Vitesse Energy, Inc.

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.

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.

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.