Shane Young: No, I would agree with it. I mean I would only say, Neal, again, we have a lot of peers today that are probably more focused on just maintaining and keeping things flat. And so I think in that regard, Coterra is differentiated and that we can still generate consistent profitable growth in the current price environment that we sit in.
Neal Dingmann: Yes. Great add-on, Shane, I agree with that. And then second question, just on the cost reductions, very noticeable on the prepared remarks, you talked about the simul-fracs have potential for the 5% decrease, and taking the covering [ph] costs all the way down up to 15%. Can you remind me prior to this or a quarter or two quarters ago, into deflation next year? Are we all just thinking kind of maybe a 5% deflation, I am just wondering kind of how you are looking at sort of total, I don’t know if you want to call it deflation time, but sort of all in lower cost next year, versus maybe what expectations were a quarter or two quarters ago?
Blake Sirgo: Yes. For the total program, we are still estimating about 5% deflation going into ‘24. That’s based on what we know today, these simul-frac savings would be in addition to that. But that’s just for this one project, and we have a big portfolio, so it’s gone across the board savings. We are in the middle of negotiating our rig and frac contracts for ‘24 right now, and look forward to updating that when we put our plan out in February.
Neal Dingmann: Thanks guys. Great update.
Operator: The next question comes from the line of Matt Portillo with TPH. Your line is open, Matt.
Matt Portillo: Good morning all. Tom, maybe a question on the Anadarko Basin to follow-up on Doug’s question. It sounds like next year, you will have a relatively healthy level of activity. But I am just curious, maybe looking into the medium-term, it is an asset where you still have about 240 locations that compete for capital. It’s also a base that seems to be well situated to meet some of the pull demand from an LNG perspective. Just curious what you need to see either from a cost perspective or well productivity perspective or maybe a macro change, to see a healthy level of rig activity in the basin moving into the second half of the decade.
Tom Jorden: Well, look, what I would love to see is long-term LNG contract guarantees saw uplift in price, we would be willing to get after it. So, I am looking at Blake, getting him working on that. We do have an amazing asset in the Anadarko Basin. It’s ready to go. I mean we when we look at the Permian, the Marcellus, Anadarko, Coterra is very well positioned for exactly what was designed when we formed it. We can react to liquids prices or natural gas prices with a healthy inventory. When I say healthy, I mean a deep and robust inventory, and really, more and more people are seeing that in our asset base. But we would have that option. I mean that’s, Blake, do you want to comment on that?
Blake Sirgo: Yes. Just, the Anadarko is very well positioned for LNG. It’s got a straight shot to the coast. There is lots of new facilities coming online there. All of them intrigue us. As Tom said, we would love to find one that guarantees us some great tailwinds to our cash flow. We haven’t found that yet. But we are focused on how do we do an LNG deal that minimizes our total cost, but also gives us some flexibility. We do like to move capital around and we hate for the tail to end up wagging the dog on that.
Matt Portillo: Perfect. And maybe just a follow-up on gas specifically. Tom, just curious how you all are feeling about the hedge book heading into 2024. It still seems like it might be a bit of a transition year with some challenges on the inventory carryout from ‘23. And so just wanted to see how you all are thinking about your hedge profile for next year and then maybe longer term philosophy around hedging for natural gas.
Tom Jorden: Yes. Shane, why don’t you take that?
Shane Young: Yes, sure. So look, over the course of the last quarter, we did add some hedges to the book. And again, I think historically, we have been pretty consistent in messaging, we want to be somewhere between 20%, 25% to upwards of 50% hedged, any sort of forward 12 months, 18 months window. And so we try to get back into that posture. I think as you look today, we are positioned that way, plus or minus, around 25% to 30%, on the gas side, if you include the physical hedges and the financial hedges in concert. And we think that’s a good place to be, but we will continue to monitor it as we go. You will also find that if you just look at the shape of that hedge book, it is probably a little bit front half of the year weighted, a little less second half, not to the extreme, but there is a little bit of a slope to that profile.
Matt Portillo: Thank you.
Operator: Your next question comes from the line of Roger Read with Wells Fargo. Mr. Read, your line is open.
Roger Read: Yes. Thanks. Good morning. Just, come back to some of the productivity questions. There is obviously a portion of it you have talked about that’s above ground driven, and there is a portion that’s below ground driven. I think the above ground is not too hard to understand from a logistics standpoint, e-fracs switch over. But the below ground, what have you been able to do there that’s led to better performance per lateral foot?
Tom Jorden: Well, one of the things we have done, Roger, over the last few years, has really spent a tremendous amount of time studying the optimum development scheme for a drilling spacing unit. We have a little different spacing assumption than others. And I think we are – as we apply that throughout our portfolio, we are seeing ongoing benefits from it. We think that with fewer wells, we can extract the same amount of resource. Our machine learning team has been instrumental to Coterra in that understanding. And they continue to drive a lot of our thinking. It’s been a remarkable piece of technology to adopt internally, and it’s had direct benefits in our capital efficiency.
Roger Read: As we think about wider spacing, how does it factor in with the total inventory like the [Technical Difficulty] or are we thinking about enough of a run that you are not concerned over the next several years?
Tom Jorden: Yes, you were breaking up there, but I believe your question is with wider spacing, how does that impact the duration of our resource. We have modeled that into everything you see in our deck, that’s modeled in. And we don’t count number six on the map, quite frankly. Although everybody loves a high number there, we look at – I mean if we can drill fewer wells and get better financial returns and not leave stranded resource, that is the holy grail. And we think we are never there. Well, we are moving in that direction in a very positive way, and that’s part of what’s underwritten our results this quarter.
Roger Read: Alright. Thank you. Apologies for the break.
Operator: Your next question comes from the line of Leo Mariani with ROTH. Leo, your line is open.
Leo Mariani: Yes. Hi. I just wanted to ask on the seventh Permian rig here. It sounds like that was kind of always part of the plan and perhaps you guys just accelerated. So, I just wanted to confirm that was something that was going to be in place kind of all year in 2024. So, I mean it sounds like you are probably going to have a little bit more all-in Permian activity next year?
Tom Jorden: Well, I will tell you, if that was pretty big, there are a lot of people down in the hallway that have scars from us finding over that. But I will let Blake answer the question.
