Ralph, you want to add to that?
Ralph D’Amico: No, I think that’s right. It’s a balance. It’s hard to say. You can just — it’s not just one thing. Right. So it’s a combination of all of those factors together. I don’t think it’s a good exercise to go back and say, what if something else had happened? What would the dividend have been?
Donovan Schafer: Sure. Well, so maybe to think through kind of the relationships and the linkages, I think maybe I’ll rephrase it based on what Chad said. So it seems like it’s more those acquisitions were part of, and I think you included this in the release. It’s – that was part of an overall indication that you’re returning into more of a growth orientation. Now that you’ve almost completed the swapping in, the swap out in the portfolio of working interest production for royalty production, that achievement allows you to then focus on deploying capital in a way that grows production. And then in turn, that’s kind of how you plan to be going forward. Reinvesting a certain amount, growing a certain amount of royalty production, while at the same time positions you to raise the dividend. Is that kind of the way that those linkages flow? Okay.
Chad Stephens: That’s why we continue to highlight our royalty production volume growth, because historically, we also had the non-op working interest piece that combined, made up our total corporate volumes. And in Danielle’s notes today, we highlighted the fact that our year-over-year corporate volumes were down 9% because we had sold a material amount of our non-op working interest assets. But our royalty volume is continuing to grow and will now be the main story, instead of having to reconcile royalty volume growth versus total corporate. So it’s the royalty volumes that have continued over the last three years compounded annual growth rate, as we show in our best relations slide deck of over 20%. And that’s where the business is focused, not non-op working interest. So now that that’s gone and we’re focused on this 20 plus percent royalty volume growth, we have real conviction around allocating a bigger piece of that cash flow from those volumes into a dividend.
Donovan Schafer: Got it. Okay, understood. And then as a follow up, and this is sort of a little bit of just a housekeeping modeling question, but with the SCOOP becoming a larger part of the production mix, how should we be thinking about the mix of oil and natural gas as we head into 2024? And also the trend on transportation costs with the impact from the Haynesville? Should we expect transportation costs to keep falling on an Mcf basis in 2024? Or are we kind of at a new run rate here?
Ralph D’Amico: Donovan, I think on the split between oil and gas, right? I mean, around that 80%, because even though the SCOOP is growing, the Haynesville is growing as well. Right? So and the Haynesville is a bigger piece today, so it doesn’t have to grow as much to mitigate. Oil can grow. But if the Haynesville is growing at a faster clip than the SCOOP, given its size, you’re probably plus or minus a couple of percentage points. You’re going to be around that 80% split being natural gas. And as far as your other questions on a per unit metric, I think it’s the same. We’re going to provide more granular guidance as we get into early 2024. But even in the Haynesville, there is not every lease is a cost free lease, right. We have some leases that are cost bearing leases, right?
So it’s not going to go to zero. Right? Is it going to stabilize around where it is today or fluctuate a couple of percentage points one way or the other, depending on how many cost free leases versus cost bearing leases on any given quarter come online? Yes, there’s going to be a little bit of variability, but none of it should be a drastic increase. The decrease that you see from 2022 to 2023 is really just a reflection of having the minerals having better economics than any of the working interest did. Right? The higher per unit metrics that you see in prior quarters were really associated with the working interest. So I hope that helps.
Donovan Schafer: Okay, it does. And if I can squeeze in just one last one on, just kind of zooming out at a more macro natural gas price supply demand level, do you have any thoughts? The rig count has definitely come down in some of the gas focused basins, but at the same time, we’re still getting strong production in the oil rich basins, and there’s associated gas coming from that. I mean, I think the EIA even had it’s like one of its daily blog posts or something on that talking about. We’re getting these natural gas production increases in the Permian, and people aren’t there drilling the Permian to produce gas. They’re going after it for the oil, but they get the gas with it. So I don’t know, just do you have any thoughts and are there maybe regional differences to highlight? If it depresses prices in the Permian at all, how much of that would propagate to Henry Hub or places where you sell your gas?
Chad Stephens: Well, yes, you saw it just about 10 days ago there was one weather forecast that flipped maybe sometime last week. And natural gas prices, they were up at like 350. Front month was up at like $3.50 maybe a little bit above that 355. And the weather forecast flipped to warmer and the price just collapsed over a two or three day trading period. And today it’s down, back down to right around I think $3, so a dramatic drop. And it’s all weather related. When you look at the EIA storage data and it comes out this morning. I hadn’t had a chance to look at my phone because of the call here what the storage number is today. But over the last three weeks I think it is the EIA storage number suggests that were supply and demand is tight.
That there is not enough. We’re short supply. We’re at not far a warmer than normal 14 day forecast. What happens after that 14 day period? And really when winter sets in, in early December and who knows? These days weather is a wild card and El Nino is a wild card. So it’s hard for us to forecast what prices are going to be. But to your comment about there is more natural gas associated gas coming from the Permian but it’s later in 2024 there’s several. Kinder Morgan and energy transfer have a pipeline that’s being built as we speak. Earlier this summer flaring out in the Permian Basin went back up to some of the highest flaring volumes in the history of the Permian Basin. And I had read some articles. I thought that the Railroad Commission and even ExxonMobil and Chevron were trying to publicly shame these operators to stop the flaring practices from an environmental perspective.
But because of the amount of wells being completed associated gas from those wells and no takeaway capacity they were flaring the volume. So it’s hard to know exactly what the number is going to be once the Kinder Morgan Energy transfer line is in service. But that’ll be in mid-to-late 2024. And that’s right when ExxonMobil’s LNG export facility comes in to service. And then in first quarter 2025 Sempra’s LNG export facility comes into service. So the timing of the associated gas coming from the Permian could probably keep the market balanced. Weather adjusted. If we have a normal winter, exit winter into spring at a normal kind of storage number the gas price should stay at $3 or above. If we have a warmer than normal winter for the rest of the winter all bets are off.
Who knows?
Donovan Schafer: Okay, that’s very helpful. Thank you guys and congratulations again. I’ll take the rest of my questions offline.
Chad Stephens: Thanks. Thanks for being here.
Operator: Thank you. Ladies and gentlemen, that concludes our question-and-answer session. I’ll turn the floor back to Mr. Stephens for any final comments.
