As we get closer to that number or in and around that number, look for us to grow that profile as well. And then further beyond that, when you look at the business moving forward, Dennis, we’d like to be in the neighborhood of about $1.7 billion of absolute debt is how we’d like to run the business for the long-term. And that would equate to 1x debt to cash flow at $50 WTI. And when you’re in that type of level, you’re pretty much bulletproof from a balance sheet standpoint. So when we talk balance sheet optimization, that’s what we’re gearing towards is that type of level. And I can tell you I’m pretty pumped myself on a billion dollar net reduction here over, call it a 12-month period ideally, Dennis, next time we’re talking, we can say we’re doing even more than that, but certainly a good start.
And Ken, I don’t know.
Ken Lamont: Yes. The only thing I’ll add to that Dennis is we’re obviously very highly hedged here the back half of this year. So 45% fixed price hedged on oil, 30% on gas, and that extends in oil into 2025 as well in the first half about 20%. So as far as our ability to harvest that retained excess cash feels very comfortable, just given the level of the hedge books as well too. So that’ll provide a little more certainty in bringing that in and bringing that debt down.
Dennis Fong: Great. I appreciate the context there. I’ll turn it back. Thanks.
Craig Bryksa: Thanks, Dennis.
Operator: Thank you. Your next question comes from Amir Arif with ATB Capital. Please go ahead.
Amir Arif: Thanks. Good morning, guys. Just a few quick questions. Just on those Karr West wells, I know it was previous completion approach, but just the variability between the 400 to 1,400. Can you just give us a sense of what was causing that and if there were any lower Montney wells included in those pads?
Craig Bryksa: Yes. I think it’s best for Ryan to grab that one.
Ryan Gritzfeldt: Yes, good question. So the 5 of 11 pad, it did have three lower, or it does have three lower Montney wells. We spoke a little bit at our Investor Day at how the previous operator drilled through a fault on that pad. And so there are a handful of wells that have shortened lateral lengths because of that. And we also think that the lowers were drilled a little bit too low, close to the bottom, the very bottom of the Montney zone. So we think that definitely some of the wells have been impacted by that. Some of the B and the C Montney wells are strong at that 1,400 BOE a day. What we’re excited about here go-forward. So we’re bringing a pad on right now. It’s our 2 to 10 pad. We’ll have IP30 results in the next quarter.
Still at the previous operator well spacing, but with our fluid system in our frac design. So look for those results. And then we’re also right now drilling a pad down in that Karr South, Karr West area, the 5 of 23 pad, where we’re testing the lower Montney again. But we didn’t drill those as low as on that 5 of 11 pad. So look for that pad, the 5 of 23 pad, where it’s our well spacing. So a little bit wider well spacing and our fluid system for our frac. So look for those results in the summer.
Amir Arif: And I don’t believe you booked too many lower Montney wells like, it could be inventory at B from that zone or the two or three.
Ryan Gritzfeldt: Yes, I think — yes, there’s a very small amount of lower Montney booked, but, yes, if you apply a fairly conservative well spacing, there’s probably conservatively 150 and 200 lower Montney locations in that area.
Amir Arif: Okay. Sounds good.
Craig Bryksa: But just a handful booked.
Amir Arif: Yes, yes. And then just a question on the different completion approach of the sliding sleeve versus plug and perf. Doesn’t seem to be making much of a difference on the performance, but obviously lower well costs. Can you just give us a sense of how much you could reduce your well cost and when you’d be comfortable enough, potentially shifting more to plug and perf and what the magnitude of the well cost saving would be?
Craig Bryksa: Yes. So this is Craig. Extremely excited about how those wells have came in. Do know that the plug and perf, the IP wasn’t quite as high as the sliding sleeves. So the sliding, which makes sense when you think of that single entry point. Extremely excited, though, with how the operations team went through on the plug and perf and the success we had. And really, your point there, the big win on that is twofold. One, ideally, the decline rate is a little bit shallower. And then two, the cost of those wells was about 500,000-ish less than what we are seeing on the sliding sleeve. So it’s a significant win operationally for the team, and then as well on the cost structure moving forward. So we do have a few more of those wells that we’re going to be doing this year. And we built in that, that, call it cost savings into those wells as we see it in our 2024 program. Ryan, I don’t know.
Ryan Gritzfeldt: Yes, no, that’s good.
Amir Arif: I appreciate that color.
Craig Bryksa: Did that help you?
Amir Arif: Yes, absolutely. I appreciate the color. And just one final question, just on the open hole multilateral over in Saskatchewan, I believe the economics for your open holes are significantly better than your frac well. Is this an area where eventually, should we be thinking about you switching over to open holes for the full development eventually, over time, or does open hole only work over certain parts of that play?
