Good morning, and welcome to the Chesapeake Energy Third Quarter 2022 Earnings Teleconference. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Chris Ayres, Vice President, Investor Relations and Treasurer at Chesapeake Energy. Please go ahead.

Thank you, Andrew. Good morning, everyone, and thank you for joining our call today to discuss Chesapeake Energy's third quarter 2022 financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday. During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements. Including the factors identified and discussed in our press release yesterday and in other SEC filings. Please recognize that, except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures which help facilitate comparisons across periods and with peers. For any non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measure and 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. I'll now turn it over to Nick.

Good morning, and thank you all for joining our call. Before we get to Q&A this morning, I want to cover 3 topics that we believe are most important to our shareholders. The first is our strong third quarter execution, second is our industry-leading cash returns and the third is our strategy to continue our momentum into 2023 and be LNG ready. So to start off, we had another strong quarter operationally. We delivered on our production in the Haynesville and Marcellus and had some great well results in the Eagle Ford. We did experience a few delays in Eagle Ford production due to facility delays that pushed some volumes into Q4, but believe those will be temporary. We're reaffirming our annual production and CapEx guidance ranges for 2022, reflecting our confidence in our delivery as we finish out the year. In the Haynesville, we've made significant strides with midstream capacity. We've increased our gathering and treating capacity by 25% for this year and up to 60% in out years. We've also committed 700 million cubic feet a day to a new pipeline to be built by momentum from the heart of the Haynesville play down to [Gilles.] This project also has an associated carbon capture and sequestration program with it. And we're really excited to be a part of this, we think, unique and transformational project. We have an opportunity to participate in up to 35% of the equity of the project, and we expect to take that option. This gives us greater than a Bcf day or more than 50% of 2024 and beyond Haynesville volumes that are contracted for Gulf Coast delivery and pricing with both the Momentum pipe and our Golden Pass transaction. In the Marcellus, our synergies from the Chief acquisition continue to come to…

[Operator Instructions] The first question comes from Scott Hanold with RBC Capital Markets.

Obviously, the Haynesville, you all are -- we're preparing to do more there. But I guess, the last couple of quarters, there had been some, I guess, constraints and there are a couple of different constraints. Can you just provide a little bit of color on that? And then to Slide 23, it looks like you've got some solutions, but just give us a sense of like timing and level of confidence that you have in this plan and strategy? Because it does seem like the Haynesville from an LNG perspective and just from a volume perspective, it's going to be important to you all going forward.

Yes. Great question, Scott. It's super important. I'll talk a bit about this and others may have something to add in here. But we have seen constraints. We've been talking about that for a number of quarters, and we've been active in contracting for incremental capacity, both on the gathering side as well as the treating side. We've also now contracted for incremental takeaway with the momentum pipe. And so we are positioning for what we do think is an opportunity to grow over the next few years. But in the near term, we really don't see any need for growth. And so 2023 is probably setting up to be about flat on a year-over-year basis but we'll have -- as we talked about last quarter, we'll have an exit to exit growth rate. So when you think about what we've done in the Haynesville, the beginning of last year, as we were integrating the buying assets and recognizing some of the constraints that existed, we dropped to 5 rigs. There's a lag effect on the reduction in rig count like that, and we're seeing lower turn in lines as a result of that reduction in rig count show up now in the fourth quarter as well as into the first quarter of 2023. That's really all exactly as expected and the capacity additions that we've contracted for, and you can see on that map on Slide 23 that you referenced, they do begin to show up as we move through 2023 and get into 2024. So we're right in line with aligning our volumes to capacity additions as we've been talking about. So volumes ticked down a little bit in the first quarter of '23 and then as we build our activity moving through the year, we'll see an exit to exit growth. And again, we think this is all very well timed with where we think the longer-term supply-demand dynamics will head, and we're pretty pleased with the setup.

Got it. And just to clarify that, so you've got your guide post for 4Q, which is a downtick and then '23 is another downtick before it goes up. Just wanted to clarify that.

First quarter of '23 should be a little bit of a downtick from there, yes.

Okay. Got it. Got it. Okay. And then my follow-up is on that Momentum pipeline. Can you just discuss a couple of things. One, the pricing dynamics around that for you all in the gas. And then number two, the CCS options, you talk about, it sounds like you're going to commit to the 35% participation. What kind of capital and timing around that capital would that result in?

Sure. So the pipe itself will deliver gas to [Gilles.] And so we'll pay a rate which isn't disclosed for -- we can't disclose it for the terms of the contract. But if you look at the market out there for FT in the basin, we think this is right in line with what other pipes are charging. We ran a pretty competitive RFP to determine which pipe we would participate in and ultimately selected this one. So we felt it was a really attractive overall rate on the pipe as well as market delivery solution and then the carbon capture piece was quite helpful as well. Momentum is also going to build a bit of gathering for us in the field. There was a couple of sections on the vine acreage that had yet to be contracted for wellhead gathering. So we've been able to tie that into this entire contract and get that done at a very attractive rate as well. The carbon capture element of it is going to take longer to be built out than just the delivery to Gilles. But the way this will work is that we will deliver the gas to Gilles inclusive of CO2, so it won't be CO2 treated in the field. The CO2 will all be removed at the delivery point, so you'll have scale in the removal of the CO2 before it goes further downstream to market. And then with that scale, you can afford to sequester the carbon. So we think it's a really innovative project. We're excited to be a part of it. And it's not done yet. We still have to finish the contracts and the documentation around the equity participation. But we do intend to do that. The cost to participate in the equity, of course, it's a projection, not completely known, but we would estimate probably around $350 million over a couple of year period. And again, the return on that investment to us should be quite attractive.

The next question comes from Umang Choudhary with Goldman Sachs.

I would love your thoughts on the macro environment here, given price -- gas prices have been so volatile and weak recently, and there are concerns around supply outpacing demand next year. And also, would love to get your thoughts around what price levels will you look to reduce activity in the Haynesville if, say, the winter pricing -- winter weather is more warmer than expected.

Great question, Umang. We spent a lot of time talking about the macro lately. It has certainly been volatile, as you suggest. And it has been headed a bit lower. The great thing about the gas market today is, well, it's been volatile and well, it's been headed a bit lower. We're still talking about gas prices at which our company makes a really attractive profit. And we generate great cash flows for shareholders. So we think we're really well prepared for either a weaker gas price environment or if it does turn cold and gas prices go back to being more robust, we're obviously prepared for that as well. I would tell you that based on the setup of growing supply that we see across the market today and demand that is really going to rely on weather in the short term, we certainly have our -- we're very well prepared for a weaker gas market here as we move into 2023. And we can't predict it, don't know if that will actually happen but if it does, we'll be ready for that. At what price would we reduce activity in the Haynesville is a great question. And there's no real hard and fast answer to that, Umang. It depends on a handful of things. One, it depends on how the curve reacts relative to just the nearest term months on the curve. And it depends on how we see the dynamics that affect that. So what the drivers really look like they are. We do remain super bullish on the longer-term supply-demand fundamentals, particularly for the Haynesville, but really for the U.S. as a whole. And so we will pay very close attention to the 2023 and 2024 setup as to really how that supply/demand is going to…

That's great. Clear. And my next question was on your capital spending outlook for next year. As you go through your budgeting process, any early read across in terms of how you're thinking about cost inflation and the impact on your spending next year? And then any -- you talked about enhanced completions and shifting to longer laterals. Any benefits from that as you add more of those into your program next year?

Yes, this is Josh. As far as inflation goes for next year, year-over-year, I think we're thinking it's going to be in the 10% to 15% range. And so if you think about the activity that we've been talking about kind of carrying forward 5 rigs in Marcellus. We're just in the process of adding a seventh rig in the Haynesville, which again, as Nick talked about, we'll continue to monitor the markets and be flexible with that program. And then a relatively steady 2- to 3-rig program in the Eagle Ford is the activity that we're outlining. So that's kind of how we see the year shaping up from a capital standpoint. And then you asked about the enhanced completions, if I maybe go ahead and address that. Really, where we're looking at that is going to be in the Marcellus specifically, and one of the things that we're attempting to do there is not only increased lateral links, but we're also looking at adding additional wells per pad, and that's one of the advantages we find with the toe development. The completion optimization there is really about fluid loading and we think there are some areas that benefit actually from less fluid. And so those are the things that we'll look at, which not only drives potential cost reductions and enhances our capital efficiency, but we also think there's opportunities there to increase productivity as well. So that comment was really specific to Marcellus.

The next question comes from Doug Leggate with Bank of America.

So Nick, I'm clearly losing the value erosion debate on the variable dividend. So I wouldn't plug that to that, but I do have a question on use of proceeds if and when you eventually sell the Eagle Ford, what should we think in terms of how you deploy that -- those proceeds, whether it be to incremental acquisitions to the balance sheet or indeed, to share buybacks, given that, I guess, you and -- does continue to see your share price undervalued.

Great question, Doug. So we've talked about with the proceeds from the Eagle Ford that we have a return model, we would think about applying these proceeds through that return model. We've said that the dividends really are about operating cash flow. This is not operating cash flow. So we would lean more heavily to buybacks when we think about the proceeds here. But importantly, I think, especially as we recognize that we could have a softer gas market here, at least for a year or a little bit more. And again, I think the softer requires a little bit of emphasis there because we don't really anticipate it to be a negative market for us as a company, just maybe not quite as robust as 2022 has been. We will pay down some debt with the proceeds. We will make sure that as we sell off an asset that has a lot of EBITDA, we make sure our balance sheet stays in great shape. So we expect to look at the proceeds that come in, think about what the right balance sheet impact is to reduce leverage and then think about the best way to pursue a return of some of that capital to shareholders through a buyback. But we'll have to wait and see when the proceeds come in, the magnitude of the proceeds and exactly how it all plays out to have specific answers for you, Doug.

Great. Thank you. It's a good enough answer. Thank you, Nick. I appreciate the directional color. I guess my follow-up is I hate to be predictable and ask about inflation, but one of your peers reported last night, not the right peers perhaps, but pointing to perhaps higher than consensus expectations, for capital. You guys haven't really given a '23 look yet, but your -- your fourth quarter run rate doesn't seem to be seeing a lot of cost pressure. So upward cost pressures. So I wonder if you could just give us a steer as to what you think in your 2 core basis, inflationary capital impacts could look like for the 2023 budget in that flat production profile you talked about. And I'll leave it there.

Yes, this is Josh. So first, on the Q4 burn rate, we do see some activity pull back in the fourth quarter because, of course, we dropped some rigs in the Eagle Ford. So that's pulling back our Eagle Ford spend. And then also we see a little bit lighter completion quarter in the Haynesville. So that's why our burn rate in Q4 will look a little bit different than maybe what we saw in the preceding quarter. As we think about 2023 and again, I'll kind of reference year-over-year inflation, we would expect to see the most inflationary pressures in the Haynesville. And so I think you're going to be looking at 15% plus there potentially, assuming we see rig counts stay relatively flat to where we are this year. In the Marcellus, we expect that to be a little bit more moderated. That basin just tends to be more stable in nature. And so the inflation that we're anticipating there is really going to be in the mid-single digits.

Yes, I'll just add that while we haven't given full CapEx guidance yet. We did put dollar per foot expectations for 2023 for both the Haynesville and the Marcellus in our slides today. Yes, that's inclusive of our expectations for inflation.

The next question comes from Zach Parham with JP Morgan.

I guess just another follow-up on Doug's question there. You talked about this 10% -- 10% to 15% inflation in '23 if we think about that in the context of the '22 budget, should we just add 10% to 15% on top of that and if so, does that include the impact of the seventh rig in the Haynesville and also any spending associated with the Momentum project.

Well, anything that we were -- I guess maybe on the momentum question specifically, I think anything that we've done in '22, of course, that's going to be an incremental capital expenditure that we would need to layer in. So that would be one clear addition if you're trying to come up with a 2023 estimate. But generally, we've guided you on activity. So the 5 rigs in the Marcellus, you need to account for the seventh rig in the Haynesville. And again, we've given you some guidance here on cost per foot. And then again, that 2 to 3 rig range in the Eagle Ford. I mean, we'll continue to look at other opportunities. One of the things we highlighted in the presentation today as we were successful in picking up some acreage in the Marcellus. We'll continue to look for opportunities such as that. And if there's more good opportunities such as that, that could also push up capital just a little bit heading into next year.

Got it. And then one just on the operational side. I think Nick mentioned that the average well performance would come down marginally in the Marcellus as you do more co-development. Can you just compare the Upper and Lower Marcellus well productivity, while both still clearly have very strong returns, what's the step down in EUR you expect on the upper versus lower?

Yes. Maybe I'll just stick to what we've disclosed in our presentation, but what we provided you in the deck is an estimate on a 12-month [indiscernible] per foot. And what you see there is it's just over 20% reduction on a per foot basis. But what I'll remind you of, though, is we do have the ability to drill longer laterals in the upper. And so that, on an absolute well basis, that starts to offset some of that productivity loss and we can drill longer laterals just simply because there are fewer wells to be navigating around. And that's why we see such an opportunity here and drilling wells that really, really competitive returns. In addition to that, I'll just add something that's not necessarily layered in here explicitly which is with the upper and co-developing it with the lower, we can put more wells on a pad, and that creates additional capital efficiencies, which we think can only further enhance the returns that we've specified in the deck today.

[Operator Instructions] The next question comes from Charles Meade with Johnson Rice.

Good morning, Nick, you and your team. You hear me?

Yes, Charles. How are you?

I'm fine. I wanted to pick up on the -- on that upper versus lower. Maybe in a slightly different direction. I think that this is the first time, at least I can recall you guys comparing the productivity, and that's really helpful, what you put on that slide. But I'm curious, my baseline, really the only other one other operator that has talked about the upper versus lower Northeast PA. And their number was more like the upper bean 70% as productive. And my understanding was that, that was primarily a function of less thickness in the upper. But I'm wondering if you can talk about if -- your number, I think, works out to 77% if that number has changed over time or if it changes in the XY plane over your geography? Just give us a little of your kind of history and outlook on that upper versus lower.

Well, maybe just one thing, Charles, this is Josh, that maybe to consider is the productivity decline that you see from the lower to the upper will be dependent upon the spacing at which the lower was developed. And so you do expect to encounter some depletion, and that depletion will vary on a number of things. Obviously, your overall thickness, but also the thickness of the Cherry Valley limestone, which is the barrier between the two but really how that lower was developed, the space unit which was developed at could lead you to a lower productivity. And we do know there are some operators to the east of us as they stepped into the upper they developed the asset, a little bit tighter spacing. We've been a little bit wider throughout our history, developing the lower. And so that's why we have a maybe a little bit advantaged expectation with the upper performance going forward.

Got it. That is helpful, Josh. And then shifting on to the Haynesville, maybe kind of -- this may be more for Nick. Nick, if I think back to our last -- the last quarterly call, you were talking about the possibility of an eighth rig in '23. And if I'm understanding your commentary right, that remains a possibility, but it seems like it's more of a distant possibility or maybe a second half '23 possibility at this point? Do we have the right sense?

I think you do, Charles. I mean, I think I would just call it an option. And one of the things that we wanted to communicate around that is that we wanted to make sure we had midstream capacity, takeaway capacity in the gathering and treating space should we get to a place where we want the eighth rig. Look, over time, as LNG export capacity grows and there's incremental demand out of the Haynesville I'd love to see us today, and I'd love to see us more than that as we get into the second half of the decade. We certainly have the inventory and the great assets to justify acceleration when there is demand that's not being met. But as we sit looking at the market today, we don't really anticipate that an eighth rig would be needed during 2023. Now if it turns out that it is needed, then great, we'll be ready, and we can add a rig and we have the full setup to do it. But right now, we're not expecting to go to eighth in 2023.

The next question comes from Subhasish Chandra with Benchmark.

Nick, I appreciate the Eagle Ford sale proceeds is a bit hypothetical, but I still want to ask you on the debt reduction to keep sort of calibrate the debt ratio there. You have a very healthy working capital surplus if you include that in that debt calculation, and if you can sort of give maybe a rough number of what the debt reduction piece might be, maybe you don't -- you can't really do that because it's too hypothetical. But secondly, I guess on the return of capital, related to the Eagle Ford sale. Have you considered a special dividend that might accompany the sale? Or is that hypothetical as well?

Well, Subhasish, this is Mohit. Thanks for those questions. On the first one, as Nick said before, the intent is to let the process -- the sales process play out and see what kind of proceeds we get from them. And I'll maybe go back to what was said earlier. At a very high level, the intent is to pay down some debt. And at this point, we would not get into the specifics of how much that would be. Overall, I would say, we are very, very happy with the shape that the balance sheet is in. As you can see from the materials, we are saying Net debt-to-EBITDA is 0.4 turns. We are very comfortable with that. The intent behind it is when we're selling a producing property and the loss of EBITDA has to mirror the overall pro forma debt level. So we will pay down some of it, but the specifics of that will come at a different point of time. On your second part of your question about a special dividend, the same logic applies. I think once the bids are in and once we recognize which path we are taking, then we'd be happy to share more details around that.

Yes. Fair enough.

One, just obvious connection, Subhasish, I would make is that as we talk about the fact that we don't see structural supply demand growth for the gas market until at the earliest 2024, that could mean soft gas prices, soft gas prices can lead to weaker equity prices just as a gut reaction. Should that happen, we think our stock would be even more undervalued than it is today. So we certainly don't mind the dynamics that we would receive a bunch of cash from this transaction and be poised to acquire our stock, if you will, if it's falling due to macro, which we would, at that point, believe is short term in nature with growth in demand coming. So we like the setup of thinking about the fact that there's volatility in the near term of natural gas prices, that volatility can obviously lead to volatility in equities, and we show a lot of cash.

Yes. That will be a good place to be. A follow-up is on -- could you just remind us about your bid week versus spot. For fourth quarter, I guess we got October, November, a bit weaken already. So how much of your 4Q is locked in at this point?

Yes. So October and November are pretty well locked in. So when we give our basics expectations, the biggest floating piece there is going to be December. We did lean a little bit heavier on first of month for November than we typically do. We see the forecast for warmer weather in the East Coast through at least the first half of the month. This week, there's the first reports of the potential of cold fronts showing up -- but -- and it's pretty early and supply is plenty robust. So we leaned a little bit harder on first amount to pricing for the month of November.

Excellent.

The next question comes from Nicholas Pope with Seaport Research.

I had a question on kind of the post quarter share repurchases. I think you want to comment the repurchased 400 million shares in October. Just looking at kind of the math, it seems like with the dividend and with kind of the cash flows where they are that you probably use some debt to repurchase those shares. So I was curious if that was kind of a choice because it was a creditor that had some availability, there's a block trade -- or if that -- just kind of the timing of kind of when the dividend is going to be paid out in December versus kind of where everything is? Just kind of curious about that big share repurchase that you commented on.

Yes. So Nick, this is Mohit. You're right, the trade was done after the quarter closed. We've been clear all along that the intent of having a $2 billion share buyback, share and warrant buyback plan is to have availability that in case one of our creditors at emergence if they want to sell down, then we are ready to provide a bid. And as was said earlier in the call, more than 80% of the buybacks we have done are former creditors, and it helps remove the overhang of the perceived overhang from these former creditors. And we've been very pleased with our ability to be able to do about $1.1 billion of buybacks and well ahead of schedule, and we still have about $900 million and until the end of 2023 to prosecute the rest of the program.

Got it. I appreciate that. And then as you look at that credit facility, if you're going to kind of add on to that, it looked like I think you all commented that something 6% -- 6.6% kind of average interest rate in the credit facility in the third quarter. What's the timing of that? Is that -- it's obviously coming out of the bankruptcy is a little higher than kind of where your peers or even where your debt metrics would kind of say you could kind of get that too. So what's the timing and the ability to kind of move around the credit facility kind of go to a more traditional facility in the next -- in the near term?

Yes. So thanks for that question also. The interest rate that you referenced, yes, it obviously goes off of a pricing grid depending on how much utilization that we have of the credit facility. We carefully monitor the conditions and we -- the intent would be to try and refinance the credit facility before it becomes current. So it matures it will become current next year. So we are looking into ways of trying to refinance the credit facility prior to it becoming current. And so depending on what happens in the macro conditions, the Fed is obviously increasing rates, as you know. But given the shape that the company is in our engagement with different lenders, we feel pretty optimistic about being able to do it in a timely manner.

That's really all I had. I think everything else has been asked. I appreciate the time, everyone.

The next question comes from Phillips Johnston with Capital One.

Just one more on the cost inflation front. Nick, you referenced Slide 12, which is really helpful. It looks like you guys are anticipating, Haynesville well costs can move up to a little over $1,600 per foot on a blended basis next year. What are the factors that could sort of move that number either higher or lower? And can you maybe give us a sense of what percentage of that is essentially locked in from a pricing perspective?

Yes. Philip, this is Josh. I think some of the risk that we see to inflation is diesel is one of them that we're seeing shortages really across the country right now. And we'll need to continue to monitor that and see that how it plays out. That affects our much cost on the drilling side, has an implication on our transportation costs for things such as proppant. So that's one that we'll continue to monitor closely. The demand for rigs, pumping services obviously remains quite high with most high-spec rigs that being utilized today. So if that demand were to remain high through the course of the year, obviously, that may enable those providers to continue to push on pricing. We've been very active in the second half of the year and specifically in the third and early parts of the fourth quarter where we've been working with our existing suppliers and it may look like us taking on a little bit higher cost today but providing some pricing certainty and protection from additional inflation in 2023. And so that's something that we think is a good indicator of how we can preserve it. As far as an absolute percentage, I'm not really in a position to go down that path with you today. But the bulk of our primary services being on the frac on the drilling side have been locked in for next year.

Okay. Great. I appreciate the color. I also wanted to ask just about potential timing of ultimately achieving investment grade and just how important that is to the company. I know it's not something that you can control directly and you clearly have the financial metrics already. So based on your conversations with the agencies, is the limiting factor mainly just a function of scale? And also, just what's the overall path that they want to see? And how important is investment-grade rating to management and the Board?

Yes, Philip, this is Mohit. Investment grade is important to us. As you start thinking about the LNG strategy that we have in play, being investment grade would be extremely valuable in that scenario. We are actively engaged with all 3 rating agencies. There's -- as you referenced, the credit metrics are obviously investment-grade quality already. There is an element of seasoning and showing a track record of performance, which we clearly are demonstrating. So the tone of that conversation is great. The engagement is there. And as we referenced, S&P just last month, upgraded us to BB so we are seeing green shoots of that notch upgrade that we are seeing, and we are a couple of notches away from getting to investment grade, but we feel confident that we are on the right trajectory, and it's kind of little bit of a matter of time to see that, but we remain confident that we'll get there eventually. Thank you.

And the last question today will come from Matt Portillo with TPH.

Just a question in the Haynesville. I appreciate the color on Slide 12 around the cost difference between the Haynesville and the Bossier. I assume a little bit of that might be apples and oranges as you've got some shallower targets in the Haynesville further north in the basin. But could you talk a bit about the cost difference between the 2 horizons and then if we head into a lower commodity price environment in '23, '24, is there some potential to cut back on the Bossier development? Or should we consider that necessary from a co-development perspective moving forward?

The Bossier just in general, is a more challenging formation for us. I mean it is shallower, but lithology, the rock type there does make it a little bit more difficult from a drilling and a completion standpoint. And so that's ultimately what ends up driving some of your cost differences. At this point, I don't think we would pivot away from that. We think that's a really important interval for us to continue to develop. Obviously, it represents a relatively modest part of the program, but we think it's important to continue to work down a learning curve within that particular zone, continue to extend the limits of it and what we see it just simply as we think about the long-term optimization of the asset. So we do think there's some opportunities to get better. It's probably one that we benefited the most through the learnings with Bain. They were more active in that interval. And we just think there's a lot of efficiency still to be gained. And so that's hopefully a story we're talking about next year.

Perfect. And then as my second question on gas marketing, just curious the momentum pipeline brings a unique opportunity here with TPS. We've obviously seen some industry participants talk about net 0 or carbon neutral oil marketing going forward and potentially achieving a premium. Just curious on the gas side. I know you've talked a bit about RSG getting a very small premium at the moment. But if you guys are able to tie kind of your gas marketing opportunities with CCS and then obviously working towards the LNG contracts, do you think we could see a more meaningful uplift to your gas pricing as we step forward with all these projects in the queue?

Matt, that's a great question. And there's no question in my mind that we should see that. I think it's going to take a bit of time for it to evolve. What we are seeing in our early discussions with LNG off-takers in Europe and Asia is that they are extremely interested in the carbon footprint of the gas that they're buying. They're asking a lot of questions about it. They're wanting to understand what being responsibly sourced gas means they're wanting to understand the overall footprint. When we flash stats like the fact that we have a 0.02 methane intensity from our gas production. It certainly gets the attention of international gas buyers. We think it will increasingly get the attention of domestic gas buyers as well. I'd remind you that today, there's no tax or structural incentive for buyers of gas to pay more for a lower emissions footprint gas molecule. That may come. We think it should probably come at some point. There is the talk, of course, in the IRA about the methane tax and what that will look like over time and how that will be -- how that will show up in the way that producers develop their assets is something that we're going to be keenly interested in. We think with the footprint that we have we are very well positioned relative to that potential tax. So we think this is an area that will evolve pretty significantly as the world recognizes the huge need for growing natural gas production and the big demand that really does exist out there today and should continue to grow as the world seeks to have more of the affordable, reliable and lower carbon energy that solves some of the biggest challenges facing the economy today. All…

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