Nick O’Grady : I’m curious, what’s that wonderful music in the background?
Scott Hanold : Sorry. Lot of the calls going on today?
Nick O’Grady : I think what you see is what you get, I think what I would tell you is we still see the same, I think, we still see a lot of the same stuff. We still see a lot of regular way, the ground game blew up. We did almost $300 million with the ground game that was a record year. I mean, I think we did, several thousand acres over a third — which included over 30 locations, which is frankly, a monstrous record. And we’re doing it in a different way. We’re solving, we’re doing it in, we’ve moved out of the sort of fractional small scale stuff into much larger, we’re solving major operator problems. And it’s mostly dealing with our mega operators. Obviously, we have moved into the JVs. But that’s more a function that we can actually do that.
They were dealing with private equity groups that were non-commercial in the past, because they were the only ones that had their capital. And they’d much prefer to work with an actual true oil and gas concern that’s a permanent owner of the assets. And so we really become the first oil and gas concern that can actually do that. And so I do think that that will be an avenue that goes there. I think there are still, we know of a half a dozen regular way non-op transactions that are going to come to market, either on or off market in the next — within this year. And so obviously, we will be looking at those. But I can tell you, to Adam’s point, we’ve signed 10 non-disclosure agreements this year, it just keeps coming. We continue to be contacted of people coming to see us saying, I have this problem, or I need to buy this or I want to do this, can you help us do this?
And we are trying to solve solutions, whether it be rationalize their assets, whether they have an asset that cannot be sold, and they would like to sell a portion of it, like what we did with Midland Petro. There are all sorts of solutions that we’re trying to provide. And with that, we can create the scale that I’m describing. But I’m extremely confident that we can grow it and create a return for our investors. As for other basins, there are other great economic basins. There are certainly ones that I would very much like to avoid. But I think we can solve for the risks around them. We certainly have technical expertise. We’ve looked at a handful of other basins that we would be interested in. There are some that I think are going to be a challenge, I think there are some that we would have pushed for the right opportunity to go to.
I think there are some that we would have to frankly, create governance or other things to get around those risks. And I don’t know, Adam, if you want to add to that.
Adam Dirlam : Yeah, I mean, I just feel like a broken record, quarter after quarter. But it’s the scale that we have now. It’s the optionality in the deal structures and the blueprint that we’ve created. And then frankly, it comes down to reputation. And our ability to execute and our ability to be commercial. And so we’ve got that more than we can shake a stick at in terms of the inbounds, and how can we solve a problem together. And so those are the conversations that we’re having. And I’ve talked about the stuff that’s in the market. And that’s everything from the non-op packages to the drill co like joint development agreements, as well as the co-buying. But now you’ve got this different theme emerging with the operators merging and the rationalization coming in there.
And so you can add another kind of arrow to the quiver, in terms of how Northern can be helpful. And so if you’ve got all of those options, and you’ve got the balance sheet you got a reputation, then you can use all of those to your advantage in order to execute.
Scott Hanold : Okay, appreciate that color. And my follow up question is on shareholder return. You mentioned that you’d be willing to kind of step in and, laying the buybacks with market dislocations? Can you give us a sense of like, how aggressive are you willing to get there? And, how do you think about intrinsic value. I mean, it seems like you think the stock price is attractive today, but like, where is — can you give a sense of where’s that sort of point where you really get aggressive? And, and how deep can you go?
Nick O’Grady : Yeah, I mean, I think that would I can’t give away too much of our playbook, Scott. And, obviously, it’s a board decision, we’ve been in discussions with the board. We are watching. I’d say as an ex-hedge fund manager, we have a fairly sophisticated internal modeling of this. And we try to use it and we model it internally and compete and compare it and competed versus generic M&A, and all that stuff. When we run all these things, versus we effectively mock it against where that capital to go elsewhere. Because it is, you have to sit there and say to yourself, if I spend this money today, workers go elsewhere. But frankly, as we look to the first quarter, this represents the worst relative performance we’ve seen in about three years.
And we view it as relatively inexplicable, given the fact that our growth profiles, we look this year as one of the best in the space. Perhaps it’s because I can come up with, harebrained long short thesis of some sort, or whatever. But regardless, that generally, like I said, life gives you lemons, you make lemonade that creates opportunities for us. And that’s how you allocate capital when you see that. So we’ll be watching. And if the opportunity presented, we’re ready to activate we certainly have availability and our buyback authorization, we can always create more and go to the board if necessary. And so, that, I think we have over $80 million today available, we can always ask for more if the board’s willing. And that’s a board level decision.
Scott Hanold : Thanks.
Operator: We’ll go next to John Freeman at Raymond James.
John Freeman : Good morning, guys. Just following up on the last comment, there where you said that you would consider looking at I guess there’s a handful of other basins that you all have looked at or considered. I would assume that for you all to do anything outside of the three basins that you’re in, that it would require a pretty substantial position. I mean, not something they all sort of build into, right. You need enough scale, for it to be make sense to add a fourth kind of leg to the stool, right, correct?
Nick O’Grady : Yeah, yeah, I think that’s a fair point. And I think there’s a handful of different dynamics that kind of come into play. Obviously, the land and the regulation around that, and what that means, for non-operator. And then, when you think about co-buying or buying down of minority interest in an operator position, you’re kind of linking arms with an operator that likely already has that expertise in that basin to the extent that, we need to have two sets of eyes taking a look at things. And so I think that’s an interesting dynamic in terms of taking a look outside of our own backyard and being able to link up with some of the best in class operators that we want to partner with.
Adam Dirlam : I think there are some basics that would be a real challenge John. I think there’s some basins that may have some risks to them that could be solved if you add the right operator that might have the right rock but have other risks associated with them that could be solved if you had the right operating partner.
John Freeman : That makes sense. And then my follow up question, obviously, we spent a lot of time on the accrual aspects on the CapEx. And it looks pretty clear that whether it’s late this year, next year that the cost improvements that you’re seeing that some of those major properties eventually that’ll show up. If I shift gears and think about the guidance as it relates to production. You’ve got a slide in there that shows the productivity you’re seeing in the Permian and the Williston. And I think the well in particular was pretty surprising for me just you think of it as a mature one of the older basins. And, it looks like obviously still early here, but ’24 results look like they’re meaningfully outperforming. Is your guidance on production related to the Williston, does it assume we’re like a 2023-type well results?
Jim Evans: Yeah, Hey, John, this is Jim. We always go into the year kind of assuming there’s going to be some well performance degradation. Obviously we’ve got about nine months of wells in process, we already have a pretty good idea what we think the performance of those wells will be. But we do always assume there’s going to be some degradation. But really, that plays into our portfolio management, right, as we’re thinking about which wells we want to participate in which operators we think are the best performers where we’re going to target our activity levels. And so that’s really how we kind of manage our activity and our wealth performance and make sure that year-over-year we’re doing a good job and participating in the in the best well.
Obviously, 2024 is off to a great start, but it’s pretty early on, we’ll keep an eye on that and see how it changes overtime. But we’re obviously very encouraged, we’re happy with the Permian 2023 outperformed a little bit, versus 2022, even as we move more into the Midland, which is less productive than the Delaware side, so we’re very happy there as well. And again, 2024 is off to a great start. So overall well performance has been as good are better than expected. But we’ll stay true to our roots and expect some well degradation, which is what we build into our guidance and our forecasts. So, potentially some upside there. But we’ll wait until we get more information as we go farther into the year.
Nick O’Grady : If you’re looking for optimism from an operator, you’re not going to get it done.
Adam Dirlam : I’m going to give you a little different perspective, I think, from our PDPs from a Williston standpoint, it was generally concentrated with Continental Marathon and Slawson. So some of our best operators and ’23 If I’m looking at the D&C list, as well as some of the near term AFEs, you’ve got a similar setup with Conoco and Slawson and Continental, all kind of leading the pack in terms of what that makeup is. So encouraged by where these guys are operating and how they’re performing.
John Freeman : Appreciate it, guys. Thanks a lot.
Nick O’Grady : Thanks, John.
Operator: Our next question comes from Phillips Johnston at Capital One.
Phillips Johnston : I got it. Thanks, Chad, you gave some pretty good color on LOE in your prepared remarks. You mentioned the run rate should start to fall in mid-’24 as production ramps and obviously, you’ve got the AFE charges tapering off by the middle of next year. So wondering where we might be by Q4. And as you look out into ’25, would $9 a barrel be a good place holder for our models? Or would you steer us to something above that or below that?
Chad Allen : Yeah, I mean, I think I think that that sounds in the ballpark. Phillips. Yeah, like I mentioned, we’re going to be running a little hot. As we kind of catch up the AFE charge. We only have instead of a year to a group, well, we only have six months. So that’ll be a little bit heavier in the first quarter. But yeah, then, as I mentioned, we will trend down probably towards the bottom end of our guidance range, maybe even a little bit lower as we close out the back half of the year.
Phillips Johnston : Okay, sounds good. And then maybe just a question for Adam. Looks like the plan involves 70, net spuds and 90 till in lines. You talked about maybe what’s driving that 20 well gap and what that might mean for the trajectory of production, capital efficiency in to 2025.
Adam Dirlam : You’ve got, obviously the Midland Petro project, kind of finishing up, that’s a 40% working interest. So you’ve got concentration there. And then, well, as we proceed throughout the year, we’re going to be getting these well proposals coming in the door. And so what that looks like. And so I think it’ll depend on obviously, that working interests mix, as well as kind of the cadence and activity levels of kind of the Permian as well as the Bakken. So I think it’s a function of both Novo and some of the other larger transactions that we had, and where that activity levels concentrated. We’re having these conversations on a quarterly basis with our operating partners. And so that can change.
Nick O’Grady: I mean, so as for our normal course, or D&C list, usually roughly equate to about half of our total count. And obviously, it’s been elevated. We’ve been building it, because we’ve been growing organically. So overtime, it should be about half. And that’s partly why I’m elevated. So it masks some of the capital efficiency in the business. And so that’s why you will see our capital efficiency markedly improved. And if you go back to say, 2021, where our D&C list was declining, you would see material improvements, the free cash flow, yield and other things, and that’s because you were, you’re running a leaner D&C list, and so it’s more just a normalization of it. So I wouldn’t make the assumption that it leads to material declines or something like that.
It’s just more a normalization of the D&C list. Because obviously, we’ve been going through for I mean, think about it last quarter, our production grew like 53 — our oil production grew to 5,300 barrels, and not all that was just Novo that a lot of that was organic. So you’ve been seeing volume growth and material, right? So you’re, you’re just really flattening out that growth production effectively as you as you exit the year to some degree.
Phillips Johnston: Sounds good guys, thank you.
Nick O’Grady : Yeah.
Operator: We’ll move next to Donovan Schafer at Northland Capital Markets.
Donovan Schafer : Hey, guys, thanks for taking the questions. So, first, I want to talk about the reserves. So I was a reservoir engineer, my first job at a college so I might be biased on this. But I do think, you can make a lot of you can draw a lot of meaningful conclusions, or pull out some insights from if you know how to make some adjustments. Because obviously, there are a lot of adjustments to make in order to show real a truce or economic reality. But so the TV 10 was $5 billion, which is almost exactly in line for your trading terms of enterprise value. And, that’s on an SEC pricing basis. And that can cause crazy distortions, this time around, it does, at least, in my view look like the SEC pricing happens to not look too crazy, and be kind of sort of close to what we could expect going forward.
But there are a lot of other things for where you are right now as a company, where the reserve work may not be accurate and need more adjustments. So one is Utica and Delaware acquisitions. I don’t think those of you included, so if you can confirm that.
Nick O’Grady : We don’t really book spuds in our — as a non-op, we don’t book our spuds, right? So we have, unlike an operator an operator can book a full spud booking for five years. I mean, how many spuds do we book in there. We generally book about two to two and a half years of activity, right. As a non-operator, we still need to show that we’re converting more than 20% of our spuds every single year. And so in the projects that we’ve been doing the Midland forward, we have a more definitive drill schedule so we can book more spuds there. But on your typical non-op, where the operators aren’t providing us with their actual drill schedules, it’s hard for us to show that high level of confidence that certain locations will get drilled over the next five years.
Now, we’re obviously going to have the activity that we showed last year almost 80 net till’s, but we can book those specific locations, because we need to make sure that we’re converting those locations. So we have a lot more locations than what we’re booking in our reserves. And so it’s a very conservative reserve set that you’re seeing there.
Donovan Schafer : Right. And then another thing is just, this is coming from kind of my recollection of how things work. So I’m looking for what your thoughts are on kind of the relative impact of this is that, the other thing about how the way to do affiliate with the SEC, the pricing gets locked in on a historical basis. And so like, in this case, with the current reserve report that you just put out, or the numbers you just shared. You’re kind of stuck with the current commodity price, the 2023 commodity prices, and then they do the same thing on D&C prices, or D&C costs. But D&C costs follow commodity prices on kind of a lag basis. Like you’re only just now, it sounds like the more material decline in D&C costs, you’re kind of only just now starting to see that yet, you’re sort of locked in at a level of D&C costs that honestly may have been more reflective of commodity prices in 2022.
So that also kind of creates, like, am I right in that? Am I remembering that correctly?
Nick O’Grady : Yeah, you’re correct there, right. We have to use trailing 12-month prices. So that’s locked in, we have to hold that constant going forward. Similarly, for elderly. And so if you think about where we were last year, SEC prices were in in the mid-90s. Now we’re in the high 70s. So that has an impact on reserves. And we lose a lot of reserves, just cutting off the tail end, those reserves that we had to replace those about 30 million barrels that we lost just due to pricing. And then also on the well costs. Because we’re not an operator, we look back at historical AFEs that we’ve gotten over the last year, which is more of an $80-$90 kind of price environment. And that’s what we have to bake in going forward versus an operator.
