Q: Tom and Shane, congrats on the great results. Tom, I want to start off in the Marcellus, and you deferred 12 completed wells for later in the year. The plan still calls for about 29 wells to be put online. Could you maybe talk us through how are -- what are the market conditions? Is there a specific price? Or is there a supply or demand equation that you're looking at to, one, bring on the 12 wells? And 2, how would you think about the rest of the program for the year? A: Thomas E. Jorden - Coterra Energy Inc. - CEO, President & Chairman: Thank you, Nitin. Well, first, I'm going to say if there's a specific price or a complex formula, nobody has shared that with me yet. But we're looking at our received price. And quite frankly, we sell into indices. Leidy is the one that we typically point to. And when it's -- I would say, when it's sub $1.50, we really look at that and we say, okay, what's the outlook for that? And we do have transportation and LOE that comes off of that. And I wouldn't say there's a particular price. But I'll say this, we do have a very low cost of supply.
Q: Great. Tom, and I appreciate that. I want to shift to the Permian and talk about the Windham Row. Could you maybe talk a little bit about what have you seen, obviously, adding a few wells in the Harkey is a positive. But what are you seeing? And what are some of the lessons learned? And if you can walk us through the 5% to 15% cost reduction that you're seeing, if I think about $1 billion spend in the Permian this year, could we look at something which is 10% less capital spend in the Permian for the same result down the road? A: Thomas E. Jorden - Coterra Energy Inc. - CEO, President & Chairman: Yes. I'm going to hit the Harkey and let Blake look at the cost reduction. Our general observation in a lot of our Delaware program is that in our assets, our observation has been that whether we exploit these reservoirs 1 layer at a time or not that we don't really see any incremental recovery out of a drilling spacing unit.
Q: My first question is on cash return. You returned 90% of free cash flow this quarter. But I wanted to get maybe some broader thoughts on just the overall philosophy given your views on the valuation of the stock. You recently issued $500 million of notes to help refund the payment of the $575 million maturity later this year. How did cash return, Tom, attractiveness of the valuation of the stock play into that decision? A: Thomas E. Jorden - Coterra Energy Inc. - CEO, President & Chairman: Yes, I'll let Shane handle that one.
Q: Great. And Shane, what do you view as the minimum cash you'd like to keep on the balance sheet? A: Shannon E. Young - Coterra Energy Inc. - Executive VP & CFO: We've gone as low as $600 million over the last, call it, 7, 8 quarters. And -- and again, I think that probably as low as we go. We target $1 billion. We've been as high as $1.4 billion. And I think you'll continue to see us live somewhere in that range. It's a broad range. But I think you'll continue to see us reside within that range.
Q: Yes, it's a sleep [well] at night balance sheet. My follow-up is just maybe for Blake is your Marcellus well costs are guided down to $950 a foot in the second half versus $1,200 a foot in the first half. Talk to us about that decline? And what's the good go-forward run rate? A: Blake A. Sirgo - Coterra Energy Inc. - SVP of Operations: The decline is really just driven by the well set that we're bringing on that part of the year. We have some great, really long laterals that are in there and they trend on a lower dollar per foot. Run rate is kind of hard to pin down exactly, one, it depends if you're talking upper Marcellus lower Marcellus. I think it could be anywhere from $1,000 to $1,200 per foot. It's probably going to flow in there. Lateral lengths could drive that a little lower.
Q: Tom, long-dated gas because they have been moving higher on all the data center growth excitement, how would you think about capital allocation between Anadarko and the Marcellus, if the forward curve is right, and we're in the $3.50 to $4 range, in late '25, '26? And Oil is still healthy, call it, in the 70s. How would you think about that allocation? A: Thomas E. Jorden - Coterra Energy Inc. - CEO, President & Chairman: Well, I wouldn't have to thank very hard. I'd look at the incremental economics and we go where the best economics are. We have tremendous gas resources in both basins. The -- and Anadarko has natural gas liquids, which really provides an economic boost. But the Marcellus has amazingly low cost of supply, and we produce pure methane, which we just have to compress and put into an air state line, so -- or a pipeline.
Q: It's exciting. We'll wait for a word. And then just turning back to Windham Row. Just curious, you mentioned doing simul-frac on half the wells. What's the limitation there, why not doing on all the wells? Is it comfort with the technique or tag configuration or scheduling the frac crews? Just some color on the limitation there? And if there's any upside to doing it on more than half? A: Blake A. Sirgo - Coterra Energy Inc. - SVP of Operations: Yes, Scott, it's Blake. I'll take that. That's a great question. And I think it's something that gets missed sometimes in simul-frac is you really have to have an optimal pad with a lot of wellheads on one pad to optimize the cost savings. There is sometimes where you might some frac and save no money because a simul frac crew is just basically 2 frac crews smashed together. So you're paying a lot of money for that crew to be there. The efficiencies come when you have a lot of wells on one pad. And just the layout of these drill spacing units doesn't always give us enough wells per pad to use simul-
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