ANTERO RESOURCES Corp Q3 FY2025 Earnings Call

Greetings, and welcome to the Antero Resources Third Quarter 2025 Earnings Call. 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 include 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 highlights 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. We 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 with our completion stages per day continuing to climb higher, averaging another quarterly record at 14.5 stages per day or 2,900 feet per day. As Patterson-UTI highlighted on their call last week, we set what we believe to be a world record for continuous pumping hours with 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 our organic leasing efforts. 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, 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 geological risk while leveraging the benefits of Antero Midstream.

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 to capture high dock premiums. 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 are 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. 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.

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.

And your first question comes from Arun Jayaram with JPMorgan.

Gentlemen, I wanted to maybe start with the decision to commence drilling and completion 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, play into kind of the calculus about doing something you hadn't done in 10 years or so?

Yes, Arun, that's exactly the kind of catalyst. We've been active in those discussions, and it became clear to us that all those discussions really related to the eastern portion of our acreage position and where those opportunities would be located, also where the local demand is. We thought looking at our position, we have 100,000 acres. We have significant historical activity there. We also have the midstream infrastructure. We have a proof-of-concept pad that already exists with wells going south. If it’s drilled north, it will be very low-cost wells and highly productive. 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. 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. For this fourth quarter production level, we're in the range of 3.25 to 3.5 Bcf per day. 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 the market is related to that, and 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 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 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 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 a bigger focus of the company? Or was this sort of a one-off in nature, and just you happened to have all these 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 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. 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. I think it goes up to 14,000 feet. 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 while also expanding our position. So next year is up about 1,000 feet per well.

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 three separate transactions, all with working interest; another one is royalty interest, and 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, and these types of transactions tend to be available to us 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 in that you aggressively hedged the next quarter or fourth quarter in this instance, and you opted for swaps for next year instead of the wide collars before. Has your strategy on hedging changed? Or was this just opportunistic? And should we expect you to have a certain hedge level heading forward from here?

I think it's probably both. If we could replicate what we have next year, these are approximate numbers – a quarter with wide collars protecting at $3.25 with exposure up to $6.25 in that high $3 to $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 of around 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 also the spreads into the Gulf Coast on ATEX have been improving here in the back half of the year. So we're 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 were more like 1.3 Bcf per day, but with today and after 12 years, we've gotten a lot better at it. I think we have approximately 1,500 wells now, and those are one of our first. So we're excited about optimizing the completion of those wells. So it was 1.3 Bcf per day, and the expectation is now 2 Bcf per 1,000 feet.

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 the 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 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 and close to water having the upstream, midstream integration really do position Antero well. We're having a lot of discussions there, nothing to announce at this time, but we continue to have quite a bit of discussions. As we look at just the regional demand overall, we view this as it could take a few different forms. You've got either behind-the-meter power for data centers. There have been quite a few announcements just on natural gas-fired power generation, both in West Virginia and the region at large. 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 prices that were much lower than what we're seeing basis trade at as that LNG facility is ramped up. We think patience is a bit of a key here. 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. We're having a lot of discussions, but we're 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 in the basin. What's your decision point for growth? 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. 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, and some of the best midstream infrastructure. We have investment-grade balance sheet. So everything you'd want for developing it. So why shouldn't we develop it? It's proof of concept; we believe in the resource. Local demand would absolutely encourage us to grow into that. If you kind of look out the curve, if you get $4 NYMEX natural gas and can hedge basis in the future years, that may be something we would entertain as well. There are a lot of 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 your inventory, you've got a lot of optionality, but it does raise the question about the rest of your portfolio and the potential for asset sales. 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, 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. All the data centers over in Ohio and all the power demand over there makes it highly coveted. That's kind of why we wanted to do a market check. We're 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. So this proof of concept is really for the customers and people you're speaking to on the other hand. My question is, 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 once that pad is online, could that catalyze the conversation that you're having on the power and data center side?

I believe the proof of concept is twofold for us, and then I'll let Brendan discuss his conversations with the counterparties. For us, it's first about understanding the EURs and the deliverability, especially since we haven't drilled a well in this area for 12 years. We need to determine whether it's the 2 Bcf, more, or less, and how to optimize that development. Additionally, in the midstream, it's about demonstrating that we can deliver gas to local sites where the data centers are likely to be located, showcasing our ability to transport gas directly to the facility. I'll let Brendan address other aspects as well.

Yes. I think just to add, we haven't drilled a well over here in 10 years. It shows we've got the inventory over here. It will give them good perspective on the ability to quickly ramp up. By having that residue gas, not only at the processing facilities in the Eastern 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. We’re having multiple discussions, and so the ability to be flexible around these discussions will be best for Antero as it relates to margin enhancement. We're being patient and want to get good deals rather than just announce something for the sake of it.

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? What needs to happen?

Yes, Doug, interesting question. We've been talking about that. This is a proof of concept; we want to see the results on this, but we're highly encouraged. We're the dominant producer in West Virginia; we possess a dominant acreage position, and we have investment-grade balance sheets. Everything you'd want for developing it. While we are uniquely positioned for this, we look forward to this pad.

Thanks, Mike. And as we think about the relationship between the operating results and your growth strategy, how much of your results have been impacted by the operational efficiencies you've achieved over the last couple of years.

Our results have definitely been impacted by operational efficiencies. When we drilled that well, we saw improvement in both recovery and efficiency, which gives us confidence moving forward in our growth strategy.

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 you have. Have a good day.

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