Brian Cree: Yes. The only thing that I would really say is that, look, I mean, we – our guidance is for $90 million to $110 million of CapEx in ‘24. Part of that is a carryover from the acquisition we did last year. And so I think you can kind of back into our organic, which is we always talk about being kind of in that $40 million to $50 million range, plus or minus, of the organic. And so you can kind of do the math to what we’re expecting. It’s certainly not at the $35 million level that we had last year is not what’s baked into our guidance.
Jeff Grampp: Got it. That’s very helpful. Thank you, guys.
Operator: Our next question comes from Donovan Schafer with Northland Capital Markets. Please state your question.
Donovan Schafer: Hey, guys. Thanks for taking the questions. So the first one I want to ask about – kind of coming back to differentials and the Trans Mountain pipeline. Of course, that’s a crude oil pipeline, and that’s what’s kind of causing the wider differentials there. And some of that’s because I think I believe it’s Canadian oil sands production that is – it’s a type of production activity that takes time to ramp up. And so they’ve kind of missed time to started ramping it up, particularly, things get rolling and then the pipeline got delayed. But one other benefit of that is, it increases the natural gas consumption because they use a lot of natural gas. They burn a lot of natural gas to generate the heat and stuff they need for that – for extracting the oil from oil sands.
So I’m just curious, are you starting to see – I don’t think we’ve seen anything in the pricing, but have you seen anything indicating or showing that kind of natural gas burn uptick or increasing in the Alberta area? Any kind of earlier indications of anything positive there and if that could be – if that can rise to a level of materiality or if that’s just to, I mean, obviously, production is very much skewed towards oil, but could that become significant in any way, any early indications?
Jimmy Henderson: Don, this is Jamie. I’ll take a shot at that, and thank you for providing that color on TMX and how it affects North Dakota. It could set it better myself. As far as the natural gas, we’re not really baking something in to improve, we’re more impacted because of the way the gas flows from North Dakota and the stream mix with NGLs were much more impacted by market centers in the Gulf Coast. And so we’re definitely more impacted by Henry Hub and Mont Belvieu for the NGLs. So we’re continuing to model that sort of depressed scenario for our gas sales for the time being. We’d love to see more of a call on gas going north, but there’s not as much infrastructure going that way of North Dakota as there is – with the pipelines, with ONEOK, etcetera, going down to the South.
But we’d love to see that change and see gas being exported from North Dakota, more so into Canada to facilitate production up there. But we are not baking that in at this point. We’ll keep you apprised if we see things change fundamentally on that.
Donovan Schafer: Okay. That is helpful. And then I did – I wanted to follow-up. In the press release, you included an interesting data point, which was this 1.5 million BOEs in TDT reserves are added in this iteration of the reservoir, that were coming from wells that had not been booked at all as puds in the prior year. And as I understand, I think the idea here is you’re trying to get around like as a non-operator – like with an operator, think is that we’ll drill here, we’ll drill here and we’ll drill there and they can kind of stick to the plan and meet the SEC 5-year requirement of converting about 20% of puds in a given year. And you guys as more of a statistical game or something where you could sort of say, well, peers, we could guesstimate numbers and come up with something where we’ll hit 20% conversion rate, but that actually want you to get the exact right well locations, and you can’t do that.
