AR - NYSE

Greetings, and welcome to the Antero Resources Third Quarter 2025 Earnings Call. [Operator Instructions] 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 Antero'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.anteroresources.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 release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids 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 #3 titled Antero's 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. The significant demand growth is driven by increasing U.S. LNG exports, combined with a 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 countercyclical 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 #4, 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 [indiscernible] 5,000 feet. On the completion side, our completion stages per day continues to climb higher, averaging another quarterly record at 14.5 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 [indiscernible] 15 days of nonstop pumping hours, a truly remarkable feat. Next, let's turn to Slide #5, 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 believe will 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. Antero'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 Antero 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 Cannelongo, 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, particularly in the Permian Basin, which accounts for more than half of total U.S. C3+ supply. As shown on Slide #6 titled U.S. C3+ 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 U.S. C3+ 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+ supply growth comes at a time when exports from the U.S. are now able to ramp up, aided by a debottlenecking 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 #7 titled New Capacity to ramp up Exports. Going forward, unconstrained dock capacity will allow U.S. barrels to efficiently clear the market and bring Mont Belvieu prices as close as possible to premium international LPG prices. In the past, Antero has often benefited during times of U.S. Gulf Coast terminal constraints with our ability to export barrels out of markets so it can capture high dock premiums. The ability to execute this strategy has served as a differentiator for Antero versus almost all other NGL producers in the U.S. However, it is important to remember that Antero benefits more from higher Mont Belvieu prices than from high dock premiums. This is because higher Mont Belvieu prices lift both our export sales and all of our domestic sales, the latter of which are exclusively priced on a Mont Belvieu index. Antero on average exports less than 45% of its gross C3+ production and sells the remainder of its C3+ 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 pull is expected to bring propane storage inventories from the top of the 5-year range to near the 5-year average by early 2026. These fundamentals will support Mont Belvieu prices in 2026 and strengthen C3+ 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 #8 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 2, 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 pull for this LNG facility has led to higher demand along our TGP 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 $0.80. And in 2026, the premium is now at $0.64 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 500 pricing hub. Our exposure to TGP 500L is expected to lead to higher natural gas realizations. Slide #9 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 start-up of Plaquemines 2, Golden Pass, Corpus Christi 3 and Calcasieu Pass 2. 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 5 years. The map on Slide #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, Antero 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 3 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 time frame. Antero is uniquely positioned to participate in each of these 3 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 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 price. 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 20% 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 #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 per 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 repurchases. 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.

[Operator Instructions] And your first question comes from Arun Jayaram with JPMorgan.

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

Yes, Arun, 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 to 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 if it's drilled north, and it will 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, just given, Mike, this -- doing a little bit more kind of gas drilling, thoughts on how you're thinking about a 2026 program at Antero. And obviously, historically, around this time, you have decided to do a, call it, a drilling partnership, which has defrayed some of the costs. But how are you -- what is your thinking around 2026 at this point? Understanding it's still probably early in the budgeting process.

Yes, it's still early, but we're still at maintenance capital, Arun. This is just one pad. Really, the fourth quarter production level, we're in the [ 3.25 to 3.5 ] range. That's the level we'll hold generally in '26. 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 have -- we could continue that in '26, but we haven't made that decision yet.

Your next question comes from John Freeman with Raymond James.

Just a follow-up on Arun's question with the -- following 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've 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 increased -- 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. 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 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?

Yes. 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 they make sense at the time. When you look at our acreage position and 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 make sense.

Your next question comes from David Deckelbaum with TD Cowen.

Mike, I guess, as we get into '26, 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?

Yes. No, it actually goes up. 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 is up 1,000, but you highlighted the very efficient nature of our leasing program, David, that's exactly what it's doing, is trying to optimize those lateral lengths and also expand our position. So next year is up about 1,000 foot per well.

Yes. 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 interest, which I guess is -- 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 3 separate transactions, all with working interest, another one is royalty interest, another one with more acreage based. So hopefully, they continue into 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 are -- if they make sense and if they're accretive.

Your next question comes from Kevin MacCurdy with Pickering Energy Partners.

The hedges you added this quarter were unlike past quarters and 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. If we could replicate what we have next year where it's these are approximate numbers a quarter with wide collars protecting at $3.25 with exposure up to 6 and a quarter in that high $3, $4 range and then 50% unhedged. 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. That feels like a prudent way to manage the business.

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

Yes, Kevin, this is Dave Cannelongo. Really just a function of customers and when they're up and running and taking full volumes and then also -- or the 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.

Your next question comes from Phillip Jungwirth with BMO Capital Markets.

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.

Yes, we expect about a 50% improvement. The old wells in that area was more like 1.3 Bcf per day, but with today, after 12 years, we've gotten a lot better at it. And I think we have approximately 1,500 wells now, and those are one of our first. So we're excited about optimizing the completion of those wells. And so it was 1.3 Bcf per day, expectation is 2 Bcf -- I mean, 2 Bcf per 1,000 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 Antero Resources and Antero Midstream. Just what would this look like? And how would you look to play a role?

Yes. I think just to build on what we said last quarter, 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 in West Virginia, in particular, with an advantage, I think, relative to other areas. 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 Antero 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.

Your next question comes from Doug Leggate with Wolfe Research.

Mike, I wonder if I could pick up on this topic of not ceding 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?

Yes, Doug, interesting question. 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 ceding the basin, and 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 HBP. We have investment-grade balance sheet. I mean, everything you'd want for developing it. So why shouldn't we develop it? So it's proof of concept. We'll prove out the resource. And then when you look local demand, absolutely would encourage us to grow into that. Also, if you kind of look out the curve, if you get $4 NYMEX natural gas and you could hedge basis in the future years, that may be something we would entertain as well. So a lot of kind of different decision points there. But like I said, we're uniquely positioned for this, and we're very encouraged, and we look forward to this pad.

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 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 color, confirmatory or otherwise as to where you are in that process?

Yes. 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 contiguous 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, 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.

Your next question comes from Betty Jiang with Barclays.

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 it 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, these customers and entities, what are they looking to derisk 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 once 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, 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 and how to optimize that development. But also in the midstream, 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 -- the customers.

Yes. I think just to add on top of that, I think from the standpoint, we haven't drilled a well over here in 10 years. It just shows we've got the inventory over here. It will give them good perspective on the ability to quickly ramp up. And I think having the ability to have that residue gas, not only at the processing facilities in the Eastern -- I'm sorry, 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-fired generation, it provides just more flexibility in discussions -- like 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?

Yes. We generally go -- so our kind of base organic leasing is always kind of looking out the next 24 months and trying to enhance those -- the working interest or the lateral lengths like we discussed earlier. And that's generally up to the $50 million to $75 million level. And then above that is the expansion and what do we see in a particular year. So we go in generally in the year in that $75 million to $100 million range, and that's where we've been in the last 3 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 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 right now, it'd probably go into next year, and I think most people's models has 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.

Your next question comes from Jacob Roberts with TPH.

I wanted to ask about cash taxes. I think on the last update you gave the market, it was a 2028 time frame at those 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. So 2028 would be that first year we expect to pay some.

Okay. Perfect. And then circling back to the dry gas activity. This 6-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?

Ready you 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-foot stages and the spacing on it is like 830-foot spacing. So lateral -- 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.

Your next question comes from Nitin Kumar with Mizuho Securities.

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'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 a dividend, but I think we can be very countercyclical on share repurchases with locking that in, also evaluating transactions even in a low commodity price environment. We always want to be countercyclical, and we have really no debt, very low debt, no maturities for years and years. So we want to be countercyclical, but if you don't have the hedges in place when the countercyclicality 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 then 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?

Yes. No, 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 that -- 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. The other $600 million is a 2030 maturity, I think, [indiscernible]. So that's a good piece of paper. So that -- but then you also look at where our equity trades and the type of valuations that you're going to see for the Utica is well in excess of where our equity trades. So that could be a use of proceeds as well. 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 the shares.

Your next question comes from Leo Mariani with ROTH MKM.

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 interest? 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 3 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.

Yes. I think you hit on it. These are all small bolt-on transactions increasing interest. When we talk about gross versus net, all of our processing is full. I think we're at 106% of processing capacity. All the FT is full. So on the liquids side, it's a challenge to grow gross because all the facilities are full. So in order to grow that the net, 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 our 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 on this call, the ability to grow the dry gas is really dependent on regional demand on a local basis. And so that is an opportunity for growth there, but really just trying to grow the net and maintain the gross volumes.

Okay. That's helpful. And then you obviously highlighted a number of kind of operational records on the quarter with some very strong improvements in terms of frac stages and cycle times and everything. Can you just give us any thoughts on whether or not you think there's 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 frac side. It seems like maybe hard to do a lot better than that.

Yes, if we continue that. So when you get those days, you're doing 16, 17, 18 stages a day, and we averaged 14.5 during the quarter. So we get more continuous pumping throughout, which is our goal. I think you could see that go a bit higher. But right now, I think if we had a pad and had this type of performance, you think it average on the 15 stages kind of per day. So a little bit of improvement, but the 14.5 stages is really high.

And your next question comes from Kalei Akamine with Bank of America.

Maybe to start, I'd like you to talk to Slide #5 and 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 that is now core. But activity to the South and the East has been a little bit less frequent. What gives you confidence that the core is expanding to those areas?

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

Got it, Mike. I appreciate that. For the second question, I will go to Slide #10 here. So gas demand has expanded across that pipeline fairway. So 2 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?

Yes. I think Justin can correct me, I think we had 2.1 Bcf a day going down into the Gulf. And we've intentionally been floating like Brendan's comments suggested, 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'll be a lot of opportunities, but I can let Justin expand on that.

This is Justin Fowler. So the way we think about this 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 various local pipes, various local pools. And then to Mike's point, when you think about the Antero 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 south. And then when you really zoom in on some of our pipelines, which we're calling mid-path, Antero owns rights past those potential projects as well. So we are evaluating different projects in Kentucky, Tennessee, Mississippi, where we cross. And then to your point on just the LNG market, yes, the LNG groups are going to have to potentially start to lock in supply just as there will be scarcity across the summer season, winter season, et cetera, that could cause peak situation. 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 Antero is in a good situation here to continue to watch the basis locally and just that behavior locally and then also just working with these various groups in the mid-path delivery points that those projects move forward.

And the only thing I would add just on the point about end users, there has seemed to be a bit of a shift in terms of the demand pull side of things. When the basin took off, it was more of a producer push. There has been a lot more significant interest from a demand pull 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.

Your next question comes from Neil Mehta with Goldman Sachs.

And Mike, congratulations on stepping into the CEO role. I'd just love your perspective early on. It's been a couple of months now of just observations as you step into this new role and 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 next end of this decade?

Yes. I think you saw that in the strategic initiatives, Neil, we have such a terrific asset and best rock, some of the best rock in North America, definitely the best rock for liquids development and midstream access, midstream capacity, balance sheet, investment grade. So it kind of ticks all the boxes. And now the strategic initiatives going forward, just trying to enhance that, doing bolt-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 using hedging as a tool. That's one thing that, like I mentioned, we want to be countercyclical and 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 have the dominant position in West Virginia, so we should expand upon that.

Very clear, Mike. And then I just wanted to go to the macro on NGLs. And as we watch your pricing sheet, it's a tougher environment right now. I guess not so bad when you look at it as a percentage of WTI, but on an absolute basis, it's pretty challenging. So just talk about the path for recovery in '26. 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 in the Permian for NGLs next year. So is that 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?

Yes, Neil, this is Dave Cannelongo. I'll take that one. So I guess to your first question on looking forward to 2026, Certainly, oil prices do play a key role in what happens with NGL pricing. And as you alluded to, as a percentage of WTI, it's been improving here in 2025 despite some of the market headwinds that were out there. So if you kind of look back at 2024, through the first 9 months of the year, a little less than 54% WTI, 60% WTI here in 2025. So that really kind of speaks to the value for NGLs is still there, driven by res/com in elasticity and petchem 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 some of that. If you look back to what was being exported in particular to China prior to the tariff announcements in early April was around 600,000 barrels a day or 1/3 of U.S. LPG exports headed that direction or propane exports. In June, it was a little less than 100,000 barrels a day and since rebounded to about 300,000. So certainly, some following there, but we'd like to see that continue to improve. That will help with efficiencies on freight pricing, which will also drive Mont Belvieu higher. So those are kind of the key things we're looking to. I don't know how long the world can sustain at a $50-something per barrel WTI as well. So we're -- you expect at some point, that's going to resolve itself and also become a tailwind 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 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 undoubtedly, I don't think anybody is disputing in this oil price environment and lower rig count environment that NGL supply growth is going to be as strong as it was if you're looking at the chart in the prior years.

And your next question comes from Paul Diamond with Citi.

Just wanted to touch quickly on kind of capital allocation given current conditions. With your hedge book, you guys put out a pretty decent your free cash flow next year and have used kind of 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 countercyclicality, assuming that you have limited debt to really buy back now? And if your stock starts to run, what level of cash is comfortable?

Yes, that will be a good problem to have. But I think I mentioned earlier, we have $700 million of debt that we can pay down. Of course, we'd be buying shares all along that way as well. So in a real bull case scenario where you get into a couple of billion of free cash flow a year, you would start to build some cash. But I think you'd be -- unless 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 1/3 repay debt, 1/3 equity purchases and 1/3 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 production management, whether it be curtailments or choking or anything along those lines. Given your FT, I know it's less of an opportunity for you, but just wanted to see if you saw how Antero would play in that on the margins. Is that something you haven't looked 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 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 FT 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.

And 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.