Thank you, Rocco. Good morning, everyone. And thank you for joining our call today to discuss Chesapeake's fourth quarter and full year 2023 financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday. During this morning's call, we will be making forward-looking statements, which consists 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 and the other SEC filings. Please also recognize that as exempt 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 help facilitate comparisons across periods and peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure, which can be found on our website. With me today on the call are Nick Dell'Osso, Mohit Singh, and Josh Viets. Nick will give a brief overview of our results, and then we will open up the teleconference to Q&A. So with that, thank you again. And I'll now turn the conference over to Nick.

Good morning. And thank you for joining our call. We continue to execute on our strategic pillars in 2023, proving we're a company built to deliver sustainable value to shareholders through cycles. The Marcellus team had another strong year with well cost improving 17% since Q1. We increased our footage drilled per day by 40% and drilled nine of the ten longest laterals in our history in the basin. In the Haynesville, we delivered strong production performance throughout the year, benefiting from improved gathering system hydraulics while our drilling performance continues to outpace our peers in the most difficult drilling environment in the Lower 48. Importantly, we accomplished these operational milestones while improving our total recordable incident rate by 40% to an industry-leading 0.14 injury rate. Additional highlights for the year include returning approximately $840 million to shareholders via dividends and buybacks; advancing our path to be LNG ready by securing HOAs up to 3 million tonnes per annum linked to JKM and recently signing an LNG sales and purchase agreement with Delfin and Gunvor for long-term liquefaction offtake; completing our Eagle Ford exit for a total consideration of greater than $3.5 billion and receiving credit upgrades from all three agencies and exiting the year with a cash balance of approximately $1.1 billion. Turning our attention to 2024. We started the year by announcing our shareholder value-driven merger with Southwestern. Our combined company will accelerate America's energy reach by accessing more markets, effectively mitigating price volatility and ultimately increasing the revenue per unit of the product we sell. We are very encouraged about the growth and long-term demand for natural gas, the affordable, reliable, lower carbon energy the world needs. Today, the market is clearly oversupplied. In addition, we see capital supply cycles that can take 12 to 18 months to evolve while demand fluctuates quarterly. While we will benefit from a strong hedge position, we are responding accordingly with our 2024 capital and operational plan. First, we are reducing capital by nearly 20% and production approximately 15% from the preliminary outlook we provided last quarter. Under our revised capital program, we plan to limit our turn-in-line count to 30 to 40 wells with the majority having already occurred in January and February, drop two frac crews, leaving one frac crew in each basin and drop two rigs, resulting in four rigs in the Haynesville beginning in March and three rigs in the Marcellus beginning midyear. We believe limiting turn-in-lines and building DUCs is the prudent response to today's market. Doing so will shorten our cycle of supply to appropriately and effectively meet market demand. This results in shorter cycle capital-efficient decisions that will ultimately offer incremental capacity of up to 1 Bcf per day by the fourth quarter, ensuring we have ample supply to provide customers when demand recovers. Ultimately, our plan is designed to maintain productive capacity which positions us to quickly return to over 3 Bcf per day with minimal incremental capital investment. We will be prudent in our approach, bringing production back online efficiently as consumer demand warrants. Overall, our 2024 program demonstrates Chesapeake's continued focus on capital discipline, operational efficiency and free cash flow generation, while building the capacity to consistently deliver for consumers and shareholders through all demand cycles. Simply put, Chesapeake is built for the volatility we are experiencing today and our strategy is positioning the company to thrive as the market rebalances into 2025. We have the portfolio, balance sheet and demonstrated operational track record to continue driving capital efficiencies, maximizing returns and reducing risk. I look forward to updating you on our progress throughout the year. And we're now pleased to address your questions.

Today's first question comes from Josh Silverstein with UBS.

So I wanted to start just on the game plan that you guys have outlined here. The 1 Bcf a day reduction in this plan, was this a function of the base declines that you have with the lower rig count or asked another way, what are the other iterations that you guys came up with for the outlook?

I want you to consider the current production decline as a result of base declines, since we're primarily halting turn-in-line wells that were already in progress. We are doing this because we recognize that the market is oversupplied at the moment. The capital expenditure reductions we, along with others in the industry, implement will affect production in several months, possibly up to 12 months. For our business, we believe the best approach is to reduce production now. Given the current oversupply, the value for these turn-in-line wells reflects that situation. Therefore, we think it is wise to hold onto that productive capacity and only bring it online when demand increases and the market is not oversupplied. This strategy allows us to respond more quickly. The production figures we provided are intended to give you an idea of the productive capacity we could develop to respond to market demand by the end of the year. We mentioned it as a billion cubic feet per day if all those wells were turned online in one quarter, although that's likely not realistic. We would probably introduce them gradually, assuming demand rebounds in a measured way, allowing for a proportional return of production. But that figure represents the total volume that would be prepared to respond.

And then just given the volatility in natural gas prices you've seen over the past couple of years, do you think you'd want to operate with a backlog of wells going forward? This way you could respond to the changes in price environment, your balance sheet and interest rates can afford that. So I'm curious how you're thinking about operating going forward?

I believe that our decision to pause turn-in lines and slow down completion activities and drilling to align with market conditions demonstrates our flexibility. We are extending the cycle times for previous investments, and we could potentially accelerate those cycles in the future if the market requires it, enabling us to produce more in a shorter time frame relative to our expenditures. We appreciate having this flexibility in our operations. If the market continues to show signs of being undersupplied, we have the option to invest more capital to increase our productive capacity beyond current levels. This strategy aims to maintain our productive capacity around 3.2 Bcf a day, with maintenance capital anticipated to be between $1.5 billion and $1.6 billion for that production level, which remains unchanged. We are allowing cycle times to extend and managing our base decline to alleviate the current oversupply that negatively impacts gas prices, while also positioning ourselves to deliver production more effectively when market demand increases.

Our next question today comes from Charles Meade with Johnson Rice.

I want to continue along that line of questioning. You've already provided a lot of insight, but what you're describing is a new approach compared to what I've observed in the industry over the past several years, particularly in terms of building DUCs and TILs. Can you elaborate a bit on how you plan to sequence the spending on DUCs versus bringing TILs online? I can envision a couple of different scenarios. While I don't expect you to share a specific price at which you'll act, it’s possible that when you reach your desired price, you might bring your TILs online first and then follow up with DUCs. Alternatively, I can see a situation where you continue operating a completion crew without bringing wells online, so you would work through the DUC inventory first. Could you provide more detail on how you're approaching these new aspects?

I'll start and Josh may have something to add here. But the way we're thinking about this, Charles, is we will be paying very close attention to the underlying fundamentals, the underlying supply and demand situation in the market. And we'll try to bring gas online when we see that there is demand that needs the gas. Today, we are filling storage or not drawing from storage at the levels consistent with the past, which is setting us up to have pretty full storage going into the next storage season next fall. And so we can see very clearly that the market has more supply today than there is demand on an annualized basis. And so we think we should hold back our supply to better meet that demand in the future. We know that demand will grow in the future. We have confidence in that and we believe we should be more efficient with the capital we have spent, the wells that we have in cycle and the wells that we will continue to have in cycle. And so this really is about making sure that we are continuing a business from a capital perspective that is efficient at drilling wells, is efficient at delivering productive capacity, but that we can then have the flexibility to hold that production for the times that it's better needed. I want to reiterate that we are pretty optimistic about the future for gas markets and this allows us to better deliver production when it's needed, where it's needed into those markets as demand is present and ready for it.

I think just the other thing I would comment on is we're going to be very prudent around how we activate production. And the optionality that we like about the deferred TILs is that it gives us an immediate response when we see that structural change in the gas markets. And so we would anticipate that we would start to activate the TILs and then we would likely soon after begin starting to activate some of the DUCs. But one thing to keep in mind is that any production associated with those deferred completions is effectively going to lag by a quarter. And so we do see that as effectively starting to backfill the TILs that we're starting to activate in the prior quarter. So we really like the cadence that is set up by this. And again, we think it offers quite a bit of flexibility for us going forward.

And then my follow-up, it looks like to us like on a pro forma basis, like 20% decline, '24 versus '23, and that's a little bit higher than I would have guessed. And Nick, you may have given part of the answer already with the majority of your TILs for the year already haven't happened. But I'm wondering, is there also perhaps some kind of elective production restriction in there maybe through deferred midstream projects, or is there anything else that is contributing to that decline beyond just the pause in TILs?

No, really the decline is being by the deferred TILs. You have a material amount of production that we're simply choosing not to enter into the system. And so that is ultimately what's leading the decline. And so what you see on a year-over-year basis or if you want to think about it from Q4 to Q4 is effectively the underlying base decline of the assets that we operate today.

And our next question comes from Matt Portillo with TPH.

Maybe Nick, just starting out at a high level, I just wanted to come back to the philosophical view on the capital allocation cut here. Looking at your hedge book that you have in place, it looks like your breakeven could have been justified on maintenance capital at a very low gas price in 2024, and you've obviously taken a very decisive step here to help correct the market from an oversupply perspective. Just curious how the team arrived at that decision and how this may kind of play out in regards to your views on return on capital and how you might think about adding back to the market in '25 and '26 as it relates to production?

Let me begin by clarifying that we do not see this change as an effort to fix the market. Instead, we view it as a prudent approach to managing our assets and ensuring cash flow generation for our shareholders. We believe that one company cannot resolve market issues, so our focus is solely on what is best for our company and shareholders each day. When it comes to hedging, we distinguish it from our capital deployment decisions. Hedges are linked to our historical capital deployment and provide financial protection for paper gains and losses, but they should not distract us from the supply-demand fundamentals that affect the pricing of the physical product we sell daily. The decision we've made today is entirely focused on our productive capacity, which we've invested in throughout 2023. Currently, the market indicates that there is little need for our gas, and we have the flexibility to defer its delivery until demand increases. We evaluated various scenarios, including potentially more substantial cuts to our capital program, but we concluded that such choices would lead to significant impacts on our 2025 production, which we do not think is wise given current fundamentals. We anticipate a notable increase in demand by 2025 as additional LNG capacity becomes operational and as domestic demand for natural gas grows. We also expect improvements in supply dynamics by then, considering the significant capital cuts across the industry last summer, the effects of which have yet to materialize. The cycle of capital and supply can take 12 to 18 months, and the maximum supply to the market was observed last fall, with ongoing effects today. The increases in capital expenditures associated with that supply response began in the summer of 2022 and continued into early 2023 until major reductions occurred in mid-2023. The time lag for capital expenditure decisions is substantial, and we aim to respond effectively to current market conditions while recognizing that capital decisions have lasting impacts. Therefore, halting certain wells can have an immediate effect on our resource economics.

And then maybe as a follow-up question for Josh. Just curious how we should be thinking about the outlook for 2025? I know it's still a long ways off. But trying to think through how long it might take you to get back to more of a maintenance program as it relates to your rigs and your frac fleets? And then effectively, is it still fair to think about the timing being from about six months from when a rig hits the ground to when we should be expecting production to turn-in-line? I know you've got, obviously, the deferred TILs. But just thinking about kind of the base program, how that might progress over the next 12 to 18 months and what we need to see maybe fundamentally to start to pick back up towards the maintenance level on the base program?

First of all, I mean, we clearly are looking for structural shifts in the demand side of the equation for us to be thinking about getting back up to some maintenance level of activity. But I think the way, again, that we would likely start to phase in activity is starting to activate our deferred TILs first. We then begin to activate our incremental frac crews, which would take us to a total of four frac crews across our business today, and then in the way we would think about any additional rig additions. So again, as we go down from five to four rigs in the Haynesville and then from four to three in the Marcellus is as we start to deplete the deferred completion inventory down to something that we would consider to be a more normal working level, we would then start to bring those rigs back. And you're absolutely right. As far as kind of a typical cycle time, you are looking at roughly six months from the time you add a rig to actually start seeing any meaningful production impact from those rigs.

And our next question comes from Nitin Kumar with Mizuho.

I want to start off, Nick, by discussing the framework you've put together. It seems like you're keeping a balance between Appalachia and Haynesville, as both are declining at similar rates and the mix remains consistent. Would it have been more effective to decrease Haynesville a bit more quickly? I'd appreciate any insights on that.

Well, just keep in mind that pricing is different in both of the assets. And so certainly today when the market is oversupplied, you're receiving quite a low value for gas and the Marcellus storage is quite full in the Northeast. And so we do see it prudent to reduce turn-in-lines in both basins to what is something pretty close to zero for the rest of the year. Good news is we can change that quickly if the market changes and shows us that the gas is needed and we can change that by region if there is a shortfall or improved market in the Northeast; we can change that separate and apart from the Haynesville. So we maintain full flexibility but we just see pretty similar market conditions in both places right now.

And then for my follow-up, you mentioned that one company cannot fix the market, but you're about to become much bigger somewhere in the second quarter. The size of this deferred TIL inventory that you're holding, I know you can't comment on Southwestern's plans. But is this the right size for just Chesapeake or do you think this could be the right size for a combined company down the road?

We're just thinking about Chesapeake here.

And our next question comes from Bert Donnes with Truist Securities.

I just wanted to follow up and clarify one of your previous comments. Is there a limit to the amount of DUCs you would build if we see a prolonged down cycle, maybe the 1 Bcf is kind of the limit maybe like that amount as you saved up ammo or would you start dropping rigs immediately in ‘25 if we saw sustained down cycle?

That was part of our rationale for why we wanted to start taking rigs out now. You get to a certain point with DUC inventory where it simply starts to look and feel like inefficient use of capital. And so that's why we'll be dropping a rig next month in the Haynesville and then another rig in the Marcellus in July. So that is absolutely a consideration for us as we think about the allocation of capital to rigs and frac crews.

Was it a limit based on DUCs or was it the production amount that was the limit? It seemed like a neat figure at 1 Bcf, and I wasn't sure if that was the determining factor or if it related to how your rig frac crew would operate.

I mean we clearly looked at both. But we really just tried to balance what we thought was a meaningful amount of production that we could activate with an efficient use of capital going forward. So there was simply a balance that we try to strike between the two.

And then I'll shift gears to stop hammering that point. I'm just trying to understand the buyback activity in 4Q. Was that cut short due to the merger announcement or would there have been kind of a similar amount, even if you didn't enter a blackout period? And maybe if you could reconcile that against the cash, free cash flow being technically negative in 4Q, yet you still had some activity?

Look, we were really comfortable executing our buyback throughout 2024. Obviously, once we got deep into the merger discussions that activity had to pause. We are not able to restart that activity while we have a pending transaction like the merger out there. So in the future, we'll be back to buying back stock when we can and look forward to that day. But I'd just remind you that inclusive of buybacks and dividends in 2023, we had an 8% return to equity, pretty robust, and we felt good about that number. And I guess it's a fair statement to say that if we weren't engaged in those discussions we probably would have continued to buy some stock through the end of the year.

And our next question comes from Doug Leggate with Bank of America.

Nick, the markets just opened, and gas stocks are up, with gas prices increasing by 17%. I want to highlight the strong leadership you've shown in navigating this situation, which the rest of the industry should take note of. My question has two parts that are related. First, you are still planning to spend $1.3 billion this year. However, I see that by the end of the year, you're establishing a spare capacity of about 1 Bcf a day, which reflects a 30% decline. If I simply add these numbers together, with the exit rate being approximately 2.2 plus 1 Bcf, you essentially return to your maintenance production level but at a significantly lower capital expenditure of $1.3 billion compared to the $1.5 to $1.6 billion you've mentioned. What am I missing?

Doug, the key point is that to maintain production at the 3.2 to 3.3 level in the fourth quarter, we need to return to a regular schedule of maintenance activities. This includes completing about 15 to 20 wells each month and ultimately operating five to four rigs between the Haynesville and Marcellus. The essential factor is that while we can increase production, we also need to allocate capital to maintenance levels to support that moving forward.

So we shouldn't think that there's an implicit reset in sustaining capital now that the Eagle Ford has gone.

No, we don't see that.

My follow up is…

I would add, Doug, we did say in our opening comments that we're continuing to see some good capital efficiencies across the assets. We had record wells drilled in both the Marcellus and Haynesville. We continue to focus on capital efficiencies across our assets and generally, we find that these times when you reduce activity or when you make real progress. And so we're looking forward to 2024 being another very strong year from a capital efficiency standpoint, continuing to improve our pace of drilling, our cost per stage of completions and our overall effectiveness at bringing wells online for the maximum productivity for that given location at the lowest possible cost.

And obviously, I know you don't want to talk about Southwestern, but presumably, this would be the strategy for the combined company. Fair point?

Well, I mean, again, when we think about the decisions we're making for capital allocation for this year, it has nothing to do with our merger. This is just simply looking at the productive capacity we have today, the market conditions we see in front of us, making the best decisions we can make for our shareholders. Now the concept that a company with a very strong balance sheet and a large production base can basically use the turn-in-line cadence available to us much the way that we would use storage if there was more storage available in the market is a strategy that I think could be deployed in the future and we would look forward to considering those opportunities. But our hope is that by the time you get to 2025, you have a step change in demand. We see growing demand for gas. We will be in a position to continue to deliver the most efficient, lowest cost gas we can to the market as quickly as we possibly can to a market that needs it. We think that's the more likely future for us.

My follow-up is a quick one. Again, to the extent you can speak to this, Nick. You haven't had an FTC request, a second FTC request, I should say. You're still talking notionally about second quarter close. If we look at everything else going on in the market, one would assume that you're probably going to get a second FTC request. My question is, does that have any impact on integration planning or does that go ahead anyway?

No, we're well into the weeds of integration planning at this point. We have a tremendous amount to work on, very busy. We have teams that have been set up and working through how to think about a pro forma organizational structure, all the business processes, all the IT systems, all of the things that you plan for. We will be ready for a quick close. We can continue to work on things from an integration standpoint. If it takes longer, we won't let that distract us or bother us in any way. We're well into the work required for a successful integration.

And our next question today comes from Paul Diamond with Citi.

Just a quick one on the kind of more the operational side of those deferred TILs. How should we think about any potential movement just on the type curves, whether it's increased pressure bleed or maybe increased saturation. Do you guys anticipate those type curves looking any different from just normally completed wells and normally tied wells?

No, we don't. We've been operating these assets for well over a decade. And so we have a lot of experience being in a situation where we had to defer completions and in this case, defer TILs. And actually, through the years, we've seen some benefits to this where we simply see the water and dive into the reservoir. And so as we start to reactivate the production, we see similar gas productivity but less water production which, of course, is beneficial from an operating cost standpoint. So no, we do not anticipate any change to type curves.

I want to revisit a point from the prepared remarks about the 70% improvement in well costs in Marcellus. I'm curious about your thoughts on how this progress will continue, specifically what your internal target is for further enhancements in that area.

I mean, the teams have done an unbelievable job this year really across the whole company, capturing efficiencies. We quoted there a 40% improvement in our footage per day. On top of that, starting in the fourth quarter, we are starting to see some deflationary elements start to show up in the cost with the biggest mover being on the OCTG side, which has come off for us around 40%. So we do think there's some tailwind coming into the year. We guided at the end of last year to around a 5% to 7% deflation from kind of year-over-year levels. We still feel pretty good about that right now. We're anticipating the Marcellus to be around 10% year-over-year cost improvements, which is a combination of deflation, extended laterals, which were going to be up about 15% or so and just execution efficiencies that we see showing up in the system. And my expectation is we continue to get better as well and we start to see costs beyond that 10% that I've quoted here.

And our next question comes from Michael Scialla at Stephens.

Nick, you mentioned you probably wouldn't bring back the 1 Bcf per day in any given quarter. But if you do get the step change in demand that you're anticipating, how quickly could you bring that Bcf per day online? Does it take a full quarter or is it something less than that? And are there any infill constraints or anything that you need to be thinking about there?

There's going to be some operational considerations as we start to reactivate the production. It's just simply logistics planning around managing gas, coming into gas gathering systems and water. And so we think that over the course of weeks, if not months or a quarter, it's over a matter of weeks, so say, month. We think we can start to reactivate that production. But I'd just remind you, we're obviously going to be monitoring the markets in each of the basins, though they are very different, they have different market dynamics. And so it could be that we start to phase in TILs in one area and not the other with that may be lagging behind. And so I think there's just a number of considerations. But the teams are well prepared to manage this type of activity and anxious to see what they do with it.

And just a follow-up to that. With the reduction in volumes you have, are there any commitments with momentum or any other pipelines that will come into play that you need to keep an eye on?

So the way you should think about momentum pipeline, the volumes that we have committed there, which is 700 million a day, is essentially volumes that we would read out from existing pipelines. So this is not a volume that we are growing into and that's just altering the flow path and moving volumes around on the pipeline network. So it doesn't really constrain us or put any restrictions on us with regards to how we grow it. So you shouldn't really worry about that constraint.

And our next question comes from Ati Modak with Goldman Sachs.

Just curious if you can provide any color on how you are thinking about the deleveraging plan given where the strip is, and what that means for free cash flow this year? I know you have cash on the balance sheet. But is there a minimum cash you would like to retain through the year as you go paying down debt?

I'll start and then Mohit may have more to add here. I just would reiterate that as a stand-alone company, we don't have a debt reduction target. And so as we think about our 2024 plan, we're very, very comfortable with all of the decisions we're making and the very strong balance sheet we have, frankly, with and without these decisions being made. That said, pro forma for the close we will be very focused on debt reduction. One of the reasons we find ourselves in the position we're in today, which is to be able to be a very efficient consolidator, in a merger context with Southwestern, to be able to have the capital flexibility we're showing with how we're directing our production cadence this year, all relates to having a very strong balance sheet. It will be a top priority of this company to maintain a strong balance sheet through these cycles. And we see that being absolutely front and center for our strategy and something we expect to deliver on regardless of the market conditions.

The only thing I would add to that is coupled with a very strong hedge book and $1.1 billion of cash that we have on hand, it's a pretty strong balance sheet. So from a leverage point of view, we feel pretty comfortable. And then when you start looking at the maturity profile of the debt that we have also, so there's no near-term maturities, which are coming up. So as a stand-alone company, we are pretty comfortable with where we are. And as Nick said, once we are post close with Southwestern then we'll have a slightly different approach.

And then with the activity and production guidance you've given, how should we think about the cadence of production through the rest of the year? It sounds like it could be a steady quarterly reduction, but any color you can provide there if it's going to be a step change or steady? And then also help us understand what the cadence is between the Appalachia and the Haynesville assets?

Maybe just kind of address the second question first. Really, at this point, that's just undetermined. Again, there's different market dynamics between each area. Each of the assets have different cost structures that's going to guide that ultimate decision on how we restart tilting wells or activating completions. As far as the production cadence, again, we stated that we'll have 30 to 40 turn-in-lines for the year. We've already turned in line 25 of those. And so as a result, we are anticipating quarter-over-quarter decline. And as we look at kind of Q4 of '23 to Q4 '24, we see that equating at a corporate level to just under 30% with Haynesville being slightly above that and Marcellus being slightly under 30%. So it will be a pretty steady decline.

And our final question today comes from Phillips Johnston with Capital One.

I appreciate your comments, but you can't really speak for Southwestern. I'm just curious about when you plan to provide pro forma guidance that reflects the impact of the deal. Is the timing likely to be around when it closes?

I think that's a good safe assumption, Phillips.

And then, Nick, I'd be curious to hear your high-level thoughts just on the administrations all on the LNG front and what you think that might mean for the long-term gas market?

We are still really optimistic on the long-term gas market. And that's just based on the underlying view that natural gas is the most efficient answer to energy supply challenges around the world. Those supply challenges come from shortages or limited access to energy broadly, they come from climate concerns, they come from political and stability concerns. And natural gas is really the best answer, especially natural gas in the US is the best answer to all of those challenges. As a result, we think that the administration will ultimately find a very strong answer as they review the need for permitting approvals here. We expect that, that will be seen positively as we see it and we expect this will move on in due time. I think it's unfortunate. I think it's not good for those parts of the economy that need incremental energy and need it as quickly as they can get it. This pause will slow things down a little, which is unfortunate and not great for those that are seeking incremental gas. But we have confidence that the merits of LNG export from the US will be seen by all and that approvals will be taken back up again in the future.

Thank you. And this concludes our question-and-answer session. I'd like to turn the conference back over to the management team for any closing remarks.

Okay. Thanks, Rocco. Really appreciate everybody's time today. We know that our approach for 2024 is a little bit different than we've been able to do in the past as a company and that we think we've seen from others. We think it very much addresses the challenge that is seen in the market today, which is a near-term oversupply and a long-term very structurally positive natural gas market. We're excited about the position we're in. We look forward to the ultimate aligning of supply and demand in the market and a recovery for natural gas broadly associated with that alignment. And we think we're really well positioned for that. So look forward to continuing to discuss this with all of you. We’ll be out on the road at a number of different conferences and events in the next week to two weeks, and look forward to engaging throughout the year. Thanks very much for your time again today, and we'll talk soon.

Thank you. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.