Operator: Thank you. Your next question comes from the line of Michael Scialla with Stephens. Please go ahead.
Michael Scialla: Good morning, everybody. Wanted to see, you talked about the potential for the $150 per foot of savings with the operational efficiencies that you’re applying to the Tug Hill assets, what needs to happen for that to become a reality? And I guess where are those relative costs based on the wells completed there so far?
Toby Rice: Well, the cost savings that we had, the $150, about half of that is operational efficiency, the other half is well design. So for that to materialize, we need to continue executing in the field and putting up some big numbers on drilling speeds and completion pace, obviously doing it as safely as possible to accomplish that. The other thing I’d say on the well design side of things, that’s probably going to take a little bit more time to materialize because we will take a more methodical pace on the science. We don’t just run out and make all the changes at once. So there’ll be some monitoring time observed there. But when you step back and think about these type of operational synergies that we’ll achieve, the $150 a foot could translate to about $50 million of total spend, which would translate to about, call it, $0.02 to $0.03 lower on our cost structure on top of the previously planned $0.15. So I hope that adds some more color to your question.
Michael Scialla: That’s helpful. Thank you. And I wanted to ask about the – your agreements with the LNG. In terms of – any comments there on the discussions you’re having with potential end users of LNG? And would any agreement there be contingent on converting your HOAs to binding agreements? Sort of what’s the process that needs to play out there?
Jeremy Knop: Yes. Great question. There’s actually been a lot of interest, a lot of parties reaching out to us about this so we’ve been really encouraged by that to date. In terms of sequencing, we do need to get those long-term agreements signed on the supply side before signing the ultimate SPA. But it’s really a – it’s a parallel process and so we are working through that. In terms of timing, it’s probably six to 12 months out before kind of the whole package of those is done. But look, we’ve been really encouraged by the progress to date.
Michael Scialla: Thank you, guys.
Operator: Thank you. Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Please go ahead.
Kevin MacCurdy: Hey, good morning. The firm sales contracts you locked in starting in 2027 are very impressive. With those margins derisked, do you have any plans to grow into the volumes? And is that baked into your 2024 to 2028 free cash flow outlook?
Jeremy Knop: We certainly have the option to. We just got these deals signed a couple of weeks ago so we’ve not made any long-term plan adjustments. But that is an exciting option that’s really paired with this from a value creation standpoint and something that we will evaluate in time if the price environment merits that level of activity.
Kevin MacCurdy: Got it. So it’s not baked into that outlook at this time, the 60% free cash flow of BV?
Jeremy Knop: That’s right.
Kevin MacCurdy: Great. And then you mentioned the $0.55 of NYMEX for 2024. I just wanted to get a little bit more clarity on whether that included basis hedges and any Btu uplift?
Jeremy Knop: Yes, that’s right. It’s all in.
Kevin MacCurdy: Great. Thank you.
Operator: Thank you. Your next question comes from the line of Jean Ann Salisbury with Bernstein. Please go ahead.
Jean Ann Salisbury: Hi. Good morning. I just – on the 2 MPA of HOAs, do you have an ideal share of portfolio linked to global gas prices? And what’s kind of your thinking that underpins that ideal share if you do?
Toby Rice: Yes. I think if you step back and said and looked at this purely from a market diversification perspective, somewhere around 10% exposed to international markets feels balanced. But this will ultimately depend on what type of netbacks that we’re able to achieve by connecting to that market, and that will sort of turn the knob on where we sit with that. But right now, as it stands, this 2 million tons per annum for us is us putting our toes in the water. I mean, it’s a significant amount of volume of the gas and provide a ton of energy security for customers around the world, but it’s less than 5% of our total volume. So we’re going to take a measured approach in accessing this market.
Jean Ann Salisbury: Great. That’s all for me. Thanks.
Operator: Thank you. Your next question comes from the line of Paul Diamond with Citi. Please go ahead.
Paul Diamond: Good morning and thanks for taking my call. Just a quick one. You guys talked about the kind of that theoretical max is 500 days versus the average of about 400 currently. I just wanted to see if you guys could put a little bit of clarity around, I guess, how you see bridging that gap. Like how close can you get to the 600 and over what timeframe?
Toby Rice: Yes. So the theoretic max is around 600 hours per month, and we set plans for 400 and hope to repeat the 500 hours per month. Listen, the biggest thing is going to be the logistical support for these frac operations. And that’s all about getting as much water and sand to location as possible. We’ve spent a lot of time on the sand side. There could be some infrastructure investment opportunities for us on that pace to bring transload facilities closer to the actual frac sites. Those opportunities are relatively small, $8 million to $10 million upfront cost but they can pay dividends over time. And then obviously, we understand the benefits and economics behind water infrastructure. One of the biggest benefits with EQT and one of the benefits of our having a deep inventory in this area is we’re going to be able to make these investments because we have so much inventory that’s going to benefit from these investments.
And that certainly is a key differentiator to think about when you think about these opportunities present within EQT versus others.
Paul Diamond: Understood. Thank you. And just one quick follow-up. You guys talked about the incorporation of MVP and coal retirements producing about 4 Bcf of incremental demand out of Appalachia. Just want to see if you could give a bit of clarity around the timing of that. Is that over the next one year, five years? Just how do you see that kind of developing?
Jeremy Knop: Yes. So I mean, half of that is obviously MVP at 2 Bcf a day. And the rest of it, we kind of look at it over the next five years kind of chipping away. It’s not obviously an annual growth number, but we see over that timeframe that demand showing up kind of through those different changes in the market.
Paul Diamond: Understood. That’s all for me. Thanks for your time.
