EQT - NYSE

Good morning. My name is Briana, and I will be your conference operator today. At this time, I'd like to welcome everyone to the EQT First Quarter 2024 Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Cameron Horwitz, Managing Director, Investor Relations and Strategy. Please go ahead.

Good morning, and thank you for joining our first 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 yesterday's earnings release, in our investor presentation, the Risk Factors section of our Form 10-K 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. Last month, we announced our agreement to acquire Equitrans Midstream, a transaction that will transform EQT into America's first vertically integrated large-scale natural gas business. As we described in our conference call last month, this deal catapults EQT to the absolute low end of the North American natural gas cost curve, providing free cash flow durability in the low parts of the commodity cycle while simultaneously unlocking unmatched price upside by mitigating defensive hedging needs, thus providing investors with peer-leading risk-adjusted exposure to natural gas prices. This combination is anticipated to drive our long-term free cash flow breakeven price to approximately $2 per million BTU, which is $0.75 below the peer average and $1.50 below the marginal cost of supply in the Haynesville. This gap between EQT and both average and marginal natural gas producers is a sustainable advantage, which is rare to find among any commodity business and ensures EQT is best positioned to create through cycle value for shareholders, while other producers are forced to either chase commodity prices with the drill bit in a similar fashion to what has led to historical industry, value destruction or defensively hedge a significant amount of production, thus limiting the ability to capture value in the up cycle. Along with the material cost structure advantage, the combination of EQT and Equitrans will also create an integrated well to watch solution that will help enable and power growing demand associated with the data center and artificial intelligence booms that are burgeoning across the Southeast and Mid-Atlantic regions of the United States. Our base case view suggests the proliferation of data centers along with growth in other electricity-intensive markets such as electric vehicles to drive an incremental 10 Bcf per day of natural gas demand by 2030. While there is a plausible upside case that could take this number up to 18 Bcf per day. This means growth in the power generation segment that exceed LNG exports as a bullish demand catalyst for the natural gas market this decade. And this structural baseload demand growth story resides at the doorstep of our asset base. Our 1.2 Bcf a day of capacity on MVP, along with the long-term firm sales arrangements we announced with investment-grade utilities last year, means EQT's low emissions natural gas will be a key facilitator of the data center build-out occurring in the Southeastern United States and will give us significant exposure to premium Transco

Thanks, Toby, and good morning, everyone. I'll start by summarizing our first quarter results beginning with sales volumes, which totaled 534 Bcfe. As previously announced, we curtailed 1 Bcf per day of gross production beginning in late February and through all of March in response to the low natural gas price environment resulting from warm winter weather. Along with nonoperated curtailments, we estimate the total impact was 30 to 35 Bcfe during the quarter. Thus, normalized for curtailments, first quarter production would have been toward the high end of our guidance range, underscoring strong operational efficiency and well performance during the quarter. Despite the curtailments during the quarter, our per unit operating costs still came in at the midpoint of our guidance range at $1.36 per Mcfe. A significant contributor to this was the outperformance on LOE, which came in below the low end of our guidance range. This LOE beat represents a continuation of the trend of LOE outperformance we highlighted throughout 2023, as our strategic investments in water infrastructure continue to drive tangible cost structure reductions. Turning to the balance sheet. Recall, we retired all of our outstanding convertible notes, which eliminated $400 million of absolute debt over the past 2 quarters. We also liquidated the capped call that we had purchased in conjunction with issuing the convertible notes for cash proceeds of $93 million. Additionally, we issued a $750 million 10-year bond and use the proceeds to reduce our term loan balance from $1.25 billion to $500 million, while extending the maturity by 12 months to June 2026. We exited the first quarter with total debt of approximately $5.5 billion and roughly $650 million of cash on the balance sheet, leaving a net debt position of approximately $4.9 billion at the end of the quarter, down from $5.7 billion at the end of 2023. Subsequent to quarter end, we used $205 million of our cash balance to fund the previously announced buyout of a minority equity partner in EQT-operated gathering systems in Lycoming County, Pennsylvania, which closed earlier this month. This acquisition is expected to add approximately $30 million to our 2025 free cash flow outlook, highlighting an attractive free cash flow yield on assets that are annuity-like and have near zero execution risk due to EQT's existing operatorship of both upstream development and the midstream system. We intend to apply the remainder of our cash balance, along with the $500 million of cash proceeds from the Equinor deal towards debt reduction, which will allow us to make swift and significant progress toward the deleveraging goals that we laid out with the Equitrans announcement. We also recently added to our Q4 2024 and first half 2025 hedge book to further derisk our deleveraging plans. We are now between 40% and 50% hedged for the remainder of 2024, with an average floor price of approximately $3.40 per MMBtu. We are also approximately 40% hedged in Q1 and Q2 of 2025, with average floor prices ranging from roughly $3.05 to $3.30 per MMBtu. Upon closing the Equitrans acquisition and achieving our debt targets, we anticipate limiting defensive programmatic hedging to less than 20% of our production in a given year. Going forward, our $2 Henry Hub free cash flow breakeven price provides a structural hedge as the Equitrans acquisition strips out the operating leverage from our business, limiting our need to financially hedge. This unique dynamic provides EQT's investors differentiated upside torque to natural gas prices and peer-leading downside protection simultaneously. Turning to the 2024 outlook, we issued second quarter guidance and updated our full year production outlook to reflect voluntary production curtailments in response to the current low natural gas price environment. Our second quarter production outlook and per unit metrics embed the expectation that we will continue to curtail 1 Bcf per day of gross operated production through the end of May. Our updated full year production guidance also captures this assumption and embeds additional optionality for further curtailments this fall should natural gas prices remain low. We believe our strategy of near-term curtailments while maintaining steady operations is the right approach to this market for EQT, in contrast to high-cost producers who need to cut activity to reduce CapEx in hopes of remaining free cash flow positive. It is also important to remember that production is fungible between old wells and new wells, so it makes little sense to defer new well TILs versus simply turning off production today. Our production today is a product of our investments in the last 2 to 3 years. And our CapEx investments today have little impact on the volume this year, but rather drive volumes in 2025 and 2026, when the futures market suggests gas prices will be higher than they are today. EQT is positioned to take this approach as a result of our low-cost structure and strong balance sheet. And this is a good reminder of why we refer to a low-cost structure as our strategic north star. We also embedded a June startup for MVP and our updated outlook on the heels of Equitrans' filing for in service with the FERC this week. This represents a meaningful milestone as MVPs in service is a contractual condition precedent to closing the Equitrans acquisition and will finally allow EQT to provide much-needed natural gas to consumers in the Southeast region to meet growing power demand, displace coal and improve grid reliability. As Toby mentioned, upon closing of the Equitrans acquisition, we intend to pursue expanding MVP from 2 Bcf per day to 2.5 Bcf per day to meet additional demand growth expected in the Southeast region. This expansion will be achieved through the addition of compression to the existing pipe rather than laying new steel and thus has a low execution and regulatory risk profile and high returns, with an estimated build multiple of just 4 to 5x EBITDA. Turning to Slide 7 of our investor presentation, we provided more granular details on how the Equitrans transaction is expected to impact EQT's pro forma cost structure. While we are still working through some of the nuances of exactly how the transaction will be accounted for in our financial statements, this cost walk should give investors a good framework for thinking about the pro forma impacts of the transaction. In summary, we expect the transaction to drive a pro forma unlevered cost structure improvement of approximately $0.50 per Mcfe. Base synergies equate to approximately $0.12 per Mcfe and upside synergies provide a further $0.08 improvement. So the cost structure benefits to EQT from the Equitrans deal could total approximately $0.70 per Mcfe over time. That is a monumental impact. The advantage arising from this cost structure improvement is evident on Slide 10 of our investor deck, where we show cumulative 2025 to 2029 free cash flow for pro forma EQT and natural gas peers at gas prices ranging from $2.75 to $5 per MMBtu. EQT's pro forma free cash flow durability is peer leading at $2.75 natural gas prices as we project approximately $8 billion of cumulative free cash flow versus most peers to our free cash flow negative at this price deck. At the same time, free cash flow and an upside price environment, pro forma cumulative free cash flow generation of a staggering $26 billion. And importantly, most peers will actually have much less upside than shown here as they are likely to defensively and programmatically hedge away much of the commodity price upside to protect the downside risk resulting from high operating leverage. This underscores how the Equitrans acquisition drives free cash flow durability and down cycles while unlocking the ability to capture asymmetric upside in high-priced environments, given limited financial hedging needs. I want to close by sharing a few observations from the more than 100 meetings we've had with EQT and Equitrans shareholders in the wake of our acquisition announcement. While we have already experienced a high grading of our shareholder base over the past several years, the Equitrans transaction has further accelerated this trend as the merits of pairing the characteristics of a major integrated company with the superior long-term demand profile of natural gas is resonating extremely well. And we have been encouraged by the near unanimous support for the transaction from some of the world's largest, most thoughtful long-term fund managers, including shareholders of Equitrans who have expressed excitement in owning significant stakes in the new EQT. We think our easy-to-own business model will be increasingly coveted by long-term coffee can style investors who are structurally bullish natural gas long term. and we look forward to demonstrating this differentiated value proposition for shareholders as we navigate the volatile world ahead. And with that, we'd now like to open up the call to questions.

[Operator Instructions] Your first question comes from the line of Neil Mehta with Goldman Sachs.

This is Ati on for Neil. Guys, I'd be curious on the nonoperated asset sales in the pipeline, how are you thinking about the portion that's remaining? How the conversations are going with potential buyers? And what should we expect in terms of the structure of those deals? Should it be similar to what you've announced? Or is it going to be a little bit more cash oriented?

Yes. So we're continuing to have some really constructive conversations there and have a lot of great momentum. And I think what we're seeing is the announcement of the deal with Equinor a couple of weeks ago is actually really catalyzing those to move forward even more swiftly. So we have a ton of confidence in getting that done and a lot of great dialogue that's ongoing. Look, I think the deal with Equinor was a little bit unique because they had other strategic objectives in their exit from U.S. onshore. That's why we structured that deal the way we did, but I'd anticipate the remaining sale of that interest to be in the -- in cash consideration as opposed to a more complex kind of mix of assets and cash.

Got it. Appreciate that. And then as you think about the supply/demand macro for natural gas in the U.S. right now, you did mention that you will extend the cuts. How are you seeing the response -- the production response that you're seeing from the latest numbers? Is that -- is there an element of sufficiency there? Do you think there's additional cuts required? And how should we think about your philosophy as you think of bringing the cadence back online?

Yes. We think that you're going to continue to see cuts and discipline from other operators. But I think a lot of eyeballs are focused on what's going to happen with some weather with a normal summer, that could bring the -- that could tighten up some of the storage overhang we have. And then also these low gas prices are going to encourage more power demand. So I mean, we think there's a couple of catalysts here. But in the meantime, until those hit, I think you could continue to see more patience from operators.

Yes. At a high level, when you think about the macro outlook, you added about 400 Bcf a day into storage in excess from the winter weather, then another 200 on top of that from production being higher than we all forecasted. So you have an overhang of about 600 Bcf that has to get worked out by, call it, October. And that will happen -- the market mechanism forces that to happen both through curtailments to limitations in supply but also increases in demand from coal to gas switching. And as Toby said, certainly constructive summer weather can give that a boost as well. But look, I think to maintain that market rebalance through the summer, you probably maintain low prices. It probably can't rise all that much. But once you get through that October period, you see the inflection of LNG demand really start to pick up. We think that market starts to change pretty swiftly.

Your next question comes from Arun Jayaram with JPMorgan.

Gentlemen, I wanted to get your thoughts on, obviously, the data center demand, you highlighted in your deck how you think that this could create kind of a premium opportunity for gas that's sold on the Transco

Yes, Arun. So look, I'd start with going back to those physical gas sales deals that we announced in Q3, Q4 last year. And if you look at the way that was structured, we tranche that out across those markets. And so those were sold in tranches ranging from M2 plus $1.15, all the way up to Henry Hub plus $0.50, right? So we gave you guys the blended pricing for how that impacts the company. But to us, that sort of keyed us off to a lot of the demand and the tailwinds that are really coming that the utilities are seeing. And effectively, the premium being paid is to lock in reliability of supply. And so I think that's a good proxy for where that market moves in time. And if you think about what's happening between just electrification of everything, now adding data centers into that and think about the way the Transco pipeline, where it supplies gaps across the country, you're going to see the LNG facilities pull gas south on that pipeline and create an even bigger deficit in that Southeast market. So we think that market really in time becomes the most premium market in the country because you have a combination of LNG pulling gas away, and a deeper deficit from all these other factors we're talking about, whether it's retirement of coal, whether it's data center growth. And so that's why the utilities, I think, are willing to pay the prices that they did to lock up reliable gas supply. That's the reason we're so excited about expanding MVP and adding additional capacity because we think -- I mean, there's a big demand sync being created in that market from both themes but it's really the confluence of both of those big demand themes that's going to drive that market where it is. That's why we're so excited about MVP and also where our asset sits adjacent to that market.

And just I have a follow-up. We had been liaising with a couple of utilities and they mentioned how Governor Shapiro in Pennsylvania was somewhat focused on trying to keep grow demand within the state. And so I just wondered, Toby, give your perspective on some of the thoughts because Pennsylvania, as you know, exports electricity and gas, thoughts about some of that data center demand coming within the state of Pennsylvania as well as any latest views on East Coast LNG.

Yes, we were certainly encouraged to hear Governor Shapiro's comments about natural gas, both on increasing potential for power demand, but also in his comments about the LNG pause and advising President Biden that this LNG pause is a bad idea. I think Governor Shapiro understands that the people of Pennsylvania understand that natural gas is the economic engine that's powering the economy here in Pennsylvania and understands that natural gas is the key to decarbonizing, not only our own grids in the U.S., which Pennsylvania is the poster child for how impactful you can be lowering emissions when you replace coal with gas, but also understanding how we can do that on the world stage. People need to recognize -- I think a lot of people don't understand how much power Pennsylvania actually generates. And with the lowest cost, cleanest source of natural gas in the country being located in Pennsylvania, we have an opportunity to really think about expanding electricity exports to other states. And listen, look at what's happening in the Northeast part of this country, a lot of them put a lot of eggs in the offshore wind basket, and we consistently see offshore wind get knocked down, have projects get pulled. What's going to replace that? The sure thing, the thing that's always been there, natural gas demand, and we have an opportunity here that we are pushing to make sure natural gas can continue to give Americans affordable, reliable clean energy.

Your next question comes from Jacob Roberts with TPH & Company.

Just looking at the second quarter production guide, I apologize if I missed it, but can you help quantify the impact of the non-op side of things on the curtailments and TIL deferrals, please?

Are you talking about from the sale or which you're talking about specifically?

I believe the guide includes the 1 Bcf a day from your side and then also note some non-op TIL deferrals and curtailments as well. So I was just wondering on that on non-op side of things.

Yes. So net to the non-op interest, what's baked in there is about 10 to 15 Bs and the rest of it is operated deferrals that we -- are direct impact of our decisions.

Okay. Great. And then the second question, I think our work would help us agreeing with you on the outlook on the Southeast and Mid-Atlantic demand growth as we progressed through the decade. Just wanted to get your views on the potential to send more gas that way beyond MVP and the expansion? And maybe related to that, how should we think about third-party volumes on MVP over time?

Yes. So I think what's unique about MVP is that it is a -- it's a pipe where EQT owns 60% of the capacity today. And we are the only producer shipper on that pipe. So there's no other producers who actually can access that market through MVP. The other 40% are held by utilities on the other end. And so I think we are very uniquely positioned in that sense. The expansion will be part of a FERC open season. So who ends up with that capacity just under that regulated process. But it's certainly something that we think we are positioned to benefit from either way. I mean there's value to be created through the expansion. There's value to be added for the utilities by supplying them new gas in that end market. I mean we're all aligned and wanting to have that happen. Even if we are not the ones to take the capacity out, not win that auction, I think we benefit either way, we get to sell more gas where producers collectively in Appalachia get to sell more gas to the utilities on the other end of that pipe. So it's -- no matter how you look at it, I think, a big net benefit to EQT.

Your next question comes from Michael Scialla with Stephens.

I want to see a little bit more detail on your curtailments in terms of price level you would need to see before you change your decision there on the Bcf per day of curtailments.

Yes. At a high level, we think about it as cash cost plus F&D costs. We do want to recover the sunk cost of drilling the well. So that's why we think about it like that. So I mean you -- I mean it depends on the area, but call it around $1.50 in basin.

Okay. And Jeremy, so say you -- it sounds like you expect a pretty good step up in price when you get to sort of the October time frame. If you were to see that $1.50 price persists through the summer before you see that step up, would that suggest you're going to likely extend those curtailments through the summer?

I mean, look, we'll always do what's best to create long-term value. So look, we're always watching the market. There's always events that happen that we will change our decisions if the facts change. So it depends. But what we've mapped out right now is our current expectation.

Got you. And then just want to follow up on MVP. You talked about the demand growth you see in the Southeast U.S. and your plans to expand the pipeline, so a lot of focus on the integrated upstream, midstream model for you in your lower cost structure. How do you think about that with your divestiture plan and your potential to lay off, so I'm interested in that pipeline. Is it important to maintain control there? Or could you sell off all your interest there? I guess, just how you're thinking about marrying those 2 things?

Yes. So we have a tremendous amount of optionality, first of all. If you think about -- I mean, look, I think if you back in, first of all, the non-op asset sales side, the $1.1 billion value level that we called out for what we did with Equinor, if you gross that up, that implies about $2.75 billion to that whole package, right? So if the rest of it is a cash sale, you end up with, call it, $2 billion to $2.5 billion of cash coming in the door from that side, right? That's already, call it, 2/3 of the $3.5 billion asset sale target we talked about a month or 2 ago when we announced the Equitrans deal. So we don't have to really divest a lot or many assets on the Equitrans side if we don't want to. So again, it gives us a lot of optionality. If you think about some of the other deals done in the market like in the regulated space recently, TC Energy did a pretty interesting deal with GIP. It was a deal done for assets, not as high quality as MVP at like 11x EBITDA. BlackRock did a deal with Portland Gas recently also about 11x EBITDA. Again, not as good of a quality asset as MVP. And when you think about just the regulated assets overall in Equitrans, it's call it a $7 billion bucket of value. We could sell off some of those, we could sell off a minority interest, maintain control, maintain operatorship. There's a lot of different ways to structure it. And that is something we're working through right now. But I think our confidence level in getting something done that maintains optionality both near term and long term while still ensuring we delever the balance sheet rapidly in a really efficient way is very, very high.

[Operator Instructions] Your next question comes from Bert Donnes with Truist Securities.

Just had a question on the potential divestitures. As you reduce debt, how price sensitive are you? Is this kind of a highest bidder wins? Or is this, say, hey, if the bids aren't up to your expectations, you just kind of walk away?

Yes. As Jeremy mentioned, I mean, we have a ton of optionality and that means we're going to continue to be really value focused on these things. So while there's certainly -- there's a lot of interest here, which gives us a lot of confidence in completing this plan. I think you look at the Equinor transaction, we're going to be getting some pretty good values for these assets.

Yes. If you step back and think about the time line, the rating agency guided us towards, it's, call it, 12 to 18 months post-closing. We have guided closing to be probably a Q4 event. So we think about it as like we need to get through the deleveraging plan by the end of 2025, right? I think most of us expect the market for gas in 2025 to be a lot more robust than it is today, so because we're taking an opportunistic approach. We have good momentum right now. I feel very good that we get things done near term at very attractive values. But if we -- if something happens, and we decide, hey, let's be a little more patient, wait 6 months, wait 9 months, there's no issue doing that to make sure we maximize value.

That makes sense. And then switching to the LNG agreement you announced. I just wanted to make sure I understood the strategy right. This puts you at 45% of kind of your Gulf Coast exposure. Are you approaching the limit? Or is maybe there some understanding that, hey, you could go to 75% or so if you in the future plan to add some volumes that maybe had Gulf Coast exposure through a bolt-on or something like that? Or is there some number you guys have in your head where you kind of call it off or is 100% fine?

Yes. I think stepping back at a very high level, just from a market diversification perspective, we sort of soft circled around 10% of our volumes being exposed to international pricing, feels about right. And depending on the discussions with end buyers, we could toggle that number up or down. Where we're at right now, we've got about 10% of our numbers here. But keep in mind, these agreements are nonbinding, and there's some work to do to get the terms that allow us to achieve our objectives. So we have that level here, but maybe not all of those agreements will make it to the finish line, but we've got a lot of optionality, give us the ability to make sure we get the terms that we need.

Got you. And then this is a shot in the dark and it's related. I wouldn't call it an extra question. Is there any push because of the data center demand that maybe you would take your foot off the pedal of LNG? Is there -- are there balancing forces there? Or there are just kind of 2 positive outlooks that you're looking at? That's all I've got.

Yes, it's certainly another dynamic that we're putting into consideration. And when we step back and we look at the opportunity, servicing the emerging market of LNG, we have capacity to do that with our existing pipes. But one of the great things about data center demand is Appalachia has proximity to that. And so when we talk about advocating for LNG, this is more of a tide is going to raise all ships and be constructive for long-term demand of natural gas demand in the U.S. But when it comes to data centers, our view is really how can we get more direct exposure to that rising demand. And so we positioned the company extremely favorably to be able to make sure that we can get differentiated access to this new opportunity set. Things like positioning with MVP is great, showing the willingness to be first mover on doing large transformative gas supply deals that deliver reliable clean energy to customers. We're fielding calls on that front. And so we're really taking a much more targeted approach and leveraging our operation and commercial footprint to capture these opportunities in front of us.

Yes. I think it's really important to remember, if you step back and think about these LNG deals. I mean, they are very long-term agreements. And if you just look at the time when the U.S. became an exporter of LNG from 2015 to 2020, that arb was actually negative, right? So we expect over the long-term LNG to be a very positive catalyst, can add a lot of value. But if you sign up for too much LNG and that arb is negative for a couple of years, it's like a very, very expensive pipeline contract, right? You can get yourself into trouble with that. You saw that happen in the past decade. And so we think about it from -- you learn from the past. This is -- it's not the same as pipeline, but it is similar. So we are taking a very prudent approach to it. And when we step back and compare and contrast LNG versus data center demand, I think what's happening in the data centers will create a lot more like structural baseload demand not subject to is the arb open, is the arb closed for different periods of time. And that sort of stability is something that we really try to focus on in our business as we build it for the long term. So we'll have exposure to both, right? So in certain periods, one will be better than the other. But I think that growing data center demand theme on the doorstep of our asset base is something that has really surprised us. And the more we study it, the more excited we get.

Your next question comes from Roger Read with Wells Fargo.

Yes. Just want to follow up. Is there any update on any of the regulatory hurdles related to the acquisition of ETRN?

Yes. Part for the course, we pulled and refiled with the FTC and the sustained operating procedure. So we've continued to work alongside the FTC and provide updates along the way. We're really encouraged about the opportunity to talk to the FCC about how this transaction makes Americas natural gas Champion EQT, a lower-cost energy provider, delivering more reliable energy and also helping customers acquire cleaner energy sources. So a lot of great things for us to talk about with the FTC, and we're excited about the process.

Understood. And along those lines, the long-term demand here on the AI side, is there anything the data centers, let's call it, is there anything else you've seen recently or heard recently or any sort of direct outreach from consumers to EQT?

Yes. I think there's a new dynamic that's really taking center stage here. Everybody understands the energy that they acquired. They want it affordable. They want it reliable. They want it clean. And certainly, with data centers liability is at the top of the list. But the other dynamic at play is going to be speed. And there's only one energy source that has shown the proof of track record of being able to meet any sort of demand from America and that is natural gas. Speed matters. And at a very high level, there's a couple of things that's going to allow natural gas to service this new demand quickly. Number one is leveraging existing power infrastructure, understanding that natural gas power plants are only running on average around a 60% utilization factor. There's an opportunity to leverage that underutilized capacity, and that could increase natural gas demand in the near short term. And then stepping back, I think people are getting -- looking at how are they going to service this new demand. And all the challenges it takes to build any infrastructure even looking at natural gas, which will require a 20-acre footprint and all the permits associated need to make that happen, compare that to a 3,000-acre footprint if you're going to do solar or a 5,000-acre footprint if you're going to do wind. And you can understand that the best bet and the fastest option most proven is going to be leveraging natural gas to fill this demand.

I think it's super important to remember here, too, in terms of like in consumers reaching out wanting to buy gas, like if there is a first-mover advantage in this, like we already have it, right? We already sold 1.2 Bcf a day on a 10-year basis to the 2 biggest utilities in this region, right? And so when you think about where all the demand for data centers is right now in the country, today, you have about 20 gigawatts of demand. 13 of that is in the Southeast market, right? So a tremendous amount. So when these utilities reach out and they say, we need long-term reliable gas from a stable producer like EQT is the first name on the list. That is why we are the only ones who have already done a deal like this and done it at a scale that I think dwarfs what most people could do because we're the preferred supplier of gas. And you have to have a lot of characteristics in your business to be able to be that preferred supplier, part of it is scale, part of it is depth of inventory, it's credit ratings. It's having a really creative team that can work with utilities in buyers of gas to structure deals like this. So look, we think we're really, really well positioned to leverage what we've already done and accelerate that. And look, like we've already done, we're taking molecules that anyone can produce and selling them at a premium. I mean that's the essence of what we're doing. And I think we can do that and unlock sustainable demand in the process.

Your next question comes from Noel Parks with Tuohy Brothers.

I've got a couple of questions. Start on some of the same curve you've just been discussing. One of them was -- well, maybe sort of a broader question. You guys have clearly done a lot of thinking about risk reward and LNG timing. And I just wondered if you had any thoughts sort of in hindsight on the Freeport LNG outage of a couple of years ago. As we have LNG taking up a greater percentage of the consumption, possibility of events like that seems to loom a little large. I'm just wondering what your thoughts are on that? Whether that's something that's best addressed through hedging or whether it's just going to be another sort of potential volatility in the gas market?

Yes. I think the Freeport outage is just an example of the uncertainties that exist in any market, natural gas not excluded. And the Ukraine war, who saw that happening and the positive catalyst that created on our market. I think how do we deal with these types of uncertainties. One is understand that these uncertainties will exist. And part of the way we handle that and position the business is to take a steady measured approach when we're thinking about accessing new markets. I think we certainly are the first ones to get excited. But when it comes to translating that to action, we are very strategic and very methodical on the steps that we're taking to do that. And I think you look at these uncertainties, this volatility that we're going to see in the natural gas market, we positioned our business at a very high level to be able to thrive in a volatile commodity price environment. And you can hedge, you can pay down debt, but we think the most impactful thing you can do to derisk your business is to lower your cost structure. And having a cost structure at $2 is not only going to derisk our business, it's also going to increase our exposure to higher pricing by mitigating our need to defensively hedge. So I think we're pretty good with the strategy right here, and it's just keeping the track on all the different moving parts and pieces, but that's sort of the general framework that we're deploying here.

Noel, think about how much LNG export capacity is being built just in Calcasieu Pass as an example, right? I mean that dwarfs just Freeport alone. So say there's a hurricane or a barge sinks, I mean, come up with any scenario, say that is shut in even for a month, the amount of volume that backs up in U.S. storage from just one event like that can be pretty tremendous. So when you think about LNG, I think there's certainly risk where like the pull could be to the upside. But in terms of what happens really quick, you don't expect it's probably more skewed to the downside, right? So what we're trying to do with our business, I mean, we make money as price times volume less costs, right? It's pretty simple. We want to make sure that no matter what that cost is so low that we don't have to be chasing after price, right? Because it's easy to cut production. That's what we've done right now. Increasing production is a lot harder, right? So if you run a business model where bad thing happens, you have to decline production, a significant amount to remain cash flow positive. But then when prices go up, it takes you 12 to 18 months to ramp production back up sustainably. I mean, prices don't hang high that long, right? It's a bit of a chasing after the wind. So we're trying to run our business in a much more stable way, where the downside is not really a big deal. We can still generate durable cash flow. And in the upside case, we've got the same volume times the higher price, and we don't have the huge hedge loss, right? One of the things that I think is remarkable to us when we step back and look at the last 5 years, even the winners in 2020 were the big integrated companies, right? They didn't really sweat COVID as much because they have high-quality, low-cost businesses. The winters in 2022 when you had windfall pricing about oil and gas, were again integrated because they were unhedged, right? That's why stock prices are at all-time highs. They're sitting on a lot of cash. We lost more money hedging in 2022, nearly $6 billion than the market cap we just paid for Equitrans. So just like put that in perspective and think about you go through that sort of cycle again in a world we expect to be more volatile that looks more and more like that more frequently, if a deal like this puts us in a position where we can emulate the sort of success that those bigger companies actually achieved over that time period, the amount of shareholder value unlocked by doing that is tremendous. It's a very hard thing to model, right? But in reality, when you overlay psychology and risk management coming to protect against operating leverage on top of that, that's the result that plays out. right? And so that's how we positioned ourselves. We think there's a lot more events like that, that happen again, whether it's from LNG or something else. Prices will go very low. You're seeing it this year. Conversely, all of a sudden, demand gets pulled. You have full utilization. You can drain U.S. storage very rapidly. And it will take production a little while to respond, right? So we want to be in a position where we're best able to weather the downside and capture that upside. And over the long term, that value will compound in a very differentiated way.

Great. And I totally understand your framing of the factors of data center demand growth, coal retirement. And sort of on the issue of grid fragility, I think, in particular, about the microgrid market. I was thinking back to your deal with Bloom Energy a couple of years ago for RSG certificate sales. And I just wondered if you saw similar opportunities, whether deals like that are kind of a good investment in company time, in terms of just what you can capture, in terms of sort of economics of those. So any thoughts on that would be great.

Yes. Specifically on RSG and making investments there, we think, producing clean energy and having the transparency backed up with certificates to prove that, it's going to be normal operating procedure going forward. But if your question is about power generation and partnering with power-generating companies like Bloom Energy, there's really 2 different worlds that are going to be servicing this data set, this power demand. One is going to be on the grid. And if you want to use that, get in line. You've got long queues that you need to work through to get interconnected to the grid. But this other world, which is one of the ones we're being a little bit more direct with our partnerships to bring solutions to market is behind the grid power generation solutions. That's where we can leverage our operational footprint, our existing assets, the pipelines and develop behind the grid energy solutions for customers. We think that could offer a much faster pathway to meeting their energy demands. And as I mentioned before, speed matters. And I think behind the grid solutions will be ways that we can flex some of those partnerships.

Your next question comes from Josh Silverstein with UBS.

So you provided a lot of good details on the lower breakeven price. So I just had a couple of questions there. First, I think you exclude the non-divestiture impacts. Can you give us what the pro forma numbers would be? And then just around the third-party revenues, it's big at $0.27 here. Does this change over time? Or are these under 10-, 15-year or 20-year agreements that, that should stay pretty consistent through 2030s?

Yes. So I guess, first of all, on the cost walk, I don't anticipate much of a change from the non-op sales. They are high-quality assets, but it's not going to move the needle all that much. I think there's other variables in the mix that will have a more outsized impact of that in terms of like you capturing synergies, other projects we're investing in around the asset footprint. So I wouldn't -- I think that's still a pretty good directional walk as to where we expect that to end up.

Yes. And then as far as the third-party opportunity set, yes, we look at that as a way to reduce our cost structure. Listen, we're rolling up our sleeves and understanding what the opportunity set looks like there. Like what we did when we came in here with EQT, we wanted to realize the full potential of EQT's assets. It's the same playbook being -- in mentality being applied to the E-Train assets. And one of the ways that we can realize the full potential of those assets is increasing the utilization of those midstream assets. And one of the ways that we can do that is with our own volumes, but also there's going to be opportunities where there's opportunities for us to increase utilization using third-party volumes. So that's something that we're mapping out. The leadership at EQT, that's going to be running these assets, has a track record of maximizing the utilization of our pipe systems. Just a reminder, at Rice Energy producing 2 Bcf a day gross, our midstream team was gathering almost 3 Bcf a day. So this is a part of the DNA, and it's aligned with our core strategy of lowering our cost structure.

Got it. That's helpful. And then just before just on the hedges, just going back to the prior call, I thought the view was that E-Train would now be the new hedge, but you guys have added hedges into the first half of next year, pretty similar to it looks like to what the second half of '24 is. Was it just a view of maybe some potential weakness or uncertainty this winter before you have a rising demand outlook going forward? Or is this a change in strategy over the past few months?

No, Josh, it's consistent with what we talked about before. I mean step one is deleveraging. So we need to protect the balance sheet first and foremost. By the time we get through that, we hit our targets by the end of 2025. I think you see the post 2025 hedge strategy look very different. But look, the next 12 to 18 months is all about the balance sheet, bulletproofing that plan. But in 2026 and beyond, I think you're going to see us have differentiated upside to higher gas prices in volatility.