EQT Corporation (NYSE:EQT) Q4 2024 Earnings Call Transcript

EQT Corporation (NYSE:EQT) Q4 2024 Earnings Call Transcript February 19, 2025

Operator: Thank you for standing by. My name is [Jale] (ph), and I will be your conference operator today. At this time, I would like to welcome everyone to the EQT Q4 2024 Quarterly Results Conference Call. [Operator Instructions] After the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] I would now like to turn the conference over to Cameron Horwitz, Manager Director, Investor Relations and Strategy. You may begin.

Cameron Horwitz: Good morning, and thank you for joining our fourth quarter and year-end 2024 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer; and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website. And we will reference certain slides during today’s discussion. A replay of today’s call will be available on our website beginning this evening. I would like to remind you that today’s call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday’s earnings release and our investor presentation, the risk factor section of our most recent Form 10-K and Form 10-Q, and in subsequent filings we make with the SEC.

We do not undertake any duty to update any forward-looking statements. Today’s call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures including reconciliation to the most comparable GAAP financial measures. With that, I will turn the call over to Toby.

Toby Rice: Thanks, Cam, and good morning, everyone. 2024 was a transformational year for EQT, marked by both record-setting operational accomplishments and bold strategic positioning at unprecedented speed. The highlight of the year was closing of the Equitrans acquisition in July, which created America’s only large-scale integrated natural gas company. After only six months, our integration process is now 90% complete with synergies captured to date exceeding base case expectations, building on our growing track record of value-enhancing M&A followed by successful efficient integration. Our rapid execution speed has driven the capture of more than $200 million of annualized base synergies, or 85% of our forecasted plan. Our 2025 budget also reflects much faster-than-expected impact from our midstream compression investments.

As tangible evidence, we now expect to turn in line 10 to 15 fewer wells annually while maintaining current production levels with more reductions in savings expected in the years ahead. In upstream operations, our teams shattered multiple company efficiency records last year, resulting in 20% increase in completed lateral footage per day relative to 2023. These efficiency gains are carrying over into 2025, allowing us to drop from three to two frac crews in April as we are choosing to prioritize cost savings instead of production growth. It is important to note that until recently, we plan to run a third frac crew for the most of 2025, highlighting our continued momentum into the end of the year. As a result of these efficiency gains, we expect our 2025 average well cost to fall by approximately $70 per foot compared to 2024.

Additionally, well productivity continues to improve, which drove 65 Bcf of production outperformance in 2024. Had we not curtailed volumes in response to market conditions, our production would have exceeded the high end of our original guidance by 3%. We expect this performance will carry into 2025 in the form of more volume and a higher price environment without having to increase activity or capital. During the fourth quarter, EQT’s operational momentum resulted in outperformance across the board. We delivered production at the high end of guidance and CapEx 7% below the low end of guidance. Our tactical curtailment strategy improved realized pricing. And once again, the teams kept operating expenses in check, driving costs to the low end of guidance.

EQT generated more than $750 million of net cash provided by operating activities and nearly $600 million of free cash flow during the fourth quarter alone, despite Henry Hub averaging just $2.81 per million Btu. These results showcase the unparalleled earnings power of our integrated low-cost platform and underscore EQT’s unrivaled free cash flow durability even at low gas prices. Turning to reserves, pro forma for our non-operated asset sales, EQT’s year-end 2024 approved reserves were essentially unchanged year over year at approximately 26 Tcfe, despite the SEC price deck dropping from $2.64 to $2.13 per million Btu, underscoring the resiliency of our premier low-cost Appalachian reserve base. At strict pricing, the PV-10 of our approved reserves totals approximately $28 billion.

However, this value only includes three years of our more than 30 years of future inventory. And excludes the value associated with our third-party midstream revenue that MVP and Hammerhead pipelines and our 1.2 Bcf per day of premium firm sales deals with the major utilities in the Southeast market. The total value of our approved reserves at strict pricing plus these other core assets equates to roughly our current enterprise value. That means investors can own EQT today and essentially get our peer-leading inventory depth for free, underscoring what is still an unrivaled value proposition for investors. Shifting to our 2025 outlook, we are initiating a production guidance range of 2175 to 2275 Bcfe with a midpoint that is 125 Bcfe above the preliminary 2025 volume outlook referenced last quarter.

This strong outlook is driven by robust well performance, completion efficiency gains, and earlier than expected benefits from compression investments. We will continue running just two to three rigs and recently elected to drop from three to two frac crews, beginning in April to prevent our efficiency gains from tipping the business into growth mode. This minimal level of activity juxtaposed against our 7+ Bcf a day of gross production, underscores our operational momentum and our world-class assets. As it relates to our investments, we have established a 2025 maintenance capital budget of $1.95 billion to $2.1 billion. We have also allocated $350 million to $380 million to value creating growth projects beyond maintenance, including $130 million in Equitrans compression investments.

Our reserve development capital budget of $1.35 billion to $1.45 billion is down nearly 10% per unit of production compared to 2024 when normalized for curtailments and approximately 15% below 2023 levels. We expect our continued efficiency gains and compression investments will drive this number down even further over the coming years. At strip pricing, we expect EQT to generate approximately $2.6 billion of free cash flow in 2025, $3.3 billion in 2026, and approximately $15 billion cumulatively over the next five years. To wrap up, material efficiency gains, robust well-performance, and Equitrans integration momentum continue to drive our performance across the board. The momentum within EQT is at its highest level since we took over the company in 2019, and we are excited to continue showcasing the power of our platform in 2025 and beyond.

With that, I’ll now turn the call over to Jeremy.

Jeremy Knop: Thanks, Toby. I’ll start with the highlights of our fourth quarter results. First, we delivered sales volumes of 605 Bcfe at the high-end of guidance, driven by operational momentum that Toby discussed. Normalized for curtailment, production would have come in at approximately 632 Bcfe or 6.9 Bcfe per day, a tangible demonstration of our operational momentum. While on the topic of production, it is worth noting that we experienced less than 1 Bcf of freeze-offs during the polar Vortex events last month, compared with 13 Bcf during Winter Storm Elliot in 2022. Greater alignment and collaboration with our new midstream colleagues drove the step change improvement in performance. Turning to pricing, our differential came in $0.13 tighter than the midpoint of our guidance range as we curtailed volumes early in the quarter during the weakest periods of local pricing before surging volumes back when pricing strengthened.

This is the second consecutive quarter of material realized pricing outperformance due to tactical curtailments, underscoring how our curtailment strategy creates shareholder value without disrupting operations or impairing productive capacity in a volatile market. To further demonstrate the value of this strategy, amid cold winter weather and strong local pricing in January, we opened up chokes on many of our wells, providing customers additional volume to meet winter demand while simultaneously exposing more production to high local pricing. Year-to-date in 2025, we’ve realized $20 million of revenue uplift from this strategy while delivering record levels of company production. Fourth quarter operating costs came in at $1.07 per Mcfe at the low-end of our guidance range due to production outperformance and gathering LOE and G&A expenses below expectations, CapEx of $583 million with 7% below the low-end of our guidance range due to efficiency gains and lower midstream spending.

It’s worth nothing that aggregate capital expenditures during the second half of 2024 came in nearly $200 million below the midpoint of our expectations, again, tangibly highlighting our capital efficiency momentum. On the midstream side, third-party pipeline revenue was $166 million, 7% above the high-end of guidance. MVP capital contributions of $60 million were 14% below the low-end of guidance, and MVP distributions of $53 million were in line with expectations. EQT generated $756 million of net cash provided by operating activities and $588 million of free cash flow during the fourth quarter, despite Henry Hub averaging just $2.81 per MMBtu, underscoring the unparalleled nature of our low-cost business model during all parts of the commodity cycle.

Turning to the balance sheet, during the fourth quarter, we delivered on our asset sale promises a year ahead of schedule to de-risk our balance sheet and position our hedge book for a rising price environment. In December, we closed on the sale of our remaining non-operated Northeast Pennsylvania assets and Midstream Joint Venture. Proceeds from these transactions totaled $4.7 billion, which we used to fully repay our term loan, fund the repayment of senior notes, and pay down our credit facility. We exited 2024 with $9.3 billion of total debt and $9.1 billion of net debt compared to $13.8 billion and $13.7 billion, respectively, at the end of the third quarter. It’s worth noting that our net debt at year-end reflects the impact of $475 million of working capital usage during the quarter, the bulk of which should reverse in 2025.

At strip pricing, we expect to exit 2025 with net debt of approximately $7 billion, comfortably below our target of $7.5 billion. In the medium-term, we plan to reduce our absolutely debt balance toward $5 billion to bulletproof our balance sheet and credit ratings, so that we can play offense during the next down cycle when others are forced to play defense. For reference, this debt balance equates to approximately five times free cash flow at a $2.75 Henry Hub price, which is a price point where many of our peers are free cash flow neutral to negative. Turning to hedging, our rapid asset sale execution and bullish outlook for pricing in 2025 and 2026 positioned us to add no incremental hedges during this quarter. To recall, we tactically sculpted our hedge book to have material upside to improving macro conditions later this year.

Our hedge percentage falls to approximately 40% in Q4, with 100% of our hedges becoming white collars with ceilings of $5.50 per MMBtu in November. We remain unhedged in 2026 and beyond, providing investors full exposure to an increasingly bullish setup for prices. Our position at the low-end of the cost curve acts as a structural hedge, which in turn facilitates unmatched exposure to high-price scenarios by limiting our need to financially hedge. As previously communicated, we plan to approach future hedging patiently and opportunistically in order to capture asymmetric skew in the options market. In essence, this approach positions us to monetize volatility and realize higher-than-average gas prices through the cycle. Turning to the macro landscape, three years of low commodity prices resulted in upstream underinvestment.

This supply backdrop, combined with an unusually cold winter, ramping LNG exports and robust power demand, has catalyzed an inflection in natural gas prices over the past quarter. While gas prices have already surged, we think there is still room to run and cannot recall as wide of a disconnect between the equity and commodity markets as we are observing today. The Haynesville is suffering from years of underinvestment and increasingly scarce inventory debt. And we believe will be much slower to respond than the commodity markets or pricing. Appalachia is largely pipeline constrained and there are no new pipelines out of the Permian until late 2026. Simply put, it will take too long to increase gas production to meet this step change increase in demand during such a short time.

And we believe the market may have to balance inventories through demand destruction at the hands of higher prices in 2025 and 2026. Looking further ahead, we are eyes wide open at nearly 5 Bcf per day of new Permian gas pipeline or slated for completion in late 2026, just before Qatar brings 6 Bcf per day at the LNG onto the global market. With these medium-term headwinds and the fact that capital spending would not result in additional production until mid-2026, we do not have plans to invest in production growth this year and view the coming inventory imbalance and higher prices as a phenomenon of the timing mismatch of supply and demand, amplified by a cold winter and the theme of too little gas storage capacity. Alongside a broader bullish backdrop for natural gas, the underlying fundamentals in Appalachia continue to strengthen, with the tightening base as one of the most underappreciated themes.

Robust demand in the southeast region has driven MVP flows to maximum capacity of 2 Bcf per day this winter, contributing to eastern storage levels moving from near five-year highs last fall to near five-year lows today. As a result, our production sold into the local M2 market and our MVP volumes sold at Station 165 have received robust pricing. During the January cold spell, Station 165 spread to Appalachian price points rose to more than $25 per MMBtu, underscoring the tremendous upside option value embedded in our MBT capacity during periods of high demand. Longer term, we continue to see 6 to 7 Bcf per day of incremental Appalachian demand by 2030, driven by load growth, coal retirement, and pipeline expansions. At the same time, we believe many producers in Appalachia will see productivity degradation or run out of inventory entirely, further tightening local fundamentals.

M2 base’s futures are beginning to reflect this reality, tightening by approximately $0.30 between 2026 to 2030 over the past two years. EQT is uniquely positioned to capitalize on this setup, as we have the highest quality and longest duration inventory in the basin, paired with irreplicable, world-class infrastructure. These characteristics are investment grade credit ratings and low emissions credentials make EQT the go-to company for new power projects and position the business for sustainable future production growth. Turning to capital allocation, in recent strip pricing, we expect to generate approximately $2.6 billion of free cash flow in 2025, which we plan to allocate toward debt repayment. With our balance sheet de-risked, we plan to steadily and sustainably grow our base dividends over the years ahead and position to opportunistically repurchase shares when the market is fearful.

Beyond 2025, our integrated business is ideally situated to support appellation demand growth, positioning EQT to provide sustainable, low-risk organic growth for shareholders, a key attribute missing from the industry today. We are in the process of generating a backlog of low risk, high return midstream investments to support this demand growth, which would in turn unlock modest upstream production growth from our decades of high quality inventory. We have uniquely positioned EQT among the energy landscape, offering investors not only the best risk adjusted exposure to natural gas, but also idiosyncratic growth opportunities that should allow us to compound capital and create differentiated value over the long-term. And with that, I will turn it back over to Toby for concluding remarks.

Toby Rice: Thanks, Jeremy. The past five years have been an incredible journey. In this time, we have transformed EQT into America’s only large scale integrated gas producer, becoming the must own natural gas company. Looking forward, we will continue our pursuit of becoming the operator of choice amongst all stakeholders and we’ve got a great setup in front of us. Costs are going down, operational efficiency gains continue, asset quality shining, our inventory is still staying deep, capital intensity is improving, deleveraging plans are ahead of expectations, the E-Train integration and synergy capture, both ahead of schedule, durable midstream growth projects are entering our program, and Appalachia fundamentals are strengthening and demand for our product across this country is surging.

2025 is poised to deliver a banner year. We are excited to demonstrate the differentiated benefits and earnings power of our business in the years ahead. The bullish inflection in natural gas fundamentals supercharges our excitement. And when we look at the 2026 free cash flow and beyond, investors still have the opportunity to own our premium story and assets at a discounted valuation compared to peers. With that, I’d now like to open the call to questions.

Operator: Thank you. [Operator Instructions] Your first question comes from the line of Doug Leggate of Wolfe Research. Your line is open.

Q&A Session

John Abbott: Good morning. This is John Abbott on for Doug Leggate. Just Toby, maybe I just want to start off with your like, we appreciate the breakout on maintenance CapEx for 2025, maybe you can start off just sort of discussing how you risk that and how you sort of see that evolving in the coming years?

Toby Rice: Yes. So, when we think about the maintenance CapEx, you start with the asset quality, I think we put numbers out there on well performance. That gives us a good read on the type of volumes we’re looking to replace. And then, it just comes down to picking the operational efficiencies that drive that along with the costs. So, we fully baked these plans. We’re backed by historical performance. We are taking into account the operational efficiencies we proved in ’24, and are rolling that forward in ’25. I think a lot of the things that are giving us confidence in the operational efficiencies are structural fixes to the business, one of them being E-Train and the water infrastructure that has always been a challenge for us.

But now that we have those assets, the teams are locking in the efficiency gains there. Going forward, what this looks like, I think we put that slide out there on the reserve development capital efficiency, and you’ll see that that will continue to come down over time. So there is a little bit of a dynamic at play in the near term with us adding compression, but still long-term trends, the upstream maintenance in intensity is going to be coming down.

Jeremy Knop: Yes, John, I’d also add to that. Initially, when we talked about our 2025 capital plans, the assumption was peak spend for our compression investments probably wouldn’t happen until 2026. We’ve been able to pull that forward. And so the numbers you see for spend of about a $130 million in 2025 is peak spend. Kind of ballpark, we expect that to decline in 2026 and then thereafter. So 2026 ballpark number today is like $85 million. So that’s really been pulled forward and that’s pulled production forward at the same time. So I think in terms of a lot of those investments, it’s really downhill from here, which is great. It’s accelerating value into the exact market. We want to do that. And then in terms of how we model it, I know we talked about this in the past, but I think there’s — I think there’s still a bit of conservatism baked into how we’re modeling the net impact from these projects.

It’s still early, so I don’t think we want to get ahead of ourselves just yet. But if you boil it down, the beats that we have seen the last couple of quarters, both with CapEx coming in low and also production being really robust are really coming from that. So I think we’re hopeful that we see continued outperformance, but we’re being patient at this time until we see a little bit more time go by and results come in.

John Abbott: And that’s a good segue into our second question. So where are you right now as far as thinking about the benefits from compression? You raised 2025 production guidance. What is your understanding of the benefits of compression that have added compression at this point? And how do you bake that into your plan?

Toby Rice: We have put that into our plans now. The question really is just going to be on the timing. The teams — are there some more compression projects that they can that they’re identifying in the future. Sure. But that will now be part of our base maintenance plans, to make sure that we’re installing compression to keep gathering lines at the right pressures. As Jeremy mentioned, I mean I think the biggest focus for us was getting these compression projects onto the schedule as quickly as possible and commend the team for the work they’ve done. In less than six months from closing this deal to be able to get these projects put on board. So, what we’ll be watching going forward, we are assuming an uplift on these compression projects.

That could change a little bit higher or lower. We’ve got about — I think it’s about eight compression projects that we’ve got history that we’re using to guide our forecast. But that’s probably the biggest moving piece right now, but it should be very small in nature.

John Abbott: Great. Thank you very much for taking our questions.

Operator: Your next question comes from the line of Arun Jayaram of J.P. Morgan. Your line is open.

Arun Jayaram: Yes, good morning. Toby, I wanted to see if we could discuss your thoughts on kind of the longer term kind of CapEx trajectory at EQT. The budget this year is for $2.4 billion call it just under call it about $2 billion for maintenance, just under $400 million for strategic growth. Last quarter, you highlighted the potential for EQTs all-in CapEx to be in the low 2s and that was before capturing $175 million of potential E-Train synergies. So I was wondering how you think about kind of your maintenance CapEx evolving over time, including that strategic, kind of CapEx budget, include some compression in some of those midstream type of projects?

Toby Rice: Yes. Arun, I think it’s important why we’re putting the spotlight on the actual maintenance spending that we have, being around that $2 billion number this year. Looking forward, what could that look like? If you look at Slide eight on our deck, we’re showing the res dev capital intensity. We’ll show that the cost coming down for maintenance spending on res dev, which is our upstream business. The question is going to be, are we going to have more growth opportunities on the midstream front? But we should see a natural trending down of our maintenance CapEx for the upstream side of the business over the coming years.

Jeremy Knop: Arun, the reason we broke out our maintenance capital separate from growth again, if you look at the midpoint of that number, it’s already trending below that prior guidance we had put out. So I think things are already moving that that direction. I’d suspect that that with successful results on the compression, I think that has a chance to move even lower. But that’s why we put that out just so as you think about modeling two years out and beyond, I think that’s kind of the number you need to anchor to before thinking about any sort of other projects that that would be more bespoke in nature.

Arun Jayaram: Got it. Yes. Sounds like you already had over 800,000 horsepower in terms of compression and expect that to grow a little bit. Maybe the second one for you, Jeremy, you’ve highlighted the potential for in basin demand to grow by 6% to 7%, which is obviously key to the EQT story. I was wondering how you’re seeing things on the power demand side of the equation kind of evolve, kind of locally. And also I know you have now a strategic relationship with Blackstone and they recently announced a deal to buy a large gas power plant in Virginia, in that call that data center alley. So I was wondering if you could see how things are going on the power front in ways that this could be beneficial for EQT in terms of announcing gas for power deals or anything like that where you could capture that part of the earning stream, which is really being highly valued in the marketplace today?

Jeremy Knop: Yes, it’s a great question. So I just say something seems to have happened in the last two months or so. Momentum has picked up in those discussions rapidly. We’re having discussions directly with several hyperscalers, other intermediaries, other power producers. And I think while a quarter or two ago we were hopeful, I think you’re now seeing tangible signs of that. There’s active negotiations going on different fronts exploring specific opportunities. And when you step back and think about why that is there’s a couple sort of key gating items, I think, to even be relevant and at the table in these discussions. First of all is you have to be fully investment grade rated. And when you look at the natural gas landscape, that that doesn’t that’s not really a pervasive theme with many of our peers or really any of them at this point, especially across all three agencies.

Our net zero credentials, I think are differentiated especially in that tech crowd, in really a peer group. We’re the only peer. Production scale, the depth of inventory we have is unmatched. And so if you’re going to build a data center or a power plant and you need 20, 30 years of gas supply reliably, there’s not really anyone else you can go to. We saw the same dynamic with the big utilities in the Southeast for those deals we did 18 months ago, which were index plus style deals. And then I think the business we have really sculpted with this reintegration with Equitrans allows us to provide a holistic solution for these guys. So, you’ve seen Williams Energy Transfer and some others talk about deals directly to power plants, but what they can’t provide is gas supply.

And if you think about it from the perspective of a tech company or anyone further downstream, they don’t want to have to go piece all this together with different dogs and cats to try to put a whole deal together. The beauty of working with someone like EQT is we can take care of all of that upstream of the power plant. And so we’ve seen that be a pretty powerful theme, especially with an existing big fork regulated business already. So, look, I think we’re pretty optimistic from where we stand today, the timing exact structure of how it comes together. Hopefully, at some point this year, I think we’re still working through that. But there’s a lot of different structures that we can provide. And really, when you think about it, there’s not many peers who can provide probably many of those, and a lot of it comes down to counterparty credit risk.

So, say, for every gigawatt, the power plant, it probably costs you $30 billion in chips to invest in that. If you’re the tech company building that, you’re not going to compromise with a non-investment grade counterparty, period. Like, you just don’t take that risk. And so for EQT, if we did even a fixed price deal, or a deal with some sort of premium index, that creates counterparty margin posting. You’re not going to do that with a non-investment grade counterparty. And so, I think really in these discussions, we’re realizing more and more, it’s kind of just EQT because we don’t really have anybody who can provide really the rest of those attributes as part of negotiating one of these deals. So we’re pretty optimistic for where we sit today.

Arun Jayaram: Great. Thanks a lot.

Operator: Your next question comes from the line of Kalei Akamine of Bank of America Merrill Lynch. Your line is open.

Kalei Akamine: Hey, good morning, guys. It’s Kalei. My question is a follow-up to the in-basin pricing question related to future demand. Just a clarification here, when you say premium to index, are you talking about Henry Hub rather than a local index?

Jeremy Knop: Yes.

Kalei Akamine: Awesome. My next question is a follow-up on Southgate. So a couple of weeks ago, we saw a filing suggesting that the route would be shorter, 31 miles farther than 75 miles with maybe fewer water crossings. Can you simply give us an update on that project?

Jeremy Knop: Yes, that’s a really cool example too of, I think a synergy that that we’ve been able to capture without I mean, it’s not counted in, like, the synergy numbers that we talked to. So that was really a holistic upstream, midstream solution that we were able to provide PS&C to help, really keep that project going, shorten the cost of it while still delivering the same volume and letting them ensure they have the gas reliably into that North Carolina market. So I would say things are on track right now, and I think that’s just a tangible example of that progress we’re making.

Kalei Akamine: Thanks, Jeremy.

Operator: Your next question comes from the line of Neil Mehta of Goldman Sachs. Your line is open.

Neil Mehta: Yes, great. Thanks, team. So, starting questions on slide 12, I think you guys have made a really good progress on getting the net debt down towards your targets. Can you talk about how you plan on getting towards that $5 billion number? It sounds like a lot of that’s going to be organic free cash flow at this point. And then how does that ultimately ties into your hedging strategy and leaving 2026 more open, so your perspective on how the two tie together?

Jeremy Knop: Yes. I mean, from where we sit today, we’ve knocked out our objectives again, above that $3 billion to $5 billion range on the asset sales. So go forward. It’s just free cash flow. No, we’re being pretty patient right now. I think as you get into mid-year, I think the market expects rig count to ramp up pretty rapidly. We just don’t see that happening. When we think about what does it take to balance even ’25, you probably need Haynesville rigs to get to 50-ish by mid-year. I’d be surprised if we get out of the thirties personally. So we’re, I think, between now and mid-summer, I think we’re going to sit tight and be pretty patient. I think Cal 26, look, I wouldn’t be surprised a bit if you see a five handle on, on Cal 26 full-year pricing.

I wouldn’t be surprised if this summer you see the same in 2025. So we’re going to be pretty patient right now. And I think where we are with the balance sheet, but the rating agencies, with just our trajectory of free cash flow, I think we’re in a perfect spot to continue being patient.

Neil Mehta: And then, Jeremy, your perspective on long-term gas was interesting. Just the view that Qatar coming online and Permian associate supply could put a constraint on how high we go, so how do you think about, but it sounds like that’s probably not post ’26 dynamic in some ways. So how do you think about potentially locking in the ’27 plus to the extent that comes that firms up with the ’26 curve. And am I reading your view right there that while there’s reasons to be bullish on the intermediate term, there’s some headwinds over the long-term for global gas?

Jeremy Knop: Yes, I mean, I think your commodity team specifically of everybody’s done a phenomenal job. I think outlining some of this in the more medium-term, look, none of that impacts 2025, ’26 that we can see. I think you could — we could go pretty high over the next two years. Look, I think what happens beyond that is really a factor of what happens to U.S. supply. And what happens with Russia, Ukraine? I think there’s a lot of noise going around right now about if there is a peace deal this year, what does that do to TTF pricing? We don’t really see a tangible impact to that. I think those fears are overblown personally. so I think there’s still a pretty bullish case for European gas. I don’t — I mean, you can — might see that Ukraine transit deal reinstated.

You already have gas going through Turk stream. I don’t see a real chance that that, that YAML pipeline through Poland comes back into service and three of the four Nord Stream pipes are out of service. There’s also some litigation where gas from owes $20 billion, $30 billion to a bunch of these European utilities that would all have to be settled too. That’s something that U.S. negotiators can’t settle on behalf of Europe. So we just don’t see that risk near term. So even if there is a deal in terms of like balances and where pricing goes over the next two years, I think you might see some sentiment driven moves, but fundamentally I think pricing has ways to run.

Neil Mehta: All right. Thanks, Jeremy. Thanks, Toby.

Operator: Your next question comes from the line of Josh Silverstein of UBS. Your line is open.

Josh Silverstein: Hey, thanks. Good morning, guys. Maybe just sticking on the price discussion there, but in a different way, you talked about how you view your stock is disconnected to the commodity outlook, so why not take advantage of that now and introduce the buybacks this year versus taking all the 2.6 to the balance sheet, given that you’re 55% hedged and you kind of know what your cash flow is going to be this year. Thanks.

Jeremy Knop: Yes, I mean, look what enables counter cyclical buybacks is having a really strong balance sheet liquidity. we’re coming off 45 days away from having closed almost $3 billion up or $5 billion of transactions. So we still want to get the balance sheet down where we have closer to $5 billion of debt. I mean, if you think about even over the last three years, our stock has ping pong between $30 and $50. I mean, there’s times over and over again to buy the stock back cheap. Look, I think the stock has a ways to go in the next two years. It wouldn’t surprise me though. I mean, you always have something come up with whether you see big pullbacks. I think we’re going to continue to be patient. What we saw with that, that deep seek scare a couple of weeks ago is a perfect example of that.

You can buy it back on some of those days. So look, we’re going to be opportunistic. I think we’re eyes wide open about the situation, the relative value right now. But I don’t think you’re going to see us rush out and buy our stock aggressively when we’re setting new 10 year highs every day. I think our — my comments in the earlier remarks were more geared at when you look at the embedded gas price in gas equities relative to where the strip needs to be in 2025 and ’26. I mean, I think our internal views is you probably need to see $5 gas, at least in those two years. Does it need to be at $5 forever after that? TBD, I think it depends on a lot of this AI stuff, but I look, I think we’re going to always be patient, opportunistic buyers for our stock rather than, than chasing a new 10 year high to buy it.

Josh Silverstein: Got it. Well, maybe flipping that around a little bit given the success of the compression program and the uplift and well-performance, can you use your equity to an advantage in acquisitions and are in a pockets out there also to you guys that, or maybe you’re seeing well-performance like your old well-performance that you can then put compression projects into to kind of get an uplift in as well.

Toby Rice: Yes, Josh, I’d say our, our approach towards M&A will still be disciplined in how we look at things, but one of the things that we’re showcasing now is sort of the power of the platform with upstream and midstream and creating a real, a real operational edge, those edges will be used to look at offset operators and look for opportunities, but I, I’d say our framework is still in place and a disciplined approach is still there.

Operator: Your next question comes from the line of Roger Reed of Wells Fargo. Your line is open.

Roger Reed: Yes, thanks. Good morning. Toby, maybe to come at some of the other macro ideas for gas, we haven’t thought of in a while, which should be going north, some signs that New York is recognizing the shortcomings in their gas market. We have obviously the president pushing to potentially move more gas into the Northeast. How would you look at that? And any thoughts on timing and magnitude or anything like that?

Toby Rice: Yes, I think you’re seeing the impact of the new administration. If you characterize the administration in the past as being a little bit about energy subtraction, this administration has made it clear. They’re going to be about energy addition. And seeing pipeline projects, breathing new life into those with constitution or even lifting the LNG pause, these are all signs that we’re going to let market forces work in this country. And that’s going to be key in letting the most affordable, reliable, cleanest form of energy, natural gas to meet those needs. Also, we’re seeing some other dynamics take place in our backyard. PJM has just allowed put an order out to allow us to reshuffle more natural gas power plants, come to the top of the queue, that’s significant.

And what hasn’t changed is the fragility of these grids. I mean, there’s a reason why this administration put an national — called the national emergency, largely about the state of the grid. We’ll see those opportunities across the country, but we’ll also see those largely in our backyard as well, especially given the proximity to the data center demand that’s taking place.

Roger Reed: I appreciate that. And then just to follow up question on the opening comments about whether giving you the opportunity to open the chokes up and understand guidance for the full-year and everything, it doesn’t sound like there’s an issue, but just wanted to understand maybe the extent you can provide a little more insight. Opening the chokes, what does that do in terms of pressure management, reservoir management, and your expectations going forward as we think about the call it plus or minus $2 billion of CapEx on an annual basis.

Toby Rice: Yes. So, I think one of the — one of the great characteristics of our business is the ability to respond to the current environment. You see what happened — see our ability to curtail volumes when prices are low. Now you’re seeing the ability to respond when prices are high, that the dynamic at play here that gives us the flexibility to open chokes is the fact that we instill a managed choke program when we turn our wells back in line. So we have the capacity to grab a few 100 million a day of production. I mean, that’s sizable. So, we look at that and our commercial team can call for that when they see market signals that — and we’ll respond to those volumes. As far as a cost perspective, really, it doesn’t cost us hardly anything, to increase those volumes.

We’re, we’re, it’s as simple as just opening up the chokes for some of the newly drilled wells that are on that managed choke program. So it’s really just pure upside from higher pricing and really the higher volumes that we’re putting into the market.

Jeremy Knop: Yes. To provide a little more clarity on that too, as it relates to the — just the total year we have today, about 300 million a day of extra gas in the market as a result of that open choke program, into EGTS pricing this week in Appalachia. I mean, today it’s about $6.30. So, when we open those chokes, we’re flowing directly into that market and selling at a significant premium. That’s why we do that. so it’s adding like real material value. Now that said, when you think about the course of the year and the trajectory of production, I mean, like right now it’s probably the high point of production for the year. We pull that volume back in and then go back on managed decline. I don’t — I think when you look at where December production is versus this moment in time, we’re down at that point, just because we have so much of that volume open back up right now due to how high pricing is.

So we’re taking advantage of it. I mean, again, we’re in a price times volume game, so we’re maximizing productivity when we see the opportunities, but we’re not exactly like ramping towards the end of the year. I think we’re just taking advantage of high pricing when we see it.

Roger Reed: Thank you for the clarity on that. I’ll turn it back.

Operator: Your next question comes from the line of John Ennis of Texas Capital. Your line is open.

John Ennis: Hey, good morning, guys. And congrats on a strong update. For my first question, I wanted to touch on commentary provided on last quarter’s call regarding the opportunity to complete 50% more footage per day in ’25 versus the historical average, how should we think about what level of improvement above that 35% improvement from historical levels that was achieved in the second half of ’24 is embedded in guidance versus what is potential upside?

Toby Rice: Yes, I think, the theme here for operationally really is going to be us continuing to push the pace on these operational efficiencies. We’re going to be conservative on that. The other impact, I think that’s, that’s probably more focused on driving our cost down as just the impact, the compression and allowing us to reduce the amount of horizontal footage that’s needed to maintain productions.

Jeremy Knop: Yes, I’d say that the other thing too, is a lot of that improvement is driven by logistics. And so things like expanding our water network and integrating fully with Equitrans and some of the legacy Tug Hill and Chevron systems. So the more we complete there and the more throughput we add on the water side, the faster we can track, that those sort of connections don’t happen overnight, so we’re still working through that. In terms of where we could get to probably peak throughput or maybe even a year off from that still. So I think there’s still improvements to make. And I’m hoping we continue to carry on the momentum we’ve seen in terms of just quarter-over-quarter improvements. So we have some of it baked in based on how we’re performing today, but I think we’re always continuing to try to push the envelope and build on that.

John Ennis: Perfect. And for my follow-up, just building on the macro commentary in your prepared remarks, there seems to be a price signal in the Ford strip that highlights the need for natural gas growth by the end of this year, if not sooner, yet the sector is largely in maintenance mode, knowing that it’s just more than just price that you consider, could you just help frame how you as a management team contemplate the decision to potentially shift back to that sustainable growth mentioned in the presentation?

Toby Rice: Yes, it’s very simple. And to reiterate what we’ve said in the past is EQT will respond with growth, but it’s got to be sustainable. And that means we need to see demand on the other side of that production growth. I think, the days of us just growing volumes into the commodity market, because we see a good strip. we want to see a little bit more than that. We want to see demand on the other side and then, we will grow to make sure that demand is materialized. the dynamic that we have right now is going to present Jeremy and the commercial team opportunities to connect to that demand. And I think that will create the opportunity for EQT. And it’s something that we’re looking to make sure we create and connect those opportunities. And I think our integrated platform is going to give EQT an advantage in capturing those types of opportunities.

Jeremy Knop: Yes, I think we’re also seeing, I mean, like, look, if you, if you — in conversations with other producers, privates, operators in the Haynesville, I don’t think anyone cares anymore about a single well return. It just doesn’t mean anything. And I have yet to hear from even talking to too many privates that they really care about that anymore either. So, I think that the focus across the board is more generally, what is my corporate return to my investors measured in actual free cash flow, not EBITDA, not the single well return, but what am I actually able to deliver back through a dividend, through a buyback? And so I think a lot of producers, especially if you’re in the Haynesville, you’re looking at this and saying, Well, gosh, I need maybe a $5, it starts getting interesting and I can start thinking about making growth plans, but it’s a lot easier.

It’s a lot more efficient. I can drive well cost down. If I get into a cadence where I have larger scale operations, like what EQT does with combo development, driving efficiencies and look at the end of the day, it’s like we keep saying, it’s a price times volume game. If we had not done the Equitrans deal, if we had not gotten those transactions done as quickly as we had towards the end of last year, we probably would have added another, call it 20% of hedges in the back half of ’25. We’d probably be about 30% hedged in 2026 today, that hedge position, if we were to put that on over the course of Q4, we’d be about $700 million underwater on that right now. So there is so much more value to gain by just being flexible, having low leverage, being able to be have production available when pricing is there relative to chasing a price signal.

When in reality you put a rig out today, you don’t see production until next year. I think everybody got snake bit in 2021, ’22, when they tried to do that. And then you had a warm winter and an LNG facility go down, pricing fell apart. So I think everybody’s kind of learned their lesson. I think everybody seems to have just stepped back and for us, we’re just trying to run a good, consistent, low cost business. if you can put a rig out there in 30 days and capture a little bit of it, could make sense, but that’s not really the game that we’re playing So, look, I think you do see some rigs come back, but the best we can tell by I commented before, I think it’s hard to even see the Haynesville getting out of the thirties in terms of rig count.

I just don’t really know who’s motivated to add them at this point.

John Ennis: I appreciate all the color and thanks for taking my questions.

Operator: Your next question comes from line of Scott Hanold of RBC. Your line is open.

Scott Hanold: Yes, thanks. Hey, great quarter guys. I’ve got — I’ll kind of basket my two questions into one. So just asking one and it’s around well performance. Obviously, you talked about like compression helping and, you’re just seeing better well productivity, but can you give us a sense of, as you look at your core inventory duration, like what is your confidence level on how far that goes out comparatively to others with all the upside you’re seeing. And then kind of question number two on well performances, as you guys manage your chokes, and pardon me for the way of saying this, but on and off, have you seen any change in, in well you ours over time, has that had a positive or a negative benefit?

Toby Rice: Yes, great question. And Scott, I pointed to slide seven, as I think very illustrative picture of the dynamic that’s taking place, both with what’s happening outside of our walls with our peers and what’s giving us confidence in the quality inventory that allows us to say with confidence, we’ve got decades and decades of inventory. When you look at the chart on the left, you can see EQT sort of middle of the back performance for Well — put online in 2021. but you look at the picture fast forward a few years later, you see peers, inventory degradation, pretty significant. And I think this should be a concern for investors when evaluating companies is looking at the quality inventory, because as you see here with peers, those numbers are coming down.

but one thing that’s saying that’s still shining is our EQT well performance actually is increasing. and so from a reservoir quality perspective, we have a deep inventory and then from an economic perspective, when you layer in the fact that we just pulled in all of these midstream costs from Equitrans, the ultimate, what we’re looking for is not just high quality reservoirs, high quality economics. And our inventory is, is deep. On the EURs question, I think one thing that we’re looking at pretty closely on the impacts of compression is going to be, are we seeing just acceleration of reserve recovery or are we actually increasing EURs? I’d say, initially right now we’re seeing signs of this is just an acceleration, but we’ll keep an eye on that.

And we do not anticipate any degradation or on the enhanced removing the chokes on our wells when we flow back.

Jeremy Knop: On the inventory life specifically, we had done a deep internal analysis pre-Equitrans on this, just so we could — you see Veris and others put out estimates. Our view internally was we had about 25 years of locations that we considered high quality that we had more than a 50% working interest in. I think a lot of the numbers you see publicly are numbers where someone might have a 25% working interest. They counted as one of their locations. And it’s really not because someone else owns the other 75%. So that was our threshold. Equitrans totally transformed that though, because what then was Tier 3 inventory can become Tier 1 on an integrated cost basis. And then when you think about leasing, because in Appalachia, there’s still plenty of land to lease.

If someone else wants to lease that land, they still have to flow through our pipelines or we can go lease the land ourselves. That’s why we still spend call it a $100 million a year in our budget on infill leasing, because we’re adding to that inventory and really replacing a lot of what we do every single year. So look, I think at this point, we haven’t updated the analysis handily since then, but I would estimate that added at least 10 years to it. So it’s a level where that’s before infill leasing. So, every year we probably replace 70% of all the inventory we develop with our — with that program. So I think we’re — we kind of have a level of inventory where leased EQT, we don’t really have to think about it. And that well productivity is not only maintained, but as Toby pointed out, continues to actually improve due to the operational improvements.

Toby Rice: Yes. Only point I would add is just the land replenishment, the dynamic that’s taking place over the last few years, our land budget cumulatively in the past was majority spent on maintenance and a small portion on infill. Now that’s flipped and the majority of our dollars are spent on infill leasing, which is adding new working interests, increasing, adding to our inventory. And you can sort of see that on our budget slide, the instant dollar spent on infill versus land. So we’re getting, I’d say more, more value creation out of the land that we’re spending right now to promote that dynamic that Jeremy just discussed.

Scott Hanold: Got it. Thanks.

Operator: Your next question comes from line of Jacob Roberts of TPH. Your line is open.

Jacob Roberts: Good morning. Maybe a clarifying question on 2025 capital, it sounds like the maintenance budget is somewhat of a function of some of the strategic growth budget, specifically the compression. So I was wondering if you could help risk to that number relative to those compression projects coming on stronger than expected, or perhaps the other direction, given some concerns around lead time delivery installation, things like that.

Toby Rice: Yes, I would say that what we have in place for the compression plans, is follows our normal project management operation schedule type risking, for when those get turned in line, so teams have looked at that and that is baked into our plans. There’s not going to be — we don’t anticipate a lot of flex in upside downside on the impact of compression. Like I said, we’ve already done a handful of pilots here and have a pretty good level of comfort on what those will do. And we broke one of the reasons why I think we broke out pressure reduction as a portion of our CapEx against where to see that on our budget as well.

Jacob Roberts: Okay, perfect. Thank you. And my second question, it looks like some midstream spend maybe fell out of Q4. I was wondering if you could frame, is that showing up in 2025 or some portion was permanently eliminated based on what you’ve seen from the assets?

Jeremy Knop: I’d say a little bit about the short answer.

Jacob Roberts: Perfect. I appreciate the time, guys.

Toby Rice: Thanks.

Operator: Your next question comes from the line of Michael Scialla of Stephens. Your line is open.

Michael Scialla: Thank you. Good morning, guys. I wanted to ask about your 2025 plans specifically the net — till as you plan in Southwest PA, it looks like 32 to 40. Were all of those intended to be in the Marcellus or any of those in the Utica? Just want to get your thoughts on the deep Utica returns, how they compete with Marcellus at this point.

Toby Rice: Yes, in PA we have no deep Utica West Virginia. I think we’re finishing up a handful, less than five. That is not going to be a core part of the program going forward. So, some of that work was in West Virginia was finishing up some wells in progress that we have from the Tug Hill. We’ve had a good time to assess the competitiveness of those and feel at this time that the Marcellus is still the best investment opportunity for us and we’ve loaded our programs with those types of projects going forward.

Jeremy Knop: It’s interesting point, actually, though, going back to the prior questions on inventory depth. When we talk about inventory, we just talk about Marcellus. You do have a lot of deep inventory out there. I mean, some of our peers are testing that already. I mean, some areas have really good results. That’s all upside to what we talk about. We already have the infrastructure in place too. So we don’t need to drill that today. Not as good as the Marcellus as Toby said, but it’s certainly upside for us.

Michael Scialla: Got it. Thanks. And I wanted to ask about slide 11 with MVP. Just curious, I guess my impression was that you talked about the capacity constraints out of the Appalachia, yet MVP wasn’t running at full capacity last summer. Can you talk about the reason for that? Was that just a function of demand? And, what was the source of that incremental demand moving forward? And do you anticipate the flow at capacity going forward from here?

Toby Rice: Yes. I mean what we’ve mentioned in the past about MVP, up until the expansion that takes place on Transco should be slated for call it ’27 and maybe early ’28. Until that point in time, MVP is going to be more of a seasonal pipe. And that’s based off pricing that area. And I think you can see that dynamic play out in the volumes there. But I think it’s pretty remarkable just to step back and look at this. There were people with this pipeline that questioned the need of Mountain Valley Pipeline needing to get built. And the fact that this thing is flowing over to Bcf a day, the fact that pricing in this area touched over almost $35 per million Btu is a signal that this pipeline was needed. And there’s dozens of other pipelines in this country that would produce a similar type of story if they were allowed to get built.

Michael Scialla: Appreciate that. Thanks, guys.

Operator: Your next question comes from a line of Bert Donnes of Truist Securities. Your line is open.

Bert Donnes: Hey, guys, I’ll bundle my questions for time as well. I just wanted to hit on the data center demand again. You mentioned the value of — your ID rating, your inventory and as well as net zero status. Just curious if the hyperscalers are trying to get around maybe paying up for EQT premium assets? And, maybe thinking, hey, we can do a deal with maybe a consortium of EMPs? Each company taking a share of it and then maybe those items matter less? Or, is that not even in the mix? And the second question would just be, are you leaning — are the deals out there leaning more towards that premium to an index you reference? Or, is it more leaning towards the fixed price Thanks, guys.

Toby Rice: Yes. I mean I think that’s a great question. And no doubt EQT competes with every operator, every gas molecule that gets produced. And we need to provide a differentiate option. But I’ll tell you this, as Jeremy mentioned, there was a shift in sentiment over the last couple months. I mean, the event, if you ask me, this was Stargate coming out. I think a lot of tech companies looked at that announcement and got questions. Where are you at with your power demand and meeting that? And I think a lot of people are frustrated in the progress and speed to market is a critical component. And so what’s going to be faster dealing with 15, 10, 5, putting those together or dealing with one, dealing with multiple parts of the value chain or dealing with one.

We think that that is going to be a great solution for our service providers and for our data centers. And those are the conversations that is how EQT will differentiate ourselves. Simple, one-stop shop, best, cleanest, most reliable, most affordable gas on the market.

Bert Donnes: Perfect. And then the second part, just — is it leaning towards a premium to an index or maybe a fixed pricing? Thanks.

Jeremy Knop: I think the beauty of the situation for EQT is we can offer both. We have offered both. Generally, when you structure that stuff, you have to price it at an indifference point. So there’s a lot of different kind of flavors of that that we worked through with all of our in-customers and the utilities we’ve already done deals with. So, I think it’s a little early to say, but I think both are on the table.

Bert Donnes: Perfect. Thanks, guys.

Operator: Thank you. And with that, that concludes our Q&A session. We’ve run out of time. We thank you for your participation. This concludes today’s conference call. You may now disconnect.