NFG - NYSE

Hello, and welcome to the National Fuel Gas Company First Quarter Fiscal 2026 Earnings Call. My name is Harry, and I'll be coordinating your call today. [Operator Instructions] I will now hand the call over to Natalie Fischer, Director of Investor Relations. Please go ahead.

Thank you, Harry, and good morning. We appreciate you joining us on today's teleconference for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Bauer, President and Chief Executive Officer; Tim Silverstein, Treasurer and Chief Financial Officer; and Justin Loweth, President of Seneca Resources and National Fuel Midstream. At the end of today's prepared remarks, we will open the discussion to questions. The first quarter fiscal 2026 earnings release and January investor presentation have been posted on our Investor Relations website. We may refer to these materials during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, I'll turn it over to Dave Bauer.

Thank you, Natalie. Good morning, everyone. I want to start by taking a moment to recognize the fantastic job by our operations team who are braving incredibly challenging winter weather conditions. As you'd expect, our systems are holding up extremely well with minimal operational disruptions at Seneca and no significant issues on our transmission and distribution systems. Thank you to everyone for your hard work. I really appreciate it. Moving to our results. The first quarter was a solid start to the fiscal year with adjusted earnings per share of $2.06, right in line with our expectations. Our integrated upstream and gathering business continues to perform well with higher production and natural gas prices driving a 29% increase in adjusted EBITDA compared to the prior year. Our regulated businesses also delivered strong results, driven in part by our 3-year rate settlement at our New York utility and our pipeline modernization tracker at our Pennsylvania utility. Overall, we're pleased with our first quarter results, which provide a great foundation for the balance of the year. Looking ahead, the outlook for natural gas is as strong as it's ever been with demand at all-time highs. On top of that, there's a growing need for LNG feed gas and new baseload power generation, most of which will be produced using natural gas. And from a policy perspective, there is a rising tide of bipartisan support for an all-of-the-above approach to energy. Against that positive backdrop, our focus remains on operational excellence and the continued growth of National Fuel. In our Integrated Upstream and Gathering segment, we continue to expand Seneca's inventory and significantly improve capital efficiency, which is on track for a 30% gain since 2023, far outpacing our peers. Well results from our Lower Utica program in Tioga County remain among the basin's best and success in delineating the Upper Utica over the last couple of years has essentially doubled our core Tioga inventory estimate. We'll remain disciplined in how we leverage our integrated operations as we develop this region over the coming decades. Our Upper and Lower Utica co-development tests will offer critical insights to guide our long-term strategy, and Justin will speak more to this later in the call. Switching to our pipeline business. Our near-term expansion projects are progressing well. The Tioga Pathway project is moving forward according to schedule. We received our notice to proceed from FERC earlier in the month, and we will begin tree clearing in the next few weeks. Additionally, our Shippingport Lateral Project has now received all its required permits, keeping it on track for a late calendar 2026 in-service date. Beyond these 2 projects, we're seeing increasing interest in other expansion opportunities across our systems, and I'm optimistic we'll have additional projects to talk about in the coming year. Before leaving the pipeline business, one quick comment on ratemaking. Supply Corporation expects to file a rate case later this year to recover costs related to our modernization program and general expense inflation since our last rate increase 2 years ago. I'll keep you up to date on our plans with respect to timing as we move through the fiscal year. Turning to the Utility business. Yesterday, our Pennsylvania division filed a new rate case that requests an approximately $20 million increase in rates. In addition to addressing general cost inflation, the case will reset our modernization tracking mechanism, which will allow us to maintain the cadence of that program. If approved, customer bills will go up by about 11%, which is below the rate of inflation we've seen over the 3 years since we last increased delivery rates. Customer affordability has been and always will be a top priority for us. We currently have the lowest rates in Pennsylvania and fully expect we'll maintain that position after this case. We're the lowest cost provider in New York as well. The utility is in year 2 of a 3-year rate settlement that extends through the end of fiscal 2027. Even with the increases approved as part of that settlement, our delivery rates are still the lowest in the state. In fact, over the last 20 years, the rate of increase in our customer bills is well below the rate of inflation. And with a cost that's 3.5x more affordable than electricity, natural gas is unquestionably the fuel of choice for space heating in Western New York. New York policymakers are increasingly in favor of an all-of-the-above approach to energy. The state's energy plan, the final version of which was published in December, acknowledges the difficulty in meeting the targets required by the Climate Act and emphasizes the need for continued investment in natural gas infrastructure to support New York energy demand. Further, the state has agreed to delay implementation of the All-electric Buildings Act pending resolution of ongoing litigation. The delay is expected to last at least 1 year and could be permanent if the court rules in the industry's favor. We've long advocated that an all-the-above approach to energy is the most effective way to both reduce emissions and maintain the affordability and reliability of energy supplies. I'm encouraged to see policymakers begin to move in that direction. Lastly, at the Utility, we're making great progress on our acquisition of CenterPoint's Ohio LDC, which remains on track to close in the fourth quarter of calendar '26. With respect to financing, in December, we completed a well-executed $350 million private placement of common stock, which satisfies our equity need for the transaction. With respect to regulatory approvals, both the HSR and Public Utility Commission of Ohio notice filings were made earlier this month. And the National Fuel and CenterPoint teams are working closely to ensure a smooth transition for customers and employees. We're really excited about this transaction and the value creation opportunity it offers. Tim will have more details on the acquisition and our financing plans later in the call. Bringing it all together, it's an exciting time to be in the natural gas industry. National Fuel has a unique set of integrated assets in the most prolific gas region of the country. Add to that a strong investment-grade balance sheet, and we are very well positioned to help develop the resource and build the infrastructure needed to serve the growing demand for natural gas. With that, I'll turn the call over to Tim.

Thanks, Dave, and good morning, everyone. National Fuel had a great start to the fiscal year with adjusted EPS of $2.06, which keeps us on track to achieve our full year guidance. Since Dave hit on the high points for the quarter, I'll just briefly explain 2 items impacting comparability that result from our pending Ohio utility acquisition. The first relates to costs incurred ahead of the expected calendar fourth quarter closing. This is a combination of transaction-related costs, items such as legal fees and regulatory filings as well as integration readiness costs to prepare us for post-close operations. We expect that a fair amount of the integration costs can be recovered in the future, particularly those tied to the development of IT systems to replace those that will remain with CenterPoint after closing. The second item is related to financing costs. While raising permanent financing ahead of closing derisk the acquisition, there is an associated cost in the form of earlier dilution and incremental interest expense, both of which we plan to present as an item impacting comparability so investors can better see the results from current operations. Switching to the outlook for the remainder of the year, all of our previous assumptions remain unchanged. We are reaffirming our adjusted EPS guidance range of $7.60 to $8.10 or $7.85 at the midpoint. We are seeing some tailwinds that could favorably impact full year results, particularly on our integrated upstream and gathering cost structure and in-basin prices, which have improved with recent cold weather. Natural gas prices remain the biggest variable for our outlook. And if the past few months are any indication, we expect to see more near-term weather-driven impacts. For example, yesterday, the February contract settled at almost $7.50, a 140% increase from just 2 weeks ago. This was a record move in the 35-year history of a NYMEX natural gas contract. Over the same time period, we saw prices for the balance of the fiscal year as low as $3 and more recently in the $3.75 to $4.25 area. Given this dynamic, we decided to maintain our previous $3.75 assumption for the remainder of the fiscal year. Prices will likely keep moving around. And as a result, we will continue to provide earnings sensitivities at various levels. While pricing fluctuations will likely persist, our hedge book provides downside protection in 70% of our remaining production for the fiscal year, while allowing for us to capture upside to the extent higher prices persist. Within our 2026 portfolio, we have approximately 80 Bcf of collars with an average weighted floor of $3.60 and a cap of $4.75. These collars, along with our unhedged volumes provide us with exposure to higher prices on more than 50% of our expected remaining production. Looking beyond this fiscal year, we were opportunistic in the fall when the longer end of the curve moved up quickly. Across fiscal '27 and '28, we added swap layers between $4 and $4.25, and collars with weighted average floors in the high $3 area and caps well north of $5. At these prices, we are locking in strong cash flows and high returns. Switching to capital, the outlook is unchanged from our prior guidance. Collectively, with earnings, capital and cash flow in line with previous expectations, we are confident in the strength of our balance sheet, which we expect to approach 1.75x net debt to EBITDA as we exit fiscal '26. This outlook played into our decision to stay below the high end of the range of equity needed to fund our Ohio utility acquisition. As Dave mentioned, in December, we issued $350 million of common equity via a private placement. Coming out of the acquisition announcement, we had broad support for the transaction and its strategic merits. We received several unsolicited inbounds expressing interest in a transaction that could be executed in advance of our original public offering timeline. Given the strong demand, we were able to take equity risk off the table at a 2% to 3% discount to our market price at that time. This transaction took care of our expected equity needs for this acquisition. When combined with our current business outlook, we are confident that by the end of the first year post closing, we will be able to achieve the low end of our previously disclosed 2.5 to 3x net debt-to-EBITDA range. With our equity needs solved, our focus turns to debt financing. Between the remaining proceeds needed for the acquisition at closing as well as refinancing our term loan and October long-term debt maturity, we expect to issue approximately $1.5 billion in long-term debt. As a reminder, any public offering tied to acquisition financing of this size drives underwriters to require pro forma financial statements, which in turn are contingent on audited financials of the acquired asset. We expect to receive those audited financials in the next month or so, and we'll have the pro formas shortly thereafter, at which point we can begin evaluating the timing of our transaction. Sticking with CenterPoint, Dave gave a high-level update on the major work streams but I want to touch on a few more points. First, the Ohio Commission issued its final order in CenterPoint's rate case, where they modified a few key terms of the proposed settlement. First, they slightly lowered the agreed-upon ROE to 9.79%, a 6 basis point reduction from the proposed settlement. This will have a fairly small impact on near-term earnings, roughly $500,000 per year. The other action the commission took was to extend the amortization period of deferrals related to various modernization trackers from 15 to 25 years. In the near term, this has no impact on earnings but does modestly reduce cash flows. Longer term, this is actually a benefit as we will be able to earn on a larger rate base amount, which is a tailwind to our long-term earnings and cash flows. More broadly, the Ohio regulatory environment has further positive trends developing. Most notably, the Ohio Governor recently signed into law a bill that modernizes the natural gas ratemaking process. We were optimistic this would occur in the near term but didn't incorporate it into our overall valuation. The new construct significantly shortens the rate case timeline, which typically took 15 to 18 months but now is required to be completed in 360 days. It also moves from a historic test year to a 3-year fully projected test year with annual true-ups to authorized ROEs. These are nice improvements from the current approach as they minimize regulatory lag and provide greater certainty in achieving allowed returns. We remain excited about the Ohio utility acquisition. And as we spent more time with the employees that support this business, we've seen that we're not only acquiring a great asset but also a great team. Overall, the outlook for our business is as strong as ever. Fiscal '26 adjusted EPS is projected to grow 14% over last year, and the setup for 2027 is for even more growth across the organization. Our balance sheet remains strong, which provides flexibility to capitalize on further growth opportunities that may arise. Overlaying this with the broader tailwinds across the natural gas industry, and you can see why we are excited about our ability to continue to create significant long-term value for shareholders. With that, I'll turn the call over to Justin.

Thank you, Tim, and good morning, everyone. I want to begin by echoing Dave's appreciation for our dedicated employees and contractors. Your planning, communication and teamwork throughout the recent storm and ongoing extreme cold weather has been exceptional. Thank you for keeping our gas flowing and doing so safely. Turning to the quarter. Our integrated upstream and Gathering business delivered a strong start to fiscal '26. driven by consistent execution across our operating teams. Net production was 109 Bcf, an increase of 12% over the first quarter of fiscal '25. This significant production growth paired with lower capital spending highlights the strength of our Tioga Utica program and our relentless focus on capital efficiency. As we continue testing to further optimize well designs, we expect additional productivity gains in the quarters to come. We are reaffirming fiscal '26 guidance with production of 440 to 455 Bcf and capital of $560 million to $610 million. We expect capital to be relatively steady throughout the year. Looking ahead, starting in the second half of the year, Seneca will maintain its plans to operate a single drilling rig and a full-time frac crew, and gathering will ramp up seasonal construction of pipelines and other infrastructure over the summer months. The only other item of note is the timing of activity for a joint development pad, which could pull forward about $10 million of capital into fiscal '26. On production cadence, we anticipate Q2 volumes will be slightly down from Q1, in part due to till timing and deferring some activity during the recent storm. Moving into Q3, we expect production to increase and then hold relatively steady through the end of the fiscal year as we bring online some large Tioga Utica pads during that time frame. Looking ahead, we have several important initiatives underway to optimize future development. First, we are advancing our Tioga Utica well design through Gen 4 testing. This spring, a 5-well lower Utica pad featuring wider inter-well spacing and larger completion designs is expected to come online, enabling us to assess productivity and cost impacts, what we refer to as bang for our buck. In the Upper Utica, we are piloting similar larger completions to evaluate whether the improved performance we have seen in the Lower Utica can be replicated. Above ground, we are enhancing facility designs to support higher initial rates up to 40 million per day on longer laterals while minimizing incremental capital. Second, we are just beginning to flow back our first full upper and lower Utica co-development pad and have more tests planned over the next 12 to 18 months. While the Lower Utica is our current operational plan based on slightly better economic performance, our testing program is designed to confirm that view over a broader set of results and well designs. As results come in, we will preserve flexibility across both development paths and remain focused on identifying the highest returning integrated development program. Turning to Gathering. Our focus remains on supporting Seneca's volumes while adding new third-party production in Tioga County. Our near-term plan leverages existing facilities with target additions of new pipelines and compression. We are also building for the future and recently completed pad construction for the Croft Hollow station, which is located in the northwestern section of our development area. The build-out of this large centralized station and its associated pipeline network is designed to meet expected growth in both Seneca and third-party volumes over many years. Turning to the natural gas markets. Winter Storm Fern has brought very cold weather to a large portion of the U.S. and with it natural gas price volatility. We believe this kind of price fluctuation is the new normal and will persist in the coming years. Strong structural demand from LNG exports and power generation, combined with limited new storage and pipeline infrastructure supports a price environment in the $3 to $5 range with potential for weather-driven deviations lasting weeks or months. Given this outlook, we will maintain disciplined risk management practices and an emphasis on retaining upside during periods of peak demand. Our increasing future production is supported by a diversified and growing portfolio of firm transportation and firm sales. Our total firm transportation capacity will grow from 1 Bcf a day to 1.5 Bcf a day over the next few years with recently announced interstate pipeline projects and capacity releases we have secured. However, we are not stopping there and are actively evaluating opportunities to further expand our marketing portfolio. More near term, we are tactically protecting our production with roughly 80% of our remaining volumes covered by physical firm sales that link our price realization to mostly NYMEX and premium out-of-basin markets. On the sustainability front, I want to highlight a significant achievement. We recently executed a first-of-its-kind 10-year agreement to provide 250,000 MMBtu per day of MiQ certified methane reduction certificates to a European utility. This agreement reinforces Seneca's leadership in responsibly sourced gas and provides a framework for similar transactions in the future. In closing, our integrated Upstream and Gathering business entered 2026 from a position of strength, and our momentum continues to build. Our focus on capital efficiency through well-designed testing, co-development pilots and ongoing operational optimization provides us -- positions us to further enhance long-term value. Combined with our Integrated gathering assets and diversified marketing portfolio, these efforts support best-in-class margins and growing free cash flow in the years ahead. With that, I'll ask the operator to open the line for questions.

Our first question today will be from the line of

First, I just wanted to ask on if you have any ability to take advantage of local prices that have spiked over the last week or so, we've seen some of the local basis points spike into the triple digits on some days given the cold weather and the freezeouts we've seen. Do you have any ability to flow incremental volumes and take advantage of that? Just curious if you were able to benefit at all there.

Yes,

And then my follow-up, I just wanted to ask more broadly on the pipeline side. Could you talk about the potential for future growth projects in the pipeline business beyond Tioga Pathway and the Line N Lateral that you've announced. I know there's a lot of infrastructure development going on in the basin. Just curious what the opportunity set there could look like to drive further growth from the pipeline business.

Yes.

The next question will be from the line of Noah Hungness with Bank of America.

For my first question here, there is a few bills working their way through the Senate regarding federal permitting reform, a couple targeting changes to NEPA and the Clean Water Act. I was just wondering your all thoughts if those bills do end up passing, how would that change how you think of regulated pipeline projects and other projects that may be able to be greenlit?

Yes. Well, I think it would be great if they were passed both for the pipeline industry and the renewal industry for that matter. I'm not sure that it would change our view on pipeline development, right? I mean we've got a great team that runs all the traps on getting these projects developed. And for us, the permitting reform issue has generally, at least in Pennsylvania, been a question of time as opposed to whether projects get built or not. So I think the net outcome of permitting reform would be projects would get built sooner.

Great. And then for my second question, this is probably for you, Justin. How can we think about the D&C costs of the Seneca Gen 4 design? And how does that compare to some of the costs shown on Slide 50? And also, could you maybe talk about what D&C costs would look like for the larger upper Utica frac? Would that also be similar to a Gen 4 design?

Yes. Sure, Noah. So there are several things going on with the Gen 4 design that we're looking at. But if I really boil it down to, I think, the 2 biggest factors, it's a little bit wider inter-well spacing and then obviously, the upsized proppant loading and completion design going to 3,000 pounds per foot more or less. So really, the main cost that you have when you do something like that, you're pumping a little bit more fluid, you're pumping a little bit more sand and you've got a little more pump time. And so ballpark, that adds probably $150 to $175 a foot, something like that. we see in the -- we've got a couple of tests in the ground now where we did this on a pad and had a single well where we kind of tested out the Gen 4 design. We're now moving to the place where we're testing these out where all the wells on a pad are going to be Gen 4 designs to kind of see it. But we think there's a pretty meaningful uplift that is significantly in excess of that incremental cost in terms of overall pad-based IRRs and ultimately, EUR that we would get out of these wells. And so right now, we're excited to kind of see that play out. I noted in my remarks, we've got this spring, our first well that will be -- our first pad, excuse me, that will be a true pad Gen 4 design. It will come online, we expect later in the spring. And so that will be a great opportunity to really see how these wells do. I will note we already rate constrained and rate restrict all of our wells. We kind of hold them flat at around that usually 25 million, 30 million a day. And the other element, though, on Gen 4 and just generally is we're looking at facilities where we would hold them flat at up to 40 million a day. So there's a lot of things playing into that. But holistically, what I'd tell you is we think there's a lot of opportunity here, and we're going to continually evaluate is this a better economic answer, kind of balancing the increased productivity, the EUR versus the costs. On the uppers, it's a similar amount, and we're earlier in that testing. We just have less wells but it will go through kind of a similar process where we test out moving to maybe a larger completion design.

And I'm sorry, any early thoughts on the Gen 4 productivity uplift?

Yes. I would say we haven't really put in like a detail on that but that will come. But I guess what I'm sharing with you is just expect that you would take a curve where it will be rate restricted for a period but would have probably a longer flat period and then ultimately a higher EUR. And so you would have pickup, say, after you exit that flat period 6 to 12 months out, you would just be holding flat longer. So you're getting back a lot of this value nearer term. And with an increased deliverability and productivity, we may rate restrict them at a higher rate during the initial flat period.

The next question today will be from the line of Gretta Drefke with Goldman Sachs.

As you've noted, natural gas pricing has continued to be incredibly volatile. But as you think about the outlook for NFG on more of a through-cycle basis, what is the optimal production growth rate for the company over the next several years? Is mid-single-digit growth still a fair starting point? Or if we go into a less constructive gas price environment maybe over time, would you be inclined to maybe slow down some of that growth if we have to work through some periods of pricing weakness?

Yes. Thanks, Gretta. A couple of things on that. One, I would say, we feel pretty good about our outlook on gas kind of being in that $3 to $5 range. And when it's in that $3 to $5 range, we earn fantastic returns, and that's kind of just a continue on go forward. If we saw prices outside of that range and not consistently and in a forward curve or frankly, even to the high end of that range, I think we would be looking for ways to go a little bit faster. But the real governor for us is interstate pipeline capacity. So we need more -- I've talked about this in the past. We either need to see a little bit more attrition from other operators, particularly in Northeast PA, where some of the inventory there is more mature. And so we think there's a market share opportunity for us or we need new pipes, either through modernizations, expansions or new builds, that's really going to be the governor. Certainly, if we saw sustained prices below that 3% to 5%, we would be looking at ways to maybe moderate on the margin. But overall, our base plan is to continue in that mid-digit range, kind of 3% to 7% per year on average.

Great. And then just for my next question, last quarter, you announced 220 location additions in the Upper Utica zone. As you spend a little bit more time with that geology, can you speak to if there are any plans for further delineation or testing that could unlock even more locations and expand that upper Utica inventory across the portfolio?

Sure. So there's opportunity to further expand our inventory count, both in the upper, but also in the lower. And we're continuing to appraise and delineate. So we've got over 400 Utica locations between uppers and lowers that we feel really good about and have largely appraised and delineated. We think there probably is some opportunity to have upside to that as we go forward in potentially uppers and lowers. And so that's something we'll -- we will -- we've got a lot of inventory. So it's always a balance on how much money you want to put into, call it, a leading-edge appraisal well where you're moving into, say, a different fault block versus drilling the inventory you have that's very well delineated. But we're looking to kind of continue to expand our position here and grow to have as many future development locations as possible. And so I think we'll find ways to do that. We have a lot of lot of smart people in our subsurface teams that are working through this, and we'll be testing some areas that expand potentially the boundaries of our current well-delineated 400-count upper and lower locations today.

The next question will be from the line of Tim Schneider with the Schneider Capital Group.

So most of my questions have actually been answered. So I'll follow up on a comment that I think Justin made in terms of volatility expected to stay here in natural gas markets. So as you kind of look at that, what do you think going forward alleviates that issue? Is it more steel in the ground, either via pipelines or storage? Or is there something else that needs to happen as well?

Yes. Tim, this is Dave. I think it's more steel on the ground, right? I mean you look at gas prices and electric prices in the Northeast are just incredible this past week. And the easiest way to get that down, whether it's gas or electricity is building more pipeline infrastructure. And we've got the resource without question. By using more of it, we can damp down a lot of that volatility.

Got it. And obviously, putting in steel storage, whatever is a lot tougher in the Northeast than it is in other parts of the country. Have you guys looked at rates that it would cost that you would need in order to put new storage assets in the ground in the Northeast to the extent that is even possible?

Yes. And we have looked at that. It is quite high. Our focus is on optimizing our existing storage facilities, right? So either drilling, say, horizontal wells or doing other things that can either increase the amount of gas we can get downhole or improve the deliverability rates that we see when we're bringing gas out.

And then lastly for me, can you remind us what percentage of your storage is merchant versus kind of contracted?

It's 100% contracted. Under straight variable rates.

[Operator Instructions] The next question today will be from the line of John Freeman with Raymond James.

Just following up on the Upper Utica topic. Justin, have you determined sort of like what's the appropriate sort of co-development type strategy going forward? I assume there's been some testing, maybe wine rack type, maybe there's some others. Just kind of where you are in that process.

Yes, John, thanks for the question. So we think about it a lot. Right now, our base development plan, what we think about is to go with a lower Utica development first because it has a slightly better economic edge. That being said, we really want to challenge that thesis and that result. So what we're doing is literally here right now, we're going to begin flowback on a true co-development Upper, Lower Utica pad. We've got another one planned for later this year. And we're going to take that data and that information and really use it to assess the right development plan. And as I mentioned, our lean right now is towards go ahead and do the lowers initially and come back and do the uppers in time. But we don't want to just make that assumption. And so we're keeping our options open. We've got the ability to pivot to go one way or the other but we want to be led and informed by data and results. And so that's what we're in the process of doing, and we'll be doing so over the next kind of 12 to 18 months before making a conclusive decision.

Got it. And then just kind of a bigger picture question. There's been a healthy amount of upstream sort of M&A by some of your peers over the last like 6 months. I'm curious if you all's M&A focus will remain on more of the regulated businesses or following CenterPoint closing, if we could see maybe a shift of M&A focus back toward whether it's upstream or just your unregulated businesses.

Yes. John, I mean you're right. Going into CenterPoint, we were focused on the regulated side of the business, and we're able to do a great transaction. I'd still like us to be a bigger company. And I think the CenterPoint deal kind of rebalances the company a bit and it gives us the flexibility to look at transactions on both the regulated and nonregulated side of the business. I don't know that I'd say that I have a particular priority one way or the other, other than to invest capital in ways that get the best returns for our shareholders.

The next question will be from the line of Jeff Bellman with Daniel Energy Partners.

I had 2 questions. First question, Justin, just on the frac barrier between the upper and the lower, how variable is that? Or is it not? And just kind of an assessment of how that frac barrier looks across your acreage? That's my first question.

Yes. At a big picture level, what I would share with you is that this is a regionally unique feature that we have due to some series of or singular seismic event that happened several hundred million years ago. The thickness, we've got really good well control and understanding of the thickness of that seismic barrier across our acreage position. It does vary in the depth -- excuse me, in the size of it, but the overall characteristics of that largely impermeable barrier is consistent across our acreage from everything we've seen. So we think it's -- everything we've delineated in the uppers and you can see, and we've tried to provide a map in our latest IR deck, you can just get a sense of the areal extent of our testing. We feel like it's a very effective barrier across that position that we fully delineated.

Great. Second question, can you guys speak a little bit more broadly just in terms of -- you kind of touched on a little bit, just incremental takeaway industry-wide out of the basin. I hear some comments about kind of more gas that can move west out of Pennsylvania to Ohio, a lot of data center development there. Just broadly speaking, what's your sense on kind of brownfield takeaway out of the basin going west? And maybe if you have any view on volumes going south?

Sure. Well, I'd say, I mean, for the first time in a while, there's actually projects that are kind of happening more, right? So there are -- within the basin, I would put it into a few categories. I mean the brownfield is happening. I mean that's this new capacity that Seneca has signed up for that will go in service in 2028 is a good example. The Tioga Pathway Project that supply -- National Fuel Gas Supply is building this year that will serve Seneca is another good example. So a combination of brownfield and quasi-greenfield kind of intra-basin or moving a bit out of basin but to more premium markets. That's great. I think the potential for really big greenfield pipe is still pretty challenged. We're really encouraged with the news out of both FERC and New York that seems to have greenlit NEE getting built. That's also a very important project for us specifically because we move a lot of our gas through our Atlantic Sunrise and Leidy South capacity. exactly into that market, and this will create a new significant pull on demand and should further support the pricing there. And then there is the in-basin demand. I mean there's been a number of significant power gen and/or power gen data center-related projects that have been announced and that are in various stages of construction. So that will keep growing the demand. So I think it's kind of all those things. And the last one I would put in there is that we think there's still a big opportunity, particularly for some of the very large interstate pipelines that have -- that move well out of the basin you can pick on different names, whether it's a Transco or Tennessee or others, where they likely have some real opportunities to further debottleneck their pipe by doing some minor modernizations or compression adds even beyond in the basin that could free up more gas to get out of Appalachia. And I think, as Dave said just a minute ago, what we need is more steel and more takeaway in order to help dampen some of this volatility. And so those are the very projects that could really help do that. And frankly, our position at Seneca and NFG Midstream is well interconnected to where that takeaway would start. So we're watching it closely. We're participating in it through the projects we're doing, and I'll call it, cautiously optimistic we'll see more of that.

Thank you. This will conclude today's Q&A session. I will now hand the call back to Natalie Fischer for closing remarks.

Thank you, Harry. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available this afternoon on both our website and by telephone and will run through the close of business on Thursday, February 5. Please feel free to reach out if you have any follow-up questions. Otherwise, we look forward to speaking with you again next quarter. Thank you, and have a nice day.