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spk03: What that means is deeper. Originally, the Bakken was just developed as the Bakken. We thought that the three forks would be productive at some point. That came to be, so it was deeper. Denser, we bought most of our inventory based on economics for four Bakken wells only per DSU. Since 2010 up to about 2017 to 2018, operators experimented with putting a lot of more wells into each DSU. That didn't necessarily result in the best economics. So they backed off of that heavy number. and relied on improvements in frac technology. So anywhere from six to eight wells for DSU is now the standard, and we're recovering a tremendous amount more oil out of each DSU than we were over the last 10 years. The cheaper is that the wells, as infrastructure would be built out, the wealth would become more economic. That has happened. Better, the EURs in the Bakken, almost on a daily basis, get better. You've got to remember the Bakken is such an incredibly, incredibly tight rock. If you can increase your recoveries by just 2% or 3%, then that is highly economic. So technology develops slowly, but it continues to evolve. And every day we see better wells than we saw before. So we're very encouraged that over the course of time, frac technology will continue to improve recoveries. We look at Tier 2 to Tier 1. but what we really look at is the economics. Sometimes if you take a look at what would be considered a Tier 4 area, and that Tier 4 is considered just on an EUR basis, well, the drilling costs in that area by that operator is lower than some of the stuff in the Tier 2 or Tier 1 locations, and therefore that economics are actually better. So, you have to differentiate between Tier 1 and Tier 2 economics and Tier 4 or Tier 5 economics. So, we do this all the time. The field is constantly changing, and we think for the better. So, Donovan, I'm sorry about the long answer, but that's really core to what we do.
spk04: Okay. No, that's great. kind of, uh, following up on that, I want to talk about refracts a little bit, because I think, you know, you could, you can argue that that would tie into the same kind of thesis and you, you talked about recovery rates. So when you talk about, you know, the, the huge improvement in economics from just improving at a couple of percentage points, I think, you know, correct me if I'm wrong on this. I have to go back to my petroleum engineering days. But, you know, you're framing that probably in terms of, like, figuring out, okay, what's the total oil in place in this sort of cube? You know, you kind of model out some cube of reservoir area. And a lot of times, you know, you're only recovering something less than, you know, in a shale plane, maybe 10% or potentially less. And so you're talking about, you know, going from, just picking numbers, like a 10% going to a 12%. That's more of like, even though it's 2% on those terms, it's a 20% increase in the volume. So when you look at the old wells, the Bakken's an old basin now, kind of at this point, certainly compared to the shale-type development in places like the Permian. So it's going to be one of the earlier basins, shale basins versus others. where it starts to become sensible with all the advances in technology. Do you have a sense of some of the early wells being able to go back and say, gosh, we think this was really only a 6% recovery, and given all the changes that we've done with technology and track designs and everything, and being able to go back and say, well, we were really only in zone for a third of the well bore. third of the lateral and the other two-thirds of the lateral weren't even landed properly. Can you give us a sense of what potentials you're seeing there? And actually, I mean, if you do know the recovery numbers, I actually would be really curious where you think they were in the beginning and where they are today and the implied amount you could come back and recover with refracts.
spk03: Right on. So, Donovan, I don't think anybody, in fact, I'm sure no one really knows the initial recovery rate. But, you know, in our shop, we do ascribe to that 9% to 10% in initial recovery percentage. So that's not far off. I'm looking at a map in our conference room right now that has identified all wells that that we believe will be refract. And it is shocking how many wells are prospective to be refract. And it's all over the basin. Remember, the field was developed maniacally to hold it by production from 2008 to 2012. All of those wells. are prospective to be refract. From 2012 until they moved from gel to slick water, all of those wells are prospective to be refract. We've seen a three-fold increase in the last six months in operators starting to refract wells. We believe that that refract technology is It's really new, and we're not sure if the refract technology is going to improve faster than standard fracturing technology, but the cost will certainly come down. The last thing I'll say about refracts is, look, the economics of a refract are extraordinary. They're the best economics we have out in the field. One of the negatives for an operator to refract is that you really need to shut in the rest of the DSU. So your production in that DSU will initially go down. So the timing of refracts is very difficult to ascertain. There is one operator that has proposed refracting five wells in one DSU. We have not seen the results from that. I can't say if that's a good thing or a bad thing. But refracts will be a wildly economic future in the Bakken.
spk04: OK, and then just one last question to follow up on that. With the refracts, is your sense that it's kind of like a broad-based uniform potential in this? What I mean by that is you can imagine a case where sort of entire vintages or entire years, say every year, Every well drilled from, you know, 2014 to 2017 or something was done at this way, at this scale. And so that entire, you know, that whole bundle of DSUs or whatever, that would be one perspective. Another perspective would be, well, you know, you didn't have as good a well control early on. I don't think as many companies were doing, like, the gamma ray. You know, you can now put a gamma ray detector on the back of the bed. And so, you know, today, you know, am I in zone or am I not in real time as you're drilling the lateral? And, you know, that wasn't the case before, but now you have so much well control, even if you didn't get that reading the first time, you could probably actually go back and actually come up with those conclusions after the fact now. So maybe you're not, it's not wide uniform, it's maybe, you know, kind of rolling the dice each time and it's more like you could go back and look and say, oh, you know, one in six of those dice rolls early on is badly out of zone. And so maybe we'd even re-drill it because we just don't even think this thing, this lateral is even there or even really, you know, that type of thing versus this much broader just uniform everywhere. Is it more one, more the other, maybe a mix of both, and it's more the latter case where refracts will start first before migrating to more uniforms?
spk03: Yeah, it's a good question, and there's no perfect answer for that. Wells drilled between 2008 and 2011 often were out of zone. So you're absolutely right about that. Whether or not you can go in and refract that well that is mildly out of zone or not, I don't know. And that, I don't think, has been proven yet. You got to remember that the Bakken is such a closed unit that in the Bakken we have a halo effect. When you refract or frack a well in a DSU, the parent wells actually have their production increased. So again, it is a different basin. And I think that where you refract, The intensity you refract, it all needs to be worked out, and it needs to be bespoke to each different DSU, both, as you said, by vintage and by an initial frack technique. So, again, you know, when you refract a well, you often increase production in the surrounding wells. So, it's a It's a different beast. It's very tight.
spk04: Yeah, and, you know, I can kind of feel like almost like unprecedented levels of data for going back into an area like this. So there's a lot of engineers, a lot of number crunching, a lot of fascinating analysis stuff that goes into it. Okay, well, I'm going to leave it at that. I'll take the rest of my questions offline or follow up with you guys. But, yeah, congratulations on the quarter. And I will second what you said about Ben. He's been doing great.
spk03: Thanks. Thanks. And I'll reaffirm what you said is we try very hard to be boring. So thanks for that comment. So thanks, Donovan.
spk00: Thank you. Our next question is from Lloyd Byrne with Jefferies. Please proceed with your question.
spk01: Hey, good morning, Bob. And I don't know if Brian's on, but good morning. I'd love to go back to the M&A market for just a second. And I'm kind of wondering whether you said kind of the deal flows the same, but whether with the lack of capital out there for the space, you get more opportunities going forward. And then maybe on the back of that, whether you'd ever go out of base and going forward as well.
spk03: Yeah, so good questions, questions we ponder every day. We would definitely go out of basin. We've got a little interest in the Powder River Basin, mostly in the mud rocks, which we've done well with. We think the powder is prospective. It's just too expensive now for us to do anything meaningful there. We managed some assets for Jefferies in the Eagleford. We like the Eagleford very much. We think that's prospective. We do not see a lot of deal flow in the Eagleford. We do have a fair position in the DJ, love the DJ, have done extremely well there, but don't think that that is something that we're able to get much scale with. We look at two or three days of well proposals a day in the Permian, and it can't really compete to what we're seeing in the Bakken. So, wide open for the Permian, we have some organizational experience in the Permian, but right now the bread and butter in the Bakken is still the best we see. So that's going outside of the basin. We have seen on the larger $100 million to $500 million deals, we have seen more flow. And I would love to do one of those deals if it would be supportive of our dividend. Most of those deals are right now priced so that they're not that attractive to us. Again, we're not looking for scale. We're greedy as it comes to looking for something that would bolster the dividend.
spk01: That makes sense. I just also want to go back to the 42% of rigs operating on the acreage. It was mentioned earlier, but can you just tell me whether that's higher or lower than in the past? And then that seems like an awful high run rate for the inventory. And just does that tell us about the inventory quality? Is it because it's pushing out into Tier 2 and Tier 3 acreage?
spk03: Yeah, it's a little bit of that. That's true. And that's higher, the 40%, 50% of rigs running on our acreage. That's higher than normal. But it's not that out of line. We average about, Dave, about a third. About one-third. About one-third of all the rigs running in the Bakken are on our acreage. And, you know, that's because we're like a Bakken ETF, right? We have acreage all over everywhere. So, yeah, I think that's a, you know, your conclusion that the rigs are spreading out, Pretty good. Yeah, we would agree with that.
spk01: Okay, awesome. And I have one more. You just talked about the CapEx run rate going forward. I mean, as you get the refracts and you got some inflation in there, but how do you see that for maybe over the course of the rest of the year?
spk03: Yeah, it's very lumpy, Lloyd. I would love to say that we're going to be able to replicate what we did in the first quarter, each of the quarters, but we can't. We're not in control of that. That is a negative, being the non-op. And if we have similar CapEx in Q2, maybe we will change our guidance, but at this point, it's too premature. But I got to tell you, we are very excited about the CapEx that we had in the first quarter. And again, more CapEx is a very good sign for us because we're very disciplined in what we drill. And remember, the lag between CapEx and production is roughly a year, less than that on Refrax, but we know that CapEx.
spk01: That's great. I appreciate all the commentary on the Bakken productivity. It's interesting. So thank you very much.
spk03: Thank you, Lloyd.
spk00: Thank you. Our next question is from Jeff Graham with . Please proceed with your question.
spk05: Hi, Bob and team. Thanks for the time. Hi, Jeff. Morning. Full softball question for you, Bob. Obviously, you guys have a super clean balance sheet. You're returning a lot of capital to shareholders through the dividend. oil prices are being a bit volatile here in the near term. How are you guys thinking about allocating capital to ground game opportunities? Is that kind of constrained to organic free cash flow, or would you guys periodically use the balance sheet if you saw some good opportunities come across your desk?
spk03: Yeah, we would use the balance sheet, Jeff, no doubt about it. But again, you know, We do, you know, we're specialists, especially in the Bakken. So our hurdle rates for the wellbore interest we buy are pretty high. So, you know, we buy whatever we can. It's not limited by budget. It's limited by opportunity and economics. So philosophically, you know, if you see our CapEx go up, that's a good thing. We would use our balance sheet if we saw an extraordinary opportunity, but not just to grow. Did that answer your question, Jeff? I can be more philosophical if you want.
spk05: No, that was perfect. I appreciate it. And just a smaller housekeeping on the modeling side. You mentioned LOE was a bit elevated due to some workovers. Any sense of where that kind of levels out or how we should think about LOE going forward? Is Q1 a bit of an aberration on the high side or any commentary that would be helpful?
spk03: Great. I'm going to ask Dave to answer that one.
spk02: Okay. Hey, Jeff. This is Dave McCosko. I think what we saw is, you know, a lot of work over activity in Q1. I think going forward we'll see that level off. We'll be sitting right in that $850 to $9 per BOE range of LOE going forward.
spk03: A lot of that's depending on the seasons, right?
spk02: There's seasonality in that first quarter. Obviously, as it gets warmer, things will get cheaper to operate.
spk05: Understood. Perfect. Very helpful. Thanks for the time, guys.
spk03: All right. Thanks, Jeff. Well, that's it for now. We really appreciate you guys listening in. And please reach out to Ben if you've got – Any further questions? And we're going to go back to being boring. So thanks, everybody. Bye-bye.
spk00: Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.
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