Antero Midstream Corporation (NYSE:AM) Q3 2025 Earnings Call Transcript

Antero Midstream Corporation (NYSE:AM) Q3 2025 Earnings Call Transcript October 30, 2025

Operator: Greetings, and welcome to the Antero Midstream Third Quarter 2025 Earnings Call. [Operator Instructions] And as a reminder, this conference is being recorded. It is now my pleasure to introduce to you Dan Katzenberg, the Director of Finance. Thank you, sir. Please go ahead.

Dan Katzenberg: Thank you for joining us for Antero Midstream’s Third Quarter 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.anteromidstream.com, where we have provided a separate earnings call presentation that will be reviewed during today’s call. Today’s call may also 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 of Antero Midstream; Justin Agnew, CFO of Antero Midstream; and Brendan Krueger, CFO of Antero Resources. With that, I’ll turn the call over to Mike.

Michael Kennedy: Thanks, Dan. Good morning, everyone. In my comments, I will discuss our 2025 capital budget and strategic initiatives. Justin will then walk through our financial results for the quarter. Let’s start on Slide #3 titled Investing in the Core of the Marcellus Shale. The maps on this page depict the core outline as we knew upon Antero Resources 2013 IPO compared to where we see it today. As step-out development has proved up acreage over the last decade, the core boundaries continue to expand in the Marcellus along with improving well results. These results have driven an increase in organic leasing program at AR and an expansion of AM’s infrastructure. This organic expansion of both AR and AM is a core initiative of both entities and positions us well for the structured change in natural gas demand over the next several years.

During the quarter, AR acquired approximately $260 million of assets in this core area. This included transactions acquiring working and royalty interest, which were already gathered by AM as well as additional core acreage. The acreage acquisition was undedicated to a midstream provider and resulted in 10 additional locations dedicated to AM. Along with the grassroots leasing program, this brings the total locations acquired year-to-date and dedicated to AM approximately 80 locations, more than offsetting the 2025 development plan. Looking at AM’s capital investment. During the third quarter, we invested $51 million, bringing our year-to-date capital invested to $133 million or approximately 75% of our total budget at the midpoint of guidance.

This capital included significant investments in water assets to expand and connect the southern end of the Marcellus Shale. This investment provides development flexibility and unlocks significant low-cost inventory across the liquids-rich midstream corridor. I also want to touch on some new initiatives on the dry gas portion in West Virginia of our acreage highlighted in blue on Slide #4. With only a small investment by AM, AR is now planning to drill its first dry gas Marcellus pad in over a decade. This pad is located on existing infrastructure with underutilized midstream capacity that AM acquired in 2022. This pad highlights the speed to market Antero can deliver on a coordinated basis with Antero Midstream and significant dry gas optionality.

Our midstream infrastructure will allow AR to immediately access local markets as proof of concept for future in-basin demand growth from data centers and power generation projects or if local basis were to tighten. This dry gas development results in attractive rates of return for AM and more importantly, significant upside to our previous acquisition that was valued on a PDP-only basis. In summary, we continue to remain active in our expansion efforts, leveraging our existing assets to drive growth and capitalize on the structure change in demand for natural gas. With that, I’ll turn the call over to Justin.

Justin Agnew: Thanks, Mike. I’ll start with our third quarter financial results on Slide #5. During the third quarter, gathering and compression volumes increased by 5% year-over-year, driven by another quarter of uptime availability over 99%. Adjusted EBITDA was $281 million, which is a 10% increase year-over-year. This was driven primarily by an increase in gathering, processing and fresh water delivery volumes. Fresh water delivery volumes increased by almost 30% year-over-year while operating just 1 completion crew, which is a testament to the significant completion efficiencies achieved over the last year. This EBITDA growth, combined with the decline in capital, resulted in free cash flow after dividends of $78 million, which was a 94% increase compared to last year.

We utilized this free cash flow for share repurchases and debt reduction, which drove our leverage down to 2.7x as of September 30. I’ll finish my comments on Slide #6 titled Balance Sheet Strength and Flexibility. Over the last year, we’ve reduced our absolute debt by approximately $175 million and taken our leverage down by almost 0.5 turn. This credit improvement resulted in credit ratings upgrade from Moody’s and ability to refinance our nearest maturity notes that were due in 2027. This transaction, which was upsized due to significant demand, extended the maturity to 2033 at the same 5.75% coupon. Pro forma for this refinancing, we have over $870 million of liquidity and no near-term maturities. Our balanced approach to debt reduction and share repurchases has allowed us to reduce our financing costs, further compounding the growth in free cash flow after dividends.

In summary, AM’s balance sheet is in the strongest position since our IPO over a decade ago. Our capital investments continue to deliver consistent free cash flow, which we expect to further expand as we head into 2026. This expanding free cash flow positions us well to return additional capital to shareholders and continue to expand our growth opportunities across both the liquids-rich and dry gas portions of our asset base. With that, operator, we are ready to take questions.

Q&A Session

Operator: [Operator Instructions] And the first question comes from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet: Just wanted to turn to the topic of in-basin demand, specifically as it relates to the potential for behind-the-meter opportunities. And I believe Antero has talked about being in discussions there and looking at this. I’m just trying to get a sense for, I guess, how near or later term this is. Just trying to get a feel for that and whether customers are looking for prices pin to just in-basin or is Henry Hub part of the conversation? I’m wondering how this all mixes together.

Brendan Krueger: Yes, this is Brendan. Just to touch on the in-basin demand and behind the meter. I think we’ve talked about it in the past. Antero Resources is one of the largest consumers of power in the state of West Virginia at the Sherwood complex. So we’ve talked about it in that light. in the past where you could go behind the meter, that would accomplish a couple of things. One, it would reduce overall operating costs for Antero Resources on the power side of things. And then secondly, you’d obviously free up incremental grid power if you were to go behind the meter in that scenario. So obviously, it takes a lot of different parties to work through solutions such as that. So no time frame on our end, still analyzing, still having discussions around opportunities like that.

And then in addition, we’ve mentioned in the past, but we do feel the Antero family is very well positioned as it relates to data center opportunities to the extent they take hold in the state of West Virginia. I think Antero Resources produces about 40% of the production — natural gas production in the state, highly integrated with AM. Antero Midstream has the water system that it’s invested about $600 million in. So significant water system, which can be helpful in power infrastructure. So a lot of good attributes between the 2 parties that we think could play out well, but still ongoing discussions at this point and no set time frame.

Jeremy Tonet: Got it. Understood. And on this Sherwood behind-the-meter potential project here, what are the specific, I guess, hurdles at this point that would stop, I guess, moving forward?

Brendan Krueger: There’s a lot of different pieces to it as it relates to equipment availability and making sure you have the right agreements in place from a power perspective with the utilities in that area. So I think still quite a bit of hurdles just to get something across the finish line. So again, no near-term announcements expected on that as we sit here today.

Jeremy Tonet: Got it. And then as regards to the underutilized assets that fit quite nicely given the dynamics there. Just wondering, are there other, I guess, pockets across your footprint where the same potential could unfold going forward where there’s underutilized assets that could step into new production that provides the strong accretion?

Michael Kennedy: Yes. Antero Midstream was early in doing all these bolt-on acquisitions has really consolidated the play. And so we bought the Crestwood asset, which is the dry gas kind of portion in 2022. We bought Summit as well in 2024, which is kind of in that more lean gas area. So those 2 areas and those comprise a significant amount of acreage, probably about 150,000 acres in total are all underutilized right now from both high-pressure and compression perspective. So a lot of availability there for Antero Resources to develop into Antero Midstream’s underutilized capacity.

Operator: And the next question comes from the line of Ivan Scotto with UBS.

Ivan Scotto: I wanted to ask about the 10 undeveloped locations that AR acquired. What kind of capital or infrastructure spend is needed on your end for connectivity to those locations?

Michael Kennedy: Not very material. I mean it’s within our core areas. So generally, when I think about it, and this is just a good rule of thumb, it’s about $1 million per well when you think about it from an LP and water. And then it’s already tied into compression and HP. So incrementally, maybe $10 million.

Ivan Scotto: Okay. Got it. And then just based off of your free cash flow growth and leverage of 2.7x, how should we think about capital allocation priorities moving forward?

Justin Agnew: Yes, good question. I think for now, we’re still focused on debt reduction and repurchasing shares. We’ve had a fairly balanced approach year-to-date. It’s obviously ebbed and flowed a little bit on a quarter-to-quarter basis. But where the shares are trading today, we obviously see a lot of value in repurchasing shares, and there’s obviously some benefit and value of paying down debt. It provides you with a lot of flexibility, and you saw the benefit in terms of refinancing the notes. So I think looking forward, it’s still going to be that balanced approach, roughly 50-50 of share repurchases and debt reduction.

Operator: Next question comes from the line of John Mackay with Goldman Sachs.

John Mackay: I wanted to touch on some of these comments around drilling into where AM is moving capacity. You called this kind of first dry gas well as a bit of a proof of concept. But I guess, is the current AR plan to kind of lean more in this direction? Really, what I’m trying to get to is could we see the effective capital intensity for AM per incremental [ M ] of AR production come down if you’re moving into those windows? Or is this again a kind of, hey, we’ll see how we develop the dry side?

Michael Kennedy: I mean I think it’s the back half. We’ll see how it goes. But if that does occur, it would be AM’s capital intensity will be much lower, obviously, because we already have its structure in the region.

John Mackay: And maybe just a follow-up to that is, yes, I mean, you are calling it a proof of concept. I guess is this a comment on your side on the liquids outlook and more enthusiasm for the dry side? Or is this a, hey, people that are looking at us for in-basin solutions do kind of want to see us be able to execute on the dry piece as well?

Michael Kennedy: Yes, it’s the second, it’s in-basin, but also — I mean, it’s not a bad thought on the first. We do have the diversity of product here and the ability to toggle between liquids and dry gas from both upstream and midstream. So you look at a $4 gas curve versus backwardated oil curve. And so that would suggest that dry gas has become more economic on a relative basis. So that is something that’s optionality for us from both midstream and upstream. So the proof of concept is really for the local demand. But at the same time, it could be a portfolio approach as well.

Operator: There are no further questions at this time. And I would like to turn the floor back over to Dan for any closing remarks.

Dan Katzenberg: Thank you, everyone, for dialing into the call today. Please reach out to us with any questions that you have. Have a good day.

Operator: And thank you, everyone. That does conclude today’s teleconference. We thank you for your participation. You may disconnect your lines at this time.