Overall, I think that’s kind of where we’re headed.
Arun Jayaram: Okay. Fair enough. Maybe one for Jeff. Jeff, if you can give some more details. You’ve provided your Utica type curve on Slide 11. Just wanted to get a sense of is that type curve for the entire play? Is it for the volatile oil window only? And would that be representative of both the North and the Southern portions of the play?
Jeff Leitzell: Yes. That would just be the general type curve in mix across the 140 miles kind of from North to South there in the play. So it’s pretty consistent. You can see on the slide that we put our first handful of wells on there, and that’s really what a lot of the type curve was going to be built off. And you can see the Timberwolf package is the most recent one that we brought on and the outperformance in that one.
Operator: The next question comes from Philips Johnston of Capital One Securities. Please go ahead.
Philips Johnston: Just a few quick follow-ups for Jeff on the Utica. First, on the 55% oil cut, what sort of API are we talking about on that crew? Or is it more of a quasi-condensate type of mix there?
Lance Terveen: Hey, Philip. This is Lance. Yes, what we’re seeing is still early, but what we’re seeing is kind of APIs in kind of the 40s to 50s.
Philips Johnston: Okay. Sounds good. And then, the wells so far are pretty much all been up along the eastern edge of the acreage. And I’m pretty sure you guys have previously cited the black oil window. It’s sort of in the exploratory phase still. But how does the geology change as you go West? And when would you expect to test other parts of your acreage?
Jeff Leitzell: Yes. Good question. So to kind of start off, why do we started off on the East, really the big reason with that is just we had good quality seismic data over on the east side of it when we were first starting out. And obviously, that’s really important, so you can get a really good look at the detailed subsurface, any kind of drilling hazards to make sure you perform really, really clean tests. So where we started, where that seismics at, obviously, we started the delineation. We’ve got spacing tests in place. And then as we start to zero in on that spacing, we’ll be able to kind of step out more to the west and be able to apply some of those spacing techniques to start developing out there. But we do know there’s going to be variation in productivity. And as you did state, we do expect it to get more oilier as you do move out to the west.
Operator: The next question comes from Neal Dingmann of Truist Securities. Please go ahead.
Neal Dingmann: I’ll maybe stick with the Utica. Just my first question, typically, would your AMI in the eastern side of the play limit in any way thoughts about incremental activity or potential additional acquisitions in that Eastern oil window?
Ezra Yacob: Yes, Neal, this is Ezra. We’re pretty happy with the footprint that we’ve been able to put together since we entered the play. I think we highlighted on the call that we’ve added an additional 25,000 acres, bringing our total up to 425,000 acres at very low cost. And let me just highlight again that we actually own the minerals across 130,000 mineral acres down in the southern portion of the play. So when we look at it right now, as Jeff said, we’re drilling some initial spacing packages, some delineation tests where we currently have seismic. We’re also this year acquiring seismic in a couple of different parts of the play. So we can continue to step out and gather results on that and provide a bigger better estimate of what we’ve captured here for you guys.
As far as being limited on incremental activity. I want to think of it that way. Like I said, we’ve put together a very large contiguous acreage position. And really, our activity right now as far as investment in pace, as Billy said, is going to be determined on our ability to collect data and integrate the production data that we’re seeing back into the front-end of our geologic models. The activity is really always considered to be at a pace where we can continue to learn and incorporate those learnings on the next set of wells.
Neal Dingmann: Great details, Ezra. And then just to follow up, I want to make sure, I’ll stick with the Utica. Just it sounds like you have more than ample takeaway if I hear right, on the Southern Utica, but I just want to make sure it was clear for plans on the Northern portion that. Bill, I think you’re one of the guys just talking about it. Maybe just talk about the infrastructure plans and if that would capture any of the upside if you decided to boost activity in that northern area.
Lance Terveen: Yes, Neal. This is Lance. Good morning. I think what makes this place so unique is that it is just positioned to so much existing capacity. I mean, actually, in fact, when — there’s even some idle processing capacity and fractionation, ideal processing capacity that’s nearby on our acreage. So when we look at that just from an infrastructure standpoint, we’ve been focused on more just the gathering infrastructure. And as Jeff mentioned, we put into service our pipeline in the North and then we’re going to have a pipeline in the South as well. So we’re going to have plenty of running room, just long-term running room as we think about the infrastructure that we’re putting in place along with third parties and then also the available capacity that’s in place.
Operator: The next question comes from Doug Leggate of Bank of America. Please go ahead.
Doug Leggate: I’m not loving the new dial-in system, but thanks for getting me on. Ezra, I wonder if I could hit first two things. I want to hit the cash return change and the evolution of the portfolio as you look forward. So dealing first with the 70% number, that obviously is subject to whatever the level of capital is. And I guess, the flow on the machine is that 60% of free cash flow or 70% of free cash flow is still free cash flow, which means it’s entirely dependent on what you decide as a discretionary spending, which to me doesn’t mean a whole lot. So what commitment can you give or at least guidance or framework for what the level of spending looks like in order for us to interpret what the increase in free cash flow commitment actually means?
Ezra Yacob: Yes, Doug, it’s a good question. We based our cash return model on free cash flow for a couple of reasons. It’s simple but it’s also pretty dynamic, and it’s close to the intentions that we have over a range of different price scenarios. So we’re not entering into an area where we need to modify the commitment going forward. It’s something that once we come out with that commitment, hopefully, our shareholders can see by our track record that once we come out with something, we’re very consistent with it. The 70% return is a minimum of free cash flow is pretty consistent with our longstanding strategy, I would say, to build shareholder value and position the company to be able to do it through industry cycles. And that means that reinvestment at the right pace in our high-return inventory, that’s the best thing we can do to create shareholder value.
Ultimately, the cash return strategy, it begins with our commitment to a growing and sustainable regular dividend which, again, we raised that. We increased that just 10% and that dividend has never been cut or suspended over the 25 years that we’ve been paying one. In addition, we’ve committed now to return either additional specials or buybacks to reach that 70% minimum commitment. For us, hopefully, the increased commitment, the reason we like the 70% of free cash flow is, it’s consistent with our free cash flow return in that it puts the emphasis on our regular dividend, which we think is peer-leading and competitive with S&P 500. And again, we feel that we can maintain current levels of production and cover that base dividend at WTI prices as low as $45.
