EQT Corp Q1 FY2024 Earnings Call

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. 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 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, will drive an incremental 10 Bcf per day of natural gas demand by 2030, with a plausible upside case that could take this number up to 18 Bcf per day. This means growth in the power generation segment that exceeds 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 Zones 4 and 5 price points. Due to the confluence of LNG facilities pulling gas South on Transco and power demand growth in the Southeast, we expect this region will become even more desirable than the Gulf Coast later this decade. As a result, we intend to pursue an expansion of MVP through additional compression to increase capacity from 2 to 2.5 Bcf per day, which will provide additional affordable, reliable, and clean Appalachian natural gas to our downstream utility customers. On top of the tremendous opportunity to service customers in the Southeast, where we already have first-mover advantage through our record-sized physical gas supply deals with utilities we announced last fall, EQT is ideally situated to meet significant growth in power demand within PJM as well. Our analysis suggests the combination of data center build-outs and additional coal retirements could generate up to 6 Bcf a day of incremental natural gas power demand in our own backyard by 2030. Whether it's in the Southeast or at the doorstep of our asset base in Appalachia, EQT is well positioned to capture this thematic tailwind through our material inventory depth and integrated business model that will create a one-stop shop to provide clean, reliable, and affordable natural gas that will be foundational to meeting America's power needs as we embark on what will be a transformational journey into the age of AI. Turning briefly to first quarter results, the significant operational momentum we achieved last year has carried into 2024, which facilitated better-than-expected results across our drilling and completion teams in Q1. The continuation of highly efficient operational execution, along with strong well performance and lower-than-expected LOE, associated with our water infrastructure investments drove outperformance relative to consensus expectations across every major financial metric during the first quarter. We continue to find new innovative ways to push the envelope of what is possible and I want to thank our entire crew for their relentless pursuit of operational excellence. Shifting gears, last week, we announced an agreement with Equinor to sell a 40% undivided interest in our nonoperated natural gas assets in Northeast Pennsylvania. Consideration is comprised of $500 million of cash and upstream and midstream assets worth more than $600 million, implying EQT is receiving total value north of $1.1 billion in this transaction. For perspective, we attributed approximately $1.1 billion of value to 100% of the Northeast PA non-op assets when we originally acquired them as part of our Alta acquisition. And the assets have already generated free cash flow in excess of that amount in the past two years. This transaction marks an incredibly successful outcome for shareholders and a strong start to our deleveraging plan. The upstream assets we are receiving include approximately 26,000 net acres in Monroe County, Ohio, directly offsetting EQT-operated existing core acreage in West Virginia. We are also receiving an average working interest of 14% in more than 200 producing wells that EQT currently operates in Lycoming County, Pennsylvania, along with a 16.25% interest in the EQT-operated Seely and Warrensville gathering systems servicing this acreage. Following the closing of this transaction, EQT will own 100% of the Seely and Warrensville gathering systems, which aligns with our strategy of lowering cost structure via vertical integration. I'd also note our teams have identified significant operational synergy potential across the operated assets as well as longer-term upside associated with the liquids-rich Marcellus in Monroe County. The nonoperated assets we are selling have forecasted 2025 net production of approximately 225 million cubic feet per day, while the operated assets we are receiving have forecasted 2025 net production of approximately 150 million cubic feet per day. Comparing to $1.1 billion of total value to the 225 million cubic feet per day of total production we are selling implies a roughly $4,900 per Mcf flowing production multiple. While looking at metrics using net divested production and comparing this to the $500 million of cash consideration equates to roughly $6,700 per flowing Mcfd production multiple. We believe these attractive transaction metrics speak to the value of the high-quality natural gas assets, which are increasingly being coveted by international buyers looking to get exposure to the U.S. natural gas market. This transaction highlights that we are wasting no time, jump-starting the deleveraging plan we laid out with the Equitrans announcement and creating additional shareholder value in the process. The sale of our remaining 60% interest in these nonoperated upstream assets and the option to monetize regulated or noncore midstream assets at Equitrans gives us tremendous confidence in our ability to achieve our debt repayment goals, and we look forward to updating the market as we make additional progress on this front. To sum up, first quarter results demonstrate a continuation of peak performance at EQT. Our announcement of the Equitrans acquisition is a once-in-a-lifetime opportunity to vertically integrate one of the highest-quality natural gas resource bases in the world, creating a one-stop shop to provide natural gas that will meet the growing data center and power generation needs at the doorstep of our asset base. And our recent transaction with Equinor illuminates significant hidden value embedded in our nonoperated natural gas assets and gets us off to an extremely strong start towards achieving our deleveraging goals.

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, we retired all of our outstanding convertible notes, which eliminated $400 million of absolute debt over the past two 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 used 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 with 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 two to three 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 in our updated outlook on the heels of Equitrans' filing for in-service with the FERC this week. This represents a meaningful milestone as MVP's 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 being free cash flow negative at this price deck. At the same time, free cash flow in an upside price environment is projected to be a staggering $26 billion. 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 in 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. 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 investors who are structurally bullish on natural gas long term and we look forward to demonstrating this differentiated value proposition for shareholders as we navigate the volatile world ahead.

Your first question comes from the line of Neil Mehta with Goldman Sachs.

This is Ati on for Neil. Guys, I'd be curious about 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. 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 would anticipate the remaining sale of that interest to be in cash consideration as opposed to a more complex kind of mix of assets and cash.

Got it. I appreciate that. As you consider the current supply and demand situation for natural gas in the U.S., you mentioned that you will extend the cuts. What is your perception of the production response based on the latest figures? Is there a sense of sufficiency? Do you believe further cuts are necessary? Also, how should we understand your approach to reintroducing production?

Yes. We believe that other operators will continue to show cuts and discipline. However, many are watching closely for potential weather impacts. A typical summer could help reduce the excess storage we have. Additionally, low gas prices are likely to boost power demand. We see a couple of catalysts on the horizon. Until these factors materialize, we anticipate that operators will remain patient.

At a high level, considering the macro outlook, approximately 400 Bcf a day was added to storage due to winter weather, and an additional 200 Bcf came from production exceeding forecasts. This results in an oversupply of about 600 Bcf that needs to be addressed by around October. Market mechanisms will facilitate this resolution through supply limitations and increased demand from coal to gas switching. Constructive summer weather could provide a boost as well. To maintain market balance during the summer, it is likely that prices will remain low and not rise significantly. However, after October, we anticipate a rapid increase in LNG demand, which is expected to shift the market.

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 Zones 4 and 5 South lines. I was wondering if you could give us just your general thoughts on how differentials may play out in the Appalachia Basin over time and specifically highlight your leverage to these two zones?

Yes, Arun. So look, I'd start with going back to those physical gas sales deals that we announced in Q3 and Q4 last year. And if you look at how that was structured, we tranch that out across those markets. 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. That sort of keyed us off to a lot of the demand and the tailwinds that are really coming that the utilities are seeing. The premium being paid is to lock in reliability of supply. That said, 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 or data center growth.

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. 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.

We were encouraged by Governor Shapiro's remarks on natural gas, highlighting both the potential for increased power demand and his stance on the LNG pause, which he described as ill-advised. Governor Shapiro recognizes that the people of Pennsylvania understand the vital role of natural gas as the economic driver of the state's economy and its importance in decarbonizing our energy grids. Pennsylvania exemplifies how significantly emissions can be reduced by switching from coal to gas and underscores the potential for a similar impact globally. Many are unaware of the substantial power generation capabilities of Pennsylvania, which boasts the lowest cost and cleanest natural gas in the country. This positions us to consider expanding electricity exports to other states. Observing the Northeast, many have invested heavily in offshore wind, yet we frequently see setbacks with those projects. The dependable option remains the demand for natural gas, and we are committed to ensuring that it continues to provide Americans with affordable and 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 the non-op side of things.

Net to the non-op interest, there is approximately 10 to 15 billion included, and the remainder consists of operational deferrals that are a direct result of our decisions.

Okay. Great. And then the second question, I think our work would help us agree 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. I believe what makes MVP unique is that EQT currently owns 60% of the pipeline's capacity and we are the sole producer shipper on it. There are no other producers accessing that market via MVP. The remaining 40% is owned by utilities at the other end. This gives us a unique position. The expansion will undergo a FERC open season, determining who receives that capacity through a regulated process. We feel well positioned to benefit from this, regardless of the outcome. The expansion creates value not only for us but also for the utilities by providing them with new gas in that market. We are all aligned in wanting this to happen. Even if we do not secure the capacity in the auction, we still gain from being able to sell more gas, allowing producers in Appalachia to sell more to the utilities on the other end of the pipeline. Ultimately, it presents a significant 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 consider it as cash cost plus finding and development costs. We aim to recover the sunk costs associated with drilling the well, which is why we approach it this way. It varies depending on the area, but generally, it's about $1.50 in the basin.

Okay, Jeremy, it seems like you anticipate a significant price increase by October. If the price remains at $1.50 through the summer before that increase, would that indicate that you are likely to continue the curtailments into 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 two things?

We have a significant amount of flexibility. When considering the non-operational asset sales, the $1.1 billion value we mentioned from our work with Equinor suggests that the entire package could be valued around $2.75 billion. If the rest of the assets are sold for cash, it could generate between $2 billion and $2.5 billion coming in. This already covers about two-thirds of the $3.5 billion asset sale target we set a month or two ago with the Equitrans deal. Therefore, we don't necessarily have to sell many assets on the Equitrans side if we choose not to. This situation offers us a lot of options. Looking at other transactions in the market, TC Energy recently made an intriguing deal with GIP for assets of lower quality than MVP at around 11 times EBITDA. Similarly, BlackRock completed a transaction with Portland Gas also at about 11 times EBITDA, again for lower quality assets compared to MVP. Regarding Equitrans' overall regulated assets, we estimate it to be about a $7 billion value. We have the option to sell some of these, or we could sell a minority interest while keeping control and operations. There are numerous ways to approach this, and we are currently exploring these options. I am very confident that we can achieve a solution that retains our flexibility both in the short and long term while effectively reducing our debt in a timely manner.

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, we have a lot of options and that means we will keep our focus on value in these matters. There is significant interest here, which boosts our confidence in executing this plan. Looking at the Equinor transaction, we anticipate receiving strong values for these assets.

Yes. If you consider the timeline suggested by the rating agency, it indicates around 12 to 18 months after closing. We anticipate closing to be around Q4. Therefore, our target is to complete the deleveraging plan by the end of 2025. Many of us believe that the gas market in 2025 will be significantly stronger than it is now, so we are adopting an opportunistic approach. We have strong momentum currently, and I am optimistic that we can achieve favorable outcomes in the near term. However, if circumstances change and we decide to wait an additional 6 to 9 months, we can do that to ensure 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 non-binding, 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 to ensure we get the terms that we need.

Got you. This is a bit of an uncertain question, but is there any possibility that the demand from data centers could lead you to reduce your focus on LNG? Are there competing factors at play, or are you just looking at two positive outcomes?

Yes, it's certainly another dynamic that we're putting into consideration. And when we step back and we look at the opportunity to service 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's 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. It's crucial to keep in mind that these LNG deals are long-term agreements. From 2015 to 2020, when the U.S. started exporting LNG, the market conditions were actually unfavorable. We anticipate that, in the long run, LNG will serve as a strong positive factor and add significant value. However, if too much LNG is secured during a period when market conditions are poor, it can resemble an expensive pipeline contract and lead to complications. We've seen this occur in the last decade, so we're taking a cautious stance. When we compare LNG to data center demand, the trends within data centers are expected to generate more stable, ongoing demand that isn't influenced by market fluctuations. This stability is a focus for us as we plan for the long term. We will have exposure to both LNG and data centers; in different periods, one might perform better than the other. Nonetheless, we are pleasantly surprised by the growing demand in data centers, and our excitement continues to increase as we learn more about it.

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 America's 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, there's a new dynamic that's becoming quite prominent. Everyone wants energy that is affordable, reliable, and clean, particularly for data centers where reliability is critical. Another important factor is speed. Natural gas is the only energy source with a proven history of meeting various demands in the U.S. Speed is crucial, and there are several factors that will enable natural gas to quickly meet this new demand. First, we can utilize existing power infrastructure since natural gas power plants are operating at only about 60% capacity on average. This underutilized capacity represents an opportunity to boost natural gas demand in the short term. Additionally, it's essential to consider the challenges of building new infrastructure. For instance, a natural gas operation needs about 20 acres and will require various permits, whereas solar installations might need 3,000 acres and wind might need 5,000 acres. This highlights that leveraging natural gas is likely the best and fastest way to meet new energy demands.

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 two 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. 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 and 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 have a couple of questions. I'll start with a broader question related to the curve you've been discussing. I'm curious about your reflections on the Freeport LNG outage from a couple of years ago, considering how LNG is becoming a larger part of consumption. The likelihood of similar events seems to be a significant concern. I’d like to know your thoughts on this—whether you believe it's best managed through hedging or if it's just going to introduce another form of 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 to 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 track of 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 things happen, 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. One of the things that I think is remarkable to us when we step back and look at the last five 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 for 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 put that in perspective and think about what happens if you go through that sort of cycle again in a world we expect to be more volatile and 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. 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 two 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 the 2030s?

Yes. Regarding the cost analysis, I do not expect significant changes from the non-operational sales. While they are high-quality assets, their impact will be minimal. There are other factors that will have a greater effect, such as capturing synergies and other projects we are investing in around the asset footprint. Therefore, I believe that still provides a solid indication of where we anticipate things 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 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 are 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.

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