Welcom`e back. So the rest of this afternoon, we're going to be talking with some of what we've characterized as some of our top ideas for 2024, 2023, and thinking ahead to 2024, which is basically, we are bullish on the gas equities. I just want to make that clear. You've heard some panelists talk about softness in gas prices. We're going to get into this in a little while. But in kicking us off this afternoon, I'm delighted to welcome Nick Dell'Osso, President and CEO of Chesapeake Energy Corporation. I've known you now, Nick, for going on 15 years.
That's about right.
Been a long time. So we're delighted to have you here. I was going to kick off and ask you, just to double-check, you don't have a house in Thailand, do you?
I do not have a house in Thailand.
No.
No.
Just wanted to check.
No.
Okay. The previous panelists, we're going to struggle to be nearly as entertaining as them. But in all seriousness.
I would never purport to be as entertaining as Mr. Teague.
Yep, so anyway.
Unfortunately, nor is it profitable.
We're going to get into that.
We're going to get into that.
Don't steal my thunder here Jim .
All right.
So, 105 BCF a day. Just summarize for us, your view of the gas market here in the U.S.
It's 105 BCF a day. Let's start there. The gas market's been pretty interesting this year. Prices have been weak all year. You've continued to see supply just creep, creep, creep, higher, higher. And then we felt like, hey, it's plateauing a bit as we get into shoulder season here. This makes sense. And then we hit November 1st, and it's just jumped another couple of BCF a day. We can't say we're surprised by that. If you look at the last several years, you've seen supply pop up in November and December. And it's pretty logical. There is a real shoulder season to the market. It is predictable. It happens annually. And we this year took pretty specific action. We do curtailments in shoulder season just about every year. Generally, we will curtail more in the fall. Some years we don't need to curtail anything in the spring.
It sort of depends on weather. We almost always curtail some volumes in the fall. This year, curtailment was an active daily discussion. Shoulder season's particularly weak.
Was it or just the Marcellus?
Mostly Marcellus. We did a little bit of deferral of activity in the Haynesville. Basically, we just weren't in a hurry to get anything done in the Haynesville in shoulder season, which worked out pretty well, and so we have brought back some volumes now that we're into November. You've seen demand show up a little bit, so despite the fact that production popped up to 105, pricing in New England right now is decent. It's okay. It's much better than it was in the depth of shoulder season, so we feel good about that, and we're not surprised to see that other producers behave similarly and hold back volumes waiting for the winter. What we're really interested to see is, is this just timing of volumes hitting the market, or is this real growth?
In other words, will you see the same thing we've seen in the last several years, which is volumes peak a bit in November, December, January timeframe, and then they begin to wane back down to a more sustained level as you get into the latter part of winter? Or is this something where we've seen volumes go up and they're going to stay up? We continue to believe that with rig count going from 70 to about 40 in the Haynesville, that it will not be sustained growth, that volumes, particularly in the Haynesville, will roll over. We see it in our own business. We've told the market to expect it. We're pleased that that's happening in our own business. It's by design. And we assume that others will look pretty similar.
Just on that point, I mean, I'd like to spend a little bit of time on the macro because ultimately, it's about how you plan your business. And then we can maybe talk about how the dynamics of this market are, we think, are at least poised to change. But why do you think we haven't seen that rollover in production in the Haynesville yet?
It just takes a long time. The cycle times in the Haynesville are pretty long. When you think about spudding a well until when that well comes online, it's part of a pad. Drilling in the Haynesville is a significantly longer period of time than it is in the Marcellus or, gosh, we just exited the process of finishing our exit from the Eagle Ford. Very short cycle times in a play like that. Haynesville is a much longer cycle time. Deeper, hotter, takes longer to drill, takes longer to complete.
And so when you're doing a whole pad at a time, you should assume it's around nine months from the moment a rig spuds a well until that well is completed and turned in line. And you really didn't see the rig count fall in a material way until May, June of this year. So you're really not at a point yet where you should see that activity rollover. You still have turn-in lines. And we believe that probably people weren't in a rush to turn wells in line in August and September and October.
So that's what you're seeing now?
Yeah. But you really actually, as you pop to 105, that's mostly coming in the Marcellus and a little bit in the Permian. You're not really seeing it in Louisiana.
You had shut-ins in the Marcellus. Have you turned that back?
We've mostly turned that back on, yeah, but that's a daily decision, so right now, it's flowing. But really, when we think about the shut-ins that we have, our volume management, our shut-ins, it's all around what the market needs. It's all around matching supply with demand, so this is not a game of trying to pick a price or something like that. You can see that the pipes are full. You can see that nominations aren't going to be fulfilled or needed, and so you pull back volumes.
Generally, the way that works for us is we pull back volumes going into the weekend, and then during the week, volumes come back, and so we give a number that's easier to model, which is the average curtailment over the quarter, and it was 50-75 million cubic feet a day for us. But that's not 50 to 75 million cubic feet a day for 90 days. That is 250 million cubic feet a day on a weekend and zero during the week quite often. And so this is a daily decision that we make based on what the market is telling us the demand is for our product.
So we could conceivably see those swings a couple hundred million a day, either direction, through this. You look at 105 today. If a handful of producers do that, it could easily be back down again. So we just have to watch it on a.
Could be. Yeah, could be. I mean, if prices really start to weaken, I think you'd see volumes come back off. And it's a decision. We can make that decision. But in a lot of ways, it's often not a real decision. Pipes pressure up and they're full. You can't send more gas. So the market's pretty clear about what it needs from a demand perspective. We don't have to guess.
But yeah, so we've got folks talking about potentially November being a net fill, a net injection period. But yet gas is still holding at $3.20. What's happening to basis differentials?
That's a great question. Oh, basis differentials, they've been fine. I mean, we're holding in okay. They're still relatively wide. Cash in the Northeast today is around $2. NYMEX is, what, 3.20, something like that. So I mean, $1.20 is pretty wide. Pretty wide. But that flat price is what's most important to us. And around $2, that's a decent price. We think that that's holding up because demand, I mean, it's gotten a little bit colder. So you're starting to see some demand show up. The forecast is that it's going to continue to get colder now over the next 10 days. So people are starting to buy ahead, and that'll put some tightness into the market. But the other thing to keep in mind is that storage overall in the U.S., unchanged, we all know that. There's nobody built any new storage of any significant capacity.
But our market has gotten a lot bigger. So if you think about storage as days of demand, you have significantly less coverage of demand and storage. And I think that gives you a different probability weighting as you trade gas around what your floor should be. Because it doesn't take very much for storage to go from full to not full with a slight change in demand given the percentage that demand represents.
Greater volatility as a consequence.
Greater volatility is the issue.
So how do you plan your business around this? And I guess this question is two parts. You've got the short term. We're obviously Q3 barely generating any free cash flow. In this gas price environment, no surprise. But we've got a forward curve that still says there's a substantial change in the dynamics of U.S. gas coming over the next two years. So how do you manage the short term? How do you position yourself for the longer term?
The significant change that's coming in the next couple of years is a little bit hard to wrap your mind around when you really think about it in percentage terms. So our market, while it prints 105 today, it's a round 100 BCF a day market, 102 most of this year or most of the last several months. And so 12 BCF a day of export capacity is under construction right now. There's a lot more that's planned and talked about, and some of it's even permitted. I put all of that aside for the moment and say there's 12 BCF a day that steel is going in the ground, people are spending money on, and it will show up. And we have to grow our gas production by what is effectively more than 10%.
We being industry.
We, being industry, yeah, have to grow by about 10% or a little bit more to meet that. I don't actually know how that happens in a really short timeframe. That's a challenge for this industry. And what I think the real takeaway from that needs to be isn't that we don't have enough gas. I think we have plenty of gas in this country. But I don't think we have plenty of gas that breaks even at $2.50. And so what I think happens is that we have to touch a lot more resource that has higher break-evens as an industry. And what I like about where we sit as a company is that we have a pretty long-life inventory of gas that sits at the lowest end of the cost curve of remaining undeveloped locations in the U.S.
And there's only so much of that we can bring to market in any given year. We're completely constrained by pipelines in Northeast Pennsylvania. We have some pipeline capacity in the Haynesville. We intend to utilize that pipeline capacity as effectively as we can. But we can't go double our rig count. That's just not physically possible. You can't have a ramp that goes that fast given the infrastructure that's there. And so I think the market will have to price in resource away from the cores of these plays that has higher break-evens that allows the market to ultimately fill all of this demand. And we sit with a long live inventory at the low end of the cost curve and should see our profitability expand when that happens. Now, really where that gas will come from, a bunch of it will come from the Haynesville.
We'll participate in that. A bunch of it will come from the Permian. I think we can all model exactly what will come from the Permian. I don't think we have to wonder what associated gas is from the Permian. And all you have to do is go figure out the number or the capacity of new pipes that are being built out of the Permian. Whatever that capacity is, is the amount of associated gas that will be available. If you build a cubic foot of capacity, that will be filled. So you could model that, and you're not going to get to 12 BCF a day growth out of the Haynesville and associated gas from the Permian.
So what does that mean? It means you're going to need gas from South Texas. It means you're going to need gas from East Texas. It probably means you're going to need gas from Oklahoma. Because while there is a tremendous amount of gas behind pipe in the Marcellus and in the Rockies and in other places in the U.S., it does not have incremental infrastructure to get to market. So it will not be a part of this solution in the near term.
I was going to say you can double your rig count unless you buy somebody, but we'll get to that later.
But that's not from a macro perspective. That doesn't solve anything.
Sure. No, I understand. So I want to play on this theme a little while longer because it really is critical to whether gas equities make sense in this environment. I would put it to you that we have Mexico exports. We had a gas panel the other day talking about the pull potentially from Mexico. We have six of that 12 BCF of LNG capacity that is going to be sitting in Texas. And I don't see six of associated gas coming out of Texas. So there are a lot of moving parts that say this is a six-month kind of final slug of who the hell knows what gas is going to do. But post second half of 2024, we're potentially into a whole new dynamic. Would you agree with that, or do you think that's overly optimistic?
I generally agree with that. The thing that I would be just a little bit more balanced on is that I think that while that is true, that the supply-demand fundamentals fundamentally change, a lot of fundamental there, as we see that the first two projects, Plaquemines and Golden Pass, come online, which we don't have a different view than anybody else. We just call it generically kind of end of 2024.
Oh, okay. You're late.
I know. And that's fine. I don't mind being late. I don't mind being a little bit late. We don't want to model that aggressively, but we'll call it late 2024. How about that? So when that comes online, that's a step change in the demand. And again, I think we as an industry will have fits and starts of being able to meet that demand as it shows up in bulk. And so I do think that's a step change in the fundamentals. But I also think that there will be volatility. There will be plenty of volatility that comes with this. So you're going to have those first two facilities. You'll have another one in 2025. So you're going to get a pretty good tailwind that'll last for a while. Eventually, we will supply that capacity.
And also, you will see periods of time where that capacity isn't fully utilized. And that will show up because you'll have either competing supply show up from projects in the Middle East or Africa, or you'll have demand disruptions somewhere around the world. You'll have all sorts of different. We had Freeport go offline for an extended period of time last year into the beginning of part of this year. You will have events like that that will disrupt that dynamic. And the big difference for our domestic natural gas industry is that we're going to go from zero BCF a day or something that rounded to zero BCF a day of exports in 2016 to more than 25 BCF a day of exports by 2026, 2027. And that's 25% of our market.
Yeah, the numbers are extraordinary.
So when you have an upset to that, that's a lot of gas that will not have a home. We have the exact same amount of storage that we had when we were a 60 BCF a day market.
Well, you said that. We obviously, we all watch what our traders are saying. Josh Sherman was up here with Warren Russell the other day. Guys on our team that basically were talking about the dynamics of the gas market. And what I find intriguing is even you guys, you don't talk about the fact that we have three, I think we're a little over 3.7 right now, TCF of gas. But 0.5 TCF of gas didn't get exported because of Freeport. Where would our gas market be if that fire hadn't happened is a question we're constantly asking.
Because ultimately, we probably would have had the tightest gas market in 20 years had that not happened. So the way we kind of look at it is as we think about 2024 and beyond, we have three major dynamics happening. I'd love to get your perspective on two of them. We talked about LNG. What about coal gas switching and power burn? Because that seems to be an area of controversy, as was 2023 a one-off. And then the second one is the industrial demand, the pool coming from Mexico.
So a couple of things. I want to go back and talk about your Freeport point for just a second. So if you rewind a year ago, that 2 BCF a day came offline. But we were 100 or 101 BCF a day market at that time, probably closer to 100 at that time. We were sustained closer to 102 most of this year. We've now popped to 105. So we would have a tight market coming into storage season this year, coming into November. But we also would be solving that with incremental supply. And I just think it's important to point out that our market is pretty good at finding balance.
But even with that said, we're still okay. So we're high, but we're not at the $4.2 folks thought we would be at at the beginning of the year.
That's right, and the answer to that is power burn, and so I just had a conversation with your commodities research.
Francisco.
Yeah, Francisco, just before walking up here and we were talking about this. Gas demand for power, I think, is a very interesting story and if I'm going to point to one aspect of 10-year models in the U.S. that I would bet differently than the consensus, it would be that domestic gas demand for power will be higher than a lot of those models would predict and there's a fair amount of gut feel in that statement but if you think about the drivers of electricity demand growth being certainly EVs, but also IT-related demand, data centers, and AI-driven.
Crypto.
Crypto. I mean, crypto, maybe we've already seen that growth. I don't know if that continues to be a draw or a growth factor, but I think AI and the amount of data that's being processed with AI is going to continue to grow pretty rapidly and all of the related technologies and machine learning and everything that come with that, and our generation capacity is going to be supported by renewables. But I think utilities are starting to get much more interested in, will we have enough gas to meet demand? And they will also tell you a little bit quietly, will we have enough generation capacity to meet demand? Because growth in renewables is only so effective at meeting baseload, and the demand growth for power is, I think, going to be greater going forward than it has been in recent years. It's going to be a challenge.
So let's bring it back to Chesapeake. I want to bring John into the discussion here in a minute, also when we get into discussions on inventory and so on, so the punchline for us is, how do you manage your business? How do you plan your business? Both short-term and long-term, you have the inventory depth, but you're not really a growth company, so how do you think about activity levels, mid-cycle pricing, and the level of activity you want to have to navigate this more volatile market?
So we are not a growth company in our base case today. But if we think about how the market should unfold with this coming growth and demand of 12 BCF a day, we could be a growth company. We could choose to grow in the Haynesville. Now, I said a few minutes ago, it's impossible for us to double our rig count in the Haynesville. That's true.
I see why some think.
That would be only marginal growth in volumes because efficiencies.
I'm being sold.
Efficiencies through consolidation could drive some volume growth in the aggregate, and we believe that's a real thing, but for the most part, you can grow, but you can grow incrementally unless you want to overrun infrastructure, unless you want to destroy capital. We've seen that. We've lived that for a lot of years. Our company in particular lived that for a lot of years, and so we know what that looks like, and we're trying to be significantly more disciplined about paying attention to what the supply-demand fundamentals are telling us, and the lesson learned that we are really trying to be disciplined about implementing here is that while we can see demand growth coming, we should not put ourselves in a place where we're just blindly growing supply waiting for that to show up. We want to be in step with the market.
So that's where we coined the phrase be LNG ready rather than grow today, hope LNG will show up. We want to be positioned with all of the infrastructure needed, with the resource needed so that when the market has a step change need for supply, we can respond if we have the assets and the cost structure to be effective in meeting that demand. We think we will. But we think it could be modest growth after you get through this increase in demand. And that's probably into 2025, maybe into 2026.
What does that mean for, I mean, you've signaled to the market pretty well. I mean, you've laid it out, what the profile of your production is. But what does it mean for your capital program? Because at the end of the day, I'm guessing that the trick in this kind of market is to be the low-cost producer. But not just low cost and operating cost, but low cost and all-in capital break-even. Where do you think your break-even sits? And what do you think your capital profile looks like?
Yeah. So we think about break-evens a couple of different ways. We think about break-evens on an annual basis. What are you spending this year? What are you earning this year? Super volatile around what commodity prices are and how hedged you are and all of that, but then we also think about break-even of, I'm going to go drill a well, the life of that well, the value of that well, what does it take to break-even on that investment?
In the short term, break-evens on that annual cash flow basis are running up a little bit higher, and the drivers of that are our volumes are dipping as we go into 2024 because we've allowed volumes to fall. And our capital should start to come back next year to redirect that volume back up, so you get sort of pinched on both sides of that equation. On the true investment break-even of a well, I think we're on balance for the portfolio. Marcellus is well below three, and Haynesville is probably close to three.
But in the Haynesville, you're still drilling wells significantly cheaper than some of your peers. So when you say that's your break-even level, is it a production optimization decision that goes along with that? I mean, you could drill big wells, big fracs, tons of frac fluid, and have big wells out of the Haynesville, but you're choosing not to do that. Why not?
What do you mean we're choosing not to do that? I mean, we're.
If you can all see what the completion designs look like, the fluid loadings and so on.
This is an optimization question.
That's what I'm really getting.
Yeah. So we have tried a lot of different recipes around what the completion should look like, what your drawdown should look like. In other words, how high you let your IP start and how quickly you allow that production to flow freely. And we continue to experiment around this. And given the market that we're in today, we like how we're approaching it. If you were to reprice our market to a, I'll just pick a big number, $5, it probably doesn't need to be that high. You could probably justify a bigger completion, a higher IP, but you will see degradation out the curve of an individual well when you do.
So it's acceleration rather than increase of recovery.
Correct.
I've got one last big picture question. I want to throw it to John because I know he's big on takeaway and things of that nature that he wants to touch on. But the big picture question for me is, I think you said you're almost done with the Eagle Ford. I think it's due to close here imminently, if not already, which means you're left as a 100% dry gas company. We had Tourmaline on the stage earlier today. Last 20% of their production is liquids. And it obviously drops their break-even pretty dramatically. Are you happy with the portfolio to be 100% dry gas in those two basins? Or how do you think about the five-year look as to how you potentially reposition it?
We didn't become a Haynesville and Marcellus-only company because we said dry gas is the only product we want to have. We became that because we felt like it was the right answer for the mix of assets in our portfolio. We've owned a very productive, great Eagle Ford asset for a long time, and it's at a point of maturity where we felt like we either needed to go buy something else or exit it because we felt like it was at a point of ongoing development pace that didn't fit our model as well. We like to be able to bring a larger program with a lot more scale and drive costs down as low as can be and have a robust development program. Eagle Ford, for us, was getting to a point of maturity where, again, we needed to either add to it or exit.
We looked at some of the stuff to add to it over the last year, didn't like the relative values at where it was trading. And so we decided the best thing for us was to exit that position. But it had nothing to do with saying we'd rather not own oil or rather not own NGLs. So we'll continue to think about all of those things from just a value perspective. And obviously, diversification of product has some real value to it. But if you're going to go and buy something, you need to still fit our non-negotiables.
You need to fit with a model that says if you're going to buy something, you should have some operational synergies. You need to not overpay. So all of those things show up in the equation. And so for us to go wave a wand into a situation where we own a bunch of NGLs or oil again is a not insignificant hurdle. That would be economically, that would be a big hurdle for us. I would never say never to that because for the right deal at the right time and the right price, sure. If you know of any core acreage in the Midland Basin that we can buy for well below recent trading levels.
Give me a call.
Yeah, give us a call.
You've inadvertently sleepwalked into an M&A discussion.
No, I didn't. It's never inadvertent with you, Doug.
Obviously, I'm not going to address directly the speculation a few weeks ago. But at a high level, you've taken the portfolio to a level where you're practically zero net debt. You've got your break-evens down. Your cost structure is great. You're positioned for, let's say, the forward curve. And good assets in the hands of great management is typically a good way to create value. So when you think about big picture consolidation, what are the barriers? Clearly, you want to get bigger. Vine, Chief, you've done it already. What's next?
You say you want to get bigger. We want to get better. We're going to continue to make a distinction of those two things. I think Vine and Chief made us better in both of those instances. We were able to acquire really good offsetting acreage that had real operational synergies. We were able to achieve those operational synergies. Those deals, integration's hard. We had our bumps along the way with both of those deals. Not everything goes exactly as planned. We had all kinds of challenges in both of them. Ultimately, we think both of them were pretty good successes. If there's opportunities to make our company better, then we'll continue to pursue that. It's really hard to do. In both of those instances, you had sellers that were ready to be consolidated into something bigger.
They saw real value for their future equity. And they wanted to hold equity into those sales for an extended period of time. In fact, both of the principals are still significant owners of Chesapeake by design, by their preference. And that's worked out pretty well for both of them. And I think we've created some real value for our shareholders and for their ownership through that consolidation. You need to be focused on, with consolidation, can you improve how you allocate capital in a year? So you've made the to the side comment a couple of times about you could double your rig count by buying someone. Well, sure. But the question is, can you improve your efficiency of those rigs? And if you can improve the efficiency of those rigs through consolidation, now you have a win.
That is a big humor.
Yeah, well, yeah.
I think we all.
Got a rumor.
Yeah, exactly. We know what the situation was a few weeks ago. I'm just curious. When those kind of things hit the press, how do you react?
You just don't. I mean, look, I think the fact that there's been so much willingness to have rumors in the marketplace around deals that have happened and haven't happened is terrible. I mean, things are hard enough in this industry to have people speculating about things that are impossible to have real insights into. So you just don't react. It's not the first time we've had rumors about our company. And it won't be the last. And we've been pretty open to say we are interested in consolidation. So I'm not really surprised that people are trying to project what that may look like. And you just don't react.
So from our side of the fence, it's fascinating to see the you either get, "Oh my God, surely not," or, "Yeah, that would be a fantastic kind of response from the buy side." And I think in that particular case, it was, yeah, the response was, as you would expect, pretty positive. Okay. So we'll move on from that. The takeaway issue, the basis differentials are big topics. John, why don't you take that because I know it's a topic you focus a lot on?
Yeah, there's lift. So with the takeaway issues, I guess there's two parts of this. I mean, we could talk about LNG, and we just can talk about what you can do in basin and maybe to improve differentials. So when you look at the Northeast, when you look at your Haynesville position, not touching LNG at the moment, what can you do from a marketing perspective just to improve the differentials in those areas?
Sure. Well, and I'm going to talk about the Haynesville first because it's just frankly more interesting. The Haynesville, there's plenty of infrastructure that can and is being built in the Haynesville. So we've participated in a project called NG3 that's going to take gas from the heart of the Haynesville to a point called Gillis. That project should be a really constructive project for us. We have an equity interest in the pipe, which should be worth a lot of money once it's built. And we will deliver. We have a commitment of 700 million cubic feet a day on that pipe to deliver from the Haynesville to Gillis. It's important to note, and we've gotten a couple of questions today. I think it's a really important distinction. We're not planning to grow our volume 700 million a day for that pipe. This volume exists today.
And so what we're attempting to do is optimize the delivery of that gas to markets where it's needed most. We anticipate that Gillis will be a market where it is sorely needed because that will be a jumping-off point to the LNG facilities. There's a lot of pipe being built to Gillis that's going to go in a lot of different directions, including to the LNG facilities, but also just to the east to some industrial areas along the coast. That's going to be an important. It's not a true hub, but it's going to function kind of like a hub. We think it's going to be great to have some gas show up there.
Beyond that, in the Haynesville, we continue to talk to industrial buyers, utilities that are very interested in long-term supply and having constructive discussions with them about which basis should we tie these contracts to. And we're seeing some real opportunities to construct contracts that are better for us long-term that provide access to more premium market pricing long-term. So we really like that dynamic right now as domestic industrial and utility customers are starting to think more about how to make sure they have adequate supply in the future. In the Northeast, there's just not a lot of infrastructure that is being built or can be built. There are some expansion opportunities, and we see some of those. The REA pipe from Williams, REA project from Williams, is a good project. We have a small participation in that.
It's going to change some dynamics, and there may be some other things that could be expanded in order to help fill gas into that project. We'll pay close attention to that. MVP, I'm really happy to see it get finished. Really want that to get finished soon. That's tangential to us because it serves more of the Southwest PA and West Virginia market. But nonetheless, we just think infrastructure in Pennsylvania that's successful is a great thing. We'd like to see a lot more of it.
And then just one more question for me. This could be on LNG. So with your LNG contracts, you don't go on. I mean, it's FOB, right?
Correct.
You're not going to market these contracts. You're not actually going to market the gas. When you look at something that's going on with the Panama Canal, right, with the low water levels there and rerouting of ships, and you've highlighted you do not want to deal with the issues with marketing. Does a situation like that just sort of change the way a domestic E&P that's looking to get into the LNG market think about entering the contracts?
I don't know that it changes our calculus at all. What I think it highlights is exactly the reasons. And just to nitpick the words a little bit, you said we don't want to get into that kind of marketing. I think realistically, we see it as very hard for us. If I could wave a wand and have a giant marketing business with its own balance sheet and could take on a risk structure that would allow us to own a lot of ships and buy a lot of gas every day and liquefy that gas and then spot market it, I think that would be a great business to be in. But I think you have to be very large to be successful in that business.
And so what we've done alternatively to that is have these two agreements, one with Vitol and one with Gunvor, whereby we are selling gas FOB, and we're getting an international price that has a net back of JKM minus we've guided to $5-$7 will be our price. And Gunvor and Vitol, on the other hand, maintain a trading portfolio of LNG that's very significant. So they can take the gas from us FOB, and they can go sell it anywhere they want. And we know that we are gaining exposure to an international index that we find attractive at a basis to that index that we find attractive. And so we think that is a really good risk-adjusted way to gain access to international pricing. And they get the ability to then go out and proactively market that volume wherever they see the best answer.
And so they can match their book of business, their book of customers, along with the supply they procure from us. We get exposure to the volatility associated with that, but we don't have to take on the capital at risk to go out and optimize that on a daily basis. So we really like the risk-adjusted exposure we have there. And I think we can continue to do things that way. If five or 10 years from now, we're a $100 billion company, I'll give you a very different answer.
We've only got a couple of minutes left, Nick. So there's two quick things I wanted to hit. One's just a quick one on inventory depth into Marcellus. You've talked about these dog-legged completions, and you told Taylor about where your break-evens were. Is the inventory depth at break-even, are you comfortable? Are we still talking 15 years plus? Does that include that innovation?
Yeah. I think we'll continue to have a lot of innovation around driving our break-evens lower in our inventory. Not every one of the sticks in our inventory breaks even at $2.50, that's for sure. And so there's a degradation or a range of break-evens within our own inventory. As we grade that relative to the inventory of the entire Lower 48, we feel like we sit at the really far good side of that. But yeah, there is a range of outcomes for us as well. And we'll always try to be innovative about lowering each one of those locations' break-evens that we can.
Doubling down on the debate we had earlier about the corporate break-even, you're not generating a ton of free cash flow right now. But if we're both right on the forward curve, at least notionally where it's headed, Chesapeake could have some very substantial free cash flow with negligible debt. You know where I'm going with this.
I do.
When you think about, I think you know how we see your valuation, when you get back to free cash flow, material free cash flow generation, how would you prioritize cash returns?
Well, we like our cash return model. And we'll continue to discuss this and maybe debate this with you. We like our cash return model. We like all the above approach we have. And we like the fact that investors can understand the formula very clearly. And we like the fact that our cash return model can function countercyclically. So when you have a big run-up in prices, you will see our dividends expand through our variable return program.
When you have prices pull back, you'll see our dividends contract. And we think that makes sense. We think investors can model that. We think that is aligned with the outcomes of our business. We know that if we are building excess cash alongside of that at every point, which we will be with the variable dividend structure that we have, then when there are opportune times to buy our stock, we can buy plenty of it.
You'll keep it flexible.
Absolutely.
Great stuff. Nick, I know you moved your diary to be down here with us today. Thanks very much indeed for coming. Thanks for the support and look forward to seeing what happens in 2024.
Absolutely. Thank you.