Leggate from Bank of America. Doug, please go ahead.

Doug Leggate: Thank you. Good morning, everyone. Nick or Josh, I don’t know which one of you wants to take this, but I have a slightly different micro question. One of the pushbacks we get on our sort of new dynamics of U.S. gas markets is the DUC overhang in the Haynesville. But when we look at the data, whether it be Rystad and Baris CIA, whatever, there seems to be a very big difference between what the industry seems to think and what we’re hearing from the company. So, I wonder what – if you could tell us what your DUC backlog looks like and maybe can trust that with what you’re seeing the agencies are reporting your DUC backlog looks like?

Josh Viets: Yes, good morning, Dough. This is Josh. We would agree there is a lot of noise in the public data on DUCs. It’s a relatively complex metric to track accurately. But I think, we would generally align and that this metric is most commonly overstated. And of course, the implication for that is it would indicate that if you were to believe the current numbers of something over 700 in the Haynesville that there’s a supply overhang that could potentially impact any type of recovery. So, I think there’s several reasons for that, which may be fall into noncore zones being included in that, which really can’t contribute you have maybe mismatches on how many units of production a rig or a frac crew is creating. And then also, you just have a case of abandoned wells that simply don’t get taken out of that, that will do to maybe mechanical reasons will never be completed.

So, I think the best data we have is really looking at our own data set. If we were to extract from public sources, what they see our DUC inventory in the Haynesville beam, it would put us at 45%. What we see is the majority of these roughly two-thirds are actually sitting on pads that we’re actively drilling. And so therefore, they’re not considered true DUCs in any sense of the word. And so, that leaves us with about 15 what we would consider to be true DUCs. If you consider about three wells per pad, that leaves you with about five pads. And if you run in two frac crews, that would put you into a pretty normal working inventory. So again, the implication of this, you have roughly maybe two-thirds overstated. And ultimately, where that would maybe put the Haynesville is probably something closer to 150 to 200 DUCs as opposed to the 700 that stated and other publishers.

So again, that’s just using our internal data to kind of back into maybe where the industry sits as a whole.

Doug Leggate: That’s really helpful color, Josh. Thanks guys. Is the kind of way I was going with that, but I wanted to just sense check it so thank you for that. My follow-up is hopefully a simple question. My understanding is you’re largely done with activity now in the Eagle Ford. So, to the extent you can looking at your cadence of your capital, which I realize is a little under where you would normally be. It looks so as that your sustaining capital has come down quite a bit. So portfolio go forward ex Eagle Ford, what would you say that current capital outlook and main capital outlook looks for maybe ’24 and beyond down there? Thanks

Nick Dell’Osso: Yes. Hi Doug, I’ll start with this, and Josh may have something to add. But the way we think about sustaining capital is really about what development profile it takes to maintain production. And that really hasn’t changed for us in both the Marcellus and the Haynesville. It’s around five rigs in the Marcellus and around six rigs in Haynesville. And obviously, at different times, you can you can either slow that down or accelerate that by either adding or subtracting a frac crew. And so, there’s a ratio of rigs to frac crews that equate to an exact maintenance level there. But right now, we’re a little below that and that’s by design. And so as we go into next year and we see the clear signals of the market recovery and we see the market looking for more supply, then we’ll go back to that level and always maintain the ability to increase above that for true growth should the market need the volumes.

So when you think about modeling us, think about five rigs in the Marcellus, six rigs in Haynesville, that’s going to get you a pretty good maintenance capital level for us.

Doug Leggate: Got it. Thanks Nick and appreciate the answers.

Operator: Our next question comes from Matt Portillo from TPH. Matt, please go ahead.

Matt Portillo: Good morning all. Maybe just to start off, a question for Josh. On the Haynesville, looks like the asset has been outperforming expectations year-to-date. I know you talked a bit about some of the infrastructure expansion occurred. Could you just talk about some of the operational tail you’ve seen at the field level? And do you expect additional gains going forward?

Josh Viets: Yes. Good morning, Matt. We have seen very strong performance out of our Haynesville asset through the first half of the year, and it is largely related to infrastructure. I would just maybe comment as far as new wells, everything there looks relatively in line with expectations. And so, the outperformance is largely coming from the base. And a large part of that is from our 2022 TILs. And one of the things we worked very hard at last year was introducing interconnects between adjacent gathering systems. And so, what that has allowed us to do is any time we see a pressure response as in a midstream upset, potentially adding pressure into system that’s alarming our operations center. And then, we quickly have the ability to work with our marketing teams to redirect flow.

And what that translates to is less downtime associated midstream outages. And that’s ultimately what’s allowed us to outproduce relative to our own forecast. And really, it’s just simply demonstrating the strength of our underlying asset there in the Haynesville.

Matt Portillo: Great. And then a follow-up question. I know you guys have been quite active on the LNG front. You’re making some great progress there. Just curious how those negotiations have evolved and maybe how potentially reaching investment grade going forward could potentially improve your position on the LNG side of things?

Mohit Singh: Yes, Matt. Good morning. This is Mohit. I’ll take that. We are very pleased with where we stand today. So if you recall, in March, we announced our heads of agreement with Gunvor. So that was going to be the buyer of LNG. And then since then, we’ve been working jointly with Gunvor to high-grade the facilities that we would liquefy through. And just it’s your main here, the methodology we used to high grade has five different dimensions. One is accessibility, which is – which means do we have a way of transporting, our gas from the field to that LNG facility. The second one would be the pricing, of course, which is how much liquefaction fees do we have to pay. The third, which was important to us was also the accounting treatment, whether it gets treated versus not.

So, we’ve made a ton of progress on that front as well. And the fourth one would be just the credit requirements, which you referenced us not being investment grade, but we have come up with some creative ways of circumventing that, which feels very good. And last but not the least, is the picking a facility that will get to FID. So that gets to what is the probability of them declaring FID on a time line that works for us. So based on using that methodology, we have high graded to a few facilities. And you recently saw, we signed a heads of agreement with Energy Transfer on the Lake Charles facility. So pretty excited. There’s three parties involved now us being a willing seller. Gunvor being the willing buyer there and then taking it through Lake Charles.

That’s not to say that’s the end state. We have previously signaled to you we want to get 15% to 20% of our production linked to LNG. This is a step towards that. And you should clearly see us announcing similar deals in the future. There’s a lot of conversations going on. And I’m very, very proud of the efforts that the team has put in and the progress that we have made.

Matt Portillo: Thank you.

Operator: Our next question comes from Zach Parham from JPMorgan. Zach, please go ahead.

Zach Parham: Yes, thanks for taking my question. I guess just starting on cash taxes. I know there were some moving pieces with the numbers this quarter. But the updated cash tax guidance indicates that $0 million to $50 million of cash tax payments for the year, and that includes the taxes associated with the Eagle Ford sale. Can you just clarify what your expectation is for cash tax payments in the second half of the year?

Mohit Singh: Yes, Zach, good morning. This is Mohit. So as you referenced, our guidance for the full year still remains $0 million to $50 million. That is unchanged. What has changed also, as you pointed out, is that includes our base business and also divestitures. The way you should think about it is the cash outflow net us again, stays between $0 million to $50 million.

Zach Parham: And just to clarify, is that for the second half or for the full year?

Mohit Singh: No, that’s for the full year. That’s for the full year.

Zach Parham: Okay. Thanks. And then just one follow-up. In the slide deck, you provided some pretty granular detail on cost deflation, highlighting total deflation of 5% to 7%. Can you talk about any differences in deflation you’re seeing the operating area? Are you seeing a little more deflation in Haynesville versus the Marcellus just given the level of activity declines there?

Josh Viets: Yes, good morning. This is Josh. We – just like we saw some differential level of inflation in the Haynesville relative to the Marcellus I think we would expect to see the deflation behave somewhat similarly. I think that’s going to be somewhat dependent upon though the service and also the contractual terms at which we’re working under. And that really just going to depend or we have something under long-term contract in the Marcellus, whereas we have contracting flexibility in the Haynesville today. So, I think long term, I think you would expect to see probably a little bit more deflation in the Haynesville. But I think the timing of it is going to be more dependent upon your contract situation, than it is so much what’s occurring in the fundamentals of each basin.

Zach Parham: Got it. Thanks for the color guys.

Operator: And our next question comes from Bert Donnes from Truist. Bert, please go ahead.

Bertrand Donnes: Hi. Good morning, guys. Just want to follow-up on the LNG question. Can you maybe talk about what’s the next step for Chesapeake? Are you more focused on locking in your existing volumes with liquefaction? Or are you more focused on finding additional volumes and then you’ll just kind of backfill liquefaction after the fact? And then maybe if you could pull the curtain back a little bit and describe the power dynamic in some of these negotiations. Is energy transfer – pitting you guys against each other? Or are these agreements so far out that everybody is going into these negotiations very comfortably?

Mohit Singh: Yes. Good morning, Bert. This is Mohit. I’ll take that. The strategy on the LNG side remains unchanged for us. When we initially announced it, the plan was to get diversification of our production. And the way we view LNG is just another sales point for us. So, when we say 15% to 20% of our production should be linked to some sort of an LNG index, the intent is to – just look at the overall portfolio and we view that 15% to 20% is just a sales point similar to say, Tedco M3 or any sales to CGML in a Haynesville. Now, we do go in eyes wide open that there will be periods of time where that diversification will be in the money. There will be periods of time when it will be out of the money. But we are looking at a long-term duration 15-plus years of duration on these contracts.

And the expectation is that we reduce the overall risk in the portfolio and the risk for the returns, which underpins our returns back to the shareholders by doing this diversification. So that’s the broad strategy behind this, and that remains unchanged. The second part of your question about the power dynamics in these conversations, the LNG universe, is pretty tight-knit group. We have been working – making inroads for the past year and a half at least. And what I would say is once we did announce our first heads of agreement in March, that suddenly created a lot of interest in what Chesapeake was doing and the number of inbounds that we have received since then has been great and working together with Gunvor, we have high graded as I said, some of the facilities that we want to go through.

So, it’s a pretty competitive space and us announcing our heads of agreement suddenly increased visibility and – we were very excited to see that increased traction that we were getting. And as we referenced earlier, that led to the heads of agreement that we have signed with Lake Charles, and we think more of these – you should expect us to be announcing some more of these.

Bertrand Donnes: That’s great. Thanks. And then shifting gears. I think you kind of touched on it earlier, but on the buyback front, you guys obviously have a large cash balance. And so, some investors are probably pushing for you to use a significant amount of that to do buybacks now. Could you maybe talk about what – how you guys have your internal formula for that? You just want to do a certain percentage of your float? Is it opportunistic based on market drivers? Or are you reserving some amount of cash for optionality in the market? Just your buybacks aren’t linked to your free cash flow. So I just want to get a little more color on how you decide when to enter the market?

Nick Dell’Osso: Yes, hi. This is Nick. All those things are relevant to us. We certainly think about how we’re valued at any point in time, and that drives how we think about doing repurchases. We think about a consistent approach of wanting to make sure that we – what we’ve said before, we’re not just going to warehouse cash. So, we want to be delivering cash back to shareholders. But, we definitely think about the macro environment, and think about what we expect to come about. And there’s been a lot of uncertainty this year. There’s been a lot of volatility in gas. We don’t think that volatility is over. We’ve been active with our buyback program and like the fact that even with that uncertainty, we’ve been active and we’re positioned to continue to be active.

So, we’ll look for opportunities to do more, but we’re going to be pretty prudent about it, and we’re going to approach the second half of the year looking for the right times to deploy cash through the buyback in a way, that we think is good for shareholders in the long-term. We do think about having some cash on the balance sheet. We think that’s a nice thing maintained when you can. And right now, we have that flexibility. So, we don’t have a specific number that we talk about with investors, but we certainly think that holding a cash balance is a good thing. So, we have a lot right now. And we’ll continue to deploy it, and we’ll see how the market unfolds for us. But I would expect us to continue to be quite active. And like I said before, we’ll look for opportunities to do more.

Bertrand Donnes: I appreciate. Thanks guys.

Operator: And we have a question now from Paul Diamond from Citigroup. Please Paul, go ahead.

Paul Diamond: Good morning. Yes. Thanks for taking my call. Just a quick question on Slide 9, talking about the hybrid well you guys highlighted in the Marcellus. Does that – and you guys view over the long-term, is that tech – that transferred down to Haynesville as well between Haynesville and Bossier?

Josh Viets: Yes. Good morning, Paul. This is Josh. I think we’re constantly going to be looking for opportunities to replicate technology and operational practices and other basins there’s unique differences between the Marcellus and the Haynesville that probably makes that a little bit more challenging distances true vertical differences between the two formations is one general rock characteristics that require certain bud types as another. So, I would never say never. Paul, because our teams are capable of doing some pretty phenomenal things. But today, I would say that looks like a pretty tough feat to accomplish.

Paul Diamond: Understood. Thanks. And then just a quick follow-up as well on you guys gave a bit of breakdown on your expectations around coming to flationary environment. I was wondering if you could give a bit more color on those that you see going down 3G [ph] rigs, pressure pumping sand and logistics? Is there any one or few that stand out more than the others? Or are they all kind of like right in that mid-single-digit range?

Josh Viets: Yes. Paul, I’ll take that again. So right now, I mean, I think the one that is probably easiest for us to see and really think about how impactful it could be is on the OCTG side. There’s just a general surplus of inventory. Imports are high. U.S. mill capacity has been healthy over the last year. And so that’s created a little bit of surplus. And so really, it’s not about, I think, the magnitude. I think we think that it’s going to be quite material as part our savings go, but just timing. And we have inventories of pipe that we bought out in advance we need to work through that. And so as we get into the fourth quarter, we start realizing the benefits of that. I think the others, maybe just described as being a little bit more sticky.

It’s going to be dependent upon really where we see rig counts going, not just in the gas basins, but places like the Haynesville is going to be impacted by activity in the Permian. And so, I think right now, I think we feel pretty good about seeing softening in the pressure pumping side I think with oil commodities being relatively modestly priced today, diesel prices are low, which really help support lower logistical cost on sand. And then rigs, rigs are typically under longer-term contracts. And so in order to realize that, you really have to have managed your contract situation to be in a position to go renegotiate and bring in rigs at lower rates. So I think the market conditions are primed for that. But I think the pace, the magnitude really is still up in the air.

The work that we’ve done to date has taken us to a spot of where we see that roughly 5% to 7% reduction from Q1 of this year to a well that we do in Q1 of next year. And we think that’s a pretty good down the road level. And it is also going to – just want to point out, that will exclude any efficiency improvements or changes to lateraling. So potentially some upside on that as well as we head into 2024.

Paul Diamond: Thanks for clarity.

Operator: And our next question is from Scott Hanold from RBC Capital. Scott, please go ahead.

Scott Hanold: Hi Nick, it sounded like you all are optimistic, but somewhat cautious on the gas macro outlook. And obviously, that is when you look in ’24 in your activity pace, it leads you to kind of hold off some decisions at this point in time. But what specifically are you looking for to get more, I guess, more constructive where you’d look to add back, those rigs next year? Is it just the price? Is it your amount of hedging? Is it where storage is at on a relative basis? So, if you can give us just a sense of what specific trigger points are there that you’re really focused on?

Nick Dell’Osso: Yes, Scott, great question. We’re focused on the fundamentals. So, we’re focused on certainly where storage ends this fall, what that positions the market to look like as we come through winter and out of winter into the spring, what production is doing relative to that storage level. all of those things, of course, factor in. And then, the big wild card that we always face this time of year is what, will winter be. No one knows. Early predictions of weather usually are highly inaccurate. So we don’t put much stock in those. And we’ll watch and see what happens with winter demand. And then the longer-term trends for demand for gas are very strong. We’re continuing to see power gen for gas performed well on a weather-adjusted basis.

We’re seeing domestic demand for gas hold up quite nicely despite the predictions of recession and economic pullback in the country. We watch for those things to hold. Are they holding? And then, of course, very importantly, on the demand side, we’ll pay attention to the timing of the LNG facilities. That growth in demand will be very impactful, but also very chunky. And so if there are changes to those schedules that will impact us. We feel good about what we’re reading on those projects. We don’t have any better information than anybody else has on those projects. I think the market is gaining confidence in the time line of those projects, and we would for share in that same view but we’ll allow again, the fundamentals of the market to show us that the market actually needs supply before we lean out really far in front of that.

Scott Hanold: Okay. It definitely sounds more of like a very real-time kind of monitoring situation. So certainly, I appreciate that?

Nick Dell’Osso: Again, I would point you there though, Scott, if you don’t mind me adding is that we’re talking about right now, we’re at four rigs in the Marcellus and five in the Haynesville. So we’re really talking about being one rig in each play below what we’ve indicated as our maintenance. So the amount of change that it would take for us to change the trajectory of our production is not much. And that’s by design. We have wanted to pull back capital so that we can allocate our capital in a really prudent manner in a soft market, but we also don’t want to be in a place where there’s tremendous friction costs of a pivot. And that’s why you hedge, and we think all of that is working for us. And so when we decide that we’re ready to respond to the market, when the market shows us it’s time to respond, it’s not going to take a heroic move on our part.

Mohit Singh: Scott, if I may add on the hedging, this is Mohit. The – so, we’ve added about 174 Bcf of hedges since our last disclosure. When you look at our hedge book, we feel very, very good about the downside protection that it offers and the width of the callers fairly wide. So, it retains the upside while at the same time, protects us from the downside. So, if the bare scenario plays out, then we feel very good about the floors that through the callers. But at the same time, with the bullish new plays out, then we are retaining quite a bit of the upside through the white collars.

Scott Hanold: Okay. Got it. And my follow-up question is a little bit on M&A and obviously, the strategic I guess, tactical bolt-ons you all are doing. Just big picture, like what are you – what is your appetite on M&A? Is there attractive things out there? I mean you talk about financing being issued with some of the car parties on the Eagle Ford side, but with your quantum of cash balance, does that provide you the opportunity to be a little bit more countercyclical with M&A right now? Is there things out there that are attractive? And just give us a sense of the scale of some of the bolt-ons that we could see moving forward?

Nick Dell’Osso: We’re always paying really close attention to what’s available. And so there are things that are attractive, but attractive at what price you have to have a motivated seller or a seller that’s willing to transact. And we stay in contact with a lot of people about a lot of things. We’ve been quiet now for several months on the acquisition side. So, I think that tells you that the things that we’ve been interested in, there’s probably a bid-ask spread there or at least uncertainty part of sellers as to what their strategic direction may be. But there’s always a side if there’s good available acreage at a reasonable price, we always want to add. But we’ll be patient and needs be patient now for a while. We don’t feel in a rush to do anything.

And so, we’ll watch and see what comes our way. We do have a financial strength to do something should we decide to. And so, I appreciate you raising that point, because that is a part of financial flexibility that we think is really important to maintain. If there are good attractive assets to buy at a time when others maybe are not able to be as aggressive, that’s a real strategic advantage. So, we try to hold on to that, and we can wait for those things to come to us.

Scott Hanold: Thank you.

Operator: And our next question comes from Roger Read from Wells Fargo. Roger, please go ahead.

Roger Read: Thanks. Good morning. I guess I’d like to follow-up on maybe a couple of the last questions here in terms of your service contracts, your willingness to, I guess, be proactive or reactive in terms of committing to get up to the maintenance level of drilling and then maybe something beyond that as the macro gets more favorable, latter part of ’24 to ’25. So as you think about whether it’s rigs or materials or the pressure pumping side, just how does the market look there? How do you current – how does your current contract status compared to maybe an ideal contract status as we look over the next, say, 12 to 18 months?

Josh Viets: Yes, good morning Roger. This is Josh. As far as contracts go, when we look at our rigs, roughly half of our rig fleet of line that will be in service kind of as of the end of this week, roughly half of those will come up for renewal by the end of the year. So we have some flexibility with that to potentially take advantage of softer markets. And I would actually say on the frac side, it turns out that it’s pretty similar to that. We’re roughly half of the half of the fleet is on shorter-term contracts, and we have one. I don’t know, a longer-term contract, but will come up at the end of the year. So we think we’re actually pretty well positioned to be able to action structural adjustments that will ultimately lead to lower cost. That’s really by design. We think maintaining flexibility across contract tenors is always going to work to our advantage and provide us, the flexibility that we think is important for our business.

Roger Read: And then willingness or I mean, I guess, earlier, I think you answered the question, which is you’ll wait for the market to show you it needs more production rather than trying to anticipate. Just wanted to clarify, if I understood that comment correctly?

Josh Viets: Yes, Roger. This is Josh again here. That is absolutely true. And as Nick was commenting earlier as far as the macro, we want to see this 2024 shape up a little bit more. We just don’t feel the need to aggressively start adding activity back, until there are very clear market signals that the gas is, in fact, needed. So it’s fairly dynamic. But we think, again, flexibility matters. And we think the strength of the company really affords us that flexibility.

Roger Read: Okay. And then my follow-up question on cash taxes. I understand the guidance for this year. Mohit, this is probably for you. But as we think about a better gas price environment going forward, is there any sort of linear expectation between where prices and how we should think about cash tax obligations?

Mohit Singh: Yes, Roger, this is Mohit. Yes, certainly, when you think of our tax outlay for this year, there’s a couple of components. One is how much we would pay on the divestitures. That one is pretty well settled because we know the numbers. To your other point, the unknown would be what are the prices the – what are gas prices doing and how much of a tax leakage, the base business is generating. And that’s a little bit of an unknown. When you think of the refund that we have received in 2Q from IRS and that was linked to us overpaying last year just because the prices last year, if you remember, they were strengthening. And then when they started weakening, we had overpaid based on the estimates they had initially. So, the volatility will remain.

Unfortunately, that is an unknown as to what prices would do. Our guidance, as I said, just to reiterate, is on an all-in basis, including the divestitures in the base business. Our guidance for now still remains between the $0 million to $50 million of net cash flow adding up all different components. And probably that’s the best guidance we can give at this point.

Roger Read: Okay. Thank you.

Operator: And at this time, we’ll take our last question from Subash Chandra. Please Subash from Benchmark forgive me. Subash, go ahead.

Subash Chandra: Great. Yes. Thank you. So Nick, I think you talked about equity stakes and liquefaction as being a separate effort and maybe something that’s not imminent. But a two-part question there, I guess, on the LNG. First is if you have any updated thoughts on those opportunities? And then the other part on the LNG is if you had to handicap projects that get FID this year, how many do you think? Obviously, I assume Lake Charles makes that list?

Nick Dell’Osso: Hi Subash, so on equity stakes and projects, we’ve said that we would consider that if the right deal came along. We’ve talked to a handful of the projects about that. Not sure that, that will ever make sense for us. If it does, great. We’ve done – we’ve not been afraid to invest in for structure lately, we’ve done our momentum project, and that has proven to be, so far, very successful for us. And so things like that, that could be similar where it’s a relatively modest amount of dollars compared to our capital program. and give you exposure to a great rate of return because you’re derisking a project. We could think about that, but we’re not in a place where I would tell you to necessarily expect that coming.

So open to it but not necessarily anticipating it right now. . On the point about what gets FID-ed, we’ve got a slide in our deck where we try to show the tracking of what projects are out there. There’s a lot of projects that have been FID that are under construction, and we think there are a handful of others that are going to get there. We continue to think about what that really means to the LNG market, Rod. And a lot of the estimates about demand for LNG internationally are that we need all of this and more. So, I think as long as that continues to be the estimates hold up around the demand for gas internationally growing, then you’re going to see projects continue to get FID. The U.S. has a tremendous volume of gas resources. And we should connect those gas resources to markets where they’re needed.

It’s an advantage to the economy broadly from an export perspective, it’s an advantage to the economies that are importing a lower cost and lower carbon fuel. It’s an advanced consumers to have a more reliable – lower carbon fuel. So, I think there’s plenty of momentum for more LNG. I think it will continue, and I think we’re well positioned to pertain in that value chain.

Subash Chandra: Great. Thank you. My follow-up is on the Haynesville and sort of industry activity. I think you guys were spot on in calling for the rig drops even though they were slow to start. And if I recall, I think your view was that most of those rig drops would happen by the third quarter. So just about now, give or take, and then it would slowdown, if not stop. And so just wanted your thoughts on if that’s still the case and what replacement rigs are required to hold production flat?

Nick Dell’Osso: Yes. So, we have made all those changes now. You’re seeing that activity fall to the levels that we predicted right now. And one of the things that we did early this year to smooth out the effects of that or to get sooner effects of that is we did defer some TILs and we’ve had some reduced production particularly in the Marcellus. And so, you’re seeing that show up in our numbers where otherwise you might see stronger production had the demand been there for gas. We’re in a position where we can pull back on production and defer TILs in a way that makes a lot of sense given the market conditions and then allow for activity drop to take place in what is a more thoughtful cycle of decision-making. So in other words, you don’t have to run out and shut down a rig in the middle of a pad that it’s drilling.

You finish what you’re doing, you work through the plans that you have in front of you there where you’ve already started spending money and then you can make a better decision to reduce friction costs of changes in activity wells. So seeing that play out for us this year. We’re really happy how that’s gone. Modest changes to activity have a pretty big impact on how we think about what we’re doing from a production standpoint. That’s good. We like to have that lever to pull, and we’ve been able to pull it. So, we feel really good about how that’s gone for us. And then like I said before, we’re currently at four rigs in the Marcellus and five in the Haynesville, that’s one short of maintenance for both of those plays. And so, as we see the market recover, you’ll see us add back a rig in both of those.

And we always would have the option to go towards growth, should the market need that. But right now, we’re just focused on doing what we’re doing until the market shows us what supply is really required.

Subash Chandra: Yes. Sorry, Nick. To clarify, I was wondering about industry level activity. And yes. And if you think that industry Haynesville production will kind of mirror what you’re experiencing. And if truly that DUC count is a fraction of what’s publicly stated if maybe some of the views that Haynesville will hold firm are overstated as well?

Nick Dell’Osso: Yes. We think that the Haynesville has reduced to an activity level now that is maintenance or below. And when we thought that DUC count, Josh walked through a really good analysis of how we think about the cadence of rig count and cycle times and what happens. And one of the things that has happened this year, of course, is with reduced rig activity but also reduced completions. You are seeing the cycle times of wells expand a bit, and that’s underlying all the moving numbers that he walked through of the ratio of rig running to wells in process, to wells that are truly waiting on completion, you can affect that in the short-term with adding additional completion crews. But the market for completions has been relatively tight.

You are starting to see some completion crews now go to the side lines and stay there. But the market for completions has been tight. So, I think the Haynesville is in a place now of activity levels that are at mains or maybe below maintenance. That has a lag effect. So you’re going to still see production showing up from the activity of the last six to nine months for a bit. But we do think that the industry has made the right decisions around supply in the Haynesville, and we should wait for to show up.

Subash Chandra: Thanks so much.

Operator: And 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: Well, thank you all for the time this morning. We feel really good about where we sit in this year. It’s been a year of certainly reduced gas prices, but strong performance for our company. We are proud of that performance, proud of the way that we continue to return value to shareholders and really pleased with the setup we have for the future. Thanks again for your time, and we’re always available for questions offline after this call and look forward to seeing you guys out on the road. Thanks.

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