So this is kind of the flipside of that, right, where it’s like, okay, here’s something that will be where we picked the wrong exact locations, but we were right in the broader scheme of things and there’s those 1.5 million BOEs where it increases. So one, I guess, if I’m – I have the right idea there. And then two would be in your experience, is it kind of a consistent like this $1.5 million, is there some consistency even in rough terms from year-to-year like – so if we’re talking about a 5-year rule, my understanding is you take like the 1.5 million and then you can multiply that by 5 million to get 7.5 million BOEs. And then you kind of add that back into like the 40 – I know – I don’t want to get in trouble with SEC stuff, like I know, of course, technically, the SEC folks wouldn’t approve that.
But from the standpoint of – like just trying to roughly approximate what could be more similar to how things look for an operator? Am I kind of at least like on the right track there?
Brian Cree: So Donovan, this is Brian. You did a great job of describing the impact of the pipeline. You did just a fabulous job right there of describing what happens for a non-operative working interest owner when they’re trying to figure out what’s going to get drilled over the next 5 years. Obviously, from our standpoint, we have got a – we take all the information that we have got, permits, AFEs, information from the operators, and we try to project out what we believe will get drilled over the next 5 years. A lot of our focus because of the amount of undeveloped acreage that we own and the wide range of our working interest ownership, we have got some stuff that is 10%, 15% working interest. We have got a lot of other wells that may be far less than 1%.
We are going to spend more of our time trying to figure out which wells are drilled in the higher working interest wells. And so in any given year, there is going to be a subset of properties drilled that are at lower working interest or that we just didn’t expect to get drilled. And so you nailed it, I mean you hit it exactly out of the park with your explanation there. We are doing the best we can to figure our what’s going to get drilled over 5 years. But every year, there is going to be a group of properties that are drilled, completed and turned online that we did not have in our proved reserves at the end of a given year. Now, whether that’s averages 1.5 or more or less, I think it’s in the range. I haven’t done the calculation to be able to tell you whether you use the 1.5 and you can multiply that by 5.
But I would tell you is that there is no doubt that every year, there are definitely properties drilled that we did not have in our proved reserves at the end of the year.
Donovan Schafer: Okay. Very helpful. And then just the last question and I will take the rest offline after this, just to DD&A expense in the quarter is a significant uptick in absolute terms. And of course, a lot of that, I would say, probably even just the majority of that comes from the increased the 24% quarter-over-quarter increase in production rate. But it does look like there is a bit of an uptick in terms of DD&A per BOE. I think it went from kind of 18s – $18 – high-$18s to kind of low-$20s. So, is that just a matter of the acquisitions, or was there anything elsewhere like the reserve on existing wells, there is maybe tightening up of reserve base or something. Yes, if you say the remaining number of barrels is reduced in some way because of a type curve adjustment or something, then you are going to have to – that will kind of accelerate that – some of that DD&A recognition.
So, just curious if you can talk to you what was the driver of the increase on a per BOE basis?
Jimmy Henderson: Yes. Jonathan, this is Jimmy. I will give it a shot here. But I would say the increase was a combination of the acquisitions and getting the CapEx for those into the calculation. And to have a timing difference on – I think the reserves will continue to increase as we go forward on those particular wells, but we put all the CapEx in depreciable base here in the fourth quarter. In addition to the change in the reserves that you were discussing earlier, the reduction in our total proved reserves is also part of that calculation. So, will effect and we true up the – within the fourth quarter to that year-end reserve calculation. So, it’s kind of a combination of both of those equally impactful.
Bob Gerrity: Yes. And I would just add. One thing you got to think about there is from the standpoint of making acquisitions, when oil and gas prices are higher like they have been the last couple of years, when you are making those acquisitions at very attractive rates of return because of what you are paying to acquire those assets at those higher oil and gas prices, you are seeing a higher depreciable base being added into your overall reserve base. So, when you take that into consideration plus the fact that we pulled off a lot of proved undeveloped reserves that we just talked about. And then the final component of that is, from our standpoint, we don’t exclude any of our capital costs, any of the cost on our balance sheet, they are not outside of that depreciable base.
So, we don’t have any unproven assets on our balance sheet. Everything on our balance sheet including all the costs associated with all of our undeveloped resource is included in our depreciable base. And so the combination of all of those things can cause that DD&A rate to fluctuate.
Donovan Schafer: Okay. Very helpful. I appreciate. Thank you, guys. I will take the rest of my questions offline.
Bob Gerrity: Thanks Donovan.
Operator: Our next question comes from John White with ROTH Capital Partners. Please state your question.
