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Operator: Good day and welcome to the Chesapeake Energy Fourth Quarter and Full Year 2022 Earnings Conference Call and Webcast. Please note this event is being recorded. I would now like to turn the conference over to Chris Ayres, Vice President of Investor Relations and Treasurer. Please go ahead.

Chris Ayres: Thank you, Betsy. Good morning, everyone and thank you for joining our call today to discuss Chesapeake’s fourth quarter and full year 2022 financial and operating results. Hopefully, you have had a chance to review our press release and the updated 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 the factors identified and discussed in our press release yesterday and in other SEC filings.

Please recognize that except by required €“ except where 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 some non-GAAP financial measures, which will help facilitate comparisons across periods and with peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure that can be found on our website. With me 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 I will now turn the teleconference over to Nick.

Nick Dell’Osso: Good morning and thank you for joining our call. This morning, we are going to talk about two key announcements we made yesterday. First, we are pleased to highlight our fourth quarter results and 2023 outlook. Second, we announced the next significant step toward exiting our Eagle Ford assets. The fourth quarter finished off a strong year for Chesapeake. Production in capital were essentially in line with expectations and EBITDAX was slightly ahead. Based on those results and adjusted for the October 1 effective date of the Eagle Ford asset sales, we are delivering a dividend for the quarter of $1.29 per share. Overall, in 2022, we delivered company record free cash flow, resulting in $2.3 billion in cash returned to shareholders in the form of dividends and buybacks.

The second announcement yesterday was the $1.4 billion sale of our black oil Eagle Ford assets in Dimmit, LaSalle and McMullen counties to INEOS Energy. This is another important step as we solidify our focus on the premium rock returns and runway of our Marcellus and Haynesville assets. We are pleased with the progress we have made to-date in our Eagle Ford exit and look forward to completing the process. In aggregate, from the first two sales, we expect to receive approximately $1.7 billion in after-tax proceeds at closing with an incremental $450 million to come over the next few years. The proceeds will be used to drive value for shareholders by reducing debt to maintain our balance sheet strength and support our ongoing buyback program as we work to complete the remaining authorization, which sits at over $900 million.

We are strong believers in the value of cash and liquidity in the soft market and the proceeds from the sales. In addition to the cash, we expect to generate from our operations will be a key strategic advantage as we continue to allocate capital in a prudent and value-oriented manner with an eye on our ability to be countercyclical. Pro forma the sale of the Brazos Valley and black oil areas, Chesapeake will have approximately 21,000 barrels a day of oil and NGLs and 80 million cubic feet a day of gas production remaining on our Eagle Ford position, which is in the rich gas window of the basin. We are actively engaged with several parties regarding these assets, which include acreage that is prospective for the attractive and maturing Upper Austin Chalk play, where we have delivered strong well results in recent months.

As we planned our initial capital allocation for 2023, we are proactively addressing the macro challenges affecting our industry with year-over-year natural gas prices lowering while service costs remain inflated. Our preliminary capital allocation and outlook for the year clearly demonstrate we believe the prudent step is to show capital discipline and reduce our activity levels in the Marcellus and Haynesville. While we never wish for low prices, Chesapeake is built for the volatility we are experiencing today. We have the assets, balance sheet, cost structure and hedges to allocate capital prudently, allowing modest production declines and saving CapEx for better investments, including repurchasing our shares. Overall, we are dropping 2 rigs in the Haynesville and 1 rig in the Marcellus as we move through the year.

In addition, we are reducing our completion activity in the near-term as the market is currently oversupplied with the warm winter we are experiencing in North America. Year-over-year, despite the inflationary environment, our annual drilling and completion CapEx will be modestly lower, but we expect to see only a slight production decline of approximately 2% in the Marcellus and Haynesville, allowing us to maintain our cash flow resiliency and continue our leading shareholder return profile. We find ourselves in this position today, thanks to several important strategic actions taken over the last 2 years, including our well-timed Haynesville and Marcellus acquisitions, which bolstered the depth of our high-return, low-cost inventory as well as our decision to exit the Eagle Ford.

All of this positions our company to provide consistent results and cash returns to shareholders as we move through this cycle and prepare for the increase in natural gas demand in the coming years from the growth in LNG export capacity. Reducing activity today helps to ensure Chesapeake remains LNG ready to capture the value of strong growth and demand for gas in the coming years and preserves cash for us to allocate capital in a countercyclical manner, many in our industry have not achieved historically. We look forward to updating you on our continued progress and I am now happy to address your questions.

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Operator: The first question today comes from Zach Parham from JPMorgan. Please go ahead.

Zach Parham: Hey, guys. Thanks for taking my question. I guess just on the buyback, you talked about being countercyclical with the buyback. You’re going to have a significant amount of proceeds coming in shortly when the Brazos and the oil window sale closed, can you give us some thoughts about how you plan to utilize those proceeds kind of in the first half of €˜23 and into the back half of the year via the buyback, debt reduction and other potential uses?

Nick Dell’Osso: Well, we don’t even have the cash yet. So we don’t plan to announce very specific actions around the buyback other than just to note that we will have a lot of liquidity to pursue the buyback. We expect the market conditions to offer us some attractive opportunities to do it, and we want to be opportunistic with it. So we will be patient. We’ll let the market come to us. We think there is ample opportunity in the coming year to put this cash to work.

Zach Parham: Got it. Thanks for that. And then my follow-up is just on well productivity. Within the industry, there has been a lot of talk about degradation of well productivity. Looking at some state data, it does seem like your well productivity has trended a bit lower in both the Marcellus and Haynesville in €˜22. In the slide deck, you did highlight a lower drawdown in the Haynesville, so maybe that’s one of the drivers. But could you give us just some color on well productivity in general and how you expect productivity to trend in 2023 and in future years?

Josh Viets: Good morning, Zach. This is Josh. We’ve looked at this data as well. And of course, we recognize that the trends into 2022 did show a drop off and to address maybe the Haynesville first. We are looking at incremental drawdown strategies that will have an impact on early time rates and really, that starts to show up in the first 3 to 6 months of the production history. But really, we start to see something that looks like an incremental gain as you get out beyond 12 months. The other thing, just to remind you, that’s impacted our position within the Haynesville this past year. And I suspect in some others is the increased line pressures. And so with increased line pressures that does lead to lower IPs but ultimately flatter declines through the first 12 months of the year.

In the Marcellus, I think the thing that we need to remember is that we’ve been operating the Marcellus for well over a decade. We’ve drilled over 700 wells within our Lower Marcellus core and these are unbelievable wells, really the best shale gas basin in the world. The other thing, I think, to point out as you look back at historical trends in 2020, 2021, really across the industry, we were having to high-grade locations and this is no different for Chesapeake. And so we absolutely drilled the very best wells with a relatively modest program in the heart of our core. And so I think if you were to look back and compare our 2022 well results to something in the 2018 and 2019 time frame, you’ll actually see productivity that’s on par. In fact, on an absolute basis, when you adjust for lateral lengths, you’ll see a slight advantage on productivity.

And so really, that’s going to be our focus going forward is extending laterals. We’ve done so by increasing our lateral length by 65% in the Marcellus over the last 5 years and we are going to continue to do that.

Zach Parham: Got it. Thanks, Josh. That’s great color.

Operator: The next question comes from Nitin Kumar with Mizuho. Please go ahead.

Nitin Kumar: Hi, good morning guys and thanks for taking our question. Nick, I am going to start with the kind of elephant in the room, gas this morning breached $2. What is your macro outlook for gas now that you are transforming into a more pure-play gas company. Curious how you are looking at both the near term and the medium term?

Nick Dell’Osso: Yes, hey, good morning. And our macro outlook for gas hasn’t changed. We are very bullish, the long-term natural gas fundamentals, and we’ve been cautious to 2023 setup for quite some time and we have referenced that throughout last year. We noted that the supply-demand dynamics were trending in a manner that suggested supply was going to outpace demand. That has clearly happened and then has been exacerbated by what’s been a pretty low demand winter weather set up. In terms of near term, I think we’re at a pretty interesting point. We’re making some changes to our program. We’ve seen a handful of others make changes to their program, hard to really know what the rest of the industry will do. You have variables like the associated gas from the Permian that as pipeline capacity comes on, that gas is going to show up to market, and you don’t really have any structural demand growth for at least a year.

And really in the end of €˜24 and into €˜25 is where you start to expect LNG export capacity to expand and so that’s how we’re going to think about what our production profile should do. We should be flat to down a little bit because the market is currently oversupplied until that structural demand growth shows up. We will never be perfect to timing that. But we do think that there are some long-term trends here that we can plan for. And then I would just note that while this morning’s gas price dipped below $2 and that is a low level and nobody likes that, we’re really not bothered by the short-term dip in gas prices, because we do expect it to be short term. We are very bullish in the long-term fundamentals. We think that the projects that are coming online will represent true incremental demand, the demand for natural gas internationally with the competitive economics of shale gas in the U.S., is strong.

We expect it to remain strong. We get a lot of questions about whether or not the war in Ukraine could end and what might happen with that. We actually think the demand for gas remains resilient regardless. There is plenty of demand for natural gas growth around the world that we don’t actually think that would have a meaningful negative impact to this long-term trend that we see. So we remain bullish beyond 2024. And we think we can manage through a flattish period until then, and we can do so in a way where we are optimizing cash flows and creating great returns for shareholders along the way.

Nitin Kumar: Great. Thanks for that detail. My other question is around the momentum spending. It was a little bit higher than we expected for 2023. It sounds like it’s just an acceleration, but could you maybe talk a little bit about what drove that exploration? And any specific milestones we should be looking for as that project starts ramping up and in terms of getting gas to that pipeline?

Nick Dell’Osso: The pipeline is on schedule as originally contemplated to come online in the fourth quarter of 2024, project has gone really, really well so far. We are very pleased with our partnership with momentum here. And all that has happened is just the timing of the cash calls has changed a bit. The total budget hasn’t changed at all. So we are thrilled with this investment.

Nitin Kumar: Great. Thanks, guys.

Operator: The next question comes from Umang Choudhary with Goldman Sachs. Please go ahead.

Umang Choudhary: Hi, good morning and thank you for taking my questions. Thanks for sharing your thoughts on the macro. You highlighted being disciplined to the changing natural gas conditions, focusing on free cash flow and conserving your undeveloped inventory for better pricing. What flexibility do you have in your service contracts to respond to changes in gas prices? And maybe you can touch on what you are hearing from non-operated partners in the Haynesville to recent gas price shifts?

Josh Viets: Good morning, Umang. On the service side, we are absolutely exercising flexibility in the first half of the year with dropping 3 rigs throughout in the first 6 months of the 2023 calendar year. We have a lot of flexibility on the frac crew side. We are going to be flexing between 2 and 4 frac crews throughout the course of the year. Only one of those is actually under a longer term contract, and that’s less than 12 months remaining on that. We do have some longer term rig contracts, but we do think that we’re in a pretty well position to manage those as we work through the course of the year. And to date, we’re not really going to incur any incremental penalties on the rigs that we’re dropping. It’s a pretty modest amount.

But that’s something that will continue to work as we go through the year. As far as non-operated rigs, we are starting to see some signs of operators pulling back activity, specifically in the Haynesville. It’s been primarily showing up on the €“ with the privates to date. We are continuing to see new ballots come in the door from some of our non-op partners. And so we’re going to continue to monitor that activity. But we are expecting operators to start pulling back with the weakness in the gas pricing we see today.

Umang Choudhary: Got it. That’s really helpful. Maybe a quick follow-up, I mean if you look at EIA data, they show that more than 600 Haynesville drilled and uncompleted wells currently. At what price levels do you expect these drilled and uncompleted wells to be turned into sales, both for you as well as for the industry?

Nick Dell’Osso: Hey, Umang, it’s Nick. I’ll take that. When we look at that, we don’t believe that, that DUC build is anything more than the working inventory DUC build associated with the rig count growth over the last couple of years. And there’s always a little bit of inefficiency for the industry when a bunch of rigs were thrown in. So we think cycle times probably slowed down a little bit. But when we take the total DUCs and we move off the DUCs that are probably more mature, the DUCs that are aged, and so they’re not likely to get turned in line. And then we think about how many rigs have been running and what the cycle time is and how there’s probably been some slippage in that cycle time with increased activity, we think this is really probably the working inventory.

So it will be interesting to see as producers drop rigs, do they attempt to maintain their cycle times and turn those wells in line in other words, reducing that DUC count or do they hold back on completion crews and allow those DUCs to sit for a little bit longer. It will be a mix. It’s our assumption. And so we expect that DUC count to come a little bit lower through the year. You can think about it as producers choosing to bring those wells online or you can think about it as not adding new DUCs as the DUCs that are there continue to just get warm down. I would say that in the full cycle economics of the Haynesville, we certainly see that it’s prudent to pull back capital, and we think we’re seeing others do the same thing. We’re making money on the capital that we are investing but the margins are not nearly on a full cycle basis what they were historically and they do rely on some of that contango in the strip playing out.

Obviously, if prices were to stay where they are this morning and all that contango were to roll down to the prompt, you would have a very different economic outlook for the Haynesville, and I think a lot of activity was shut in. But I don’t expect that to happen. I think the contango is there for a reason. And so I expect there will be some conversion of those DUCs. I just don’t expect that there will be as much activation of new wells to maintain that same cadence.

Umang Choudhary: That’s great. Very helpful. Thank you.

Operator: The next question comes from Doug Leggate with Bank of America. Please go ahead.

Doug Leggate: Thank you. Good morning, everyone. Hey, Nick. Nick, can you walk us through the thoughts on the remaining sale in the Eagle Ford line of sight, if you can, to the extent you can. And the implications of what you showed is what looked like some pretty strong wells out of the Cotton Valley, what does that say about your thinking on the value of that asset relative to the sales that you have achieved so far?

Nick Dell’Osso: Yes. Hey, Doug, I will chime in here and the others may have some things to say as well. First, just to make sure it’s clear it’s the Upper Austin Chalk, not the Cotton Valley.

Doug Leggate: Sorry, my apologies that’s right. My apologies.

Nick Dell’Osso: No worries. So we have drilled some good wells there. And we knew last year as we engaged with buyers that, that would be a pretty interesting component of how people thought about valuation and thought about the value of the PDP relative to the value of the upside available. I think the Chalk wells that we have drilled are pretty attractive and confirmatory of the upside value associated with the asset. We are still in an A&D market overall that doesn’t end up putting a ton of value on undrilled locations. And so we have been willing to be a little bit patient here and let those wells come online. We have really just released these well results to the public now. And so we’ll be staying engaged with the interested parties.

And there are quite a few interested in this asset to understand what those chalk wells look like and understand if it fits for them as an investment. But we don’t need to be in a rush. We have got plenty of proceeds coming in. We are making progress on the exit strategically and we will be thoughtful about achieving a good result here. But we are actively engaged still with several interested parties and getting great feedback on what this asset looks like and what these incremental results mean.

Doug Leggate: Thanks. Yes, I don’t want to start with a rumor that you are selling Haynesville, so my apologies for speaking. My follow-up is really a housekeeping question, so I apologize for this, it maybe for Mohit. The transport costs, are there any MVC or other type of midstream obligations that have €“ there’s some kind of ramification from the decline in production, monies decline admittedly, but it just looked to us that your transport costs were ticking up a bit, I wonder if the two were related? So, that’s my follow-up. Thanks.

Mohit Singh: Yes, Doug, good morning, this is Mohit. None that we are concerned about at this point, I mean the MVCs historically that we have discussed have been in the Eagle Ford and as yesterday’s announcement to INEOS, so the buyer is stepping into those obligations for that package. There are some MVCs in the rich package also, but our production is way ahead of those minimum volume commitments. So any €“ and then when you start looking at Haynesville, there is quite a bit of uncommitted volumes that we had, and we’ve proactively been looking to try and get flow assurance through transport contracts and firm sales, which you start building up towards the overall projection of the volume that you’re forecasting and trying to get flow assurance for all those molecules. But overall, when you look across the portfolio, Doug, nothing that bothers us at this point from an overall obligation perspective.

Doug Leggate: Thanks, guys. Appreciate the time.

Operator: The next question comes from Matt Portillo with TPH. Please go ahead.

Matt Portillo: Good morning, all. Mohit, maybe just a question, starting out with the hedge book, great to see you guys added quite a bit in 2024. Just curious how you’re feeling about your hedge position now, looks like relative to your public peers, you’re in a position of strength given your coverage in €˜23 and in €˜24. But just curious how you guys are thinking about the €˜24 curve today?

Mohit Singh: Yes. Thanks for that question, Matt. it’s interesting when things were €“ when prices were going up, we heard a lot of pushback from our investors that we should not hedge as much. Now what we did do is we stayed consistent and our plan is to hedge the wedge as we have described before, Matt, when we’re making capital investment decisions now, the production comes on 9 to 12 months. Later on, we want some certainty on the cash flow from that production. And that’s why we hedge. So what you have seen in the disclosure that came out yesterday, we’ve added about 360 Bcf of new hedges since our last disclosure. We have done that both for 2023 and into 2024. So we feel pretty good about our exposure there and our coverage. What it does do is provide us downside protection, which underpins the commitment that we have towards shareholder returns.

Matt Portillo: Perfect. And then a follow-up question, just maybe a bit of a longer-term view on the market. Nick, you talked about being well positioned in the Haynesville to meet a surge in demand from LNG takeaway coming on, the basin as a whole, I think the industry doesn’t have as good of an acreage position as you and maybe one or two of your public peers have in terms of inventory depth and quality. Just curious how you view the cost curve in the Haynesville over time, even in your portfolio, there are wells that need something closer to $3 to $4 an Mcf to make a return. So I’m curious if you think the cost curve in the Haynesville over time is going to take higher as inventory depletes from maybe some of your smaller peers that are running a lot of activity in the basin.

Nick Dell’Osso: Well, I think as the Haynesville goes in the way of cost curve, will the U.S. market go in the way of cost curve because the Haynesville is going to be the leading asset to deliver the volume growth into LNG. So you’re spot on, Matt. The growth required for LNG is not going to be met by the very best acreage in the Haynesville alone. Now we and a couple of others do own that very best acreage. And so the relative advantages those with the best cost structure, the best full cycle return investment points for that gas are going to win. And we think this is setting up for exactly that. We think that you’re going to have some higher cost areas of the Haynesville developed. We think you’re probably going to have some higher cost areas away from the Haynesville developed as well.

One thing that we do point to as an important trend there is that we think that one of the reasons you will continue to have some of these higher cost areas developed readily in a rising price environment, and you probably will have less exploration or new play development than you’ve seen in past cycles like this is that the build-out of infrastructure is a massive challenge in the United States today. We would love to see more infrastructure built in Northeast U.S., where there is vast resources of gas that will wait for room and infrastructure to be delivered to market. If we saw more pipe built throughout all of Appalachia, including the area that we operate in Northeast Pennsylvania as well as Southwest Appalachia. I think it changed the game on how the dynamics of the cost curve for U.S. gas works.

But we don’t see that as a likely outcome in the near-term, aside from maybe Mountain Valley, which is pretty close. We’d really like to see that come online and think that there is still a reasonable chance that it will given how close it is and how much the country needs the gas. But new projects are going to be hard until there is a fundamental change in the social and political views of infrastructure in this country, not just for natural gas, but for really all forms of energy and all forms of infrastructure. And that needs to happen because until it does, we’re not going to deliver to consumers the most efficient form of energy product that they can have. And we think that’s an important trend that will play out. But until it does, we see that our company sits in a great position being overall the lowest on the cost structure for full cycle investment to activate natural gas.

Matt Portillo: Thank you.

Operator: The next question comes from Subash Chandra with Benchmark. Please go ahead.

Subash Chandra: Thank you. Hey, Nick, I think you might have references that you don’t think curtailment conditions are likely based on the shape of the curve. Is that a fair comment in the Marcellus and Haynesville, or do you think there could be some near-term physical constraints that are imminent?

Nick Dell’Osso: Whether it’s physical constraints or producers just deciding to pull back volumes, we could sell gas almost every shoulder season. And given the price set up that’s in front of us now, we’re going to expect to curtail some gas in the shoulder season. I had no idea what other producers will do, but they are going to be staring at similar economics to us. So it wouldn’t surprise me if they did the same. But that’s a common occurrence for us. We get full pipes, we get an economic flow on certain days, and we have the processes set up internally to day-by-day, hour-by-hour, decide what gas to flow and whatnot. We will proactively manage that this year, just like we do every year.

Subash Chandra: Okay. Okay. Thank you. That’s helpful. And then, I guess, second, so the investment Marcellus versus Haynesville sort of the inverse of the economics of the two places, right, Marcellus being superior, and I suppose that part of your LNG-ready strategy, is there a point though where that may be the carrying costs of those €“ of the relative economics is too great, and we see additional changes to CapEx?

Nick Dell’Osso: I’m not sure exactly what you’re asking me, Subash. Do you think €“ are you asking me if we pull back more capital in the Haynesville in favor of more capital in the Marcellus?

Subash Chandra: Yes. I think so the Marcellus being superior economics, I think it’s guiding €“ you’re guiding for declining volumes there, but flat volumes in the Haynesville. Is that fair? And if that’s the case, the Marcellus economics is superior, which might argue that you keep volumes there flat allow Haynesville to dissipate, but you’re probably not because of the LNG-ready strategy? And if at some point, you reconsider those economics?

Nick Dell’Osso: Yes, I don’t think that’s actually right. We’re looking at a pretty €“ it’s closer to flat in the Marcellus with a little bit of a decline in the Haynesville. So maybe we can walk you through that math after the call. But directionally, we’re, I would say, following the economics right now, but the one rig pullback in the Marcellus is it’s as much about optimizing how we spend and managing the logistics of development and then pressures in the gathering system as it is anything else. So we expect a very modest change in flow there.

Subash Chandra: Okay. Never mind. That makes a ton more sense, and just finally, is there a cash on hand sort of number that we could be €“ we should be looking at?

Mohit Singh: Yes. I mean the minimum €“ since we have ample liquidity, which is available through our revolving credit facility, I mean, the minimum cash balance that we’d like to keep on hand is the minimum, Subash.

Subash Chandra: Okay, thank you.

Operator: The next question comes from Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks: Hi, good morning.

Nick Dell’Osso: Good morning, Noel.

Noel Parks: Just a couple of things. I wondered with the Eagle Ford divestiture happening as we go through the year. I just wonder, do you have any thoughts on just what the pacing might be like with G&A, I don’t know if there are transaction costs that will be embedded that might be in the mix for a while. But maybe if you have a rough idea of what quarter we might get to serve a pretty normalized G&A after the divestments are taken into account?

Mohit Singh: No. We will have a handful of changes to our business as a result of the sale of this size. We do have a very long transition services agreement with INEOS that will be in place. They do not have a material upstream business in the U.S. And so we will be aiding them as they create that organization. So it will take a while for us to sort through all of that. But we will have some underlying changes to our business as a result, and you’ll see that play through.

Noel Parks: Great. And with your discussion in the release about making some adjustments to the rig count, and you also mentioned you saw other operators some signs of slowing. I’m just curious, have you €“ well, I guess two things, have you gotten any fresh body language from your vendors around €“ how they are sounding around pricing. I’m just curious, maybe when your next test case is going to be as far as having services where a contract is close to expiring, you might be going out for a bit and have a chance to sort of test the market on pricing.

Josh Viets: Yes. So on the inflation question specifically, at this point, just with the oil commodity markets remaining somewhat constructive, we’re simply not seeing much softening in service costs to date. There are some areas that we expect to pull back as we get into the second part of the year. One of those is OCTG. But right now, as we look at our inflationary estimates, we do expect to see some year-over-year inflation in the Haynesville, probably something pushing 10% on a cost per foot basis, we would expect the Marcellus to really be less than 5% in the low single digits. But one of things I would point out to you is that as we look at our inflation, and we look at year-over-year inflation, it’s important to us to think about it on a net basis.

So i.e., what are those things that we’re doing to extract cost out of our business. And one of those is we will drill longer laterals this year where our lateral length is going to be up 6% to 7% year-over-year. And then the other thing that’s going to impact it, again, if you think about on a net inflation basis, it’s just a well mix. So for example, in the Haynesville last year, we tilled 70% of our wells were in the Haynesville 30% in the Bossier. This year, it’s going to be much more weighted towards the Haynesville and less so towards the Bossier. It’s about 90-10. So that also will impact our inflation. So when we look at things at a corporate level, that net inflation is somewhere in the low single-digit. Now as far as flexibility with our contracts to go out and rebid work, we have a lot of flexibility, probably more so on the frac side.

But again, I think until we start seeing any softening in the oil markets, we’re not sure, at least we’re not baking any material cost inflation as we worked into the back half of this year.

Noel Parks: Great. Thanks a lot.

Operator: The next question comes from Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston: Hi, guys. Thank you. First, just a clarification on your plans to reduce rig and frac activity for modeling purposes, in the release, you mentioned plans to drop three rigs in total, but maintaining your existing number of frac crews, but in the slide deck, you referenced dropping two rigs and two frac crews. It sounds like from your earlier comments that it is three rigs in total, but what’s the plan on the frac crew side?

Josh Viets: So between Haynesville and Marcellus, we run €“ would intend to run around four crews if we were at our current activity levels. But as we’re dropping rigs, we do have plans to reduce the frac activity. So currently, we’re at one frac crew in the Marcellus. Again, normally, we’d be running two. So we dropped that frac crew. It will come back later in the year in the second half of the year for a period of time as we build up some inventory with the rigs that we’re running today. In the Haynesville today, we’re running two frac crews. We do expect as we work through the course of the year, that will drop the frac crew later in the second quarter. And then that frac crew would come back late in the third quarter. And so in aggregate, we do €“ we see ourselves flexing between two and four frac crews in the gas basins throughout the course of the year.

Phillips Johnston: Okay. Perfect. Makes sense. And then Slide 19, you highlight investment-grade achievement as near-term value catalysts. Obviously, you can’t directly control the timing there. But could you maybe touch on your recent conversations with the rating agencies? And what they still need to see before upgrading your ratings?

Mohit Singh: So this is Mohit. We remain actively engaged with the rating agencies. The influx of cash that we will expect at the closing of these divestitures, that’s considered positive from the rating agency perspective. Overall, what they need to see is just some more seasoning and time and financial policy and financial discipline, which we continue to demonstrate. They like all of that. It’s just more a matter of time and continued engagement. And we remain confident it’s a matter of time until we get to investment rate.

Phillips Johnston: Sounds good, guys. Thank you.

Mohit Singh: Thank you.

Operator: The final question today comes from Nicholas Pope with Seaport Research. Please go ahead.

Nicholas Pope: Good morning, everyone.

Nick Dell’Osso: Good morning, Nic.

Nicholas Pope: I was hoping you guys could talk a little bit about potential for M&A opportunities in Haynesville, Marcellus, Obviously, you’re going to have €“ if these two deals close, a fair amount of cash on hand, Gas prices are low. Just curious what the landscape looks like in both those areas, if that’s something that you are targeting, you could target? And also, on the Marcellus side, is there any limitation because of the structure of the ownership that 50% stake that limits if you being able to go out and add additional or is that not a factor?

Nick Dell’Osso: Second question first, that’s not a factor. First question, bigger question, what does the M&A landscape look like to us? It’s interesting, I guess. When prices are low, people think hard about their strategy going forward and how they participate in the upside as prices inevitably rebound. I’m sure that the industry will have plenty of chatter around M&A as it has had for the last couple of years. We think consolidation is a trend in the industry that matters. We’ve been vocal about that. We think the opportunity to allocate capital across a bigger set of assets, therefore, constantly high grading how you allocate capital. is important, and we think you optimize cost structures when you do that, and we think you generate overall better returns for shareholders.

But I would just continue to note something that we’ve said all along, which is that M&A is hard €“ and it’s really hard to get buyers and sellers to agree on values that we would find would meet our non-negotiables. And our non-negotiables haven’t gone away. We continue to print them in our investor presentation for a reason. And we know that we’re going to have some liquidity this year, and we know that there is going to be some volatility in the market. We also expect that volatility to result in some attractive opportunities to buy our own stock. And so we will weigh our non-negotiables, we will weigh the attractiveness of our own stock, we will weigh all of those factors around if anybody wants to engage in an M&A discussion, is it something that is truly a good answer for our shareholders.

And if it’s not, we won’t engage. If it is, we will find out if there is a viable path forward. But M&A is hard. And it’s not something that just because you have some cash around, you’ll go pursue in a different way than you otherwise would because if you’re doing the right M&A, it’s financeable. I’ve always believed that. And so having cash can be a cost of capital advantage at times, but that’s it because otherwise, your capital is the €“ your cost of capital is reflected in your stock price, it’s reflected in the way that you trade, and it all has to work which is, again, very much in line with our non-negotiables and just having cash doesn’t make it necessarily more attractive to do M&A. Deals have to make sense. They have to be accretive.

You have to buy assets that you can make better by consolidating them into your existing portfolio, thereby creating value for both sets of shareholders that wasn’t able to be created on its own.

Nicholas Pope: Got it. I appreciate that. One thing €“ another item on modeling, the guidance for 1Q for NGL is a pretty big uptick, is that just related to the NGL price strength relative to gas and an expectation about the injection. Is there a fair amount of flexibility down there in South Texas or why that €“ we’re seeing the jump in the guidance on the NGL?

Nick Dell’Osso: It’s probably just a mix. We may have to follow-up with you on that. But obviously, we have our volumes in the rich gas area, which has a fair amount of NGLs that are going up based on the investments we had in the Upper Austin Chalk last year, and so then just the mix of assets and pricing is probably affecting that a little bit as we look at 2023 relative to 2022.

Nicholas Pope: Okay. That’s all I had. I appreciate the time, everyone.

Nick Dell’Osso: Alright, thanks a lot.

Nick Dell’Osso: Okay, thank you all for joining the call this morning. I think that was our last question. I appreciate everybody’s time. We think it’s a really interesting time in the market. We really like how we’re positioned. We think that there is an opportunity to create a lot of value for shareholders in a down market. When you have the cash flow, the liquidity and the overall strength that we have, we think this is the time the companies differentiate themselves, and we look forward to doing that for our shareholders. So we look forward to this being a really important and value-creating year for Chesapeake. We look forward to talking to all of you as we see you out at conferences or over the phone. Thanks a lot.

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