Good day, and welcome to the Chesapeake Energy Q4 and full year 2022 earnings conference call and webcast. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Star, then one on a touch-tone phone. To withdraw your question, please press Star, then two. Please note, this event is being recorded. I would now like to turn the conference over to Chris Ayres, Vice President of Investor Relations and Treasurer. Please go ahead. Thank you, Betsy. Good morning, everyone. Thank you for joining our call today to discuss Chesapeake's Q4 and full year 2022 financial and operating results. Hopefully, you've 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 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. With that, thank you again, and I'll now turn the teleconference over to Nick. Good morning, thank you for joining our call. This morning, we're going to talk about two key announcements we made yesterday. First, we're pleased to highlight our Q4 results and 2023 outlook. Second, we announced the next significant step toward exiting our Eagle Ford assets. The Q4 finished off a strong year for Chesapeake. Production and capital were essentially in line with expectations, and EBITDAX was slightly ahead. Based on those results and adjusted for the October 1st effective date of the Eagle Ford asset sales, we're 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 DeWitt, 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're pleased with the progress we've 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 a soft market. 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 bbl a day of oil and NGLs and 80 million cu ft 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've 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're dropping two rigs in the Haynesville and one rig in the Marcellus as we move through the year. In addition, we're 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 two 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 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. I'm now happy to address your questions. We will now begin the question-and-answer session. To ask a question, you may press Star, then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press Star then two. At this time, we will pause momentarily to assemble our roster. The first question today comes from Zach Parham from JP Morgan. Please go ahead. Hey, guys. Thanks for taking my question. I guess. Sorry. Just on the buyback. You talked about being countercyclical with the buyback. You know, you're gonna have a significant amount of proceeds coming in shortly when the Brazos and the oil window sale close. You know, can you give us some thoughts about how you plan to utilize those proceeds kind of in the H1 of 2023 and then to the back half of the year via the buyback, debt reduction, and other potential uses? We don't even have the cash yet, so, you know, 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 wanna be opportunistic with it. We'll be patient. We'll let the market come to us. We think there's ample opportunity in the coming year, to put this cash to work. Got it. Thanks for that. My follow-up is just on well productivity. You know, within the industry, there's been a lot of talk about degradation of well productivity. Looking at some state data, it does seem like your well productivity's trended a bit lower in both the Marcellus and Haynesville in 2022. You know, in the slide deck, you did highlight a lower drawdown in the Haynesville, maybe that's one of the drivers. You know, 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? Good morning, Zach. This is Josh. We've, you know, looked at this data as well. Of course, we recognize that, you know, the trends into 2022 did show a drop-off. To, you know, address maybe the Haynesville first, you know, we are looking at, you know, incremental drawdown strategies that will have an impact on early time rates. Really that starts to show up in the first three to six months of the production history. Really, we start to see something that looks like an incremental gain as you get out, you know, beyond 12 months. The other thing, just to remind you of, that's impacted, you know, our position within the Haynesville this past year, and I suspect in some others, is, the increased line pressures. With increased line pressures, that does lead to lower IPs, but ultimately flatter declines, you know, through the first, you know, 12 months of the year. In the Marcellus, you know, I think the thing that we need to remember is that, you know, we've been operating the Marcellus for, you know, well over a decade. You know, we've drilled, you know, over 700 wells within our lower Marcellus core, and these are, you know, unbelievable wells, you know, really the best, you know, 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 industry, we were having to high-grade locations, and this was no different for Chesapeake. We absolutely drilled, you know, the very best wells with a relatively modest program in the heart of our core. I think if you were to look back and compare our 2022 well results into something in the 2018 and 2019 timeframe, you'll actually see, you know, productivity that's, you know, on par. In fact, on an absolute basis, when you adjust for lateral lengths, you'll see a slight advantage, you know, on productivity. Really that's gonna be our focus going forward is extending laterals. We've done so by increasing our lateral lengths by 65% in the Marcellus over the last five years, and we're gonna continue to do that. Got it. Thanks, Josh. That's great color. The next question comes from Nitin Kumar with Mizuho. Please go ahead. Hi. Good morning, guys, and thanks for taking our question. Nick, I'm gonna start with the kind of elephant in the room. You know, gas this morning breached $2. What is your macro outlook for gas, you know, now that you're transforming into a more pure play gas company? Curious how you're looking at both the near term and the medium term. Yeah. Hey, good morning, Nitin. Our macro outlook for gas hasn't changed. We are very bullish the long-term natural gas fundamentals, and we've been cautious the 2023 setup for quite some time, and we've 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 setup. 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 gonna show up to market, and you don't really have any structural demand growth for, you know, at least a year. Really in the end of 2024 and into 2025 is where you start to expect LNG export capacity to expand. That's how we're gonna 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'll never be perfect at timing that, but, you know, we do think that there are some long-term trends here that we can plan for. I would just note that, you know, while this morning's gas price dipped below $2, and that is a low level, and, you know, nobody likes that, we're really not bothered by this 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. you know, 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's plenty of demand for natural gas growth around the world, but we don't actually think that would have a meaningful negative impact to this long-term trend that we see. We remain bullish beyond 2024, and we think we can manage through a flat-ish 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. Great. Thanks. Thanks for that detail. My other question is around the momentum spending. It was a little bit higher than we expected for 2023. Sounds like it's just an acceleration, but could you maybe talk a little bit about what drove that acceleration and any specific milestones we should be looking for as that project starts ramping up and in terms of getting gas to that pipeline? The pipeline is on schedule, as originally contemplated to come online in the Q4 of 2024. Project's gone really, really well so far. We're very pleased with our partnership with Momentum here. All that has happened is just the timing of the cash calls has changed a bit. The total budget hasn't changed at all. We're thrilled with this investment. Great. Thanks, guys. The next question comes from Umang Choudhary with Goldman Sachs. Please go ahead. 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? Maybe you can touch on what you're hearing from non-operated partners in the Haynesville to recent gas price shifts. Good morning, Umang. On the service side, you know, we are absolutely exercising flexibility in the H1 of the year, with dropping three rigs throughout, you know, the first six months of the 2023 calendar year. We have a lot of flexibility on the frac crew side. We're, you know, gonna be flexing between two and four frac crews, you know, throughout the course of the year. Only one of those is actually under a longer-term contract, and that's, you know, 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. You know, to date, you know, we're not really gonna incur any incremental penalties on the rigs that we're dropping. It's a pretty modest amount, but that's something that we'll continue to work as we go through the year. As far as non-operated rigs, you know, we are starting to see some signs of operators pulling back activity, specifically in the Haynesville. It's been primarily showing up with the privates to date. We are continuing to see new ballots come in the door from some of our non-op partners. We're gonna continue to monitor that activity, but we are expecting operators to start pulling back with the weakness in the gas pricing we see today. Got it. That's really helpful. 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 from the industry? Hey, Umang, it's Nick. I'll take that. You know, 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. You know, there's always a little bit of inefficiency for the industry when a bunch of rigs are thrown in, so we think cycle times probably slowed down a little bit. When we take the total DUCs and we move off the DUCs that are probably more mature, the DUCs that are aged, so they're not likely to get turned in line. 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. It'll 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'll be a mix, is our assumption. 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 wound down. I would say that, you know, 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'd have a very different economic outlook for the Haynesville, and I think a lot of activity would shut in. I don't expect that to happen. I think the contango is there for a reason. 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. That's great. Very helpful. Thank you. The next question comes from Doug Leggate with Bank of America. Please go ahead. Thank you. Good morning, everyone. Hey, 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 as 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've achieved so far? Yeah. Hey, Doug, I'll 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. Sorry, my apologies. Yeah. Right. Yeah. That's what I meant. My apologies. No worries. 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, you know, the value of the PDP relative to the value of the upside available. I think the chalk wells that we drilled are pretty attractive and confirmatory of the upside value associated with the asset. We're still in an A&D market overall that doesn't end up putting a ton of value on undrilled locations. You know, we've been willing to be a little bit patient here and let those wells come online. We've really just released these well results to the public now. We'll be, you know, 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. We don't need to be in a rush. We've got plenty of proceeds coming in. We're making progress on the exit strategically. We'll be thoughtful about achieving a good result here. 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. Thanks. Yeah, I don't wanna start a rumor that you're selling the Haynesville, so my apologies for speaking. My follow-up is really a housekeeping question, so I apologize for this. It might be for Mohit. The transport costs, are there any MVC or other type of midstream obligations? There's some kind of ramification from the decline in production. Managed decline, admittedly, but, it just looked to us that your transport costs were ticking up a bit. I wonder if the two were related. That's my follow-up. Thanks. Thank you. 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. And then when you start looking at Haynesville, there's 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 know, 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. Overall, when you look across the portfolio, Doug, nothing that bothers us at this point from an overall obligation perspective. That's it. Thanks. Thanks, guys. Appreciate the time. Thank you. The next question comes from Matt Portillo with TPH. Please go ahead. Good morning, all. Morning. 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 2023 and in 2024. Just curious how you guys are thinking about the 2024 curve today. Yeah, thanks for that question, Matt. You know, it's interesting when prices were going up, we heard a lot of pushback from our investors that we should not hedge as much. What we did do is we stayed consistent, our plan is to hedge the wedge as we have described before, Matt. When we are making capital investment decisions now, the production comes on nine to 12 months later on. We want some certainty on the cash flow from that production, that's why we hedge. What, 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've done that both for 2023 and into 2024. 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. Perfect. 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-$4 in Mcf to make a return. I'm curious if you think the cost curve in the Haynesville over time is gonna tick higher as inventory depletes from maybe some of your smaller peers that are running a lot of activity in the basin? 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? The Haynesville is going to be the leading asset to deliver the volume growth into LNG. 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. We and a couple of others do own that very best acreage, the relative advantages, those with the best cost structure, the best full cycle return investment points for that gas are gonna win. We think this is setting up for exactly that. We think that you're going to have to have some higher cost areas of the Haynesville developed. We think you're probably going to have 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's 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, Northeast Pennsylvania as well as Southwest Appalachia, I think it would change the game on how the dynamics of the cost curve for U.S. gas works. We don't see that as a likely outcome in the near term, aside from, you know, maybe Mountain Valley, which is pretty close. We'd really like to see that come online and think that there's still a reasonable chance that it will given how close it is and how much the country needs the gas. New projects are gonna 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. 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. We think that's an important trend that will play out. 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. Thank you. The next question comes from Subash Chandra with Benchmark. Please go ahead. 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, you know, near-term physical constraints that are imminent? You know, whether it's physical constraints or producers just deciding to pull back volumes, we curtail gas almost every shoulder season. Given the price set up that's in front of us now, we're gonna expect to curtail some gas in the shoulder season. I got no idea what other producers will do, but they're gonna be staring at similar economics to us, so wouldn't surprise me if they did the same. That's a common occurrence for us. We get full pipes, we get uneconomic 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'll proactively manage that this year, just like we do every year. Okay. Okay. Thank you. That's helpful. Then I guess second, you know, so, the investment, you know, Marcellus versus Haynesville is sort of the inverse of the economics of the two plays, right? Marcellus being superior. I suppose that's part of your, you know, LNG ready strategy. Is there a point, though, where that maybe, the carrying cost of those, of the relative economics is too great, and, we see additional changes to CapEx? I'm not sure exactly what you're asking me, Subash. Are you asking me if we pull back more capital in the Haynesville in favor of more capital in the Marcellus? Yeah. I think the Marcellus being in superior economics, I think you're guiding for, you know, declining volumes there, but flat volumes in the Haynesville. Is that fair? If that's the case, you know, the Marcellus economics is superior, which, you know, might argue that you'd keep volumes there flat, allow Haynesville to dissipate. You're probably not because of the LNG-ready strategy, and if at some point you reconsider those economics. Yeah, I don't think that's actually right. We're looking at, you know, it's closer to flat in the Marcellus with a little bit of a decline in the Haynesville. Maybe we can walk you through that math after the call. You know, directionally, we're, I would say, following the economics right now. The one rig pullback into 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. We expect a very modest change in flow there. Okay. Never mind. That makes a ton more sense. Just finally, is there a cash on hand, sort of number that we should be looking at? Yeah. 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 de minimis, Subash. Okay. Thank you. The next question comes from Noel Parks with Tuohy Brothers. Please go ahead. Hi. Good morning. Morning, Noel. Just a couple of things. I wondered, with the Eagle Ford divestitures 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'll 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 sort of a pretty normalized G&A after the investments are taken into account. Noel, we'll have, you know, a handful of changes to our business as a result of a 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., we will be aiding them as they create that organization. It'll take a while for us to sort through all of that. We'll have some underlying changes to our business as a result. You know, you'll see that play through. Great. With your discussion in the release about making some adjustments to the rig count, and you also mentioned you saw in other operators some signs of slowing. I'm just curious. Well, I guess two things. Have you gotten any fresh body language from your vendors around, you know, how they're sounding around pricing? I'm just curious, maybe when is your next test case gonna be as far as having services where a contract's close to expiring, and you might be going out for a bid and have a chance to sort of test the market on pricing. Good morning. You know, on the inflation question specifically, you know, at this point, just with the, you know, oil commodity markets, you know, remaining somewhat constructive, you know, we're simply not seeing much softening in service cost 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. Right now, as we look at our in-inflationary estimates, we do expect to see some year-over-year inflation in the Haynesville, you know, probably something, you know, pushing 10% on a cost per foot basis. We would expect the Marcellus, you know, to really be, you know, less than five in the low single digits. One of the 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 think about it on a net basis. I.e., you know, what are those things that we're doing to extract cost out of our business? One of those is we will drill longer laterals this year, where our lateral length is gonna be up 6%-7% year-over-year. Then the other thing that's gonna impact it, again, if you think about on a net inflation basis, is just our well mix. For example, in the Haynesville last year, you know, we tilled 70% of our wells were in the Haynesville, 30% in the Bossier. This year, it's gonna be much more weighted, towards the Haynesville and less so towards the Bossier. It's about 90/10. That also will impact our inflation. When we look at things at a corporate level, you know, that net inflation is somewhere in the low single digit. As far as, you know, flexibility with our contracts to go out and rebid work, we have a lot of, you know, flexibility, probably more so on the frack side. 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 work into the back half of this year. Great. Thanks a lot. The next question comes from Phillips Johnston with Capital One. Please go ahead. Hey, guys. Thank you. First, just a clarification on your plans to reduce rig and frack activity for modeling purposes. In the release, you mentioned plans to drop three rigs in total, but maintaining your existing number of frack crews. In the slide deck, you referenced dropping two rigs and two frack crews. It sounds like from your earlier comments that it is three rigs in total, but, what's the plan on the frack crew side? Between Haynesville and Marcellus, we run, would intend to run around four crews if we were at our current activity levels. As we're dropping rigs, we do have plans to reduce the frack activity. Currently, we're at 1 frack crew in the Marcellus. Again, normally we'd be running two, so we dropped that frack crew. It will come back later in the year, in the H2 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 frack crews. We do expect, as we work through the course of the year, that we'll drop a frack crew, later, in the Q2, and then that frack crew would come back, late in the Q3. You know, in aggregate, you know, we see ourselves flexing between two and four frack crews, you know, in the gas basins throughout the course of the year. Okay, perfect. Makes sense. Then, slide 19, you highlight investment-grade achievement as a near-term value catalyst. 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? This is Mohit. We remain actively engaged with the rating agencies. The influx of cash that we'll 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've remain confident it's a matter of time till we get to investment grade. Sounds good, guys. Thank you. Thank you. The final question today comes from Nicholas Pope with Seaport Research. Please go ahead. Morning, everyone. Morning, Nick. I was hoping you guys could talk a little bit about potential for M&A opportunities in Haynesville, Marcellus. Obviously, you're gonna have a, 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 y'all are targeting, you could target. 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? Second question first, that's not a factor. First question, bigger question, what does the M&A landscape look like to us? You know, 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. We think you optimize cost structures when you do that, and we think you generate overall better returns for shareholders. 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. Our non-negotiables haven't gone away. We continue to print them in our investor presentation for a reason. You know, we know that we're gonna have some liquidity this year, and we know that there's gonna be some volatility in the market. We also expect that volatility to result in some attractive opportunities to buy our own stock. We will weigh our non-negotiables, we'll weigh the attractiveness of our own stock. We'll 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? If it's not, we won't engage. If it is, we'll find out if there's a viable path forward. M&A is hard. 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. You know, having cash can be a cost of capital advantage at times, but that's it. Because otherwise your capital is your cost of capital is reflected in your stock price. It's reflected in the way that you trade. It all has to work, which is, again, very much in line with our non-negotiables. Just having cash doesn't make it necessarily more attractive to go 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. Got it. Appreciate that. One thing. Another item on modeling. The guidance for 1Q for NGLs 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 for this? Why we're seeing that jump in the guidance on NGL? It's probably just a mix. We may have to follow up with you on that. Obviously, we have our volumes in the Rich Gas area, which has a fair amount of NGLs in it, are going up, based on the investments we had in the Upper Austin Chalk last year. Just the mix of assets and pricing is probably affecting that a little bit as we look at 2023 relative to 2022. Okay. That's all I had. I appreciate the time, everyone. All right. Thanks a lot. Okay. Thank you all for joining the call this morning. I think that was our last question. 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's 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 that companies differentiate themselves, and we look forward to doing that for our shareholders. We look forward to this being a really important and value-creating year for Chesapeake. We'll look forward to talking to all of you, as we see you out at conferences or over the phone. Thanks a lot. The conference is now concluded. Thank you for attending today's presentation. 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