Greetings, and welcome to SM Energy Company's 2024 financial and operating results and 2025 operating plan question and answer session. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Jennifer Samuels. Please go ahead.

Thank you, Donna. Good morning, everyone. In today's call, we may reference the earnings release, IR presentation, or prepared remarks, all of which are posted to our website. Thank you for joining us. To answer your questions today, we have our President and CEO, Herb Vogel, COO, Beth McDonald, and CFO, Wade Pursell. Before we get started, I need to remind you that our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to the accompanying slide deck, earnings release, and risk factors section of our most recently filed 10-Ks, which describe risks associated with forward-looking statements that could cause actual results to differ. Also, please see the slide deck appendix and earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures. Also, our 2024 10-K was filed this morning. With that, I will turn it over to Herb for brief opening commentary. Herb?

Thank you, Jennifer. Good morning, everyone, and thank you for joining us. We posted a lot of information yesterday afternoon, so I'll sum up some key takeaways. SM Energy Company's 2025 plan is expected to deliver a sizable 40% increase in free cash flow, which would be even higher if gas exceeds $3.25 or oil prices improve. This is supported by a step-change 30% oil production growth while maintaining a very strong balance sheet that should meet one times leverage by the second half of this year. While the Uinta Basin acquisition realized a cash production margin right on top of Midland production head, about $40 per BOE while increasing gross inventory count by about 40%. I believe we're off to a great start in 2025. With that, I'll pass the call to Donna to start the Q&A. Donna?

Thank you. The floor is now open for questions. If you would like to ask a question, please. We do ask that you please limit yourself to one question and one follow-up before rejoining the queue for any additional questions. Again, that is star one to register a question at this time. Today's first question is coming from Mike Scala of Stephens. Please go ahead.

Hi. Good morning, everybody. I want to see if you could speak to the first quarter guidance, why production was down sequentially, and I want to see specifically was the third-party issue that I guess impacted the you had some delays in railing oil. Was that resolved in the fourth quarter or some of that done in the first quarter as well?

Thanks for the question, Mike. I'll pass that one over to Beth so she can cover the rationale there.

Alright. So when you look at the first quarter production, we dropped a South Texas frac crew in the fourth quarter. And so we have about a three-month gap in our tilts, which impacts the volumes in the first quarter. We restarted that crew in January, and as discussed, our production will grow throughout the year and into the third quarter.

So, really, just a timing issue. Nothing more than that?

Exactly.

And then you talked about the 40% increase in that drilling inventory year over year. I want to see if you can provide any detail behind where that number is and can you break it out by area, even at a high level?

Yeah. Mike, this is Herb. So we're not really breaking down the inventory. What we know is the Uinta acquisition was a big contributor to the inventory growth. And as usual, we're being conservative on our inventory, making sure we stick up everything with detail and put it in our database, and we'll continue to do that over time.

Okay. Very good. If I can follow-up with just one more on that inventory, I don't think last year you included any of the dry gas locations that you have in the Eagle Ford. Wondering if you included any of those this year given the increase in prices and are there any plans to develop any of those assets with the stronger?

Yes. Mike, great question. I think we put that in one of our slides. You'll see that we aren't focused on the dry gas portion of the Eagle Ford at all. And other intervals that have pretty much dry gas. So, yeah, that's not an area of focus, so we don't really count that. And when we're at ten plus years of inventory, we don't really feel the need to go and really push that unless prices go up substantially.

Great. Thanks for the color. Appreciate it.

You bet. Thanks, Mike.

Thank you. The next question is coming from Gabe Doud of Cowen. Please go ahead.

Hey, Sala. Hey. Morning, everyone. I was hoping we can maybe touch on just the full-year guidance range for 2025. Quite a wide range there. Could you maybe speak to what you need to see or confidence level and maybe getting close to that 112,000 barrel a day level?

Gabe, I'll start on that one. So, yeah, it's not really in our view not that wide a range, and you start with the BOEs, and then we put an oil percentage of 51% to 52%. So we just tie the 51% to 52% to that BOE range. So that's why the oil looks wider because of those percentages on the BOE range.

Okay. Okay. And so just on the prior question, Mike's question. But so the trajectory is basically significant growth in 2Q, 3Q, and then down in 4Q. Is that how we should think about it?

Yes. I mean, that's it's all timing related. As it relates to the activity that I laid out on slide ten yesterday. And so the production will grow through the third quarter. And then level out in the fourth quarter. And it's all just timing related.

Okay. Okay. Thanks, Seth. And then my official follow-up is how should we be looking at 2026? Obviously, a lot of moving pieces in 2025. Starting the year with a heavy level of equipment then dropping. So maybe the shortest way to ask is what would maintenance capital be to hold, let's say, the midpoint of 2025 oil production flat into 2026?

Yeah. And, Gabe, I'll talk. Obviously, you know, 2026 is a ways out. And assuming commodity prices hang in there at current levels, you should view it as our plan would be the flat to single-digit growth in production. You can view it that by year-end 2025 where our balance sheet will be in great shape and one or below. And you can expect 2026 to really be about return of capital increasing for our stockholders. So those are really the key aspects of 2026 as we see it today. Obviously, we'll play out 2025 to see where things go on commodity prices.

Okay. Okay. Then and so similar capital spend. Was that fair? Too or no?

Yeah. I mean, it'll depend on where things go with tariffs and commodity prices and activity levels in the industry. But that would be a way to look at it is to it'll be slight growth, at flat capital levels.

Okay. Awesome. Great. Thanks a lot, guys. Very helpful.

Thank you. The next question is coming from Zach Parham of JPMorgan. Please go ahead.

Thanks. Maybe just following up on Michael's question. You mentioned some transport delays during the quarter. I think those are rail delays in the event. Can you just give us a little more color on those delays? Is this a one-off or would you expect, you know, are these things that regularly happen just and you have to plan for in the future? Just trying to get a sense on this as it's a new for y'all.

Yeah. So I think a couple of things. If I start on the fourth quarter, we did have takeaway constraints there, and that was really on the refinery downtime in Salt Lake City as well as with the rail delays. And just a reminder, we have about 15% to 20% of our crude going to Salt Lake City? And the other is going to a rail station in Wellington, Utah. And so both basically just defer the timing of recognizing sales for us and we're building in flexibility within our railcar and our storage capacity to be able to deal with this in the future. So that's the main thing. I mean, as it relates to Q1, and how we're moving forward.

Got it. Thank you. Then my follow-up, in the release, you mentioned some potential non-op spending that would be decided on later in the year. Could you just give us a little more color there? What non-op assets or projects are you considering maybe could you quantify the potential level of spending?

So Zach, we excluded the potential non-op activity from our capital expenditures. So we've had discussions with certain Midland neighbors. So this is all Permian Basin. About non-op drilling that hasn't been confirmed or approved, and it's that part of the year, potentially. So it wasn't really appropriate to code it in the budget. It would represent several net wells and wouldn't contribute production at all until 2026. So it's that late in the year. So we just wanted to give you a heads up that we may participate if we find the economics stack up with ours. And then just for reference in 2024, we did include non-op in our budget, then that was $19 million in 2024.

Is it fair if it's a few net wells, is it fair to say that it would be in the ballpark of the same level of spending you had in 2024 on non-op?

No. With few net wells, it'd be more, and it would be back-end weighted in the year. And so there's always that question of will it actually happen or not. Depending on where commodity prices go, you know. If you saw commodity prices increasing and those operators or the increasing their activity, you could see how that could come about. But there's no guarantee, plus we have to check the economics.

Thanks, Herb. Appreciate the color.

Thank you. The next question is coming from Leo Mariani of Roth Capital. Please go ahead.

Hi, guys. I wanted to ask, really just about the drilling and completion activity this year. So I'm looking at this right. You guys are drilling 105 net wells in 2025. But completing 150 net wells. So definitely seems like a bit of a mismatch on the drilling, you know, versus the completion. So I was hoping you could speak to that a little bit more. Sounds like you guys are maybe blowing down some inventory here and you know, would you foresee a situation where you have to kind of pick up drilling in 2026 to maybe get back to a similar you know, number of completions? Just any color on that would be helpful.

Yeah. Hey. Thanks, Leo. You know, we don't manage to DUC count, right? And, so it's an outcome of a program, and we just took on a big asset from Utah, which was at a pretty furious pace of drilling. So I'll pass that over to Beth to give you more color on it.

Yeah. We ended 2024 with a DUC count of 104. Which just like Herb said, was really due to some of the Utah activity there. And so based on 2025 net drilling completes, we should reduce that number by about 45. And really, again, it's just timing related, and the DUC count is an output of that activity timing.

Okay. So do you see a situation where you have to increase drilling a bit to kind of get back to that kind of 150 rough completions if that's the plan?

Leo, not really. If you just look at the pace we're at and what you want to keep production flat or slightly growing, you don't need an enormous DUC count. It will ultimately, though, depend on the size of the pads. So if we're doing eight well pads versus six well pads versus more. That would influence where the DUC's inventory builds to. So that's all in the details of it. So that's why we really don't manage to DUC count. It's really we're driving for capital efficiency here.

Yeah. And the other part, just to elaborate a little bit is really the capital efficiency that we've seen in South Texas, Midland, and in Utah across the board is really leaning to what our new kind of cadence is on our activity. And so we've seen those step changes, which I talked about in the call. And so on the drilling and completion side and taxes as well as the double barrel frac in our Utah assets.

Okay. That's helpful color. And then just jumping over to that you went to here, I know these were, like, really early numbers, but you guys announced the acquisition in mid-2024. You know, there's discussion of you went to production of around 43,000 BOE per day. It looks like it came in at 36, you know, in the fourth quarter. I know you guys that some of that was, you know, inventory, you know, build, and then also, I think you guys had talked about an LOE in Utah of around $4.70 a barrel. Looks like it came in around $7.15 in the fourth quarter. So hoping you could just give a little bit more color in terms of the variance from a high level on those numbers.

Yeah. Yeah. Leo, just bottom line, you'd you're aware that we took over basically got all the information in Utah in August once we passed the HSR review. Then we closed October first, and then we over operations on January first. So during the fourth quarter, we had limited control on the actual programs themselves, and we obviously had integration things that we were watching and taking care of to meet our standards. So that's kind of a noisy quarter when it comes to Utah. To think about. And we do see what we said back in June is where ultimately things will shake out. Because these are really oily assets and there's a lot of infrastructure that really helps us on the cost-effectiveness on the OpEx side. And then, ultimately, there's also how much work over expense. And I believe there was quite a bit of work over expense on the part of XCL during the back end of the year.

Yeah. Leo, I'd add one thing. The thing to me, always go straight to the bottom line margin and our cash margin, if you notice on that same table, so you're looking at for LOE, you know, it's pretty darn close to the Midland margin per barrel, which is what we anticipated and hoped for, and that's kinda where it is.

K. Thank you.

You bet, Leo.

Thank you. The next question is coming from Oliver Hong of Tudor Pickering Holt. Please go ahead.

Good morning all and thanks for taking my questions. Just wanted to start on the Uinta just with respect to well productivity. I know it's still pretty early on the assets but just any sort of initial takeaways with respect to well productivity you're seeing relative to the acquisition type curves that were underwritten with the deal, anything that we should be aware of from the perspective of downtime or constraint flow and when we might start to see full start to complete SM well design to come online.

Alright. Oliver, I'll take that one. When you look at the well performance of the upper and lower cubes in the Uinta, could really use the Sprayberry Wolfcamp as kind of an analog for well performance. So the upper cube there has kind of a lower rate. It takes a while to clean up, and then it to get to that peak oil rate, but it has much shallower decline. So that's the difference that you're seeing there on the slide that I presented. So, I would say, in general, we're creating value through the lower cube. As we march through our 2025 plan. And we have some tests in the upper cube, as well as one well online in the deep cube. And we'll continue to enhance our understanding there in the other zones while maintaining most of our value creation within the lower cube.

Okay. Perfect. That's helpful color. And maybe just for a follow-up, I was kind of looking at your inventory slide. The ten plus years on an assumed 120 to 130 gross well run rate per year. Just kinda wondering what average lateral length does that assume and just kinda seeing how you all are turning in line 150 net wells this year the gross being a bit higher than that. Really just trying to reconcile if this 120 to 130 run rate is how you all are thinking about a sustaining program run rate beyond 2025. Just kinda given that delta or if it's just more illustrative in nature.

Yeah. That's a great one, Oliver. So we look at out five years on what we see as kind of our sustainable program. That makes sense that meets all those objectives we have around return of capital, what debt level we wanna sit at. So when you look at that, that's how you get to that completion count per year. 2025 is a bit unique because of how we came into the year following, XCL's activity level. So that's why you see it. So I'd say the completion count in 2025 is high compared to what we need to for a sustainable program that meets all the objectives we have. That makes sense?

Yes. And just to clarify, for the lateral length, something similar to what the 2025 program in that eleven to twelve thousand range that's a good number to kind of use for that.

We in Utah, we assume ten thousand foot laterals. You know, we've done our first fifteen thousand footers, but we're not yet putting a full program together with the longer lateral lengths. But in South Texas and Permian, they are over eleven thousand feet.

Perfect. Thanks for the time.

You bet, Oliver.

Thank you. The next question is coming from Michael Faroo of Pickering Energy Partners. Please go ahead.

That's alright. Thanks for having me on this morning. Just wanted to hit on sort of the DUC drawdown. And, you know, what sort of went into that decision. So you know, clearly, there's a drilling cycle times are sort of outpacing your completion cycle time. It looks like 2024, you grew your net DUCs by about eight net DUCs down to, like, a hundred up to a hundred and four. Right? Planning on drawing down 45 of those this year. Barely an efficient use of capital. So I was wondering if you guys could just sort of walk us through, you know, what went into the decision to sort of draw those down this year and maybe give us an idea about, you know, what percentage of the current DUC count is more of a, you know, a regular working DUC count that's not just sort of a DUC backlog.

Yeah. Michael, you know, DUCs are not something we manage to. They're just an outcome, and with the acquisition from XCL where they were running three rigs, obviously, the DUC count went up. High, so you could say the capital efficiency in 2024 was lower than you'd normally have because of those DUCs. That's not really what we manage to at all. And it depends on the size of the pads through the year. If you're doing more, say, three well pads in South Texas, then you'll have a lower DUC count. If you're doing eight well pads in Utah, you'll have a higher DUC count. So that's not really something to manage to, and it's not around just getting capital efficiency. It just was efficient capital-wise across the full program, not year in, year out. That makes sense?

Yeah. That makes sense. Very helpful. I wouldn't emphasize I would not put any emphasis on DUC count.

Alright. That's noted.

I'd like to talk a little bit about capital allocation, a few moving pieces with the company integrating you with the deal, you know, changing activity levels. I'm just looking at your slide. Your slide here with the capital allocation, you know, 35% to 40% split in the Midland. You went to 25% in South Texas. So longer term, does this seem like the right capital allocation split you know, the 150 net turn in line cadence for the go-forward company, would you expect to keep, you know, volumes around that 2025 guidance level of, you know, 107,000 barrels a day?

So, Michael, we run multiple scenarios when we set up the plan each year. And if oil prices are relatively strong or gas price strong, we'll flex between the regions. We like having that flexibility with more gassy in South Texas, more NGLs in South Texas. And then Utah with very oily. So we basically have those scenarios and we line out a multiyear plan that maximizes free cash flow generation over multiple years, not just a single year. And that's really what drives ours. The returns are very similar.

Yeah. Returns are similar between the three programs at current commodity prices.

Alright. That's helpful. I'll turn it back.

Thank you. The next question is coming from Gregory Miller of Truist Securities. Please go ahead. Great. Please make sure your phone's not on mute.

Is this for me, for Neil?

Yes. Go ahead, sir.

Okay. Thanks. This is Neil Dingmann. My first question, guys, is just on another on the UNIFI May, specifically. Just wondered, as you talked a bit about this already this morning on the release. I'm just wondering, has the 2025 plan program or your growth expectation changed at all based on the or you're seeing the current expected status of that Salt Lake refinery May I'm not thinking so, but I just wanted to ask that. And then secondly, are you expecting differentials for Main saying that.

Okay. I'll start on that one, Neil. So yeah. The no. We've got the customers in Salt Lake, the refiners, and they're gonna have turnarounds at times that are planned and then things that were, you know, go bump in the night and they'll shut down. That will obviously affect volumes and we'll put stuff in the storage. That just affects the sales timing. To the degree we can. That's really a key point there. And then, Beth, do you wanna ask?

Yeah. And there's really no changes in our 2025 plan as far as the activity is related to Utah and the crude takeaway from there.

Great. No. Great. Great. I'd bet. And then maybe my second just on reserve. Specifically, notice 2024 net proved reserves went up nicely. I obviously, given that you went to addition, I'm just wondering when you look sort of go forward, can you just talk about maybe about what you're expecting for future conduct. Do you want to sort of hold based on what you're doing there and is your adding things and then secondly, it looked like the Midland reserve decreased a little bit. Was that related performance revisions or what was driving that?

So, Neil, as it relates to the Midland assets, if you recall, we're slowing down activity a bit in the and so that'll impact some of our PUDs falling out of that five-year window. And so that's the primary reason that you're seeing that difference. It doesn't take away from the stellar assets that we have. It's just following the activity level that we have there. And as far as Utah, I would think of it just like we think of all of our assets. We continue to offer and understand those assets over time, and we'll have additions and infills as we would in any other year for all three of our core assets.

That was that slowed on just driven by the you went to buy reallocation? Is that primarily what you're doing?

Exactly. Yes.

Okay. Thank you.

They're still great pies. They're just not within five years now.

Yeah. Right. We call them they become they convert from pods to technical pods. So all it means is you put them back in the plan five years, and they come back.

Right. Great update. Thank you all.

Thank you. The next question is coming from Tim Rezvan of KeyBanc Capital Markets. Please go ahead.

Good morning, folks. Thanks for taking my question. Herb, I'll spare you on any more DUC questions. I'll throw one at Ray here. Okay. Repurchases, obviously, came down a lot in 2024. It makes sense with the, you know, the big you went to. Acquisition. There's been an interesting dynamic in the market where companies that are actively repurchasing, you know, really didn't see much outperformance in 2024. So just kinda curious what it looks you have a clear path to get leverage back at that 0.7, 0.8 times range at the end of the year. How are you thinking about repurchases, and should we look at 2023 as, like, a kind of maybe a steady state, you know, kind of cadence for you all?

A great one for Wade. Yeah. I guess. A great question. And yeah. No. I take all of your comments there, and I agree with them. We are on a very clear path, you know, back to one times, and we're pretty disciplined about that. And just like we did in 2022, get to one times or get close to one times. I say that all the time. It's not a hard and fast dark black line as we feel comfortable. Going through this year with macro and with execution and all those things, you could see a step in before then that these definitely our plan to prioritize free cash flow, to get the balance sheet really, really strong. That's how we roll. And then prioritize return of capital once we're to that level. And your comment about would the cadence be similar? You know, you could model something like that. Every quarter is different and we look at things on a daily basis when we're in them. We're in the market. But for modeling purposes, you could probably assume something similar.

To 2023?

Yep.

Okay. That's helpful. And my follow-up I noticed on the oil realizations in the fourth quarter, were a little better than what we expected. You know, it's hard to have a feel for kind of how Uinta's gonna trend over time. So as you look forward, you know, Herb, you've sort of vaguely commented about initiatives you're looking to undertake. Sort of tighten the Uinta oil diff. Can you give any comments about sort of incremental initiatives you have or anything underway to maybe continue improving Utah oil desk. Thank you.

Tim, yeah, I don't think it'd be prudent for me to say what we do out in the market for improving our diffs, but you can rest assured that we're working that heavily, and we think the opportunity set is wide. And it's not it just hasn't been around that long with rail volumes out in the market, and we see opportunities to do better and better over time. We'll see how those play out, and you'll see it in our realizations over time.

Okay. Fair enough. Thank you.

Thanks, Tim.

Thank you. The next question is coming from Scott Hanold of RBC Capital Markets. Please go ahead.

Thanks. First, Jennifer, congrats on the retirement. It was good working, you know, all these years, and best of luck in future?

Thank you.

You're welcome. My first question is, you know, just on some of the South Texas gas gasier assets, it seems like you guys have more of a I guess, bent to kind of focus on the oil properties right now. I know the commodities are sort of moving in the different direction where I think just broadly speaking, it feels like more folks are more constructive on gas and less so on oil, but it seems like you're taking a different sort of angle. Is it more on commodity view or is it just the fact that your oil properties still, you know, provide a better rate of return opportunity?

Scott, that's a great question. There's a lot of things on gas that you can look at. And if you just look at where strips sat every January first and then where they panned out in the subsequent twelve months. It's a quite a telling picture. And, you know, there was a lot of hype about gas being much higher currently. So we thought it's been prudent to just fit. And not try and go after our gas assets. Know, if we saw, you know, that gas was priced at four dollars when temperatures are over fifty degrees or summer temperatures are below a hundred. Then we could start to think about it. But right now, the volatility in natural gas is high. There's a lot of hope in the future, and why would we do that now in terms of development when there's that prospect of significantly greater power demand for everything you're hearing about AI. And potential for LNG exports. And there's still uncertainty on how those LNG markets grow with the change in administration and what happens. So and we have returns. Yeah. And we have great returns where we are and there's just less volatility in it. So that's kind of the way we look at it. We think, yes, gas will be great, but do we need to rush into it? And our answer is no.

K. Understood. And when we take a look at, you know, the Permian opportunities, and, you know, specifically, if we look at Klondike and the Greater you know, sweetie pack, Woodford Barnet opportunity, how do those returns. I know it's still early, but how do you think those returns will compare to sort of your legacy you know, Permian activity?

So that's a great one, Scott. I'm gonna hand that over to Beth because she knows off the top of her head some of the recent well results that have been strong in those areas. So I'll just pass it over to Beth on now.

And I would say, you know, as it relates to the well performance, we have very strong returns across all of our Permian assets, and that's why they're in our optimized plan. Just to talk specifically about Klondike, you know, when you look at the results that we've had to date, one of our best Klondike bean producers produced over 150 MBOE in the first six months. So we've had really stellar results there in Klondike. We have a great geoscience and engineering team working on our geologic model. And as those well performance and results come in, it's just verifying that model. And so we'll continue our delineation program in Klondike, with six more wells this year and then it's come on and then around the summer time frame. We're really encouraged with what we see there.

And then Woodford Barnet. Though we had a really good Woodford Barnet. Yes.

Yeah. And Sweetie Peck, as far as the Woodford Barnett, we had a well produced about 250 MBOE. In the first eight months. So significantly outperforming our peers and definitely competitive for capital going forward.

Okay. So it sounds like things are going well, but I guess, I'm sensing it maybe too early for you guys to put a stake in the ground and saying it's as good as your legacy stuff. That you've done in the past? Is it just too early?

So on that one, I'd say, you know, on the Klondike side, side of things, we expected some variability, and we're seeing that variability. And it's focusing in, okay, where are the best ones gonna be and where are the other ones gonna. It's gonna be pad dependent. I would say the dean just because of productivity, it's really competitive. And then as long as you select the right locations, for it. And then on the Woodford Barnett, we're real pleased with that one, but it's you know, we're two wells into it. We're drilling some more now. And then in South Texas, we did that western extension, and we're pleased with one well that's really strong that's down there. And so we'll sort that one out also. So I'm seeing them as competitive. Very competitive.

Okay. Thank you.

Thank you. The next question is a follow-up coming from Gabe Doud of Cowen. Please go ahead.

Thanks for getting me back on. Jennifer, I do want to say congrats to you as well. Hope you enjoy retirement. And then my follow-up, guys, is this on Gabe.

Yeah. Sure. Thanks, Jennifer. It's been a pleasure.

Guys, just on the Midland reserves, I recognize the removal of pods related to the five-year window, but then the negative performance revisions, and then the additions related to infills. Could you maybe just discuss a little bit what's going on there? Thanks.

Yeah. I think I'll start that and then pass it to Beth, but I think those were quite minimal, the performance revisions. That were there. And not unique at all. But Beth, do you wanna elaborate a little?

I mean, I agree with that, Herb. And just as you look at our ads and infills over time, and I would say relative to other years, our ads and infills is in line with what we've seen in the past. Just the same as the performance revision. So the real change that you're talking about and you're seeing within our reserves number is associated with the PUDs going out of that five-year window.

And it really cost price too.

Oh, okay. Pricing too.

Okay.

Right. Okay.

Alright. Thanks, everyone.

Thanks, Gabe.

Thank you. At this time, I'd like to turn the floor back over to Mr. Vogel for closing.

Well, thank you all for joining us, and we look forward to seeing a number of you at an upcoming event. I'll also mark today as to thank Jennifer for a really great run at SM Energy Company for the past many years. We've really enjoyed working with her. And I will say Scott Hanold beat me to the punch and then Gabe, but Jennifer's been a key part of our executive team here at SM Energy Company. And we wish her a long, happy, and fruitful retirement.

Thank you very much, and I'll add that it's been ten great years and a privilege to work with such smart and high integrity people. And thank you to many of you on the call who have sent me such nice notes. Thank you.

Thank you, ladies and gentlemen, this concludes today's event. You may disconnect your lines or log off the webcast at this time. And enjoy the rest of your day.