Thank you for standing by. My name is Danica, and I will be your conference operator today. At this time, I would like to welcome everyone to the EQT Q3 2024 Quarterly Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. 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 third 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 and future events could materially differ from these forward-looking statements because of factors described in our 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. The third quarter was hallmarked by the closing of our strategic acquisition of Equitrans Midstream, which transformed EQT into America's only large-scale vertically-integrated natural gas business. This combination has created a differentiated business model among the energy landscape, one that has leading inventory duration at the absolute low end of the North American natural gas cost curve. EQT's position as the lowest cost producer structurally derisks our business in the low parts of the commodity cycle while simultaneously unlocking unmatched upside to higher price environments by eliminating the need to defensively hedge longer-term. We believe these characteristics position EQT to generate disproportionate value for our shareholders regardless of where we are in the commodity cycle. Since we closed the Equitrans acquisition, our integration team has been sprinting ahead with more than 60% of total integration tasks completed in just three months. This remarkable pace is a testament to our proprietary integration system which has been honed across multiple successful transactions over the past several years. The highly efficient integration pace we've seen to date is resulting in synergy capture occurring quicker than we originally expected. Recall, we had previously assumed base synergies would start accruing by the middle of 2025. But with our integration progress to date, we have already achieved $145 million of annualized financial and corporate cost savings which is $25 million more than our original underwriting assumptions. Said another way, we have already derisked more than half of our $250 million base synergies in just three months of owning Equitrans. This rapid pace of base synergy capture along with longer-term system compression upside further increases confidence in our ability to optimize value from the combined entities. We are also seeing Equitrans employees excited to be integrated into EQT's culture. This is a similar situation to what we observed when we took over EQT in 2019, where the cultural buy-in of our employee base enabled us to create more value than we originally anticipated. I'm extremely excited to see what the combined EQT and Equitrans teams can accomplish together over the coming years. Alongside rapid integration and synergy capture, we are already unlocking operational efficiency gains as a direct consequence of the acquisition. An example of this can be seen in our investor presentation, where we highlight a new EQT record for water delivered to a well site. This record water delivery pace in turn facilitated another all-time EQT record for completions pumping time, besting our prior record set earlier this year by 10%. The pace of water delivery is a key factor in completion efficiency. Put simply, the faster you deliver water to the well site, the faster you can frac, which in turn, drives down well costs. This record was only possible because of the seamless coordination of our internal Equitrans water system with EQT's upstream operations, highlighting how the optimization of the Equitrans water assets has the potential to drive additional operational efficiencies that we could not have achieved standalone. We also recently completed the connection of EQT's water network in West Virginia with Equitrans' water system in Pennsylvania, which structurally improves our ability to deliver water to well sites. This connection should also save more than $70 million in water disposal costs over the next two years from an investment of just $15 million, providing an example of the type of low-risk, high-return investment opportunities unlocked by the acquisition. Efficient water delivery along with various other supply chain initiatives are supercharging the recent completion efficiency gains that we highlighted with Q2 results. During the third quarter, we set a new EQT record for completion efficiency with footage completed per day averaging 35% faster than our 2023 pace. The past two quarters of operational performance along with our Equitrans integration momentum are increasing our confidence in a sustainably faster completion space, and we see the opportunity to complete 50% more footage per day in 2025 compared to our historic average. With continued success, we may ultimately be able to drop from 3 to 2 frac crews over time, which is remarkable given we are able to maintain 7 Bcf a day of gross operated production at this activity level. We are still quantifying the potential impacts to our capital budget, but we believe these gains could have the potential to sustainably save approximately $50 per foot, which could translate to $50 million to $60 million per year. Shifting gears. We recently announced that EQT has become the first traditional energy producer of scale in the world to achieve net zero Scope 1 and 2 greenhouse gas emissions. Not only did we accomplish this ahead of our 2025 goal, but achieved this net zero status across the entirety of our upstream operations, inclusive of recently acquired Tug Hill, XcL Midstream and Alta assets, which were not included in the target originally set in 2021. This means that over the past five years, EQT has reduced total Scope 1 and Scope 2 GHG emissions by over 900,000 tons, which is equivalent to taking approximately 195,000 cars off the road annually. The bulk of these reductions came from structural emissions abatement, including replacing more than 9,000 pneumatic devices shifting to electric frac fleets, deploying combo development and installing advanced emissions control devices. For the remaining emissions that are not available with current technologies, EQT has generated carbon offsets through forest management projects as opposed to purchasing third-party carbon credits. This was done via our partnership with the state of West Virginia and includes conservation management practices such as the removal of invasive species, wildfire risk monitoring, and native tree and shrub placement, all of which have co-benefits for our local stakeholders. These efforts are verified by West Virginia University, ensuring both economic and environmental benefits to the region. Over the life of this partnership, we expect to generate approximately 10 million tons of high-quality carbon offsets at a cost to EQT below $3 per ton, underscoring EQT's capital-efficient path to achieving net zero emissions. We believe EQT's unique position as the only vertically integrated low-cost natural gas producer with multi-decade inventory and net zero Scope 1 and 2 emissions will continue to open differentiated ways to maximize the value of each molecule similar to the long-term supply deals we announced with utilities in the Southeast last year. With that, I'll now turn the call over to Jeremy.

Thanks Toby. I'll start by summarizing our third quarter results. But prior to doing so, I'd like to note that results shown on our financial statements include Equitrans for 70 days during the quarter. So, we've also provided pro forma numbers assuming a full quarter of Equitrans results for the purpose of comparability to guidance and consensus estimates. Strong well performance, continued efficiency gains, and modestly lower-than-expected curtailments drove Q3 sales volumes to 581 Bcfe, or 4% above the high end of our guidance range. It's worth noting that had we not curtailed, we estimate production would have come in at 616 Bcfe for the quarter, or 6.8 Bcfe per day, highlighting the true strength of our performance. As it relates to curtailments, we have been taking a highly tactical approach over the past few months in response to the volatile gas price environment. This strategy has allowed us to match supply with demand on a daily basis, thus maximizing our price realizations. Consequently, our differential for the third quarter came in $0.10 better than the midpoint of our guidance range at $0.65 per Mcf, underscoring how this tactical approach is creating value in real-time without disrupting operations or impairing productive capacity. We believe these impressive results prove why tactically curtailing volumes in periods of weak pricing is the right strategy in a volatile world. The acquisition of Equitrans gives us greater ability to deploy this strategy as it eliminated 4 Bcf per day of minimum volume commitments while simultaneously lowering our cost structure to a level that we can maintain steady operations even in the low parts of the commodity cycle rather than being forced to slash activity due to high operating leverage. Pro forma for the full quarter of Equitrans, our operating costs came in at $1.07 per Mcfe, which is $0.05 below the low end of guidance due to production outperformance and LOE and G&A expenses below expectations. Pro forma CapEx was nearly $100 million below the midpoint of our guidance range at $573 million, with efficiency gains and lower midstream and pad construction spending accruing to our benefit. On the midstream side, pro forma third-party revenue came in at $142 million, at the high end of guidance, driven by better-than-expected uptime. MVP capital contributions were $160 million, in line with expectations. Turning to the balance sheet, Q3 was an eventful quarter with the closing of Equitrans in July from $2.5 billion to $3.5 billion. At closing, EQT redeemed all of Equitrans' outstanding preferred shares, followed shortly thereafter by the redemption of EQM's $300 million of bonds due in August 2024, saving approximately $50 million annually from reduced cost of capital. Yesterday, we announced the divestiture of our remaining non-operated assets in Northeastern Pennsylvania to Equinor for $1.25 billion in cash. Recall, these non-operated assets came with our Alta acquisition in 2021, and we allocated approximately $1.1 billion of value to them at the time. Between asset-level cash flows and the two transactions announced this year, we expect to realize approximately $3.6 billion of total value, implying a 3.3 times return on investment since 2021. We expect this transaction with Equinor to close by year-end, with proceeds expected to be used for debt repayment. With this latest sale, we have now announced cash proceeds of $1.75 billion compared to our $3 billion to $5 billion asset sale target. We are simultaneously making rapid progress in our regulated midstream sales process, giving us confidence in achieving the high end of our asset sale target range by year-end 2024, thus derisking our balance sheet several quarters ahead of schedule. Turning to hedging. Since our last update, we have added a significant amount of hedges in the back half of 2025 to bulletproof our deleveraging plan. Post these additions and considered for the non-op sale, we are now approximately 60% hedged for calendar year 2025 with an average floor price of $3.25 per MMBtu, with upside as high as $5.50 per MMBtu in Q4. With our updated hedge book and low breakeven cost structure, we estimate EQT can generate free cash flow next year down to a NYMEX natural gas price of approximately $1 per MMBtu and generate nearly $1 billion of free cash flow at $2 per MMBtu Henry Hub prices, underscoring the unrivaled earnings power of our business in any scenario. Beyond 2025, we expect to use commodity derivatives opportunistically rather than defensively as our position at the low end of the natural gas cost curve acts as a structural hedge, which in turn facilitates unmatched exposure to high-price scenarios by limiting our need to financially hedge. Turning briefly to the macro landscape. We have spent the last few quarters studying the power markets, which are awakening from two lost decades and becoming one of the most interesting corners of the energy industry with a direct impact on natural gas demand. Over the course of this year, we have witnessed a reluctance to entertain the idea of gas power generation for data centers evolve into a widespread acceptance of natural gas as critical. At the same time, more than 80 gigawatts of coal generation capacity is scheduled to be retired by 2030 and nearly 200 gigawatts by 2035, leaving a hole in the US base load power stack that can only be filled quickly by reliable natural gas generation. We expect natural gas to take 50% to 80% of new power generation market share as intermittent renewables are not suited for 24/7 reliability, and we believe there are just a handful of more nuclear facilities that can be restarted through the end of the decade. These dynamics are giving us greater confidence in our base case view that data centers and additional coal retirements will drive up to 10 Bcf per day of incremental natural gas power demand by 2030. Notably, this demand will be regional in nature with more than half likely to come from the Southeast and PJM markets. Given EQT is the only large-scale integrated natural gas producer with exposure to these regions, we stand ready to support and directly benefit from this megatrend. Turning to fourth quarter guidance. We've made some modest tweaks to our prior outlook. We now expect fourth quarter production to range from 555 to 605 Bcfe, up 7% from our prior outlook of 515 to 565 Bcfe due to robust well results and less curtailed volumes than we previously expected amid an improving Appalachia price environment. For perspective, we estimate our 2024 production is tracking above the high end of our original 2,200 to 2,300 Bcfe guidance range when normalized for curtailments, demonstrating the strength of this year's underlying performance before the impact of our decision to curtail production. Looking into 2025, we still intend to maintain flat year-over-year sales volumes pro forma the transactions with Equinor around 2,100 Bcfe and expect to pull back activity if efficiency improvements continue to pull forward volumes. On basis differentials, we are tightening our fourth quarter differential guidance range by $0.05 to $0.50 to $0.60 per Mcf as Eastern storage levels have normalized, improving local pricing this winter. Looking at operating expenses, we are lowering the midpoint of our fourth quarter operating expense guidance range by $0.05 per Mcfe, largely driven by higher volumes and lower upstream LOE and G&A expenses. Note, we reallocated some expenses within our GP&T outlook as we fine-tuned our pro forma accounting for Equitrans. But this had essentially no net impact on our total GP&T expenses. On CapEx, as I mentioned previously, third quarter spending came in nearly $100 million below expectations with part of this variance driven by pad construction shifting from Q3 into Q4. This shift, along with embedding some conservatism around non-op spending, drove a $50 million increase in our fourth quarter capital guidance. That said, our total second-half spending is still trending below the midpoint of guidance we put out last quarter by a net $50 million, reflecting the efficiency gains referenced previously. At MVP, we have fine-tuned estimates for slightly higher capital contributions to complete the right-of-way reclamation post Hurricane Helene and a slightly lower distribution in the fourth quarter, simply driven by payment timing. At recent strip pricing and pro forma the non-op sale, we forecast cumulative free cash flow of approximately $14.5 billion from 2025 to 2029 at an average natural gas price of roughly $3.50 per MMBtu. At $2.75 natural gas prices, EQT would still generate approximately $8 billion of five-year cumulative free cash flow. While at $5 gas, this number swells to almost $25 billion, which we can realize as we do not need to defensively hedge. There is no other natural gas business that comes close to providing the same combination of downside protection and upside exposure for investors. We believe EQT is now in a class of its own. Our simple goal is to be the easy-to-own way for investors to gain exposure to natural gas, meaning if you're thematically bullish on natural gas, whether it's because of coal retirements, power growth, LNG exports, dwindling core inventory, bearish oil prices due to OPEC oversupply or anything else, we are positioning EQT to be the go-to natural gas stock that is a fixture in your energy portfolio through the cycle. We see our story increasingly resonating with long-term investors who trust we will continue to operate from the same principal framework that has brought us success to date, compounding cash flow year after year. And with that, I will turn it back to Toby for some concluding remarks.

Thanks, Jeremy. EQT today is operating at the highest levels of efficiency in history. And quarter after quarter, we continue to break records. We've built an unrivaled integrated natural gas business with key catalysts for continued value creation. We have high confidence in the successful completion of our deleveraging program and continuing our long track record of delivering on our promises to shareholders ahead of schedule with better-than-expected results. And with that, I'd now like to open the call to questions.

Your first question comes from Doug Leggate with Wolfe Research. Please go ahead.

Thanks. Good morning. Congratulations on your achievements. Toby, I suppose we’re never fully satisfied with the baseline, especially since you are progressing more rapidly than initially anticipated. My question is, when I look at slide 6, which outlines your progress towards the $250 million target, and then slide 25, which presents the potential upside to $425 million, how should we interpret the timing and risks associated with both figures, particularly regarding the potential additional benefits from infrastructure optimization?

Well, I'd say we're ahead of schedule, both from a time perspective and realizing synergies that are a little bit greater than what we had anticipated. What's in front of us now really are the synergies related to operational execution. And those the pace at which we're moving in this integration being 60% through this helps us frame those up a little bit better. And Doug, those synergy capture estimates will be folded into our 2025 budget, which we're currently working through when we'll provide updates in future calls.

The pace of progress appears to be ahead of expectations. Toby, my next question is somewhat complex to formulate. Observing the fluctuations in gas prices during the third quarter and how you monitor volumes, I'm curious about the flexibility of your curtailment strategy. Specifically, how easily can you adjust operations in response to price changes? My question stems from the fact that you no longer have MVP obligations linked to your ownership of E-Train, which gives you significant flexibility to adapt to short-term price shifts. Should we view your curtailment strategy in this light, or am I misunderstanding it?

Yeah. I think it's really important to understand. I think the dynamic that we laid out on slide 21, which is framing up sort of the natural gas market characteristics and how they've changed. I think it was a really powerful chart that sort of supports the fact that we're going to be in a more highly volatile world going forward. And the question that people need to ask is how are these businesses going to perform in this more volatile world where you're going to have lower lows and higher highs. The way that our business is going to manage in those low price periods, there's really two things. It's the integrated nature of our business, which as you mentioned will give us tremendous flexibility by removing MVCs that we had in place. So we've lifted a huge constraint and have more flexibility there. But the other thing that's going to allow us to curtail that's equally as important is having a super low cost structure, and that will give us the ability to curtail volumes and not have to alter or slash activity levels. What that means is that when those higher price environments show up, we're going to be positioned to capture that. And we're not going to be sitting six months. Our production is not going to be sitting behind six months of restart. It's something that we can turn on pretty rapidly. And that's a muscle that we've been flexing in the past, and it's going to be a muscle that's going to be really important in this environment that we're looking at.

Doug, if you look at Q3 specifically, we have been turning on and off up to a Bcf a day on a near daily basis in response to where pricing is. That is really the reason we've realized that $0.10 better differential this quarter is just being able to tactically do that. Now I think in a low price environment, that's a great tool. It's kind of like hedging, kind of like basis hedging away. And when you look at that chart, Toby referenced on page 21, 60% of the data points you see on that bottom chart are really below $3, so about 20% of those are below $2. And in that environment, that's generally where you're going to see us turn volumes off because you just can't make money there; the rest of that time we plan to be supplying gas to the market. And so it allows us to almost delete the lows out of our sales volumes, but still be positioned to capture the highs. And so if you look at the data shown there, the difference between the median and the average is over $0.80. And that's effectively the difference if you pursue the strategy we're pursuing, where you don't have to hedge away the highs, but you still are protected against the lows, you can curtail and you have a structurally resilient business. $0.80 for us over two years of production is a tremendous amount of value added certainly when you look out long-term. So it's very hard to model that. I think the character of the market, as we keep talking about, as you and I have discussed a lot, is changing, and that's how we're trying to position.

Guys, pardon the clarification and of course, I meant MVC, not MVP, I think you've got too many pipelines, I guess. But just to be clear, so when we look at the volatility intra-quarter, in your curtailment strategy, you have the ability to basically pick your spots and therefore, beat us on your basis differentials? Is that the right way we should think about it?

Correct.

Thank you. That's what I was looking for. Thanks, guys. Appreciate the time.

Our next question comes from Roger Read with Wells Fargo. Please go ahead.

Yeah. Thanks. Good morning, and I appreciate the clarity on the previous question. I think a lot of us were trying to figure that out on the curtailment side. I think one of the other questions I have is early days, obviously, with the Equitrans acquisition. But as you think about synergies into 2025, maybe a little bit of a – what have you seen that surprised you so far? What do you think it might take a little bit longer? And just trying to get an idea, we're used to companies setting a synergy target and outperforming it, you think that's something likely to play out for you here?

Yeah. So the biggest thing for us operationally, which I think you have most of the conservative baked in, in the synergy estimate really is outlined on slide 26, the uplift we're going to see from compression. It's important to note, when we framed up that synergy, we were assuming a 10% uplift from the benefits of adding compression. And these pilots that we're showing here are showing that we're seeing nearly two times that uplift. So, that will be helpful. Timing on when we can get these compression projects rolling at a larger scale is going to be the big determining factor and the team has been hard at work, and we'll be putting those projects into our budget. So, timing and all of that will be framed up in our 2025 budget plan.

Okay. And then my other question is, obviously, things have gone fairly well on the asset dispositions, the non-op stuff you cited. I think we've seen rumors in the press about MVP sale, if you're able to generate more cash just from operations in addition to the asset sales, what's the right way to think about how you would right-size the balance sheet? Meaning, how much of a premium would you have to pay on any of the debt to retire early? And I'm just trying to think about it as do you build cash, do you return cash and then pay the debt off in a more methodical pattern?

No. We've been spending a lot of time on this. I think we have a pretty efficient plan to eliminate the debt that we have in front of us and smooth out our maturity stacks. So, I don't expect any sort of inefficiency to come out of that. I think it will be pretty straightforward.

All right. Appreciate it. Thank you.

Thanks.

Our next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Thank you, team, and congratulations on the progress with the asset sales. In your prepared remarks, you mentioned spending a lot of time in the power markets. I'm interested in your current assessment of AI and data demand related to data centers. How do you view this in the Marcellus region? Do you anticipate an increase in local demand for data centers? I would appreciate any real-time insights or perspectives you can share, considering you are at the forefront of this situation.

Yes. So, we laid out sort of our plan on 2016, we're seeing between 10 and 18 Bcf a day of demand growth for natural gas due to power. Some of the real-time data that we're looking at because this is the million-dollar question is AI, people know power generation is coming. What percentage of that is going to be natural gas? So, like a lot of you, we're looking at the orders that are coming in for natural gas turbines. And you see one of the largest turbine manufacturers in the world, Mitsubishi, seeing a 50% increase in their orders. You see GE, compared to last year, their orders are up 90%. So, while this stuff isn't making the headlines of how much market share natural gas is taking, the orders are building up and strengthening that natural gas is going to continue to be the workhorse that adds a lot of this power demand. And just looking at the baseline of what we've done over the last 10 years, natural gas has seen power demand needs requiring 14 Bcf a day. That's what we've done over the last decade. Not a lot of people have talked about that. That was largely driven by coal-to-gas switching, which is still a theme going forward. And now you add on the power generation growth from AI. And it's not too hard to believe some of these numbers that we're putting forward.

Toby, we've seen nuclear restarts in PJM. We've seen some talk about license extensions on the nuclear side as well. As you think about competition for that natural gas demand, how do you think about the alternatives, whether it's renewables or nuclear? And how does that fit into the math for the TAM around this market?

On nuclear, that was something we looked at what would be the other options like Three Mile Island that could come back online, keep in mind, some of this power demand growth estimates is around, call it, 70 to 80 gigawatts. Our view on this looking at similar nuclear facilities that would have the potential to add about 3 gigawatts of power demand. Relative to what's required, it's a drop in the bucket, it's not meaningful. And it still needs to happen, but the world is going to be looking for fresh, reliable, affordable energy sources that are going to mean more natural gas. And that's what we're seeing in the order books when people are looking to pick up these turbines.

Thank you, sir.

The next question comes from Jacob Roberts with TPH. Please go ahead.

Good morning.

Good morning.

I just wanted to see if we could hit on an early 2025 look. But looking at Q3 and Q4, excluding shut-ins, I think the run rate is closer to 2400, and should the market be thinking about slight declines in your production base in 2025, given the earlier comments kind of the 2,100 level net of the sale?

Yes. Look, I think from where we are within the year, I think we're in a peak time right now. So I do expect that to come up a little bit as we get into 2025. But I would say year-over-year, we see it as relatively flat growth on our remaining assets that we've not divested.

Okay. I appreciate that. And then lastly, I know the release noted the production and capital impact from the non-op sale. Should we be thinking about any changes to operating expense?

No, I wouldn't say materially at this time.

All right. Appreciate the time, guys.

Your next question comes from Kalei Akamine with Bank of America. Please go ahead.

Hey, good morning, guys. Thanks for getting me on. My first question is on operational synergies, water, in particular. Can you talk a little bit more about how putting water in the right places can help you drop one frac crew? Are you simply cutting the standby time? When could this happen? And what does the impact on capital look like?

Yes. It's pretty simple. When we look at driving factor for completion efficiencies. It's the amount of feet we can frac per day. That is driven by the amount of hours that we're pumping per day. So we look at the NPT and when we're not pumping for us, a big part of that nonproductive time wedge was waiting on water. We've eliminated a large part of that. So you take out a lot of NPT time, you replace that with pump time, and your footage per day increases. So if you can increase your efficiencies by 30% and you're running 3 frac crews, you've positioned yourself to get the same amount of footage and have 33% less frac crews. That's what we're set up and monitoring to bake that into the 2025 plan. From a cost perspective, that could translate to about $50 per foot of savings or roughly $50 million per year of operational efficiency value.

And Toby, to clarify, is this in your synergy target? I guess from our perspective, it's hard to tease out with the synergy and with the natural evolution of your business and it pulls over time that's going to get more blurry. But just to be clear, is this in the target or is this separate?

That would be separate. That was not included in our synergies.

I appreciate the clarity. The second question pertains to gas balances, and it has two parts. First, could you remind us about curtailments, specifically how much you currently have and your plans for bringing that back in light of winter in-basin pricing? Then regarding MVP, our understanding is that it can flow more fully in the winter; could you provide some insight into what that entails and its implications for headline in-basin production numbers?

Yeah. So on that first question of what we have tail, we've been fully online for several weeks, actually. So I wouldn't expect when you're looking at your gas balances that EQT is bringing back an additional 1 Bcf a day, which we had curtailed at the peak. That's already back. It's been back. And so I think as everyone is trying to look at their gas models, I think that's a pretty important factor. And look, we did that because the market showed that there is a need for that gas. It was above our price targets. And so as you look at our improved guidance for Q4, a lot of that's because the assumptions we had previously made for curtailment in October just haven't played out. We just haven't needed to curtail in response to what the market has told us. And so that's why you've seen that move up in addition to better well performance. And then on your MVP question, look, the assumption we are making is effectively that between December and February, MVP should flow at full capacity or near it, as you see that ARB opened up, and there's that downstream demand. So that's effectively what you'll see baked into our guidance.

Awesome. Appreciate that. Thanks, guys.

Your next question comes from Dave Deckelbaum with TD Cowen.

Good morning, guys. Good morning, Toby. Thanks for taking my questions this morning. I was hoping that you guys could give a little bit of color and update around the regulated asset sales process. Just given the success of the non-op now, how do you think about timeline? I know that you have a year end 2025 debt target. So presumably, I guess, you have roughly 15 months or so before we get down to that level. Is this something you want to get done sooner than later? And then as you think about selling those, a portion of those assets, is there a right ownership percentage that would like to retain outside of just a controlling stake?

I believe we've clearly outlined our strategy in previous calls and have been transparent about it. There should be no changes from what we've discussed before. Investor interest has been strong, and the cost of capital has surpassed our expectations. The level of investment in high-quality natural gas pipelines is higher than anticipated, which is accelerating our timeline for when a deal may be finalized. We are currently engaged in discussions and working through the process. While we initially expected to close in the first half of next year, we now anticipate that it could happen before the end of this year.

That's helpful. If I could just ask one more. Obviously, I know the industry is focused on MSAI power generation thematic. And you talked about, obviously, the regionalization of demand with a lot of that proliferating in the Southeast where EQT has a ton of egress via MVP and expansion. I know you guys have already guided to, obviously, benefiting from the firm demand contracts that you have in place in late 2027 with the Transco expansion with utilities. As we think about AI and its commercial impact to EQT, you talked about benefiting from this directly. What is like the remaining quantum if you see this proliferation in the Southeast of how much more we could see contracted on top of those firm sales? And is this something that is much more of a 2030 and beyond expectation, or should we expect potential for incremental basis improvement between now and the end of the decade?

Yeah, great question. So in our view, Appalachian demand would include what is taken – really exported out of basin plus in-basin demand. We think between now and the end of this decade that should increase from about 35, 36 Bcf a day to about 42 Bcf. So effectively adding a whole another EQT in terms of demand, I think that is overlooked in many ways. And really, in our assumption, no new pipes are getting built aside from the expansion we expect to pursue on MVP through the compression that we've talked about previously. Beyond that, it's really in-basin demand, and when we step back and think about how does that play out and impact our business, it's either one of two ways and it's probably a combination of both. One, we think it tightens in-basin differentials, but it also allows us to grow. So we're really a price times volume business. We expect to see benefits on both sides of that. And now in our new integrated business model, we effectively control a lot of the quarter in the basin, we expect to be the one to probably disproportionately benefit from that growth where we can connect our low-cost decades of supply to those different sources of demand as they come online. So that's something we're hyper-focused on. It's one of the reasons we haven't gone out to other plays because we do see that backdrop playing out in Appalachia. And I think we're as well-positioned anybody to benefit from that.

Appreciate that color.

Our next question comes from Josh Silverstein with UBS. Please go ahead.

Good morning guys. Last quarter, you talked about an initial outlook for spending next year around the 2.3 to 2.6 range. Given the efficiency gains that you guys have seen this year, the non-op sale, and then a pending midstream sale, are you thinking that the lower end of that range is now more likely relative to the initial use?

So if you're at a high level bridge that, and just start with the midpoint for ease of discussion, the midpoint of that range we gave out was 2.45. The non-op sale removes about $75 million out of 2025 and the efficiency gains we referenced in prepared remarks, we equated to about $50 million of additional savings beyond what we had assumed at the time. So I would expect that to probably be toward the lower end of that range at this point in time. But look, we're still working through it to figure out exactly how we might even put some of those savings into accelerating some of the midstream synergies. So it's a work in process, but I'd say directionally things are moving to the positive side of that range we looked at previously.

Got it. Thanks. And sorry to come back to the curtailments, but I'm curious what specifically in the markets you guys see to bring back all of your volumes that were previously curtailed. Henry Hub in the fourth quarter pricing is lower versus when you announced the 45 Bcf of expected curtailments for the quarter. Is it something in Appalachia? Is there something else? What is it that you guys are looking at that we should be thinking about going forward to kind of adjust our quarterly numbers for you guys?

Yes. So, all the volumes we curtail are volumes that we are selling into the Appalachia market, those are in excess beyond what we have had without a basin. So, the number we're looking at in Appalachia is about $1.50 at M2. So, when you see M2 above that, you should assume we're generally going to be flowing at full capacity. When it dips below that, you'll see us pull volumes off the market. And that at a high level is really our cash costs, excluding the sort of integrated midstream payments we pay ourselves plus F&D, about that $1.50 level. And so when you kind of put that all together and think about what it means for the gas market, I think there's kind of three bands of the way you'll see the market evolve over the next 12 months, call it. I think you will continue to sort of ping pong between $2 and $3 until all curtailments are back online because as you approach $3, all of that should come back online. I think there's a second band between probably $3 and $3.50 where you see some of the short-cycle DUCs and deferred tills sitting out there, that some of our peers have. I would expect that's the band with some of that start coming online. So, you see that additional resistance level. But I think once you get beyond that, you need to have real activity, and there's a delayed effect to that as we saw on the downside; there's a delayed effect of production falling, which is a delayed effect to production resuming growth when activity is added. And I think the longer production stays down where it is, the more difficult it's going to be to bring it back. So, going back to that Slide 21 that we referenced, I think we're likely to sit kind of at that below $3 level. And so you see a lot of this production back. And very quickly, you're going to snap towards the high end of that level as you get towards the back half of 2025 and into 2026, which is also why we've hedged the way we have. We remain unhedged in 2026 and highly exposed in Q4 next year. But I think it is going to be a path to get back to that level, just putting aside how winter goes, which is hard to predict.

Got it. Thanks for the color.

Our next question comes from Bert Donnes with Truist Securities. Please go ahead.

Hey good morning team. You mentioned that the production should be kind of directionally flattish on the remaining upstream assets. Historically, though, we've seen some operators attempt to take advantage of shoulder months and shape their production. Should we expect to see that come out naturally as you use curtailments throughout the year next year? Or is that strategy just not viable anymore because of the loss in efficiencies when you try to bring all those wells all at once?

Yes, that's never really been our strategy. I mean we've always really focused on really the most efficient way to operate and execute, which is not really the start-soft nature of operations cadence, which you need to execute to pursue that strategy. So, I don't think at least from EQT, you're going to see that sort of seasonal up and down that you see in the market more broadly or out of Appalachia more broadly. I think for us, we try to run that pretty consistently. You will see like in Q3 this year, there are some quarters that will be higher than others, but year-over-year, you should expect that to be pretty flat until there's a real need in the market for that production, which I think you'll see in terms of Henry Hub price rising and local basis being relatively tight.

That makes sense. I have a more specific question about the timing of the asset sale. You received a strong price on the non-operated assets. However, we have some questions about the possibility of selling assets that require low capital during a period of lower near-term gas prices. Could you explain how you balance selling assets with reaching your leverage target, or are buyers simply looking beyond the near-term gas prices, possibly focusing on projections for 2026 in relation to acquisitions and divestitures?

Yes. I would describe the assets we sold as having a value of about $3.50 gas before tax, based on how we would have evaluated them. Despite current prompt prices, we believe there is solid value there. This includes the Upper Marcellus, which we anticipate will significantly drive development in Northeast Pennsylvania over the next few years, given the limited core lower area available. We're satisfied with the intrinsic value of the assets. Specifically, we estimate that these assets will generate about $750 million of free cash over the next five years, and we've received $1.25 billion currently without considering discounting. We believe the valuation remains quite strong. Comparing this deal to our previous one with Equinor six months ago, there are two main differences. First, the back end of the pricing curve has likely decreased by about $0.50, affecting value. Second, the earlier deal included an asset swap, complicating the comparison. Additionally, that deal was part of their strategic exit from US onshore operations, which may have added a premium. Overall, we believe the outcome of this process has been very favorable.

And just to clarify, regarding the acquisition and divestiture, does it work both ways? You mentioned that you received value for the later periods' strip pricing. Are you observing the same when considering potential acquisitions? Does that also apply to sellers?

It really depends on the environment. For core assets, there's a greater likelihood of seeing value in longer-term inventory. Over the past five years, we believe EQT has undergone a transformation, with mergers and acquisitions playing a crucial role in establishing us as the lowest cost producer with substantial inventory. Currently, there are no assets that match what we have developed. Therefore, we aren't placing a strong emphasis on M&A in the future. Instead, we will evaluate how to best use any excess cash to acquire durable inventory at the lowest cost. Historically, we've lacked the opportunity to repurchase shares since our business has changed significantly. Moving forward, once we stabilize our balance sheet, our focus will be on this strategy with confidence.

Perfect. Thank you.

Our final question for today comes from Noel Parks with Tuohy Brothers. Please go ahead.

Good morning. I was really interested to hear your comments about just as you have become more integrated again, your thoughts about volatility going forward. And do you see us reaching a point where this volatility winds up reflected in the strip? I'm thinking about how low the liquidity is out beyond a year or so compared to what we saw in prior eras, where I guess there is just more speculative capital out there. So just curious what your thoughts on that.

I believe that the market will face a shortage of storage capacity. To encourage the development of more storage capacity, particularly short-cycle self-storage, seasonal spreads need to widen. As the market progresses in the coming years, I anticipate that summer-winter spreads will increase significantly, which will serve as the incentive for building that storage capacity. Additionally, I expect to see this reflected in the options market, so I would focus on how the market is going to price that additional volatility.

Got it. Storage again, always comes to the floor sooner or later. And I'm just wondering, as you have outlined your strategy around curtailments and just how those can be useful. Do any of your scenarios that you look at contemplate the possibility of LNG capacity that has been planned, getting pushed out and its start-up? And with your strategy, I was just trying to get a sense of whether that could actually be something favorable for you if sort of that demand burst, given your cost structure and everything does get delayed or more or less neutral effect?

Yes. If that happens, gas prices would respond negatively. This is why we've worked hard to position the business to maintain a cost structure that can endure low-cost environments without needing to reduce activity. I believe it's just a matter of time before gas demand returns, and being able to navigate those downturns while remaining unhedged allows us to capitalize on higher prices when demand does pick up. We've set up the business with this in mind. Additionally, the volatility from LNG, weather events, and geopolitical factors should be considered. Looking back over the last few years, we've encountered significant events that have created substantial opportunities, and we’ve positioned the business to take advantage of those. In response to your earlier question about pricing in the strip, we demonstrated in the third quarter that opportunities to curtail volumes strategically have led to higher realized prices. I think it will be challenging to model this opportunity due to our approach of adjusting volumes and optimizing for improved pricing instead of merely choosing a gas price.

Noel, I'm trying to understand exactly what you're asking. If you're referring to potential delays with Golden Pass or other facilities, I believe one of the most optimistic aspects for the gas market right now is if that capacity comes online quickly. If that facility comes online by the end of 2025 along with others instead of gradually, we could see a substantial amount of capacity, say 3 Bcf, coming online rapidly. Over a year, that translates to a significant increase in demand. Producers simply can't ramp up that quickly, which would create a notable shift in US supply balances. While this may seem a bit bearish in the short term, I believe that once this occurs and as we move into 2026, it will be very positive. We plan to take advantage of any opportunities that arise and feel well-equipped for whatever direction the market takes. This delay could end up being a silver lining if many facilities come online simultaneously, particularly later next year.

Right. That was exactly what I was getting out your remark earlier about longer prices stay low and it suppresses overall industry activity, the harder it is to come back beyond DUCs and TILs to build activity back. So that was, kind of, what I was thinking. Thanks.

All right. Thank you all for joining. That concludes today's call. You may now disconnect.