All right. We're really excited here, Umang and myself, to welcome Ezra from EOG, to this conversation about balancing growth versus free cash flow generation. Ezra, thank you so much for being here today. Yeah, thank you. It's been a good conference. I had some great meetings. I appreciate being back in person. Yeah. It's nice. It's nice. It's nice to see everyone, and a lot to celebrate over the last year in the energy sector and hopefully more to come. As we think about EOG, what do you think is underappreciated in the conversation, in the stock and in the value of the business right now? Yeah, that's a good question. That hits right at the meat of the matter. I mean, I think what you have with EOG is, we have a very different, a lot of the rest of the E&P space here. It starts with our multi-basin portfolio. You know, we see a lot of advantages, a lot of leverage to being able to build and work across a multi-basin asset base. That base has been created dominantly organically as well. It's taking information and technology that we have from one basin, applying it to the next, and then as we develop new technologies in the new basin, we extrapolate those back to the previous basin. Much of that inventory has been discovered and found and based, and the investment decisions are all based on our premium pricing deck. That deck is a $40 WTI oil price and a $2.50 natural gas price for the life of the asset. So as we add new plays, new exploration areas, new basins, you think about that, is that we're only adding things that are additive to the preexisting inventory. For us, it's not inventory unless it makes at least a 30%, and dominantly right now, a 60% direct wellhead after-tax rate of return based on that price deck, $40, $2.50 natural gas for the life of the well. I think that's the first thing that's underappreciated. The second thing that's underappreciated is the fact that we support that by being a low-cost operator. We really do that on two ways. We focus on it by utilizing technology to increase operational efficiencies, so sustainable well cost reductions. That's just less time on location, is essentially what it comes down to. Drilling, keeping the bit on bottom, not having to make trips. The second thing we do is we strategically look for opportunities to bring different pieces of the value chain in-house. Historically, we've done that with sand, chemicals, water. Recent years, we've been doing drilling mud, more recently, things like drilling motors. The third piece of differentiation for us is our financial policies, our cash return strategy. We're still focused dominantly on the regular dividend. You know, we look to increase, in a sustainable manner, the regular dividend because we really think looking forward, that's the hallmark of a great company, not just in the E&P space, but across the broad market. That should be telling the investment community what we think the increase in an ongoing capital efficiency of the company is, and we're proud that we were able to raise that 10% this year again. On top of that, we've made a commitment to return a minimum of 60% of our free cash flow every year. This year, we're on track to exceed that. We were able to return just over $5 billion to the shareholders, inclusive of the regular dividend. All of that is also supported by what I think is industry's strongest balance sheet. We have a strong cash position, very low debt, and that provides us a lot of counter-cyclic opportunities to make investments that otherwise we may have to think twice about. We're a safety and environmental leader. We're utilizing technology to drive down our emissions intensity. We're using technology to use things like carbon capture and a storage pilot project that we'll be starting up this year. We've instituted some new technology called closed-loop gas capture to eliminate flaring. We also just announced and are rolling out iSense, which is some continuous methane monitoring across all of our assets. The thing that really is our competitive advantage, that really makes us special is our culture. You know, this is ongoing for 30 years now to create a decentralized, entrepreneurial, really business-minded, interdisciplinary group of employees that work and live close into the field where we have our assets. Those are the things I think are really underappreciated, and those are the things that really create a very interesting and unique value proposition for the investors. Thanks, Ezra. Let's start on the macro. I know EOG over the last couple of years has really started to build out some organizational capability around forecasting commodity prices scenarios. Talk about how you're looking at the oil balances in 2023. Yeah. There's a lot going on, at the same time you can boil it down to kind of a few things. You know, we entered this year looking at the operational capabilities of the U.S. to kind of build a model on U.S. growth. We looked at the supply chain constraints that were out there. We looked at the rig utilization, frac utilization, things of that nature. We forecasted that, you know, growth would be significantly muted from where it's historically been, and that's what we see coming up. We're kind of looking at that same type of direction going forward into 2022. On the global scale, on the real macro, though, the things that are moving forward that we're looking at, and this is a lot of the stuff that we talked about on the last call. Not a whole lot has changed quite yet. obviously, the Russian sanctions, you know, how are those really gonna play out? we've got crude sanctions in place now. in the first part of February, we should have some product sanctions that we think will have a bit of a bigger role. obviously, another one on the supply side, we've got lower U.S. growth. ultimately, the SPR has been a very big driver. When you look at what the SPR has done, you know, we're basically at the same level of inventory where we were, roughly a year ago. the SPR has arbitrarily added about 650,000 bbl per day on an annualized average. All that really came in the last six months of the year, so basically 1 million bbl a day, and that is finished. You know, there was a small release here. There are a couple more small releases, but dominantly the majority of that is gonna be done. On the supply side, we definitely see some tightening. On the demand side, it's a little more difficult to see. We'll see what happens with the recession that, you know, one year ago, I think all, you know, many people thought were gonna be here by now. Yeah. We'll see how the recession plays out on demand. What we've seen over the last, I would say, you know, four, six quarters, is that dominantly energy demand use has been pretty inelastic with recession fears. The second one, the big one is China demand and China recovery. With zero-COVID being taken off the table now, I can't tell you when China recovery is gonna come back. I assume it's gonna kinda ebb and flow, but I think it's safe for all of us to assume that China demand is gonna come back. What you see is going out throughout this year, well, with front months are showing some lower pricing due to what we think is the inventory levels heavily influenced by that SPR. You're gonna get to a spot this year where we're forecasting pretty tight supply and demand balances. Talk to us about the gas macro, Ezra. How are you thinking about the setup near term, especially after the weather has really spoiled the gas party- Yeah. ... recently? How do you balance that versus your organic growth plans for 2023? Yeah, we're very well positioned on the natural gas side with Dorado. I'll get back to that in a minute. On the macro gas side, yeah, gas is always difficult, right? Because you have to work up your oil macro first, so you understand what's happening with associated gas. Ultimately, you need to come down to what does the weather look like? Which is a difficult thing. As we sit here today, obviously price has pulled back pretty dramatically in the last month, and a lot of it has to do with two drivers. You know, the first obviously is it's been a warm start to winter. That's the first thing. The second thing is, not unlike the SPR, but you've arbitrarily had 2 Bcf a day kinda taken offline for the last six months, with the outages down along the Gulf Coast with Freeport. That should come back online, you're gonna have right off the bat 2 Bcf a day that comes back online and helps demand. The other thing that I think we all need to keep in mind, and we're watching this, we're modeling this, is really what presented itself this past year, and especially in the summer, has been gas-to-coal switching and what the relationship is there. Not only has the U.S. retired ultimately a lot of coal-fired generation, power generation, but you've got increasing power generation demanding natural gas in light of that also. This is power generation that, you know, renewables can't keep up with. While you've got that going on domestically abroad, you've got increased use of coal-fired power generation, and that's really disrupted or altered, is maybe a better word for it, the actual trade routes and trade flows for coal. Now we've got a higher coal price. It's come off a little bit from the summer, but still and we're exporting a lot of coal, plus you've got the ultimate. We sit today with gas basically at about the five-year average, gas price somewhere at the, you know, $3.70-$3.75 range. You know, I'd say we're constructive on 2023. I would say we're bullish on 2025 and beyond. That's because of the increased demand coming along the Gulf Coast for the increased LNG that everybody's been well aware of. For us, how it affects our capital allocation, you know, Dorado is a natural gas play. We discovered it's Austin Chalk, Upper Eagle Ford, and Lower Eagle Ford there in South Texas. We've been drilling it for a few years now. We're about 50 wells in that play, and we have what we think is identified over 1,000 locations. We think it's got the potential to be 20 Tcf ultimately recoverable. If you think about that 20 Tcf number, one way to do the simple math on that is, that would be a Bcf a day produced for 50 years. It is a world-class resource. The finding cost competes with some of the lowest cost gas in the U.S., and obviously, with it located in South Texas, the transportation fees are gonna be very, very low. It couldn't be better positioned to take advantage of the major demand center in the U.S., which is along the Gulf Coast, not just LNG, but also petrochemical. For us, it's a play that eventually we'll be able to flex on really quickly. Right now it's so early. We're honestly still making progress on completions designs. We're still building out some of the infrastructure, sand, water lines, things of that nature. For the next couple of years, it'll be really investing in that play with two kind of bookends on it. The first is, when would you end up overcapitalizing that? Well, for us, that's simple. It's the same as any other portfolio in our any other asset in our portfolio. You overcapitalize the minute your returns start to decrease or your finding cost starts to go up. That's a simple way to look at it. All you need to do at that point is just pull back a little bit, allow that team I talked about, the culture of our company, allow them to understand what they're doing, allow them to catch up, give them the tools that they need to either increase that well productivity or drive down the well costs. That's on the over-investment side. On the under-investment side, that's a risk too, because think about what I just talked about, the culture of our company, is it's continuous learning. It's continuous improvement. You need to fund each of these assets to a degree so that they're continuing to build out infrastructure, learn about the rock, learn about different landing zones, how to complete the wells, and ultimately continue to not only technically learn, but also move further down the cost curve due to capturing the economies of scale, which is always an important thing in these, in these unconventional plays. Given where gas prices are right now, and I agree with you that Dorado is very much low on the cost curve, but the long-term outlook for gas prices are much more robust. What do you think about pulling back activity, and what gas price would you say, like, "You know what? These assets are much more valuable if I bring them online in 2025 versus in 2023. Yeah. The premium strategy of the company, it's an amazing thing to think about. It makes us somewhat agnostic to the actual gas price because we're making our investment decisions based on the $2.50 natural gas price that we run internally. Those Dorado wells, we have line of sight that they'll be generating double premium returns, which I know everybody thinks double premium is really funny. That's just how we talk about it internally. It's a 60% direct after-tax rate of return on, in Dorado's case, that $2.50 natural gas price. You know, the ultimate thing when we think about capitalizing these projects, Umang, gets back to the fact that what is the right amount of capitalization for it? You know, first, obviously, you need to look at the macro, like you said, we're assuming, you know, longer-term outstanding growth, the market needs the molecules. It really does come down to the fact that we wanna make sure every single year that asset is continuing to improve. Just one penny per MCF is improvement on that finding cost. The minute you start to go the other way, while you could still be generating upfront really high cash returns- Mm-hmm. you know, those higher costs are gonna stay with you. They're gonna go into the cost base of the company. They're gonna end up raising your breakevens. We all know that times are good in cyclical businesses, but they don't always last. Things go the other way. At EOG, we're focused on shareholder value creation through the cycles. We've done a lot on focusing on this premium pricing deck, basically taking pricing control into our own. You know, a lot of people say that our industry are price takers. What we did is we basically turned that on its head and we said, "No, we're gonna go ahead and make our own price. We're gonna be a price maker, and we're gonna make our investment decisions based on this price because we think this price is not sustainable through the cycle. Right. What that means is we've done as much as we possibly can to decouple ourselves from the inevitable commodity price cycles, even though, you know, we're an oil and gas company. That's what we do. In the next 20 minutes, Ezra, let's spend some time talking about the assets and then spend some time talking about capital returns and capital allocation. To start on the assets, one of the things we've done with some of the producers is ask the CEOs to talk about the walk from 2022 to 2023. Recognize many of you are gonna provide official and fine-tuned guidance in the next couple of weeks, but what breadcrumbs can you leave us with as we think about 2023 off the 2022 base? Yeah. I think part of it goes back to our story being a little bit different, the fact that we do have multiple assets across multiple basins. When you think about that, part of the way to think about our structure is where are each of those assets in their life cycle? We start with the Utica. You know, the Utica is very early on, so we're still doing a lot of delineation there. We'll be doing some spacing tests, things of that nature. We talked about on the last earnings call, we'll be drilling, you know, roughly 20 wells there is what we anticipate doing for next year. Sure. In Dorado, in the Southern Powder River Basin, making fantastic progress there. We don't have all the infrastructure, not necessarily gas takeaway and things like that, but again, sand, water, things of that nature. We understand spacing. We understand landing zones, but we're tweaking those in combination with the completions designs. Both of those, you can anticipate should be seeing a little bit more activity from what we saw this year. Mm-hmm. Again, those are at that critical point where you wanna make sure that you're not moving too fast. They're, you know, what we internally refer to as emerging plays, you know, not an exploration opportunity, but they're emerging. They're headed towards one of our core assets. Obviously, right now, the Permian is core. You know, the Permian is in the sweet spot. We've got our infrastructure. We've got, you know, over 5,000 vertical feet of productive opportunities across six different, you know, play types. We probably have something like 20 different landing zones in there, depending on where we're at geologically. We've got a large asset team out there that lives and works in Midland. They tear apart the data every day. They're planning each of the wells, not through manufacturing mode, but actually looking at the geology, looking at each drilling unit individually, and figuring out what the best spacing and targeting is to kind of find that balance between returns and ultimately NPV. You know, the thing about the Permian right now, though, when you transition from 2022 to 2023, is things out there are very tight. Yeah. They're expensive and they're tight. Again, you know, we like the level that we're working at. We've talked about carrying a pretty consistent activity level across the year. Part of that, again, goes back to, well, you know, pricing's up right now, and so even though well costs are up with the inflationary pressures, you still got expanding margins. Why don't you lean in a little bit harder? Well, that is taking the last six years' worth of premium drilling and discipline and throwing it out the window. We wanna remain disciplined and move at a pace where even though we've offset a lot of the inflationary pressures out there, we haven't been able to offset it all. Mm-hmm. We have been able, luckily, to increase the productivity gains, in some of our wells, which helps to offset the well costs and continue to lower that finding cost, and that's what we really wanna stay focused on. Pretty flat activity level is probably a safe forecast there. Lastly would be some of our longer tooth, you know, the assets that are a little bit longer in the tooth, like the Eagle Ford. You know, the Eagle Ford, is not really a growth asset anymore. We've slowed down there. We put to sales, you know, roughly 125 wells per year. The amazing thing about the Eagle Ford is, and this is a great example of what happens, when these assets kinda go through this life cycle that I'm talking about. It's not unlike the, you know, Boston Consulting Group chart where you end up being a cash cow. In the Eagle Ford, even though we're drilling less productive rock than we were six, seven, eight, nine, 10 years ago, in the last two years, we've actually turned in the highest scorecard, the highest rate of return results than we've ever had in nearly 15 years of drilling in that asset. Mm-hmm. Even though the wells are less productive, the well costs have come down significantly. We've learned more about the asset. We've been able to put in infrastructure, things like water reuse, localized sand. Things of that nature do a lot to save not only on operating costs, but upfront costs. The last year, if we think about the cost side of the equation, last year, if we think about the opportunity set, you talked about super zippers, you talked about moving to longer laterals. There were some secular drivers which could improve the cost structure down. When you think about 2023, what are the things which you're evaluating in a toolkit which can help costs come down as well? Yeah. This year, you know, last year we did make a big shift into zipper fracs. Zipper fracs. Which saved, yes, Super Zippers or whatever we need to simulfracs, whatever they're called. Yeah, we made a big shift there, and that helped offset quite a bit. The other thing we did, though, is we were able to just actually spend less time on location. Drill times went down across the board. This year, you know, every year we have incremental gains like that. This year we're gonna lean in on some of the things, and they'll be probably to a little bit smaller of a degree, but they'll still help offset much of the inflationary pressure that's out there. Things like drilling motor, our drilling motor program, in which originally we took drilling motor kind of QA/ QC in-house. We've taken that a big step further. The big thing about drilling motors is making sure, especially in these longer laterals, when you start drilling fast, when you start drilling a 2 mi lateral in, say, seven days, if the motor dies when you're in the middle of the lateral and you have to trip out, you know, that's potentially a 12, 18, 24 hour trip time. On a seven-day well, that's a lot of added costs. It's not just the cost of the motor, it's actually that time on location. Motor program's gonna pay off to be a big one here for us in the future. Then we've got some other things like drilling mud. We continue to optimize not only the mud properties that we have, the chemical properties, where we need to use, let's say, the Cadillac of mud and where we can get away with a little bit cheaper of a mud system. Most importantly is balancing out the right mud weight. You know, too much mud weight, not only will you break down potentially formation and lose that mud, and mud is made out of oil, so that gets expensive, especially, you know, when you're trying to make oil. The other piece of it is the higher your mud weight, obviously the slower that you're out there drilling. Those are some of the tweaks we'll have. Right now we're forecasting potentially another 10% increase on the inflationary pressure on the well cost side, kinda going 2022 to 2023. Great. Let's talk about some of the assets. You unveiled the Utica recently, and we talked a little bit about it in Texas a couple weeks ago. At first I think the investor reaction was, "Is this a gas play?" I think you've clarified it's actually a liquids play. Given Utica was a little choppy before, what gives you confidence that this time is different? Yeah. We've, you know, we've been looking at the liquids fairway here in the Utica Well for a number of years, kind of passively, and monitoring some of the activity, not only going on in the, in the deep part of the, you know, the hot part of the gas window, but also as you come up into the condensate and get close to the liquids fairway. What we've noticed there is, you know, there's a lot of upside to be applied on the completions. It's a lot of what we've learned from mechanical stratigraphy of working recently on plays like the Woodford, the continued progress we make in the Eagle Ford, and some of the work that we're doing on the Leonard Shale or the Avalon Shale. Once you understand kind of the subtleties in these shales and how the geomechanics work, that introduces landing zones to you, and you can combine your completions technology. We're talking about, you know, things like cluster spacing and stage spacing and diverter and the way you're pumping your sand and water, these things that have been talked about in the past. When you apply those, you can really start to get some upside. We have some proprietary software in-house that we've developed, it's reservoir modeling, that when you put in the geomechanical parameters, the rock type, you know, the porosity and permeability, how it's gonna break, and combine that with some of the completions technologies, you can really start to get, you know, a forecast of what you think the well will do. It's, it's basically a predictive analytics tool. That's what we started using in a lot of our exploration plays, but that's where it really panned out in the, in the Utica. Now, the nice thing about the Utica is there was enough activity up there that we've been watching people drill, we've been watching people land their horizontals, we've been looking at how they're completing the wells, and we've been able to confirm and prove up this forecasting tool that we have. That is ultimately what gives us a lot of confidence on where that play is going. It's not like the deep hot Utica. You know, it's a very benign environment. It is overpressured, but we feel that we'll be able to drill 3 mi laterals as a standard. Many operators are already doing that. Completions designs are right in our bailiwick, like I described, with the shale structure that it sets up. You have two slightly different geologic environments. To the north, you know, it's a little bit thicker. To the south, it's a little bit thinner, but you get more robust frac barriers. In the south, we also, you know, over the entirety of the trend, we have about 400,000 acres under lease. It's about 200,000 acres in both the north and the south. In the south end, we actually have purchased 120,000 acres worth of mineral rights, which also gives a massive uplift, not only to wellhead rate of returns, but really to through the cycle, full cycle returns. Like, going back to your base assets, including the Delaware Basin, EOG historically has had premium levels of productivity. You have seen competitors catch up to you as natural, right? Because it's the life cycle. How are you seeing the productivity as you compare to your peers into 2023? Yeah, a lot of it kind of depends on where you're drilling. You know, the fascinating thing to keep in mind about the Delaware Basin is, you know, the differences from west to east. The west side, actually, we call that even a combo play, similar to what we were just talking about in the Utica. We've got a Wolfcamp oil and a Wolfcamp combo play in there. It comes back down to the ultimate reserves, how much of it is oil versus oil NGLs and natural gas. When you're looking at productivity, we need to keep in mind a couple of different things. Where are you actually drilling in the basin geographically, and then what are the specific landing zones that you're looking at? For us, we still feel very confident on what we're seeing with our well productivity, our capital efficiency in the basin. I think a lot of that, since that is the main driver for us, you can see that evidenced last year on our quarterly performance as far as production and CapEx spend, is that everything fell right in line. With regards to the peers, you know, there are a lot of peers out there, and it kind of depends on where you're at. A lot of the wells that are being drilled now are dominantly, you know, being operated by independents with acreage and not necessarily the same areas as our Red Hills acreage or anything like that. The peers that are closer by to us, you just need to look at the different landing zones, the different spacing, the co-development that's gone on, because each of us has a bit of a different kind of technique on how we exploit the resource. For us, as I said, our team is focused on every, each and every drilling unit, trying to co-develop, and we've been doing this for years, co-develop those targets that are gonna be in geomechanical communication with one another. We do it in such a way between spacing, whether vertically or horizontally, such that we can optimize returns and NPV of those drilling units. We don't want to leave anything on the table by spacing the wells too wide. At the same time, we don't want to start to erode the returns by spacing those wells way too close. Yeah. Let's go back to Dorado. It's very interesting play. How are the productivity and cost trending to internal expectations for 2022? When you think about Dorado and how it fits into your LNG strategy, which is obviously increasing over time, can you maybe expound a little bit on that? How do you think of your LNG strategy evolving as well with- Yeah. That's a great question. Dorado in general, and the reason I say it's gonna command more capital in this coming year, is because the performance on the learning curve has been moving faster, at a faster pace than what we've typically seen in a lot of our, let's call them again, emerging assets or emerging plays. Our asset team down there has done a great job reaching out across the other basins and basically borrowing every good idea that they've seen out there and implementing it as quickly as possible, which is, you know, kudos to them for being interdisciplinary and looking out there and keeping an eye on what else is going on in the company. Well costs have come down. We've done a tremendous effort on there, even though... I should say operational efficiency is coming down. Drill times are coming down significantly. It has been difficult with a limited program down there to be able to offset some of the inflationary pressures. On the well productivity side, they're fantastic wells. It's amazing the productivity of these. Dominantly, we started out drilling on the Austin Chalk, knowing that we had potential in both the Upper and Lower Eagle Ford. Honestly, I thought it was probably gonna be a couple of years before we got into co-development down there. Credit to our team, again, the asset team and the frontline employees, there are some areas where they've already moved fully into co-development. They're already drilling Austin Chalk, Upper Eagle Ford, and Lower Eagle Ford, like I said, probably, you know, at least a year before I really thought that we would be there. If we go back again to what we talked about briefly before, we think it's some of the lowest cost gas, especially to the Gulf Coast, with transportation and GMP, really across North America. It's not just how does it play into our LNG strategy, but really how does it play into the U.S.' North America's LNG strategy, because it is a significant resource located in a great spot for it. If you guys recall, you know, we're some of the first movers here in getting some LNG agreements done. We currently have exposure to $140 million a day on an LNG contract where it's a gas sales agreement. We sell right there, FOB, kind of at the dock. We don't have any risk. We don't have any exposure to buyers overseas or anything like that. We are seeing some upside to the pricing, and that's actually, with what we saw over the summer, obviously, it's actually showing up in our realized pricing, which is fantastic. It's great to see. We started negotiating that contract, you know, probably about four years ago, honestly, right when we were, you know, kind of early on exploring in Dorado. Since that time, about two years ago, we actually negotiated an extension, an expansion of that contract, and that's the one that we announced earlier this year. It's similar. It's a gas sales agreement, it takes our total exposure on the LNG side up to 720 million a day, that's commensurate when stage three starts up with Cheniere in, at Corpus. We'll have a couple of different pricing contracts on that. We'll have 300,000 MMBtu/d that's getting exposed to international pricing then I'm sorry, 420,000 MMBtu/d that gets exposed to international pricing, then 300,000 MMBtu/d that's getting exposed to the domestic pricing and getting shipped offshore. For us, when we look at it, you know, LNG is another way to diversify our exposure on our marketing agreements. Whether it's at the corporate level, we're at an asset level. Mm-hmm. One of our strategies is to be able to sell all of our gas and oil into multiple markets. When you think about us, at the asset level, we do all of our in-basin gathering. We usually deliver it to a sales point. That sales point will be an area where we've got two, three, four, you know, multiple markets that come in. The reason for that is we do think that arbitrages are created, and we don't wanna have to try and chase arbitrages. We wanna be able to be exposed to the arbitrages when they present themselves because we think the market's pretty efficient, and they won't last for very long. It also allows us to bypass any bottlenecks or downstream interruptions. Part of our strategy is really to have control and diversification. Not only diversification regionally or geographically, diversification of product type, but also diversification to the marketing exposure is what we're selling into. We consider LNG to be the same type of strategy. Thanks. Ezra, when you roll this up, you've walked through a lot of different assets. How should we think about your 2023 production profile for on an oil basis and a gas basis, or I should say on a BOED basis as well? Yeah. What we talked about on the third quarter call, and things haven't really changed from then. On the oil side, you know, activity levels probably be pretty consistent. Assuming things don't dramatically change, which they haven't, you know, in our minds since early November, you can probably expect similar rates of activity and similar rates of oil growth to what we saw in 2022. Kind of that low single-digit type of range. On the BOE side, obviously, we've talked today about a little more allocation to the Southern Powder River Basin, a little more allocation to Dorado. We didn't talk about today, but we've set a platform in Trinidad, we will have increased international drilling, and that's a dry gas play. A little bit of increased natural gas down there. The BOEs that flow out of that will probably, you know, be in that double digit range. We've gone, this whole session, we haven't talked about return of capital, and we only have two minutes left. You are in a net cash position, talk to us about the way you're thinking about returning capital to shareholders, from these levels. The first thing let me say is being in a net cash position is a strategic advantage, and it's a great place to be in a cyclical business with what we can see has been, you know, can be very volatile very quickly. It's what allowed us to make strategic acquisitions, like in the Utica when we bought the minerals there. It's what allows us to be opportunistic and pre-purchase pipe that we're now installing down in Dorado, things of that nature. It's a fantastic place to be. And quite frankly, I think we're kind of unique because we do have a cash return framework out there. It's a minimum of 60% of our free cash flow will get returned. Again, that includes, that incorporates, the focus hopefully is still on that regular dividend, because that's an important piece, like I described at the beginning of this. Not only have we returned in excess of 60% of free cash flow this past year, we've been able to reinvest in the business, which is still, when you're reinvesting at high returns, the best way to create shareholder value. We've been able to strengthen the balance sheet over the last year. Those are three things that I think, we're in a very unique position to do it, and it's really because a lot of the things we talked about today are focused on being a low cost operator, are focused on being in multiple basins to allow technology and data drive our improvements. The fact that we invest on a conservative, fiscally conservative, fiscally disciplined price deck, and I think that's really again what separates us from many of our peer companies. Yeah. Very good. Well, great. Ezra, thank you. Thank you for being here. Thank you so much. Ezra, I wish you a wonderful 2023, we'll talk to you in a couple weeks on the call. Great. Thank you, guys. Really appreciate everybody. Really appreciate everyone attending.