Antero Resources Corporation

Greetings and welcome to the Antero Resources Third Quarter 2025 Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to your host, Dan Katzenberg, Director of Investor Relations. Thank you. You may begin.

Thank you for joining us for Intero's third quarter 2025 investor conference call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.interoresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President, Brendan Krueger, CFO, Dave Canalongo, Senior Vice President of Liquid Marketing and Transportation, and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'd like to start on slide number three titled Antero Strategic Initiatives. We are entering an exciting time period for the natural gas market. Rarely have we witnessed such a visible step change in demand. This significant demand growth is driven by increasing U.S. LNG exports combined with the surge in natural gas power generation that is accelerating from the build out of new data centers. Antero is poised to benefit from these structural demand changes through our long-term vision and recent strategic initiatives, which includes adding to our core Marcellus position in West Virginia. We accomplished this through both bolt-on transactions and continuing our organic leasing program to increase our position in the West Virginia Marcellus fairway. Returning to West Virginia dry gas development, to highlight our ability to quickly respond to the regional demand that is beginning to show up in Appalachia. We can either supply directly into future demand projects or grow into the local market if the local basis tightens. Also use hedging as a tool to lock in attractive free cash flow yields to support our dry and lean gas development program and our efforts to be counter-cyclical in transactions and share repurchases. We believe the execution of these strategic initiatives will enhance our ability to capitalize on the significant demand increases that are expected for natural gas over the long term. Now let's turn to slide number four, which highlights our third quarter operating results. Continuing our trend of improving our drilling and completion results, the third quarter was our most impressive operating performance to date. We set numerous company records and achieved significant progress. The right-hand side of the slide highlights the various company records 5,000 feet. On the completion side, our completion stages per day continues to climb higher, averaging another quarterly record at 14 and a half stages per day, or 2,900 feet per day. And as Patterson UTI highlighted on their call last week, we set what we believe to be a world record for continuous pumping hours, 15 days of nonstop pumping hours, a truly remarkable feat. Next, let's turn to slide number five, titled Marcellus Core Fairway Expansion. Our additional land investment is driven by the ongoing success we are seeing from our development plan and on the ground from our organic leasing effort. Strong well performance continues to expand our view of where the Marcellus Core boundaries extend. The map on the left of this slide depicts what we believe to be the Marcellus Core at the time of our IPO in 2013. As you can see, we built our position focused on Doddridge and Harrison counties which we believed would deliver the best drilling results. However, over the past decade as our development focus shifted into the neighboring counties and our well performance continued to strengthen, these results have driven an increased organic leasing program into those counties. And Terra's organic leasing efforts have been a tremendous success over the years. We continue to acquire acreage at attractive levels per location with the incremental locations more than offsetting our annual turn in lines. Further, this program allows us to maintain our development focus in close proximity to our current footprint, reducing geologic risk while leveraging the benefits of Ontario midstream. Now, to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Canalongo, for his comments.

Thanks, Mike. Several market trends are pointing to improving NGL fundamentals and higher prices in the coming quarters. Following several years of substantial year-over-year supply increases, multiple third-party data providers are forecasting a slowing of NGL production growth across the U.S. due to the current low oil price environment and sharp reduction in oil-directed rig counts. Subdued drilling activity in oil basins will have an impact on associated rich gas and NGL production 3-plus supply. As shown on slide number 6, titled USC 3-plus supply growth slows, the chart on the left shows projected NGL supply growth in the Permian slowing down dramatically in 2026 compared to previous years. At the same time, the chart on the right shows total USC 3-plus production growth in 2026 is nearly flat, with only 11,000 barrels a day of incremental supply expected. This indicates that while the Permian should continue to rise, albeit at a slower rate, this increase is being offset by even slower growth or outright declines in less economic Tier 2 producing regions, including the Bakken, Rockies, and Mid-Continent. The declining expectations for C3 plus supply growth comes at a time when exports from the U.S. are now able to ramp up aided by a de-bottlenecking of terminal capacity. Year to date, propane exports have increased by over 120,000 barrels a day, averaging 1.85 million barrels a day compared to 1.72 million barrels a day for the same period last year. This increase occurred despite current global trade uncertainty, illustrating the continued call on U.S. barrels. At the same time, LPG export terminal expansions have started to come online beginning this summer, and ample export capacity will be available for the foreseeable future, as shown on slide number seven, titled New Capacity to Ramp Up Exports. Going forward, unconstrained dock capacity will allow U.S. barrels to efficiently clear the market and bring mock Bellevue prices as close as possible to premium international LPG prices. In the past, Santero has often benefited during times of U.S. Gulf Coast terminal constraints, with our ability to export barrels out of market so it can capture high DOC premiums. The ability to execute this strategy has served as a differentiator for Intero versus almost all other NGL producers in the U.S. However, it is important to remember that Intero benefits more from higher Montbelvi prices than from high DOC premiums. This is because higher Montbelvi prices lift both our export sales and all of our domestic sales. the latter of which are exclusively priced on a Mott Bellevue index. Antero on average exports less than 45% of its gross C3 Plus production and sells the remainder of its C3 Plus volumes in the domestic market. Therefore, an uplift in domestic sales prices is much more impactful for Antero's NGL realizations. In conclusion, the key challenges of 2025 all trend in our favor moving forward as reduced producer activity combined with higher export capacity and international demand pool is expected to bring propane storage inventories from the top of the five-year range to near the five-year average by early 2026. These fundamentals will support Montbelvi prices in 2026 and strengthen C3 plus prices as a percentage of WTI. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Thanks, Dave. As we approach winter, we see seasonal and overall positive fundamental demand trends coming for natural gas. I'll start on slide number eight, titled TGP 500L Basis Strength. LNG export demand is expected to increase by 4.5 BCF, from the beginning of 2025 to exit 2025. This increase is almost entirely due to the successful and quick ramp up of the Plaquemines LNG facility. This week, the facility achieved a new daily record for feed gas at approximately 3.9 BCF per day. With the first 18 trains now complete, Venture Global will begin Plaquemines II, which will increase the capacity by an incremental 2.4 BCF per day, with the first phase in 2026 followed by the second phase in 2027. The significant demand pool for this LNG facility has led to higher demand along our TTP 500L firm transport path and has driven a higher premium at that delivery point relative to Henry Hub. Looking ahead to the winter, this premium to Henry Hub has increased to nearly 80 cents, and in 2026, the premium is now at 64 cents for the full calendar year, the highest level seen to date. As a reminder, approximately 25% of Antero's gross natural gas is sold at the TGP's 500 pricing hub. Our exposure to TTP 500L is expected to lead to higher natural gas realizations. Slide number nine takes a closer look at the significant natural gas demand surge that is coming over the next 24 months from the new LNG capacity additions. Over this short period, LNG demand is expected to increase by another 10 BCF per day, driven by the startup of Plaquemines II, Golden Pass, Corpus Christi III, and Calcasieu Pass II. These new LNG facilities are expected to continue to drive higher price premiums along the LNG fairway hubs, where we sell 75% of our natural gas. In addition to the substantial LNG demand growth, Power demand is also expected to increase significantly over the next five years. The map on slide number 10 illustrates all of the competition for natural gas supply in our development region and down our firm transportation corridor. Based on announcements that have been made to date, regional demand is expected to increase by 8 BCF per day. As Mike has discussed in the past, Ontario has 1,000 gross dry gas locations that we could accelerate activity on if there is a regional call for higher supply. Along our firm transportation fairway, there has been more than three BCF of power demand projects announced to date. Additionally, there is an incremental 13 BCF per day of expected demand between LNG facilities and power projects announced along the LNG Gulf Coast Fairway. All of these projects will be competing for natural gas supply that could face supply challenges in that short timeframe. Antero is uniquely positioned to participate in each of these three regions with our ability to increase dry gas activity for local demand or use our firm transportation portfolio to access increasing demand all the way down to the LNG fairway. With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. Our capital efficient program that Mike highlighted resulted in an attractive free cash flow of over $90 million during the quarter. Year to date, we have generated almost $600 million of free cash flow. Slide 11 highlights the uses of our 2025 free cash flow. Year-to-date, we have paid down debt by approximately $180 million, purchased $163 million of stock, and invested $242 million in asset acquisitions. We believe this portfolio approach to uses of free cash flow will drive attractive shareholder value creation as we continue to compound this effort going forward. As we've proven historically, we will be disciplined in our transactions. The transactions we completed during the third quarter were accretive to the key metrics that we prioritize, including free cash flow and net asset value per share. Importantly, we were able to fund this activity entirely with our free cash flow in 2025 and therefore did not have to issue equity at today's levels in our financing efforts. Now let's turn to slide 12 to discuss our updated hedge program. During the quarter, we added natural gas swaps for the fourth quarter of 2025 and full years 2026 and 2027. We also restructured our wide natural gas collars for 2026, raising the floor brace. As Mike touched on during his comments, these hedges support our strategic initiatives. We have now hedged 24% of our expected natural gas volumes in 2026 with swaps at $3.82 per MMBTU and 28% with wide collars between $3.22 and $5.83 per MMBTU. Our hedge book allows us to protect the downside by locking in a portion of our free cash flow yield. This is illustrated on slide number 13, titled Reduced Cash Flow Volatility. Our hedges have locked in base level free cash flow yields of 6% to 9% at natural gas prices between $2 and $3, while at the same time we maintain significant exposure to rising natural gas prices. Further, these hedges result in a 2026 free cash flow breakeven at just $1.75 for MCF, assuming year-to-date NGL prices. Looking forward, our return of capital and transaction strategy is anchored by our low absolute debt position that provides us with substantial flexibility to pivot between accretive transactions in our core Marcellus West Virginia footprint, debt reduction, and share re-purchases. We will continue to evaluate accretive opportunities to increase our net production and core inventory while importantly waiting to increase gross volumes until the broader natural gas market calls for it. While we continue to target maintenance capital, we are well positioned with substantial dry gas inventory for future growth opportunities from the regional demand increases that are expected. With that, I will now turn the call over to the operator for questions.

Thank you. And ladies and gentlemen, at this time we will conduct our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we pull for questions. And your first question comes from Arun Jayaram with JP Morgan. Please state your question.

Yeah, good morning. Gentlemen, I wanted to maybe start with the decision to commence DNC operations on the gas side in Harrison County. I was wanting to know if you could talk about what the catalyst was for that kind of decision. And, you know, did data centers, power deals down the road, did that play into kind of the calculus about, you know, doing something you hadn't done in 10 years or so?

Yeah, that's exactly kind of the catalyst. We've been active in those discussions and it became clear to us all those discussions really related kind of the eastern portion of our acreage position and where those opportunities would be located, also where the local demand is. And so we thought, looking at our position, we have 100,000 acres, we have significant historical activity there. We have the midstream infrastructure, so we have a proof-of-concept pad. It's already a pad that exists with wells going south, so it's still north, and it'll be very low-cost wells and highly productive, and we're excited to get back at it in the Harrison County area.

Got it. And then maybe my follow-up You know, just given Mike this, you know, doing a little bit more kind of gas drilling, thoughts on, you know, how you're thinking about a 2026 program at Entero and, you know, obviously historically around this time you've decided to do a drilling partnership, which has defrayed some of the costs. But what is your thinking around 2026 at this point? Understanding it's still probably early in the budgeting process.

Yeah, it's still early, but we're still at maintenance capital around. This is just one pad. Really, the fourth quarter production level, we're in the 3.5 to 3.525 range. That's the level we'll hold generally in 2026. So we're still there. This is just more of a proof of concept pad. On the drilling JV, that's still to be determined. We'll see where kind of the market is related to that, and we could continue that in 26, but we haven't made that decision yet.

All right, great.

I'll turn it back. Your next question comes from John Freeman with Raymond James. Please state your questions.

Just a follow-up on a range question with the following, you know, the acquisitions and the higher production level now that you cited that you're going to have in 4Q. Just kind of how does that impact kind of the prior commentary about maintenance capex? I just think previously you kind of talked about kind of flattish capex to maintain production. Just wondering if this has an impact.

It is at the same ratio that the increase, you know, the production increased by 3%. So it's logical to expect a 3% increase in your maintenance capital. So that's like an incremental $20 million from that $675 million level.

Got it. Thanks. And then looking at the acquisitions, the $260 million of acquisitions in the quarter, Just trying to get a better feel for if this is now kind of a bigger focus of the company or it was this sort of kind of one-off in nature and just you happen to have all these sort of transactions domino during the quarter. Just kind of how to think about that going forward.

Yeah, I don't know if it's a bigger focus. I just think with our position in the West Virginia Marcellus, these type of transactions come to us and are available to us if, you know, they make sense at the time. When you look at our acreage position, the contiguous nature of it, we are the liquids developer in West Virginia, and so we get opportunities from time to time, and so we evaluate them, and these ones made sense.

Thanks, Mike.

Yep.

Your next question comes from David Deckelbaum with TD Cowan. Please state your question.

Thanks for taking my questions, guys. Mike, I guess as we get into 26, you know, obviously you guys just drilled a record lateral length, and we saw the impacts to the average lateral length in the quarter. I guess just given some of the land spends that you have this year, how do you see that progressing on average into 26, given that you guys have had some pretty significant efficiency gains to date?

Yeah, no, it actually goes up. You know, it's a good – I think it goes up to 14,000. I think we're generally around this year in the low 13,000. Next year's up 1,000, but you highlighted the very efficient nature of our leasing program. David, that's exactly what it's doing. It's trying to optimize those lateral lengths and also expand our position. So next year's up about 1,000 foot per well.

Yeah, I guess I appreciate that color, Mike. My follow-up is just... We saw, obviously, the acquisition this quarter. It looked like it was an increase in existing working interests, which I guess is, you know, I don't know if you would view that as aberrational or if you view this as a trend that likely continues, perhaps, into next year.

I don't know if we'll have those opportunities. It was three separate transactions, all with working interests. Another one's royalty interest, another one with more acreage-based transactions. So hopefully they continue in the next year, but it's hard to forecast. But like I mentioned, we have such a dominant position in this area of the Marcellus. These type of transactions tend to be available to us if they make sense and if they're accretive.

Appreciate it, guys.

Your next question comes from Kevin McCurdy with Pickering Energy Partners. Please say your question.

Hey, good morning. The hedges you added this quarter were unlike past quarters in that you aggressively hedged the next quarter or fourth quarter in this instance, and you opted for swaps for next year instead of the wide collars before. Has your strategy on hedging changed or was this just opportunistic and should we expect you to have a certain hedge level heading forward from here?

I think it's probably both. You know, if we could replicate what we have next year where it's These are approximate numbers, a quarter with white collars protecting at $3.25 with exposure up to six, and a quarter in that high $3, $4 range, and then 50% unhatched. That's actually a good model for us. I don't know if that will be available going forward, but that's a good level for us when we looked at the program. As Brendan mentioned in his comments, the ability to lock in above 5% free cash flow yields I think it's 6% to 9% in the $2 to $3 range, but then expose ourselves completely to the upside up to a 20% free cash flow yield. You know, that feels like a prudent way to manage the business.

I appreciate the color there. And then as a follow-up, ethane volume significantly outperformed on price and volume this quarter. Was that just due to sales timing or is there any sustainability to that beat?

Yeah, Kevin, this is Dave Cantalongo. Really just a function of customers and when they're up and running and taking full volumes. And then also our spreads into the Gulf Coast on ATEX have been improving here in the back half of the year. So just taking advantage of our capacity on that system.

Great.

Thank you.

Your next question comes from Philip Jungwirth with BMO Capital Markets. Please state your questions.

Thanks. Good morning. On the dry gas acreage in Harrison County, there's been a lot of operational improvements and advancements in drilling and completion technology since you last drilled here. So I was wondering if you could talk to your expectations as to how much of an uplift you'd expect versus kind of the historical type curves from the wells that you had drilled here previously.

Yeah, we expect about a 50% improvement. The old wells in that area was more like 1.3 BCF per day, but with After 12 years, we've gotten a lot better at it. I think we have approximately 1,500 wells now, and those are one of our first. We're excited about optimizing the completion of those wells. It was 1.3 BCF per day. My expectation is 2 BCF per thousand foot now.

Okay, great. And then I wanted to come back to something you referenced last quarter. But with your water systems, I was wondering if you could expand upon the data center cooling opportunity for Entero Resources and Entero Midstream. Just what would this look like and how would you look to play a role?

Yeah, I think just to build on what we said last quarter, you know, we think we are well positioned and uniquely positioned. Having that upstream-midstream integration being Fifth largest gas producer in Appalachia. We've invested about $600 million or so in the water system. So that provides Appalachia and West Virginia in particular with an advantage, I think, relative to other areas. You know, the terrain is a bit more difficult in West Virginia, but we think the advantages of being close to fuel supply, being close to water, having the upstream-midstream integration really do position Antara well. So having a lot of discussions there, nothing to announce at this time, but continue to have quite a bit of discussions there. And then I think in terms of as we look at just the regional demand overall, I think we view this as it could take a few different forms. You've got either behind the meter power for data centers. There's been quite a few announcements just on natural gas fired power generation, both in West Virginia and the region at large. And then I think just local prices tightening to the extent you have regional demand and local prices tightening. As Mike had mentioned, we've got that significant dry gas inventory to take advantage of all those various opportunities. The other thing I would just note is we are intentionally being a bit patient on this as well. I mean, I think as you look at our LNG portfolio, for example, we had many opportunities on Plaquemines, for example, to do long-term deals at certain prices with Plaquemines that were much lower than what we're seeing basis trade at as that LNG facility is ramped up. So we do think patience is a bit of a key here, and as you let this play out and the scarcity of supply continues to build, we think the ability to do margin-enhancing deals will become greater for Antero. So having a lot of discussions but also taking a patient approach and we want to do the right thing versus just coming out with an announcement just for the sake of coming out with an announcement.

Very helpful. Thanks, guys.

Your next question comes from Doug Legate with Wolf Research. Please state your question.

Thanks for having me on. Mike, I wonder if I could pick up on this topic of not seeding market share, if you like, in the basin. What's your decision point for growth? And I guess I'd kind of frame the question like, what are the conditions you need to see? Do you need to see basis improve or is it just about local demand increasing before you decide to step into dry gas growth in your backyard?

Yeah, Doug, interesting question. You know, we've been talking about that. Obviously, this is a proof of concept, so we'll see the results on this, but we're highly encouraged currently. So you mentioned seeding the base, and, you know, we are the dominant producer in West Virginia. I think we produce over 40% of the state's natural gas. We have the dominant acreage position. We have the midstream. We have the acreage HPP. We have investment-grade balance sheet. I mean, everything you'd want. uh for developing it so why why shouldn't we develop it uh so it's proof of concept we'll prove out the resource and then when you look local demand uh absolutely uh would encourage us to grow into that also if you kind of look out the curve if you get you know four dollar 9x natural gas and you could you could hedge basis in the future years that may be something we we would entertain as well so a lot of uh kind of different decision points there but Like I said, we're uniquely positioned for this one. We're very encouraged and we look forward to this, Pat.

I appreciate that. And of course, given the depth of the inventory you have, you've got a lot of optionality, but it does raise the question, and you've got to forgive me for this one, about the rest of your portfolio and the potential for asset sales. And you know where I'm going with this in Ohio. Can you offer any colour confirmatory or otherwise as to where you are in that process?

Yeah, we're just in the middle of that process, Doug. We're highly encouraged there as well, as you can imagine. I mean, that's a highly desirable or coveted asset with the continuous acreage position, all the midstreams in place, the ability to access the firm transport to price it outside of the basin, the liquids portion, the dry gas portion. You know, it's kind of a ready-made asset for companies, so. also all the data centers over in Ohio as well, and all the power demand over there. So it's highly coveted. So that's kind of why we wanted to do a market check. We're just in the middle of it, but we are encouraged.

Great stuff. Thanks so much, guys.

Your next question comes from Betty Jang with Barclays. Please state your question.

Good morning. I want to go back to the data center proof of concept, it seems to me that you don't need to prove to the market that you can grow dry gas and grow at very cost effectively. And so this proof of concept is really for the customers and people you're speaking to on the other hand. So my question is that these customers and entities, what are they looking to de-risk with your proof of concept pad? Is it the speed of which you can deliver volume? Is it the capacity of resources that you can deliver to? And was that, PAD is online. Could that catalyze the conversation that you're having on the power and data center side?

I think the proof of concept is twofold for us, and then I'll let Brendan talk about his discussions with the counterparties. But for us, it's one, you know, what's the EURs? What's the deliverability? Just so we know, we haven't drilled a well over here in 12 years. So is it the 2 BCF? Is it higher than that? Is it lower? So we'll see in how to optimize that development. But also in the midstream, you know, a lot of midstream capacity over there showing that we can flow it into these local kind of sites where these data centers are potentially being located, just the ease of our ability to deliver gas straight to the actual facility. But I'll let Brendan talk about other customers.

Yeah, I think just to add on top of that, you know, I think from the standpoint we haven't drilled a well over here in 10 years, it just shows, you know, we've got the inventory over here. It'll give them good perspective on the ability to quickly ramp up. And I think, you know, having the ability to have that residue gas not only at the processing facilities and in the western part of our play, but also on the eastern part of the play where you're seeing some announcements out there on gas fire generation. It provides just more flexibility in discussions. As I mentioned, we're having multiple discussions, and so the ability to have flexibility around these discussions and what could be best for ANTERO as it relates to kind of margin enhancement This just gives us more flexibility having different parts of the play producing in larger ways.

Got it. That's helpful. My follow-up is on the land budget. You have increased it for 2025, but I'm wondering if the land budget would just be higher for longer given you have expanded the scope or the boundaries of what you define as core, and can you just speak to the attractiveness of the organic leasing initiative versus potentially what you see in the private space in that area?

Yeah, you know, we generally go, you know, so our kind of base organic leasing is always kind of looking out the next 24 months and trying to enhance those, the working interests or the lateral lengths, like we discussed earlier. And that's generally up to the 75, you know, $50 to $75 million level. And then Above that is the expansion and, you know, what do we see in a particular year? So we go into generally in a year and that's 75 to a hundred million dollar range. And that's where we've been the last three years. This year, we've just seen a lot of opportunities because our wells continue to strengthen in these areas that we're developing. And there's more acreage, you know, in those areas than there have been kind of in the middle of the field. So our opportunity set continues to grow as our wells and our continue to support that. So, you know, right now it's probably going to next year, and I think most people's models have about $100 million, but if we continue to see opportunities throughout next year, that could be higher, kind of in the back half of 26, if this level of activity continues.

Got it. Okay. Thank you.

Your next question comes from Jacob Roberts with TPH. Please state your question.

Good morning.

Good morning.

I wanted to ask about cash taxes. I think on the last update you gave the market, it was a 2028 timeframe. It was commodity prices. Just wondering if that math has changed at all, given where we sit today.

No, no change there. No material cash taxes through 2027 to 2028 would be that first year we'd expect to pay some.

Okay, perfect. And then circling back to the dry gas activity, this six-well pad or the activity going on currently, to get to that 50% uplift relative to a decade ago, should we be expecting some iterative completion design, or is this ready to go into manufacturing mode?

Oh, ready to go. I mean, like I mentioned, I think we've, since that time, drilled over 1,000 wells. So It was primitive back in 2013 when you look at it. So it would just be doing our typical 36 barrels of water per foot, 200 feet stages. And the spacing on it is like 830 foot spacing between the laterals. So just our typical design in the liquids, but just applying it to the dry gas for the first time in 12 years.

Great. Appreciate the time.

Sure. Sure.

Your next question comes from Nitin Kumar with Mizuho Securities. Please state your question.

Hey guys, good morning and thanks for taking my questions. I want to start on the hedging. You addressed earlier it's a little bit more prudent sort of financial management and I agree. As you've kind of put a floor on your free cash flow yield, what are your thoughts on the cash return profile? You know, you've kind of not done a dividend like some of your peers, as you're stabilizing your cash flow. Is that part of the discussion going forward?

I don't think it's evident, but I think we can be very counter-cyclical on share repurchases with locking that in, also evaluating transactions even in a low commodity price environment. We always want to be counter-cyclical, and we have really no debt, very low debt, no maturities for years and years. We want to be counter-cyclical, but if you don't have the hedges in place when the counter-cyclicality happens in low commodity prices, the free cash flow is not there as well. So we wanted to lock in a baseline of free cash flow and then be able to use it for share repurchases or transactions is where we're thinking.

Great, great. I appreciate that. And the topic of M&A has been covered quite a bit, but you confirmed earlier that you're marketing the Ohio assets. Just curious, as you mentioned, you don't have a lot of near-term debt or a big balance sheet. What do you think would be the use of proceeds if you were successful in getting the price you want?

Yeah, it's a good question, and that's why it's a high bar for us, because the most likely case, I would still say it's the hold case, but we'll see where the marketing goes. But the use of proceeds right now is, like you mentioned, we're at $1.3 billion of debt. We have $300 million on our credit facility, and we have, I think, $400 million on a 29. That's kind of callable at par, so we really only have $700 million of prepayable debt that there's 600 million, so 20, 30 maturity, I think five and three-eighths, so that's a good piece of paper. So that, but then, you know, you also look at where our equity trades and the type of valuations that you're going to see through the UTICA as well in excess of where our equity trades. So that could be a use of proceeds as well as, you know, it wouldn't be a bad trade if you sell your UTICA for well in excess of where your equity trades and you use that to buy into shares.

Appreciate it. Good luck.

Sure.

Your next question comes from Leo Mariani with Roth MKM. Please state your question.

Yeah, hi. I just wanted to follow up a bit more on this concept of growing net volumes without growing sort of gross in the near term. Obviously, you talked about M&A. It sounds like you're undecided on the drilling partnership here. But just in terms of the M&A strategy other than undeveloped acreage, are there opportunities to continue to pick up minerals, working interests? Are you generally trying to do this kind of ahead of the drill bit over the next kind of 12 to 24 months? I mean, you said that these three deals kind of came up. Recently, are you seeing just kind of more deals in the basin? Just want to get a little bit more color around some specifics on kind of the M&A strategy here and kind of growing the net without growing the gross.

Yeah, I think you hit on it. These are all small bolt-on transactions, increasing interest. You know, when we talk about gross versus net, all of our processing is full. I think we're at 106% of processing capacity. All the FTE is full. So on the liquid side, It's a challenge to grow growth because all the facilities are full. So in order to grow that, you have to look to the working interest and the royalty. And all of these are highly free cash flow accretive. So that's where it heads at. So as they come up, we assess them and see if it makes sense based on that. And then like we've been talking about a lot in this call, the ability to grow the dry gas is really dependent on regional demand and local basis. And so that is an opportunity for for growth there, but really just trying to grow the net and maintain the growth volumes.

Okay, that's helpful. And then, you obviously highlighted a number of kind of operational records on the quarter with just some very strong improvements in terms of prac stages and cycle times and everything. Can you just give us, you know, any thoughts on whether or not you think there's, you know, a decent amount, kind of more improvement to come here, or do you think you're starting to kind of maybe bump up on some of the limits, I guess, 15 days in a row without stopping on the frack side? It seems like maybe hard to do a lot better than that.

Yeah, if we continue that. So when you get those days, you're doing 16, 17, 18 stages a day, and we average 14.5 during the quarter. So we get more continuous pumping throughout, which is our goal. I think you can see that go a bit higher. But, you know, right now I think if we had a pad and had this type of performance, you'd think it would average, you know, in the 15 stages kind of per day. So a little bit of improvement, but, you know, the 14 1⁄2 stages is really high. Okay, thank you.

Mm-hmm. Thanks, Dan. Your next question comes from Kalei Ackermine with Bank of America. Please state your question.

Hey, good morning, guys. Maybe to start, I'd like you to talk to slide number five, the one that illustrates the expansion of what you consider to be core in the Marcellus. So activity in the east in areas like Wetzel and Tyler, that's been robust for quite a while, and it's easy to see how bad it's now core. But activity to the south and the east has been a little bit less frequent. What gives you confidence that the Corps is expanding to those areas?

Our recent well performance is, you know, we've piloted Wessel, but it's also been in the kind of in the eastern portion of Ritchie and northern part of Gilmore. And you look at some other competitors, and they've had good results down in the Gilmore-Lewis area. So you've seen that. And then, like we talked about on the dry gas, that's in Harrison County.

I appreciate that. For my second question, Got it, Mike. I appreciate that. For the second question, I'm going to go to slide number 10 here. So gas demand is expanded across that pipeline fairway. So two questions. Pipes in that direction are quite full. Do you guys have visibility on maybe new FT opportunities to push more gas into that region? And then it feels like given the demand pull, there's increased competition in the Gulf to lock these volumes down. Do you see any direct-to-consumer opportunities along this route that you could participate in?

Yeah, I think, if Justin can correct me, I think we had a 2.1 BCF a day going down into the Gulf. Yeah. And we've intentionally been floating, like Brendan's comments suggested. You know, we've carried this for quite some time. We're going to see where the actual basis goes. And when you look at these type of opportunities and demand growth, 25 BCF a day, 17 of it being in the Gulf Coast or along that path, we think there will be a lot of opportunities. But I can let Justin expand on that.

Yeah, good morning. This is Justin Fowler. So the way we think about this, you know, on Mike and Brendan's previous comments, the local demand, if all these projects go forward, it's going to be there. So that's going to drain gas out of, you know, various local pipes, various local pools. And then to Mike's point, when you think about the Ontario 2.1 or so BCF of Southbound, there was approximately 10 BCF reversed over the years since the shale revolution took off. So right there, we're about 20% of that volume heading cells. And then when you really zoom in on some of our pipelines, which we're calling mid-path, Antara owns rights past those potential projects as well. So we are evaluating different projects in Kentucky. Mississippi, you know, where we cross, and then to your point on just the LNG market, yes, you know, the LNG groups are going to have to potentially start to lock in supply just as there will be scarcity across, you know, the summer season, winter season, et cetera, that could cause peak situations. So, we have been talking to a lot of those groups as well, but to Brendan's point, patience is key at the moment, and there's a lot still to be developed. If I understood your first part of your question correctly, in terms of new capacity being added southbound, it's just such high cost, and any of those projects are going to be toward the end of the decade. So, Ontario is in a good situation here to continue to watch the basis locally and just that behavior locally.

and then also um just working with you know these various groups in the mid-path uh delivery points if those projects uh move forward and the only thing i would add just on the uh on the on the point about end users that there has seemed to be a bit of a shift in terms of the demand poll side of things you know when the basin took off it was more of a producer push there has been a lot more uh significant interest from a demand pulse perspective and folks wanting to get the actual supply due to some of that scarcity of supply that I think is starting to take hold in the market now.

Sounds like a good opportunity, Seth. Thanks, guys.

Thank you. Thanks. Your next question comes from Neil Mehta with Goldman Sachs. Please state your question.

Yeah, good morning, team. And Mike, congratulations on stepping into the CEO role. I just love your your perspective early on. It's been a couple months now of just observations as you step into this new role. And, you know, the business has done very well over the last couple of years, particularly coming out of COVID. But what do you think the next frontiers are from a strategy perspective as you look to the end of this decade?

Yeah, I think you saw that in the strategic initiatives, you know, the You know, we have such a terrific asset and, you know, best rock, some of the best rock in North America, definitely the best rock for liquids development, you know, and midstream access, midstream capacity, balance sheet, investment grade. So it kind of ticks all the boxes. So now the strategic initiatives going forward are just trying to enhance that, you know, doing bulk on acquisitions in West Virginia, trying to enhance our exposure there, some dry gas development like we've talked about, That's a good opportunity for us. And then easing hedging as a tool. That's one thing that, like I mentioned, we want to be counter-cyclical. The only way to do that is to have some sort of certainty of cash flow during low commodity price times. So that's kind of the next frontier that we're looking at, but we're excited about it. And like I mentioned, we are at the dominant position in West Virginia, so we should expand upon that.

Very clear, Mike. And then? Just wanted to go to the macro on NGLs. As we watch your pricing sheet, it's a tougher environment right now. I guess it's not so bad when you look at it as a percentage of WTI, but on an absolute basis, it's pretty challenging. Just talk about the path for recovery in 2060. Do you think that recovery is going to be more supply-driven or demand-driven? On the supply side, I saw you put out some interesting numbers in terms of volume growth. It's probably below where I think consensus is for volume growth. volume growth in the Permian for NGLs next year. So, you know, is that an out-of-consensus view that you guys have that we can offset sort of the prevailing view that even if black oil is flat, that NGLs will still be growing significantly?

Yeah, Neil, this is Dave Cantalongo. I'll take that one. So, I guess your first question, I'm looking forward to 2026. You know, certainly oil prices do play a key role in what happens with NGL price. through the first nine months of the year, a little less than 54% of WTI, 60% of WTI here in 2025. So that really kind of speaks to the value for NGLs is still there, driven by ResCom, you know, in elasticity and at chem demand. Looking forward to 26. Obviously, we're very optimistic about the trade uncertainties getting resolved here. Obviously, some announcements here this morning that we think will certainly thaw some of that if you look back to, you know, what was being explored And in June, it was a little less than 100,000 barrels a day and since rebound to about 300. So certainly some thawing there, but, you know, we'd like to see that continue to improve. That'll help with deficiencies on freight pricing, which will also drive Mott Bellevue higher. So those are kind of the key things we're looking to, you know, I don't know how long, you know, the world can sustain at a 50-something dollar per barrel WTI as well. So we're for NGL prices on an absolute basis. Coming back to the supply picture and your questions on that, that view is a third-party view that we put in our presentation. I think that there's a lot of different groups that are out there. There's been some consolidation in the third-party analytical groups, so there aren't as many people out there providing views. It seems to be a belief around gas-oil ratios increasing, and that really seems to be what's behind some of the higher NGL supply growth views. But on account environment, that NGL supply growth is going to be as strong as it was, you know, if you're looking at the chart in the prior years.

Thanks, Tim. Appreciate it.

And your next question comes from Paul Diamond with Citi. Please state your question.

Thank you. Good morning, all. Thanks for taking the call. Just wanted to touch quickly on kind of capital allocation given current conditions. You know, with your hedge book, you guys put on a pretty decent floor under free cash flow next year. And I've used kind of split evenly between stock repurchases, debt repayment, and acquisitions. I guess in kind of a bull scenario, how much cash would you be willing to build if you want to really maintain counter-cyclicality, assuming that you have limited debt to really buy back now?

and you know if your stock starts to run because what level of cash is comfortable yeah that'll be a good problem to have but i think i mentioned earlier we have 700 million of debt that we can pay down uh of course we'd be buying shares all along that way as well so um in a in a real bull case scenario where you get into a couple billion of free cash flow a year you know you would start to build some cash but i i think you know you'd be unless You know, you didn't really have any other transaction opportunities. I think you'd kind of be where we're at right now, where it's kind of like a third repay of debt, third equity purchases, and a third in transactions.

Got it. And just kind of switching to the other side of that coin, some of your peers have really started to do, you know, production management, whether it's the curtailments or...

choking or anything along those lines um given your ft i know it's less of an opportunity for you but just wanted to see if you saw you know how intera would play in that on the margins is that something you haven't worked into or well when we do it we just don't talk about it it's already built into kind of our guidance and it's really kind of they may say it's curtailment practices but i think it's really economics based and the gas prices are are low in the basin so it wouldn't make economic sense to flow to that Whenever that occurs, which is rare, like you mentioned with the SP and the liquids, we don't really have that much local basis exposure. But we do have it from time to time, but we always build that in the risking of our guidance.

Got it. Understood. Appreciate the clarity. I'll leave it there.

Thank you, Ann. Ladies and gentlemen, there are no further questions at this time, so I'll turn the floor back to Dan Katzenberg for closing remarks. Thank you.

Thank you, and thanks, everyone, for joining the call today. Please feel free to reach out with any questions that you have. Have a good day.

This concludes today's call. All parties may disconnect. Have a good day.