Subhasish Chandra: And in terms of sort of application here in the early months of ’24, how you visit versus, say, last year?
Paul Rady: I think it’s a development in the last 6 months to a year where we’ve perfected it. And it will continue on.
Operator: Our next question comes from the line of Bert Donnes with Truist.
Bertrand Donnes: Just wanted to ask around the data center demand question a little bit differently. You’ve continued to kind of avoid the temptation to go overseas with an LNG contract. Is there may be a thought process that if we see a data center-driven boost, maybe there’s no reason to lead to the U.S.? And does that lead you to maybe trying to lock in a long-term contract in the U.S.
Michael Kennedy: Yes. No, it wasn’t around the data centers. It’s just around we’re the only company that can really get molecule to the docks or to the LNG actual facilities. So we didn’t have any need to enter into long-term contracts around that. We’ve already done our commitments on the pipeline in itself. And so we just wanted to stay floating in retain optionality for us on what that pricing would look like when they have to compete for our gas. But with the data centers, that actually adds more, obviously, demand for that gas. So that competition just continues to grow.
Bertrand Donnes: Okay. And no interest in maybe boosting legacy Northeast volumes for a long-term contract or anything direct, you’d rather just say indirect for both kind of uplift?
Michael Kennedy: Yes. Yes. That’s our philosophy, stay in the Gulf Coast. I mean, an interesting thing that it was highlighted in our prepared remarks, TGP, that 500 line we talked about. This time last year, what is that a $0.03 premium for next year, and now it’s at $0.40 that is going to continue to go higher. So as it gets closer and closer, you’re going to see the premiums continue to go higher in the Gulf Coast, and that’s where we sell our gas.
Bertrand Donnes: Great. And then changing gears. On the Marcellus rates, on a per foot basis, it was surprisingly strong quarter-over-quarter they were shorter laterals. Is there may be some logic going on that the shorter laterals are more economic and maybe 18,000-foot laterals are a little bit too long? Or is that just — it’s one data point and not shifting gears?
Michael Kennedy: Yes. I’d say it’s one data point. Generally, the longer laterals are more economic to spread the cost around longer lateral foot, but we’re so good drilling and completing these the longer lateral still provide the economics that it would suggest.
Bertrand Donnes: So maybe on the tail end, there will be a stronger later dated production from the longer laterals?
Paul Rady: Yes. I mean, I would say, a shorter lateral will clean up more quickly, will dewater more quickly. And so it will get to peak rate in a shorter period of time. But over the longer run, as Mike just said, the economics are so much better when we’re going out to 16,000, 18,000 and even 20,000 feet. Those are really big wells. And so you wait a little longer until you get to peak rate, but it’s worth it.
Operator: Our next question comes from the line of Neil Mehta with Goldman Sachs.
Neil Mehta: I had a couple of questions on capital allocation. The first one on Slide 10, you’ve done a great job of getting your debt down to this level, and you talk about the next area to deploy free cash flow is to pay down your credit facility balance. So maybe curious on your perspective of how shareholder return specifically buybacks fit into this equation. And given the strengthening of the balance sheet, when do you think you’re at that inflection point to buy back stock?
Michael Kennedy: Yes. I said in the remarks, the first call on that free cash flow is to pay down the credit facility and that near-term maturity in ’26. So that’s about $500 million. And then after that, we’ll return to our 50-50 strategy of paying down debt plus buying back shares. It will depend on commodity prices when we actually achieve those. But based on today’s commodity prices, it’d be in the first half of next year.
Neil Mehta: Helpful. And then we’ve seen a lot of consolidation across the E&P space, across energy space broadly. You have a really deep inventory. So I would just love your perspective on how do you see Antero fitting within the M&A landscape? And is the right strategy and organic strategy?
Michael Kennedy: We do believe the right strategy is the organic strategy. You saw we were able to add, I believe, 19 locations in the first quarter, we had $26 million of land. That’s highly economic compared to how much locations go for in the M&A landscape. So — and we continue to consolidate our areas of operation right where we’re drilling these terrific wells and just continue to build out our position in the liquids portion of the Marcellus. So we believe that’s the best way to add value and continue to increase our 20-year inventory position.
Operator: Our next question comes from the line of Jacob Roberts with TPH.
Jacob Roberts: Dave, I wanted to circle back to the liquids market, and I apologize if you did hit on this in your answers, I may have missed it, but I was hoping you could comment just on storage levels at the moment. Specifically, them being above the 5-year it appears as well as the production coming out of PADD 3 and just where do you see those playing out through the summer?
David Cannelongo: Jacob, this is Dave. If you go back to the first quarter, we actually had that polar vortex in January went from the top of the 5-year range to the 5-year average and then kind of continued along that trend until the last 5 or 6 weeks, we’ve had I would say some pretty unusual EIA data. It didn’t really change at all for 1 month, 1.5 months, and then we had significant change last week and then a below expectation build this week. So we are back kind of in that between the 5-year range and the top of the range below last year, but above that 5-year average. And we’ll see what the inflection point looks like, how does that slope rise over the summer. I think there’s a lot of different forecasts out there on propane production this year.
Hard to say exactly who’s right on that. We do pay attention to the rig count in all the basins and watch that. And so that’s, again, part of what drove our earlier comments on just taking that small amount of domestic Mont Belvieu propane exposure we have doing some hedging there this year. But sorry, I answered all your questions there, Jacob?
