JP Morgan 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. I'm gonna cover quite a bit today, but I'm gonna try and do it in 10 or 15 minutes and really hit the high points. We issued a press release this morning. I'm sure all of you have eagerly looked at that and anticipated that. Let me just start with the usual disclaimers, that I'm gonna be making some forward-looking statements, and I'll just direct you to that slide, which is on our website, too. The breaking news.
I'm gonna start just with the operational metrics. The big news here is we've had quite a bit of success in the Austin Chalk and Midland Basin. We're gonna 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. 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 that I'm gonna 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 will be 43%-44%, and then our LOE is also down $0.50 per BOE. All super positive there. Next is really the repurchases. 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, we basically bought 2.6 million shares, and that's about 2.2% of shares outstanding. Our yield to market capitalization over the last 9 months, if you include the dividend payments of about $55 million, is about 7%. 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. We've had deflation both in LOE and capital. A lot of people have been following what was going on in South Texas, where our oil takeaway capacity or really it's our oil gathering capacity, was limited because of how oily our wells are in the Austin Chalk. The build-out was completed early in the second quarter, and we had announced it would be by the end of the second quarter. 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 and is $93 and a half million dollars.
The rest is an additional 3,000 acres on top of the 6,000 we announced. We haven't disclosed where that is yet, other than it's in the Midland Basin. We'll be getting more detail out on that when it's appropriate to do so. That's the breaking news. 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. The more return of capital is obviously 2Q. We're thinking about this longer term. What do we do for more inventory and more return of capital over the long haul?
That's where we focus things on. By doing the acquisitions, that allows for inventory replacement with high-quality inventory. It doesn't mean anything if you just add acres for the sake of acres. We're really adding on break even below $50 barrel type of inventory, so that each year we can show you a slide deck and it says, "10-13 years of remaining inventory." I want to be able to say that next year, the following year, and the following year, or more. 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.
I was talking to some of the investors earlier today, and, we kind of got to the conclusion we're kind of a unicorn midcap 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 the capital to shareholders. 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 on capital. 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 on the metrics that matter, you'll see that we do really well. I'm just gonna touch on those real quickly because some of the slides we've had out there for quite a while, on the ESG side, we also benchmark extremely well, especially for an oily operator. 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. In the Midland Basin, our break-even costs, our break-even oil price is among the best regional peers altogether, that's the best measure you can have.
Somebody looks at it and says, "Well, your costs are higher," the reason the costs are higher is because we've got a completion design that gives us higher value wells. The returns we're generating are what we really focus on. You'll see I'll take a $900 per foot well over a $700 per foot well if I'm going to get a much higher EUR and much higher return. That's the way we look at it, and I've got one 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 two 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. When somebody talks about child well issues, we don't have those, and those are already baked in to our forecasts because it's integrated in the design. Because every DSU is custom designed based on the geomechanics of the area, and the returns we expect at certain commodity prices. That's the point I want to make. I circled the Dean, and that's because go into this next slide. You can see we've got 91,000 net acres.
You used to see 82,000 net acres in the Permian Basin before. We added 9,000 acres in the undisclosed location, then the other 20,000 acres, which are pending close. We announced that the play there is different than your normal stacked mudrock pay play. What we're doing there is targeting the Dean Sand and the Middle Spraberry sand. 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. That's the real plus. That's what we just announced today, and you can see, well, 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, that was a combination of things. Again, here, we've got a lot of inventory in the Austin Chalk, you can see how it stacks up with low breakevens. This is Enverus analysis. That's their most recent update. This is the quote. We love to hear this high-stake unicorn comment I made that we've got the deepest and highest quality well inventory among the mid caps. 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 was a lot of skepticism about it. Since that time, since 2016, when we got in, now at 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 the high oil content in the area led to really economic wells. We got as of year-end in 2021, reported 12 years of inventory, that we want to keep hanging in there at that level or better. Austin Chalk, same sort of story. No one was drilling the Austin Chalk. It didn't really work.
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. We estimated about 400 locations. We've already drilled 75 that have passed their IP30 today. We've got a lot of data, and we continue to optimize, and you're seeing that in 1 Q and 2 Q productivity. This is the slide that Jennifer, our VP of IR, thinks I talk about too much, probably. 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.
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. 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. This is done with machine learning and simulation also. With that, I'll just say quality inventory. Couple updates on this slide. I want to keep that 10-13 or more in front of you, and we're gonna be keep doing that to show that we're a sustainable company.
We wanna 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 2-3 years. That growth rate is really back solved to maximize the free cash flow, which would allow us to get that return on capital. You can see here really high-quality inventory. It's quite certain. We added this upside. Some people say, "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 4-5 years to that inventory number if you went to certain DSUs and just decreased the spacing to around 1,100 feet per zone, and that would do...
add that much inventory." 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. Then again, we do run our inventory at $65 barrel oil, just so you know. Next, I'm not gonna go to the balance sheet, but obviously we're in great shape on the balance sheet. Finally, on ESG, we put in our 2022 numbers. Great numbers again on the 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 A minus. Routine flaring, 0%. Non-routine flaring, 0.4%. Great numbers there. With that, I think the point I'm trying to make is we're sustainable.
We're gonna keep being able to do that return of capital, and we'll have a strong balance sheet, and then we're gonna 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. 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 three 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 all the Austin Chalk wells before is better than expected. Finally, the new wells, we're getting much better contributions production-wise from the new wells. Part of that is there's more lateral feet producing. We have assumption on how many lateral feet will actually produce.
That's been getting better and better as we learn the Austin Chalk with our, I guess, about a three-year learning curve now.
On the midstream constraints, I think you'd previously talked about those being alleviated in the second half of the year. You know, at this point, are those alleviated? Do you not see it being a problem going forward?
Right. 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. 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. You know, do you wanna quantify that at all? Maybe also just give us a little bit on the thought process of adding that incremental rig here?
Right. Yeah. That kind of links to what I was saying before. 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. How much of that we run in 2024, we haven't decided. We haven't budgeted for 2024 yet. 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 gonna see us with 2 rigs running in South Texas, 4 rigs running in the Permian Basin. You'll see a little bit of a higher capital allocation towards the Permian, which will mean a little bit oilier growth as looking forward.
Overall, it'll be a few more completions in the year, each year, that will also drive a little bit of the growth, which is really driven to getting that maximized free cash flow the next 2-3 years.
Thanks. Then could you give us a little more color on the acquisition, you know, particularly the one you said was not closed yet, but where you'll be adding the rig? You know, you talked about it being in the sand zones, but just any other color you've got there, you know, what level of, you know, well control do you have, as far as historical?
Right. Yeah. This is a great area, and the seller hasn't allowed us to disclose much at all, not their name and nothing, because until we close. The way I characterize this, 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. 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 chased that down, and that's really what drove where we decided to acquire the Dean. There's additional intervals also.
I don't wanna dismiss them. What the key one from a value standpoint was the Dean, and we'll find out what more we can do on that acreage. That drove us. The intention is, of course, to have inventory replacement each year from an organic level, and this pretty much falls in that category. We're not paying a lot for PDP. You know, there's obviously production there, but we're not going for PDP-heavy assets.
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 year, in October. You know, what are you seeing right now on cost deflation?
Cost deflation, it's pretty straightforward. I think most of you would see this on diesel, steel, rig services have been pretty flat, we had anticipated some increase, we got some of that back. We do see. I just ran the numbers, you can use different providers, it looked like from the peak last year, the oil rig, oil-directed rig count dropped by 12% from the peak last year, the gas-directed rig count, there were two peaks, one earlier this year and one middle part of last year, down 19%. Obviously, with those rig counts dropping, I would say there's a six-month rule of thumb, that once you see activity drop, you'll start seeing the costs drop.
We haven't integrated any of that additional decrease. The big ones are diesel and steel. Some people have asked, and you'd be surprised, you know, last year, with about a 900 some million dollar capital spend, we spent $80 million on diesel. Just think about that. If you remember what diesel costs are, were last year and what they are now, you can see how much deflation there is in that. Of course, we enjoyed the high commodity prices, too, but.
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.
Right.
I mean, clearly, some of it already has.
The rigs, we're currently running five. We've not contracted the sixth yet, and those are on annual contracts, and they are feathered. Every two and a half months, we have another rig contract expire, and at that time, we basically negotiate with rig contractor 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 using the same pumping service provider, both in South Texas and the Permian Basin, and those are on a continuous basis. We've used the same provider, and they're more market floating, but they're not spot crews. These are crews that have been running...
The one crew's been running it for us for six years now, and that's how we like to operate, 'cause 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. You know, tends to be focused on the larger caps and some of the gassy players, but any thoughts about using an e-fleet?
Yeah. We did work on E-fleet in South Texas for a while, a couple years back. For a while there, you had to enter three-year contracts for E-fleets, and you had to help them justify their capital spend to get them. It made it a little bit more challenging to get in the E-fleet area. Also, in South Texas, we don't have any grid power at our sites at all. We don't need it, we never put capital in. You'd have to have a generator anyway to produce the power to drive the E-fleet. It's kinda like a Tesla with a generator being towed with it. You know, that doesn't work as efficiently as being able to take grid power.
We use dual fuel in the Permian Basin, so natural gas, diesel, and that's quite efficient. There's gonna be a day when I think we'll be running e-fleets, but we're not there yet for our company.
Last one, just on today's release. You know, if we look back to 4Q and 1Q, you've repurchased around $40 million in shares per quarter. You've clearly stepped up here in 2Q. You know, how should we be thinking about the buyback pace going forward?
Okay. Yeah, Zach, you know, we said right from the program inception last September, that we'd be opportunistic. We didn't put a 10b5-1 in place, and 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. You're right, we went from $40 million and basically almost $40 million in the fourth quarter, and $40 million in the first quarter, to $69 million last quarter, and bought 2.6 million shares. You can see us dollar cost averaging down on our purchases.
If we go back to when you originally established the buyback program, I think the $500 million buyback was based on $60 oil and $3 gas. You know, on the oil side, we're definitely trading above that. Gas is a little lower, but, you know, if commodity prices stay at these levels, you know, 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?
Yeah. pretty much, Zach, we're sticking to our commitment. You know, the $500 million is by the end of fourth quarter of 2024. We're sticking to that. It's gonna be opportunistic, on how fast we do it. Obviously, we've got cash on the balance sheet. There's no issue with the buybacks.
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.
Thanks. 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 the acquisition be a little bit of extra on top of that?
No, it does, just so you know, just for perspective, that's a little less than 0.2 million barrels, it's a small contributor to it. The acquisition is 1,250 BOE per day, current rate, obviously, it declines away from there.
he's got one.
Yeah. Can you just comment a bit more on the acquisitions you've made? You know, 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 on other zones or not? That's one question. 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 skunk works or geographic positioning? What makes you say that?
Great. Those are great questions. I don't need to repeat that. You're good? First, let me go with the exploratory skunk works. 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, 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 the completion designs. 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 some...
There was a high water saturation, and then it turns out, no, they've missed something there. 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. When I said, like, the Dean and the Millsap, 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 that where we have confidence that the value will be there, so they'll work it. For example, in the Eagle Ford, we started developing that in 2009. We didn't drill our first Austin Chalk well until 2018. It was the detailed work, the core, seeing that enabled that play.
We had a success, and then it turned out there was a better landing zone, and that led to really, really great, you know, top-tier well results. 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.
This is the same thing that you know, brought in in Howard County in the first place?
That's exactly right. Howard County, at the time, which is what I showed that on that one slide, there were only 79 wells, horizontal wells at the time. At the same time, there's a lot of vertical wells, 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 from... It's a more traditional how does a E&P company grow value? This is the way to do it. Yeah, a couple questions over here.
Excuse me.
Herb, congrats on running a great business. one reason I really like SM is you're the most scientifically oriented mid cap on the planet. being an engineer, I find that very pleasing. one comment from the Midland, 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've anticipated. I think that's the next big play out in the Permian. I know it comes at higher cost, but there's gonna be a treasure trove down there. Would love your comments on that. then the Austin Chalk, congratulations on putting together a lot of value for your shareholders.
Right.
I think where the rubber meets the road is on fully bounded wells and their performance versus single wells or single-bounded wells. How much data do you have to get confidence on the repeatability of that play?
Okay. Let me go to the Austin Chalk. We got Mark, you probably saw, you know, the initial program was just a couple wells, unbounded. We started stretching get the geographic extent.
Yeah.
that enabled us to get to the total count. we started doing multiple pilots of different spacings, and typically there were three wells with spacing. In the middle, we started doing some in thick Austin Chalk, 500 feet thick, two different landing zones in the Austin Chalk, and doing spacing tests on those. The confidence has gone. As you're aware, we've got 75 pads that are IP30, and we've got more than 82 already. we've done numerous tests, including staggering with the Eagle Ford. That confidence just continues to improve. we ran into the facility bottleneck because of how much oil we were producing.
If you have two big pads coming on with a lot of oil production and your gatherers, your third-party gatherer system, is designed for dry gas, you've 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 so a clay, a more clay-rich interval. It's got a great frack barrier, so it's independent development. We, 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. We do see it as a, as a great play, and it's not one you have to go to immediately with the co-development.
You can say, "Yeah, it's the best well we can drill," or, "Hey, it fits in the middle of the pack. We don't need to drill it today." That's what we're gonna be figuring out, the where it fits in our stack.
Thank you.
Yeah, you bet. Thanks, Mark.
On the 9,000 acres. Sorry. Yeah. On the 9,000 acres in the 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? If so, what would be a full position for you in, in that area?
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. Once we do, and we get a couple wells into it, we'll talk about it in more detail. That's kind of how we're approaching it.
Is there a maximum potential you can see that position reaching?
I think then we'll run into where we can't lease anymore because we'll run into what's already owned.
Okay. Lastly, just when you say $50 a barrel is your breakeven, how do you define breakeven? Is that PV10? PV15?
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. It is the flat oil price required to get a 10% rate of return, so PV10 breakeven, and we do it at $2.50 gas. At $50 oil, it just happens to be the 20 to 1 that Enverus would use in their breakevens. 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, you know, 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.
They'll apply somebody else's type curve with our costs 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. Pre-drill, we will test what is the rate of return going to be on the last well we put in the DSU. Let's say there's 16 wells in DSU, we'll say, put a 17th well in there instead of 16. What's the rate of return on that incremental, call it $9 million? That's got to exceed a hurdle of 25%. 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.
We really make sure that we don't overcapitalize a DSU. You could, you know, put 40 wells into a DSU and find that your last five wells in it earn you nothing. That's the system we use.
Thanks, Herb. We're running up at the end of our time here.
Okay.
Thank you and the SM team for being a participant here at our conference.
Okay, thanks. Thanks, Jack. Thanks for asking questions.