SM Energy Company (SM) Earnings Call Transcript & Summary

JPMorgan for hosting the conference. It's great to see as many people as we have out here today. And thanks to those of you who are interested in SM are here today or on the webcast live. So I'm going to cover quite a bit today, but I'm going to try and do it in 10 or 15 minutes and really hit the high points, and we issued a press release this morning. I'm sure all of you have eagerly looked at that and anticipated that. But let me just start with the usual disclaimers that I'm going to be making some forward-looking statements, and I'll just direct you to that slide, which is on our website, too. So the breaking news. I'm going to start just with the operational metrics. And the big news here is we've had quite a bit of success in the Austin Chalk and Midland Basin, and we're going to be upping our guidance for the year for production by 1 million barrels equivalent. Our oil production will be going up 3%, compared to what expectations were in terms of the barrels for the year. And then with deflation and a few other impacts, we're reducing our capital guidance for the year by $50 million. At the same time, we'll be increasing activity in the fourth quarter with the picking up of a rig for an acquisition, then I'm going to be covering in a bit. You can see the details there. capital down by $50 million, production up 1 million barrels and then oil percentage would be 43% to 44%. And then our LOE is also down $0.50 per BOE. So all super positives there. Next is really the repurchases. So we said that we'd be opportunistic on the share repurchase program that we announced in September, which is $500 million. We leaned in a bit more in the second quarter with where the share price was trading. So we basically bought 2.6 million shares and that's about 2.2% of shares outstanding. So our yield to market capitalization over the last 9 months, if you include the dividend payments of about $55 million is about 7%. So the total program to date is 5.3 million shares repurchased. Operational performance, I went over. Basically, it's 4% production over expectations for the second quarter. And then we've had deflation both in LOE and capital. And a lot of people have been following what was going on in South Texas where our oil takeaway capacity or really is our oil gathering capacity was limited, because of how oily our wells are in the Austin Chalk and the build-out was completed early in the second quarter, and we had announced it would be by the end of second quarter. And finally, the really exciting thing is, in the second quarter, we did asset acquisitions of a total of 22,800 acres in the Midland Basin. One of those is for 20,000 acres that is $93.5 million. The rest is an additional 3,000 acres on top of the 6,000 we announced, and we haven't disclosed where that is yet other than it's in the Midland Basin. And we'll be getting more detail out on that when it's appropriate to do so. So that's the breaking news. So how do I sum all that up? Well, it's really a combination of more growth, which really means in 2023, obviously, on the production side of things and then more oil, which I just mentioned, and then more return of capital. And the key thing is more inventory throughout also. So the more return of capital is obviously 2Q and we're thinking about this longer term. What do we do for more inventory and more return of capital over the long haul, and that's where we've focused things on. So by doing the acquisitions, that allows for inventory replacement with high-quality inventory. So it doesn't mean anything if you just add acres for the sake of acres. So we're really adding on breakeven below $50 barrel type of inventory. So that each year we can show you a slide deck, and it says 10 to 13 years of remaining inventory, I want to be able to say that next year, the following year and the following year or more. So the basic thing, if you want to believe in the return of capital being sustainable, we can show you that there's going to be the inventory backing it up and it's going to be quality inventory. And that's really the path we're on. So I was talking to some of the investors earlier today and we kind of got to the conclusion where we're kind of a unicorn SMID cap, because we've got long duration, high-quality inventory, and we have the differential ability to add high-quality inventory, because the basins we operate in and the way that our teams -- the geoscience together with the engineering teams can handle it, and that ultimately returns to capital to shareholders. So that's the whole point of what we're doing. And the reason we came out is we're hitting every dimension from operational performance, inventory replacement and return of capital. So that's the headline right there. This is the traditional way we've positioned ourselves that we're a premier operator of top-tier assets. If you look at how we're operating and how we benchmark the metrics that matter, you'll see that we do really well. I'm just going to touch on those real quickly, because some of the slides we've had out there for quite a while. And on the ESG side, we also benchmark extremely well, especially for an oil operator. So if I go here, Midland Basin. You can see where we operate, we can do better than offset operators, because of the technical capabilities that we have built over time. And in the Midland Basin, our breakeven costs or breakeven oil price is among the best regional peers altogether. And that's the best measure you can have. Now somebody looks at it and says, "Well, your costs are higher." But the reason the costs are higher is because we've got a completion design that gives us higher value wells. So the returns we're generating are what we really focus on. And you'll see I'll take a $900 per foot well over $700 per foot well if I'm going to get a much higher EUR and much higher return. So that's the way we look at it. And I've got 1 slide to just kind of demonstrate that. In the Midland Basin, one key thing is we do co-develop our assets. And that means that we basically take an average of the highest return interval together with 2 other intervals, and the composite retains the inventory and gets the highest overall return rather than doing the best zone first and then not being able to come back. So when somebody talks about child well issues, we don't have those, and those are already baked into our forecast because it's integrated in the design, because every DSU is custom designed based on the geo-mechanics of the area and the returns, we expect that certain commodity prices. So that's the point I want to make. I circled the Dean and that's because going to this next slide, you can see we've got 91,000 net acres. We used to see 82,000 net acres in the Permian Basin before. We added 9,000 acres in the undisclosed location. And then the other 20,000 acres, which are pending close, and we announced that the play there is different than your normal stack mudrock play. What we're doing there is targeting the Dean sand and the Middle Spraberry sand. So it's a different play. It has a different type of type curve. It's got a great peak rate, but also a slower decline, and it's 90% oil. So that's -- that's the real plus. So that's what we just announced today. And you can see that puts us at a total of 111,000 acres in the Permian Basin. In the Austin Chalk, this is a slide we've shown before. We continue to see great performance in the big operational outperformance this quarter was in the Austin Chalk and that was a combination of things. Again, here, we've got a lot of inventory in the Austin Chalk, and you can see how it stacks up with low breakevens. And this is Enverus' analysis that's their most recent update. And this is the quote we love to hear. This ties to that unicorn comment I made that we've got the deepest and highest quality well inventory among the SMID caps. So here's the whole thing behind the acquisition and kind of how you have to look at SM Energy, if you're new to us. We came into Howard County in 2016. At the time, there was very little data. There's a lot of skepticism about it. And since that time, since 2016, when we got in now 2022, there's over -- from 79 wells to 3,200. It was one of the more active counties in Texas, and we kind of opened that up, showing people that, that high oil content in the area led to really economic wells. And we've got -- as of year-end 2021, we reported -- this is an old slide, reported 12 years of inventory that we want to keep hanging in there at that level or better. And Austin Chalk, same sort of story. No one was drilling the Austin Chalk. It didn't really work. And then we figured out a way. We figured out the right landing zone was the key. And it took core data and a lot of technology to get there. So we estimate about 400 locations. We've already drilled 75 that have passed their IP30 today. So we've got a lot of data, and we continue to optimize, and you're seeing that in 1Q and 2Q productivity. So this is the slide that Jennifer, our VP of IR, thinks I talked about too much probably. But the point here is that if you put in additional completion capital and you put it in the right way, your value per well can increase significantly. And the way we do that is really the return going from the orange to the blue is well over 200% in the wells we're doing. So it's that incremental sand cost and the incremental water cost, together with the drill out together with the way we're handling the rest of the completion design is enormous value, and that's the way we approach it throughout. And this is done with machine learning and simulation also. So with that, I'll just say quality inventory, a couple of updates on this slide. I want to keep that 10% to 13% or more in front of you, and we're going to keep doing that to show that we're a sustainable company. We want to have some slight growth going from low single-digit growth to mid-single-digit growth, and that really maximizes free cash flow over the next 2 to 3 years. So that growth rate is really back-solved to maximize the free cash flow, which would allow us to get that return of capital. You can see here really high-quality inventory. It's quite certain. And we added this upside. Some people said, "Well, how much upside is it? Like if I'm trying to compare inventory across companies, how do I do that? We said, well, you could add 4 to 5 years to that inventory number if we went to certain DSUs and just decreased the spacing to around 1,100 feet per zone. And that would do -- add that much inventory. So you can see when -- we don't do just sticks on a map, but if we were to do sticks on a map, we could show a different inventory number. And then again, we do run our inventory at $65 barrel of oil, just so you know. Next, I'm not going to go over the balance sheet, but obviously, we're in great shape on the balance sheet. And finally, on ESG, we put in our 2022 numbers, great numbers again on CDP side for an oil and gas company, getting a B on CDP is just great. And then with even supplier engagement, we get A-. So routine flaring, 0% nonroutine flaring, 0.4%. And great numbers there. So with that, I think the point I'm trying to make is sustainable. We're going to keep being able to the return of capital and we'll have a strong balance sheet, and then we're going to show you how we can organically add inventory. We prefer not to do big PDP acquisitions because those are lower return. We prefer to have the technical ability to run as an E&P company that builds value, creates value on its own. So with that, I think I'll turn it over to you, Zach, for questions.

Thanks, Herb. I guess first, maybe just a few on the release you had today. Maybe first off, could you talk about the drivers of the production beat that you got for 2Q?

Right? The production beat for 2Q is primarily from the South Texas assets. The Permian came in pretty much -- or is coming in pretty much as expected. And the beats there are really kind of 3 parts to it. One is the facility constraints were relieved that we had in the third quarter and fourth quarter, and that was just the pipe diameter was too small for how much oil we were producing with all those new Austin Chalk pads. Another one, the base performance of the all the Austin Chalk wells before is better than expected. And then finally, the new wells, we're getting much better contributions production-wise from the new wells. And part of that is there's more lateral feet producing. We have assumption of how many lateral feet we'll actually produce. That's been getting better and better as we learn the Austin Chalk with our, I guess, has been about a 3-year learning curve now.

And on the midstream constraints, I think you'd previously talked about those being alleviated in the second half of the year. At this point, are those alleviated? Do you not see it being a problem going forward?

Right. So we did earlier than expected, we got the facilities in place, so that we didn't have the back pressures from limited oil gathering capacity. In the future, we'll have to do some additional investment as we move further south with the development. But for now, it's good.

Got it. And then the second question, just on the release this morning. You'll be adding a rig, I think, in October in the Midland Basin to really drive more growth in 2024. Do you want to quantify that at all? And maybe also just give us a little bit on the thought process of adding that incremental rig here.

Right. Yes, it's kind of linked to what I was saying before. So the addition of the rig is first to go onto the acquired acreage and to start developing there. It doesn't exclusively need to go there. And how much of that we run in '24, we haven't decided we haven't planned for -- budgeted for 2024 yet. So you can anticipate that there's going to be more oily growth than we had before. If we so, let's say, the first quarter and we're still running that rig, you're going to see us with 2 rigs running South Texas, 4 rigs running in the Permian Basin. So you'll see a little bit of a higher capital allocation towards the Permian, which will mean a little bit oilier growth looking forward. And then overall, it will be a few more completions in the year in each year, and that will also drive a little bit of the growth, which is really driven to getting that maximized free cash flow the next 2 to 3 years.

And then could you give us a little more color on the acquisition, particularly the one you said was not closed yet, but where you would be adding the rig? You talked about it being in the sand zones, but just any other color you've got there? What level of well control do you have as far as historical?

Right. Yes. So this is a great area and the seller hasn't allowed us to disclose much at all, not their name and nothing until we close. But the way I characterize it, and I showed you that slide with the stratigraphic column in the Permian, and I circled the Dean. And you'll see the best wells we've had in all the Midland Basin have been in the Dean. And our geoscience team integrated with the reservoir team really saw where and what factors drove good Dean performance and went scouting around for where would you say the sweet spots were for the Dean. And we really chase that down and that's really what drove -- where we decided to acquire the Dean. And there's additional intervals also. I don't want to dismiss them, but what -- the key one from a value standpoint was the Dean and we'll find out what more we can do on that acreage. So that drove us. So the intention is, of course, to have inventory replacement each year from an organic level. And this pretty much falls in that category. So we're not paying a lot for PDP. There's obviously production there, but we're not going for PDP-heavy assets.

And another one on this morning's release, you talked about cost deflation. Maybe just give us a little more color on what you're seeing. I know you took down the budget. I believe $50 million, but that also includes adding the rig in the back half of the -- or in October, what are you seeing right now on cost deflation?

Yes. So cost deflation, it's pretty straightforward. I think most of you would see this on diesel, steel, then rig services have been pretty flat, and we had anticipated some increase. So we got some of that back. We do see -- I just ran the numbers and you can use different providers, but it looked like from the peak last year, the oil rig -- oil-directed rig count dropped by 12% from the peak last year and the gas director rig count, there were 2 peaks, 1 earlier this year and 1 middle part of last year, down 19%. So obviously, with those rig counts dropping, I always say there's a 6-month rule of thumb that once you see activity drop, then you'll start seeing the costs drop. We haven't integrated any of that additional decrease, but the big ones are diesel and steel. Some people have asked, and you'd be surprised last year with about a $900-some-million capital spend, we spent $80 million on diesel. So just think about that. I remember what diesel costs are -- were last year and what they are now, you can see how much deflation there is in that. Now of course, we enjoy the high commodity prices, too.

And then just following up on that, could you remind us how contracted you are in your rigs and completion crews? Just trying to get a sense of when we could see more of that hit the budget. I mean clearly, some of it already has.

Yes. The rigs, we're currently running 5. We've not contracted the sixth yet. And those are on annual contracts, and they are feathered, so every 2.5 months, we have another rig contract expire. And at that time, we basically negotiate with a rig contract to extend the rig. We're real happy with the rigs we have. They're great performing rigs, happy with the rig contractor, and we work closely with them, because from a value standpoint, what matters is how effective they drill. On the pumping service provider, we are using the same pumping service provider, both in South Texas and the Permian Basin. And those are on a continuous basin we've used the same provider and they're more market floating, but they're not spot crews. So these are crews that have been running -- or the one crew has been running for us for 6 years now. And so that's how we'd like to operate, because that gives us the efficiency metrics that we deliver.

Have you considered E-fleets at all? We've heard a decent amount about that from some of your peers today tends to be focused on the larger caps and some of the gassy players. But any thoughts about using the e-fleet?

Yes. So we did work an E-fleet in South Texas for a while a couple of years back. And for a while there. You had to enter 3-year contracts for E-fleets, and you had to help them justify their capital spend to get them. So it made a little bit more challenging to get in the E-fleet area. Also in South Texas, we don't have any grid power grid power at our site at all, we don't need it. And so we never put capital in. So you'd have to have a generator anyway to produce the power to drive the E-fleet. So it's kind of like a Tesla with a generator being towed with it. That doesn't work as efficiently as being able to take grid power. We use dual fuel in the Permian Basin. So natural gas to diesel and that's quite efficient. So there's going to be a day when I think we'll be running E-fleets, but we're not there yet from our -- for our company.

And last one just on today's release. If we look back to 4Q and 1Q, you repurchased around $40 million in shares per quarter, you clearly stepped up here in 2Q. How should we be thinking about the buyback pace going forward?

Okay. Yes. Zach, we said right from the program inception last September that we'd be opportunistic. We didn't put a 10b5-1 in place, but we may do that in the future. But we found that it works when we lean in when we're trading down, and that was the case in the second quarter. So you're right, we went from $40 million in -- basically almost $40 million in the fourth quarter and $40 million in the first quarter to $69 million last quarter and about 2.6 million shares. So you can see us dollar cost averaging down on our purchases.

And if we go back to when you originally established the buyback program, I think the $500 million buyback was based on $60 oil with $3 gas. On the oil side, we're definitely trading above that. Gas is a little lower. But if commodity prices stay at these levels, how quickly could you potentially finish the buyback or any thoughts on what it could look like over kind of the near to medium term?

Yes. Pretty much, Zach, we're sticking to our commitment. The $500 million is by the end of fourth quarter of '24. So we're sticking to that. It's going to be opportunistic on how fast we do it. And obviously, we've got cash on the balance sheet. So there's no issue with the buybacks.

And we've got a few minutes left here. I know there's quite a few people in the room. Happy to open it up for questions if anyone has one.

Just a quick one. On the guidance raise for the year, I think it was 1 million barrels of equivalent. Does that include the production from the acquisition that you announced this morning? Or would that acquisition be little bit of extra on top of that?

No, it does. And I'd just say no, just for perspective, that's a little less than 0.2 million barrels. So it's a small contributor to it. The acquisition is 1,250 BOE per day current rate and then obviously, it declines away from there.

Can you just comment a bit more on the acquisitions you've made, both the one that you haven't disclosed the acreage and the 20,000 today. when you specify certain zones that you're focused on, does that indicate that maybe there's another operator in other zones or not? That's one question. And the other is you also sort of commented generally that you feel you're in an advantageous position with acquisitions. Is this due to your exploratory skunkworks or geographic positioning? What makes you say that?

Okay. Great. Yes, those are great questions. I don't need to repeat that. So First, let me go with the exploratory skunk work. So the way I'd say it is we've had a geoscience team that's been very effective at understanding the fundamental drivers behind unconventional resource development. And that, coupled with the massive database we have, that is from data trades and our own data, whose core data, log data, completion data. We've used machine learning to optimize completion designs. So the combination allows us to look at an area and see existing wells understand how they were completed, look at the vertical wells to see the aerial extent and like in the most recent case, we can see somebody would have assumed that there was a high water saturation and then it turns out, no, they've missed something there. So it's that sort of really detailed geotechnical work in focused areas that enable us to identify where there's a play that others are missing. And when I said like the Dean, the Middle Spraberry, that means that those are the intervals where we've attributed value that doesn't say there isn't more value from other intervals. It's just those are the ones where we have confidence that the value will be there. So they'll work it. So for example, in the Eagle Ford, we started developing that in 2009. We didn't drill our first Austin Chalk well until 2018. So it was the detailed work, the core seeing that enabled that play. And then had a success and then it turned out there was a better landing zone, and that led to really, really great top-tier well results. So that's kind of what drives the ability to find the acreage that we want to get at a grassroots level, which without a lot of development yet and have confidence in putting the money into it.

Is this the same thing that you brought Howard County in the first place?

That's exactly right. So Howard County at the time, which is what I showed that on that 1 slide, there were only 79 wells at the horizontal wells at the time. At the same time, there's a lot of vertical wells. So if you know what to look for in the vertical well, it makes a big difference. In the Austin Chalk, you have to know, which log to look at that tells you which is the interval to land in, and that's how we identify, so it's more of a traditional, how does a E&P company grow value, and this is the way to do it. So yes, a couple of questions over here.

Herb, congrats on running a great business. One reason I really like SM is you're the most scientifically oriented SMID cap on the planet and being an engineer, I find that very pleasing. So 1 comment from the Midland and then a question for the Austin Chalk. Given the depth of burial and pressure and temperature, the Wolfcamp D has some shockingly early results with higher oil cuts than at least I would have anticipated. I think that's the next big play out in the Permian. I know it comes at higher costs, but there's going to be a treasure trove down there. We love your comments on that. And then the Austin Chalk, congratulations on putting together a lot of value for your shareholders. I think where the rubber meets the road is on fully bounded wells in their performance versus single wells or single bounded wells. So how much data do you have to get confidence on the repeatability of that play?

Okay. So let me go to the Austin Chalk. We've got -- Mark, you probably saw the initial program was just a couple of wells unbounded. Then we started stretching across the -- get the geographic extent that enabled us to get to the total account. And then we started doing multiple lots of different spacings. And typically, there were 3 wells with spacing in the -- then we started doing some in thick Austin Chalk 500 feet thick, 2 different landing zones in the Austin Chalk and doing spacing tests on those. So the confidence has gone, as you're aware, we've got 75 pass-through IP30, and we got more than 82 already. So we've done numerous tests, including staggering with the Eagle Ford. So that top end just continues to improve. Then we ran in the facility bottleneck, because of how much oil we are producing. So if you have 2 big pads coming on with a lot of oil production and your -- gatherer, your third-party gatherer systems designed for dry gas, you got to start doing remedial investment, and that's what we've been doing. On the Wolfcamp D, you're right, there's been a lot of offset activity of ours and our own, and its a more clay-rich interval. It's got a great frac barrier. So it's independent development. And we saw that, hey, there's a better completion design here that we can try given the clay-rich nature, higher pressure. It's a little bit gassier, but still oily. And we do see it as a great play. And it's not one you have to go to immediately with the co-development. So you can say, yes, it's the best well we can drill or, hey, if it's in the middle of the pack, we don't need to drill it today. So that's what we're going to be figuring out that where it fits in our stack. Yes. You bet. Thanks, Mark.

On the 9,000 acres in new play, is that -- since you're not telling us where it is, does that imply you're still actively trying to add to that position? And if so, what would be a full position for you in that area?

Okay. So all I'll say on that one is, yes, we're not saying more, because we still see some running room on getting more acreage and once we do and we get a couple of wells into it, we'll talk about it in more detail. So that's kind of how we're approaching it.

Is there a maximum potential you could see that position reaching?

I think then we'll run into where we can't lease anymore, because we'll run into where it's already owned.

Okay. And then lastly, just when you say $50 a barrel is your breakeven? How do you define breakeven? Is that PV-10, PV-15?

Yes. The way we do it is a little bit different than Enverus, but it just happens to work out the same at $50 a barrel. So it is the flat oil price required to get a 10% rate of return. So PV-10 breakeven, and we do that $2.50 gas. So at $50 oil, it just happens to be the 20:1 that Enverus would use in their breakevens. And I think that's where you'll see we really stand out. We do see a glitch on some people. They'll see our heavier costs in the Permian, which are like $900 per foot for a well, compared to some others, but they're not adjusting the type curve to what our type curves we achieve with those. So they'll apply somebody else's type curve with our cost and conclude it's a high breakeven well. They have to correct the type curve to the type curve we have. Also, we've spaced our wells in a very systematic way on each drilling spacing unit. So predrill, we will test what is the rate of return going to be on the last well we put in the DSU. So let's say there's 16 wells in DSU, we will say put a 17th well in there instead of 16, what's the rate of return on that incremental, call it, $9 million. And that's got to exceed a hurdle of 25%. Then we'll do the next, okay, what's the 18th well? Does it still exceed? That's how we define how many wells we put in a DSU between the vertical spacing of the co-development and the horizontal spacing. So we really make sure that we don't overcapitalize a DSU. You could put 40 wells into the DSU and find that your last 5 wells are new nothing. So that's the system we use.

Thanks, Herb. We're running up at the end of our time here. Thank you and the SM team for being a participant here at our conference.

Okay. Thanks. Thanks, Zach. Thanks for asking the questions.