Antero Midstream Partners LP Aktie

Greetings, and welcome to the Antero Midstream Corporation Second Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. [Operator Instructions] It's now my pleasure to turn the call over to Dan Katzenberg, Vice President, Investor Relations. Please go ahead.

Thank you for joining us for Antero Midstream's Second Quarter Investor Conference Call. We will spend a few minutes going through the financial and operating highlights, and then we will open it up for Q&A. I would also like to direct you to the homepage of our website at intel midstream.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 the earnings press release for important disclosures regarding suction 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 will turn the call over to Mike.

Thanks, Dan. Good morning, everyone. I'll start my comments on Slide #3. Last year has been an exciting year for growth in Appalachian, more importantly, Antero Midstream. During the second quarter, we gathered over 4.1 Bcf per day of gas, which was almost a 20% increase year-over-year.

This growth was driven by the successful integration of the HG midstream assets. This increased scale, premier footprint and strong balance sheet positions Antero Midstream to capture the abundant opportunities that are beginning to materialize in the region.

To this point, we've seen an acceleration of new gas-fired power generation project announcements and supply deals, including a 2 gigawatt combined cycle power plant in Doddridge County, West Virginia, accessed by AM's joint venture pipeline. We expect this trend to continue as final investment decisions and construction startup accelerate, providing increased visibility into the Appalachian demand growth story.

Looking ahead, we are positioning our infrastructure to support the significant demand growth over the next several years. This starts with beginning construction on our first intrastate regional pipeline called eSight Express. This large diameter East-West pipeline will enhance the regional connectivity of our dry gas gathering system with several downstream market outlets.

We plan to phase in this project over the next several years as new market opportunities arise with the objective of increasing optionality and supporting low-cost dry gas growth. As the industrial builder in the state of West Virginia, that gathers half of the gas produced in the state, we view this project as step 1 in positioning Antero Midstream to capture the incremental production needed to fulfill the visible demand growth.

In our view, this production growth will have to come from high-quality investment-grade producers with multi-decade inventories like Antero Resources. In addition to this project, the opportunity set ahead of Antero Midstream is larger than ever.

In aggregate, we are evaluating several billion dollars of infrastructure opportunities within the region and we'll be selective with projects that are near term, actionable and accretive to our free cash flow and generate attractive rates of return.

Before turning the call over to Justin, I wanted to briefly touch on the early results we are seeing on our first return to the dry gas Marcellus in over a decade. As you can see on Slide #4, EURs on our revisit were over 60% higher than offset wells completed the last time we were actively developing the area.

This highlights the productivity improvements from enhanced completion designs and validates the decades of underlying resource that underpins the growth outlook at Antero Midstream. With that, I'll turn the call over to Justin.

Thanks, Mike. I'll start with our second quarter highlights on Slide #5. The second quarter represents the first full quarter of contribution from the recently acquired HG assets, which have been successfully integrated. Adjusted EBITDA for the second quarter was a company record $289 million, which was a 2% increase year-over-year, driven by an increase in gathering volumes.

Looking ahead to the third quarter, we expect high single-digit sequential EBITDA growth in Q3, driven by increased volumes which keeps us on track to achieve our full year EBITDA guidance. Capital invested during the quarter was $47 million, which helped generate $80 million of free cash flow after dividends.

This quarter marks the 12th consecutive quarter of generating free cash flow after dividends, highlighting the consistency and durability of cash flows over the last 3 years. I'll conclude my prepared remarks on Slide #6. And which highlights our pro forma balance sheet and maturity schedule.

In July, we received over $370 million of damages and interest from BOEM. Pro forma for these proceeds, our leverage was 2.8x as of June 30. The below our 3x target and well ahead of schedule. Excess cash on hand and availability available capacity under our undrawn credit facility, positioned us to call our nearest-term 2028 maturity at par.

As a result, we have no near-term maturities, and we have converted that debt into lower-cost prepayable debt on our credit facility while maintaining significant liquidity. This financial flexibility is critical into today's environment as we position Antero Midstream to execute on the large opportunity that Mike referenced in his remarks.

This flexibility and project opportunity set, in addition to our organic growth strategy, position us well to continue delivering shareholder value over the long term and enhance our return of capital to shareholders. With that, operator, we are ready to open up for Q&A.

[Operator Instructions] Our first question today is coming from John Mackay from Goldman Sachs.

Let's start on Eastside Express. Just wondering if there's a little more you can share with us in terms of CapEx expectations and the contracting side. Is this AR underwriting? Are you looking to get customers on the demand side to underwrite? Maybe just walk us through the spending and the return profile?

Yes, it's really AR underwriting, but it's $200 million to $300 million over the next 2 to 3 years. So think about kind of $100 million each year. I think at 7 interconnects with long-haul pipelines, big pipe, 1.5 to 2 Bcf a day.

So there will be opportunities, but solely underwritten by Antero Resources and its development plans, but with optionality to get third-party business and connect with all those different pipes.

That's helpful. And then maybe just looking broadly, you mentioned the several billion of opportunities. Maybe just walk us through some of the general buckets that could include -- is there anything in there that could kind of dovetail with some of the top saving initiatives that AR has been talking about? Or should we kind of think about this as pretty separate.

Yes. No, I think you've heard about all the different power plant, construction data center construction in West Virginia, that's capturing that from a midstream perspective, building these type of regional pipelines or laterals off of existing pipelines to those type of projects.

I referenced it on the AR call, but a decade ago, a good go buy the Stonewall pipeline. We had to farm that out. We don't have the ability to build that internally, whether from capital or expertise -- now that's not the case. We are the builder in this area of the world.

We have 1 million acres dedicated to us from AR. We have all these demand projects and power plants within that acreage or close to it. So we will be building those pipelines and laterals to those type of projects within the state of West Virginia.

Appreciate it. Maybe just a clarification. Is there a kind of time frame on that you can throw out there? .

No, we just said this is our first one that Eastside expressed. So that's over the next 2 to 3 years. That's a '28-'29 time frame. We're hopeful to announce more in the near term.

Next question is coming from Jeremy Tonet from JPMorgan.

Just want to pull back that several billion of CapEx opportunities as you said there. And it sounds like some of this could be servicing third parties beyond AR here.

And just wondering that part of the business -- how much opportunity do you see to grow as far as servicing other producers or just in general, moving beyond what AR provides.

Yes. I'm not going to project backlog right now, there's 15 projects. generally make that up all with the state of West Virginia. So that's what we're looking at Antero Midstream could be involved solely or more probability-wise, with AR's gas.

So we're way more comfortable what they are as a supplier of that AR, of course, we know exactly when they drill wells and where the gas goes and very confident in that throughput. So probably most likely associated with AR, but there are 15 projects on this list. I'm looking at right now and AR is probably half of them.

Okay. Got it. And then just moving towards water here, just wondering what opportunities on the water beneficial reuse side you might see there, given disposal cost, much higher in the Northeast versus Texas, does that create more incentive economic benefit to recycle here? Just wondering what that -- any updates there?

Yes. For AR, it's terrific. I have a close to the water system that is in a kind of cost plus 13% versus the kind of the disposal costs that you referenced. That's great for AR. Also great for AM because that closed loop system is the freshwater distribution where it gets nice returns both from a freshwater distribution and also from a what produced water disposal reuse case.

So really a benefit to both parties also allows AR to complete in that 14, 15, 16 stages range and not have water be a logistics issue. So very beneficial to both. We'll connect the HG system. We're connecting it as we speak. That will be what's responsible, and it could be more than this, but what we've talked about on the high single-digit EBITDA growth for '27.

That's just connecting the water systems to get the water down to the sheet area. So that will benefit us going forward in the '27 with the EBITDA growth on top of what we had this year.

Got it. That's very helpful there. And apologies if I missed the details on the AR call, but with regards to our generation investment, the governor is a 50 x 50 goal.

So clearly, a lot of appetite in state to develop new generation there. I'm just wondering, I guess, Antero's appetite to more fully, I guess, embraced that, that build-out going further downstream, what have you. Just any thoughts on that side?

Yes. We fully embrace that. We're the only investment-grade producer in West Virginia. That's focused solely on West Virginia. We are the midstream builder. We built everything up here over the last decade.

So you combine those 2, and we produce about half of the state's gas. So we would be a logical person to benefit or entities to benefit from that initiative government has.

Next question is coming from Sunil Sibal from Seaport Global.

Most of my questions have been hit, but I just had one clarification with regard to the opportunity to contract for the gas to ultimate consumer. So I was curious, when you're talking for those contracts, are you contracting with the power producers in the region? Or you're more focused on contracting with the data center entities per se?

It's all of the above, both. We're building the Eastside expression in Terra's development and where that's going and where the interconnects are and just the opportunity set in front of us, we want to get in front of that and be positioned well. So when these opportunities present themselves. We are positioned to deliver gas to them.

SPEAKER01

Next question today is coming from Ned Baramov from Wells Fargo.

Just wanted to go back to the time line for additional infrastructure or intrastate projects you're currently working on. I think you noted you plan to announce potentially other projects soon. Was just wondering if construction of these projects would potentially overlap with that of the East Side Express project?

Yes, not in '26, but 27 and beyond. That's probably a good assumption.

Understood. And then I guess, you mentioned the AR contracts on -- [indiscernible] will underwrite the project. I was just wondering if the contracts would be take-or-pay type of format? Or will there be volumetric exposure from AM's perspective?

Just acreage dedication from AR, but because we know where AR drills and the plants are drilling, that there's no need for those MVCs because we know the volumes will be there.

Understood. And then maybe one more, if I could. It seems that curtailments will be used a little bit more to better align the timing of production at AR with gas prices. Can you talk about the impact to AM's results? And does this imply that volumes going forward will have a little bit more pronounced seasonality?

Yes. No. I mean we're talking 50 million a day. I think AM gathered 4.1 Bcf. So it's about 1% for maybe one quarter of the year. So maybe you're looking at 0.25%. So that doesn't move the needle for AM.

We reach the end of our question-and-answer session. I'd like to turn the floor back over for any further closing comments.

Thank you, everyone, for joining the second quarter conference call today. If you have any follow-up questions, please reach out. Have a good day.

Thank you. That does conclude today's teleconference. You may disconnect your lines at this time, and have a wonderful day. We thank you for your participation today.

Greetings, and welcome to the Antero Midstream Corporation First Quarter 2026 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded.

It is now my pleasure to introduce Dan Katzenberg, Vice President of Investor Relations. Thank you. You may begin.

Thank you for joining us for Antero Midstream's First 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 anteromidstream.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 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.

Thanks, Dan. Good morning, everyone. I'll start my comments on Slide #3. The first quarter of 2026 was an exciting quarter for Antero Midstream as we continue to make progress on our strategic initiatives. We successfully navigated adverse winter weather conditions and delivered another quarter of EBITDA and free cash flow growth.

In addition, we closed the company's largest acquisition to date in February, which was ahead of our initial expectations. These achievements highlight 2 of Antero Midstream's greatest strengths, a world-class asset base in the lowest cost basin in North America and hard work and dedication from our team.

As we look ahead, recent geopolitical events and data center announcements highlight the significant demand growth for U.S. energy, both domestic and abroad. Given this outlook, we are focused on enhancing connectivity within our operating areas, particularly in the dry gas area and the newly acquired assets, and providing cost-effective integrated solutions for this demand growth. Our balance sheet, scale and integrated planning with our investment-grade producer position us well to capitalize on these growth opportunities.

Now let's move on to Slide #4 to highlight some of our 2026 growth projects. At the end of the first quarter, we commissioned our dry gas compression expansion depicted on the right-hand side of the page. This station utilized relocated and repurposed units to support our first dry gas Marcellus pad in over a decade.

During the first quarter, we also commenced our initial water system integration efforts. This capital investment connect Antero Midstream's water system to the acquired water system and is on track to be completed by year-end and will allow AM to begin servicing completions on the acquired assets in 2027.

Today, there are currently 3 rigs running on AM dedicated acreage, 1 on the rich gas system, 1 in the dry gas system and 1 on the acquired blended system. This balanced and consistent development program delivers low-cost volume growth and is expected to drive high single-digit EBITDA growth for the foreseeable future.

In summary, we are off to a great start in 2026, executing our capital-efficient growth plan. Beyond our base business, we continue to be active in opportunities to further extend and enhance that growth outlook to support the increasing demand for natural gas.

With that, I'll turn the call over to Justin.

Thanks, Mike. I'll start with our first quarter highlights on Slide #5. During the first quarter, we took over operations of our newly acquired assets right in the middle of Winter Storm Fern. As you can see from our results, we did not experience any outages during the storm, highlighting the benefit of integrated planning and communication between the upstream and midstream businesses.

Adjusted EBITDA for the first quarter was $288 million, which was a 5% increase year-over-year, driven by an increase in gathering, compression and processing volumes. During the quarter, we generated $192 million of free cash flow before dividends and $85 million of free cash flow after dividends, which was an 8% increase year-over-year. This cash flow was used to finance a portion of the acquisition and opportunistically repurchase shares on the open market. Importantly, even after a $1.1 billion acquisition and share repurchases, we exited the quarter with leverage in the low 3x range with over $800 million of liquidity.

Looking ahead to the next few quarters, we expect an increase in capital expenditures as we take advantage of improved construction season conditions in line with our full year budget. In addition, we expect to see gradual EBITDA growth throughout the year, driven by increasing gathering and freshwater delivery volumes. This cash flow profile results in declining leverage throughout the year towards 3.0x at year-end 2026, in line with our long-term target.

In summary, we continue to build on the growth and momentum from our organic investments in accretive acquisitions. These results place us on track to achieve our 2026 guidance, which remains unchanged and position us well for capital-efficient growth over the next several years.

With that, operator, we are ready to take questions.

[Operator Instructions] And our first question comes from John Mackay with Goldman Sachs.

Maybe we'll start on the kind of in-basin demand side of things. There's a couple of projects floating around, a lot of eyeballs on Monarch, et cetera. I know you guys are kind of too early, and you touched on this on the AR call as well. But do you mind kind of just framing up of what you guys could see the opportunity set for AM looking like here again? And if you want to use a generic kind of EBITDA per gigawatt or anything like that? Just kind of frame us up how you're thinking about the AM side of things here.

Yes. We're not going to use a generic metric there. But AM is participating in all of those because the vast majority of these need some infrastructure, laterals off existing pipe that Brendan talked about, water, some sort of infrastructure build-out from the existing infrastructure. And AM has got its seat at table of all those discussions because like I mentioned, we are the industrial builder of Northern West Virginia. We've built all of this infrastructure. It's all been a greenfield expansion for us from a gathering, compression, processing and water and it does help the whole system here.

So we are the builder of choice, and that's part of the attraction of what AR and AM bring is that integrated development between upstream and midstream. We have the resource and we have the ability to build the infrastructure.

Maybe just to clarify, any sense you guys could give on just kind of how long of a time line would be needed to kind of support a larger project?

Well, we're mainly talking about everything in state, so it wouldn't be that long of a time line. It would just be our typical kind of high-pressure build in year 1, 2, 3, not 5 years out.

Great. And then second question for me. You guys mentioned the kind of high single-digit growth target. Could you just frame that up a little bit around what that implies for AR's underlying growth? AR kind of came out with a kind of higher growth pace on the last quarter call. Just trying to figure out where that shakes and then again, kind of what the AM algorithm off that is.

Yes, that's off the base business. You get to the high single digit just from integrating the water system in '27. So just servicing ARs from a water perspective gets you that high single digit. If AR actually does pursue the 3 rigs, 2 completions and doesn't build DUCs and actually completes those, you'd be in excess of that high single-digit EBITDA growth in '27 and '28.

[Operator Instructions] Your next question comes from Ivan Scotto with UBS.

I wanted to ask for any additional color you have on how much capital is needed to fully integrate the acquired HG assets? And also how far along that process do you think you are at this point?

I think it's $25 million, probably halfway through, like I mentioned that the water system. We commenced that in the first quarter. That will be done by year-end. The other -- the gathering system was almost already fully integrated. I think it was $5 million to connect that. So it's really around the water, and we're in the midst of it and should be completed by year-end.

Okay. Great. And then just looking forward, where do you feel that most of your opportunity set is for incremental returns in the future?

I think it's around these data center, local power projects, our base business delivers very high rates of return. I think it's in the high teens, 20% return on invested capital in the base, and we've got that fully mapped out. We've built the whole backbone of the system, the whole water pipes, the large gathering system that we've got. I think the incremental returns will just be building off of that and building off of our relationship with AR and our own ability to build industrial projects in Northern West Virginia. That's kind of the next leg.

The base is terrific, high single-digit EBITDA growth we've had for quite some time and will going forward. But incremental growth and returns from that will be from these local demand projects.

And ladies and gentlemen, there appears to be no additional request for questions at this time. So I'll hand the floor back to our management team for closing remarks. Thank you.

Yes. Thank you for joining us on today's earnings conference call. Please feel free to reach out with any further questions. Have a good day.

Thank you. And that concludes today's call. All parties may disconnect.

Greetings. Welcome to Antero Midstream Fourth Quarter 2025 Earnings Call. [Operator Instructions] Please note, this conference is being recorded.

I will now turn the conference over to Dan Katzenberg, Director of Finance. Thank you. You may begin.

Thank you for joining us for Antero Midstream's Fourth 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 home page of our website at 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.

Thanks, Dan. Good morning, everyone. We recently closed the acquisition of HG Midstream for $1.1 billion. This bolt-on asset in the core of the Marcellus shale adds over 400 highly economic undeveloped locations dedicated to Antero Midstream that immediately compete for development capital and infrastructure projects in 2026. This asset is a strategic fit in AM's portfolio and will follow our just-in-time capital investment strategy that generates consistent and repeatable free cash flow.

Looking back at 2025, we generated EBITDA growth of 7% year-over-year, which marked our 11th consecutive year of growth since our IPO in 2014. Free cash flow after dividends increased by 30%, driven by capital efficient organic growth and throughput from AR. In 2026, this EBITDA and free cash flow growth continues as we expect 8% year-over-year EBITDA growth and 11% year-over-year free cash flow growth.

Looking ahead further to 2027, we expect another year of high single-digit EBITDA growth as we realize the full benefits of the acquisition and synergies, including the integration of the water system and AR running a 3-rig new completion crew development program on our dedicated acreage.

Justin will go into the details in his remarks, but the integrated water system, combined with our investment in dry gas assets, provides high visibility into growth at AM. Importantly, we can achieve this growth with very modest capital budgets, which allows us to further expand our free cash flow after dividends in 2027.

With that, I'll turn the call over to Justin.

Thanks, Mike. I'll start with our fourth quarter and full year highlights on Slide #4. Adjusted EBITDA was $285 million during the quarter, which was a 4% increase year-over-year, driven by an increase in gathering and compression volumes. During the quarter, we generated $85 million of free cash flow after dividends, which we used to reduce leverage to 2.7x and repurchased approximately $48 million of AM shares.

For the full year, we generated a company record free cash flow after dividends of $325 million, which is a 30% increase compared to 2024. This free cash flow growth driven by capital efficiencies from leveraging our existing assets, generated a 20% return on invested capital or ROIC in 2025.

Now let's move on to Slide #5, titled 2026 Capital budget. In 2026, we have budgeted a capital investment of $190 million to $220 million. The capital budget includes our blocking and tackling, well connect and water capital, construction and relocation of compression assets high-pressure gathering trunk lines and capital to integrate the water systems.

It also includes expansion capital on the dry gas portion of the acreage to enhance downstream deliverability to multiple long-haul pipelines. These projects will unlock significant optionality and improve reliability in the dry gas regime that we don't currently have today.

I'll finish my comments on Slide #6 titled 2026 guidance and outlook. This guidance includes the impact of the acquisition and divestiture with contributions to guidance based on closing dates of each transaction. For 2026, we are forecasting adjusted EBITDA of over $1.2 billion at the midpoint or an 8% increase year-over-year.

As Mike mentioned, after we finished the integration of the acquired water assets in 2026, we expect further growth in the water business in 2027, as we begin servicing locations on HG acquired acreage. After interest, a capital budget of $190 million to $220 million and an attractive $0.90 per share dividend we are forecasting to generate free cash flow after dividends of $360 million or an 11% increase compared to 2025.

Consistent with our historical approach, we expect a balanced return of capital program in 2026 in the form of debt reduction and share repurchases. This allows us to maintain a strong balance sheet with leverage in the low 3x range.

Core to AM strategy, the recent acquisition highlights the benefit of lower leverage and debt reduction, which allowed us to flex the balance sheet for the HG acquisition. This improves after tax accretion and more importantly, allows the value to accrete to our existing shareholders without the need for equity financing.

In summary, we expect 2026 to be yet another year of EBITDA expansion, high capital efficiency and most importantly, double-digit free cash flow growth. Our organic growth strategy coupled with a highly accretive acquisition that is fully financed, positions us well to build upon the momentum created in 2025.

With that, operator, we are ready to take questions.

[Operator Instructions] Our first question is from John Mackay with Goldman Sachs.

I want to start on the growth outlook. I understand '26 and '27 have some tailwinds from M&A in the headline numbers. Could you just walk us through a little bit what the kind of longer-term growth trajectory looks like, let's say, once the assets are kind of fully up and running, if you guys are running a 3-rig and 2 crew program.

Yes, John, good question. That 3-rig, 2-rig program does provide continued growth even past '27. It's about a couple of hundred million a day of growth on throughput volumes. So expect that to continue. So I think it'd still be in the mid- to high single-digit EBITDA growth like we've experienced over our time, our last 11 years and will have in '25 and '26. I think that's pretty fair to have us generate those type of growth in '27 and beyond.

That's clear. I appreciate it. And then on the AR side, you guys were talking about some growth upside plans. Could you just -- and you gave the color on the AR call, but maybe just again, like walk us through the thought process there. And then what that means for AM both from an EBITDA growth standpoint, but also a capital standpoint if you move to that higher potential target?

Yes, that's a great thing about it. There's really no capital for AM outside of what we just outlined, Justin did. It's right in the heart of our field. We already have all the big trunk lines. We have whatever pipelines are necessary. We have the water. A lot of this is dry gas. So it doesn't need a further processing. So really nothing different than these capital budgets that we've experienced over the past couple of years for AM.

For AR, AR is well positioned, partly because of AM, but also because of firm transport optionality around dry gas being in the right part of the country, but also having the ability to transport our gas to the Gulf Coast for the LNG. So a lot of different demand centers coming AR's way. So AR is the likely company and most well positioned to meet the growing demand over the next 5 to 10 years.

There are no further questions at this time. I would like to turn the conference back over to Dan for closing remarks.

Thank you, everyone, for joining us on the call today. Please reach out with any questions that you have a good day.

Thank you. This will conclude today's conference. You may disconnect your lines at this time.

Greetings, and welcome to Antero Resources and Antero Midstream Corporate Update Call. [Operator Instructions] Please note, this conference is being recorded.

I will now turn the conference over to Justin Agnew, CFO for Antero Midstream. Please proceed.

Thank you for joining us for our call to discuss Antero's strategic transactions announced earlier today. We'll start by providing an overview of the transactions, 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 and www.anteromidstream.com, where we have provided a separate investor presentation that will be reviewed during today's call.

Today's call may contain certain non-GAAP financial measures. Please refer to our press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; and Brendan Krueger, CFO of Antero Resources.

With that, I'll turn the call over to Mike.

Thank you, Justin, and good morning, everyone. I'll start on Slide #3 titled Strategic Transactions Strengthen AR and AM. Earlier this morning, we announced that Antero is acquiring West Virginia Marcellus assets and divesting noncore Ohio Utica assets.

On the acquisition, AR will acquire the upstream assets for $2.8 billion and AM will acquire the midstream assets for $1.1 billion. On the divestiture, AR is divesting the upstream assets for $800 million and AM is divesting the midstream assets for $400 million. The acquired assets include 385,000 net acres and approximately 850 million a day of production. The assets include over 400 undeveloped locations with high net royalty interest while also benefiting from average lateral lengths of over 20,000 feet.

Now let's move on to Slide #4 titled Acquisition Rationale. Today, the acquisition is a hand-in-glove fit with our legacy footprint. The assets add over 400 drilling locations in the Marcellus core that will immediately compete for capital, approximately 75% of which are liquids-rich. The existing PDP production provides us with dry gas optionality for local power generation and data centers.

Given the significant acreage overlap, we estimate there are approximately $950 million of synergies that are achievable only by Antero. These include tangible D&C cost savings, development planning and marketing synergies. This transaction also highlights the benefits of the AR, AM structure with AM acquiring the midstream business and providing additional operational benefits. The acquisition reduces our cost structure by approximately $0.25 per Mcfe and increases margins by $0.15 to $0.20 per Mcfe. Lastly, this transaction is highly accretive to our operating cash flow, free cash flow and NAV per share metrics.

Now let's move on to Slide #5 titled Fully Financed Strategic Acquisition, which summarizes the transaction financing for the $2.8 billion purchase price for AR. First, we expect to generate approximately $500 million of free cash flow between now and closing at the start of the second quarter of 2026, taking advantage of near-term winter pricing.

The divestiture of our noncore Utica upstream assets for $800 million prefunds another significant portion of the acquisition. The remaining financing of the acquisition will be a 3-year Term Loan A, which we expect to pay off with hedged free cash flow from the acquired assets.

We have already locked in NYMEX and basis hedges for substantially all of the acquired production in 2026 and 2027 that results in attractive margins of over $2 per Mcfe and a visible pathway to debt reduction. Importantly, we are essentially funding this acquisition through divestiture proceeds and free cash flow from the acquired business itself. That means all of the expected free cash flow from our base business and potential synergies from this transaction will be available for further debt reduction and return of capital to shareholders. We will continue to be opportunistic on our share buyback strategy, and this transaction enhances this ability with more stable and increased cash flows.

Turning to Slide #6, let's look at Antero's pro forma production and capital outlook. Starting with the production table at the top of the slide. We began 2025 with a maintenance production program targeting approximately 3.4 Bcfe per day. Following the acquisitions executed during the third quarter of 2025, the production target increased to approximately 3.5 Bcfe per day. Today, after adjusting for the Utica divestiture and the Marcellus acquisition, a 2026 maintenance program would be approximately 4.2 Bcfe per day.

This level could increase further if we elect to run the program without a drilling partnership in 2026 and/or if we add any growth capital to our '26 development plan due to local dry gas demand. As you can see in the far right bar, any increase in capital in '26 would drive roughly a 1:1 increase in net production for 2027. So if we invest an incremental $100 million, we would grow net production by roughly 100 million per day.

On the capital side, we have stated for the last several years that our maintenance capital target is approximately $700 million. Including our third quarter 2025 acquisitions and the transaction announced today, the pro forma maintenance capital target would increase to approximately $900 million. As depicted on the far right of the slide, we have further flexibility to increase our net production by electing to move forward without a drilling partnership and/or adding growth capital that would bring our total capital anywhere from $1.1 billion to $1.2 billion.

Before turning the call over to Brendan for more details on the synergies I mentioned earlier, I wanted to provide one specific example of development plan optimization synergies laid out on Slide #7. We selected this pad as it's already been publicly filed for a pooling application in West Virginia and is slated for development in the 2026/2027 time frame. The map on the left shows the pad development of pre-acquisition for both Antero and HG. While the map on the right shows the pro forma development of the same pad. Instead of capital invested to build 2 pad sites and drilled 10 wells with average lateral length of 9,500 feet, this leasehold can now be developed from 1 pad with 5 long laterals averaging nearly 20,000 feet.

From just this pad alone, the PV-10 value increases $30 million and the IRR increases from 47% to 81%. This is just one example of many all along the southern border of our legacy acreage. This overlapping acreage position provides clear, easily attainable synergies that can only be recognized by Antero. I'll now turn it over to our CFO, Brendan Krueger, for his comments.

Thanks, Mike. I'll begin my comments on Slide #8. This slide highlights the identified synergies of approximately $950 million on a PV-10 basis over the next 10 years. On the capital side, there are over $500 million of estimated drilling and completion cost and development optimization synergies. Due to HG's assets directly offsetting Antero's legacy position, there are substantial overlapping leasehold positions that when combined result in longer laterals and reduced civil spend from pad and road capital savings.

These development plan savings are compounded by a faster and more efficient drilling and completion base on a large contiguous and long lateral development program. In addition, we expect significant D&C cost savings from scale, including reduced sand, fuel and chemical costs, to name a few. Next, we expect to integrate HG's production into AR's firm transportation portfolio. This will allow us to fill legacy unutilized capacity and optimize the FT portfolio to drive better price realizations and lower our net marketing expenses, improving both the top and bottom lines by $140 million on a 10-year cumulative PV-10 basis.

Justin will touch on it in a minute, but AR also expects substantial water handling savings as a result of AM investing capital to connect the assets to AM's water system. This is expected to result in a reduction in completion gaps and associated water handling expenses.

Lastly, by using the Utica proceeds to immediately purchase another asset, we realized tax benefits structuring it as a like-kind exchange, which combined with other smaller synergies result in another $185 million in savings. In total, these result in PV-10 savings of $950 million over 10 years or over 30% of the total transaction value, highlighting the value creation that this transaction delivers for our shareholders.

Now let's move to Slide #9, titled Conservative Underwriting With Compelling Valuation. Mike already highlighted that this acquisition is over 30% accretive to operating cash flow, free cash flow and NAV per share. Looking more closely at the purchase price, the acquisition was completed at less than the combined value of the PDP and the work-in-process wells. This conservative underwriting provides material upside from synergies and undeveloped locations essentially adding highly economic inventory and no incremental costs.

Next, let's discuss the balance sheet on Slide 10. As we have proven over the last 5 years, we are committed to maintaining low absolute debt levels. We expect our investment-grade ratings to be reaffirmed by the rating agencies. Based on the current commodity strip, we also expect to be below 1x leverage in 2026. To protect our free cash flow outlook, we assumed HG's hedge book and have approximately 90% of HG's production hedged over the next 2 years. Further, financing the transaction with a 3-year term loan highlights the high confidence we have in the acquired asset free cash flow profile over the next several years, which is supported by these hedges.

I'll echo Mike's comments from the outset that we are extremely excited about the outlook for the Antero family. The highly accretive nature of these transactions will drive substantial enhancement to our free cash flow outlook and position Antero to capitalize on the significant demand outlook for natural gas in the years and decades ahead.

I'll now turn it over to Justin Agnew, CFO of Antero Midstream.

Thanks, Brendan. As Mike mentioned, this acquisition highlights the complementary structure of AM acquiring assets alongside AR that fit the traditional risk and fixed fee return profile of a midstream company. As you can see on the map on Slide 11, the acquired midstream assets consist of approximately 50 miles of East-West gathering pipelines in dark green adjacent to the Antero Midstream's existing assets. This close proximity allows us to integrate the gathering assets almost immediately.

The transaction also includes strategic water pipelines and storage assets that we plan to integrate into AM's water system throughout 2026. In combination, the capital required to integrate the acquired assets with AM's legacy assets is only $25 million. In addition, the trunk lines of the gathering and water systems are fully built out requiring ongoing capital of only $25 million per year at a maintenance capital level.

Moving to synergies and savings on the bottom left. We have identified over $100 million of capital avoidance synergies on a PV-10 basis. This includes approximately 30 miles of avoided gathering pipeline build, 20 miles of water pipeline build and other savings that correspond to the same land and civil synergies identified at AR. In addition, AM expects to utilize bonus depreciation immediately on the acquired assets, deferring approximately $50 million of cash taxes on a PV-10 basis, net of the impact of the Utica divestiture.

In summary, today's acquisition provides scale at an attractive 7.5x acquisition multiple over the next 3 years, significant synergies, low capital intensity and an increasing EBITDA profile. In tandem with the Utica divestiture, which was divested at a multiple over 11x for a declining asset, today's strategic announcements result in a combined multiple of 6.5x, excluding synergies.

I'll finish my comments on Slide #12 titled Transactions Strength Outlook at AM. Today's acquisition high-grades Antero Midstream's asset base and can be debt financed, given our strong balance sheet. Looking ahead, we expect leverage to decline below our 3.0x target in 2026. This is a testament to our just-in-time organic growth strategy supplemented by several immediately accretive bolt-on transactions. The peer-leading return on invested capital positions us well for additional debt reduction and return of capital to shareholders.

I will now turn the call back to Mike for closing remarks.

Thanks, Justin. I'll close on Slide #13 titled HG Acquisition Accelerates Antero's Strategic Initiatives. On our third quarter 2025 conference call, we detailed our key strategic initiatives going forward. Today's transactions make significant progress toward all of the goals we highlighted. It expands our core Marcellus position in West Virginia by adding 385,000 net acres and over 400 drilling locations. This extends our core inventory life by approximately 5 years, assuming a maintenance capital development plan. The acquired acreage increases our exposure to dry gas, strengthening our position for future dry gas development. We added hedges to lock in attractive free cash flow yields, providing high confidence in our free cash flow outlook over the next several years. In addition, this transaction meaningfully reduces cash costs, by approximately 10% and expands margins, lowering our peer-leading breakeven price. Lastly, it highlights the benefits of Antero's integrated structure with Antero Midstream.

With that, I will now turn the call over to the operator for questions.

[Operator Instructions] Our first question is from Kevin MacCurdy with Pickering Energy Partners.

Congratulations on the deal. I guess I wanted to start off maybe on Slide 6. You present an option for a growth plan. And I wonder if maybe you can just talk about that, the puts and takes on that decision and what would make you kind of pursue growth into 2027?

Yes, Kevin, we talked on the third quarter call, we just spud our first dry gas pad over a decade, [indiscernible] pad and kind of a proof-of-concept. And really, it generated what we thought were a lot of calls from local demand, gas demand from data centers from power generators and kind of opened up a lot of opportunities or just kind of put us in play more squarely in play for the West Virginia local demand. So if that materializes over this time, you could see us continuing that plant or that rig in that area and further increasing our dry gas there for the local uses.

Great. Appreciate that. And maybe can you talk a little bit about the development plan on this asset? You mentioned $200 million of capital in 2026. Are we right to think that's probably like 15 to 20 wells? And will you be immediately shifting the focus to the wet gas? Or does that require some prep work?

Yes. It's about 20 wells, a little on the high end, but yes, it's about approximately 0.75 of a rig line. But just think of us now as a 3-rig company instead of a 2-rig company. And initially, on the dry gas a little bit more focused just because that's what they're drilling right now and the pads they have ready, but they do have some liquids pads as well. So it will be a mix of both.

Our next question is from Leo Mariani with ROTH Capital Markets.

I wanted to ask a bit more about the synergies here. I see you guys have kind of put that in here on sort of a PV basis, not sure how you're kind of discounting that. But could you give us kind of an annual number? And I know you guys are saying that the deal should close around April 1. Just anything on kind of the time line of the synergies you expect those to start to be relatively immediate post closing.

Yes. I'll use my one example on the slide and then I'll kick it over to Brendan for a little bit more detail, Leo. But this is the one the southern and kind of Southwest portion of our acreage is overlapped with HG just basically hand-in-glove like the title suggested on that slide. And so there is immediate synergies. We wanted to highlight that one pad. It's a 1223 North pad for HG and our [ little buck ] pad going south because that was a public pooling application that really showed that the synergies that would come from having one developer of this acreage versus two. So that is immediate. So that was $30 million of capital, at least in the '26, '27 time frame. But that type of example exists throughout the southern portion of our acreage because it [ borders ] HG's. But with that, I'll kind of kick it over to Brendan for a little more detail.

Yes. Thanks, Mike. Yes. I think, Leo, just to talk about details a little bit more, talking about D&C savings. I think we hit on a few of these sand savings. We expect to be about $10 million to $15 million a year. The chemicals and fuel same story in that $10 million to $15 million a year. So when you look at overall D&C savings, we expect to be in the $40 million to $50 million a year. Now we expect all of this to kind of ramp up over time. But on the D&C, call it $40 million to $50 million a year.

On the development planning, as we get into the undeveloped portion of this beyond the work-in-process wells, so call it in that '28, '29 time period, we expect another, call it, $50 million to $60 million a year as a result of development planning optimization. And then as we look at more of the, what I'll call, the EBITDAX/income synergy. So if you're looking at that Page 8, the EBITDAX income related, the marketing is really driven by the ability to flow some of the gas that HG is flowing today into unutilized transport that we have. That's about $15 million a year so that we would expect to be able to integrate fairly quickly here.

The water handling, that's a result of the flowback water that we have. If you looked at our forecast prior to HG, that flowback water, we would have had to truck some of that to far distances. So that incremental trucking costs will now be reduced because we will be able to reuse with that third rig that Mike mentioned. So that's what's driving the water blending. And then the tax just due to the like-kind exchange, I think we mentioned in the prepared remarks, that will defer about $85 million of taxes as a result of that like-kind exchange and then there's a handful of just other smaller synergies in that bucket. So if we brought all that together, it's about, call it, $50 million a year, first year, $100 million a year by year 2, year 3 and then $150 million a year beyond that time period. So I know a long-winded answer, but hopefully, that gives you a little more color on the synergies we see here.

No, that was great color, for sure. And I just wanted to also ask about the buyback. You referenced this in your prepared comments that you guys would continue to be opportunistic. It certainly makes sense. But as also you've noted, the leverage is going up some in the near term, but a lot of that's going to be hedged free cash flow and pay off debt. So is there any shift at all in thinking on the buyback where you might be a little bit more conservative as you're paying off debt in the next couple of years? Can you just provide a little bit more color around your thinking around that?

No, no change to that. We'll continue to be opportunistic. That's how we've always talked about it, Leo, wherever the opportunity is. In fact, I think this probably enhances our ability because we always want to try to be countercyclical on this. So adding this portion of hedge free cash flow and the substantial amount that we added really adds to our kind of stable free cash flow profile on a go-forward basis, whereas in the past, it was always subject to commodity prices.

So when the share -- the buyback opportunities would be, you'd have low commodity prices and you wouldn't have that free cash flow, whereas now we've kind of locked in these $2-plus margins on this 775 million to 800 million a day of gas for '26 and '27 hedged back to the basis as well. So we feel a lot more confident to be countercyclical and opportunistic on the buybacks. So we'll just continue and be, like I mentioned, opportunistic on what's best to either reduce debt or buy back shares over the next couple of years.

Our next question is from Jacob Roberts with TPH.

I was wondering if you could speak to the base decline assumptions on the acquired assets. I'm not sure if I missed it, if you could break down the hydrocarbon mix of that asset and where you see that mix corporately in 2026, please?

It's fairly similar to AR, but I believe it's 10,000 to 12,000 barrels a day of NGLs and the rest is dry gas. So you can see on our hedge profile, we hedged -- of the 850, we hedged 775 over the next 2 years. So remaining is liquids and then it goes a bit higher after that as you begin to develop the more liquids acreage of HG. So -- and then the decline is similar to ours. They face a lot more back pressure right now than we do. So there's a lot of ability for compression optimization that we should be able to manage that, but our decline rate is in the mid- to low 20s.

Great. And maybe pulling on that thread a little bit. Looking at Slide 17 on the GP&T cost reductions. Is that predicated on a certain dry gas percentage? And to your point, if you shift more liquids weighted in maybe a 2027-plus time frame, is that number moving higher?

It wouldn't move a tad higher, but it's not material. This is pretty indicative of where it will be for the next 5 years.

Our next question is from Josh Silverstein with UBS.

Can you just talk about how the added production may help you in potential power or some sort of industrial supply discussions you may be having within the basin?

Yes. We didn't highlight this in this slide. But now I think we produce over half the total production in West Virginia, which is getting a lot of investment or a lot of looks for investment based on their microgrid bill and their kind of push to get more and more natural gas demand locally in the state. So I think we were the #1 operator by far, around 35% to 40% of the total state. HG was #4 in combination, now will be more than half of the total production in the West Virginia state. So if there's any investment there, we will be definitely a strong counterparty for that.

Got it. And then I was just curious on the $0.15 to $0.20 margin reduction. This is mostly on the GP&T side. Can you just talk about how much of this is HG selling in basin versus having capacity charges? And I know you mentioned there was maybe some shift towards more dry gas drilling, which reduces some of the, I guess, processing fees there.

Yes. No, it's all in basin. But the way to think about it, we were kind of going off a $4 strip. We hedged the basis $0.80 back, you're at $3.20, but then you're at 1,100 Btu gas that gets you in the $3.50 range and then the liquids uplift gets you to $4. So you get $4 kind of realization all in and $1.50 all-in cost. So you got a $2.50 margin on these HG volumes, and that's how you get that $0.15 to $0.20 margin improvement.

Our next question is from Kalei Akamine with Bank of America.

My question is on acreage delineation. And kind of looking at the well results, HG's activity has been concentrated into one pocket of a large 385 net acre position that you guys call out. What is the exploration risk that you associate with the 400 drilling locations here? And is the acreage all held?

Yes, over 90% HBP, but that's 2 wells, the Riddle well and the Goodnight well on the far western portion of their acreage, which shows, I think, the 1.3 Bcf per 1,000 about the liquids 1,300-plus Btu. So those are terrific wells. And that's far out on their western portion of their acreage position. So the delineation is there, along with our 1,500 wells. So we feel really good about their acreage position, a delineation of the wells, and it's all HBP.

For my follow-up, can you simply talk about their working interest and whether that changes throughout the position and what the royalty rates are?

Yes, that's another attractive profile. Very high working interest, but the NRIs because it was a storage pool is 85% to 86% over the next 5 years what we're drilling from HG. So accretive there.

Our next question is from Neil Mehta with Goldman Sachs.

As part of this, Mike and team, you guys announced the divesting of some noncore Utica. And can you just talk about are there other opportunities for noncore portfolio monetization as we think about you continuing to move south in the portfolio?

Yes. No, Neil, this is pretty much it. The Utica, like we mentioned in the materials, we only have 3 wells in the next 5 years planned, and that's right now the English pad. So to divest a noncore asset that you weren't developing and to redeploy those proceeds into this asset where you'll actually run 1 rig and drill 20 wells per year is terrific. So that's pretty much all we have. We're now solely a West Virginia company with a highly contiguous over 800,000 acreage position running 3 rigs and producing 4.2 Bcfe a day.

Then can you just spend some time on Slide 7. It does seem effectively, you're doubling your lateral length here in the pro forma development profile. So just if you can unpack that for us and what it means for the business? And any risk associated with the approaching the pads this way too?

No, our legacy program, we're able to do 13,000 to 14,000 feet. HG had the ability to basically have one row of midstream and drill north and south and perfectly optimize it to 20,000 feet going both north and south across that storage pool and their acreage in that southern acreage position. So we'll continue to do that. So we'll have 1 rig being able to obtain 20,000 feet laterals for our program and the other 2 will be 13,000 to 14,000-foot laterals.

Our next question is from [ Subash Chandra with StoneX ].

Does this acquisition change your C3+ production profile at all?

A little bit. I mean we are at total liquids of 200,000 barrels a day and about 2.3 of gas, that's what made up to 3.5. That will be 2.15 of the liquids of the 4.2, so it goes from 35-ish percent to 30%.

Okay. Yes. So yes. And I guess the BTU levels of the HG acreage are comparable?

They are. Yes, the curves go across their acreage just like it does ours.

Okay. Got it. And just to clarify on the OpEx number. We will see a $0.15 to $0.20 benefit to cash costs in the income statement.

No, that's the margin hasn't. The actual -- we have a slide out there with slide, Brendan?

Page 17.

Page 17 outlines that there is a $1.50, so in combination, we go down $0.25 on the cost structure from $2.68 to $2.43.

And most of that is all in that [ GP&T ].

Okay. Yes, I see it now. Okay. Yes. And I guess, one last one. So the -- I don't know if you want to comment on this, but what do you attribute to that variance in the multiple on the asset you sold especially?

Well, I think they're going to grow it. I mean it was a build-to-grow asset for them. We weren't going to develop it. We were focused on the Marcellus, but everything was there, the acreage, the infrastructure and their Utica focus. So a company I was going to focus on the Utica and grow that asset whereas we are focused on the Marcellus, and we were going to grow that asset.

Our next question is from Betty Jiang with Barclays.

I have a broader question. Maybe just on the M&A strategy in general. It's a -- with this deal, it's one of the largest in recent memory for Antero. And before that is the PDP acquisition, which I understand is different. But certainly, the company is getting more active on the M&A side. So do we see this as a strategy to lean more into M&A and seeing AR as a consolidator going forward? And where do you see opportunities around your acreage from here?

No. But I think we just were capitalizing on opportunities that presented to us at the time. We are the liquids developer in the Marcellus. We are kind of the West Virginia oil and gas company as well. So when you look at a map of West Virginia, with the liquids acreage, we should be developing that with the platform that we have. So we just took advantage of that. If there are further opportunities on that map, in and around our West Virginia acreage position, we'll take a look at them, but I think these just came about at these times.

Got it. And then a question on Drillco or drilling JV decision into next year. I'm surprised you have not made that decision yet, just given the higher gas price and it seems strategic to forgo that JV at this point. Just what's your rationale and the decision point around that?

No, exactly that. I think it really speaks to the high quality of our asset and there's no variability in our wells. So if someone looks at a drilling JV, they have high confidence in what it's going to deliver. So those decisions can be made on a very timely basis and very quick just speaks to the high-quality nature of our asset. We obviously can wait and hold that optionality for ourselves. And with today's transactions, I would assume we probably are not going to do one just with how strong we are and how strong the quantity prices are and the returns and our profile I think you'll see us right now, all things else being equal, that we'll probably not pursue a drilling JV.

Our next question is from Ned Baramov with Wells Fargo.

I guess, could you talk about how the gathering and compression fees for the HG acreage compared to those fees on the legacy acreage and whether there is a potential optimization angle for AR in its future development plans, if there is a gathering and compression fee advantage in developing one acreage versus the other?

No, they're the same. The only difference is HG has on-pad compression versus centralized compression for AR. So that's the only difference. You saw that in the 8-K. We did amend the agreements to allow for on-pad compression, but that's just for HG pads over the next couple of years.

Got it. And then maybe can you share a bit more on the key sources of midstream annual synergies similar to how you laid out the upstream synergies in response to an earlier question?

Yes. Ned, this is Justin. It's about 30 miles of avoided gathering pipeline in 20 miles of water pipeline essentially shorter geographic builds, either connecting future areas of development to their system versus ours or in specific areas where you have significant acreage overlap that Mike kind of touched on, you're essentially building 1 row of pads versus kind of 2 rows of pads drilling towards each other. So it's really all identifiable capital avoidance based on specific mileage.

Our next question is from David Deckelbaum with TD Cowen.

Congrats on the deal, guys. Mike, I'm curious, I know I'm hopping on a little late. I'm curious how this deal sort of impacts your outlook for land spend over the next several years. If we should be at the same sort of absolute level or if you anticipate that there's going to be a lot more kind of leasing opportunities your way now with a substantially larger...

So at or lower, David. This obviously adds significant acreage in that liquids area, which is the future liquids development of our company. And so now that we've acquired that should result in lower going forward in that area. We may still be active in maybe other areas, maybe a little more in the dry gas areas. So that $100 million kind of placehold that we have each year is probably still a good number, but it's just a bigger enterprise.

I appreciate that. And then maybe just on the marketing synergies. I know you all identified $140 million of 10-year savings related to marketing. I guess is that included in there? Should we think about that as reallocating some of the acquired volumes from in-basin end markets looks like they're at M2 and Dom South, like to some of the firm transportation portfolio that you have. Is that sort of the calculated ARB that you have now?

Yes, there's a bit of that. So we had some just due to how we had structured our firm transport portfolio over the years. We had portions of our capacity that was unmatched essentially is what we call it. And so by integrating some of the production from HG that was just being sold locally, we can move it into that unutilized portion. And so number one, you don't have that unutilized portion, but you'll also get a pickup in price relative to what HG was selling at before. So that's essentially what it is, David.

Our next question is from Carlos Escalante with Wolfe Research.

So incorporating the 90% of your -- of the hedging from HG into your '26 portfolio, wondering how you plan to move forward with hedging as a whole on the gas side, considering now you have that moving part in your overall realizations and if that should be something we consider you do more of in '27 and beyond?

Good question, Carlos. Obviously, we've got a lot of hedged in '26. So I think we're pretty good there. '27 when you look at that 3 Bcf of gas, we talked about the 775 plus the previous 100 we had, we have 875 kind of swapped in that $4 level. We've talked before about being 25% swaps and then 25% wide collars. So we're done probably with swaps for '27, but you could see us add maybe 20% wide collars now like we did in '26.

Got it. Makes sense. And then as a quick follow-up. Just looking at the type curves comparing yours to HG's, you have much better productivity, but the yields look to be the same from an NGL and liquids perspective. Maybe you got a little more of that. Just wondering what is the key difference in your completion style that you plan to implement outside of just longing and making your laterals longer?

The longer laterals really help the economics off of the NRIs. The net royalty interest we're talking about being in that 85, 86 versus our 82 to 83 really kind of evens it out and when we look at their EURs, we're in the 1.8 to 1.9 Bcf per 1,000 for them, HG and we're more in like the 2.0. So it's not terribly different. And then NRI and the longer laterals even that out. So from an economic standpoint, very comparable. And that's why we mentioned it will compete heavily for capital in our development plan going forward.

There are no further questions at this time. I would like to turn the conference back over to management for closing remarks.

Thank you, everybody, for joining today's conference call. Please feel free to reach out with any other follow-up questions.

Thank you. This will conclude today's conference. You may disconnect at this time, and thank you for your participation.

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.

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.

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 it 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 at 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 interests, which were already gathered by AM as well as additional core acreage. The acreage acquisition was undedicated to a midstream provider and results 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 investment of $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 unlock significant low-cost inventory across the liquid-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 the 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 returned 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.

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. .

Freshwater 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 declining capital resulting 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 taking our leverage down wells to half a 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.

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

Just wanted to turn to the topic of in-basin demand, specifically as it relates to the potential for behind-the-meter opportunities in I believe Antero 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? Wondering how this all mixes together? .

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 1 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 grant 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 natural gas production in the state highly integrated with AM, Antero Midstream has the water system that is invested about $600 million in. So a 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.

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? .

There's just 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 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.

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?

Yes. Antero Midstream was early in doing all these bolt-on acquisitions is really consolidated to play. And so we bought the Crestwood asset, which is the dry gas kind of portion in 2022, but 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.

And the next question comes from the line of Ivan Sato with UBS. .

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? .

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 in HP. So incrementally, maybe $10 million.

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

Yes. Good question. I think for now, we're still focused on debt reduction and repurchasing shares. We've got 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 provides you with a lot of flexibility, and you saw the benefit in terms of refinancing the notes. So I think that looking forward, it's still going to be that balanced approach, roughly 50-50 of share repurchases and debt reduction.

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

I wanted to touch on some of these comments around drilling into where AM [indiscernible] 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 plans 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 AR production come down if you're moving into those windows? Or is this again kind of, hey, we'll see how we develop the dry side?

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 to be much lower, obviously, because we already have it structure in the region.

And maybe just a follow-up to that is, I mean, you are calling it a proof of concept. I guess this is this a comment on your side on the liquids outlook and more enthusiasm for the dry side? Or is they say, 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?

Yes. So that kind of in-basin based, 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 backward dated oil curve. And so that would suggest that dry gas has become more economic on a relative basis. So that is something that is optionality for us from both midstream and upstream. So the proof of concept is really for the -- in local demand. But at the same time, it could be a portfolio approach as well.

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

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

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