EXPAND ENERGY Corp Q2 FY2024 Earnings Call

Good morning, and welcome to the Chesapeake Energy Corporation Second Quarter 2024 Earnings Conference Call. All participants will be in listen-only mode. After today’s presentation there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference to Chris Ayres, VP of Investor Relations and Treasurer. Please go ahead.

Thank you. Good morning, everyone, and thank you for joining our call to discuss Chesapeake's second quarter 2024 financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation 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, 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 in other SEC filings. Please also recognize that as except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. We may also refer to some non-GAAP measures, which will help facilitate comparisons across periods and with peers. For any non-GAAP measure, we use a reconciliation to the nearest GAAP measure, which can be found on our website. With me on the call today are Nick Dell'Osso, Mohit Singh and Josh Viets. Nick will give a brief overview of our results, and then we'll open up the teleconference to Q&A. So with that, thank you again and now turn the time over to Nick.

Good morning. Thank you for joining us today. We are pleased with our quarterly results, which further demonstrate that our strategy designed to provide the greatest level of flexibility to manage unpredictable market conditions is working. And we are achieving meaningful improvements in capital efficiency and reductions in operating costs, which we believe will be durable when prices recover. Today, we are primarily focused on three key elements of our business. First, reducing costs and improving breakevens. We have recognized a 50% improvement in Marcellus drilling performance since 2022. We have achieved this by steadily increasing our feet drilled per day over the last two years by approximately 50% as well as by growing the average lateral length of our wells by nearly 3,000 feet in the second quarter. The increase in drilling pace, lateral length and deflation, all combined to recognize a 20% decrease in drilling costs over the last two years. In the Haynesville, efforts to lower production expenses continue to pay dividends, as evidenced by a 25% decrease in saltwater disposal costs per barrel since the third quarter of last year. This improvement is due to the team optimizing routes, increasing utilization of owned assets, strategic partnerships with vendors and deflation. Combined, these operational improvements allowed us to lower our full year capital and production expense guidance by $50 million and approximately 8%, respectively. Lowering breakeven costs is critical to delivering sustainable value to our shareholders and ensuring the market remains well supplied with affordable natural gas. We expect the majority of savings recognized will be durable through cycles, which will only continue to improve the strength and competitiveness of our Marcellus and Haynesville positions. Second, maintaining production flexibility to match market conditions. Through the first half of the year, we have deferred 46 TILs and built 29 DUCs. By year-end, we expect to have up to 1 Bcf a day of productive capacity available to meet demand when conditions warrant. In addition to the deferral of TILs and completions, we proactively curtailed volumes during the weaker spring shoulder pricing months and are prepared to do so again as necessary in the fall. We will be disciplined in activating the deferred capacity with market conditions dictating the pace and timing of our approach. We are confident this strategy will provide a distinct competitive advantage when natural gas demand recovers, given the inherent flexibility it provides and the speed and limited capital needed to bring volumes to market. Finally, we are focused on our pending merger with Southwestern, and our confidence in our ability to deliver the planned synergies is only growing. We are using the extended time between signing and closing to focus on our integration planning efforts and on delivering the synergies identified at the announcement of the merger, which we expect to close in the back half of the year. I have been extremely impressed with the openness and creativity of both organizations, as we seek to establish a business that has more talent, better assets and greater overall strength than either could have achieved as a standalone company. We look forward to seeing what we can achieve together once the deal closes, and we can fully unlock the power of our two organizations for the benefit of consumers and our shareholders. Our long-term outlook for natural gas, the affordable, reliable, lower carbon energy the world needs remains strong and we are working diligently to ensure our pro-forma merged company with Southwestern is poised to meet consumer demand at the most efficient price. I look forward to continuing to update you on our progress as we move through the year. We're now pleased to answer your questions. Operator, if you'd like to assemble the queue.

Our first question will come from Bert Donnes with Truist.

On the deferred activity, I just wanted to maybe clarify the strategy when you bring on the production. Does the price move qualify as improving market dynamics? Or does it need to be tangible supply-demand? And then, how do you think about rock bottom production levels? I'm assuming at one point, you kind of hang up your coat and say, listen, we've done our part. Is that 4Q '24 guidance kind of where you'd level out at? Or would you let it go below that?

Look, on the price signal, we see prices as nothing but a signal and we do pay a lot more attention to the underlying supply and demand than we do just price. Price is, in fact, a signal. So we will pay attention to that as well. But in terms of bringing on the deferred activity, we want to see the underlying fundamentals improve. As far as the bottom level of production, we could see things fall to. I guess we see the market improving while we aren't great at predicting the exact day or quarter it will improve, the overall dynamics that are setting up for us are pretty positive. So we're not too worried about that. I don't think we'll face that decision. We're going to continue to be prudent with how we manage our volumes and our capital program, and we are happy to be building the DUCs and details that we are now because it gives us a lot of operational flexibility. At some point, you would just slow down building those TILs and DUCs by reducing your capital if it continued into a much longer period of time. So we'll continue to monitor that. That would be how we would think about this. But right now, we're pretty comfortable with where we are doing what we're doing.

And then for the second one, I'm going to try to help you out here and get the words data center in your transcript a few more times. There have been some developments since last quarter with a lot of people talking about behind-the-meter deals. Do you think this is going to become maybe a catalyst-driven story where you announced an LNG contract or you announced a data center contract? Or is it just way too early in the cycle for you guys to start thinking about that?

I don't think it's too early for us to start considering it. We are in discussions with various stakeholders, including technology firms and utilities. We're excited that the market is beginning to recognize the growing demand for electricity, which has been underestimated for a long time. As we delve into the growth of electricity demand, we need to determine its sources. Natural gas is clearly a primary option moving forward. It's important to consider how these elements will integrate. We need to connect technology providers with data users and then to electricity generators and their fuel sources. These three components are currently engaged in discussions about various solutions. While the answers are not completely clear, collaboration will be essential to tackle geographical and regulatory challenges, as all three components require infrastructure. Achieving this will be complex, but essential to meet global demands, and we are prepared to address it. This presents an exciting opportunity for our company, which we are focusing on alongside our LNG projects that may have nearer-term potential. There are catalysts within this space, but the significant takeaway is not just a singular contract. It's the broader trend and its implications for our business's supply and demand fundamentals.

Our next question will come from Doug Leggate with Wolfe Research.

Nick, I know the FTC process, as you have observed many times, is still rambling on. But I'm just wondering, if you could opine on the extent to which you've been able to really dig deep on the full potential, whether it be drilling efficiency days to drill. The fact that Southwestern was running obviously very high fluid loadings, all that good stuff. What is your thinking on the $400 million at this point in terms of risk to that number?

The longer integration period gives us confidence that we are reducing risks every day. We are optimistic about reaching our target. There are numerous opportunities when merging two large organizations. Over the past several months, we have fostered a true collaboration between the teams working on the integration. We are examining everything from the IT systems to the processes and philosophies, such as fluid loading in a well. Our goal is to develop a plan for NewCo that effectively combines the strengths of both companies. We believe that achieving the synergy target is well within our capability, and we are certain we will deliver on that. Furthermore, we plan to continue our efforts even after reaching that milestone. We are enthusiastic about the possibilities this presents. While it would have been ideal to announce and close the deal immediately, we are making the most of this delay.

So maybe a quick part B to that. Would you expect on closing to give an update on the synergies or no?

I think we'll give an update on how we think about achieving them and timing for sure.

My follow-up, and I know you missed me on the last earnings call, so I'm going to try this one. Your variable dividend that you announced in the first quarter was paid out of your balance sheet this quarter. You're inheriting a lot of debt, assuming this deal closes. Can you give us some thought as to whether where you're going to prioritize the allocation of free cash flow that assuming the forward curve plays out in the context of dealing with your combined balance sheet versus transitory where I say, cash distribution that really has no impact on your valuation?

We are absolutely considering all of that, Doug, and we like our return framework. We're going to continue to think constructively about that return framework. But clearly, the pro-forma company will incorporate into that return framework a reduction in debt. We're going to work through that. And once we close, we can talk more about how that's going to play out. But the company needs to have less debt than it will day one when we close. So we'll take that into consideration. Mohit probably has some things to add here.

Just to add to what Nick said, when we take a step back from it, we are extremely proud of the $3.5 billion that we have returned to our shareholders since 2021. Obviously, as you identified it, the variable dividend is one of the components of it. We've done buybacks, we've done the base dividend in addition to that. We do recognize we will have more leverage once the transaction closes. It's a little bit too early for us to talk about what the plans would be post-closing. We will share some more details around all of that. But the commitment from our side to shareholder returns remains unwavering. And at the right time, we'll share some more details around that.

Our next question will come from Neil Mehta with Goldman Sachs.

Maybe you can spend some time talking about some of the deflationary trends that you're seeing. I think you called out a 10% deflation number. And as you think about the efficiency gains and the lower cost structure, has anything changed around that 350 mid-cycle view that Nick you've spoken to in the past?

Neil, this is Josh. I'll take the first part of that question. If you look back maybe into the fourth quarter of last year, we have seen a continual softening of service pricing. And of course, that's largely just driven by the pretty significant reduction we've seen around a 40% reduction in gas rigs between Appalachia and Haynesville. And so we've been trying to take advantage of that. I would say in the Haynesville, we've probably seen in the high single digits type of deflation. The Marcellus is going to be a couple of ticks above that, around 10%. I will say, though, that we're incredibly thoughtful about how we think about our service partners. We really value strong safety cultures, vendors that are going to be focused on driving performance. And so we're always going to be a little bit careful about just taking on the next lowest cost provider. We just don't think long-term that makes an awful lot of sense. But I think as we look ahead, I think to the back half of this year in 2025, I would say we are anticipating a little bit more weakness as we exit this year and some specific services. I would expect that pricing starts to moderate as we get into 2025.

And then the follow-up would just be your perspective on the LNG story. It's clearly, we got a big ramp ahead, call it, 10, 14 Bs depending on how you look at it. We've seen some volatility around Freeport and push out of things like Golden Pass. Just love your perspective on the multi-year outlook for the U.S. LNG ramp and how does Chesapeake fit into?

We're still really excited about the multi-year ramp in front of us on LNG. The world remains short energy and U.S. LNG is going to be a big part of solving that shortage and we're well positioned to deliver gas into that market and see the value of our gas increase as a result of how we deliver into that market at the same time recognizing that we'll be a very important source of supply for growing domestic demand for natural gas. So a lot of gas resource in the United States. We own a lot of it today. The pro-forma company will own more of it than anyone. And so we're very excited about what all of this represents. We think the opportunities are significant. You've seen a lot of headlines just recently with Woodside investing in Tellurian or buying Tellurian and giving some new momentum to that project, the Driftwood project there, just south of our asset in the Haynesville. LNG is moving and moving, we think, pretty constructively. There have been a little bit of delays in some of the projects that are coming on here in the near-term. But those projects are moving by months, not by years or decades. And so, we're fine with all of that. This is a very long-term dynamic that's playing out in front of us that we're extremely well positioned for.

Our next question will come from Zach Parham with JPMorgan.

During 2Q, you had some price-related curtailments and you've recently indicated that those curtailments have largely been brought back online. Nick, you mentioned in the prepared remarks that you were prepared to curtail again if prices were weak in the fall. Can you just detail what you would need to see from maybe a local pricing perspective to start curtailing some volumes in both the Marcellus and the Haynesville?

We'll stay away from giving you an exact price on that. You can certainly look back and see the prices in the spring and see that they got pretty low. So, if there's a repeat of some very low prices like that then we would curtail more volumes. One thing that's important to note in our projection is that we don't consider curtailment for price reasons in our projections of any significant magnitude. We sort of have a historical pattern of shoulder season reductions in volumes that's pretty modest that would be in there, but nothing beyond our historical pattern. So if there are significant price curtailments that would reduce our production in the second half of the year, which we're totally prepared and willing and ready to do if the market ends up showing us that it's necessary.

Zach, this is Josh. I’d like to add a bit to that. The market is very dynamic, and our teams do an outstanding job of monitoring conditions. Together with our marketing and operations teams, we evaluate decisions almost daily regarding the need for gas in the market. Additionally, we are focused on implementing our deferred TIL strategy. We expect a 17% decline in volume from Q2 of this year through the fourth quarter, which translates to just over 0.5 Bcf a day of production capacity coming offline. We are fully committed to restoring productive capacity when market conditions improve.

My follow-up, just on your operational plans. You're running a bit ahead of schedule on your deferred turning lines and DUCs that you're going to build this year, you took down CapEx by $50 million this quarter. If you continue to run ahead of schedule, is there room for CapEx to move incrementally lower? Or would you just enter 2025 with a few more deferrals than you'd originally planned?

At this point in time, I think we're committed to the activity levels that we've exited the second quarter at. Right now, we're running around four rigs in the Haynesville and three rigs in the Marcellus. For us, at this point, it's really about just monitoring the setup for 2025 before we would decide to adjust activity levels any further. At this point in time, we're kind of happy to carry the six to seven incremental wells as DUCs into 2025.

Our next question will come from Charles Meade with Johnson Rice.

I wanted to follow up on the topic of the PDP decline. It's a fascinating situation for us as we observe what seems like a quarter-over-quarter PDP decline from your end. I'm interested in what insights you have gained from reviewing this internally, particularly regarding the performance of your asset base, how you are managing it, and whether you are optimizing your midstream operations as you navigate this decline.

I find the PDP decline this year quite intriguing and worth exploring. In analyzing our assets, we've noticed that our PDP decline is performing slightly better than our models predicted. However, the market seems to struggle to grasp the nuances of this decline, especially since we experienced curtailments in the spring that made the decline appear more pronounced. As we resumed those operations this summer, the situation has stabilized. The underlying decline will likely become more evident as we move from Q3 to Q4, which is illustrated in our presentation. It's challenging for the market to recognize the subtle underlying decline as clearly as we can with our internal data. Undoubtedly, reducing field activity has a positive impact on performance, as it minimizes downtime from neighboring activity and enhances the efficiency of gathering systems. We can manage logistics more effectively, keeping water tanks full, and as a result, uptime improves. We have observed this trend throughout the year, and while it is encouraging and efficient, the impact is fairly modest. Our main interest lies in the fact that the underlying decline continues to trend downward. Reviewing various macro analysts' forecasts, we're not convinced that this situation has been fully taken into account yet.

I have a question about 2025. I know we can't predict how that year will unfold, but I'm curious if we can establish some estimates. When I examine your volumes on their own, it appears you're aiming for about 2.5 billion cubic feet a day in the fourth quarter, and you've mentioned you have a billion cubic feet a day of capacity. Does that imply that at the highest end, you could reach up to 3.5 billion cubic feet a day in 2025 on a standalone basis? Is that a possibility?

Yes. I would say a lot of that just depends on the timing of which we activate the TILs is ultimately going to drive that. I think our goal as we start to activate these TILs is to get back to our sustaining level of production, which what we've communicated in the past is around 3.2 Bcf a day as a standalone company. Though we would have the ability to potentially accelerate that Bcf a day and activate the TILs a little bit quicker, we want to be thoughtful about how we reintroduce those markets, and it's ultimately that pace that is going to dictate the ultimate production level that we achieve.

Our next question will come from Betty Jiang with Barclays.

I wanted to ask about the Haynesville with a broader question regarding the production decline we've seen so far this year and the recent improvement with some of the curtailed volumes coming back. I would like to hear your thoughts on the future of volumes in the Haynesville. Are we expecting to see more curtailed production or potential further decline? Additionally, how is this impacting in-basin pricing? It seems like pricing has improved year-to-date. Do you think that trend could continue?

Betty I'll start. Josh may add something here. Pricing is a little bit better today than we saw in the spring, those curtailed volumes have come back on. So you've seen that flatten out the Haynesville production overall for our asset. If you look at the slide in our presentation that we posted last night, you can see that we do expect declines to then come back as you go from Q3 to Q4. So if you think about what's happening here, we began reducing activity during the first quarter, but then we also curtail volumes at that same time. The initial slope of the decline we saw was quite steep. Now that we've brought that curtailment back on, it has plateaued or flattened out for a period of time until the effect of that curtailment is all on and the underlying decline picks back up and takes over and brings volumes lower again, which again, you can see from Q3 to Q4. We do see that decline continues at the current underlying market conditions when we consider where total supply is, we look at where total demand is, we look at where storage is. We don't anticipate at this point turning in line any material number of wells in the second half of the year in the Haynesville. So we do expect that decline to continue. If prices were to weaken materially, we would curtail volumes again. We've mentioned that now on the call already. To reiterate, our projections do not assume any material amount of curtailment through the fall. We're totally prepared to do that and that would change the shape of that decline again if we were to do it. What I think is important to note is if you look at Q1 of this year to Q4 of this year, there is an underlying decline. The slope of that gets adjusted with the effect of curtailment, and you can see that in Q2 and Q3, but that underlying decline is pretty real going from the beginning of the year to the end of the year.

And a follow-up just on the operational efficiencies that you're seeing in the Haynesville. Clearly, CapEx in Haynesville has been coming a bit lower than expected. Outside of saltwater disposal savings that you mentioned in the slide, is there anything else perhaps on the drilling and completion side where that's continued to lower that's helping your CapEx that could be sustainable going forward?

Yes. Betty, we continue to look at new technologies and improving operational practices to drive those costs lower. In the last six months or so, we've implemented insulated drill pipe in the Haynesville to help us manage temperatures a little bit better using killers to help reduce temperatures of drilling mud, optimizing the hole sizing which we've seen some benefits here of late. We continue to find new opportunities to improve our operations, and we're really starting to see those results show up. We really think that provides some tailwinds. In addition to that, as we're exiting '24 into '25, we're looking at opportunities to change the way at which we source sand in the Haynesville, which we think will also provide an additional tailwind as we head into next year.

Our next question will come from Josh Silverstein with UBS.

Nick, within the flexibility you have to bring back the Bcf capacity, what's the additional flexibility you have between the Marcellus and Haynesville? I'm just wondering, if Appalachia basis remains weak in next year, can you bring back the Haynesville volumes first and then sit on the Appalachia volumes? If you could provide a little bit more detail there, that would be great.

Yes, Josh. I would just say that we absolutely remain flexible on which area we would choose to bring back first. We look at these decisions really independent of one another. So it's really just about monitoring local market conditions and then our operations and engineering teams working together to plan out as efficiently as we can to activate these TILs when the market indicates that the gas is needed. So yes, we're going to be flexible and we could very well be bringing on one basin ahead of another.

And I just wanted to see if we could get an update on the momentum project, the investment kind of updated timeline and then anticipated benefits when complete as well.

Josh, this is Mohit. We are very pleased that the litigation that was between energy transfer and momentum has been settled. We're extremely happy with that outcome. The project is now back on track, and we expect that to go in service towards the end of 2025. We're expecting an in-service date in Q4 2025. From a project delivery point of view, the contractors are being reengaged and all the materials that they had stored in the yards, they have kind of gone back and checked the integrity of it, which all looks good. The plan here, as we've guided for the rest of this year in terms of capital calls, we're saying $50 million to $100 million of remaining capital calls that will be made on the project. So everything is back on track from that point of view. The second part of your question around what this means for us. The original thesis why we got into this project was to connect our production to the emerging demand source in the Gulf Coast. That thesis remains intact. Now that we'll have 700 million a day of production that we can bring from Haynesville down to Giles, it gives us increased flexibility and optionality because if you look at the overall flow map, we currently have capacity on Tiger and Gulf Run that allows us to go due east to Perryville. Now, we will have this optionality to take it down to Giles, which in the future when this project is in service gives us the flexibility to redirect flows as we see appropriate.

Our next question will come from Phillips Johnston with Capital One.

It looks like you've turned on close to 25 wells in the Upper Marcellus over the last four quarters or so. Just wanted to get a sense as to how those wells are performing relative to the Lower Marcellus?

Yes, Philip, I think we've documented in the past and it shows itself in the public data sources that the Upper Marcellus is not going to be as productive as the Lower Marcellus core that we've been so focused on developing really for the last decade or so. We expect that trend to continue. But our teams continue to find opportunities to improve the overall economics of the Upper Marcellus. That's what we remain focused on is generating better returns. We do that through extending our lateral lengths, which you see in the deck today. Year-over-year, we're going to end up being about 11% higher on lateral length relative to last year. This is really coming as a result of more wells being drilled in the upper by specifically using these hybrid wellbore designs, which we've talked about in the past to be able to extend laterals and create better returns than we could with just a standalone upper Marcellus well.

Our next and final question will come from Paul Diamond with Citi.

Just a quick one on Slide 5, talk about a 25% decrease in SWD cost per barrel. Just wanted to get an understanding of, I guess, how many years should we think of that trend as that $20 million investment per year continues?

Yes. So we continue to look for opportunities to invest in our water disposal system. Today, we have around 30,000 barrels a day of disposal capacity for four of the sites that we operate. This also includes about 60 miles of gathering systems. Over the last couple of years, we've been investing in and around $15 million a year. We would expect to continue to look for opportunities to do that. That's one of the reasons we're so excited about the Southwestern transaction since it allows us to better utilize that system. Today, we run the system at about a 65% to 70% utilization rate. Oftentimes, these gathering lines run right by some of the Southwestern site. We're going to continue to look for opportunities to exploit that system and help to preserve these types of disposal rates that we've shown you all today.

And just one quick follow-up. You talked about a 20% decrease in well costs in Marcellus, but then targeting $800 for the full year. You talked about how you see the second half of the year playing out. Should we think about that as kind of a run rate around $800 or more going up and down? Or how should we think about the trajectory in cadence?

Yes, Paul. I mean, from the slide, you would have noted just under 17,000 feet of average lateral length in the second quarter, and that will be the peak for the quarter. That’s why you see that corresponding number there of the cost per foot around $740 to $750 a foot. We do anticipate averaging around $800. That $800 per foot is tied to an average lateral length of around 14,500 feet. Again, it will fluctuate quarter-to-quarter just based upon how the teams are attempting to optimize the drill schedule throughout the course of the year.

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

Thanks very much. I appreciate everybody's time today. We're really looking forward to the second half of the year. There are all the catalysts in front of us, obviously, the closing of our merger, which we anticipate in the second half of the year as well as we look forward to the point in time at which the natural gas market begins to improve. We're going to be really well positioned for that, and we look forward to updating you all on our progress as we move throughout the year. We will be available through our Investor Relations group if you have any follow-up questions to today. Thanks very much.

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