Participants

Jennifer Samuels; Investor Relations; SM Energy Co

Herbert Vogel; President, Chief Executive Officer, Director; SM Energy Co

Beth McDonald; Executive Vice President and Chief Operating Officer; SM Energy Co

A. Wade Pursell; Chief Financial Officer, Executive Vice President; SM Energy Co

Michael Scialla; Analyst; Stephens Inc

Gabriel Daoud; Analyst; TD Cowen

Zach Parham; Analyst; JP Morgan

Leo Mariani; Analyst; Roth MKM

Oliver Huang; Analyst; Tudor Pickering Holt & Co

Michael Furrow; Analyst; Pickering Energy Partners

Neal Dingmann; Analyst; Truist Securities

Tim Rezvan; Analyst; KeyBanc Capital Markets

Scott Hanold; Analyst; RBC Capital Markets

Presentation

Operator

Greetings, and welcome to SM Energy's 2024 financial and operating results in 2025 operating plan question and answer session. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Jennifer Samuels. Please go ahead.

Jennifer Samuels

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-K, 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?

Herbert Vogel

Thank you, Jennifer. Good morning, everyone, and thank you for joining us. We posted a lot of information yesterday afternoon, saw sum up some key takeaways. SM'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 30% oil production growth while maintaining a very strong balance sheet that should meet 1 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 at 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?

Question and Answer Session

Operator

(Operator Instructions) Mike Scialla, Stephens.

Michael Scialla

Hi. Good morning, everybody. Wanted to see if you could speak to the first quarter guidance, why production was down, I wanted 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 still in the first quarter as well?

Herbert Vogel

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

Beth McDonald

All right. 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 TILs, which impacts the volumes in the first quarter. We restarted that crew in January, and I've discussed our production will grow throughout the year and into the third quarter.

Michael Scialla

So really just a timing issue, nothing more than that.

Beth McDonald

Exactly.

Michael Scialla

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

Herbert Vogel

Yeah, Mike, this is Herb. So the -- we're not really breaking down the inventory. What we know is obviously that the Utah 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 put in our database, and we'll continue to do that over time.

Michael Scialla

Okay. Very good. If I could 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 are there any plans to develop any of those assets with the stronger gas?

Herbert Vogel

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 yes, that's not an area of focus. So we don't really count that. And when we're at 10-plus years of inventory, we don't really feel the need to go and really push that as prices go up substantially, yes.

Michael Scialla

Great. Thanks for the color. Appreciate it.

Operator

Gabe Daoud, Cowen.

Gabriel Daoud

Hey, good 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 your confidence level and maybe getting close to that 112,000 barrels a day level?

Herbert Vogel

Gabe, I'll start on that one. So yes, it's not really -- in our view, it's not that wide a range. And you start with the BOE oil percentage of 51% to 52%. And so we just tied the 51% to 52% to that BOE range. So that's why the oil looks wider because of that -- those percentages on the BOE range.

Gabriel Daoud

Okay. And so just on the prior question, last 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?

Beth McDonald

Yes. I mean that's -- it's all timing related as it relates to the activity that I laid out on slide 10 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.

Gabriel Daoud

Okay. And then my official follow-up is, how should we be looking at 2026, Obviously, a lot of moving pieces in '25 with a heavy level of equipment and dropping, so maybe the shortest way to ask is what would maintenance be to hold -- let's say, the midpoint of 2025 oil production flat into 2026.

Herbert Vogel

Yeah. Gabe, I'll talk obviously 2026 is a ways out. And assuming commodity prices hang in their current levels, you should view it as -- our plan would be to flat to single digit in production, you can view it that by year-end '25, 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 sort of 2026 as we see it today. Obviously, we'll play out 2025 to see where things go on commodity prices.

Gabriel Daoud

Okay. And so similar capital spend, was that fair too or no?

Herbert Vogel

Yeah. I mean, it will 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 to -- will be slight growth at flat capital levels.

Gabriel Daoud

Great. Thanks a lot, guys. Very helpful.

Operator

Zach Parham, JPMorgan.

Zach Parham

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

Beth McDonald

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.

Zach Parham

Got it. And then my follow-up. In the release, you mentioned some -- the potential for some 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.

Herbert Vogel

So Zach, included the potential non-op activity from our capital expenditures. So we've had discussions with certain business neighbors. So this is all Permian Basin about non-op drilling that hasn't been confirmed or approved, and it's back part of the year potentially. So it wasn't really appropriate to quote 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.

Zach Parham

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 '24 on non-op?

Herbert Vogel

No, with few net wells, it would 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. If you saw commodity prices, increasing and those operators are increasing their activity. You could see how that could come about, but there's no guarantee plus we have to check the economics.

Zach Parham

Thank you, sir. Appreciate the color.

Operator

Leo Mariani, Roth Capital.

Leo Mariani

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, completing 150 net wells. So definitely, it seems like a bit of a mismatch on the drilling versus the completion.
So hoping you could speak to that a little bit more. It sounds like you guys are maybe blowing down some DUC inventory here and would you foresee a situation where you have to kind of pick up drilling in '26 to maybe get back to a similar number of completions? Just any color on that would be helpful.

Herbert Vogel

Yes. Thanks, Leo. We don't manage to DUCs, 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.

Beth McDonald

Yes. 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.

Leo Mariani

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

Herbert Vogel

Leo, not really. If you just look at the pace we're at and what -- if 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 8-well pads versus 6 well pads versus more, that would influence where the DUC inventory builds to. So that's all in the details of it. So that's why we really don't manage the DUC count, it's really -- we're driving for capital.

Beth McDonald

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

Leo Mariani

That's helpful color. And then just jumping over to the Uinta here. I know these were like really early numbers, but you guys announced the acquisition in mid-2024. There was a discussion of Uinta production of around 43,000 BOE per day. It looks like it came in at 36% in the fourth quarter. I know you guys said that some of that was inventory builds.
And then also, I think you guys had talked about an LOE in Utah of around $470 a barrel. It looks like it came in around $715 in the fourth quarter. So I was hoping you could just give a little bit more color in terms of the variance from a high level on those numbers.

Herbert Vogel

Leo, just bottom line, you're aware that we -- so we basically got all the information in Utah in August once we pass the HSR review. Then we closed October 1, and then we took over operations on January 1. 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 workover expense, and I believe there was quite a bit of workover expense on the part of XEL during the back end of the year.

A. Wade Pursell

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

Leo Mariani

Okay. Thank you.

Operator

Oliver Huang; Tudor, Pickering, Holt.

Oliver Huang

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 constrained flow and when we might start to see a full start to complete SM well designed to come online?

Beth McDonald

Oliver, I'll take that one. When you look at the well performance of the upper and lower cubes in the Uinta, you could really use the Spraberry Wolfcamp as kind of analog for well performance. So the upper cube there has kind of a lower rate. It takes a while to clean up and then to get to that peak oil rate, but it has a 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 so we'll continue to enhance our understanding there in the other zones, while maintaining most of our value creation within the lower cube.

Oliver Huang

And maybe just for a follow-up, kind of looking at your inventory slide, the 10-plus years assumed 120 to 130 gross well run rate per year. Just kind of wondering what average lateral length does that assume and just kind of saying 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 million to $130 million run rate is how you all are thinking about a sustaining program run rate beyond 2025, just kind of given that delta or if it's just more illustrative in nature.

Herbert Vogel

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 want to 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 so -- I'd say the completion count in 2025 is high compared to what we need for a sustainable program that meets all the objectives we have. That make sense?

Oliver Huang

Yes. And just to clarify, for the lateral length, something similar to what the 2025 program, that 11,000 to 12,000 range, that's a good number to kind of use for that.

Herbert Vogel

In Utah, we assume 10,000-foot laterals. We've done our first 15,000 footers, but we're not yet putting a full program together with longer lateral lengths, but in South Texas and the Permian, they are over 11,000 feet.

Oliver Huang

Perfect. Thanks for the time.

Operator

Michael Furrow, Pickering Energy Partners.

Michael Furrow

That's all right. Thanks for having me on this morning Just wanted to hit on sort of the DUC drawdown and what sort of went into that decision. So clearly, there is -- your drilling cycle times are sort of outpacing your completion cycle times. It looks like '24, you grew your net DUCs by about 8 net DUCs down to like up to 104, right. Planning on drawing down 45 of those this year, really an efficient use of capital.
So I was wondering if you guys could just sort of walk us through what went into the decision to sort of draw those down this year? And maybe give us an idea about what percentage of the current DUC count is more of a regular working DUC count that's not just sort of a DUC backlog.

Herbert Vogel

Yeah. Michael, 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 normally have because of those DUCs. But 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, 3-well pads in South Texas, then you'll have a lower DUC count.
If you're doing 8-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 just what's efficient capitalized across the full program, not year in, year out.
If that makes sense?

Michael Furrow

Yeah, that makes sense. Very helpful.

Herbert Vogel

I wouldn't emphasize, I would not put any emphasis on DUC count.

Michael Furrow

All right. That's noted. I'd like to talk a little bit about capital allocation. A few moving pieces with the company, integrating you went the deal, changing activity levels. I'm just looking at your slide -- your slide here was the capital allocation, 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 and the 150 net turn-in-line cadence for the go-forward company? And would you expect to keep volumes around that 25% guidance level of 107,000 barrels a day?

Herbert Vogel

So Michael, we run multiple scenarios when we set up 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 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.

A. Wade Pursell

The returns are very similar.

Herbert Vogel

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

Michael Furrow

All right. That's helpful.

Operator

Gregory Miller, Truist Securities.

Neal Dingmann

Okay. Thanks. This is Neal Dingmann. My first question, guys, is just on another one on Uinta, if I may, specifically. Just wondered, has -- you talked a bit about this already this morning on the release. I'm just wondering has the '25 plan program or your growth expectation changed at all based on the -- where you're seeing the current and expected status of that sell like refinery I'm not thinking so, but I just wanted to ask that. And then secondly, are you expecting differentials to remain about the same there?

Herbert Vogel

Okay. I'll start on that one, Neal. So yes, the -- we've got the customers in Salt Lake, the refiners, and they're going to have turnarounds at times that are planned and then things that were go bump in the night and they'll shut down, and that will obviously affect volumes, and we'll put stuff into storage. That just affects the sales timing to the degree we can. That's really the key point there. And then, Beth, do you want to add?

Beth McDonald

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

Neal Dingmann

Great, beth. And then maybe my second just on reserves, specifically noticing '24 net proved reserves went up nicely, obviously, given that Uinta 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, do Uinta you want to sort of hold based on what you're doing there? And as you're 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?

Beth McDonald

So Neal, as it relates to the Midland assets, if you recall, we're slowing down activity a bit in the Permian. And so that will 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 optimize 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.

Neal Dingmann

Was that slowdown just driven by the Uinta by reallocation? Is that primarily...

Beth McDonald

Exactly. Yes.

A. Wade Pursell

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

Herbert Vogel

We found the they convert from PUDs to technical PUDs. So all it means is you put them back in the plan five years and they come back.

Neal Dingmann

Great, great update. Thank you all

Operator

Tim Rezvan, KeyBanc Capital Markets.

Tim Rezvan

Good morning, folks. Thanks for taking my question. Herb I'll spare you on any more DUC questions, and I'll throw on away here. Look, repurchases obviously came down a lot in 2024. It makes sense with the big Uinta acquisition. It's been an interesting dynamic in the market where companies that are actively repurchasing really didn't see much outperformance in 2024.
So just kind of curious what -- it looks -- you have a pretty clear path to get leverage back at that 0.7 times, 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 kind of cadence for you all.

Herbert Vogel

A great one for Wade.

A. Wade Pursell

Yeah. That's a great question. And yes, no, I take all of your all of your comments there, and I agree with them. We are on a very clear path back to 1 times, and we're pretty disciplined about that. And just like we did in '22 get to 1 times or get close to 1 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. But it's definitely our plan to prioritize free cash flow to get the balance sheet really, really strong. That's how we roll.
And and then prioritize return of capital once we're to that level. And your comment about would the cadence be similar, you could model something like that every quarter. It's different, and we look at things on a daily basis when we're in the market. But for modeling purposes, you could probably assume something similar.

Tim Rezvan

To 2023?

A. Wade Pursell

Yes.

Tim Rezvan

Okay. That's helpful. And then my follow-up, I would -- just on the oil realizations in the fourth quarter were a little better than what we expected. It's hard to have a feel for kind of how Uinta is going to trend over time. As you look forward, Herb, you've sort of vaguely commented about initiatives you're looking to undertake to sort of tighten the Uinta oil diffs. Can you give any comments about sort of incremental initiatives you have or anything underway that maybe continue improving Utah oil rigs.

Herbert Vogel

Tim, I don't think it would be prudent for me to say what we do out in the market for improving our fits, but you can rest assured that we're working that heavily, and we think the opportunity set is wide. And we're -- it's not -- it just hasn't been around that long with rail volumes out in the market, and if 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.

Tim Rezvan

Okay. Fair enough. Thank you.

Operator

Scott Hanold, RBC Capital Markets.

Scott Hanold

Thanks. First, Jennifer, congrats on the retirement. It was a good work in all these years and best of luck in your future.

Jennifer Samuels

Thank you, Scott

Scott Hanold

My first question is going to be just on some of the South Texas gas tier assets, it seems like you guys have more of a, I guess, to kind of focus on the oil properties right now.
I know the commodities are sort of moving in a 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 the commodity view? Or is it just the fact that your oil properties still provide a better rate of return opportunity.

Herbert Vogel

Yeah. 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 strip sat every January 1, and then where they panned out, in the subsequent 12 months. It's quite a telling picture. And there was a lot of hype about gas being much higher currently. So we thought it's been prudent to just sit and not try and go after our gas assets.
If we saw the gas was priced at $4 when temperatures are over 50 degrees or summer temperatures are below 100, 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 change in administration and what happens. So we have -- yes, 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.

Scott Hanold

Okay. Understood. And when we take a look at the Permian opportunities and specifically, if we look at Klondike and the greater Sweetie Peck Woodford-Barnett 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 Permian activity?

Herbert Vogel

So that's a great one, Scott. I'm going to 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.

Beth McDonald

Yeah. And I would say, 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, but just to talk specifically about Klondike, when you look at the results that we've had to date, one of our best Klondike 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 6 more wells this year and has come on and then around the summer timeframe. So we're really encouraged with what we see there.

Herbert Vogel

And then Woodford-Barnett, we had a really good Woodford-Barnett.

Beth McDonald

Yes. 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.

Scott Hanold

Okay. So it sounds like things are going well, but I guess I'm sensing it may be 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?

Herbert Vogel

So on that one, I'd say on the Klondike side of things, we expect some variability and we're seeing that variability. And it's focusing in, okay, where are the best ones going to be? And where are the other ones going to be? It's going to be pad dependent. But I would say the deemed just because of the 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 -- we're 2 wells into it. We're drilling some more now. And then in South Texas, we did that Western extension, and we're pleased with the 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.

Scott Hanold

Okay. Thank you.

Operator

Gabe Daoud, Cowen.

Gabriel Daoud

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

Jennifer Samuels

Thank you, Gabe

Gabriel Daoud

Thanks, Jennifer. It's been a pleasure. Guys, just on the Midland reserves. I recognize the removal of PUDs 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?

Herbert Vogel

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 want to elaborate a little?

Beth McDonald

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 there -- 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.

Herbert Vogel

And really a gas price too.

Gabriel Daoud

All right. Thanks, everyone.

Beth McDonald

Pricing, too.

Operator

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

Herbert Vogel

Okay. Well, thank you all for joining us, and we look forward to seeing a number of you at an upcoming event. And I'll also mark today is to thank Jennifer for a really great run at SM 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 has been a key part of our executive team here at SM, and we wish her a long, happy and fruitful retirement.

Jennifer Samuels

Well, thank you very much, and I'll add that it's been 10 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.

Operator

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