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Operator: Hello and welcome to the EQT Q1 2025 Quarterly Results Conference Call. [Operator Instructions]. Just a reminder, this call is being recorded. Now, I would like to turn the call over to Cameron Horwitz, Managing Director of Investor Relations & Strategy. Cameron, please go ahead.

Cameron Horwitz : Good morning, and thank you for joining our first quarter 2025 earnings results conference call. With me today are Toby Rice, President & 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. 2025 is off to an exceptional start at EQT with the first quarter generating the strongest financial results in recent company history. Production was at the high end of guidance due to robust well performance and minimal winter impact. Thanks to the proactive collaboration between our upstream and midstream teams. We tactically surged our production by 300 million cubic feet per day during the quarter by opening chokes into strong winter demand, and capitalized on robust Appalachia pricing, driving our corporate differential $0.16 tighter than expectations. Our differentiated strategy of curtailing volumes during periods of oversupply and surging production during higher price environments underscores our capital-efficient approach to maximizing value amid price volatility and was a key driver behind this quarter’s record-setting performance.

Operating expenses and capital spending during the quarter were below the low end of guidance as efficiencies and synergies continued to outperform expectations. These stellar results drove more than $1 billion of free cash flow during the quarter, with natural gas prices averaging just $3.65 per million Btu. This level of free cash flow generation is nearly 2 times consensus free cash flow estimates of the next closest natural gas producer and underscores the differentiated earnings power of our low-cost integrated platform. These results are a tangible demonstration of the impact of our strategic decisions over the past several years, creating a peerless natural gas business that generates durable free cash flow during down cycles, while also having the greatest ability to capture upside pricing.

Shifting gears, we announced our agreement for the highly accretive bolt-on acquisition of Olympus Energy’s upstream and midstream assets for $1.8 billion, comprised of 26 million shares and $500 million of cash. The purchase price equates to an attractive 3.4 times adjusted EBITDA multiple and a 15% unlevered free cash flow yield at strip pricing on average over the next three years. We forecast three-year cumulative free cash flow per share accretion of 4% to 8% from the acquisition at natural gas prices ranging from $2.50 to $5 per million Btu. The Olympus assets comprise a vertically integrated contiguous 90,000 net acre position offsetting EQT’s acreage in Southwest Appalachia with net production of approximately 500 million cubic feet per day.

The assets are positioned adjacent to several proposed power generation projects in the region, providing potential strategic value upside through future gas supply deals. The EQT position has over 10 years of core Marcellus inventory, assuming maintenance activity levels, with an additional seven years of upside from the Utica. The integrated nature of Olympus’ assets and high-quality inventory drives an unlevered free cash flow breakeven price that is comparable to EQT’s peer-leading cost structure. Pro form a for the Olympus transaction, year-end 2025 net debt at recent strip pricing is forecast to be approximately $7 billion. The deal is modestly deleveraging from a credit metric perspective, with pro form a 2025 net debt to adjusted EBITDA dropping by 0.1 time at recent strip pricing.

We expect the transaction to close in early Q3 and plan to issue pro form a guidance as part of our second quarter earnings. Turning to our 2025 forecast, we continue to capture synergies from the Equitrans acquisition, with actions taken to date resulting in approximately $360 million of annual savings, an increase of $85 million relative to our last update, driven by CapEx savings and system and receipt point optimization. We have now captured 85% of guided total synergies and see the potential for ongoing initiatives to drive upside beyond our original forecast. Importantly, these synergy numbers do not include the upside optionality created through integration that has allowed us to beat our differential guidance three quarters in a row, which represents additional value creation beyond our stated synergies.

With robust synergy capture, ongoing operational efficiencies and strong well performance, we are raising our full year production outlook by 25 Bcfe, while simultaneously lowering the midpoint of 2025 capital spending guidance by $25 million, both of which are prior to the impact of Olympus. It’s worth noting our updated 2025 volume guidance is roughly in line with our maintenance production prior to the sale of our Northeast PA non-operated assets last year, which means efficiency gains asset outperformance, and the repressuring of wells from our curtailment strategy have backfilled nearly half a BCF a day of production in 2025, all while reducing capital spending and activity levels. This illustrates the tremendous momentum we’ve experienced at EQT over the past 12 months, and we see no signs of slowing down as we look ahead.

As we continue to de-risk our balance sheet, we expect to steadily grow our base dividend and position to opportunistically and counter-cyclically repurchase shares. We have built a solid foundation underpinned by a peer-leading cost structure, which drives durable free cash flow generation. The next leg of our strategy is built on the dual pillars of reducing cash flow risk and creating pathways for sustainable cash flow growth. Achievement of these two goals should result in both greater through-cycle free cash flow generation and a higher trading multiple driving differentiated shareholder value creation. As it relates to organic growth, we have a rapidly expanding pipeline of in-basin demand opportunities, which could provide us with the option to sustainably grow both our midstream and upstream businesses to serve these new facilities.

Recent media reports of sizable gas-fired power generation and data center projects in Appalachia substantiate our expectations for 6 to 7 BCF per day of local demand growth by 2030. We are in discussions with roughly a dozen proposed power projects in the region for midstream and firm gas supply solutions, and CEQT exceptionally well positioned to capitalize on this setup given our production scale inventory duration, world-class infrastructure, investment-grade credit ratings, and low emissions credentials. As these discussions mature, we have significant supply flexibility thanks to our nearly 2 Bcf per day of gross production sold locally in Appalachia. This provides volumes that we can redirect into attractive firm supply arrangements, while creating a longer-term growth option to partially or fully backfill this production.

This opens up a differentiated avenue for EQT to address sustainable production growth directly linked to end-user demand. I’d like to remind everyone that even before any in-basin supply arrangements, EQT already has a significant realized pricing tailwind from the firm sales deals we signed with the major southeastern utilities at the end of 2023. These deals are the main driver behind the upcoming tightening of our corporate gas price differential, which is forecasted to drop from around $0.60 this year to around $0.30 in 2028. This means that EQT is projected to have a $600 million pretax annual free cash flow tailwind at a time when we believe many of our peers will see free cash flow margin degradation due to core inventory exhaustion.

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

Jeremy Knop : Thanks, Toby. Our stellar first quarter results and more than $1 billion of free cash flow generated during the quarter drove significant delevering of our balance sheet. We exited the quarter with $8.1 billion of net debt, down from $9.1 billion at year-end 2024, and $13.7 billion at the end of the third quarter. We tendered for approximately $750 million of notes during the quarter and completed a successful exchange offer for outstanding EQM midstream notes, which simplifies our balance sheet and reporting requirements moving forward. As Toby mentioned, the accretive acquisition of Olympus Energy’s upstream and midstream assets accelerates our delivering plan as proforma net debt increases by 6%, while free cash flow increases by 8%, thus enhancing our debt-to-free cash flow metrics.

The acquisition has an immaterial impact on our absolute debt balance as we forecast exiting the year at $7 billion of net debt on a pro forma basis. We continue to target $5 billion of net debt on a medium-term basis and at recent strip pricing, forecast achieving this goal by the middle of 2026. Turning to hedging, rapid delivering positioned us to add no incremental hedges during the quarter, and we remain unhedged in 2026 and beyond. Our position at the low end of the cost curve acts as a structural hedge, which in turn facilitates unmatched exposure to high-priced scenarios by limiting our need to financially hedge. Instead of defensively hedging, we can now patiently look for opportunities to capture asymmetric skew in the options market, which positions EQT to realize higher-than-average gas prices through the cycle.

Turning to the macro, amid the risk-off sentiment sweeping through the markets, I want to share some thoughts on the natural gas macro landscape, which is positioned as a safe haven with strengthening fundamentals. We have talked for some time about the natural gas market being structurally tighter than pricing indicated due to the successive bearish events of LNG facilities going down in warm winters. Despite consensus thinking that this past winter was particularly cold, as measured by heating degree days, winter was in fact in line with the 10-year average and inventory balances have tightened rapidly. Importantly, this occurred on the eve of a step change increase in LNG demand in 2025 and 2026. On the supply side, we believe U.S. Gas production needs to exit 2025 near 108 Bcf per day and approach 114 Bcf a day by the end of 2026.

Given current production levels in the 104 Bcf to 105 Bcf per day range, we need to see a rapid increase in activity levels and production or pricing will reset significantly higher to suppress demand in balanced inventories. Our assumption has been that half of this growth would come from associated gas in the Permian and half from growth in the Haynesville. However, OPEC has decided to once again defend market share and start bringing back near record level of spare capacity, sending oil prices toward the 50s at the same time the trade war broke out. At this price level, we expect to see a slowdown in Permian activity and other less economic oil basins shifting to decline. Meanwhile, in the Haynesville, we still have not seen activity pick up and believe any activity additions will be disproportionately impacted by tariff-driven inflation.

Thus, we are increasingly uncertain as to where this required production growth will come from in such a short time in our increasingly bullish gas prices. On the demand side of the equation, we do not expect notable disruptions from recent macro events. As a reminder, natural gas demand is primarily driven by winter heating, power demand, industrial demand in LNG and pipeline exports and has a negligible correlation to macroeconomic demand cycles. Looking back at a worst-case scenario from 2020, industrial demand declined by less than one Bcf per day or less than 1% of total demand, and we don’t believe a modest recession would have nearly the demand impact as COVID. Further, we do not expect any impact to LNG exports in the medium term due to low inventory levels in Europe and thus expect exports to flow at full capacity.

We are also observing a faster-than-expected ramp-up from the new Plaquemines LNG facility, which is operating above nameplate capacity. If this outperformance continues and Golden Pass comes online before year-end in accordance with Exxon’s guidance. And as recent FERC filings indicate as possible, substantially more production will be required to keep 2026 in balance. All told, we are a more bullish medium-term gas prices today than we were last quarter. During risk cost periods like we’ve seen recently, the market has trouble distinguishing signal from noise. However, we are convinced that when the dust settles and the fundamental picture becomes more clear, natural gas prices are positioned to move materially higher, particularly in 2026.

The longer this macro and certainty remains, and the slower the activity response, the more bullish we become. To wrap it up is demonstrated through our record-breaking results. We continue to deliver on our promises, tangibly proving the power of our integrated platform and the unique earnings power of our business in all market cycles. Our ability to quickly adapt to market conditions and a capital-efficient manner, while concurrently driving operational efficiencies, is fueling outsized free cash flow generation. Looking ahead, we see a clear path for sustained momentum and continuing to create differentiated value for shareholders. With that, I’d now like to open the call to questions.

Operator: [Operator Instructions]. And your first question comes from the line of Doug Leggate with Wolfe Research. Doug, please go ahead.

Doug Leggate : Hey, good morning, guys. Nice to embarrass everyone in the free cash flow number. So, thanks for that, but congrats on a strong quarter. I have two unrelated questions if I may. Toby, first, I’m addressing it to you. It might be Jeremy wants to answer this, but on Olympus, big equity component, 1% dividend yield, so cheap way of doing the deal from a cash outflow standpoint. But I’m curious what it does to your levered break even to the extent you can offer any color on post-deal sustaining capital and what that how you see the lever break even today. Obviously, we’re all watching your progress towards debt reduction. So that’s my first one. I’ve got a follow-up, please.

Toby Rice : Yes, Doug, I think it’s a great question, because you can see deals get printed and show strong financial accretion. But I think what’s really exciting about the Olympus deal is we’re seeing that accretion and doing it with a high-quality asset that has a cost structure that’s equivalent to EQTs. We think that’s really special about this and what makes a good deal on the accretion numbers a great deal for our shareholders in the long term. So, we’re really excited about that set-up and being able to get that print.

Jeremy Knop : Doug, in terms of specifics, I would say, it doesn’t really have an impact on the unlevered number. It’s modestly de-levering, as you noted, due to the equity component. It marginally improves that. But on a levered basis, we see that the break-even at about $2.35 for 2025.

Doug Leggate : Guys, just a, a quick follow-up, Toby, if I may, when you were comparing it to QP, would that also apply to the inventory depth? You guys have got 20 years, you’ve talked about. What does Olympus look like?

Toby Rice : Yes, so we’ve underwritten. Basically, just the Marcellus. So, the Utica out there is all upside. And so, we think that that’s going to be more of the longer-term play that would get an inventory depth sort of on par with what we’re carrying here. But we didn’t describe any value to it in underwriting this deal. And it’s something that we’ll work on over time. But this is directly adjacent to some of the Utica activity, not just that the Olympus team has done, they’ve done a handful of wells, but some of the other activity by other operators right there. So, I mean, there’s some things to get excited about, with the deeper Utica in this area, and we think that will pull inventory levels up, for the longer term.

Doug Leggate : Thanks. Thanks for that. My follow-up, Jeremy, is definitely for you. It’s pricing strategy. The reason for the question is we obviously saw T5 and other regional hubs blow out in the quarter, and you guys obviously have got a lot of you’ve got some constraints over how you allocate bid to be versus spot. So, I’m just curious as the balance sheet improves, as you own the obviously, you own the midstream now, you can allocate things a little differently. What are you thinking? Is there any reason to think consider whether you would change that bid week versus spot mix in your gas? And I’ll leave it there. Thanks.

Jeremy Knop: Yes, it’s an interesting question. So, a lot of times we elect a first a month because our financial hedges effectively settle against that first a month price. So, for example, if you’re 50% hedged, you probably want to have at least 50% of your production settled first a month to pair that up. As we move to a position where we are hedged less due to the fact that we do have the midstream cash flows and as our leverage drops lower and lower, we’ll have a lot more flexibility to sell more into the dailies. And we change that seasonally. So, when you think about this past quarter and some of the winter storms that came through, the amount of value you can capture selling in the daily price market is pretty material.

That’s what you saw surge production into in the first quarter. So, I think we’ll have a lot more flexibility to do that, but that’s really enabled by as a core having the midstream foundational assets and the stability of cash flow, which then allows us to hedge less, which then gives us that flexibility. So, I think the opportunity is increasing.

Unidentified Analyst: Great stuff. Thanks, so much guys.

Operator: And your next question comes from the line of Devin McDermott with Morgan Stanley. Devin, please go ahead. Devin, your line is now open.

Devin McDermott: Can you hear me? Sorry about that. So, I wanted to ask first, just building a bit on the M&A strategy and Toby, you want to kind of think back at your tenure as CEO, you’ve built EQT into a premier gas company, as you framed it in your opening remarks, peerless. It’s been through a mix of organic improvement and strategic M&A. And I think one of the impacts of the strong portfolio you have right now is it raises the bar on any incremental acquisitions. So, beyond just Olympus, I guess the question is probably both for you, Toby and Jeremy, is what strategic and financial boxes need to be checked for further M&A? And kind of how are you viewing EQT’s role in additional consolidation from here?

Toby Rice : Yes, Devin, I think for us, I mean, our track record, I think we’ve been very consistent. I think we’ll continue to be consistent. And you’re right, the bar has gotten higher. And I think for us, we’re looking at value. And I’d say on the other hand, we’re looking at just the power of the platform. I mean, we are demonstrating an edge here, but we could be patient, and we’ve got a great business that we’re focused on. And it’s one of the reasons why we want to highlight, like our success has not been purely from the strategic M&A that we’ve done. We’ve transformed the operating model of this business. You’re seeing us flex the asset base and continue to see operational efficiency gains. That momentum is going to continue, and it’s going to continue to give us the ability to have opportunities in the future, just working this current asset base we have that we are pretty excited about.

Jeremy Knop: Devin, a lot of it just comes down to that North Star. We always talk about which is cost structure. And that’s one of the unique things about Olympus, just that integrated model and actually really high-quality wells out there, that allows us to maintain the integrity of what we’ve always focused on and do it in a really value-accretive manner. And do it in a way that preserves our balance sheet strength and, in this case, actually improved our leverage metrics on the margin. So, I wish there were more opportunities like that. There’s just fewer and fewer. So, I think it’s going to be pretty hard for us to find much going forward. But look, we’re always active. We’re looking — we continue to be focused on Appalachia. And if there’s a way to create outsized shareholder value by taking a strategic action, I think we’re always interested in that. It’s just becoming difficult because the opportunities have mostly been picked up.

Devin McDermott: Yes. That makes a lot of sense. And then I wanted to shift and ask about the in-basin demand opportunity. Toby, I think you mentioned you’re currently in discussion on dozen different in-basin demand sources and gas sales opportunities. I was wondering if you could characterize these in a bit more detail, like size, timeline, how you’re thinking about potential contract structure and also whether or not you’re still affecting that for announcement in 2025?

Toby Rice : Yes. I mean, Doug, I think it’s even — I think it’s important, yes, sorry, Devin. I think it’s important just to step back and just look at the dynamics that have taken place in this country. I mean — and this is what’s driving a lot of in-basin demand. We’ve had over 5 Bcf a day of pipeline projects that have been blocked, canceled or posed that would have taken low-cost, reliable, clean Appalachia gas and deliver it to other parts in the country. And so, you see the market opportunity for more natural gas and without these pipelines, that in-basin demand is going to grow. And that’s what we’re seeing. And specifically, on the power generation front, one of those pipelines, was Atlantic Coast Pipeline, got blocked.

That would have taken gas into data center ally for the build-out. Well, without that pipeline, people that want that power are going to move back closer to basis into our basin. So, I mean that’s the high-level theme that’s taking place. What that’s translating for us, obviously, I think EQT is well-positioned just with the sprawl of our acreage position. We’ve got a lot of shots on goal. So, we’ve got a lot of conversations that are taking place right now. This Olympus transaction positions us even closer to some of those opportunities. So, we’re excited about seeing how that could potentially translate to optimizing gas delivery to some of these opportunities. These are deals that take a lot of people putting it together. We’re still confident that it’s going to — we’re going to have something by this year.

We’ve got a lot of conversations happening, but it’s going to take some time to put these through.

Devin McDermott: Great. Thanks so much.

Operator: And your next question comes from the line of Arun Jayaram with JPMorgan. Arun, please go ahead.

Arun Jayaram: Good morning, gentlemen.

Toby Rice : Good morning.

Jeremy Knop: Good morning.

Arun Jayaram: Quick question here. Toby, there’s a lot you control as an E&P company, but ultimately, you’re a price taker. And so, I wanted to see if you could maybe address some of the benefits to EQT from having conversations with, call it, data center kind of counterparties. From their standpoint, I could see the benefit of a guarantee of supply — supply surety. Just wondering if you may help us think about some of the benefits to EQT from doing clinical data center deal. Obviously, it probably helped local basis, but what are the opportunity sets from a marketing standpoint to benefit your margins?

Toby Rice : Yes. So, I think it’s important for everybody to understand in a world where it’s energy short and you’re planning on building billions and billions of dollars in these data centers, having security of supply is critical. And that’s what’s having people come and look to go full path on their energy solutions, not just by natural gas on the spot market. So that’s what’s creating the opportunity for us to come in and talk. But I’d say the — what are we looking to deliver. I mean, these are competitive situations. There’s going to be lots of options for EQT to be successful. We have to provide the best combination of cost, reliability and carbon footprint of the emissions associated with that energy. We’re certainly very well positioned.

Our location is in proximity to some of these opportunities, I think it’s tough to replicate. And what will that ultimately will translate to, I think, will be opportunities like we’ve already shown the ability to capture. The deal we did back in ’23, which will really start hitting in ’27, ’28 with MVP of the tail pipe. I mean, as an example, I mean it will be just — I would look at it simply as just an uplift to just selling our gas locally. And we’ve got, call it, around a couple of Bcf a day of gas that’s already flowing above ground being sold in basin. That’s an amount of gas that’s ready today, that our commercial team is using to connect to some of these opportunities, and then we will have a decision strategically whether we want to backfill those volumes that we supply and that will create the opportunity for us to get sustainable growth.

So, it’s really an exciting opportunity, not just for the margin enhancements we can get, but also triggering the sustainable growth opportunities for our massive inventory base.

Arun Jayaram: Great. That’s super helpful. Maybe my follow-up is maybe, Jeremy, Slide 11, you highlighted the ability for your basis differentials to narrow by $0.30, $600 million uplift. Can you give us a sense of maybe break that out between what portion of that is just from M2 tightening versus the benefits or uplift from the long-term sales agreements?

Jeremy Knop: Yes, it’s a great question. So, if you think about the $600 million that Toby mentioned in some of the prepared remarks, that — about half of that is coming from those sales deals and the other half is coming from these in-basin dynamics, what you’re seeing on the forward curve right now. So, I’d call half of that more or less contractually locked in, and the other half just due to these fundamentals that we keep talking about.

Operator: And your next question comes from the line of Neil Mehta with Goldman Sachs. Neil, please go ahead.

Neil Mehta: Yes, thanks so much. Toby, Jeremy, for the comments. We agree with your view that the front month the gas curve looks a little oversold here. One of the questions that we’ve been getting is how you think about what that marginal molecule cost curve is? And if we ultimately need to price the Haynesville, how do you think about the price breakeven of it? I’m curious if you guys have done some work around that. And is there a scenario where you need to actually price through non-core Haynesville and go hires. Just your framework as you think about the upside of the volatility being?

Jeremy Knop: Yes. We spent a lot of time on that. I saw your team put out a note last night on that, too, Neil. Look, I think our view is that with the dwindling inventory in the Haynesville, and some of the more recent wells have much less productive results than what we saw a couple of years ago, that’s at least in the mid-4s. And with the volatility you’re seeing in the market right now, and even really over the last 1.5 months, seeing how much pricing swings around. I think the bar to make that capital allocation decision towards growth where you don’t see the return on those dollars for the past 2 years. I think you need to see the back end of the curve rise more to really incentivize that. And you’re just out there yet.

I mean, CAL26 right now is just over $4, and you’re seeing CAL27. From our perspective, I don’t think that’s nearly enough to get the level of activity back that’s required to meet some of these demand growth estimates and what’s effectively lock these LNG exports. So — look, that’s why we’re being patient in terms of how we think about hedging if we hedge it all. Near term, it’s really about balancing the March ’26 inventory balance in different winter scenarios. But then beyond that, as you get into 2026 unless you see that activity response and take production volumes materially higher. I think the market just gets upside down pretty quick. And it takes a little while, as you well know, between activity coming back and that production showing up.

So, I think if we go a couple of more months and we don’t see a material increase, it’s almost going to get — it’s going to become too late. And you almost crystalline that bullish inflection in 2026, where you kind of — you have to hope winners warm to keep the market balanced.

Neil Mehta: All right. That’s helpful. And as you think about the production that we’ve seen out of Appalachia to start the year, it has come in a little probably faster than some people expected. And I’d be curious, as you think about the production path for the U.S. from here, particularly in the base that you operate in? And was that just a pull forward in response to strong pricing and we stabilize production from here, so demand catches up and then we drive inventory?

Jeremy Knop: Yes. I would characterize it the same way you just did. I think it’s a bit of a pull forward. But I think for the next 2 quarters at least. We don’t see that growing much beyond where it’s at, certainly in the Northeast. I think it’s easy to extrapolate where you’re at. I think what we’re seeing every single year, it’s funny to be like we have this conversation year after year. You see Northeast product surge in the winter and then it comes back off at some point in Q2. Due to some of the deferred tills and DUCs, you probably have more of a flat scenario, but — again, I don’t see that rising beyond where it is today. So again, it just kind of underpins part of the reason we’re so constructive in addition to what’s happening on the liquid side of the space right now.

I think we said this in the prepared remarks, but half the volume we assumed was coming from the Haynesville in terms of growth and half from the Permian. It is harder and harder for us to see that showing up in the time frame you needed to show up. ’25 and ’26 is really is — it’s a unique time period because you do have that step change increase in demand so quickly. And you normally never have events like that, and it’s just — it’s very hard for production to keep up at that rapid of a pace. So, in the same way in 2023 and ’24, you didn’t have enough demand and you had enough supply, that’s going to flip on you and put the market into undersupplied scenario pretty quickly. So again, we think that macro backdrop is really attractive. And if we’re sitting here having the same conversation 3 months from now, on our Q2 earnings call, is going to feel like, I think, in our view, how we model it, like it’s a little too late and you’re really crystallizing that bullish setup in 2026.

Neil Mehta: Thanks, Jeremy.

Operator: And your next question comes from the line of Kalei Akamine with Bank of America. Kalei, please go ahead.

Kalei Akamine: Good morning, guys. I’ve got two follow-ups, both on Olympus here. I guess, first, a good deal. We think it’s accretive on multiple measures, and the industrial logic is there. Maybe first, can you talk a little bit about Olympus Midstream. We understand that business is integrated in the upstream and the midstream. Wondering if there are any opportunities to link that system into Equitrans? So differently, are there any synergies from linking into Equitrans? And do you see any compression opportunities which have been a big driver of gains in your legacy assets?

Toby Rice : Yes. So great question. And the answer is yes, we will be looking to tie this midstream system into our Equitrans base set of pipes we got out there. I mean I think the picture on Slide 10 just shows the proximity that we’ve got there. So that will definitely create opportunities for us to optimize delivery points. I think the thing that’s most interesting, though, is going to be seeing how we can leverage this asset base to service some new in-basin demand opportunities that we’re working with. So that certainly would be a nice synergy upside, however you want to categorize it. But we’ll be looking — our midstream team will be looking to maximize value from this asset base we have here.

Kalei Akamine: Got it. The second one is, we looked at the legacy Olympus wells and their well design looks a little bit different than yours, in fact, very different. Can you talk about whether you’re making any upside in from your own best practices onto the Olympics assets?

Toby Rice : Yes. No, we’ve been pretty conservative in our underwriting type curves here. So, there will be opportunities for us to tweak the well designs, but that is not factored into our math right now. So, things like well spacing and some of the completion intensity may be some tweaks, that would be considered upside.

Kalei Akamine: Got it. Thank you, Toby.

Operator: And your next question comes from the line of Roger Read with Wells Fargo. Roger, please go ahead.

Roger Read: Yes. Good morning. A lot of the big stuff has been hit here. But I think one of the questions we get kind of consistently is what are the out-of-basin opportunities that were not necessarily thinking of front page, but we should consider? I know long time we’ve talked about LNG in the Northeast. That seems unlikely. But what are some of the other opportunities we should be paying attention to there?

Toby Rice : Well, I think it’s just important to note, like we’ve got, I think, the hottest trend happening in our backyard with the power gen. I mean a lot of the focus on LNG was really driven by the fact that, that was the big source of demand for natural gas. But now we’ve got a more bullish opportunity happening in our backyard with this AI data center thing. So, I mean, I would say I’d be focusing on that, that’s certainly where we’re spending most of our time.

Roger Read: Appreciate that. The other question I have, you’ve done a lot of acquisitions. There have been some dispositions along the way, maybe a little premature with Olympus here. But are there things we should think about that will be paired at different times to bring a little more focus to the operations? Obviously, as you get the opportunity to really review everything, determine what is truly low cost and advantage within your portfolio. But is that part of the process we should presume? Or is there still just a lot more to grow within the Marcellus that we should — in other words, it’s too early to be taking any steps back?

Jeremy Knop: Roger, it’s a good question. We’re always looking at that. I think our divestitures of our non-op interest last year in those two transactions are a tangible example of that. And there’s a number of things that we’re always evaluating as a way to just continue to refocus on our core asset base and reallocate capital to what generates the highest returns. So, we’re not going to talk about specifics at this time, but there’s always things that we are looking at like the non-op last year. And I think that will be a continuous thing that we explore as we grow the business, it’s not all about growth and acquisitions. It’s just simply about reallocating capital to maximize shareholder value.

Operator: And your next question comes from the line of Jake Roberts with TPH. Jake, please go ahead.

Jacob Roberts: Good morning. Start out with on the increase of the third-party revenue guidance relative to last quarter. If you could speak a little bit about what’s driving that as well as if you see the update as kind of the upper bound on the potential?

Jeremy Knop: Yes. So, one of the things that we’ve done, it’s effectively counting reallocation to some of what we had captured in the gathering line item before has been reallocated to that revenue line item, just a little bit more consistent apples-to-apple. And if you look back to how Equitrans accounted for that as well, is more consistent there, too. So that’s effectively what’s going on. But I wouldn’t say it’s a fundamental change in the business.

Jacob Roberts: Okay. Great. And then as a second question, maybe a follow-up to Devin’s earlier question. Jeremy, you mentioned the limited opportunity set there for M&A. I was wondering if that applies to other vertically integrated businesses? Or if there’s a case to be made looking at the pure plan midstream market and what could be applied to those businesses that you’ve done to E-Train in the future?

Jeremy Knop: Yes. I mean, across anything we do strategically, it really starts with where do we have an edge. We’re not looking to just buy things for the purpose of buying and getting bigger. Equitrans was special in that sense because there are so many synergies between the two businesses, and we’re seeing that on full display. I think if you look back at really each of the quarters that we’ve reported since closing that deal, we beat each quarter pretty handily. And it’s kind of funny when we’re forecasting and giving guidance out. It’s hard to account for the 30, 40 very small things individually that we’re doing better. But I think what you’re seeing in these beats is the collective result of all of those small things coming through and positioning us to outperform what we said we would do.

I think that will continue. But it’s hard to look at the midstream assets and say we can have the quite same result. So, look, we’re open-minded about it. But I think our focus is at the core. We’re an upstream business, but we want to be the best version of what we can with the lowest cost structure. If there was an opportunity like Equitrans with the same benefits and synergies I think we’d love to explore it for the right value, but it’s hard for me if this juncture to think about what that really would be.

Operator: Your next question comes from the line of Scott Gruber with Citi Group. Scott, please go ahead.

Scott Gruber: Good morning. A couple of questions upfront. The last call, you guys talked about behind-the-meter deals likely seeing contracts signed at premiums to either a regional marker or Henry Hub. We’ve heard recent interest in potentially signing fixed price sales agreements since it will help lock in the spark spread for the power producer, which in turn can help bend secure financing for the plant. And then given hyperscale’s desire for line of sight to power, it could be positive economics all the way down to the chain. Are you hearing about an interest in fixed-price deals? Is that picking up? And obviously, it’s all price-dependent. But if these types of deals are possible. Just any color on the price point that takes you to be more interested in fixed price over a premium to a regional market for hub pricing? Thanks.

Jeremy Knop: Yes. I think — so what’s unique about each one of these power deals is that they all have different considerations. Some need helps with siding, some needing stream, some need gas, some need all of it. There’s different counterparty credit qualities of these different, whether it’s a developer or hyperscale or whoever we might be talking to. So, I wouldn’t say there’s a one-size-fits-all approach. Every one of these is going to be different. And we have the flexibility to structure around that. I think in the long run, what I would love to see is some sort of portfolio approach to this over the long term as they come together, where you have some of all of it. I think where you have to be somewhat careful on a fixed-price deal, though, is if it is priced at a level to factor in the upside asymmetry gas prices.

And if you fast forward 10 years from now, just so you do a 20-year deal, where gas prices probably need to be to, incentivize the marginal molecule is the Haynesville is fully depleted. The Utica is probably fully depleted. And a lot of these legacy oil basins don’t have a lot of inventory less or a decline. I think that gas price needs to look different. So, what might look good today for a fixed-price deal, halfway your contract, you might not like very much. So, I think one of the things we like about the index plus style deals that we’ve done with the Southeast utilities is it insulates you from that while also providing you a bit of extra margin for that reliability of long-term supply. So, I think we’re open to all of it, but that’s kind of where we gravitate to just as we think about it over the long term.

But look, we’ll see. We’re having a lot of really fascinating discussions with different parties up and down the chain. And like Toby said, I think we’re pretty optimistic we get something done this year. And I think Olympus advances our ability to do that.

Operator: Your next question comes from the line of Kevin MacCurdy with Pickering Energy. Kevin, please go ahead.

Kevin MacCurdy: Good morning, guys. I wanted to ask another one on the Olympus acquisition. It looks like the deal came with a nice EBITDA contribution and what looks like high implied margins. Can you talk about the midstream assets that you acquired and the effect on the OpEx? And any information on the sales points for the acquired guests?

Jeremy Knop: Yes. So, if you think about the total EBITDA of the business, about 1% of that, if you were to break it out, is attributable to midstream, so about $80 million roughly. I think one of the big benefits in terms of why the margins are so high is again that integrated nature of it. It’s being sold effectively all at M2 right now, but we do see opportunities to probably improve that. And certainly, if we were to link it to some of the adjacent data center power projects that are right there in that area, that could obviously be a huge improvement beyond that. It kind of sits right at the junction between the M2 and M3 markets. So, we’re probably going to explore whether there’s a way to move some volumes into that more premium market along TeCo. But that’s something that I’d say is a synergy that could develop in the coming years, but it’s not a tomorrow type of event.

Kevin MacCurdy: Great. I appreciate all that detail. And for my next question, I wanted to ask on the change on MVP capital contribution guidance. Is that just timing of spending? Or is there something on the cost of that project that is increasing?

Jeremy Knop: Yes, I’m glad you asked that. That’s an important clarification. So, it’s actually an accounting change. There’s actually no difference. If you look at the change to distributions and that changed the contributions, they actually offset each other. It’s just a difference between how we assumed, we would just recycle capital within the MVP JV before. So, there wouldn’t be an actual contribution, that’s unchanged. Except from an accounting perspective, we still have to book it as a distribution out and a contribution in effectively. But net-net, I wouldn’t — I don’t think at the bottom line, there’s any real difference in how we forecast the fusions or what MVP will generate for us or our partners.

Operator: Your next question comes from the line of John Ennis with Texas Capital. John, please go ahead.

John Ennis: Good morning, guys. Thanks for taking my questions. For my first one, just on the synergy front. Can you elaborate on the specifics that drove that $85 million in savings since the last update? And the ongoing initiatives that could drive additional upside that you’ve highlighted in the presentation?

Toby Rice : Sure. Great question. Happy to provide some more color. So since last quarter, we’ve obviously revised our synergy capture up. Some of that is going to be on water disposal costs, CapEx synergies from us to seeing if we can optimize some of the spend that’s happening on the CapEx projects. But really the real just comes on the receipt point and system optimization efforts that we’re doing. So, this is just moving volumes to optimize the receipts of the receipt points and capture some spreads there. So those are going to be some of the opportunities that we’re going to be looking for also on the — to recreate on the Olympus asset. Going forward, what we really are looking at on the upside there is going to be really more in the discrete projects bucket. So are there going to be some projects that we can identify as to continue this momentum is what would be making up the remainder of the upside there.

John Ennis: Makes sense. For my follow-up, one of the questions we get most often is what market conditions would cause you to exit production growth. How would you frame your thought process in deciding to grow volumes if the market is calling for it?

Toby Rice : Yes. I think it’s pretty simple. The market calling for it is not just price signal. It’s going to be a demand signal. So, we’re going to have a firm supply deal. And we will make sure we grow volumes to meet that firm supply. I think it will be pretty simple. So that’s sort of how we’re looking at it right now. And I think that’s where we’re going to be for a little bit until we get back to a place where we get a market that is more well connected with more pipeline infrastructure. I think we need to be more prudent in making sure that we see the demand before we bring volumes.

Jeremy Knop: Yes, John, I think I would distinguish the difference between growing to sell to the market versus sell to a customer. And we’re trying to pivot our business to sell to a customer in a large-scale way. And that’s very different than, I think, the way a lot of our peers look at it, and I think the way operators have approached this in the past, and it’s really only possible just due to the platform we’ve built a — investment retention and all the other attributes we talked about. So that’s why we’re so focused on these different power data center and other industrial opportunities because that’s really what we’re trying to turn the business more into is those to one that just chases price and has to float up and down on the wave of volatility quite so much. trying to transform the business in a sense. We think that’s just a much more durable, higher quality way to manage the company over the

Toby Rice : Yes. And I think it’s worth pointing out, too, I mean, to take advantage, I mean, price signals, we are going to be taking advantage of that with our existing asset base. I mean, if you look at, I think it’s Slide 7, we’re showing a — over 2 Bcf a day of volumes swing. So, we are being responsive to price and giving more volumes when the market is calling for it. But having that trip into activity levels, it’s going to be more of the dynamics that Jeremy to just put color on.

Operator: Your next question comes from the line of David Deckelbaum with TD Cowen. David, please go ahead.

David Deckelbaum: Toby, I’m curious, just as a data center opportunity develops here in basin. How do you square those opportunities or put it in context relative to your LNG strategy and those opportunities as it relates to contracting and the ability to improve commerciality of your products going forward?

Toby Rice : Well, I think those opportunities are going to be much lower cost access to get there. I mean I think that’s the first consideration. These are going to be happening in our backyard not on the other half — on the other side of the country, ultimately with gas consumers across the world. So, I think it’s really easy for us to know the parties and create custom tail solutions that gives them the best combination of affordable reliability. And there’s just a lot of them over here. So, I mean, we’ve gone from a card where we were having to — I think we’re going to be needing to stretch the commercial footprint of our business, which is fine. We sell gas across the country. But having these opportunities in our backyard, I think, is going to be a little bit easier. And the cost associated to connect those opportunities is a much lower bar, and we’re not going to be needing to sign up for big tolling fees to get access to these opportunities and margin uplifts.

Jeremy Knop: Yes. I think, David, to remember, we have 1.2 Bcf a day down in that into the Gulf market that LNG corridor as it is. That’s probably more than we would ever look to sign up in those LNG contracts for the reasons Toby said it just creates too much financial risk for the company. which is why we’ve set that limit around 5% for the amount of LNG that we’d probably like to sign up for exports, at least the size and scope of our business today. We think beyond that, it just creates too much financial risk. So that’s why beyond that, we’re looking back towards where that demand is domestically and to effectively take a very high-priced FT style commitment to export as around the world to sell to a utility, when we have utilities calling us virtually every day to supply their power plants, adjacent to our operating footprint.

I think for us, we can grow more quickly with less financial risk supplying that market domestically right now than we necessarily would be able to, on a much longer-term basis through LNG market. So, it’s going to be all of the above. We’re obviously looking to serve any demand that shows up. But if we can serve the same in the market in essence and do it a lot more efficiently, cheaper and faster. I think we’re going to look to do that before trying to chase an LNG project that takes years and years to even come online.

David Deckelbaum: Makes plenty of sense. And perhaps just for my follow-up, just on a clarification on how you view the Olympus assets strategically. And you highlighted, obviously, you’re picking up 0.5 Bcf a day in an area where there’s some emerging demand on the power side. I guess how do you square those opportunities on the Eastern portion of your acreage versus sort of the Ohio side? Is this more responding to what you see as a, a more compressed time line in the Western Ireland area from maybe some brownfield projects? Or is this just more of a matter of balancing the production footprint between those two areas?

Toby Rice : I think this is more of just increases our ability to get more opportunities, closer in our operating footprint. We’re going to be — we’re looking at opportunities across our entire operational footprint. Olympus is pretty special in the fact that it’s close to the industrial corridor in Pittsburgh, where a lot of people are looking at opportunities. So, it puts us right next to some of these opportunities. So, we’ll be exploring those.

Operator: Your next question comes from the line of Noel Parks with Tuohy Brothers. Noel, please go ahead.

Noel Parks: Good morning. Actually, that last question was something I had been wondering about. So, is it fair to say then that the timing of Olympus was just a — because I’m assuming that these are assets you’ve been aware of for a long time, was sort of uniquely because of the anticipation of in-basin power industrial corridor?

Toby Rice : I think this deal would have made sense without the upside opportunities that the data center — data center opportunities would present. So, we look at this as pure upside. And when we think about the volumes here with the Olympus asset base, I mean, when we are — if we can tie in our systems, it will be a way for us to connect our entire asset base in Southwestern Pennsylvania up to the industrial corridor. So that $500 million a day of gas that’s flowing today will be connected, will be supported with a huge amount of inventory that we could use to flex the service volumes way more than the $500 million a day that’s coming from the Olympus asset base today. So, I mean all to say, people that are thinking about putting data centers in the Pittsburgh region. We’re going to make sure that you have all the energy you need to achieve the power demand goals that you have.

Jeremy Knop: Well, I mean, we look at Olympus it was a value by right asset, right time, is a win-win deal for both sides. I think Blackstone sees a lot of upside in our stock at the same time. And look, I think the optionality created both on the ground leasing in that area, which is pretty inexpensive, can add some really attractive runway, we already do in our base business every year to really extend that inventory depth beyond the, call it, 15 years of really high-quality inventory that we already see right there. We think is really competitive. And again, like Toby alluded to, I mean, two of them, probably higher probability power data center opportunities that we’re in discussions with are located effectively right there, one of which could be one of the largest projects in the country.

So, I think it positions us really, really well as we continue that dialogue. And again, as we just think about the region in total, in the way we’re positioned, whether it’s in the Ohio market, whether it’s Pennsylvania market or even parts of West Virginia, where we’re inductions on projects, I think we should really be looked at as the go-to supplier of choice for any gas needs for any of these — any of these businesses. So, it’s really just improving our positioning in those conversations.

Noel Parks: Great. And I was wondering, I wanted to take your temperature on — with the macro commentary you’ve made and looking at the setup was LNG over the next few years. Do you have a sense or a stance on whether we are heading into effectively a greater volatility in gas and maybe ultimately reflected in the strip? Or do you think that sort of the reduced seasonality net-net is going to lead to more stability? And just to follow on that, I was just sort of wondering if, if you have any appetite your balance sheet improves for investing inputs as part of your hedging strategy?

Jeremy Knop: Yes. I think as we’ve been talking for a couple of years now, we think volatility is only going to increase. And that’s the reason we’re trying to position and scope the business how we have. I mean if you look back at early November, we had curtailed and we have a really interesting slide on this in our deck that you should look at This has some pretty good granularity on this and what our curtailment program has allowed us to do. But we curtailed at least 1.6 Bcf a day in the first week of November. Two months later, we not only had all that back, but we had actually surged production above our baseline. So, you saw effectively a 2 Bcf a day swing to make sure that we can actually capture the volatility, not be harmed by it on the downside, and a position to capture more of that upside value when you see the.

If you’re in a position where you get completion crews out there and frac wells chasing pricing. I mean look, if you would have done that 2 months ago, all of a sudden, you’re bringing wells online now at pricing that’s $2 below actually more than that, if you look at just Appalachian pricing, where those price levels are. So, we can be very prescripted, very tactical as we optimize around that volatility. And again, having the foundational assets of Equitrans with the operational flexibility of EQT to maximize profitability. It’s sort of like this extrinsic value that doesn’t get picked up easily in financial models. But as I noted before, it in to just observe that every quarter since we have acquired Equitrans, we consistently beat. Part of that is operational and part of that is what we’re able to do on the commercial side of things.

So, we hope that continues. We expect it to continue, and that is just more and more important as we go through these ups and downs of volatility that we expect to probably get more extreme in the coming years.

Toby Rice : Jeremy, I think that was very well set. And if I had to say it very simply, EQT is a business that is designed to evolve and align our operations with the current environment and EQT is a business that’s going to thrive in volatility. And I think everything we’ve done that Jeremy just put color on is an example of that.

Operator: There are no further questions at a time. That concludes today’s conference call. You may now disconnect.