SM Energy Company (SM) Earnings Call Transcript & Summary

Greetings, and welcome to SM Energy's First Quarter 2025 Financial and Operating Results Q&A session. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Patrick Lytle, senior Vice President of Finance. Thank you. You may begin.

Thank you, Shamali. 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. On the call this morning, 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 and 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 the earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking and non-GAAP measures. Also, our first quarter 10-Q was filed this morning. With that, I will turn it over to Herb for a brief opening commentary. Herb?

Thanks, Pat. Good morning, and thank you for joining us. We are really pleased with the performance across the company and particularly pleased with how well the integration has gone and the quality of our Uinta Basin assets. As a reminder, our plan for 2025 delivers 30% increase in oil production, 20% increase in total production, and that's a step change in scale for SM. And we clearly have 3 top-tier assets. With that, I'll turn the call back over to Shamali to take your questions. Shamali?

[Operator Instructions] Our first question comes from the line of Tim Rezvan with KeyBanc Capital Markets Inc.

My first one, I don't know if this is for Herb or Beth, but I'm trying to get an understanding on the shape and the oil skew on 2025 production. First quarter was 53%, and you're guiding to a little higher oil cut in the second quarter, but you didn't touch the full year kind of guide for oil. So just curious if you -- are there timing issues with the Uinta wells coming online that we should be aware of? Or is this just simply you not touching most annual guidance items at this point? Just trying to understand how the year is going to shake out.

Yes. Tim, I'll start, but I think Beth can dig into that one a little bit more. But yes, we didn't see material changes to change anything for the full year plan, but she can elaborate a little bit on the percentage improvement in oil cut from 1Q to 2Q and what that means later in the year.

Yes. And so what I would say is as you look at the production rates, and as we said the whole year, we go from 1Q to 2Q increasing modestly, and then you'll see a major increase in the third quarter. And as far as oil mix, we have a bit more Uinta wells coming on, but it's important to kind of take a step back and just know that every single quarter that we have variability in that oil mix depending on what wells we bring on. So we have large pads coming on in the Uinta. And so that is driving our oil mix a bit higher. For the year, we would stay within the guidance range that we've already put out there.

Okay. Okay. That's helpful. And then my second one, I guess, maybe more for Wade on the topic of cash returns. Your path back to a 1x leverage is now a little steeper with oil below $60, but we [ didn't ] see the balance sheet getting there around year-end. So is it safe to assume repurchases are going to be off the table this year until you get there? Or do you feel compelled to maybe step in and defend the equity with where shares are now?

Yes. Good question, Tim. I think my answer would be very similar to what I would have said a quarter ago that we certainly like the stock price. I mean that has nothing to do with it. We are being disciplined about allocating free cash flow to getting leverage back to that 1x area. And yes, prices are lower than they were a quarter ago. But you're right, even at current prices and, certainly, if you assume something like $55, we generate a lot of free cash flow, plenty of cash flow to frankly pay off maturities. And that leverage metric kind of gets down into that really, really close to 1x area. So I think you can assume that we are prioritizing debt reduction until we get there. I think that's a good assumption. But I wouldn't take off the table our ability to step in occasionally to support the stock.

Our next question comes from the line of Oliver Huang with TPH.

Just wanted to start out in the Uinta, looking at Slide 7 in your deck, the one showing productivity charts by various key regions. I know the lower cube is the primary focus for you all today in the Uinta. And I imagine the data set from Enverus that's being cited there likely shows a heavy lean into the Uteland Butte as the most developed pay zone within that part of the stack. So my question is, what is the expectation for being able to hit the underwritten assumptions for the lower cube when you're co-developing with other zones like the Wasatch and the Douglas Creek, which haven't been quite as prolific, historically speaking, on an oil per foot basis?

So I would say -- Oliver, thank you for the question. And 90% of our program is focused on the lower cube, and we have a majority of those going into the Uteland Butte and the Wasatch and some in the Castle Peak, right? So 90% lower cube proving up the value there. We're highly confident in the forecast that we have coming out of those zones, very competitive. The rest, 10%, is focused on the upper cube. And as you saw from Enverus, strong results there in the Douglas Creek, and we'll continue to test other intervals within the section.

That's helpful color. And maybe for a follow-up, just on LOE. I know you all called out a few items impacting the corporate LOE guide for this year. Maybe a greater mix of horizontal wells in the Uinta should help over time in addition to getting some of the costs associated with getting facilities and whatnot up to SM spec. So question is, as we think through the uplifted cost in this year's program on a corporate basis, should we view this as more onetime in nature type of impact? Or are there some of these costs that are going to be much more sticky beyond this year, if you could walk through that?

Yes, I'll take that, Oliver. So we see the use of the fuel gas and our change in the way that we record the cost to continue moving forward. We use the fuel gas within our operations. And so we see that going forward, and that's about 1/3 of that increase. The workover activity would move forward a little bit, and we have increase in water production that came from offset activity. Some of that may continue, but we've included all of that in our adjusted full year guidance.

And just a reminder, the first item has revenue offsetting it, so the accounting.

Our next question comes from the line of [ Fu Fan ] with ROTH Capital.

So I saw that like you dropped 2 rigs in the first quarter. And you also said eventually the total rig will be 6. So I was wondering if you could be more specific about the time lines when to drop one more rig.

[ Fu ], thanks for the question. We are really not giving any guidance on what our plans are for specific rigs at this time. So you can just say we'll drop to 6 rigs when it makes sense based on the program as we've laid it out. And really, what matters is the turn-in-lines in terms of translating things to production. And that's really -- we're still sticking to our TIL plan for the year. So no change on that front.

Our next question comes from the line of Michael Furrow with Pickering Energy Partners.

Last quarter, Herb, when asked about capital allocation between your assets, you mentioned that returns were really comparable across the 3 areas. But if prices move that the company would have the ability to kind of flex between regions. And at that time, prices were $74. Today, we're looking at, what, sub-60, with gas prices relatively flat. So my question is, have the returns between regions changed? And if so, should we expect sort of a higher allocation of capital activity towards South Texas versus the previous update?

Yes. That's a great question, Michael. And it's really difficult to change a program that quickly. The commodity markets work on intraday time lines, and our plans work on time lines quite different from that. So with the program we've laid out, it looks quite good at strip for the year in achieving our objectives for the year. Realistically, if prices for oil were to drop below $50 per barrel, you'd expect most companies to really revisit their programs. And we're kind of in that situation of looking. We're really comfortable above $55 with the program we have. It delivers everything we want. Pullbacks in activity take quite a bit of thought and are tied to our procurement contracts. I don't know if that answers the question for you, but we don't see a change at this time at all. It would be -- need to be more dramatic change in commodity prices for us to consider doing something different. But we do have plans made as for contingency on what we do later in the year, were something to change.

No, that answered my question. That's understood. It's not so easy to just drop a rig and pick one up as quickly as we'd like. So for my follow-up, I just want to ask a quick question on the Uinta. Now that the companies have more time to kind of look into the acquired assets, how are they looking versus the original expectations? And is there anything that the company is learning that would alter the drilling or completion designs that you guys get to have in 2026 versus the prior operators' designs?

Yes. I will just say, Michael, I'm really pleased with the assets. It's definitely exceeded our expectations, and we're really pleased with the XCL team and what they did setting us up with quite a bit of investment in infrastructure that we're really getting the benefits of now. But I'll turn it over to Beth because she can dig into the details more about specifically what we like so much.

Yes. I would say just to start and kind of piggyback off of what Herb said, the innovation of our drilling, completion and operations team has really been phenomenal, and we continue to just beat a lot of the records that we set previously. And so we're just overjoyed with the fact that we're able to drive capital efficiency there even more than we thought going into it. Now as far as the synergies and the great things that SM brings to this asset, it's really associated with the geoscience and reservoir engineering teams that continue to look at the well performance. And as I mentioned in the prepared remarks, we are not popping or turning in line the new SM design pad until 2026. And so all of the information that we're gaining through 2025, we're putting into that design to make it optimal and create the highest returns and free cash flow. So I think across the board, we're seeing outstanding results in our Uinta Basin.

Our next question comes from the line of Michael Scialla with Stephens. Michael, is your line unmute?

Sorry about that. I wanted to see if you could say how much oil went to the local refinery or refineries in the Uinta during the quarter and kind of the difference in transportation costs there between the 2? And what determines that split from quarter-to-quarter?

Yes, I can jump in on that. Typically, we sell about 15% to 20% of our crude into the Salt Lake City refineries. It has a lower transportation cost. And any time that we can get the higher percentage of our oil going to Salt Lake City refineries, we will do so. And so we continue to just try to maximize that market as much as possible, and then the rest, we send by rail.

Is the -- is that just based on capacity? There's no contracts that are underwriting or underpinning how much goes to one or the other?

Yes, that's correct. We work with multiple refineries up there, yes.

And it looks like you had pretty minor nonop activity in the first quarter, anticipating a little bit in the second quarter as well. I guess I want to see if you have any better visibility on the remainder of the year, if you think there will be any material change to that $1.3 billion of CapEx that you have planned for the year.

Yes, Mike, what I would say is, so far, you could expect a similar run rate in the second half of the year as we're seeing in the first half. We don't deem that as material to our full year CapEx program, and that's why we haven't changed guidance.

Our next question comes from the line of Zach Parham with JPMorgan.

Could you talk a little bit more about your operational plans for the year and going into '26? You've gone from 9 rigs to 7 rigs. You're planning to drop to 6. As you see things today, would you plan to add back a rig in 2026? Or is 6 the run rate going forward for the pro forma company with the 3 assets?

Yes. I'll start with that one, Zach. I got to say, hey, what do you think the strip will look like in November of 2025? Well, I don't know. So we've really got scenarios and plans laid out that really are tempered, call it, by the commodity prices that may show up or not later in the year and what the cost environment will be. So we really don't have a 2026 plan laid out there. We have scenarios, and we -- as we see a pathway unfold, we'll pursue the scenario that we've lined out for that price outcome, call it. And you know how it is. It's -- we work on a time line that's quite different from the daily prices in the commodity markets. So we have to kind of sort out what is a short-term phenomenon versus a trend in terms of what it leads to in commodity prices and costs. So that's how we set things up. Zach, we don't have a specific plan for 2026, but we have multiple scenarios, and we model the company. And that's why we can say, hey, we stick with this plan at current strip. It looks good down to $55. And then below that, we'd start looking at, do we change anything? How long would that last? That's really how we look at it.

What happens to cost.

Yes, what happens to cost. And Wade has done quite a bit of modeling the company in even more adverse environments, and we feel very comfortable from a balance sheet perspective. Wade, do you want to add anything on that?

No, you said it well. I mean, I think I mentioned it earlier, at $55 flat, I mean, you see us generating lots of free cash flow, paying the dividend, paying off maturities, a leverage metric in an area that we're very comfortable in. So if you're wondering about hedging, we -- that's kind of influenced our hedging decisions a little bit. You'll see us do a lot of $55 floors on costless collars just to protect that level because that's a very positive level for us, if I could say it that way.

Just to follow-up. I think you messaged in the past, you could generate single-digit growth at kind of flat CapEx year-over-year. Is it fair to say if you were to go to a maintenance program, CapEx would be down year-over-year? Based on costs that we're seeing now, obviously, you can have service cost deflation as well.

Yes. Zach, that is a big wildcard. We don't know exactly how things will go on costs for '26. I mean things are looking pretty good that tariffs are really only influencing a small percentage of our cost. And under scenarios that are a little bit more adverse price-wise, it's pretty close to flattish. Obviously, there's quarter-to-quarter variation depending on when turn-in-lines are coming on, but I think that answers what you're looking.

If you're just looking at year-over-year dollars going from 9 to 6 this year and being at 6-ish next year, obviously, the cost would be overall lower.

And with those 6 rigs, you could hold flat next year. Is that fair?

Yes. It depends a little bit on the mix and where you are on BOO versus BOE. So if we drill in more on the South Texas side, because of the gas and NGL prices being better, then obviously, it's easier to be above flattish. If you drill more heavily into the oil, you'd be at the lower end just because of the nature of BOEs versus BO.

It's in the flattish area.

But it's a flattish area, yes.

Our next question comes from the line of Gabe Daoud with TD Cowen.

I was hoping maybe I could just start with a clarification on the trajectory for the second half of this year. Did you say earlier that 3Q should show -- I guess it will show sequential growth, but is 3Q growth more than the type of growth that we will see or that you guided to in 2Q? Is that fair?

Yes, that's fair.

Okay. Okay. And then maybe just as a follow-up, if we could maybe get a 101-type explanation around how Uinta production/sales is booked from a revenue standpoint? And just given the lag between when the barrels get transported versus your revenue recognition, will there always be a mismatch between sales volumes and production at the wellhead? And should we expect a true-up at some point to make you whole on that? Or will there always just simply be a little bit of a discrepancy between those 2?

Yes. This is Wade. I would not call it a true-up. There will be slight lags just depending on a cutoff at the date for the reasons that you articulated. So there will always be some lag there and some small difference there going forward is the way I would say it.

And we have reached the end of the question-and-answer session. I would like to turn the floor back to Herb Vogel for closing remarks.

Thanks, Shamali, and thank you all for joining us today. We look forward to seeing a number of you at upcoming events. Have a good day.

Thank you. And this does conclude today's call. We thank you for your participation. You may disconnect your lines at this time.