Good day, and welcome to the Chesapeake Energy Corporation First Quarter 2024 Earnings Conference Call. Please note this event is being recorded.

Thank you. Good morning, everyone, and thank you for joining our call today to discuss Chesapeake's first quarter 2024 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 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 also recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures, which will help facilitate comparisons across periods and with peers. For any non-GAAP measure, there is a reconciliation to the nearest corresponding GAAP measure 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 will open up the teleconference to Q&A. So with that, thank you again and now I'll turn the time over to Nick.

Good morning, and thank you for joining us today. We continue to execute on our 2024 financial and operating plan and our first quarter results further demonstrate that we are a company built to efficiently meet consumer demand and deliver sustainable value to shareholders through cycles. Today, the natural gas market is clearly oversupplied. Our 2024 plan is focused on discipline, operational efficiency and free cash flow generation while building the productive capacity needed to deliver for consumers when demand recovers. Through the first quarter, we have deferred 22 turn-in-lines and built 24 drilled but uncompleted wells. In addition, we began curtailing base production in February, averaging approximately 200 million cubic feet a day of curtailment in the first quarter. As we continue building productive capacity, we expect to curtail approximately 400 million cubic feet a day in the second quarter. We believe this strategy will leave us well positioned to meet demand for natural gas when the market recovers. In the meantime, our base business continues to deliver. We generated free cash flow in the first quarter, allowing us to maintain our commitment to return cash to shareholders through our base and variable dividend program. Our capital structure remains strong. Our lending partners recently reaffirmed our credit facility and increased the aggregate commitments to $2.5 billion. As we continue to deliver on our sustainability commitments as demonstrated by the company meeting our interim GHG and methane intensity goals, they're both two years ahead of schedule. Importantly, we remain encouraged about the long-term trajectory for natural gas, the affordable, reliable, lower carbon energy the world needs. Over the next few years, we will see significant increases in demand for U.S. natural gas from LNG exports as well as power generation and industrial activity. Additionally, the current clear trajectory of supply in the U.S. is falling. We believe this sets up a much more constructive market backdrop for natural gas in future periods and believe our portfolio is well positioned to deliver gas supply where and when needed. Consumers demand that energy is reliable and efficient, both economically and environmentally. Simply put, natural gas will play a critical role in the energy future, both domestically and abroad. And Chesapeake and our pro forma merged company with Southwestern is poised to ensure natural gas delivers on its promise. We remain very focused in our integration planning efforts on delivering the cost synergies identified at the announcement of the merger to ensure our supply meets the demand of energy consumers at the most efficient price. We will be LNG-ready and in an advantaged position as LNG capacity continues to come online. With our well-positioned portfolio, investment-grade quality balance sheet and disciplined strategy, Chesapeake is built to not only weather the current market, but to thrive when the market rebalances. I look forward to updating you on our progress throughout the year. We're now pleased to address your questions.

And the first question will come from Nitin Kumar with Mizuho.

I want to start on CapEx that came in quite a bit below what your guidance was for the quarter and you're a little bit ahead of schedule in terms of building the deferred TILs and DUCs, so I just want to get a sense of what were the drivers of that CapEx number? And how does that shape for the rest of the year?

Yes, Nitin, this is Josh. Yes, we had a really good quarter to start off the year. We ended up around 16% under our guidance for capital. About half of that is just purely related to timing and a lot of the timing was on the non-D&C side. And so just as we're getting some of our leasing ramped up and infrastructure projects ongoing, that will just occur later in the year. But the other half of that was really just related to lower realized cost. We had a really good quarter on the drilling and completion side. We saw lower costs than planned as a result of being able to accelerate the use of the lower-cost casing that we procured late in the year. We also realized some savings associated with lower service contracts. And then also, we had several wells up in the Northeast that we had planned that were drilled in a pretty challenging part of the field that typically require contingency casing strings. The team was able to do some work with a mud company and identify a way in which we can mitigate the wellbore stability issues that we have there. So that's real structural cost changes and that really sets us up now for the full year to where we're tracking towards the lower end of our capital guide. And so we'll continue to monitor the service markets and see how that plays out. But again, got off to a pretty good start this year. On the second part of your question, we are just a little bit ahead of schedule with the DUCs. That's just how activity was kind of falling between the quarters. But as far as how we think about the full year setup with our total DUC build, I would say we still see ourselves on track for the full year.

Great. And Nick, I have to say I was a little bit disappointed that there wasn't an obligatory slide on AI demand for and power gen demand for gas in your decks last night. Just wanted to get a sense of where you guys see that evolving? And what are the early thoughts at Chesapeake about the growth for power gen in the U.S.?

Yes, it's a good question, Nitin, and we have been a little puzzled by the forecasts that have had power generation or demand for power flat in the U.S. And we know that over the last several summers, we've seen a real increase in power demand and particularly natural gas-fired power demand. We do think the utilities have struggled to voice the need for incremental generation capacity given a number of the challenges that they have within their own stakeholder base, and I think it's changed. We're really encouraged to hear the market talk about the growing demand for power. One of the reasons we're really encouraged by that is it's evidence of a very healthy economy. We have investment in the U.S. economy that's driving growing demand for power from the consumer and industrial side, which is really the continuation of the impact of all of the stimulus money that's come through the economy over the last several years and then, of course, the Inflation Reduction Act as well. So that's showing up. But what has really taken hold in the last couple of months is that there is a recognition that the massive growth in demand for data centers, significantly driven by the growth in demand around AI tools, is going to put a big draw on power grids. We think that's all very real and very interesting. There's a lot to unpack to understand exactly how and when and where that demand will show up. We're excited about, in this backdrop, Nitin, is that we, as a stand-alone company, have a really large production base and as a pro forma combined company have the largest production base in both the Appalachia and Haynesville with which to be ready to respond. Having the geographic advantage of two locations, if you think about where we sit in Northeast Pennsylvania, then we'll be in Southwest Appalachia and West Virginia and then also in the Haynesville. Keep in mind that we talked a lot about growth and demand for Haynesville gas flowing to the LNG corridor, but we deliver a lot of gas to Perryville every day, which is directly east of our field and connects into a series of pipeline networks that feed the Southeast. The opportunity to increase flow to the east is also very real and something that we stand ready to do, and we'll continue to work with our midstream counterparties as well as the utility counterparties to understand where that demand is needed and where that gas is going to be needed and how we may get it there. It's incumbent upon us as an industry to make sure that we continue to supply those markets at a really efficient cost and that's something that we think the pro forma combined company is set to do.

Your next question will come from Bert Donnes with Truist.

It did look like you had any incremental agreements on your LNG portfolio. I assume you're still looking for those, but does the data center growing demand hypothesis slow that down? Or maybe do you want a lower mix internationally, maybe you're more focused on U.S. or just what your thinking is there?

Yes. Good question, Bert. No, we're still actively engaged in a number of different LNG discussions. As you know, those discussions take a lot of time. As far as whether the data center concept would slow us down, no, it wouldn't necessarily slow us down. Competition is great, and we do think there will be competition for supply. So we'll pay attention to that. But we're moving forward with our strategies and we think we'll have ample gas to supply all of the markets where there will be demand. Frankly, we look forward to there being some competition around that. But we're not changing anything.

That makes sense. And then hypothetically, assuming everything goes well with Southwestern and you're able to gain the synergies that you've outlined, are there more synergies from getting even larger at that point? Or do you focus more on midstream? Or maybe once you have that scale is when you just switch to more of a buyback program and driving more organic?

Yes. I think at this point, you'd have to say any time you're going to talk about what's next in your strategy, you go back and talk about the things that we think are important, which are being able to supply these markets with the most efficient molecule possible to meet growing demands for energy. That means having a really low-cost structure, deep inventory and great execution. We're going to continue to stay focused on all of those things, first and foremost. We did feel like the merger with Southwestern allowed us to advance on those fronts and have real synergies, real industrial logic that helps to improve our ability to meet those goals over time. As far as whether you need something else, it would have to meet our non-negotiables that drive towards those goals, and that's really hard to predict whether or not there will be something in the future that would meet those non-negotiables. We're going to stay focused for a while here on what's a big job of integration and delivering on the promise of this merger, which is pretty tremendous for our shareholders.

Your next question will come from Zach Parham with JPMorgan.

I just wanted to get a little more detail on the curtailment. You highlighted you'd be curtailing 400 million a day in 2Q and that you curtailed 200 million a day in 1Q. Could you give us a little more color on the curtailment strategy and maybe detail how much in curtailments were built into the full-year guidance? And when do you expect those curtailed volumes to come back to the market?

Yes, I'll start this and then I'll pass it over to Josh. So as we think about what we are trying to accomplish this year, remember we talked about doing a lot of activity deferrals. Those activity deferrals are focused on the fact that the market is pretty clearly oversupplied, and we don't want to bring on wells in an environment where the initial production of these wells, the significant part of the return comes to market in an oversupplied market and receives a lower than breakeven price. We've had the activity deferral schedule in front of us, but recognize that, that activity deferral results in decline that occurs over a period of time. The curtailments that we saw occur in the end of Q1 and into Q2 are really about accelerating that decline. We don't need to keep that base volume curtailed throughout the year as the activity deferrals show up in more what I would call actual decline. We have a lot of flexibility in what we choose to deliver to market, and we're going to pay a lot of attention to the supply-demand characteristics.

Yes. Zach, this is Josh. I mean it is customary that we would see demand weakness in certain markets in the shoulder seasons. And so as we issue the 2.7 Bcf a day guide back in February, we had accounted for those volumes in there. But really to Nick's point, how do you then set up the production curve to best mimic what the market needs. That's effectively what we've done to where you model in and execute on curtailments in Q2. Then you allow those volumes to flow back in over the subsequent quarters in the second half of the year. In effect, you do see a sharper decline coming into the second quarter with it flattening out into Q3 and Q4, where we would anticipate market conditions to be a little bit better for us. But I'd also stress, I think we've demonstrated a willingness to be disciplined with how we deliver production, and we'll maintain that discipline as we move through the course of the year.

Got it. And then maybe just one on your latest macro thoughts. We've seen lower 48 production decline pretty rapidly over the last couple of months now at sub-100 Bcf a day, has overall production trended in line with your expectations? Really just looking for your updated thoughts on kind of the macro environment in general.

Yes. Great question, Zach. I would say actually to see production get below 100 as quickly as we did, is maybe a little bit surprising to us. We weren't expecting that, but what we've also seen at the same time is that demand fell off pretty quickly. So starting with the supply side, we think curtailments took a bigger role. It wasn't just activity deferrals. People didn't wait for a decline similar to what I just described within our own decision-making process. Volumes came off probably a little faster than we would have thought through the year. However, what we also saw at the same time is that there were a lot of LNG capacity that was offline through March and April and we probably had 2 to 3 Bcf a day off through a good portion of March and April that represented pretty weak demand. You're seeing a lot of that demand come back now. But it's a reminder that demand is going to be volatile when we have exposure to LNG the way that we do, and you need a flexible business plan and one that's strong enough financially to handle that. You probably ought to have a hedging policy that protects how you think about your capital program that you have at risk at any point in time. When we think about the macro trends here more broadly, I do think that, that decline that you are seeing is ultimately real. I think it has been accelerated with curtailments, but I think given the fact that we have a rig count today in the Haynesville that is half of what it was that led to the peak production that we saw in the fall of 2023, we know that decline will show up, and we think Haynesville production settles in at a much lower level than it has been and stays there until you see a pretty significant change in rig count going the other direction. All of that is quite encouraging, and we're also still very encouraged by what we see in the way of demand growth certainly through LNG exports, which we all talk about quite a bit, but also through consumer and industrial as well as power gen.

Next question will come from Charles Meade with Johnson Rice & Company.

Nick, I'm wondering if you can offer some thoughts that maybe characterize what your engagement with the FTC has been like so far?

Look, I mean, we've been engaged with the FTC. Obviously, we're in the second request phase of this process. It will take some time, as you would expect to reply. We're eager to work with the FTC and get all their questions answered. We feel good about the underlying merits of the transaction and look forward to getting through this process and getting it closed. But really hard to predict exactly how long that will take. And so that's why we gave a forecast of just the second half of the year.

Got it. And Josh, I wonder if I could ask about your TILs and DUCs. I wonder if you could kind of characterize for us what's different that you're doing now, maybe setting up these wells to be off for 3 months, 4 months, maybe 6 months, maybe longer. Are you doing something different to kind of put these wells in cold storage, so to speak, versus what you would do regularly? Have you learned anything so far from this effort that you wouldn't have expected at the beginning?

Yes. Charles, thanks for the question. As far as the DUCs go, I would say there's really not anything different that we do. This is a pretty common practice. The wellbore is in a state that it could sit there for an extended period of time. This is just pretty typical run-of-the-mill business. With the deferred TILs, we do have to be a little bit more thoughtful about how we manage those in terms of our wellbore preparation and preservation, primarily from a corrosion standpoint. But probably most importantly, we do have to stay on top of them. Specifically, it's around just monitoring the pressure. We do have pressure transducers that we install on the wells, and we have it tied back to our remote operating center here in Oklahoma City, where we can monitor any potential production decline. That production decline would be as a result of offsetting wells that could come online and start potentially pulling on those reserves. Those are the instances that we want to protect against. Of course, when there are our own wells, we're managing that by keeping wells shut in. But at the other operators, we want to be on top of that. We recognize it's a threat, and we actively manage that to ensure we're not impacting the investments that we've made on those particular wells.

Got it. Josh, so you mean you're managing the shutting pressure to see if there's offset completion?

Shutting pressure. Yes, that's correct.

Your next question will come from Josh Silverstein with UBS.

So I just wanted to follow up on the production outlook for the year, just based on where 1Q volumes were the 2Q guide and the outlook. I suggest that Chesapeake may not get down to that 2.1, 2.2 Bcf a day range in the fourth quarter, but you'll still have the 1 Bcf a day of capacity. So I want to see if that was right and just kind of see what the cadence would be for the back half of the year.

Yes, Josh, we are managing production to the level of around the 2.7 Bcf a day. So again, just to reaffirm that the guide is unchanged at this point. We did have some overproduction in the first quarter of the year. Some of that was attributed to a non-operated accounting adjustment that rolled through into the quarter. So that did push those volumes just a little bit higher. But we are still on track. Even as we talked earlier about the curtailment, which is pulling down the Q2 number, but that $400 million that we take out of Q2 starts to settle into the Q3 and Q4 numbers. So in effect, we are flattening the back half of the production curve. We still feel really good about delivering the number that we offered back in February. But again, just to remind everybody, we are absolutely flexible, and we'll continue to monitor market conditions and adjust production accordingly to what the market needs.

Josh, let me just reiterate on that point. It's really important to note that there's a forecast from with eight months left to go in the year. We've been clearly focused on the economics of our underlying business and do what makes sense. So if market conditions don't play out the way we expect them to, we'll adjust, whether that means producing more or producing less. The setup feels pretty good today, but we have a lot of flexibility in how we respond.

Yes. Well, the follow-up was kind of along those lines. We're 6 to 8 months away from winter pricing and gas going back over $3. How do you think about bringing the capacity back on, what's the process of it? Is it TILs and DUCs the new rigs? Or what's the timeline for that?

Sure. First of all, let's talk about what's going to trigger this for us. We get asked a lot about what price are you going to bring volumes back online? Of course, that's an easy way to think about it and an easy way to model it, but it's not the right way for us to make that decision. When we think about price, we think about it as an indicator of what's going on in the underlying market, but the trajectory of what's going on in the underlying market matters a lot more to us than what the price is at the moment. We will continue to monitor the current production levels and the trajectory of that production, the storage levels, the activity levels across each of the basins and think hard about what we really believe the market needs before we make any changes. Once we determine that the market does need more gas, it would just follow the logic of what we have available to us. The fastest thing for us to respond with are the wells that have been drilled and completed that are just waiting to be turned in line. Following that, we would begin to work on completing the additional wells that would have been drilled but are uncompleted. Certainly, I guess, along that time, we will be bringing back volumes that are curtailed out of the base. I think there's a lot of flexibility in how we respond to this. I would imagine that this will come about in a rather slow manner. I don't believe it's likely that we will wake up one day and see that the market needs all of the gas and that we will be racing to bring it all back at once. It's possible. If that happens, we will move through it as efficiently as possible. But I think it's more likely that we will be bringing volumes back to match a growing demand that will be pretty well previewed by the activity levels that are out there in the market around LNG around the increase in power generation and industrial demand when it's needed. You can have a cold spike, and cold spikes show up with a need for incremental demand. We would always try to respond to those needs as quickly as we can, but know that those are not necessarily sustained.

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

I wonder can you just spend some time on your hedging framework specifically the hedge the wedge concept. So can you just talk about the way that you approach hedging and the advantages of having a rolling program, especially in the contango curve? And then I have a follow-up.

Yes, Neil, this is Mohit. Thanks for that question. You referenced the hedge the wedge program that's been our way of hedging over the last several years. The way we philosophically think about it is you have a $1 billion, $1.5 billion capital program. So you're investing dollars into the ground, and you want some certainty on when you start getting the production back. Think of that as 9 or 12 months after making the initial investment decision when you're spotting the well. You fundamentally don't know what prices will be at that point. So you want to lock in some of the returns on the investments that you're making, which are fairly substantial. When you look at the market cap of the company versus that kind of a capital program, you might be investing 10% to 15% of your market cap into the ground. For us, it's a prudent way of just taking the risk off. One thing that we have done structurally, which we are pretty excited about, given the contango that you referenced out in the curve, is we've been sort of doing swaps, we've been doing collars, which allow us to monetize the volatility. Bringing up the floors that we are getting from the puts, but still retaining some of the upside by the calls that we are selling. Overall, the program is working, especially when you're in a low price environment like we are in right now. Every month, we are getting receipts of hedge settlements, which help support the base business and the cash flows. Again, it underpins the return to shareholders and the base and the variable dividends that we are making. Overall, we think it works, it works well, reduces the volatility of returns and allows us to be more consistent with shareholder returns.

And the follow-up is just on the global LNG market. You talked in the slides about the 12 Bs of incremental supply coming out of the United States, Qatar's coming through with North Field expansion in 2026 and beyond. So Nick and team, how do you think about global LNG price being a potential governor on long-term gas prices?

Yes. Neil, it's a great question, and it's something we think about a lot. As we think about LNG growth, the market is clearly eager to have more LNG supplies. There are a number of different projects eager to accept in the growth of LNG, but it's also pretty obvious that at some point, there will be oversupply and that market will have volatility in the same way that the domestic markets do, and we're prepared for that and understand that. One of the things I think we've seen that's really interesting is that there's clearly some elasticity to demand for LNG prices, I'll say, in the $9 to $12 range. That range is probably debatable; it might be down to $8 or a little higher than that. But you've seen that demand clearly goes up when you get into the single digits, and you've seen the demand can be fleeting as it gets into the mid-double digits, certainly over the longer term. What that tells us is that this market requires that you remain really efficient in your cost structure and how you deliver supplies. That's something that we'll stay focused on and we'll work with all of the different providers through the value chain both domestically and internationally to make sure that we can do that. At the end of the day, we still think natural gas is the most efficient and effective way to supply markets that are in demand for greater energy. It is affordable, reliable, and lower carbon. I don't know that we can say that enough. But the trade-offs are not as good. It's important that we remember that, and it's important that as an industry, we deliver on a product that meets that expectation of being the most efficient solution to cost and affordability relative to the alternatives. The alternatives, of course, being in a lot of markets coal, which is certainly not lower carbon. At times, it can be lower cost, and it definitely can be reliable because it is easily stored on site. But then you also have renewables, which will maintain a competitive tension, especially with policies that drive people towards renewables that really struggle from both a cost and reliability perspective and full cost have some of their own challenges from a sustainability standpoint that are just different than the product that we produce. We still feel very strongly that what we produce is the best solution, and it’s incumbent upon us to make sure that we deliver on that.

And Neil, this is Mohit. The only thing I would add to that is we are signing up 20-year LNG transactions, and we're going in eyes wide open that there will be periods of time when that transaction will be out of the money. So it's a diversification connecting us to the eventual end users, as Nick was describing. That's the strategic mandate for us. But again, being fully aware that there will be periods of time when we'll be out of the money.

Your next question will come from Paul Diamond with Citi.

Just a quick one on the kind of the timing and the cadence of the DUCs and the TILs. Should we think about that more nearly from this point forward through the year? Or is there kind of a point like Q3, where you just stop and revert back to normal? Just how should we think about the cadence?

Yes. So really, what that ties back to is just the underlying activity cadence of our drilling rigs and frac crews, where today, we're running eight rigs and two frac crews. We do anticipate that we'll drop one additional rig in the Marcellus middle of the year. By and large, you should expect those deferred TILs and DUCs to build in a linear fashion through the course of the year.

Understood. Just one quick follow-up. If we were to see any kind of increased volatility out of the three levers, I guess, for additional DUCs, TILs or the curtailments, is there any preference you guys currently hold about what order you address any near-term volatility with?

Well, I mean, I think it all depends on what's going on. If you have some short-term spike in demand that you don't think will be sustained, then we have curtailed volumes that we can bring to market to help meet that demand. If you think that there is a step change in demand and volumes are needed in a longer-term fashion, then you start to bring some of those deferred wells online.

And the final question for today will come from Kevin MacCurdy with Pickering Energy Partners.

To dig into the curtailments a little more, the 2Q guide shows that the Haynesville is declining faster than the Marcellus. I'm just curious if that's being driven by something you're seeing on local prices that is leading to more constraints or is that just natural declines in the Haynesville?

Yes. That's really just due to local market conditions. We were seeing pricing there that we were starting to question whether or not it makes sense to continue to flow gas into those markets. We selectively look at the wellsets and what margins are for each well, recognizing that chemical usage and water production will impact wells margin. We just think that pricing we're seeing in the second quarter simply doesn't make sense to flow the full allotment of volume there. So when we talk about the 400 million cubic feet a day of planned curtailment in the quarter, roughly half of that is tied to the Haynesville. When you look at the quarter-over-quarter decline from Q1 to Q2 for the Haynesville asset, a big portion of that is directly tied to the curtailment. Of course, we'll start to get that back as we get into the second half of the year. Again, that's why you see or should anticipate a flattening of the decline in the second half of this year.

Great. And to follow up on an earlier question about returning production, do you have the capacity to bring back volumes on faster in one basin compared to the other? Or will it be about the same in the Haynesville and Appalachia?

Yes, it should be about the same. There's a lot of considerations that go into how we bring the production back, outside of just the macro conditions Nick spoke to earlier. It's really just around logistical planning. We have to be thoughtful about where gas gets introduced and when to manage the gas gathering systems and things like water hauling. But really, I wouldn't say one area is advantaged or disadvantaged more than the other.

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

Well, thank you all for your time this morning. We really look forward to progressing through this year, working on planning for the integration of our merger and delivering on what we expect to be improving gas market conditions as we approach 2025. As always, if you have any other follow-up questions, please reach out to our outstanding IR team. They will be ready to take your calls, and we look forward to seeing you down the road. Thanks.

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