EQT - Q2 2024

Transcript

Operator (participant)

Standing by, and welcome to the EQT Second Quarter 2024 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number 1 on your telephone keypad. If you would like to withdraw your question, again, press the star 1. Thank you. I'd now like to turn the call over to Cameron Horwitz, Managing Director, Investor Relations and Strategy. You may begin.

Cameron Horwitz (Managing Director, Investor Relations and Strategy)

Good morning, and thank you for joining our second quarter 2024 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer, and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the investor relations portion of our website, and we will reference certain slides during today's discussion. A replay of today's call will be available on our website beginning this evening. I'd like to remind you that today's call may contain forward-looking statements. Actual results in future events could materially differ from these forward-looking statements because of the 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 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.

Toby Rice (President and CEO)

Thanks, Cam, and good morning, everyone. This week marked a significant milestone in the history of our company as we closed the acquisition of Equitrans Midstream, transforming EQT into America's only large-scale, vertically integrated natural gas business.

To put the significance of our combined companies into perspective, EQT's assets now encompass nearly 2 million acres of leasehold, producing more than 6 BCFE per day, with almost 4,000 low-cost remaining drilling locations, more than 2,000 miles of gathering lines with greater than 8 BCF a day of throughput, nearly 500 miles of water lines, 43 BCF of natural gas storage, 800,000 horsepower of compression, almost 950 miles of critical transmission infrastructure, plus the newly commissioned 300-mile Mountain Valley Pipeline, all of which are located at the gateway of Appalachia and ideally positioned to serve growing U.S. and international natural gas demand for decades to come. This combination creates a differentiated business model among the U.S. energy landscape, as EQT is now at the absolute low end of the North American natural gas cost curve.

A low-cost structure is the only competitive advantage one can have in a commodity business, and with the closing of Equitrans acquisition, EQT's unlevered free cash flow breakeven price is projected to be $2 per million BTU, with further downside potential upon synergy capture. This cost profile structurally de-risks our business in the low parts of the commodity cycle, which in turn eliminates the longer-term need to defensively hedge, thus unlocking unmatched upside to higher price environments. We believe this sustainable cost structure advantage, combined with our scale, peer-leading inventory depth, low emissions profile, and world-class operating team, offers the best risk-adjusted exposure to natural gas prices of any publicly investable asset in the world. I also want to welcome Equitrans employees and shareholders to the EQT crew. We're excited to get to work unlocking the full potential of our combined company's asset base.

With the acquisition closing a full quarter ahead of our original timeline, we estimate savings of nearly $150 million relative to our initial underwriting assumptions, even before synergies. We're also able to more rapidly mobilize our integration team, which has a proven track record of turning around EQT and efficiently integrating three large-scale acquisitions over the past several years, including seamlessly onboarding an entire midstream division with the XCL acquisition last fall. This accelerated closing amplifies our momentum and pulls forward our timeline to synergy capture. We have continued to study synergy potential since announcement and have identified further upside potential driven by completion efficiency gains through water asset integration, which is on top of early compression uplift results that are exceeding our high-end synergy assumption. We plan to share additional details as our teams work through the integration process.

Shifting gears, June 14, 2024, marked a historic moment of progress for our country as natural gas began flowing through Mountain Valley Pipeline. The gas moving through this critical infrastructure will provide low-cost, low-emission energy to millions of Americans while strengthening our national security. The upstream development underpinning flows on MVP will generate hundreds of millions of dollars royalties every year to local communities in the Appalachian region while supporting well-paying private sector jobs. Downstream, the delivery of low-cost Appalachian gas will strengthen the competitiveness of American manufacturers, whose energy input costs will be a fraction of the price paid by global competitors, which should further support a manufacturing renaissance in America. MVP will also provide utilities access to cheap, reliable fuel to power America's data center and artificial intelligence build-out, which is one of the strongest secular growth stories in the world....

Since announcing the Equitrans acquisition earlier this year, we have fielded significant inbound interest from end users of gas in the region, underscoring the depth of demand and the value of EQT's MVP capacity. MVP's volumes alone are estimated to reduce carbon emissions by up to 60 million tons per year via displacement of legacy coal generation, which, to put in context, is five times the emission reductions associated with Tesla's electric vehicles. In fact, thanks to MVP's completion, EVs in the Southeast region can now run on low-emission EQT gas delivered through MVP rather than the coal generation powering many of them today. Given the regional exposure, upstream inventory depth, and counterparty quality, we believe MVP is among the most valuable natural gas pipelines in the world, and EQT is honored to be the operator and steward of this critical infrastructure.

Turning to second quarter results, we experienced yet another quarter of operational outperformance, marked again by incremental efficiency gains. A tangible example of this on our recent Mallory C pad in Lycoming County, Pennsylvania, where our tophole rigs recently drilled the fastest well-to-kickoff point in EQT history, with the overall average drilling time to kickoff point across the pad being 25% faster than the offset wells we drilled in 2022. This efficiency improvement is resulting in tangible well cost savings, as the average tophole drilling cost on the Mallory C pad came in 14% below our pre-drill estimate. Within completions, recent improvements in logistics planning and water throughput have driven materially faster completion times on our latest wells.

Our average footage completed per day is up 6% year-over-year thus far in 2024, but our most recent pads implementing new logistics techniques have outpaced our average 2023 completion speed by more than 35%, indicating the potential for material future capital efficiency improvements. Notably, this average excludes a pad we are currently fracking, which to date has seen completed footage per day that is a whopping 120% faster than our 2023 program average and set a new EQT record with more than 3,200 feet of lateral completed in a single day. As I mentioned previously, we believe the integration of EQT and Equitrans water systems can help sustain these completion efficiency improvements, as streamlining water logistics is one of the most imperative elements to systematically increasing completed footage per day.

Despite efficiency gains accelerating activity into Q2, our second quarter CapEx still came in below the midpoint of our guidance range, highlighting how operational efficiency gains are driving tangible per well cost savings. Alongside well cost savings, we are also seeing strong well performance across our asset base, which drove upside to our second quarter volumes despite price-related curtailments. As shown on slide 6 of our investor deck, this represents a continuation of the track record of productivity gains that have been a hallmark of EQT since new management took over in 2019. Over this period, third-party data shows we have seen a nearly 40% improvement in average EUR per lateral foot, while most of our peers have seen productivity degradation as core inventory is exhausted. As a result, EQT is now generating the highest average EUR per foot of any major operator across the Appalachian Basin.

I also want to highlight this productivity improvement has come despite a material increase in field pressures across Equitrans's gathering system over the same period, which essentially makes it more difficult to flow our wells. We see significant upside from investing in compression to lower system pressures, which in turn should further improve well productivity and further reduce our upstream maintenance capital requirements in future years. On slide 7 of our investor deck, we highlight data from 3 recent in-field examples showing how impactful adding compression and lowering line pressure can be on existing wells. After lowering system pressures by approximately 300 PSI, we saw per well production rates immediately jump by roughly 50% on average across the 3 projects.

Over the first 12 months post-pressure reduction, we forecast cumulative production gains ranging from 18%-27%, which in effect lowers our base PDP decline rate and we believe will translate to higher EURs per well. Notably, the average production uplift from these projects is approximately 2 times more than what we assumed in our $175 million per annum of upside synergies with the E-Train deal, indicating potential for even more positive benefit than we originally expected. These concrete examples underscore the impact of adding compression to lower system pressures on thousands of producing wells that comprise EQT's base production. This uplift on base volumes should in turn allow us to drill and complete fewer wells to maintain production, driving sustainable improvements in long-term capital efficiency.

We are currently in the process of identifying optimal compression locations across the E-Train system and expect the tailwinds from lower maintenance capital to begin accruing in 2026. Turning to our recent ESG report, I am proud to highlight that we took another material step forward towards our ambitious environmental goals as our 2023 Scope 1 and 2 legacy production segment greenhouse gas emissions declined by 35% year-over-year to approximately 281,000 tons. We have now reduced our historical Scope 1 and 2 production emissions by nearly 70% over the past five years, and are squarely on track to achieve our ambitious and peer-leading Net Zero goal by 2025. From an emissions intensity perspective, we achieved our 2025 greenhouse gas emissions intensity goal of 160 tons per BCFE, a full year ahead of schedule.

Looking at methane, after significantly outperforming our pneumatic device replacement timeline, the methane intensity from our production operations is now 0.0074%, which is more than 60% below our 2025 goal and 97% below the ONE Future 2025 target, making EQT among the lowest methane intensity producers of natural gas anywhere in the world. With that, I'll now turn the call over to Jeremy.

Jeremy Knop (CFO)

Thanks, Toby. Before I summarize Q2 results, I want to take a moment to thank our shareholders for the tremendous show of support in last week's vote on the Equitrans acquisition. Of EQT shares cast, more than 99% voted in favor of the deal, despite this being an unconventional acquisition relative to what investors have become accustomed to in upstream M&A over the past decade. We see this vote underscoring the strong support from investors. They share our philosophical view that being at the absolute low end of the cost curve will create differentiated and sustainable long-term value amid a volatile commodity price landscape. Since taking over EQT in 2019, we as a management team have never been more convicted that this company is on the right strategic path, and we look forward to continuing our track record of execution on behalf of our shareholders.

Shifting to second quarter results, as planned, we curtailed 1 Bcf per day of gross production throughout most of the quarter, which, along with non-operated curtailments, impacted net production by approximately 60 Bcfe during Q2. Despite curtailments, strong operational efficiency and well performance drove production of 508 Bcfe, above the high end of our guidance range. Per unit operating costs came in at $1.40 per Mcfe, below the low end of guidance due to LOE and G&A expenses coming in below expectations. CapEx also came in below the midpoint of guidance, despite an accelerated development pace, as efficiency gains drove lower than expected well costs. Turning to the balance sheet, we're off to a fast start on our deleveraging plan as we repaid $600 million of 2025 senior notes last month with cash on hand and proceeds from the Equinor transaction.

We exited the quarter with net debt of roughly $4.9 billion, down from $5.7 billion at the end of 2023. Concurrent with the closing of Equitrans, we also upsized our revolver from $2.5-$3.5 billion, which speaks to the depth of support for our bank group. This revolver is on par with the largest companies in the energy industry and gives us ample liquidity to handle any foreseeable natural gas price scenario moving forward. With the close of Equitrans this week, pro forma gross debt is expected to be approximately $13.5 billion, inclusive of the redemption of Equitrans' 14% preferred equity at closing. With the deal closing sooner than we originally anticipated, we expect our deleveraging timetable to be pulled forward by approximately 6 months.

On the midstream side, we plan to pursue a minority equity sale of Equitrans' regulated assets, which are projected to generate approximately $700 million of adjusted EBITDA. This strategy will allow EQT to retain full operational control and upside value associated with synergy capture and future pipeline expansions. We're also marketing the remaining 60% of our non-operated assets in Northeast Pennsylvania and are in active discussions with both domestic and international buyers. We continue to target reducing our long-term debt to $5 billion-$7 billion and are highly confident in achieving our goal. Alongside planned asset sales, we have further de-risked our deleveraging plan by increasing our near-term hedge position.

We're approximately 60% hedged in the second half of 2024, with an average floor price of roughly $3.30 per MMBtu, and approximately 60% hedged in the first half of 2025 at an average floor price of roughly $3.20 per MMBtu. We are actively building our hedge position in the second half of 2025 in order to bulletproof our deleveraging plan in any reasonable natural gas price scenario. Turning briefly to the Appalachian macro landscape, while the pace of Eastern storage builds has moderated, absolute storage levels remain high on the back of warm winter weather last year, thus pressuring Appalachia pricing this year. In response to market fundamentals, we continue to tactically curtail production, including over the past weeks, and expect to continue this tactical curtailment program during the upcoming fall shoulder season.

To this end, our second half 2024 production guidance assumes 90 BCFE of anticipated curtailments, which should have a meaningful impact on both Eastern and total U.S. storage levels as the market wraps up injection season. I want to highlight that normalized for the roughly 180 BCFE of total curtailments that we expect this year. Our production would have been above the high end of our original 2024 guidance range, which speaks to the productivity and operational efficiency gains that Toby spoke to a few minutes ago. While Appalachian storage is elevated today, the startup of MVP last month should provide support to Appalachian differentials moving forward.

To put MVP's impact in context, assuming MVP flows at just half of its capacity on average for a year, implies 300-400 BCF of gas that otherwise would end up in Eastern storage, that now will be directed to the Southeast demand centers. Given total maximum Eastern storage is roughly 975 BCF, MVP flows represent a material and structural shift in local supply and demand fundamentals, which in turn should help tighten local bases over the coming years.

In fact, between MVP, coal retirements, and organic load growth, we see implied Appalachian demand approaching 41 BCF per day by 2030, compared with 35-36 BCF per day of current basin supply, which should translate to better local pricing and present a sustainable growth opportunity for EQT at some point in the coming years, given we have the deepest, highest quality inventory of any operator in the basin. Turning to guidance, we have issued pro forma Q3 and Q4 metrics on slide 29 of our investor presentation. Our cash operating expenses are expected to range from approximately $1.10-$1.25 per MCFE in the second half of the year, which is a midpoint, is roughly $0.25 per MCFE below our standalone operating expenses in Q2.

This reflects the benefit of eliminating expenses associated with the Equitrans acquisition, with the most notable movement being our gathering rates, which are forecasted to decline from $0.59 per MCFE in Q2 to just $0.05-$0.09 per MCFE in the second half of the year. Inclusive of the benefits from third-party revenue and the full run rate distributions from our MVP ownership, our net operating expense should equate to roughly $0.75-$0.85 per MCFE by the fourth quarter, which is approximately $0.60 per MCFE lower than standalone EQT, and drives home the relative advantage of our vertically integrated cost structure.

It's also worth highlighting that we do not embed any of the $250 million of base synergies into our Q3 or Q4 numbers, as we have conservatively modeled base synergy capture beginning in mid-2025. As I mentioned previously, our second half 2024 production outlook embeds approximately 90 BCFE of strategic curtailments this fall, which we will opportunistically execute should gas prices remain depressed. I'd note that curtailments are driving approximately $0.05 per MCFE of upward pressure on our second half 2024 cost structure. So our 2025 expenses should be even lower than the ranges I cited previously. While we still need to go through our full budgeting process for 2025, we preliminarily expect an all-in pro forma capital budget in the range of $2.3 billion-$2.6 billion.

Beyond 2025, we forecast long-term pro forma capital spending ranging from $2.1-$2.4 billion per annum, prior to capturing the $175 million of upside annual synergies we laid out with the Equitrans acquisition announcement. Said another way, our long-term capital spending, inclusive of Equitrans, should essentially be in line with standalone EQT capital spend in 2024. And this is before capturing upside synergies, which speaks to the structural capital efficiency improvements accruing in our upstream business. At recent strip pricing, we forecast pro forma cumulative free cash flow of approximately $16.5 billion from 2025 to 2029, at an average annual gas price of roughly $3.60 per MMBtu over this period.

Even assuming a $2.75 natural gas price over this period, EQT will still generate north of $9 billion of five-year cumulative free cash flow, while the bulk of our peers would be cash flow neutral or negative, underscoring the power of our low-cost structure and highlighting how EQT is uniquely positioned to create differentiated shareholder value in all parts of the commodity cycle. And with that, I'll turn the call back over to Toby for some concluding remarks.

Toby Rice (President and CEO)

Thanks, Jeremy. In closing, July tenth marks the 5-year anniversary of the EQT takeover. It has been a lifetime of work, but passed by in the blink of an eye. We have been reflecting recently on what this management team has accomplished together, taking a struggling company with great assets and transforming it into a best-in-class producer, recognized as an industry leader. We have increased production over 50% from 4 BCFE per day to 6.3 BCFE per day, and have transformed our free cash flow cost structure from $3 per million BTU to a peer-leading $2 per million BTU through operational improvements and thoughtful and accretive M&A deals.

Normalized for natural gas prices, we have grown the free cash flow generation of EQT by 5 times and increased free cash flow per share by nearly 2 times, and we have repaired our balance sheet and reattained investment-grade credit ratings. Today, we are executing at a high level operationally.

...with identified opportunities and completions in midstream, set to drive yet another step change in operational improvements. We are executing financially with a fast start to our deleveraging plan and robust support from our bank group and shareholders. We are executing strategically at an industry-leading pace as we continue to transform EQT into the energy company of the future. I'd now like to open the call up for questions.

Operator (participant)

Thank you. We will now begin the question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star one again. We ask that you limit yourself to one question and one follow-up. Your first question comes from the line of Arun Jayaram from J.P. Morgan. Your line is open.

Arun Jayaram (Research Analyst)

Good morning, gentlemen. My questions are regarding kind of the asset sales or divestiture program. Jeremy, maybe I was wondering if you could start with the amount of or, or the process to sell some of your non-op in the Northeast. Could you gauge the level of interest that you're seeing for the remaining 60%? And do you still believe the market is supportive of a similar valuation marker as you got in the Equinor transaction?

Jeremy Knop (CFO)

Hey, Arun, good morning. Yeah, we're seeing really good interest. I think I would characterize it as really a renewed set of interest. A lot of new names, actually, in the process from the international space that we didn't see the first time around. So that's been really encouraging, a lot of great engagement. So I think our feeling towards that process remains really positive. And I hope to get that wrapped up by year-end.

Arun Jayaram (Research Analyst)

Great. And then my follow-up is, you've highlighted kind of a structure you plan to pursue in terms of, you know, carving out your regulated assets and selling a minority interest in those assets. Do you plan to reduce gross debt at the EQT parent level as part of that process? And just a question that's come up is, what type of partner approvals? Is there a ROFR on MVP? But could you just go through some of those types of things that you need to do to process that, the next phase of your deleveraging program?

Jeremy Knop (CFO)

Yeah. Taking the route that we outlined in the prepared remarks, actually bypasses most of the sort of considerations you might typically get hung up in with, like, drag rights, tag rights in a deal like that. So it really simplifies it, and I think it really provides a better, higher quality, more diverse set of assets to back an investment, which drives the cost of capital down. So look, we, we've spent a lot of time, we've had a lot of discussions with a lot of parties on this already, even pre-closing. And so with closing happening a couple of days ago, we're really in the thick of getting that data organized, so we can kick that process off. And I hope to be able to get that wrapped up as soon as year-end.

It might bleed into early Q1, but I think there's a real chance that all gets wrapped up this year as well.

Arun Jayaram (Research Analyst)

Great. Thanks a lot.

Operator (participant)

Your next question comes from the line of Doug Leggate from Wolfe Research. Your line is open.

Doug Leggate (Vice Chairman of Energy)

Hey, guys. Thanks for having me on and congratulations. I didn't quite realize it had been five years, Toby. So it has indeed flown by. I've got two quick questions, I hope. The first one is on the capital budget for the next two or three years, alongside the compression results that you've had. What we're trying to figure out is, how much of the spending is related to that debottlenecking, if you like, and when does it roll over, so that you basically get back to a steady state level of spending associated with your growing program?

Toby Rice (President and CEO)

Yeah, Doug, thanks for the question. On the compression, high level, we just refer to this as pressure system optimization across our systems. We think this is gonna be about a few $100 million. Now, that—the timing of that, there's some lead time there, so that's probably gonna start maybe 12 months from now, and that could span over a couple of years, just determining on the type of pace that we see. But that being said, we have in our 2025 budget right now, we have included some cushion to be able to get those projects started as quickly as possible.

The results that we showed, the pilot that we showed today about the compression uplift, is really encouraging and will lead to some really exciting returns that we'd like to accelerate as quickly as possible.

Jeremy Knop (CFO)

Yeah, Doug, welcome back, by the way. If you look at what we've put in our new slide deck that we put out last night, we put a couple of case studies in from some recent pad level compression projects that we've installed. These are not a perfect proxy to centralized compression, which is a lot—you know, it's gonna have a much broader impact, superior to what these examples show. But even those examples, at $3 gas, I mean, these are, you know, you're generating 2.5-3 times your money on that compression on just the pad level. So again, on a centralized basis, it's gonna be higher than that. And then beyond just uplifting that base PDP for the existing production, you're gonna see an impact on all of our future development as well.

So the rate of return on, on this compression is superior to probably any well we could pick to drill. And as Toby said, the spend amount is really not that much. When you space it out across a couple of years on an annual basis, it's, it's mitigated even more. But if you look at slide 8 of our investor presentation, the delta between that 2025 guidance number and then what we call long-term right below that, you, you can kind of think about that as the annual difference in, in sort of, uplift in spending we might see in a given year while we're, while we're doing that, before reverting to a much lower range long term.

And as a reminder, that lower range that we show from 2.1-2.4 long term, that excludes the $175 million of synergies that we call upside synergies. So I would say that upside synergy assumption assumed a level of uplift from compression less than what we're already seeing on even a pad level basis. So I think that number is probably even biased higher as we see the benefits of these projects come to fruition.

Doug Leggate (Vice Chairman of Energy)

So, guys, I'm sorry for the follow-up, but just to simplify it. Would it be a stretch to say that when you get to that point with the synergies, your run rate capital could be under $2 billion?

Toby Rice (President and CEO)

That's correct, and that's a simple way to put it, Doug.

Doug Leggate (Vice Chairman of Energy)

Okay. That's, that's what I was trying to get to. Thank you, guys. My, my follow-up is a quick one. Hopefully, Jeremy, this is right down your, your fairway. Why is any ownership of the regulated assets make sense?

Jeremy Knop (CFO)

Yeah, that's a great question, actually. It's something we've kind of debated internally as we thought about the right structure here. So, for the regulated assets, specifically, if you start with the transmission storage segment of Equitrans, that is really an extension of the gathering system. There are a lot of big header pipes that cross state lines, and so they are regulated. Maintaining the right pressures on those systems, being able to control things like expansions, is really integral to managing the gathering systems appropriately. And then when you think about those pipes then flowing into a longer distance regulated pipeline like MVP, you know, maintaining that interconnection, that pressure at an appropriate level, it all kind of works together as a single system.

Then as we think about MVP, as we talked about last quarter, the expansion on that project we think is a highly economic expansion. That's something that we want to get done to evacuate more gas out of Appalachia and get it to a premium end market in the Southeast. We want to make sure that project happens. You know, whether 5 or 10 years from now, it makes sense to still own something like MVP once all that expansion is completed. I think that's something we'll always evaluate, but I think at this juncture, we do want to maintain the operatorship and ownership of it.

Toby Rice (President and CEO)

Yeah, Doug, I'd say at a very high level, what we're doing here at EQT is creating a culture that is gonna be able to pick up every penny, nickel, and dime within our operating footprint. One of the ways that we can drive the opport- the value creation is to expand the size of the operational footprint. And so there is an element of having, you know, those transmissions as a bigger commercial system is going to make it a little bit easier for us to identify and capture some of those opportunities. So that's just another factor that we have in the back of our heads as well.

Doug Leggate (Vice Chairman of Energy)

Got it, guys. That's very clear. Thanks for taking my questions and thanks for your comments, Jeremy.

Operator (participant)

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

Neil Mehta (Head of Americas Natural Resources Equity Research)

Yeah, congratulations on, on closing the transaction team. You know, two questions on the macro here. First is just, talk through your hedging strategy, both near and long term, and, and how does the Equitrans acquisition play into your hedging decisions going forward as you want to take advantage of the volatile market that you talk about?

Jeremy Knop (CFO)

Yeah, good morning, Neil. I'll break it into kind of two pieces. Near term, it's really all focused on balance sheet, de-risking, de-leveraging. I call that through 2025. Beyond 2025, I think our view is the deal we just did not only unlocks the value we've been talking about it, but it really provides a structural hedge for our business. So the need to hedge beyond that, we won't have financial leverage to really protect. We won't have operating leverage to protect, and so we don't really have to hedge at all. I think if we do, it'll be more opportunistic, but it'll be pretty small in nature, you know, probably at max, around a 20% level, if we just get really bearish on the outlook for some reason.

But otherwise, I think the goal strategically of what we're trying to do is set ourselves up where we don't have to hedge because we see so much more upside than downside. But I think as you've even seen this year, you know, you've seen gas prices go as low as about $1.60, rebound over $3, and now trade back towards $2, right? So you're already seeing this theme of volatility play out, and the best way to capture value from that is to not have to hedge. And so that's really the long-term plan and how we're trying to position.

Neil Mehta (Head of Americas Natural Resources Equity Research)

That, that's helpful. And then can you just talk through. You've done a great job walking us through your long-term views around data centers and power demand growth, which we agree, it's a very compelling story. 2025 is a little trickier, just because you've got some push out of some major projects like Golden Pass, and we're trying to digest the spare capacity that might be in the system, too. So how do you think about the supply/demand outlook for gas as we think about 2025, and what are you guys watching as markers?

Jeremy Knop (CFO)

Yeah, so, I think the key thing we're watching, probably going into year-end, is production. I think this number hovering around 102, it's a healthy number, but if you see a surge into winter again, if other producers turn on a lot of volume, I think we are watching for that because that could be a near-term headwind to price. You know, I think at most, that would impact the first half of 2025. I know the team at Goldman has the Aspen pushed out into 2026 for Golden Pass and service date. I think with some of the updates that we've seen even this week with that bankruptcy process of Zachry Holdings, it seems like that might get pulled back forward.

But a couple of these key factors on the LNG side are really gonna drive that. So I see it really as a story of production and a story of LNG. I don't, beyond that, see any sort of step change benefits necessarily in 2025 that are gonna move the needle nearly as much as those two factors.

Neil Mehta (Head of Americas Natural Resources Equity Research)

Jeremy.

Operator (participant)

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

Scott Hanold (Research Analyst)

Good morning. Hey, a question on now that MVP's online, I'm just kind of curious, you know, is there any change in the dynamics you're seeing in the Appalachian or the Southeast market now that that's flowing? And, you know, related to that, have you seen any moves by, you know, some of the Appalachian producers to increase activity given the, you know, obviously, extraction of some of the volumes in the basin?

Jeremy Knop (CFO)

Yeah. So this is actually something really exciting that we've been really pleasantly surprised by. So I guess on the production side, we have not seen any reaction. Production continues to be flat, consistent with our expectations. What has surprised us, though, is that in that end market, we model. The way we sort of mark that Station 165 pricing where we're selling gas, we've sort of modeled it around a 20-cent premium to M2 pricing. We have seen pricing recently on average $0.50-$0.70 above, so significantly higher than what we have assumed. And there have been periods of time where it's well, well north of $1 above M2. And so I think we've been really encouraged by how much gas that market has been taking.

Part of its impact—it has been impacted by some maintenance on Transco. But I think for being a midsummer period, seeing that demand and that premium price already show up, I think is an awesome, really early sign marker. And so I think that the benefit we might see in winter periods could be even better as well, and certainly better than maybe what we have forecasted. But it's still early. There's a new price market that Platts put out for that Station 165 market, so we're watching, like everybody else, to see how that develops. But I think all signs are pointing to a really positive direction on that.

Toby Rice (President and CEO)

Yeah. Scott, one other thing I'd just have you take a look at, you know, on slide 6, where we talk about, you know, the improving EURs for EQT. If you look at sort of where the peers are at, and you're seeing the EURs come down over time, that's just a sign of some of the inventory, the core inventory, depletion. You know, the read-through there is, you know, there could be some pressure against operators and their willingness to go out there and accelerate or, or, or grow purely just to preserve inventory. So that's another, you know, thing that's happening in the background. And, you know, there's only a couple operators that really have high-quality inventory like EQT, and we're—we've, we've been pretty vocal in, in staying in this maintenance mode, but continuing to supply the market.

I think that's an important backdrop just to keep in the back of your head.

Scott Hanold (Research Analyst)

I appreciate that. Sounds good. As my follow-up, Toby, you know, look, you know, you've been never shy to discuss politics from time to time, and as it relates to being a gas producer, you know, what do you think the biggest issues are in for the upcoming election? Like, what are the things that are you really focused on?

Toby Rice (President and CEO)

Well, I'd say, you know, we align our politics with the politics of our customers, which is every American that uses our products. So we don't try and be too biased one way or the other, just really centered on the facts. Listen, I think we're in a period of time where people are only gonna get smarter about energy. There are some clips talking about some politicians talking about banning fracking. And, you know, this is a time for us as an industry to and as Americans, to hold leaders accountable for statements that I think are really damaging and cause completely unintended impacts. I mean, as it relates to hydraulic fracturing and the ban of that, we cannot ignore the science on this.

Over 10 years, it's been studied, and under the Obama administration, the EPA put out a report saying hydraulic fracturing is safe. And understanding the implications of these type of decisions, you know, 98% of the wells in this country require hydraulic fracturing. That goes away, you snap your fingers, and the production in the United States, which we fought for decades to create America as an energy powerhouse, would sort of evaporate, and we'd see production in this country drop 35%. That's gonna lead to a lot of terrible things. And, you know, the ironic thing is, as an oil and gas operator, you know, this is a price times volume game.

Our production at EQT would go down, you know, call it 25%, our corporate decline, but price would skyrocket. And, you know, that, that's the tough part here, is that, it would actually be constructive for prices, but it'd be bad for Americans, and, and that's why we need to make sure our politicians are putting the right policies in place. And with all the crazy things that are happening in this world, we're really encouraged to see that energy is still at the top of the list as a key issue for American voters, and it's something that we need to take very seriously.

Scott Hanold (Research Analyst)

Appreciate the color. Thanks.

Operator (participant)

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

Joshua Silverstein (Research Analyst)

Hey, thanks. Good morning, guys. Just on the outlook for next year, I'm trying to think about the trajectory of the natural gas volumes. Do we think about, you know, kind of the second half run rate going forward with the curtailments coming back? Do you think you'd probably keep the volumes curtailed? So maybe a little bit more clarity there would be helpful. Thanks.

Jeremy Knop (CFO)

Yeah, Josh. I think in our view, it's just maintenance mode. I mean, I think, you know, in our prepared remarks, we commented that if we had not curtailed this year, we would have been above the high end of the range. Originally, that was 2,300 BCFE on the high end. We're running our business in maintenance mode, so I would expect looking into next year, that's the volume level you look at. I think the only difference there is the divestment of our non-op interest and some of the transaction impacts from that. But aside from that, we're running in a steady maintenance mode cadence.

Joshua Silverstein (Research Analyst)

... Got it. So is that kind of around maybe like a $5.50 or so kind of quarterly cadence or around there?

Jeremy Knop (CFO)

Yeah, call it $550-$600, depending on the quarter.

Joshua Silverstein (Research Analyst)

Right. Got it. Okay, so still growth into next year relative to the back half. Got it. Okay. And then just on the pro forma kind of cash flow profile, when you first announced the transaction with E-Train, you mentioned about 30% of the pro forma cash flow would be midstream. I'm wondering if that still holds, given the minority sales that you guys are looking at, would the number actually be lower? And if it is lower, would you want to reduce debt even further to be where you guys want to be pro forma? Thanks.

Jeremy Knop (CFO)

Yeah, it really comes down to kind of what value and multiple we would sell that at. But yeah, I mean, all else equal, if you sell down some of that, it could-- it should drop a little bit. But that's factored into how we look at pro forma leverage already. So I don't think it really impacts how we think about our plans. And the only other thing that's gonna impact that next year, too, is obviously gas prices. So if prices decline or go up a lot, that percent of midstream is gonna oscillate with that as well.

Joshua Silverstein (Research Analyst)

Yeah. Thanks, guys.

Operator (participant)

Your next question comes from the line of Roger Read from Wells Fargo. Your line is open.

Roger Read (Equity Research Analyst)

Yeah, thanks. Good morning, everybody. I'd like to take a look, slide 11, you have the organic deleveraging and the free cash flow expectations, 25 through 29. Just curious, clearly, you're not gonna be, you know, aggressive on the hedging side in the future. So what's sort of the underlying assumption on gas prices, gas volumes, that gets us the numbers you lay out there?

Jeremy Knop (CFO)

Yeah. So the numbers we look at on page 11 are really based on our internal assumptions around the asset sales and then where strip pricing is today. But that. Look, that's the reason why we're also hedging. If you look at it, just organic free cash flow really between now and the end of 2025 at $2.75 gas prices, you're still generating over $1 billion of free cash flow. So I really in any case that we've laid out, if we take a more conservative lean to that, if things just go wrong in the macro for whatever reason, I think we still feel really good about that assumption.

That initial target we have, the specific target of $7.5 billion by the end of 2025, I'd call that our initial target level. I think that's within a margin of safety that the rating agencies outlined for us. But longer term, we would like to take that lower. That's why we talked about that seven or that $5-$7 billion level. That could oscillate in time, depending on where we are in the cycle, depending on the opportunities, where else to invest cash. And look, we also want to very intentionally position ourselves so we have ample liquidity, so that if there is volatility in the macro landscape and in our stock, that we're positioned to step in and buy a lot of stock back countercyclically.

If you don't pay down debt below a mid-cycle level, if you don't have a lot of liquidity, you can't do that. So, you know, another example of that, that revolver, we just expanded by $1 billion to a $3.5 billion size. That's also trying to tee up and position ourselves for volatility and to take advantage of those opportunities. So this is all kind of plays hand in hand together with how we're trying to position ourselves to maximize value as we reallocate capital in the coming years.

Roger Read (Equity Research Analyst)

I appreciate. That's very helpful. Thanks. I'll turn it back.

Operator (participant)

Your next question comes from the line of David Deckelbaum from TD Cowen. Your line is open.

David Deckelbaum (Managing Director)

Thanks, Toby and Jeremy, for taking my questions. I wanted to just go back to the capital progression, you know, just in the context of the benefits that you've seen on the upstream side. I think you highlighted, obviously, the impressive achievements is getting your cycle times down on completions, like 35%. How much of that is reflected in the reduction in spend in 2025 versus 2024? And I guess just in conjunction with that, how much do you expect upstream CapEx to moderate next year?

Toby Rice (President and CEO)

Yeah, we have a small amount of that, those completion efficiencies baked into our 25 plan right now. You know, given the newness of this step change in completion efficiencies, we want to see a little bit more time, but we'll continue to add that back in there. And the second part of the question?

David Deckelbaum (Managing Director)

I was just thinking about just if you think year-over-year, what you're spending on upstream in 2025, in that $2.3-$2.6 versus this year?

Toby Rice (President and CEO)

Yeah, I would say, we think the upstream spending profile is gonna be pretty similar to what we had pre E-Train. I'd say that the impacts of the reduced CapEx is gonna really start once those compression projects start hitting the front lines, which I'd say ballpark 12-18 months before that slopes down. So, everything that you're seeing in on the upstream spending now is really just driven by base operating efficiencies and balancing the service pricing we see.

Jeremy Knop (CFO)

David, it from, like, a modeling perspective, I think about it this way at a high level: we've baked in, in the guidance we've given on those capital cost numbers, we've baked in all the capital costs, but we haven't baked in the benefits. We haven't baked in the, really, the completion benefits, nearly to the level that we're actually seeing right now. We haven't baked in the $175 million of upside synergies, even though the more work we do, I think our bias is that that number probably grows. So I think there's a lot still on the table, beyond what we have given out, that we're hopeful to achieve, but it's still early innings, and so we want to see more definitive results there before we actually bake that into our definitive guidance.

David Deckelbaum (Managing Director)

... Yeah, thanks, Jeremy. Just continuing on that, I guess that long-term guidance of 2.1-2.4, you know, at the midpoint, is it fair to say that that's just reflecting the benefits from the installed compression, bringing down that upstream budget relative to sort of the 2.3-2.6 and 25?

Toby Rice (President and CEO)

No, we'd say the 2021-2024 really reflects that the spend on the compression is behind us. As we mentioned earlier in the call, that $175 million of annual cost reductions as a result of that spending would reduce that 2021-2024 lower. So I think we're gonna just continue to quantify this, and then you can see that come down in the future.

David Deckelbaum (Managing Director)

Appreciate it, guys.

Operator (participant)

Your next question comes from the line of Kevin McCurdy from Pickering Energy Partners. Your line is open.

Kevin MacCurdy (Director of Research)

Hey, good morning. We appreciate all the details on the 2025 included in slide 8 and the further commentary you've offered in the Q&A. I have just a few more clarifying questions on that slide. I, I guess my first question is, does the Adjusted EBITDA number include the MVP distributions for next year? And is just annualizing your 4Q guidance kind of a good run rate for that?

Jeremy Knop (CFO)

That number, that EBITDA number actually does not include the MVP distributions, because that's going to be more of an equity method investment. So we'll provide clarity on that as we go forward. And the second part of your question was what again?

Kevin MacCurdy (Director of Research)

And if it's just a good estimate to annualize the fourth quarter guidance for the MVP distribution for 2025?

Jeremy Knop (CFO)

Yeah, I think it is for MVP specifically. I think on a whole company basis, the main impact was what we noted in our remarks earlier, that curtailments are skewing the per unit cost metrics higher. So I think as you look into 2025, if you were to look at per unit metrics, those should skew lower, assuming no curtailments. But otherwise, I think it should be a pretty decent proxy, which is why we broke it out separately.

Kevin MacCurdy (Director of Research)

Great. And then you mentioned that this outlook was built using a maintenance production number. What is the risk of shut-ins coming back next year, and how have you thought about that in terms of your free cash flow, or does the lower cost structure kind of reduce that shut-in risk?

Jeremy Knop (CFO)

Yeah, we don't proactively, like a year-ahead basis, bake in things like shut-ins. That's more of in response to the market. So if we did, you know, say, the whole thesis in 2025, 2026, new LNG just got derailed for some reason and there was a need to curtail, that would take production below, you know, the sort of quarterly annualized number that I think you were getting at. But that's something that I think we would address more real-time as the market evolves.

Kevin MacCurdy (Director of Research)

Great. I appreciate the detail, and congratulations on a good quarter.

Operator (participant)

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

Jacob Roberts (Managing Director)

Morning.

Jeremy Knop (CFO)

Morning.

Jacob Roberts (Managing Director)

Maybe staying on that topic, is there any difference in how we should be thinking about the curtailments being baked into the guide of the back half of this year relative to what we saw in the first half? And what we're trying to think about is if there's a change in EQT's elasticity of supply between the two periods, perhaps with MVP online.

Jeremy Knop (CFO)

No, I don't think MVP impacts that at all. I think we maintain full flexibility. I do think having midstream wholly owned, where those NVCs effectively have been integrated away, I think that does give us a tremendous amount more flexibility, to be a little more, yeah, I guess, really to pursue curtailments, more than maybe we had in the past, where we felt like we otherwise had a big debt obligation we're having to pay to the midstream service provider. But I think our reaction in the back half of this year is more just governed by pricing. We haven't changed sort of the pricing levels we outlined earlier this year, where we would look to curtail just because we own the midstream. I think we still have that sort of floor threshold level.

So we're focused on earning returns on shareholder capital, not just well CapEx, not just maintaining realized pricing above cash cost. It's, it's got to be higher than that. So that's why we're proactively trying to guide to that.

Jacob Roberts (Managing Director)

Got it. Thank you. Quick second one. On slide 7, the 3 sites you've highlighted, I think you mentioned that you see kind of thousands of opportunities to across the field to implement this. Can you give a sense of how many wells each site touches, so to speak?

Toby Rice (President and CEO)

Well, I wouldn't say that that would be the, the way we think about it. I would just say at a very high level, we just look at the system pressures. We've got over a dozen gathering systems that are all hydraulically connected. Each one of those has a operating pressure that is sort of based on the amount of volume that's going through there, vintage of the wells that feed that, drive that. We also layer in where our development program is gonna go, and that will influence pressures as well. So the, the exercise that the teams have run through is sort of forecasting what those system pressures look like, and then assessing through compression, what the, sorry, productivity uplift will be if we lower the system pressures 300, 400, 500 PSI, and what that will look like.

So, I would say as a whole, this is a pretty large opportunity for us at EQT, and it's really exciting to look at the evolution of the improvements we made in this business. I'd say the last five years have really been focused on optimizing the efforts on site, you know, drilling, completing wells, and being more efficient on the production side. But now the efficiencies that we're focused on are gonna be really more on the midstream footprint and the actual field-wide improvements.

Jacob Roberts (Managing Director)

Great. Thank you. Appreciate the time, guys.

Operator (participant)

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

Michael Scialla (Managing Director)

Yeah, good morning, everybody. Just wanted to ask on the expansion of MVP. Sounds like I heard you right, the time frame you're thinking there is maybe five years down the road, even though you're seeing pricing there getting a pretty hefty premium to other parts of the basin. So just wanted to explore that timing. Is that because you don't think the demand there is there right now? Or, just any more color you could provide on the timing of that expansion?

Jeremy Knop (CFO)

Yeah, I'm not sure where the 5 years came from. I think we're excited to pursue that expansion as soon as possible. Actually, I think you know, the only thing that would cause us any delay is just making sure that it was time to come online with that expansion project on Transco to take all the gas. But beyond that, I think we are incentivized to get that built as soon as possible. And again, you know, net to EQT, that's a cost of probably $200 million-$250 million net to get that built.

I would say that the guidance that we have given out in our slide deck, that longer-term guidance today, I'd just say there's an ample cushion built in, so I wouldn't expect that CapEx number longer term to really change at all, despite the timing that we decide to pursue that expansion project. So that remains something that, you know, high on our priority list to get knocked out.

Michael Scialla (Managing Director)

Okay, great. Sorry, I misheard you on that. Have you started the open season there yet, or is that still down the road?

Jeremy Knop (CFO)

No. I mean, we just closed two days ago, so it's a little, little quick to do that, but I think it's something that we're gonna start exploring quickly.

Michael Scialla (Managing Director)

Got you. Just wanted to ask on curtailments. Can you say how much you're currently curtailing in that 90 BCF in the second half? Is that all assumed to be in the third quarter? Any more color you can provide there?

Jeremy Knop (CFO)

Look, it's in response to the market. If we can make money selling gas, we wouldn't curtail anything, obviously. But our assumption right now is that the majority of those curtailments probably take place in September and October. We have curtailed, even over the past week, some volumes on given days, depending on weather, depending on, you know, maybe it's over a weekend, not up quite to a 1 BCF a day level, but we do, on a very dynamic basis, optimize realized pricing to make sure that we're optimizing value creation and not just giving our product away for a price where we can't make money. And that's what we'll continue to do.

Michael Scialla (Managing Director)

Makes sense. Thanks, Jeremy.

Operator (participant)

Your next question comes from the line of Noel Parks from Tuohy Brothers. Your line is open.

Noel Parks (Research Analyst)

Hi, good morning. Just had a couple. I was wondering, you talked a bit about the impact of MVP on regional gas storage, especially in the East. Where do you say we are in really offsetting the effect of seasonality as you know a big driver of gas pricing? LNG, eventually, as it feeds in, is going to offset that, but just some thoughts on where you think we are at this point.

Jeremy Knop (CFO)

Yeah, I mean, look, winter has always been, and I expect to continue to be, the biggest source of demand for natural gas. I, I think, you know, I'd love to see a world where power generation grows and helps, increase that demand in the summertime as well, so you kinda see two peaks in the market. But I, I think it's probably a little too early to say exactly how quickly that develops.

Now, I will say, if you look at our slides from last quarter, what we outlined in power, demand growth for natural gas, and the fact that over the past decade you've had an increase of about 10 BCF a day just on the power side, and now what's happening with load growth on top of that, on top of coal retirements, I do think we are moving that direction in time, but, you know, it doesn't mean you're getting away from seasonality. It just means that you have a lot of demand at peak summer and a lot of demand peak winter. So I just think the nature of that's gonna evolve a little bit. And then LNG sendouts in the middle of that, which also could be somewhat seasonally driven, I think only amplify that seasonality.

Noel Parks (Research Analyst)

Got it. And wondered just if you had thoughts on the outlook for industrial demand, both sort of in region and out of region, in terms of gas, from more of an energy security, you know, resiliency level, just taking a greater role in sort of on a microgrid level, as you know, as power demand overall keeps increasing?

Jeremy Knop (CFO)

Yeah, I mean, look, I think the theme of reshoring manufacturing, well, you know, is gonna continue. It seems like they're both sides of the aisle are very supportive of that. I think the sort of de-globalization movement out of Asia for manufacturing will be a tailwind to that. I think energy policy and prices in Europe are a tailwind for that. That is something that, you know, is baked into our comments that we made earlier on about Appalachia demand growing upwards by the end of the decade, maybe to 40-41 BCF a day. There is a component of that baked in, but I would say, you know, the beauty of industrial is it's pretty steady, it's pretty predictable.

If you, I think if you look at recent history of that, it has been flat to slowly growing, and I, I think that trend should continue. But I wouldn't say there's any sort of big catalyst needle movers that should really skew up a fundamentals model all that much.

Toby Rice (President and CEO)

Yeah, I'd say at a very high level, energy insecurity is going to continue to be a big theme around the world and even in parts of this country. And the volatility that we see is only going to drive consumers of natural gas closer to the source of where that energy is produced, to reduce the number of things in between their manufacturing facility and the source of energy. That's one way they can protect their supply and protect their business. And that just is going to mean that we think this volatility is gonna drive more in base and demand for natural gas products.

Noel Parks (Research Analyst)

Great. Thanks a lot.

Toby Rice (President and CEO)

All right. Thanks.

Operator (participant)

That concludes our question and answer session. I will now turn the call back over to Toby Rice for closing remarks.

Toby Rice (President and CEO)

Thanks, everybody, for being here today. You know, with this being our five-year anniversary, I just want to reiterate to everybody that all of the progress that we've made at EQT would not have been possible without the shareholders. It was you that voted 80% to put in a new management team here and give us this opportunity to realize the full potential of EQT. It was you all that voted, brought in a board of directors that has really been amazing at guiding us through this amazing transformation. And with this 99% shareholder vote supporting, transformative transaction with the E-Train assets, you've given us a platform to continue this momentum, and we're really excited about working hard for you going forward.