SM Energy Company Price & Performance (SM)

Thanks, 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 Purcell. 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 twenty twenty four ten 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's twenty twenty five 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 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 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 and A. Donna?

Thank you. The floor is now open for questions. Questions. Today's first question is coming from Mike Scialla of Stephens. Please go ahead.

Hi, good morning, everybody. I want to see if you could speak to the first quarter guidance, so 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 of that still 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.

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 tills, 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.

Yes.

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

Yes, 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 and put it in our database and we'll continue to do that over time.

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 and are there any plans to develop any of those assets with the 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 yes, 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 Daoud of Cowen. Please go ahead.

Hey, Sona. 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, yes, it's not really in our view, it's not that wide a range and you start with the BOEs and then we put an 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.

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 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.

Okay. Okay. Thanks, Beth. And then my official follow-up is how should we be looking at 2026? Obviously, a lot of moving pieces in 'twenty five, 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?

Yes, 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 to flat to single digit growth in production. You can view it that by year end 2025 or 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 and see where things go on commodity prices.

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

Yes. 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 will 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 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 asset for you all. Yes. 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. 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? And 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 the back part of the year potentially. So it wasn't really appropriate to include 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 $19,000,000 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 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.

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 versus the completion. So I was 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 2026 to maybe get back to a similar number of completions? Just any color on that would be helpful.

Yes. Thanks, Leo. We don't manage the ducks, right? And so it's an outcome of a program and we just took on a 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.

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 ZUC 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 roughly completions if that's the plan?

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 duct 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 the DUC count. It's really we're driving for capital efficiency here. Yes.

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 lending to what our new kind of cadences 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 in Texas as well as the double barrel frac in our Utah assets.

Okay. That's helpful color. And then just jumping over to the Euwinta here. I noticed we're like really early numbers, but you guys announced the acquisition in mid-twenty twenty four. There was discussion of Uinta production of around 43,000 BOE per day. It looks like it came in at 36,000 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 $4.70 a barrel. Looks like it came in around $7.15 in the fourth quarter. So I hoping you could just give a little bit more color in terms of the variance from a high level on those numbers.

Yes. Leo, just bottom line, you're aware that we took over we basically got all the information in Utah in August once we passed 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 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.

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 that you're looking at for LOE, it's 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.

Okay. 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 takeaway 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 a full start to complete SM well design to come online?

All right. 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 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 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 so 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 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 to 130 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?

Yes. 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 XEL'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 $11,000 to $12,000 range, that's a good number to kind of use for that?

In Utah, we assume 10,000 foot laterals. We've done our first fifteen thousand 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.

Perfect. Thanks for the time.

You bet. Thanks, Oliver.

Thank you. The next question is coming from Michael Furrow of Tudor Energy Partners. Please go ahead I'm sorry, Pickering Energy Partners. Please go ahead.

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's a you're drilling cycle times are sort of outpacing your completion cycle times. It looks like at '24, you grew your net DUCs by about eight net DUCs down to like 104, right? Planning on drawing down 45 of those this year, really an efficient use of capital. So was wondering if you guys could 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?

Yes. 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 managed 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.

Yes, that makes sense. Very helpful.

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

All right. That's noted. I'd like to talk a little bit about capital allocation. A few big pieces with the company integrating the Uinta deal, changing activity levels. I'm just looking at your slide here with 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 $25,000 guidance level of 107,000 barrels a day?

So, Michael, we run multiple scenarios when we set up a 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 was very oily. So we basically have those scenarios and we line out a multi year 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. Yes. Returns are similar between the three programs at current commodity prices.

All right. That's helpful. I'll turn it back.

Okay. Thanks, Mike.

Thank you. The next question is coming from Gregory Miller of Truist Securities. Please go ahead. Greg, please make sure your phone is 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 UNTIF, 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 where you're seeing the current expected status of that Salt Lake refinery? May not thinking so, but I just wanted to ask that. And then secondly, are you expecting differentials to remain about the same there?

Okay. I'll start on that one, Neil. So, yes, 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 a key point there. And then Beth, do you want to add?

Yes. 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.

That differential.

Great to add that. And then maybe my second just on reserves, specifically noticing '24 net proved reserves went up nicely, 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 cadence? Do 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?

So Neil, 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.

Beth, was that slowdown just driven by unit by reallocation? Is that primarily what you do on reallocation?

Exactly, yes.

Reallocation. Okay. Thank you. They're still great PUDs, they're just not within five years now?

Yes. We call them they've become 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. 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 Doug questions. I'll throw one at UA here.

Okay.

Repurchases obviously came down a lot in 2024. It makes sense with the big Uinta acquisition. There'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, zero point eight 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?

A great one for Wade.

Yes. That's a great question. And, yes, no, I take all of your comments there and I agree with him. We are on a very clear path 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 the 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 then prioritize return capital once we're to that level. And your comment about would the cadence be similar, you could model something like that every quarter is 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.

To 2023?

Yes.

Okay. Okay. That's helpful. And then my follow-up, I noticed 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. So as you look forward, Herb, you've sort of vaguely commented about initiatives you're looking to undertake to sort of tighten the U. N. Oil diffs. Can you give any comments about sort of incremental initiatives you have or anything underway to maybe continue improving Utah oil diffs? Thank you.

Tim, I don't think it'd be prudent for me to say what we do out in the market for improving our dips, but you can rest assured that we're working that heavily and we think the opportunity set is wide. And 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 all these years and best of luck in your future.

Thank you.

You're welcome. My first question is going to be just on some of the South Texas gas, gassier assets. It seems like you guys have more of a, I guess, bend to kind of focus on the old 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?

Yes. 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 1 and then where they panned out in the subsequent twelve 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 fit and not try and go after our gas assets. If we saw that 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 the change in administration and what happens. And we have great returns. 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.

Okay, understood. And when we take a look at the Permian opportunities and specifically if we look at Klondike and the Greater Sweetypeck 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?

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 on that one.

Yes. 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 deemed 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 around the summer timeframe. So we're really encouraged with what we see there.

And then Woodford Barnett, we had a really good Woodford Barnett?

Yes. Yes. In Sweetypeck, as far as the Woodford Barnett, we had a well produced about two fifty 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 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?

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 pad dependent. But 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 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 Daoud of Cowen. Please go ahead.

Thanks for getting me back on. Jennifer, I do want to say congrats to you as well. I hope you enjoy retirement. And then my follow-up guys is just on the Midland Reserves. I recognize the removal of PUDs related to the five year window. Within 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.

Yes. 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?

I mean, I agree with that Herb. And just as you look at our adds and infills over time, and I would say relative to other years, our adds 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 a really good gas price too.

Oh, okay. Pricing too.

Yes. Right. Okay. All right. Thanks, everyone.

Thanks, Gabe.

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

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 as 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 Hanel 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.

Well, 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 and lock off the webcast at this time and enjoy the rest of your day.