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Date
Thursday, October 30, 2025 at 11 a.m. ET
Call participants
Chief Executive Officer — Michael Kennedy
Senior Vice President, Liquids Marketing and Transportation — David Cannelongo
Senior Vice President, Natural Gas Marketing — Justin Fowler
Chief Financial Officer — Brendan Krueger
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Takeaways
Free Cash Flow -- bringing year-to-date free cash flow to nearly $600 million, reflecting capital efficiency and disciplined cash management.
Debt Reduction and Share Repurchases -- Approximately $180 million of debt repaid year to date 2025, and $163 million of stock repurchased year to date 2025.
Asset Acquisitions -- $242 million invested year-to-date in asset acquisitions, with $260 million in acquisitions completed in Q3 2025.
Operating Performance -- Achieved company records for drilling efficiency, including a quarterly average of 14.5 completion stages per day in Q3 2025, and a world record of 15 days of continuous pumping hours.
Production Guidance -- Fourth-quarter 2025 production is expected to range from 3.5 Bcf to 3.525 Bcf per day, with this maintenance level targeted for 2026.
Maintenance Capital Outlook -- Projected maintenance capital to increase in line with production by 3% for Q4 2025.
Hedging Update -- 24% of expected 2026 natural gas volumes hedged with swaps at $3.82 per MMBtu, and 20% hedged with wide collars between $3.22 and $5.83 per MMBtu for 2026.
Hedge Impact -- Hedges secure base-level free cash flow yields of 6%-9% at $2-$3 natural gas prices in 2026, and offer upside exposure to as much as 20% free cash flow yield in 2026.
2026 Free Cash Flow Breakeven -- Expected breakeven of $1.75 per Mcf in 2026, assuming year-to-date NGL prices.
Liquids Fundamentals -- U.S. C3 plus production growth projected to slow substantially in 2026, with only 11,000 barrels per day of supply growth anticipated in 2026.
Propane Export Growth -- Year-to-date propane exports increased by more than 120,000 barrels per day to an average of 1.85 million barrels per day, compared to 1.72 million barrels per day in the same period last year.
Exposure to Basis Premiums -- Approximately 25% of gross gas was sold at TGP 500 L as of Q3 2025, where the basis premium to Henry Hub is nearly $0.80 for winter 2025 and $0.64 for the full year 2026.
LNG Demand Forecast -- Anticipates a 4.5 Bcf per day LNG export increase exiting 2025, and an additional 10 Bcf per day increase in LNG demand over the following 24 months as new LNG facilities ramp up.
Regional Gas Demand -- Regional demand in development areas is expected to rise by 8 Bcf per day based on announced projects, with power projects along the firm transportation corridor adding over 3 Bcf per day of announced demand to date.
Dry Gas Drilling in Harrison County -- Management restarted activity in Harrison County after a decade, citing a "proof of concept pad" according to Michael Kennedy, with expected EUR improvement from 1.3 Bcf to 2.0 Bcf per 1,000 lateral feet, based on management commentary.
Land Budget -- Organic leasing is expected to be in the $75 million to $100 million range for 2025, with potential for higher levels if activity persists.
Cash Tax Outlook -- Management expects no material cash taxes through at least 2027, with payments beginning in 2028.
Balance Sheet -- Current total debt is $1.3 billion as of Q3 2025, with only $700 million of prepayable debt and no near-term maturities, affording flexibility for capital allocation.
Asset Sale Process -- Management confirmed the ongoing process to market Ohio (Utica) assets, describing them as highly desirable and "coveted" according to Michael Kennedy due to midstream infrastructure and market proximity.
Well Lateral Lengths -- Average lateral length is projected to increase by 1,000 feet to approximately 14,000 feet next year, reflecting further efficiency gains.
Summary
Antero Resources (AR 5.03%) reported record operational efficiency and disciplined allocation of capital across debt reduction, share repurchases, and opportunistic acquisitions. Management emphasized the company's strategic position to benefit from accelerating U.S. natural gas demand, supported by long-term transportation agreements, regional expansion, and a flexible hedge program securing attractive forward free cash flow yields. Executives outlined ongoing proof-of-concept activity in Harrison County to capture anticipated regional demand growth, as well as advanced preparations for asset sales in Ohio, which may enable further shareholder value creation.
Chief Executive Officer Kennedy described a twofold rationale for dry gas drilling in Harrison County: establishing modern deliverability expectations and demonstrating midstream deliverability for new local demand.
Management identified customer interest for direct supply to new power and data center projects, highlighting their ability to respond quickly with "1,000 gross dry gas locations that we could accelerate activity on if there is a regional call for higher supply."
Chief Financial Officer Krueger reiterated capital discipline, noting that third-quarter portfolio transactions were "accretive to the key metrics that we prioritize, including free cash flow, and net asset value per share."
Senior Vice President Cannelongo stated that U.S. C3 plus NGL supply growth is "nearly flat" for 2026, while year-to-date, propane exports increased despite global trade uncertainty, supporting the potential for improved future pricing.
Management expects to maintain a patient capital deployment stance, especially regarding asset sales and large-scale growth, with Kennedy remarking, "the most likely case I would still say it's the hold case, but see where that the marketing goes."
Industry glossary
C3 Plus: Natural gas liquids primarily consisting of propane (C3) and higher molecular weight hydrocarbons such as butane and natural gasoline.
TGP 500 L: Tennessee Gas Pipeline's 500 Leg, a key Appalachian outlet with its own basis pricing impacting regional gas sales.
Mont Belvieu: The reference pricing hub for U.S. natural gas liquids (NGLs), particularly in Texas.
WTI: West Texas Intermediate, serving as the benchmark for U.S. crude oil prices and a common denominator for NGL pricing discussion.
Firm Transportation: Contracted pipeline capacity guaranteeing physical gas delivery to specific markets, typically over multi-year terms.
EUR: Estimated Ultimate Recovery, used to express the total expected extractable hydrocarbons from a well or drilling location.
Full Conference Call Transcript
Michael Kennedy: Thank you, Dan, 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. The 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 include adding to our core Marcellus position in West Virginia, 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 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. Set numerous company records and achieved significant progress. The right-hand side of the slide highlights the various company records we achieved.
That's 5,000 feet. 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: fifteen 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 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, the incremental locations more than offsetting our annual turn in lines.
Further, this program allows us to maintain our development focus and 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, David Cannelongo, for his comments.
David Cannelongo: 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 plus supply. As shown on slide number six titled U.S.
C3 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 U.S. C3 plus production growth in '26 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 two 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 debottlenecking of terminal capacity. Year to date, propane exports have increased by over 120,000 barrels a day averaging 1,850,000 barrels a day compared to 1,720,000 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 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. 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 plus production and sells the remainder of its C3 plus volumes in the domestic market. Therefore, an uplift in domestic sales price 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 five-year range to near the five-year average by early 2026.
These fundamentals will support Mont Belvieu 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.
Justin Fowler: 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 500 L Basis Strength. LNG export demand is expected to increase by 4.5 Bcf from the 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 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's 500 pricing hub. Our exposure to TGP 500 L is expected to lead to higher natural gas realizations.
Slide nine takes a closer look at the significant natural gas demand surge that is coming over the next twenty-four months from the new LNG capacity additions. Over this short period, LNG demand has expected to increase by another 10 Bcf per day driven by the startup of Plaquemines II, Golden Pass Corpus Christi three, and Calcasieu Pass two. 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 corridor. Based on announcements that have been made to date, regional demand is expected to increase by eight 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 Gern 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.
Brendan Krueger: 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 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 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 in 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: Thank you. And ladies and gentlemen, at this time we will conduct our question and answer session. And your first question comes from Arun Jayaram with JPMorgan. Please state your question.
Arun Jayaram: Yes, good morning, gentlemen. I wanted to maybe start with the decision to commence D and C operations on the gas side in Harrison County. I was wondering if you could talk about what the catalyst was for that kind of decision. Did data centers, power deals down the road, did that play into kind of the calculus about doing something you hadn't done in ten years or so?
Michael Kennedy: Yes, Arun, that's exactly the catalyst. We've been active in those discussions and it became clear to us all those discussions really related to the portion of our acreage position 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 it will be very low-cost wells and highly productive and we're excited to get back at it in the Harrison County area.
Arun Jayaram: 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've 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.
Michael Kennedy: Yes, 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 have we could continue that in 2026, but we haven't made that decision yet.
Operator: All right, great. I'll turn it back. Your next question comes from John Freeman with Raymond James. Please state your question.
John Freeman: Just a follow-up on Arun's question with following the acquisitions and the higher production level now that you cited that you're going to have in 4Q. Just how does that impact 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.
Michael Kennedy: It has had the same ratio that increased the production increased by 3%. So it's logical to expect a 3% increase in your main capital. So that's like an incremental $20 million from that $675 million level.
John Freeman: Got it. Thanks. And then, looking at the acquisitions, $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 happen to have all these sort of transactions domino during the quarter, just kind of how to think about that going forward?
Michael Kennedy: Yes. 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 they make sense at the time. When you look at our acreage position, 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.
John Freeman: Thanks, Mike.
Operator: Your next question comes from David Deckelbaum with TD Cowen. Please state your question.
David Deckelbaum: Thanks for taking my questions guys. Mike, I guess as we get into 26, obviously, 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 2026 given that you guys have had some pretty significant efficiency gains? To date?
Michael Kennedy: Yes. No, it actually goes up. It's a good 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. You highlighted very efficient nature of our leasing program. David, exactly what it's doing. It's trying to optimize those lateral lengths and also expand our position. So next year is up about 1,000 foot per well.
David Deckelbaum: 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 work working interests, 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?
Michael Kennedy: I know if we'll have those opportunities. It was three separate transactions all like with working interest another one's royalty interest, another one with more acreage based. So, hopefully, they continue in the next year, but it's 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.
David Deckelbaum: Appreciate it guys.
Operator: Your next question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question.
Kevin MacCurdy: Hey, good morning. 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 white 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?
Michael Kennedy: I think it's probably both. If we could replicate what we have next year where it's these approximate numbers a quarter with wide collars protecting at three twenty five with exposure up to six 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 20% free cash flow yield. That feels like a prudent way to manage the business.
Kevin MacCurdy: 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?
David Cannelongo: Yes, Kevin, this is Dave Cannelongo. Really just a function of customers and when they're up 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.
Kevin MacCurdy: Great. Thank you.
Operator: Your next question comes from Phillip Jungwirth with BMO Capital Markets. Please state your question.
Phillip Jungwirth: 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 much of an uplift you'd expect versus kind of the historical type curves from the wells that you had drilled here previously?
Michael Kennedy: 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 twelve 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 excited about optimizing the completion in the of those wells. And so was 1.3 Bcf per day and my expectation is two Bcf. I mean two Bcf per thousand foot. Now.
Phillip Jungwirth: Okay. Great. And then I want 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?
Michael Kennedy: Yes. 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 and 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, 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 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, 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 announcement just for the sake of coming out with an announcement.
Phillip Jungwirth: Very helpful. Thanks, guys.
Operator: Your next question comes from Doug Leggate with Wolfe Research. Please state your question.
Doug Leggate: Thanks for having me on. Mike, I wonder if I could pick up on this topic of not, you know, 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?
Michael Kennedy: Yes, Doug, interesting question. We've been talking about that obviously it's 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 we are 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 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 hedge basis the future years, that may be something we would entertain as well. 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 Pat.
Doug Leggate: 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 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?
Michael Kennedy: Yes. We're just in the middle of that process. We're highly encouraged there as well. You can imagine, mean that's a highly desirable or coveted asset with contiguous acreage position. All the midstream's 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 ready-made asset to company. 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.
Doug Leggate: Great stuff. Thanks so much, guys.
Operator: Your next question comes from Betty Jiang with Barclays. Please state your question.
Betty Jiang: 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 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?
Michael Kennedy: 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 twelve years. So is it the two Bcf? Is it higher than that? Is it lower? So we'll see and how to optimize that development. But also in the midstream, 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 deliver gas straight to actual facility.
I'll let Brendan talk about other the customers.
Brendan Krueger: Yes. Think just to add on top of that, I think from the standpoint we haven't drilled a well over here in ten years. It just shows we've got the inventory over here. It'll 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 and in the Eastern I'm Sorry, 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 and 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.
Betty Jiang: 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 that 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 a private space in that area?
Michael Kennedy: You know, we generally go, you know, to our kind of base organic leasing is always kind of looking out the next twenty-four months and trying to enhance those working interests or the lateral lengths like we discussed earlier and that's generally up to the 75%, million to $75 million level and then above that is the expansion. And what do we see in a particular year. So we go into generally in the year and 75,000,000 to $100 million 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 in those areas than there have been kind of in the of the field. So our opportunity set continues to grow as wells and our continue to support that. So right now, it'd probably go into next year and I think most people's models have about $100 million. But we continue to see opportunities throughout next year that could be higher kind of in the 2026 if this level of activity continues.
Betty Jiang: Got it. Okay. Thank you.
Operator: Your next question comes from Jacob Roberts with BPH. Please state your question.
Jacob Roberts: Good morning. I wanted to ask about cash taxes. I think on the last update, gave the market, it was a 2028 timeframe. Those commodity prices. Just wondering if that math has changed at all given where we sit today?
Michael Kennedy: No, no change there. No material cash taxes. Through 2027 to 2028 would be that first year expect to pay some.
Jacob Roberts: 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?
Michael Kennedy: 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 foot stages and spacing on it. Is it like eight thirty foot spacing. 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 twelve years.
Jacob Roberts: Great. Appreciate the time.
Michael Kennedy: Sure.
Operator: Your next question comes from Nitin Kumar with Mizuho Securities. Please state your question.
Nitin Kumar: 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, how what are your thoughts on cash return profile? You've kind of not done a dividend like some of your peers, you're stabilizing your cash flow. Is that part of the discussion going forward?
Michael Kennedy: 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 haven't 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 price. The free cash flow is not there as well. We wanted to lock in a baseline of free cash flow and then be able to use it for share repurchases or transactions is what we're thinking.
Nitin Kumar: Great. Great. I appreciate that. And the topic of M and 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?
Michael Kennedy: 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 see where that the marketing goes. The use of proceeds right now 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 kind of callable at par. So we really only have $700 million of prepayable debt, other $600 million. So 2030 maturity, I think 5.8%. 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 as well excess of where our equity trades. So that could be a use of proceeds as well as it wouldn't be bad trade if you sell your Utica for well in excess of where your equity trades and use that to buy in the shares.
Nitin Kumar: Appreciate it. Good luck.
Michael Kennedy: Sure.
Operator: Your next question comes from Leo Mariani with ROTH MKM. Please state your question.
Leo Mariani: Yes, hi. 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 and A, it sounds like you're undecided on the drilling partnership here. But just in terms of the M and 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 twelve to twenty-four months? I mean, you said that these three deals kind of came up recently. Are seeing just kind of more deals in the basin?
Just want to get a little more color around some specifics on kind of the M and A strategy here and kind of growing the net without growing the gross?
Michael Kennedy: Yes. I think you hit on it. These are all small bolt-on transactions. Increasing interest. When we talk about growth versus net our all of our process is full. I think we're at 106% of processing capacity. All the Feet 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 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, it's really dependent on regional demand and local basis. And so that is an opportunity for growth there. But really just trying to grow the net and maintain the gross volumes.
Leo Mariani: Okay. That's helpful. And then you obviously highlighted a number of operational records on the quarter. With just 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 come here? Or do you think you're starting to kind of maybe bump up on some of the limits, I guess, fifteen days in a row without stopping on the frac side, it seems like maybe hard to do a lot better than that.
Michael Kennedy: Yes, if we continue that. So when you get those days, you're doing 16, 17, 18 states 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's averaging on the 15 stages kind of per day. So a little bit of improvement, but the 14.5 stages is really high.
Leo Mariani: Okay. Thank you.
Operator: Thanks. And your next question comes from Kalei Akamina with Bank of America. Please state your question.
Kalei Akamina: Hey, good morning, guys. Maybe to start, I'd like to 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. 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?
Michael Kennedy: Our recent well performance is we've Tyler and Wetzel, but it's also been in 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.
Kalei Akamina: Got it, Mike. I appreciate that. The second question, I'm going to go to slide number 10 here. So guest demand is expanded across that pipeline fairway. So two questions. Pipes in that direction are quite full. You guys have visibility on maybe new Feet opportunities to push more gas into that region? 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 that you could participate in?
Michael Kennedy: Okay. I think Justin can correct me. I think I had 2.1 Bcf a day going down into The Gulf. Yes. 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.
Justin Fowler: Yes, good morning. 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 2.1 or so 10 BCF reversed, you know, over the years since the shale revolution took off. So right there, we're about 20% of that volume heading sales. And then when you really zoom in on some of our pipelines, 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, etcetera. 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 of those projects. Move forward.
Brendan Krueger: And the only thing I would add just on the point about end users, that 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 pulse perspective and folks wanting to get the actual supply due to some of that scarcity supply that I think is starting to take hold in the market.
Kalei Akamina: Sounds like a good opportunity set. Thanks guys.
Justin Fowler: Thank you. Thanks.
Operator: Your next question comes from Neil Mehta with Goldman Sachs. Please state your question.
Neil Mehta: Yes. Good morning, team. And Mike, congratulations on stepping into the CEO role. I 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 ends of the end of this decade?
Michael Kennedy: 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 ticks all the boxes and now the strategic initiatives going forward just trying 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.
The only way to do that is to have some sort of certainty of cash flow during low commodity price time. That's kind of the next frontier that we're looking at. And we're excited about it. And like I mentioned, we are at the dominant position in West Virginia, so we should expand upon that.
Neil Mehta: Very clear Mike. And then just wanted to go to the macro on NGLs. And as we walked 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 '20 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 now the 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.
David Cannelongo: 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 prices. As you alluded to as a percentage of WTI. It's been improving here in 2025 to despite some of the market headwinds that were out there. So if you kind of look back at 2024, through the first nine months of the year, less than 54% of WTI, 60% WTI here in 2025. So that really kind of speaks to value for NGLs is still there driven by ResCom inelasticity and petchem demand.
Looking forward to 2026, obviously, we're very optimistic about trade uncertainty is getting resolved here. Obviously, some announcements here this morning that we think certainly thaw 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 100,000 barrels a day or a third of U.S. LPG exports headed that direction of propane exports. June, it was a little less than 100,000 barrels a day and since rebounding to 300,000. So certainly some falling 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 $50 something per barrel WTI as well. So we're you'd 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, 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 undoubtedly, I think anybody's 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 the prior years.
Neil Mehta: Thanks, team. Appreciate it.
Operator: And your next question comes from Paul Diamond with Citi. Please state your question.
Paul Diamond: Thank you. Good morning, Thanks for taking the call. Just wanted to touch quickly on kind of capital allocation given conditions. With your hedge book, you guys put on a pretty decent floor under free cash flow next year. And have you used kind of evenly between stock repurchases, debt repayment in acquisitions. I guess in a in kind of a bull scenario, how much 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?
Michael Kennedy: Yes, 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. Of course, we'd be buying shares all along that way as well. So in a real bold case scenario you get into the couple of billion of free cash flow a year, you would start to build some cash. But I think