Q2 2025 Earnings Call Transcript

Thank you for standing by. I would like to welcome everyone to EQT Q2 2025 Quarterly Results Conference Call. [Operator Instructions] I would now like to turn the call over to Cameron Horwitz, Managing Director, Investor Relations and Strategy. Please go ahead.

Good morning, and thank you for joining our second quarter 2025 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'd 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 factors described in yesterday's earnings release, in our investor presentation, the Risk Factors 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 reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

Thanks, Cam, and good morning, everyone. Second quarter results continue to showcase strong momentum at EQT. Production was at the high end of guidance, benefiting from robust well productivity and outperformance from compression projects. Year-to-date, our compression program is ahead of schedule, below budget and driving production uplift well above expectations, showcasing continued synergy capture from the Equitrans acquisition.

Capital spending came in approximately $50 million below the low end of guidance, driven by midstream spending optimization, continued improvements and completion efficiency and lower well costs. Our team set a new EQT record for completed footage per day during the quarter, and we believe there is still significant room for additional improvement. This strong performance resulted in approximately $240 million of Q2 free cash flow attributable to EQT despite $134 million of net expense incurred relating to a litigation settlement that resolved outstanding securities class action litigation. We view this settlement as a positive step forward for EQT as it resolves remaining, meaningful legacy liabilities inherited by current management.

Without this legal expense, second quarter free cash flow attributable to EQT would have totaled approximately $375 million, materially exceeding expectations. To put into perspective, cumulative free cash flow generation totaled nearly $2 billion over the past 3 quarters despite natural gas prices averaging just $3.30 per million Btu over this period, highlighting the differentiated earnings power of EQT's low-cost platform. Shifting gears. We closed on our acquisition of Olympus Energy on July 1, funding the deal with $475 million of cash on hand plus the issuance of approximately 25.2 million shares active purchase price adjustments.

Recall the assets comprise a vertically integrated, contiguous 90,000 net acre position offsetting EQT's acreage in Southwest Appalachia with 500 million cubic feet per day of net production and over a decade of core Marcellus inventory, along with significant upside optionality from the deep Utica. The teams are off to a fast start integrating the assets, and we expect to have the bulk of operational integration items complete within the next 30 days. We also see the opportunity to organically bolt on low-cost acreage around the Olympus assets, which could materially expand inventory duration in this area.

Turning to strategic growth opportunities. As discussed over the past several quarters, we have cultivated a significant pipeline of low-risk, high-return projects that should drive sustainable growth for our midstream and upstream businesses in the years ahead. Several of these projects recently crossed significant milestones, thus derisking the path to value creation. First, we are concluding the open season of our MVP Boost project, which is set to add 180,000 horsepower of compression to the MVP mainline and increased capacity from 2 to 2.5 Bcf per day.

This project will provide additional takeaway from Appalachia into Virginia to serve the Southeast markets, unleashing reliable, low-cost, low emissions natural gas into a region that is seeing significant demand growth. As a result of strong project momentum, we have elected to jump start long lead time orders this year in order to derisk the MVP Boost construction time line. We are also continuing to advance the MVP Southgate project and expect to receive the FERC environmental assessment in October of this year. MVP Southgate will provide 550 million cubic feet per day of capacity from MVP mainline into the Carolinas, serving anchor customers, Duke Energy and the Public Service Company of North Carolina.

This project will significantly enhance the reliability of natural gas delivery into this key growth market, reducing energy costs for consumers and support the replacement of coal. MVP Southgate and MVP Boost are projected to begin service in 2028 and 2029, respectively, following the anticipated commencement of the Transco Southeast supply expansion. Additionally, we are working to finalize our 20-year definitive agreement with the Frontier Group of companies to provide, long-term natural gas supply for the Shippingport Industrial Park project Northwest of Pittsburgh. The project will convert a retired coal power plant into a large-scale 3.6 gigawatt natural gas power generation facility with peak natural gas consumption of approximately 800 million cubic feet per day.

The project has secured a partner to build a co-located data center facility to support AI infrastructure and contemplates several phases of development beginning in 2027 and ramping through 2028, providing significant upstream growth optionality for EQT to meet increasing demand. We are also working to finalize our 20-year definitive agreement with Homer City redevelopment to build midstream pipeline infrastructure and be the project's exclusive supplier of natural gas. Once completed, Homer City will be the largest natural gas power plant ever built in North America, with an existing grid interconnection for added reliability to support AI data center loads across its 3,200 acre campus.

The facility will consist of 7 new gas turbines powered by 665 million cubic feet per day of EQT's low emissions natural gas. We plan to leverage our newly acquired Olympus assets to supply the facility as it ramps up before reaching peak capacity in late 2028. Additionally, we signed an agreement to build midstream infrastructure serving a new 610-megawatt combined cycle natural gas power plant in West Virginia, with gas demand of approximately 100 million cubic feet per day that will serve the PJM market. This project is poised to be the state's first large-scale gas-fired power plant and is being developed by a global investment-grade power company in partnership with a marquee private equity sponsor.

In service for the project is expected in 2028 and the commercial structure includes a 10-year term with recontracting optionality. We also secured a new gathering contract with a large private producer to expand capacity on our Saturn pipeline system in West Virginia. This project is expected to be in service in 2027 with a 10-year initial term and is backed by attractive minimum volume commitments. This opportunity highlights success with our strategic initiative to grow Equitrans' third-party business, which further lowers EQT's free cash flow breakeven by driving stable, fee-based revenue growth.

Collectively, these projects represent a pipeline of nearly $1 billion of organic investment opportunity with premium, low-risk supply agreements which we estimate will generate an aggregate free cash flow yield of approximately 25% once fully online. This is particularly noteworthy given the relatively low-risk annuity-like cash flow streams from the infrastructure components of these projects, which are underpinned by the deepest, highest quality natural gas resource in the United States. Further, this free cash flow yield is prior to any potential benefits from local basis improvement in the upstream growth optionality created by these projects.

The shipping port and Homer City facilities, the West Virginia power plant, the increase in MVP utilization plus the MVP Boost expansion represent new Appalachian gas demand of nearly 3 Bcf per day. This demand will be served in large part by EQT volumes flowing predominantly through EQT infrastructure, underscoring the differentiated growth opportunity for EQT. Through our integrated platform, we are demonstrating what responsible, sustainable growth looks like for oil and gas companies. This means partnering with end users to enable new demand, then meeting that demand with supply backed by firm contracts rather than simply chasing commodity price signals.

This tremendous opportunity is unique to EQT, enabled by the past 5 years of strategic work transforming our business and highlights what is possible when you have the combination of a low-cost structure, scale, integrated high-quality infrastructure, a multi-decade core inventory and investment grade credit ratings. As we highlighted last quarter, the next leg of our corporate strategy is built on the dual pillars of reducing cash flow risk and creating pathways for sustainable cash flow growth. And these projects represent a tangible step forward in executing that strategy. I also want to give a special thank you to our leadership in the state of Pennsylvania.

Senator McCormick and Governor Shapiro as well as the administration in Washington for taking bold steps to unlock the vast economic potential of the region and shining a spotlight on the massive opportunity for technology and AI to prosper in the Pittsburgh area. As we have demonstrated, EQT is ready to do its part and deliver affordable, reliable and low carbon energy to power this growth. And with that, I'll now turn the call over to Jeremy.

Thanks, Toby. Our strong second quarter results and free cash flow generation drove continued deleveraging of our balance sheet. We exited the quarter with $7.8 billion of net debt, down approximately $350 million compared to Q1 and marking nearly $6 billion of debt reduction over the past 3 quarters. The recent closing of the Olympus transaction accelerates our deleveraging plan and enhances our debt to free cash flow metrics.

Pro forma the transaction, we remain on track to achieve our year-end 2025 net debt target of $7.5 billion. Over the medium to long term, we plan to operate with a maximum of $5 billion of net debt, which is roughly 3x free cash flow before strategic growth CapEx at a $2.75 natural gas price. As a result, we will continue to focus on debt paydown, even after achieving this near-term $7.5 billion target. In higher parts of the commodity cycle, we plan to accumulate cash on the balance sheet and drive net debt well below $5 billion, creating significant flexibility for countercyclical buybacks and to build capacity for high confidence reinvestment and growth even during the low parts of the commodity cycle.

Turning to our recently announced pipeline of growth projects. We expect these projects to create a collective growth CapEx opportunity of approximately $1 billion over the next several years, and we expect to begin spending capital on associated infrastructure in 2026 with investments spaced out over a multiyear period. We structured the 2 data center projects as Index-plus style deals on fixed volume commitments. Similar to our existing contracts with the Southeastern utilities, these contracts give us confidence in leaning into moderate, midstream and upstream growth due to the lower risk nature of these agreements.

Similarly, the midstream growth projects were all backed by fixed fee contracts and minimum volume commitments, providing low-risk, high-return earnings growth pathways for EQT. While we cannot disclose specific contract terms or end customers, before the impact of upstream volume growth or basis tightening, we expect these projects to add approximately $250 million of recurring free cash flow by 2029. Initially, we will reallocate volumes to fill this new demand, followed by steady, mid-single-digit multiyear growth. We have the capacity to grow production by at least 2 Bcf per day to backfill these volumes, which means we've set the stage to responsibly grow the business by at least 30% over the coming years.

These sustainable growth opportunities distinguish EQT among industry peers, while also providing unmatched risk-adjusted exposure to natural gas prices. Furthermore, we are as confident as ever that Appalachian basis should structurally tighten through the end of the decade, and we indexed the supply deals to local pricing points to benefit from this uplift relative to Henry Hub, in addition to the contractual premium. Turning to capital allocation. As we achieve our deleveraging goals and organically grow the business, we will measure our free cash flow available to invest after the deduction of maintenance CapEx only.

Of that remaining bucket of free cash flow, we plan to allocate first dollars toward high-return, low-risk sustainable growth projects like the ones discussed today. These large projects follow on the heels of the strategic growth investments in water infrastructure and compression that we have made over the past 2 years and are now the key drivers of the operating efficiency gains and outperformance we've become accustomed to seeing in our quarterly results. We expect this high return reinvestment to drive sustainable earnings growth which should enable us to confidently grow our base dividend and ensure it is bulletproof in all parts of the commodity cycle.

Beyond organic growth and our base dividend, we plan to use excess free cash flow opportunistically to further reduce debt, patiently build up cash or opportunistically buy back a significant amount of shares during the market down cycle. Turning to hedging. We tactically added a modest amount of hedges for the upcoming winter to take advantage of call skew in the options market. We hedged 10% of costless collars for December through February at an average price floor just above $4 per MMBtu and an average ceiling price around $7 per MMBtu.

Note our updated hedge table also includes hedges that were novated with the Olympus acquisition, covering approximately 5% of our production through Q1 2027. We will continue to patiently look for hedging opportunities like this and position EQT to realize higher-than-average gas prices through the cycle. Turning to natural gas macro, while there are near-term headwinds primarily due to production growth, we continue to hold a structurally bullish view for prices as we look out to 2026 and 2027. First, on the supply side, there is growing evidence that associated gas growth is slowing. The oil-directed rig count has declined by approximately 50 rigs or roughly 11% since April.

While Brent and WTI pricing has rebounded off their April and May lows, we believe global oil markets still lean towards oversupply, particularly given OPEC's strategy to rapidly add back barrels and defend market share. That backdrop suggests U.S. oil activity will remain subdued into next year as operators stay disciplined and focused on shareholder returns. Critically, this curbs a major source of incremental gas supply. At the same time, the demand picture continues to strengthen as we expect a meaningful step-up in LNG exports by Q4 with Plaquemines LNG reaching full rate and Golden Pass LNG beginning operation.

This increase is on top of the 2.5 Bcf per day of LNG demand growth we've seen since the beginning of 2025 and should quickly tighten balances, especially as U.S. dry gas supply struggles to keep pace. Based on recent and upcoming FIDs, U.S. nameplate LNG capacity should grow to north of 30 Bcf per day by 2030, which we believe will drive structurally higher U.S. pricing next decade. At the same time, Qatar recently delayed the in-service of their new LNG capacity from early to mid-2026, further increasing our bullish near-term outlook. Due to surge in gas production, the current market is loose with storage levels 6% above normal, but this environment is self-correcting.

Lower pricing in the near term should disincentivize dry gas producers, who are chasing prices by increasing activity, especially in the marginal Haynesville play, where well productivity is beginning to degrade, a clear sign of inventory exhaustion. Shifting to guidance. We have issued an updated outlook pro forma the Olympus transaction. Our updated 2025 production guidance range is 2,300 to 2,400 Bcfe, which includes approximately 100 Bcfe of production contribution from Olympus in the second half of the year.

We are lowering our operating expense guidance range by approximately $0.06 per Mcfe, driven by accretion from the Olympus transaction and continued base business outperformance, while keeping price differential guidance unchanged. As you recall, last quarter, we reduced our full year capital guidance as tangible evidence of efficiency gains. Despite the acquisition of Olympus on July 1, and the associated $100 million of incremental second half spending, we are maintaining our full year capital guidance range of $2.3 billion to $2.45 billion. This is once again a tangible representation of continued efficiency gains within our base business, which without Olympus would have driven our capital spending well below the low end of guidance.

All told, production is up, operating costs are down, and capital efficiency continues to improve. And finally, we have modestly increased capital contributions to equity method investments, reflecting our decision to preorder the compression horsepower for MVP boost due to the growing backlog for this equipment. Note this is not an increase in CapEx, but simply a decision to pull forward an existing expenditure from 2026 into 2025. And with that, I will turn the call back over to Toby for some concluding remarks.

Thanks, Jeremy. To conclude, we've posted another stellar quarter of both operational and financial results, with the outlook continuing to improve. Our pipeline of differentiated strategic growth projects that we discussed today, places EQT in a peerless position within the industry and underscores the differentiated investment opportunities emerging from our integrated platform. We have unlocked sustainable growth, while also increasing free cash flow durability, the combination of which we expect to drive cash flow growth and further valuation multiple expansion for shareholders.

The momentum at EQT has never been stronger in the sense of purpose and excitement inside the company has never been greater. With that, I'd now like to open the call to questions.

[Operator Instructions] And your first question comes from the line of Doug Leggate with Wolfe Research.

I got to say I love Jeremy's -- we'll continue to build cash. I think you know our views on that. So happy to hear that message continually delivered. But my question is whether you can do that while spending on the tremendous growth setup that you've laid out and obviously accelerated in the last couple of months of the announcements.

So I wonder if you can address the key question perhaps for everybody this morning, which is what's the CapEx cadence to get to that $250 million of free cash flow growth by 2029. Maybe, Jeremy, you could also address your nonstop build multiple as to whether you're hinting at monetization at some point.

Yes, Doug, great question. And I think what's really important and what we really want to reiterate is that we have the ability to generate robust free cash flow, delever and fuel this sustainable growth opportunities. When we're talking about the $1 billion of CapEx on the -- really related to the midstream side of things, that's going to be back weighted closer towards '28. So we'll see a little bit of that show up in '26, but then it will start showing up closer to '27, '28. And I think the other point that's really important on the upstream side of things, keep in mind, we've got 2 Bcf a day that's already producing local.

We have the opportunity to reallocate those volumes to feed these facilities. That is going to give us a tremendous amount of flexibility to be very thoughtful with our upstream production growth. And I think both of these opportunities are going to allow us to continue to make sure that we're allocating capital where we think is best, continuing to pay down deleveraging, but also being able to capture these exciting sustainable growth opportunities.

Doug, when you think about the cadence of when the spending shows up that Toby just outlined relative to when we have a lot of cash coming in the door, I think if you look at where we are at by the end of next year, since a lot of the spending is really picking up in '27, '28, I think our debt is going to get so low at that point that it really lines up really nicely where there's not a lot more debt to repay at all, certainly on a net basis. And it's a natural point where we can start shifting dollars towards these really high return opportunities. And I'd also note, too, that at that point in time, when we look at our forecast, it kind of where strip is in the high 3s, I mean we're generating north of $3 billion a year.

And so you get to a level where our net debt can be approaching 0 and there's still a lot of dollars left over. So I think we have opportunity both ways and a ton of flexibility no matter how the macro plays out.

That's very clear. Guys, my follow-up is a quick one, it's really a note to Toby's question. What would it take for you to add production as opposed to reallocate production? I guess it's a macro question into that 2 Bcf that you laid out, because obviously, the potential uplift in associated free cash flow, call it, a couple of dollar margin could be enormous.

But what would it take for you to actually grow production? I'll leave it there.

Yes. So we're not going to be blind to what the market is showing there. So we will be thoughtful on the pricing that we're seeing there. And that will factor into our decisions on how -- I'd say, how fast we move from reallocating towards growing the production.

But Doug, you mentioned this opportunity for us. Just to highlight this growth opportunity and what this means in an end-state scenario, let's just use a Bcf a day of growth. That will translate to, call it, 360 Bcf of increased production. End state, looking at our cost structure, about $2, take a $4 Henry Hub price, you're talking about $720 million of free cash flow, throw an 8% yield on top of that, free cash flow yield, that's $9 billion of value, about $15 a share.

So just a Bcf a day is basically a 25% upside to share price now. So it's attractive, but we're going to continue to be disciplined and thoughtful about this. And like I said, we've got the volumes so that we have the flexibility to make the right decisions.

And your next question comes from the line of Devin McDermott with Morgan Stanley.

So I wanted to come back to the capital side, but talk a bit more just about the base business. If you look at this year's results so far, it's the second quarter in a row of CapEx reductions and volumes at the high end of guidance, even with some curtailments in the quarter. So I was wondering if you could talk a little bit more about the evolution of capital on that side over the next few years. So you have the roll off of compression spending, you have the reduction in D&C spending that comes along with the synergy targets.

So how much room does that give you relative to current capital budget to then layer in some of the strategic growth later in the decade, if that question makes sense? Just kind of putting all the pieces together on the total capital budgets.

Yes. It's good question, Devin. I think as we move into 2026 and 2027, you're going to see the maintenance piece of our spend come down, but you will see the growth piece of it go up. That is by design.

That's what we've been intentionally driving towards for a couple of years. We're still trying to add up and determine exactly what's in 2026 versus '27 as that ramp increases. So I'm not going to give out any specific numbers today, but I would say between the projects that we outlined on Slide 9 of our investor deck, our goal as a team is to try to build those opportunities to create and accelerate value. But I think it's well noted that the efficiencies in the underlying base business are driving down the maintenance piece of that capital spend, which is what our goal is to have everybody be able to see very clearly separate from the value-creating growth wedge that's added on top of that.

Yes. Okay. Makes a lot of sense. And then maybe we just kind of step back, you had talked about earlier in the year maybe announcing one power deal in 2025. And here, we have multiple strategic growth projects already executed by the middle of the year across both upstream and midstream.

I was wondering if you could just talk a little bit about the opportunity set as it sits today. Have you executed on your targets at this point? Is there still more room to run? How are you thinking about the longer-term evolution of strategic growth and the opportunity set for in-basin demand?

Yes. Devin, when you look back at some of the, I guess, guidance we provided in prior earnings calls, we said probably seeing of the 6 to 7 Bcf a day of in-basin demand, 2 Bcf a day of that was data center driven. And when you step back, you think EQT maybe will capture a Bcf a day of that 6 to 7 Bcf of in-basin demand. And here we are sitting with over 1.5 Bcf a day of power demand opportunities that have been captured and brought in here for EQT.

So really 2 things here. Either we've significantly underestimated the size of this opportunity or we are over executing on our ability to capture these opportunities. One thing is for sure. There's -- this is a good first step.

We still see other opportunities in the pipeline. And one of the other things that I think is important to note is the cluster effect of these AI data centers and these ecosystems, I think, will only continue to build on themselves. So as momentum grows in our operational footprint, we think the opportunity could get larger.

And your next question comes from the line of Arun Jayaram with JPMorgan.

My first question is I appreciate the detail on the shipping port in Homer City deals that you're pursuing, you talked about a multiphase development in 2027 and '28. I was wondering if you had thoughts on the time line to reach the full 800 Ms on the Shippingport facility and 665 in Homer City. What do you expect is the time line to reach those volume commitments?

Yes. Good question. I think for both of them, we think about it as year-end 2028. There will be a ramp phase. Homer City has those turbines being delivered beginning next year.

So I think you could see that one pick up a lot sooner, and we can, through our Olympus assets start to bring some volumes to that facility a lot sooner than we otherwise would be. So flexing the operational capabilities after that acquisition. . But I think to really be able to reach full rate, the way we model it is really year-end 2028, which just as a reminder, Arun, when you step back and think about what that means, that's also the same year that the Transco expansion comes online, MVP Boost, Southgate, it's all happening right in that same period of time. So that's the period too, going back to, I think, Doug's questions on the timing of growth that we're really looking at.

We're going to bring growth into the market. That's when the market is really going to need it. We have flexibility because of the reallocation, but you're going to see a very quickly tightened market in 2028 and 2029 on the back of all this demand coming online in a very short period, kind of like you are with LNG right now.

Great. And my follow-up. How do you see yesterday's PJM auction clear at the price cap? How do you see this impacting gas power gen development and gas demand overall, given indications of continued power market tightening?

Look, I think it's a great demonstration of the market working to solve the problem. I mean there are certain inefficiencies in PJM that need to get worked out. We're certainly not advocates of prices being pushed so high that it's not good for society and the economy overall. And that's what we're really able to solve through our integrated platform is providing that the best solution for customers at the cheapest cost.

But look, there's power that's needed and the power is going to get built and you're seeing generation willing to be built, but at a higher price, and that's what's happening through those auctions.

And your next question comes from the line of Neil Mehta with Goldman Sachs.

Congrats again on these data center related transactions. And just would love your perspective on how you're pricing it? It sounds like you're tying it to M2 plus. And so implicit in that is a view that the differentials should be tightening up over time.

So can you just talk about how much flexibility was there to price it to hub versus pricing it locally. If there was that flexibility, why did you choose local pricing? Just your perspective on the pricing. And then I have a follow-up on near-term macro.

Yes. Great question. So we're trying to obviously get the most value out of this we can, but also provide an anchor liquid pricing point for customers so they can financially hedge if they want to take some of the volatility out. Like I said in the prior comments, we are very bullish Appalachian pricing actually relative to Henry Hub.

I know it's not the consensus view right now. But when you see all this demand show up in the face of probably half of the players in Appalachia running real thin on inventory come into the decade, it does set up for a really interesting sort of paradigm shift where I think that basis tightens a lot. So we intentionally are structuring them linked to that for multiple reasons. I think it's best for the customer.

I actually think it's best for EQT at the same time. Look, in time, in theory, you could link it to Henry Hub, but it just makes it a little more complicated when it comes to actually procuring supply, giving EQT the flexibility to find the best molecule as a solution as an example, if we're marketing gas and we want to buy gas out of one of the more liquid pools, because that's a cheaper solution, it's a lot easier to do that when pricing is already indexed to that point. You don't run any issues of having effectively like a dirty hedge. So it allows us to, again, give the best solution for the customer still have all the flexibility and have the most upside, I think, from a production standpoint.

That's helpful, Jeremy. And then the follow-up is just on the near-term macro. Maybe just as we've been surprised by some of the scripts that have come in with production at 107 is probably north of it'd be higher than what we would have anticipated in the near term. Have you guys been surprised by that?

Has that affected the way you think about how we exit October and set up for the winter? And just in general, as you think about near-term producer discipline, are we seeing some breakdown?

I think the short answer is yes. I think we -- I think our view of Appalachia specifically is from this point towards the end of the year, you're flat to down. It looks like from what the data we see the Permian is also relatively in check. You're not seeing any sort of like race to add production growth.

It's really the Haynesville and it's other basins. And again, it's more of what we've seen in the past. It's producers chasing price signals. And look, this morning, you're seeing gas approaching $3, right?

I just -- I think if we add Haynesville assets, we would be really hard pressed as to why there's justification to add activity right now. I think there was a view for the past 2 years that 2025 was going to be this year that a lot of these producers could exit and sell their businesses. And lo and behold, they do the same thing again. They push pricing down to a level where if you're in the Haynesville, you're not getting your money back, where well productivity is today at current well costs.

And so again, it's just another example of the value destruction that comes out of unsustainably chasing prices. And again, as we talk about what does it take for EQT to grow, it's lining up our supply with known demand through our infrastructure through contracts. It's a very different, much more disciplined way that we look at it. But again, it's -- if we see this continued surge of production, there's certainly downside pricing in the years ahead.

We certainly hope that didn't happen. It's not something we control. But the good thing about being the lowest cost producer and the position EQT is in today is we make a bunch of money either way. Even at $3 gas, we can make a bunch of money.

And if gas goes up, we'll make a bunch of money, too, because we can be unhedged. So it fits perfectly into how we've sculpted the business. But again, short answer is we do think production is too high. We've been surprised to the upside, and I certainly hope it doesn't continue surging.

And your next question comes from the line of Kalei Akamine with Bank of America.

The growth option here appears to be surprisingly underappreciated. You've got sufficient in-basin molecules, and that should allow you to divert a lot of it to new customers as you get your growth ramp underway. And I appreciate that it's early, but are there any guardrails that you can kind of offer around CapEx, how you plan to shape that maybe over how many years that could be spread over?

Yes. As far as guardrails are concerned, I think as Jeremy mentioned in the opening remarks, I mean, we could talk about thinking low single-digit growth towards -- to meet these volumes. And I think just the other thing I'd just mention on these opportunities that we've been able to capture. And one of the things that's special about EQT that's worth highlighting, because this is what's ultimately going to position us to continue this momentum and continue to capture these really attractive opportunities for our shareholders is just our scale, our investment grade, balance sheet, our purely the inventory, durable cost structure and the scale part knowing that we have these volumes flowing above ground, giving us the flexibility to enter these contracts.

I mean, I think all these things really position EQT well and allow us to scope our CapEx profile so that we can still show robust free cash flow while also meeting a pretty exciting sustainable growth profile.

Got it. I want to come back to the capital efficiency trend. It's been very clear over the last several quarters. Can you kind of offer a view on where leading-edge D&C capital per lateral foot metrics are compared to maybe '24 and then offer a view on how much run rate is remaining?

Yes. So I mean on Slide -- on our record-setting completion efficiency slide, I mean, we throw out the well cost from '24 to sort of where we've seen in the first half of '25. I think we'd like to continue to see single-digit improvements in well costs. So it's really good to see these optimizations that take place. We're halfway through our compression program.

So we'll continue to see benefits and uplift from that -- those are -- we're seeing twice the uplift that we were budgeting for. So there's a lot of opportunities that these teams continue to find. We're stepping into the Olympus integration now. So we're hoping to continue to find ways to optimize there.

And then you're looking at what we're doing now, leveraging these assets to also create commercial opportunities with these supply agreements. So I mean, there's a lot of opportunities for us to continue to evolve the business, not just focused on the well cost improvements.

Yes. I would also add to that, it's just important as we talked about increasing some of our strategic spend. A lot of what we've been able to achieve on the well cost side, specifically in completions is also enabled by investments we've made in infrastructure spending money to make money over the past 2 years. That's why we want to keep doing that.

That's really the undercurrent of why we keep beating quarterly results is just seeing that come to fruition. That's why we're so excited about that. The rate of return on those investments is just so high. So that -- I think that momentum continues, as illustrated on that slide Toby referenced.

And your next question comes from the line of Josh Silverstein with UBS.

I just had a question on the 2 Bcf a day potential growth here. How do you set yourself up to deliver mid-single-digit growth? Is there enough infrastructure in place already to support this or the new projects then capable of delivering that? And then do you build up any sort of backlog over the next few years to then have that as the storage to be able to deliver that when the demand is there.

Yes, Josh. So when we're looking at supplying these specific demand opportunities, we will be building out new midstream infrastructure, connect them to existing gas networks. A lot of those will be connected that EQT has our volumes connected there. So our commercial footprint is going to allow us to move gas around.

We'll be going through optimization exercise on what exactly is the best way for us to fill the supply to get to these new interconnects. But this is one of the reasons why people are selecting this region to build their data centers is because they're building on top of a lot of gas infrastructure and EQT will close that last mile and then be in a position to optimize.

Got it. And then obviously, there's a lot of focus on the power side, but I wanted to see if you can now give us an updated view on the LNG contracting plans. Based on current supply levels, it's about 20-plus of your current supply. Do you want to have 10% or so to the LNG market?

The LNG markets now look less attractive to you because of what you've been signing in the power market. So any update there would be great.

Yes. Thanks for the question. I think -- so our long-term goal in the LNG markets is actually to do very similarly what we are doing on the power and data center side right now, which is link up supply directly to an end user of that gas. That's why we're trying to contract the way we are.

Long term, we still want to have 5% to 10% at least of volume. I think as our credit ratings continue to rise, I think our appetite for leaning into more of that will also rise. I think that's more of a 2030 and beyond opportunity where that LNG market is going to really be tight and we can make a lot of money there. We're actually in discussions with a number of facilities right now.

Those discussions have actually improved and ticked up recently. So we're actually really excited about that opportunity. And I think what we're proving we can do domestically with our platform is, in essence, exactly what we plan to do internationally. We've been having conversations with some international customers that have really underscored, I think, how great that opportunity is.

But again, we just want to do it the right way. Those long-term contracts can be very costly if not structured the right way. But I think beyond what we do domestically, that is a huge opportunity for us. And for any company who has a platform like we do, that's built to do deals like this directly within customers.

Next question comes from the line of Betty Jiang with Barclays.

A - Jeremy Knop: So I think there's some element of basis tightening, but that is really taking volume, for example, that we might sell from Olympus into EGTS, take it 20 miles down EGTS and pull it into Homer City as an example, so it really is supply matching. If you look at other projects like Mountain Valley, that plant -- or sorry, that pipeline is served on the tailgate of the Mobley plant, and we deliver a lot of gas there through Hammerhead and OVCX and other pipelines. That is predominantly all EQT gas. So I think for anyone who is buying gas in MVP, you're still buying EQT gas and interfacing with EQT at Mobley. So I think there's a tremendous amount of upstream opportunity. But to the point Toby made in his opening remarks, this is predominantly EQT infrastructure, whether it's existing or new build and in a core EQT operating area, meaning it's EQT volume. So I think there's a broader view that it's -- yes, it's an opportunity for everybody in Appalachia. I think the way we see the volume is actually flowing, is it's really more of an EQT opportunity, which is why we're talking about filling it with growth and reallocating. We have a little over 2 Bcf a day today that we can reallocate. So in theory, we don't have to grow at all if we don't want to. But I think in the long term, the most value-accretive thing for shareholders is us to tailor in moderate responsible growth to backfill as we reallocate that. So I think there's tailwinds on both sides, but it's not going to be evenly distributed across producers from the way we see volumes flowing.

That's really interesting color. So along that line, when you think about your pricing signal, are you looking at M2 specifically that you need to see maybe M2 getting to narrow its discount to, I don't know, $0.50 or something better than where it's now for you to see that production like backfilling that volume response?

I think it's a combination of both Hub and M2 and EGTS. Look, if you had a weak period in Henry Hub, but also tighter basis, we might still say the cheaper thing to do is just reallocate volumes as opposed to growing to it. We could build DUCs if we wanted to just to prepare for a period where pricing been rebounded. But again, the beauty of our scale and infrastructure platform is we can be flexible.

So answer is it kind of depends. It's hard for us to concretely commit to anything this early out because this is something that's really 3 to 5 years from now. But the point is that we continue making is we have a ton of flexibility.

And your next question comes from the line of Phillip Jungwirth with BMO Capital Markets.

On the West Virginia Power project where you're providing midstream infrastructure. Is there any reason to think you wouldn't also be supplying volumes? And if this is still to come, how much does midstream give you a competitive advantage here?

I'd say that is our expectation. It's not fully committed yet. That project should reach FID in the back half of this year, operating near full utilization, that's around 100 million a day of gas supply. So it's not this sort of mega level of the other 2 projects. But I think logically, it is a project we will also supply gas to. But I think more to come on that project.

Yes. As far as the competitive edge with midstream, midstream is a competitive edge. I mean being integrated allows us not only to give them access to supply, but connect the dots for them. So I think it's been incredibly helpful as we've sourced these opportunities.

Yes. I would say, too, the one thing that Toby and I found to be really interesting is when we and our teams look at these opportunities, we start first with what is the best solution for the customer and how do we connect those dots to provide the most efficient solution. If you don't have all the tools in the toolbox between midstream and gas trading and the quantity of supply and investment-grade ratings, you just -- you simply can't offer that. You have one product to offer.

So I think for a project like this power plant, we can truly come to them and say, we have the best solution or we can create the best solution for you if it's not a market solution. And I think that's one of the reasons why we've been able to be really successful. And really, so far, the partner of choice for these big projects as they've been developed.

Okay. Great. And then on MVP Boost, the open season here, I'm not sure how much you want to get into it, but are there any initial expectations as far as interest from demand pull type customers versus producers? And more broadly, just a similar question as it relates to some of these third-party proposed pipelines out of Appalachia.

Tariffs look like they could be quite high for producers. So how do you -- how likely do you view some of these projects ultimately reaching FID?

I'd say we got to be careful on what we say because that open season is still active right now. I think our expectation is that in certain markets where there's a lot of scarcity for gas right now, the need for volumes or that egress sits more with the end users as opposed to the producers. Consistent with, I think, some of our comments in the past, I think these pipes, if and when they get built, will predominantly be underwritten by demand-pull shippers as opposed to supply-push producer shippers like you saw over the past decade. But look, we'll see when the open season concludes and we can provide more color next quarter.

And your next question comes from the line of Scott Hanold with RBC Capital Markets.

Just curious, as your balance sheet continues to improve, it sounds like you want to be a lot more opportunistic with buybacks versus may be doing it in a structured manner or whatnot. But how does potential strategic shareholders selling, say, like some of the Olympus shareholder selling, does that play into it? Would you guys be willing to kind of step up and help manage that, if that were to occur?

I mean, look, it all depends on the price. It's hard to speculate on things like that. But Look, I think one of the big opportunities that Toby and I have been talking about for the past 24 hours is for a lot of this growth that we feel really confident in looking at that in state and what that means for valuation that some of the math he walked through in the beginning, if we're not getting credit for that early on, it just opens up this huge opportunity for us to lean into buybacks with a lot of confidence, where we have a lot more we're investing behind as opposed to just what gas price do you have to believe over the coming years, which is generally -- if you're in maintenance mode, the essence of the decision you're making.

And I think what we're setting up for EQT is you can win on more things than just gas price because we're taking more control of our own future and the value creation as part of that. So I think the opportunity to buy the stock back becomes more attractive.

Got it. Okay. And then my other question becomes -- or it goes to the deep Utica opportunity. Obviously, you've talked about that underlying the -- some of the Olympus assets and probably elsewhere in your asset base.

When does that become a target that you look a little bit harder at? Do you see that as more of a longer-term option? Or is that something you're willing to test a little bit more near term to help support the growth opportunity you need on your production base?

Yes, it's a longer-term opportunity for us. That said, we could do some science work and give the team some opportunities to prove themselves on the cost side. Utica, I think we feel pretty good about the resource. It really is going to be more about the operational execution.

So I mean we could call it science because we don't technically have that labeled as noncore. But it could be a tool for us to feather in. I mean all of this, I think, would really want to have a better appreciation for the upside inventory if we continue to see momentum on the commercial front supplying these power plants, just having more confidence on inventory, I think, could be helpful. It may be a reason why we go out there and do a couple.

But it's more of a longer-term in nature.

Yes. It's kind of interesting. Good point on this, and I know the Deep Utica has got more airtime. In Southwest Appalachia, when most producers talk about inventory depth, we all just refer to the Lower Marcellus, which is really the main Marcellus member.

If you look at the Northeast part of the play, inventory numbers referenced now include a heavy disproportionate amount of Upper Marcellus, which is call it, 1.5 Bcf per 1,000. And you look at the Haynesville, most of those numbers referenced now include a disproportionate amount of Middle Bossier. And when you think about the productivity of those second degree or sort of like second-tier members of the formation to develop, compare that to the Deep Utica where around the Olympus area, the way we underwrote that is, call it, like 2.5, 2.6 Bcf per thousand and with well costs that are probably around what Haynesville well costs are, but that's before anybody has really spent time trying to drive the cost down.

So for us, it's a free option, and I think takes our 30-ish years of inventory out much further. And so when we think about what could we grow into, there's a ton more resource out there that we have rights to in Appalachia that keep that opportunity wide open for us to continue growing. Just a question of what price and how efficient can we get on the operations side drilling the wells.

And your next question comes from the line of Roger Read with Wells Fargo.

Maybe just come up with a couple of things here. One, sort of been talked about it, I guess, as we've gone through the call here, but the idea with the very high PJM prices that are out there. Obviously, local need, you've got the infrastructure. What are you seeing?

Or is there any way for you to kind of give us an idea of what's happening in the, call it, the behind the meter, the off grid in terms of demand beyond the very high-profile Homer City and Shippingport type projects?

Yes. I'd say the dynamic that we're seeing is that in order to get this infrastructure built, people are going to be having to sign up for PPAs that are just higher than what market pricing is right now. I think that has been something that's caused a little bit of people just pause to make sure that what they're signing up for is needed. But it's -- I think people now realizing the only way to get this infrastructure built is to get these PPAs in place, and it's -- and with inflation that's taking place, it's going to require a little bit higher pricing than what people have been accustomed to.

But it's encouraging to see that these projects are going to be going forward.

Yes. I think there's also the opportunity to add some peaking supply capacity. And when you add that allows you to increase your capacity factor across existing baseload from the levels that you see today and still have that reliability. But that additional peaking supply at current inflated rates due to the scarcity of equipment simply requires a much higher price than it did even before.

And I think that's one of the misconceptions that we've observed is you're seeing much higher electricity prices, but you've also seen the cost of building these gas plants roughly double from what they might have been 3, 4 years ago. So logically, just to keep economics flat, you need your spark spreads probably double, too. So again, I think when you read through the economics of what it actually takes to build one of these plants, you can -- the need for electricity prices to rise and allow the market to evolve to meet the needs today and over the coming years, just simply requires higher prices and less the price of building these projects and the cost of capital falls back lower again.

Okay. And then just an unrelated follow-up. How are you thinking about hedging strategy at this point? I know at different times, there's been a goal for debt and then stepping away from hedging other times tied to what's going on maybe with the midstream business.

You've laid out potential -- not potential, but likely future CapEx increases on the midstream side, so not really price sensitive on the backside, but maybe price-sensitive upfront on the CapEx commitment. So does that affect any way you're thinking about hedging over the next year or two?

Let me put it this way. So when we think about the appropriate debt level for our business, I mean, I made this comment in our opening remarks, at $2.75 gas, like Henry Hub pricing, unhedged, we generate in a given year between $1 billion to $2 billion of unlevered free cash flow. Or said another way, like your EBITDA less maintenance CapEx. So at $5 billion, you're looking at a little over 3 years of just steady state unhedged to repay all your debt, right?

That compares to a lot of our peers that are free cash flow negative at that point in time. So yes, we are trying to get our ratings higher. The agencies still want to see our debt at a low level. But fundamentally, I already feel like we're very under-levered and our balance sheet is in a very safe spot.

We're mostly focused on our maturities right now, specifically looking out to 2027 and resculpting that. So look, hedging is something that I think we are less and less focused on. And I think if we're in a structurally bull market over the next 5 to 10 years, programmatically hedging or really hedging any other way aside from being opportunistic will net result in value destruction over that period of time relative to just being a taker of where prices settle. And at the same time, it gives us more flexibility in how we nominate our volumes, whether it's first to month or in the spot market.

So I think as we move to a position where really no matter what prices are, we're going to be rapidly repaying debt, able to fund projects confidently and wanting to provide investors that exposure to gas prices they want by investing in EQT structurally in addition to the growth we've talked about today. I think our bias continues to be lowly hedged if not hedged at all. And if we are going to hedge, do the types of things that we've been doing recently hedging 4 x 7 cost plus, right? I think we'd be happy hedging a lot of that sort of price.

And if we lose above $7, that's probably a fine outcome for our business.

Yes. And only other dynamic I'd just add here is these investments that we're making in our sustainable growth projects are going to bring durability to our cash flows. And this $250 million of midstream free cash flow from these growth projects, I mean, those are going to bring a pretty decent amount of durability. So we also are thinking about ways that our growth is going to continue to solidify the cash flow story at EQT, which is just worth noting.

It's like adding a hedge.

Yes. I mean, $250 million to Toby's point is another $0.10 reduction in our breakeven cost by the time all this comes online towards the end of the decade, it's a huge savings. And it takes us, I think, in our view, as you model that out below $2.

And your next question comes from the line of Jacob Roberts with TPH.

Hopefully, a quick one. In a pure reallocation scenario, and I know it will be pricing dependent. But do you see a meaningful shift to the percentages you guys lay out on Slide 24?

I think that it's just simply going to be our election. And again, I think that goes back to Betty's question earlier about where pricing is on a relative basis. If we see basis price tighten up in basin from the, call it, $0.90 you see today closer to like $0.50, $0.60, I think we're pretty open-minded about adding more exposure back in basin. It also just depends on when that is, what the remaining supply picture looks like, we have a view that you get towards the end of this decade, the Utica is also pretty thin on inventory, kind of like the Haynesville.

And so again, I think you just see a paradigm shift at that point in time where you have 30 Bs of LNG becomes fully absorbed in the global market. You have all these power plants, data centers starting to really pull real demand. At the same time you see inventory rollover that will also structurally reset the market higher. And it's really a point in time we're kind of laying the groundwork to position for where if we do grow, all of a sudden, you're going to see a paradigm shift in pricing.

And that growth we add is going to be worth a tremendous amount.

Okay. So there's nothing precluding you from moving gas wherever you want it, I guess it's the other way to ask that question. .

Correct.

And your next question comes from the line of John Annis with Texas Capital.

For my first one, the 2 supply agreements announced are for projects located in Southwest Appalachia, how would you characterize the opportunity set for EQT to secure similar agreements in Northeast PA? Or is the Southwest just more attractive with your midstream assets there?

I think you're going to see the opportunities anywhere you have EQT footprint. And that footprint can come from our midstream infrastructure. The footprint can also come from our commercial opportunities. It seems like there's a big gravitation of the tech community in Southwest Appalachia.

And so we're seeing a lot of opportunities there. But I mean, our footprint is pretty massive. So we are seeing opportunities across the horizon.

Yes, there's also nothing that precludes us from building a, for example, 20-mile lateral off someone else's pipeline to tie into a new power plant or data center as long as our traders can secure the capacity on the pipelines and make sure we get volume there 12 months out of the year at a price that makes sense. So again, I think between our trading arm and our midstream side of the business in addition to our own equity volumes, we have a ton of flexibility.

I appreciate it. And then just a quick housekeeping item on the tax front. With the tax rule changes and recently passed legislation, how does that change your outlook for cash taxes over the next couple of years?

Yes, that's a great question. I actually tees up some important color that we did not cover in prepared remarks. So just the tax bill alone saves us in the next couple of years about $500 million in taxes by deferring that out. Present value, that's about $450 million.

So logically, that's very front-end weighted in that 5-year window. But that is also before the impact of a lot of the spending, like this $1 billion opportunity. For FERC-regulated projects, which is approximately like the MVP related projects are about half of that $1 billion for perspective, FERC assets are normally depreciated under like a 15-year maker type schedule. But the rest of that is gathering CapEx.

And under that new bill with the -- which really bring back bonus depreciation up to 100% effectively all that CapEx, we can expense day 1 and defer taxes on. And so as we ramp into this, whether it's the midstream side or then it's the upstream side with IDCs, it actually serves to push taxes off in time for us because taxes otherwise were going to become a pretty large expense over the next couple of years. So it's really timely for that bill to happen and that's also the look into growth because it will minimize that cost line item for us that we otherwise were anticipating.

Thank you, everyone. That concludes our question-and-answer session, and also concludes today's call. You may now disconnect.