Earnings Call Transcript - EQT Q4 2024

Operator, Operator

Thank you for standing by. My name is Jale, 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. After the speaker's remarks, there will be a question-and-answer session. I would now like to turn the conference over to Cameron Horwitz, Managing Director, Investor Relations and Strategy. You may begin.

Cameron Horwitz, Managing Director, Investor Relations and Strategy

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, President and Chief Executive Officer

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 the 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 a 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 planned to run a third frac crew for 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.

Jeremy Knop, Chief Financial Officer

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 noting 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 absolute 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 depth. We believe it 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 slated for completion in late 2026, just before Qatar brings 6 Bcf per day of 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 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, 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 appellant 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. With that, I will turn it back over to Toby for concluding remarks.

Toby Rice, President and Chief Executive Officer

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 are both ahead of schedule, durable midstream growth projects are entering our program, and Appalachian 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, Operator

Thank you. Your first question comes from the line of Doug Leggate of Wolfe Research. Your line is open.

John Abbott, Analyst

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

Toby Rice, President and Chief Executive Officer

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 intensity is going to be coming down.

Jeremy Knop, Chief Financial Officer

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. The numbers you see for spend of about $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. And then in terms of how we model it, I know we talked about this in the past, but 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, Analyst

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

Toby Rice, President and Chief Executive Officer

We have incorporated that into our plans now. The main consideration is the timing. The teams are identifying additional compression projects for the future, which will now be integrated into our base maintenance plan to ensure we maintain the right pressures in our gathering lines. As Jeremy noted, our primary focus has been to expedite the scheduling of these compression projects, and I commend the team for their efforts. In less than six months since closing this deal, we've successfully integrated these projects. Moving forward, we anticipate an increase in output from these compression projects, though this may vary slightly. We have around eight compression projects with historical data that we are using to inform our forecast. This is currently the most significant variable, though it should have a minor impact overall.

John Abbott, Analyst

Great. Thank you very much for taking our questions.

Operator, Operator

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

Arun Jayaram, Analyst

Yes, good morning. Toby, I wanted to see if we could discuss your thoughts on the longer-term CapEx trajectory at EQT. The budget this year is for $2.4 billion, call it just under, about $2 billion for maintenance, and just under $400 million for strategic growth. Last quarter, you highlighted the potential for EQT's 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, including some compression in some of those midstream types of projects?

Toby Rice, President and Chief Executive Officer

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 reserve development capital intensity. We'll show that the cost coming down for maintenance spending on reserve development, 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, Chief Financial Officer

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 in that direction. I'd suspect 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 would be more bespoke in nature.

Arun Jayaram, Analyst

Got it. 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 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 about the 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, Chief Financial Officer

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, and other power producers. 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 are a couple sort of key gating items, I think, to even be relevant and at the table in these discussions. First of all, 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, really among peers. 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. The business we've really sculpted with this reintegration with Equitrans allows us to provide a holistic solution for these guys. You've seen Williams Energy Transfer and some others talk about deals directly to power plants, but they can't provide gas supply. If you think about it from the perspective of a tech company or anyone further downstream, they don't want to have to piece all this together with different parties 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. 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, but the timing and exact structure of how it comes together, hopefully at some point this year. I think we're still working through that. But there are a lot of different structures that we can provide. And really, when you consider that, there are not many peers who can provide many of those opportunities, and a lot of it comes down to counterparty credit risk. For every gigawatt, a power plant 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. You're just not going to take that risk. 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. 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 about where we sit today.

Arun Jayaram, Analyst

Great. Thanks a lot.

Operator, Operator

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

Kalei Akamine, Analyst

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, Chief Financial Officer

Yes.

Kalei Akamine, Analyst

Awesome. My next question is a follow-up on Southgate. 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, Chief Financial Officer

Yes, that's a really cool example of, I think a synergy that we've been able to capture. That's not counted in, like, the synergy numbers that we talked about. That was really a holistic upstream, midstream solution that we were able to provide 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'd say things are on track right now, and I think that's just a tangible example of that progress we're making.

Kalei Akamine, Analyst

Thanks, Jeremy.

Operator, Operator

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

Neil Mehta, Analyst

Yes, great. Thanks, team. So, starting questions on slide 12, I think you guys have made 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 tie into your hedging strategy and leaving 2026 more open, so your perspective on how the two tie together?

Jeremy Knop, Chief Financial Officer

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 going forward, it's just free cash flow. We're being pretty patient right now. I think as you get into mid-year, the market expects rig count to ramp up pretty rapidly. We just don't see that happening. When we think about what it takes 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 between now and mid-summer, I think we're going to sit tight and be pretty patient. I think CAL '26, I wouldn't be surprised a bit if you see a five handle 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. I think where we are with the balance sheet, 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, Analyst

And then, Jeremy, your perspective on long-term gas was interesting. Just the view that Qatar coming online and Permian associated 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 are some headwinds over the long-term for global gas?

Jeremy Knop, Chief Financial Officer

I believe your commodity team has done an outstanding job providing insight into the medium-term outlook. From what we can see, none of that influences 2025 or 2026. I think there’s potential for significant increases over the next two years. What happens beyond that really depends on U.S. supply and the situation in Russia and Ukraine. There’s a lot of speculation about how a potential peace deal this year could affect TTF pricing, but we do not anticipate any substantial impact. Personally, I think those concerns are exaggerated, which leads me to feel optimistic about European gas. There’s a possibility that the Ukraine transit deal could be reinstated, and gas is already being transported through Turkstream. However, I don't foresee the YAML pipeline in Poland returning to service, especially with three out of four Nord Stream pipelines currently inoperable. Additionally, there are legal issues regarding $20 billion to $30 billion owed to various European utilities that need to be resolved, and that's beyond the control of U.S. negotiators. We don’t perceive any near-term risks. Even if there’s a deal regarding balances and pricing in the next two years, I think there might be some sentiment-driven fluctuations, but fundamentally, pricing has more to increase.

John Ennis, Analyst

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, President and Chief Executive Officer

Yes, I think the theme here operationally really is 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 probably more focused on driving our cost down is just the impact from compression and allowing us to reduce the amount of horizontal footage that's needed to maintain productions.

Jeremy Knop, Chief Financial Officer

Yes, I'd say that the other thing too, is a lot of that improvement is driven by logistics. Things like expanding our water network and integrating fully with Equitrans and some of the legacy Tug Hill and Chevron systems. 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, we probably peak throughput or maybe even a year off from that still. So I think there are still improvements to make. 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, Analyst

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, President and Chief Executive Officer

Yes, it's very simple. To reiterate what we've said in the past is EQT will respond with growth, but it's got to be sustainable. 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. Our integrated platform is going to give EQT an advantage in capturing those types of opportunities.

Jeremy Knop, Chief Financial Officer

Yes, I think we're noticing a shift in focus among producers and operators in the Haynesville. There seems to be less interest in individual well returns, as discussions are increasingly centered around corporate returns to investors, particularly in terms of actual free cash flow rather than EBITDA or single well performance. The priority is on what can be returned to shareholders through dividends or buybacks. Many producers realize that a price point of around $5 might be necessary to consider growth plans, but achieving efficiency and driving well costs down through larger scale operations, similar to EQT's combined development strategy, is more effective. Ultimately, it's about finding a balance between price and volume. Had we not completed the Equitrans deal and secured those transactions swiftly last year, we would have increased our hedge position substantially for the latter half of 2025, leading to significant financial exposure today. The experience from 2021 and 2022, where price chasing led to substantial losses, has taught many to focus on maintaining a stable and low-cost operation. While there may be some rigs returning, it’s clear that the rig count in the Haynesville is likely to remain low due to a lack of motivation to add more at this time.

Operator, Operator

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

Scott Hanold, Analyst

Yes, thanks. Hey, great quarter guys. I'll kind of basket my two questions into one. 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 well EURs over time? Has that had a positive or a negative benefit?

Toby Rice, President and Chief Executive Officer

Yes, great question. I point to slide seven as a 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 that we've got decades of inventory. You can see EQT sort of in the middle of the pack performance for wells put online in 2021. Fast forward a few years later, you see peers' inventory degradation is pretty significant. This should be a concern for investors when evaluating companies—looking at the quality inventory. 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 is actually increasing. From a reservoir quality perspective, we have a deep inventory. Economically, when you layer in the fact that we just pulled in all of these midstream costs from Equitrans, what we're looking for is not just high quality reservoirs, but high quality economics. Our inventory is deep. On the EURs question, one thing we’re looking at closely is the impacts of compression—are we seeing acceleration of reserve recovery or are we actually increasing EURs? We're seeing signs of this as just an acceleration, but we’ll keep an eye on that. We do not anticipate any degradation on the enhanced removing the chokes on our wells when we flow back.

Jeremy Knop, Chief Financial Officer

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 internal view was that we had about 25 years of locations that we considered high quality that we had more than a 50% working interest in. 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 not really because someone else owns the other 75%. 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. 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 about $100 million a year in our budget on infill leasing, because we're adding to that inventory and replacing a lot of what we do every single year. At this point, we haven't updated the analysis handily since then, but I'd estimate that added at least 10 years to it.

Toby Rice, President and Chief Executive Officer

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 mostly spent on maintenance and a small portion on infill. Now that's flipped with the majority of our dollars spent on infill leasing, which is adding new working interests, increasing and adding to our inventory. You can sort of see that on our budget slide, the instant dollar spent on infill versus land. We’re getting more value creation out of the land that we’re spending right now to promote that dynamic that Jeremy just discussed.

Operator, Operator

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

Jacob Roberts, Analyst

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, President and Chief Executive Officer

Yes, I would say that what we have in place for the compression plans 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 or downside on the impact of compression. 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, Analyst

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, Chief Financial Officer

I'd say a little bit about the short answer.

Operator, Operator

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

Michael Scialla, Analyst

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, President and Chief Executive Officer

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. 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, Chief Financial Officer

It's an 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. Some of our peers are testing that already. Some areas have really good results. That's all upside to what we talk about. We already have the infrastructure in place too. 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, Analyst

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 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, President and Chief Executive Officer

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. That's based off pricing in that area. You can see that dynamic play out in the volumes there. I think it's pretty remarkable just to step back and look at this. There were people with this pipeline that questioned the need for Mountain Valley Pipeline needing to get built. The fact that this thing is flowing over 2 Bcf a day, the pricing in this area touched over almost $35 per million Btu is a signal that this pipeline was needed. There are dozens of other pipelines in this country that would produce a similar type of story if they were allowed to get built.

Michael Scialla, Analyst

Appreciate that. Thanks, guys.

Operator, Operator

Your next question comes from the line of Bert Donnes of Truist Securities. Your line is open.

Bert Donnes, Analyst

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 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?

Toby Rice, President and Chief Executive Officer

Yes. I think that's a great question. No doubt EQT competes with every operator, every gas molecule that gets produced. We need to provide a differentiated option. But I'll tell you this, as Jeremy mentioned, there was a shift in sentiment over the last couple of 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? A lot of people are frustrated in the progress, and speed to market is a critical component. 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. 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, Analyst

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

Jeremy Knop, Chief Financial Officer

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. There are a lot of different kinds of flavors of that that we worked through with all of our in-customers and the utilities we've already done deals with. It's a little early to say, but I think both are on the table.

Operator, 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.