SM Energy Company (SM) Earnings Call Transcript & Summary

Good morning, and welcome to our ninth Annual JPMorgan Energy Conference. I'm Zach Parham from the E&P research team here at JPMorgan. Up next, we have SM Energy and E&P focused on developing assets in the Midland Basin and in the South Texas Austin Chalk. We're very excited to be hosting SM's President and CEO, Herb Vogel. Herb was appointed as CEO in November of 2020, having previously served as COO since 2019 and SVP of Ops since 2014. Prior to SM, Herb had a lengthy career with BP. Herb, I'll turn it over to you for a brief presentation, and then we'll have a Q&A.

Thanks, Zach, and thank you, everyone, for being here, and thank you to JPMorgan for inviting us to present today. I'm excited to just go over really what differentiates SM Energy from -- and why it's attractive investment. I'm going to start, of course, with some disclaimers. I've got forward-looking statements you can look if you're listening to this on our slide deck, Slide 2. Otherwise, I'm just going to go ahead here and show you just really what our strategy is, we're premier operator of top-tier assets. And what does that really mean? It really means we're focused on operating extremely well and effectively in -- capital efficient and cost effectively and then top-tier assets really are positioning our portfolio with some of the best low breakeven cost assets that we can get our hands on. We did a lot of transactions over the past decade to hone in on the best assets that we can. So premier operators are about capital efficiency. There's also an ESG component of that, which we put at the bottom of leader, sustainability and stewardship, and I'll go over that a little bit more. And then the top tier assets, it's high-quality inventory, and there's quite a bit of it with a long runway. So let me go why invest in us. We really like to position ourselves with differential technical capabilities. When I look at my team that operates with me, there's no one with less than 9 years experience in my direct reports. And then a lot of the capability has been built in unconventional resource development since 2008. And that multiple iterations through the different improvements in unconventional resource development really allows us to differentially perform. We've got that high-quality 10-plus year inventory and that was at the start of the year with a 65% average projected return, and that's a $70 barrel price. What people haven't recognized so much is how much we've been able to do organically and that's a potential of nearly 40,000 net acres added just in the past year. And you'd say, well, 40,000 acres, how much is that? Well, that's a 15% increase on where we were before. So that just tells you what we're doing to replace the wells we drill each year with new opportunities. The return of capital is quite attractive. I'll cover more of that. And we have growth in free cash flow, if you just keep commodity prices where they are. And then our balance sheet is quite strong with 0.6x leverage. I think I'm going to quote Zach here with the chat we had this last week, and it's really -- we have a technical staff. We didn't go through down cycles and really knock down our capability. This really about geoscience, engineering and data analytics staff that we've really built over time. And that I'll show you how that leads to better well results, which leads to more free cash flow from the assets we have. This one, I'm not going to spend a lot of time on, but in the first -- this is our first quarter results. We're really focused on operational execution. When we tell you what our guidance is, you can really count on that being delivered unless there's some weather event or something extraordinary that call it a black swan. And we're constantly trying new technology. So we have to report to our Board each year all the technologies we tried and then kind of a green, yellow and red. Red, hey, didn't do much for us. A yellow means, hey, we need to do more work and green, this is a technology we're going to implement, and this is a lot of like well diagnostics about how wells are performing in the completion side in particular. We have focused our return of capital program since September of 2022 on share repurchases and fixed dividends. We increased our fixed dividend from September 2022. We increased it in the first quarter of this year. We have a $500 million commitment to buybacks. And through the first quarter, we had already done $320 million of that, $180 million remaining. And then we are constantly looking at ways we can expand the portfolio with that top-tier asset in mind to make sure we get differential returns. And you can see some of the specifics there, and I'll go into a bit more detail there. Here, just showing how our adjusted free cash flow, how much we've returned to shareholders, and in the first quarter, we returned about 79% of free cash flow. So that -- there's the total return to stockholders since September of 2022 is $429 million, and that includes the dividends and the repurchases. So we're very mindful of what our shareholders want, and we're focused on delivering those, and we want to grow those over time. Balance sheet, very strong. You can see we've got some maturities up in 2025 with a really good coupon. So we've got quite a bit of cash on the balance sheet of over $500 million as of the end of the first quarter. And obviously, we'll take out that 2025 note when appropriate, but the cash is earning almost the same as the coupon rate these days. So we've got flexibility. Here's where I'm going to get into the well results. So when you see -- you'll see that when you compare our wells to offset operators, that our wells are quite a bit stronger. And you may say, Well, is that just a coincidence that the rock or something else? And it's really that something else. It's the technical analysis and the data that goes into our designs that leads to that. Also, some people say, well, how is Permian Basin compared to South Texas. And here, we're looking at on the left, Howard County versus peers. And on the right, we're looking at Austin Chalk, the Western acreage, the oilier acreage, and you can see that after 20 months, it's almost the identical amount of oil produced. This is MBO per 10,000 foot of lateral. And you can see that they're comparable levels, which a lot of people are surprised about. I've shown several times also the repeatability, the Austin Chalk is almost at Permian level, meaning the P10/90 of the wells in the Austin Chalk are close to where they are in the Permian. So that's another real highlight. And why is it we can do that? And this is the aspect of being technically efficient. This may seem like an innocuous thing. But for a data analyst, they'd really appreciate what we're doing here. So we have from data trades in our own wells over 2,300 wells in a database where we have everything about the wells. How they were drilled? What they were completed with every single detail? That would be stage lengths, cluster, designs, pounds of sand per foot and pounds of barrels of fluid per foot. And we have that model and then this is a multivariant analysis where we vary all of these different parameters. In this case, there's 25,000 here prior to well design prior to actually implementing. And you can see where our Midland Basin average is the orange and in the blue is where our 2024 base designs are of our wells. And so you see the completions capital on the X-axis. So we'll spend more on the wells, but we'll get a lot more value out of the wells we drill. And on top of that, we designed the spacing vertical and laterally to really optimize that. So that's how we get the better wells. We spend some more capital, but it's highly, highly a high return on that incremental capital. So going from the orange to the blue might be $1 million to $1.5 million, but you're going to get a return of 100% to 200% in general on that investment. And that's what we really focus on, getting the value for our shareholders, and that leads those great well results, which leads to the free cash flow that we're able to generate. So we're also driving efficiencies constantly on the cost side. We look over the lease line at anything anybody else is doing, and we're constantly looking at how can we get our operations more efficient and more cost-effective in the way of drilling where -- if you looked at Enverus data, we are one of the fastest drillers when you especially normalize to the base areas of the Midland Basin, not looking at new intervals, and we've increased that again at another 10% in the Midland Basin. South Texas is about 20% improvement. As we get faster and faster, we drill more awesome Chalk wells. On the completion side on the right, and this is Slide 10, you see about an 85% increase from 2022 to where we are in first quarter '24. You say, "Well, how did you do that?" Well, that's really simul-fracing. And by having a very efficient simul-frac, that means you got to have a lot of sand, right? You got to have a lot of water available for your frac operations, but you can just execute really fast. And a lot of our outperformance has been from executing faster than expected, partly due to simul-frac. In South Texas, that improvement's really improved logistics continually, making sure sand is available when we get there, but that's a zipper frac fleet just because of the scale of the operation. So we're constantly driving cost down and that -- and if you look from 2023 to 2024, we went from around $900 per foot, down to $800 to $820 per foot. And we said at end of the first quarter, we're at the low end of that. Looking here, this is the new information today. Zach, sorry, there's no other announcement, just simply going over some more wells. We added 3 wells to what we had before. You'll see people haven't recognized that in the Austin Chalk, we're directly over old Eagle Ford wells, and we're not interfering with the Eagle Ford wells and the Eagle Ford wells are not interfering. There's enough of a frac barrier there. And we're spacing the wells that in this area, 625 feet if you're just looking from the top, just the Austin Chalk wells, 1,250 feet within the different intervals, and we've optimized the landing zones that we spent some time over the last 3 years optimizing exactly where we drill those. And that's leading to the results you see at the bottom. This area kind of in the middle of the Western acreage, it's 48 -- 47% to 52% oil and 70% to 80% liquids. So this is quite high, high -- these are really high return wells. And then we're drilling, you can see on the Briscoe B area that was limited by some of the lease geometry. So we had 6,847 foot laterals there, which is relatively short. But in the C2 area, it was 13,600 foot. So it's really driven by lease geometry, how long we go. Obviously, we'd like to go longer. But as an analyst pointed out this morning, after seeing the slide deck that the productivity per foot on those Briscoe B wells is extremely high. And that helps the economics quite a bit when per foot and the capital will be more with a shorter lateral. So going over here, this is really about inventory expansion. We've -- this is the slide we showed at the end of first quarter, and we acquired the Klondike. We announced that last year at this conference. So far, I'm pleased to say we have 1 pad of 4 wells already drilled, completed and drilled out, and we'll be turning that online by early July. And then we drilled a second pad, and we're on another pad -- preparing another pad for 2 more wells. So we should have 8 by year-end in the Klondike area. We're not talking about that Sweetie Peck area acquisition. We released the location of acreage, but some analysts have called it our stealth acreage. We're going to talk more about that once we've got some wells down and can talk about how those wells do. And then earlier this year, we announced that we entered into a drill to [ earn ] arrangement in the Austin Chalk. And as you can see, that's a very oily area. We're quite optimistic on how that's going. We already have drilled 3 wells in that area. I believe they're waiting on completion now. So this is really about replacing our core inventory without stretching anything. And it's relatively easy for us to do. And then bottom line, the inventory we have, it's really high-quality inventory. It's very certain that 80% categorized is 3P by the categories that SPW and others -- SPE and reserve auditors would look at. That's quite high quality. And at the start of the year, we had 10-plus years and then we'll see how much we're able to add this year. At Klondike, delineation efforts are underway. We'll talk more about stealth when we've got results to share. And then we organically increased our Austin Chalk acreage by about 16%. So with that, let me just go quickly on CDP. So we really focus on low greenhouse gas emissions, low recordable incident rate and on low spills, and that's led us -- engaging with our suppliers also, and that has led us to some really high ratings. Our Board is all over this. We just took them to South Texas. They're involved in everything to make sure that we are operating at basically the top quartile of the industry. And with that, I'm just going to put a few quotes up there talking about how SM performs overall. And I'll just say it's -- the team is super solid, have been doing their jobs for a long time and do it really well on basically, call it, the third, fourth, fifth generation completion designs that we're implementing now. With that, Zach, that's all I was going to do for prepared remarks.

Sure. I heard you talked a lot about the technical team there and mentioned the acreage you've added in Dawson and Crane County for exploration. Can you talk a little bit about your exploration program and how you decide where to lease new acreage?

So I would say we have a quite large exploration team that is really a combination of engineers and geoscientists and data analysts that have aggregated a tremendous amount of information on most basins in the U.S. Many of you who have been following us know that we were in the Bakken, and we exited at a good time. We exited the Powder River Basin, we exited the Haynesville, exited Arkoma, Anadarko basins at good times where we saw that the acreage was not at the top tier of the Permian and South Texas. So what our teams do is we've got an enormous amount of data, that means well logs across the entire Lower 48 and seismic data across a lot of the Lower 48, where we have licenses whenever we need to look at something. And then we have a lot of data. So we will look and identify, for example, the Austin Chalk, we can see what characteristics there are in the log responses that tell us that a play is going to be very productive and commercial, and we have that mapped throughout the Austin Chalk play, likewise, for a lot of the Permian plays and other plays across the country. When there's acreage that comes available in those areas, and particularly if an operator is not aware of something in an interval, that's when we're really interested in it and where we can potentially get differential returns compared to an existing operator. So that Dean example, so Klondike, that area to the north in Dawson County, we really -- we had really, really good Dean wells. In fact, our best wells in the Permian Basin, we're in the Dean sandstone and it's -- we saw that there was a migrated oil play. And when the acreage came available, we hit it hard and got it at a really good price. Subsequent to that, when we talked about that, then the acreage value went up quite a bit and a couple of more packages sold at much higher prices than we paid. And that's really just being on top of technical details of each of the plays. That's long-winded answer for that one, Zach.

You mentioned in Klondike, you're going to have your first 4-well pad turned in line in early July. What's the timing on you updating the market on those wells? And then I think this year, you've talked about 8 or 9 wells in Klondike, when will that second wave of wells come online?

Okay. Yes, Zach. So we -- the first 4 wells, and they are long laterals, 2 going North, 2 going South, and they should be drilled out here. And so they'll be on in July. Typically, we don't report well results until we get their IP30. So it would be a surprise to me if we could actually report them during the second quarter call, which is right at the beginning of August. But we'll report them as soon as we can. And I'm quite optimistic just because of how much well control we have vertically and then offset wells in the area from operators. There's 2 more that have been drilled and another 2 of the pads are being prepared right now. So we know we'll have 8 on definitely by year-end. So the 4 that will be coming on here in July and then the other 4, I don't know which -- whether it'd probably be in the fourth quarter for those.

Can you talk a little bit about what you're seeing on cost deflation currently? I think coming into the year, you all talked about 10% year-over-year cost declines. What are you seeing now? What are your expectations for the back half of the year?

Yes, exactly. We haven't really publicly gone into what we're seeing since the first quarter, but we were on track with the 10% that we went into the year with. And we felt comfortable that in the first quarter that we actually dropped our capital budget by 2% for the same activity level. So we're feeling confident in that sort of deflation. How it looks going forward? It's really a matter of what's the activity level, if gas prices have bounced back a little bit, if the gas basins start to up their activity, you could see some cost pressure. If activities stay down low and rig counts continue to drop, and obviously, it go in the opposite direction. Every year, we do an update at midyear looking at what the next 2 quarters are going to do, we reforecast and we really forecast our free cash flow out 2 to 3 years. And we look from there and would make any update and that we'd report anything there in the third -- second quarter call.

Also I wanted to ask on the cash return program. SM started a buyback program in 3Q '22 and has consistently bought back stocks each quarter since. So there's been some variability. Can you talk about your expectations for the buyback for the remainder of the year and maybe what you would need to see to get more aggressive with buyback?

Yes. So a lot of you are aware that during the first quarter, with our window and we're allowed to buy back shares is fairly limited because of the announcement dates. So typically, first quarter is going to be lower. We have said that we plan to do roughly for people modeling us is ratably. So for the last 3 quarters of the year, we intend to hit our $500 million buyback target, have $180 million left as of March 31st. So model it at $60 million a quarter. Since we're opportunistic, it moves around a little bit on how many shares we get each quarter, but that's reasonable assumption. And then going forward, we intend to improve our return of capital to shareholders, and we'll decide and we'll go back to the Board on where we are in the third and fourth quarter and look at what we might do in the way of fixed dividends and potential extension of the buyback, but we don't have anything committed at this time, nothing planned at this time. But that would be a natural discussion, and I know a lot of stockholders have asked through just March 31st, we'd already bought back I believe 9% -- or 9 million shares. So 7% of those float.

I wanted to ask one more before I open it up to the floor for questions. Can you just talk about your views on industry consolidation. We've obviously seen a ton in the Permian and maybe when you think about consolidation, do you just look in your operational areas? Or would you look outside of those geographic areas?

Yes. So on the consolidation, so first, for M&A, we're a believer in consolidation. You can see the benefits of economies of scale. But you have to be careful, too. You want to make sure it really makes sense. And so we've got 4 criteria we use when we screen these and when we look and if there's any discussions at all, it's really, first, what's the asset quality. So we don't -- we've got such a resilient portfolio. We don't want to get together with somebody where it really degrades what you can do for free cash flow generation with your capital and your capital efficiency. So we think that would harm our stockholders and may outweigh the economies of scale. The next one is from a debt standpoint, we don't want to put ourselves at 3x, 4x levered when the shareholders appreciate lower leverage. So we really watch what leverage level is appropriate. It's easy to say 1.5 is okay, that sort of level. And then it's got to be accretive. And whether you use EBITDAX or free cash flow, it obviously got to make sense for our shareholders from that perspective. And then final one is the industrial logic. And the industrial logic, you can be pretty broad about this, is whether you can bring the technical capability to do much better on wells in an area. And we do look at other basins, we've been in other basins. And if there's an opportunity that really looks like it makes sense, we would consider it. It's easier just to add acreage like we have offsetting. It's just very logical. But we consider other things if we can show that there's a way to get returns or that there's something missed by others.

We've got a few minutes left. I did want to open it up to the floor for any questions.

Yes, on simul-frac, I was wondering if you touched on it a little bit earlier, talking about the improvements you're seeing on completion per foot. But wondering if you can comment on what the current split of simul-frac is for both Austin Chalk and Midland and then for like 2024? And then how does that compare to 2023 to give us a sense on how that's changed?

Okay. Great question. It's about simul-frac. So first of all, we have one simul-frac crew running in the Permian right now, and we have one zipper frac crew running in the Permian and then South Texas is all zipper frac. And when you're running simul-frac operations, you have to have the supply chain for a lot of sand and a lot of water in a hurry, and that's easy for us to do in the Permian. You also want to have larger pads or pads near each other to simul-frac efficiently. So it doesn't work like if you go to a real peripheral area where you have a 2-well pad, you're not going to be able to simul-frac it. So the more we can put the large number of wells on a few patents, that makes it more amenable to simul-fracing. And there, you can execute very fast. Some of the -- we'll hit some days where we can be active for over 20 hours a day, targeting 23 hours a day of pumping, which leads to great efficiencies. And we've done as high as well over 20 stages per day and typically with a zipper frac here around 8 stages per day. So on a regular ongoing basis, we assume close to 16. So when you're operating at that rate, you get things done really fast. So you'll plow through some capital in a hurry, but you got to have everything lined out to do it, but then it's really both cost and schedule efficient. So that's the way we look at it. South Texas, it would be more difficult to implement a simul-frac program because we're at this stage really completing 30 to 40 wells a year. And that's really difficult to put a simul-frac unless it's just part year. And then it's harder to get the rates you want from the pumping service providers if you're just basically picking up a spot simul-frac through. So that's just -- there's a lot of logistical considerations there.

Yes, Mark?

I love your position, 100% Texas, postulated in 100 years when the last rig gets laid down, it will be in Utah or Texas due to favorable regulatory environments and I'll pick Texas. I love the Midland because of the stack pay and you've shown Dean is a new example of that. How about the deeper targets? We're hearing about the Wolfcamp D, higher oil cut than temperature plots would suggest, and you got the Barnett Woodford. Are you taking a look at that as well? Or are you letting others play that game at this point in time and saving it for the future?

So Mark, so we've pretty much delineated the Wolfcamp D across our position, and we've kind of got it timed out on when we will go access the Dean and we've got in the -- Wolfcamp D, and we're really looking at what spacing to use and we've tested the spacing in the Wolfcamp D. So we've got it pretty much lined out on the Wolfcamp D. The Woodford Barnett, we've seen a lot of offset activity. We see some of the wells are actually really quite good. They're a little bit gassier, a little bit deeper. So that's obviously something that would be of interest to us and our geoscience team would be all over it. There's enough data out there now. I think even Enverus reports the data. I think it's a large number out there. So it's obviously something that we'd be looking at.

Have you tested those deeper zones at all that -- I know you said you tested the Wolfcamp D, but if you tested the Barnett?

The Woodford Barnett is one that would be on our to-do list.

I'll squeeze one more in. Can you just talk a little bit about how you think about future capital allocation between South Texas and the Midland and how commodity prices can impact that?

Yes. I think, just in short, you look at us and you say, just assume 50-50 unless there's a reason to do otherwise. And what are the reasons to do otherwise is if we have a new acreage like Klondike, so we shifted some capital over, so we could do Klondike. So that 8 wells and they're long laterals. So -- and you can do the math at $800 per foot. That shift caused a shift. Commodity prices, if it's high oil, low gas price, it means you go a little bit more towards the Permian. If it's a high gas price, you'd shift a lot over to South Texas. So -- and you'll see us be opportunistic. So in 2022, when gas prices were 7 to 9, we shifted more over to South Texas, and it was closer to 50-50. So we like having that ability to adjust the portfolio. You don't typically respond to short-term things in commodity prices. 2022 was unique because we had DUCs that were in the gas area, and so we could pop them and we got 6-month payouts on those. So we'll be opportunistic like that. I like having that portfolio ability. Also in the Permian, there's restrictions on the gas takeaway until pipelines come on. So Waha basis always can be an issue. So we watch that. But we're well positioned for takeaway. We're using 5 different offtakers who basically can take the gas out of the basin.

We're approaching the end of our time here. Herb, thanks to you and the SM team for being here at the conference with us.

Okay. Thanks a lot, Zach. Appreciate it. Thank you.