And I think certainly, as you see some operators start to run thin on inventory in the basin. I think it provides opportunity for companies like EQT to not only capture better in-basin pricing but actually really grow our own production into that and take a bigger share of the pie. So we – that’s really our expectation over the next couple of years. We stand ready to respond to it, but we see it really more as a tailwind than a headwind.
John Abbott: Very, very helpful. Thanks for taking our questions.
Operator: Your next question comes from the line of David Deckelbaum with TD Cowen. Please go ahead.
David Deckelbaum: Good morning, guys. Thanks for taking my questions. I was hoping just to dig in a little bit more on just Arun’s question. I think you will highlight the lower implied maintenance CapEx going into ‘25 and beyond. I guess if we think about that delta of – I guess, $100 million, $200 million next year, is most of that just coming from continued synergies on the Tug Hill assets? Is it lower base decline? Is it implied cost savings? Is it less infrastructure spend? Or is it sort of all of the above? Or what’s driving the bulk of that?
Toby Rice: Yes, I would say it would be all of the above. Teams are looking across all angles of the business, looking for ways to shave pennies off the program.
David Deckelbaum: And then maybe just to talk a little bit about just the LOE side or production cost side. I think you’ve highlighted in the deck, especially on Slide 12, the benefits of the water system. The guidance, obviously, this year, I guess, now inclusive of the Tug Hill deal and some other moving parts, your LOE is moving higher. Are you including the expected benefits from the water system investments in your ‘24 guidance around LOE? Or is that something that would be additional upside?
Jeremy Knop: You’re talking about the savings of $40 million that we referred to in the prepared remarks or what are you referring to?
David Deckelbaum: Yes, the $40 million, and I guess like the completion of the systems in ‘24?
Jeremy Knop: Yes. So those investments, I mean, you don’t get an instant response to the same year. I mean the time it takes to build those systems, you usually see that savings show up in the following year and the years after that. So like the water system investments, the additional $80 million we’re spending this year in interconnecting really the Chevron Water Systems, what we’ve built out the Tug Hill systems. I mean that’s really going to pay dividends for us, not only in completion costs over the coming years just through lower water cost and water recycling, but also through LOE. I expect more of that to show up in 2025 and beyond where you start seeing that move the needle.
David Deckelbaum: Appreciate the color.
Operator: Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Please go ahead.
Kevin MacCurdy: Hey, good morning. I had a couple of questions on the liquids production and pricing. The first question is, it looked like ethane production was lower than guidance for 4Q, while pricing for the other NGLs was higher than what we expected. Can you give some more detail on those two items and maybe remind us how your heavier NGLs are priced?
Jeremy Knop: Yes. Look, I would say on the ethane side, it really just comes down to what’s going on with the Shell cracker both in terms of Q4 actuals and also the outlook for 2024. So that’s really going to be the main driver of that. I think in the guidance we gave – assumed that – our underlying assumption there is influenced by our expectation that, that cracker plant is not fully online really for another year. But that’s something that I think we and our peers around us in Southwest Appalachia are having a haircut a little bit just due to the continued startup delays on that facility.
Kevin MacCurdy: And how are your NGLs price?
Jeremy Knop: Really just based on index in basin, I wouldn’t say there was anything that’s really changing as it relates to those dynamics.
Kevin MacCurdy: Great. And looking at the forward guidance, it looks like liquids, excluding ethane, declines from 4Q volumes and then again from the 1Q volumes. What’s driving the decrease for the heavier liquids?
Jeremy Knop: Yes. I would simply chalk it up to just – we have some pretty lumpy pads in the way we develop. It really just comes down to some of the liquids-rich pads that we acquired from Tug and how that alternates with some of the more of the Utica pads that get turned online or other Marcellus, just dry Marcellus activity. So it’s just kind of normal course lumpiness. But I wouldn’t expect any sort of long-term trend or change from what you’ve seen recently.
Kevin MacCurdy: Okay. I appreciate the detail. Thank you.
Operator: Your next question comes from the line of Ati Modak with Goldman Sachs. Please go ahead.
Ati Modak: Hi, good morning, team. Thank you for taking the questions. You talked about the capital allocation priorities this year highlighted debt pay-down as the focus, maybe help us understand the thought process around how your view of the macro environment factors into that decision matrix between the different pieces and how we could expect that to evolve?
Jeremy Knop: Yes, for sure. It actually is really driven by the macro in many ways. I think at a high level – I mean look, I think we are as bullish as anybody as it relates to the gas macro outlook as you get to kind of mid-‘25 into 2026. So, really, what we have to weigh on our end is if we did – if we reallocated those dollars instead of debt pay down to something like a buyback and accelerating that right now, it would probably in turn cause us to want to go hedge more and protect the balance sheet in case you just had a bunch of macro factors not go according to plan in that time period. So, when it comes to opportunity costs for us, it’s really just a simple question of what’s the upside swing in the dollars buying the stock versus the upside, leaving that more un-hedged.
And I think with the asymmetric expectation we have to where pricing could go, certainly by the end of 2025 as you get into 2026 that – I mean that dwarfs any sort of return we can get just by buying back stock right now. And so for us, the question is what ultimately is going to create the most shareholder value. And so really, we would rather be patient on the hedging front and use our dollars near-term to just to de-risk the balance sheet. So, really by doing that, we think that actually gives investors more upside and exposure to gas prices. And if for some reason things don’t work out on our expectations on the macro, it provides more downside at the same time. So, that’s why we have allocated and plan to allocate the way I already explained.
Ati Modak: Got it. Thank you for that. And then you mentioned the low cost structure as an advantage. You mentioned a couple of drivers there as well, but I was wondering if you could provide some more color on those pieces and what drives it down further over the next few years?
Jeremy Knop: Yes. I mean it’s a couple of kind of key things, and it’s really contractual. So, I mean our gathering rights, I mean you have seen our guidance with MVP coming online, the impact on just the full year is those rates stepping down at the same time MVP goes into service. Those further step down, as we have talked about before, into 2026, ‘27 really hit a bottom in 2028. And so really, those rates are Equitrans contract that last year were about $0.80 for just the gathering rate hit a bottom of $0.30 by the time you get to 2028. On a blended basis, I mean they don’t gather all of our production, so on a blended basis, it’s a little more muted. You don’t see that full $0.50 drop. But that is a contractual step down that is part of our longer term forecast.
And again, just a tailwind to us even if you have flat pricing and everything else in the environment doesn’t improve. And then the other piece of that, too, as we talked about last quarter, these supply deals that we signed downstream MVP, and so that’s going to also improve our realizations, our realized pricing by $0.15 to $0.20, which over our production base is that kind of rounded $300 million of free cash flow. So, it’s really the combination of the two. There are some offsetting factors in there, but around like compression adds and you have a tailwind as you pay down debt, your interest expense falls as well. But by the time you get to 2028, we see that breakeven cost structure about $2.30, down about $0.30 from where we sit right now.
So, it’s a continued tailwind. And look, as we have talked about, I think over and over again, I think that is really unique to EQT. I think where you are in the shale revolution right now, a lot of that core inventory is depleted or rapidly getting depleted. I expect a lot of cost structures to be rising over that period. So, it’s really a unique differentiating characteristic of EQT and it’s really just further like share price upside, free cash flow upside relative to what you get anywhere else.
Ati Modak: Thank you. I appreciate that. I will turn it over.
Operator: Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead.
Scott Hanold: Yes. Hey. You all kind of indicated that your breakeven point this year is around 220. And how do you think about that with the gas cracker, if gas prices do, say, continue to trend on the direction they are related to weather, whatnot, I mean would you guys be willing to make changes to make sure that you guys generate positive free cash flow, like so. The bottom line question is like when you start getting around that 220 threshold, would you be willing to cut a little bit more to kind of preserve free cash flow rather than burn some cash?
