Brendan McCracken: Yes, I’ll flip it to Greg here. But type curve is largely stable year-over-year. You can see that from ’21 to ’22 to our projected ’23. We got real high confidence in that ’23 curve. And Greg, you can talk about some of the things you’re excited about that the team is doing on completions there to drive that productivity.
Greg Givens: Yes. I think one of the first things I’d point to is we continue to develop our cubes in the Permian. It’s a co-development approach that we’ve had since we’ve entered the play. So we overall get very consistent results in aggregate, but there is some variation in the individual well results as you move around the play. The team has really been working most recently on their stage architecture. The amount of spacing between stages, the amount of sand we put in each well and continuing to drive efficiencies there and seeing really positive results, as you saw in the fourth quarter results we showed on the slide. So really, the thing I would point back to is that unlike maybe some other operators, we’ve not changed our approach over time.
We continue the same cube development approach across the asset position, continue to optimize our completions on every pad. And despite some variability early in the year, we were really encouraged later in the year with how the results came out, and we feel like that will translate into good performance in ’23.
Brendan McCracken: One thing Greg mentioned that I’ll just highlight a little bit that I’m excited about is what the team is doing with real-time frac monitoring. So we’ve been able to make adjustments on the fly because we’ve got a lot more live telemetry both in the wallet were fracking and then in the wells around them. And that’s really helping us both from a productivity perspective, but also we think from a cost perspective. So that’s an exciting one to keep watching as we go through ’23 here.
Lloyd Byrne : Okay. Great. So ’23 looks more like the fourth quarter? And then — on the cost structure, is that just scale in the Uinta going forward? And then maybe just give us an idea of how much acreage you guys have there?
Brendan McCracken: Yes. I’ll let Greg hit on the acreage, but the cost structure is just scale. So we’ve been drilling a pretty small program through the last several years to really delineate and get the confidence that we now have. And so we know for sure that as we bring that load-leveled rigs and spread between the Bakken and the Uinta, that’s going to help drive those costs down. And we’ve seen that when you look at — you remember, we tend to look at these things on the pacesetter basis, and we’ve got real good indications on the pacesetter front that we’re going to be able to drive these costs down with a bit more scale on the program. And Greg, you can talk about the acreage.
Greg Givens: Yes. On the acreage side, we have 130,000 net acres in the play, and that’s with multiple development horizons across that acreage position. And it’s still about 80% undeveloped. As Brendan mentioned, we have now around 100 horizontal wells in the play, but have significant running room left there as we go forward and execute on our plans.
Operator: Your next question comes from John Abbott at Bank of America.
John Abbott : Our first question, Greg goes to you. It’s on the condensate oil and condensate guidance for the first quarter. Understandably, it’s lower given the slowdown of activity in the fourth quarter. The quarter is now about 2/3 complete. Just wondering if you could give us an update of where current oil and condensate production may be at. And are we — have we already seen the lows on oil and condensate production for the quarter.
Brendan McCracken: Yes. John, appreciate the question. The best guidance we give you is we’re on track for the guidance we’re issuing today. So — and what was the second part of your question?
