SM Energy Company (NYSE:SM) Q1 2023 Earnings Call Transcript

SM Energy Company (NYSE:SM) Q1 2023 Earnings Call Transcript April 28, 2023

SM Energy Company beats earnings expectations. Reported EPS is $1.33, expectations were $1.28.

Operator: Good day, everyone and welcome to the SM Energy First Quarter Results Q&A Discussion. Today’s call is being recorded. I’d now like to turn the conference over to Jennifer Samuels, VP of IR and ESG Stewardship. Please go ahead.

Jennifer Samuels: Good morning, everyone and thank you for joining us today for our QA session. To answer your questions today, we have our President and CEO, Herb Vogel, and CFO, Wade Pursell. Before we get started, as usual, our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to Slide 2 of the accompanying slide deck, Page 8 of the accompanying 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. We may also refer to non-GAAP measures, 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.

As a reminder, we have posted an investor presentation and the transcript to our prerecorded call from yesterday that we may reference in the call today and look for the first quarter 10-Q filed this morning. With that, I will turn it back to Herb for brief opening commentary. Herb?

Herb Vogel: Thanks Jennifer. Good morning, and thank you for joining our Q&A call this morning. Before we get stated, I’ll reiterate a few key messages this quarter. We’re pleased to report that we have repurchased 2.8 million shares since inception of our return of capital program in September and including our increased fixed dividend, we have returned a total of $134 million. We are well positioned to provide a solid return to our shareholders in 2023 through the combination of our fixed dividend and upside through share repurchases. Execution was solid in the first quarter, not only exceeding guidance for oil and total production volumes, but recognizing notable operational achievements such as drilling 75,000 feet of lateral 20 days faster than planned or successfully drilling 5,000 to 18,000-foot laterals, which are now among the longest laterals in the Midland Basin — is the key objective to maintain and build our inventory.

And during the first quarter, we made progress on this front with organic growth through the purchase of 6,300 net acres in the Midland Basin. This first quarter is a solid start to what we believe will be a great year. With that, I will turn it back to Lisa to start taking your questions.

Q&A Session

Operator: We’ll take our first question from Scott Hanold with RBC Capital Markets.

Scott Hanold: You all had a pretty good start to the year on your production performance. Can you — I know you gave some color on your prepared remarks last night and in your press release, but can you give a little more color on what sort of things are you seeing? It seems like there’s better operational efficiency, maybe a little bit better well performance and is part of it, too, as you extend these laterals are seeing better performance? Or is that more on the come yet?

Herb Vogel: Yes. Thanks, Scott. I would say it’s just regular blocking and tackling. Our well results are — it’s actually quite predictable on what they do. And it’s a matter of how much offset activity there is, and it was pretty much in line with what our expectations were during the quarter. The base performance has been great on our base decline of PDP wells. And then the new wells are performing as expected or better. And in one case, in the case of that Eagle Ford South Texas pad, seven wells came on a week early. So I would just say it’s — we find it very predictable for our wells. And then on the uncertainty it is just how much offset activity we’ve got to anticipate.

Scott Hanold: Okay. No, I appreciate that. And as my follow-up, you talked about that picking up a little bit of acreage. Could you, at a high level, talk about the strategy there? And is this more tactical kind of bolt-ons? Or do you see the opportunity to kind of continue to do more of that and scale up a little bit? And I’m just kind of curious like how big of kind of — how much acquisition activity in terms of size do you feel comfortable to do?

Herb Vogel: Yes. Scott, this is Herb again. I would say we’ve all along since we really built our position in the Midland Basin, we’ve been looking at acreage trades, acreage acquisitions where it makes sense. And fortunately, our geosciences team has — it’s pretty laser-focused on intervals that are differential in terms of their return performance. And we keep looking at places where it makes sense and where we can get the acreage at a reasonable cost. And that was certainly the case for the last quarter of last year, first quarter of this year, and we’re going to continue to do that. There are large packages. There are small packages on the market right now. Private equity, as you know, been selling some of their positions.

We look at those if we can get something that makes sense from a returns perspective, we look at it hard. And obviously, we keep it at a scale that makes sense for the company because we’re not going to do something that wrecks the balance sheet. That’s really how it looks. So yes, we’ll keep looking.

Scott Hanold: Okay, right. So similarly, there’s been some larger deals that have happened nearby. You look at things like that, it just has to make sense. Is that a fair way to look at it?

Herb Vogel: Right. Exactly. That’s to make sense for the scale of our company and the quality of the acreage. We have a really high bar on that quality of acreage metric so that we make sure we continue to get those high returns that we currently enjoy in the Midland Basin and Austin Chalk in South Texas.

Operator: We’ll take our next question from Leo Mariani with ROTH MKM.

Leo Mariani: I wanted to follow up a little bit more in terms of this 6,300 net acres, which you bought. It looks like around $10 million. So relatively low priced, I guess, roughly $1,600 an acre. So is this kind of more exploratory acreage? Just looking at the slide deck, it looks like it’s not in Rockstar. It’s not in Sweetie Peck, if I’m reading that correctly? And is there any color whether or not there’s kind of well control on this stuff? Is this kind of more away from sort of the existing assets? And maybe you’ve got some intel there that you think this can be promising. Just any more details would be great.

Herb Vogel: Yes. Leo, I know a lot of people would be curious about that. And obviously, we’re not saying we would have put it on the math if we were. And you’ll see more in the future about that. But right now, we’re really not saying anything more.

Leo Mariani: Okay. And then just in terms of the Chalk wells, you guys have these 7 wells, which you clearly saying came on early, but sounded like very strong performers as well. Just trying to get a sense there. Have you guys benefited at all from kind of the new completion designs that you guys have been experimenting with for the past handful of quarters. Is that potentially leading to some of the strong performance of wells? Or is that something that’s maybe more late this year into next year? And then just on the midstream side, you guys obviously had some issues in the fourth quarter in terms of not being able to flow your wells. Do you feel like those midstream issues are behind you in the Chalk now this year.

Herb Vogel: Yes. Thanks, Leo. Great questions. First of all, I’ll just say that all our new Austin Chalk wells outperformed our expectations. It has been great to see all the improvements, and some of that is completion and the design improvement. There’s a number of other factors why they performed better. You’ll recall, we did have too much oil in our — for our facilities last quarter and the third quarter last year, and that’s steadily being relieved, and we should be done with that by the end of the second quarter. So that kind of which made state data look kind of odd because wells were basically capped in what they could produce because of the high back pressures. That’s steadily being relieved. So we don’t anticipate that problem extending to the end of the year.

We do have to watch it when we bring on a lot of wells that are very oily. We have to really watch and choke back to make sure we don’t wind up with a problem that way. But we’ve managed through that one, and now you’re able to see those — how good those wells really are that we’ve been drilling. And part of that is all the optimizations we’re doing. And some of that’s very detailed in the completion design itself and some of it is just more the laterals and what interval they targeted. I think that got all your questions?

Leo Mariani: Yes, very thorough. Appreciate it.

Operator: We’ll take our next question from Zach Parham with JPMorgan.

Zach Parham: I guess first just on cash return. You returned over 100% of free cash flow to shareholders this quarter. Going forward, do you plan to remain purely opportunistic with the buyback? Or have you considered putting in a 10b5-1 plan? Just trying to get a sense of the future pace of the buyback?

Wade Pursell: Yes. Zach, it’s Wade. Just to answer the last part of that question first. No current plan to put in a 10b program. The — we’re basically executing the way we said we would. I see no reason that won’t continue. And that is simply during open windows, and I will say the first quarter was probably the shortest open window of the year just because of the timing of year-end reporting. But we just like to kind of methodically go through those open windows and support the stock. We certainly have a view of NAV. So when we feel like there are times of undervalue, we lean in a little bit more. I probably saw some of that in the first quarter. But that will continue, and we moderate all of those expectations with a humility towards the macro and what could happen over the remainder of this year, next year.

So that’s kind of the plan. And just to remind everyone, the Board authorized up to $500 million of share buybacks through the end of next year. And — and I guess, so far, we’re close to $100 million. So you can just kind of see we’re executing really exactly, I think, the way we said we would.

Zach Parham: Thanks for color. Just to follow up on something you said in the prepared remarks, you mentioned you were starting to see some improvement on costs and mentioning that rig counts have moved lower industry wide. At this point, what are your expectations for any cost deflation later this year? And how could that impact your CapEx budget maybe in the back half of the year and into ’24.

Wade Pursell: I would just comment and then let Herb give color if he wants that we certainly are not baking anything in at this point with respect to rig rates and completion rates. There are some — as I mentioned in the comments, utilization does appear to be falling and rates do appear to be plateauing. So that could bode well for the second half, but we’re certainly not guiding or planning on any of that yet, Herb?

Herb Vogel: Yes. Zach, I think you probably hear this from a lot of the operators. But clearly, we’ve seen a reduction in our diesel costs and diesel costs are actually a pretty significant component of our CapEx and probably call out a 25% reduction from the fourth quarter. Steel costs are rolling over pretty clearly. Rig costs, you’re aware, we feather our rig contracts, they are one year contracts. And so every 2.5 months, we have another rig contract come off, and they’re getting exposed to market rates. And we see that as so far flattening so that’s another cost component. And then on the pumping services side, it looks like there’s some gas basins that are letting crews go and some Permian pickups on fracs. We monitor how many new ones are coming to the market in the fourth quarter.

There were 7 new frac spreads in the first quarter, there were 3 and the fact there’s going to be quite a few coming on in the second quarter. So we’ll see where that goes because that is a big cost component. And then it looks like sand production in the US is up quite a bit. And we’ve got a great contract and a great provider on the sand side. And then the sand last mile logistics is another area, and that’s partly driven by diesel costs. So we benefit there. And that’s something that gets renegotiated quarterly based on what cost indexes are. So there’s quite a bit to look at on the inflation side, but we’re pretty comfortable with where we are, what we budgeted and our assumptions. So we don’t see a need to change anything at this time.

Operator: We’ll take our next question from Tim Rezvan with KeyBanc Capital Markets.

Tim Rezvan: I wanted to dig in a little more on the South Texas gathering issue because I know it was a big headwind in the end of the year. Herb, you just gave commentary, you think it will be behind you by midyear. Can you talk with specifics about what is happening and what gives you confidence that, that will be behind you?

Herb Vogel: Yes, Tim. Yes, it’s all around the facilities together with our midstream gathering partner. And there’s a lot of components to what we’re doing there. So we’ve talked about before the backbone where we put in or progressively putting in larger pipe or line looping to get more capacity. But there’s components from separation optimization to pipeline modifications, then there’s some automation to reduce manual intervention. So overall, it’s just to increase the liquids handling capacity to a system that was designed for much higher gas from the Eagle Ford. And so when we drill very oily wells, particularly in that northwest area, we’ve had to expand the capacity. The oil rates are much higher and faster than we would have anticipated when we commenced the Austin Chalk program. And so now we’re playing a little bit of catch-up, and we should be there by the end of the second quarter. It’s a great problem to have, right, too much oil?

Tim Rezvan: You can flow, yes, it’s a good problem, I guess.

Herb Vogel: That’s right.

Tim Rezvan: Okay. I appreciate. I appreciate that context. And then I wanted to circle back to the repurchases. I guess Wade had mentioned the window was sort of short in the first quarter, but $40 million was, I guess, slightly higher than what you did in the fourth quarter. Barring any unforeseen issues where you can’t repurchase, does that seem like a good steady-state cadence to model going forward?

Wade Pursell: Generally, yes. Every quarter, we’ll have it. We look at it every day. And as I mentioned, we — there will be periods where we lean in a little bit more based on our view of how the stock is trading. But generally speaking, yes, you could assume something like that.

Tim Rezvan: Okay. Okay. And then if I could just sneak one last one in. You continue to build cash on the balance sheet. You have well over $350 million, which is the 2025 note size. Do you continue to view that cash just sort of the offset to that debt maturity? And would you expect to continue to grow cash into the next year or 2 as you have these bond maturities due? Or how do you think about the right sort of capital structure?

Wade Pursell: Yes, sure. Good question. And yes, everything you said is accurate. We are building cash. We are generating free cash flow. So kind of everything else equal, you could anticipate that depending on when we decide to take out the maturities. The 2025, which is obviously the first maturity that’s facing us is still over a couple of years away, incredibly attractive coupon in this environment at 5 5/8% that’s probably better than investment right now for our peers. So the interest we’re earning on the cash is not that far away from that. So there’s not a lot of cost to continuing — to continue with the cash. It feels like the right thing to do in this environment, still a lot of uncertainty. So we’ll take another hard look at it when it — I think in a couple of months or less than a couple of months, those 25s become callable at par.

So we’ll take another hard look at that time. But you’ll see us take those out at some point. But in the meantime, you’ll — I think we’ve got a nice cash balance and it will grow and subject to opportunities that are always hard to predict. So really happy with the condition of the balance sheet, obviously.

Operator: We’ll take our next question from Oliver Huang with TPH & Company.

Oliver Huang: A quick question on the longer laterals. It looks like the team has been able to successfully push the envelope at this juncture on lateral length with 5,000, 18,000 foot lateral wells online in Q1. Just wanted to see if we might be able to get a bit more detail in terms of what some of the primary challenges that you all encountered were expectations for well productivity on a per foot basis relative to the standard 2-milers you all have been predominantly averaging over the last few years? And just how many more of these currently sit as prospective on your acreage footprint as is?

Herb Vogel: Yes. Oliver, that’s a great question. Obviously, one that we monitor very, very closely, right? And you’re probably aware, we have a few of the longest wells in the Midland Basin, we have a big database. And I will say I was skeptical this at first, but it’s pretty much one-to-one. And you’re aware, we hold the Texas record with the longest lateral of just about 4 miles. So we do have a big database, and we’re pleased with the way the longer laterals are panning out. Now the least geometry is really what drives how long those laterals are. And so it’s just a matter of when we see an opportunity to extend and improve the economics significantly, then we’ll pursue the longer laterals. If we don’t see that improved of economics, then we don’t.

What are some of the issues as long laterals is you’re probably aware, a lot of these — when we start production with the low GOR wells with the high oil percentage, that the electric submersive pumps can only pump so much. And so they wind up and plateau a little bit longer than it would be with a short lateral. But the overall returns on these wells are great because the costs are so much lower. Technically, what’s important is to really get a flick straight drilling process. You really have to have great coordinations in your drilling, your completions team and what they can do with the fracs and then the drill outs. And we have some things that we do to make sure that we get full contribution from the toe stages and I think some companies will bend their pick on that one, but we’ve been successful on that part of it also.

So that’s really the summary. And I’m not going to forecast how many of these come up, but they are great opportunities, and we look at them hard, and we do have a big database.

Oliver Huang: That makes sense. And for a second question, just on the production side, a solid quarter relative to the expectations you all had laid out. And another difficult question to answer, but we were wondering if there was any level of detail you all might be able to provide in terms of how much higher production levels could have looked if wells were performing at optimal levels, if not for frac shut-ins from offset operator activity, just to kind of help investors better understand the full potential of your asset base?

Herb Vogel: Yes, Oliver, I would just say the number of wells we have in the Permian Basin are type curves, they’re solid. We don’t move them around much year-over-year. They’re solid, and we have additional intervals coming on. As you’re aware, we forecast the 8 different potential target zones, and they’re coming in as expected. We are really good at optimizing the spacing, both vertical and horizontal and we’re codeveloping. So I would say the well results are very predictable in the Austin Chalk now. We’re at — I think we have 75 wells that have already reached the IP 30 and we’ve got another 7 online beyond those, so 82 total. So that’s very predictable also. So what is hard to predict is when there’s offset operators, less so probably in South Texas, but in the Permian, if there’s offset operators and we do have a reasonable forecast.

We do communicate so we know when they’re going to happen, but sometimes somebody will be delayed, change their schedule and that may change things. So that’s where I’d sum it up. I don’t think it makes any sense to say, here’s what the wells could have done, and then we’re going to subtract this for potential shut-ins. I think we’ll just show over time continued great performance of the wells, and it’s really — bottom line comes down how much free cash flow, right, because our plan is set up to maximize free cash flow over a 2- to 3-year period. So that’s the number we focus on. Free cash flow more than anything else.

Oliver Huang: Awesome. That’s helpful. And if I could squeeze one last question. Just on the inventory side, I know you all highlighted 6 Leonard well tests in the first half of the year and 7 Wolfcamp D tests in 2023. Just any color to provide in terms of the spacing designs of these tests? Are they part of a co-development pad? Are these tests across a specific portion of your acreage? Or is it something that’s looking to be a little bit more localized? Just trying to understand that a bit better.

Herb Vogel: Yes. I’ll just general say the Wolfcamp D is entirely isolated with a thick section between the Wolfcamp D and the prospective Wolfcamp B — so there’s no frac interference so we don’t need to do co-development there. And we’ve been working on what’s the appropriate lateral spacing and the best target interval and Wolfcamp D is quite fixed. So that’s really the focus of our effort. We have quite a few wells and then there’s a lot of offset operator wells also. So we’re starting to get a big database in order to forecast the performance there. On the Leonard, the Leonard will work where it’s firmly mature. And so you have to have a pretty good sense of thermal maturity in the Leonard to understand where those wells will perform well, and we’re gathering additional data on that.

We really don’t have any additional results to share yet on the Leonard and the Wolfcamp D. But as they get to their IP 30s and then we’ll start having some data out there. But so far, it is a focus for 2023, though.

Operator: And we have a follow-up question from Leo Mariani with ROTH MKM.

Leo Mariani: I guess just a quick question around cash taxes. Do you guys have kind of an estimate of roughly how much you think that’s going to be in kind of current commodity prices here in 2023?

Wade Pursell: Leo, it’s pretty similar to what we said before, pretty nominal this year, 2023, I think probably 0 to $10 million. Based on current commodities, if you look out to next year, it’s probably a little lower than I would have said before, something in the $60 million range, and that’s kind of a run rate for a few years beginning next year. That’s our best estimate right now. And it was, of course, 0 this quarter.

Operator: And there are no further questions at this time. I would like to turn the call back over to Herb Vogel for closing remarks.

Herb Vogel: Okay. Thanks, Lisa, and thank you all for your interest, and we look forward to seeing a number of you at the upcoming May and June conferences in Houston and New York. Thank you.

Operator: And that does conclude today’s presentation. Thank you for your participation, and you may now disconnect.