Antero Resources Corporation Stock

Greetings and welcome to the Antero Resources Corporation Second 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's Second Quarter 2026 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 anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to the earnings press release for important disclosures regarding such measures.

Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; and David CAnnelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing.

I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'll start on Slide #3 titled Structural Margin improvement at Antero. This structural improvement has strengthened our financial performance and, importantly, reduced earnings volatility. The results of this strategy can be seen in the table on the right side of the slide, while Henry Hub natural gas prices were down 16% from a year ago, the impact of increased scale product diversity and lower cash operating expense led to our adjusted EBITDA increasing 57% over that period. The structural and sustainable improvements in our business will reduce volatility in our future cash flow.

Staying on the topic of cost reductions, let's turn to Slide #4 titled Significant reduction in cash costs. The cost reductions we realized during the second quarter was just the beginning of a lower cost at Antero. In June, we announced a cost reduction initiative that will significantly improve our margins. We are forecasting our cash cost to decline by over 25% in 2025 to year-end 2028 to $2 per Mcfe. This dramatic change in our cost structure will be achieved as our company evolves from being 100% liquids development and 100% out of basins product sales to a much more balanced, rich and dry gas development program as well as having sales in basin and out of basin.

This shift in strategy that increases our exposure to dry gas and in-basin sales is supported by the surge in new regional demand. This higher regional demand is expected to occur at the same time that many of our firm transportation commitments come up for renewal. To be clear, much of our LNG fairway directed firm transport is attractive and will be retained. However, as we shift from the producer push era to the demand pull era, we are uniquely positioned to review each flow path and choose the highest margin sales point and supply contract for our natural gas and NGLs.

Next, on Slide #5, we provide details on our margin enhancement. The $0.70 improvement in our cash costs will be partially offset by $0.35 and lower price realizations as we sell more product in basin. This assumes strip pricing for in-basin differentials without any tightening of basis that could occur when regional demand starts to ramp up. In the chart on the right-hand side of the slide, we break out the $300 million of annual margin improvements in the 3 categories. First, we have 2 financial transactions that we entered into early this decade that come to an end. The overriding royalty interest transaction and the VPP.

The overriding royalty interest transaction return threshold to the counterparty was met in the second quarter, leading to the Martica entity being dissolved on June 30, resulting in an increase of $60 million of annualized cash flow beginning in the third quarter of 2026. The VPP will expire in July of '27 and result in a $30 million annualized cash flow uplift. Second, optimization of our liquids firm transport is forecast to improve margins by another $105 million. This includes limited needs for recontracting of ethane transport as well as the refinement of our LPG firm transport. The enhancements to our liquids margin structure are expected to be realized at the end of 2028.

And third, the remaining $105 million of margin improvements for '28 will primarily come to optimizing our natural gas firm transportation portfolio and increasing dry ad development. The increased demand for natural gas is shifting the market from a producer push market to a demand pull market. This is expected to drive meaningful improvements in our overall natural gas netbacks. These are exciting times for Antero and the natural gas industry in Appalachia. We are encouraged by the power deals have been publicly announced to date as they further validate the significant regional demand growth that we are expecting. We continue to be actively engaged in conversations with all of these projects. However, Antero approaches these negotiations from a uniquely advantaged position.

We hold optionality as we already sell our volumes at premium prices along the LNG fairway and are the second largest NGL producer in the country, which provides margin uplift. This means that local power projects must compete with the broader energy markets on returns to attract our volumes. This compares with many of our peers who lack the firm transportation portfolio or lipids production and are looking for projects for nearly 100% of their production. These attributes allow us to be highly selective in which projects we ultimately partner with. The projects that we elect to participate in will have to be accretive on a risk-adjusted basis, which includes pricing, timing and certainty.

Now to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave CAnnelongo for his comments.

Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing Antero achieved during the second quarter of this year. Antero's realized C3+ price was $44.26 per barrel up $6.41 per barrel compared to the second quarter of last year and our highest quarterly realized price since 2022. Liquids prices continue to be influenced by geopolitical events as uncertainty remains over the flow of products through the Strait of Hormuz and other critical transit routes. U.S. liquid supply has been called on by international buyers looking to replace Middle East cargoes.

As shown on Slide #6, U.S. propane exports averaged 2.03 million barrels a day during the second quarter of 2026, an increase of 170,000 barrels a day compared to the same period last year. Additionally, propane exports hit a new weekly high of 2.63 million barrels a day this May with another weekly export number also above 2.6 million barrels a day reached in July, according to the EIA. These new highs surpassed the previous record by 300,000 barrels a day and demonstrate that the U.S. can reach previously unseen export levels, driven in part by recently added terminal capacity. Additionally, exports of normal butane reached a new monthly record of 815,000 barrels a day in April, the most recent month of EIA data, surpassing the previous record of 661,000 barrels a day set in March.

The record levels achieved for both LPG products since the start of Epic Fury illustrate that propane and butane are fiercely competing for terminal space to backfill loss Middle East supply across demand markets worldwide. Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels a day capacity, allowing exports to continue to grow over the coming years. On the demand side, key global consumers such as China have been buying more LPG from the U.S. as the Middle East supply remains curtailed and uncertain. China's LPG imports from the U.S. declined last year following the initial imposition of the additional U.S. tariffs but have rebounded recently due to disruption in Middle East supplies U.S. LPG market share in China has risen from a low of 10% in June to 2025 to an average of 51% during the second quarter of this year according to third-party shipping data levels not seen since before liberation date.

Additionally, we are beginning to see a recovery in Chinese petrochemical demand for LPG as shown on Slide #7, titled China PDH demand on the rise. China PDH demand has increased 40% from April to July. August demand is forecast to increase further, returning to all-time high levels not seen since before the disruptions in the Middle East. This higher demand should support more U.S. imports into China in the near term.

Next, let's turn to Slide #8 to discuss shipping dynamics. VLGC freight rates have been elevated since Epic Fury due to the global resuppling of ships after the closure of the Strait of Hormuz creating some headwinds for U.S. LPG exports. However, the order book for new VLGCs is robust and will provide relief to shipping costs in the coming quarters. We anticipate 84 vessels will be added to the fleet in the second half of 2026 and all of 2027. From now through 2029, the -- fleet will increase by 31% or 138 ships. Given the imminent export expansions and new build terminals coming online, readership availability will facilitate more cargoes leaving the U.S. and continue to support Mont Belvieu prices. As the nation's second largest NGL producer and the largest producer exporter, while also remaining unhedged on NGLs and [indiscernible] benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing.

With that, I'll now turn it over to our Senior Vice President of Gas Marketing, Justin Fowler for his comments.

Thanks, Dave. I'll start on Slide #9 that highlights the strong fundamental outlook for natural gas that we see through 2030. The 2 charts on this slide illustrate total U.S. demand growth. Based on data center and power projects that have been announced to date, natural gas demand is forecasted to increase 19 Bcf LNG and Mexico export growth adds another 23 Bcf per day of natural gas being growth by 2030. In combination, this represents 37% of total main growth for natural gas by the end of decade. While associated gas from the Permian will fill a portion of this demand growth through announced egress expansions, Higher prices will be required to incentivize growth from nontraditional gas basins and Tier 2 acreage with higher breakevens to ultimately meet this demand. .

Now let's look at regional demand in our Appalachian Basin, which is highlighted on Slide #10. The power projects highlighted on this slide represent the projects that have been publicly announced in our region to date and amount to over 9 Bcf per day of demand. This does not include additional projects that we've spoken to you to add an additional incremental 3 Bcf demand to our regional profile. We've shown this slide in the past, and each time the number of projects and implied regional demand estimate has increased. But what is exciting to us today is that we now have 6 Bcf of projects that are either FID or under construction. This increases our visibility into which projects will come to fruition and allows us to prioritize our conversations.

Next, let's turn to Slide #11, titled Gas Demand Competition. As Mike detailed earlier, Antero is in an advantaged position through our long-haul firm transportation capacity. This fund transports significantly widens the footprint of demand pull projects that we can select to participate in. Our firm transport portfolio opens up opportunities into the Midwest and further south where in total, another 7 Bcf per day of power projects are being forecasted. This optionality is unique to Antero and allows us to be highly selective with our project partners around the best opportunities on a risk-adjusted basis.

With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. I will start on Slide 12, which highlights our second quarter operational and financial results. Our quarterly production was a company record and averaged above our guidance range coming in at over 4.1 Bcfe a day. This represents an increase of 21% year-over-year. In late 2025, we spud our first dry gas pad in over 12 years. And today, we announced the results of that pad. This pad delivered a more than 67% improvement in EUR and a nearly 30% decrease in cost per foot. We also announced $315 million of acquisitions in our core West Virginia Marcellus footprint. In total, these transactions increased our net production by approximately 125 million cubic feet a day equivalent and add 15 net drilling locations. I'll discuss both of these updates in more detail momentarily.

Turning to our financial results on the right-hand side of the slide, our adjusted EBITDAX increased 57% year-over-year, resulting in $220 million of free cash flow. We used a portion of this free cash flow to accelerate our share repurchase program, repurchasing 1.1 million shares for $38 million. Lastly, our total cash operating costs were at the low end of the guidance range, declining $0.29 per Mcfe or 11% from the year ago period. This first step in realizing lower costs is attributed to the second quarter being our first full quarter incorporating the HG Energy acquisition.

Next, let's turn to Slide 13, titled strong performance and return to dry gas drilling. This slide compares our well design and production performance from when we last role on our dry gas acreage over 12 years ago. So the pad we turned to sales this year using modern drilling and completion methodologies. Our lateral lengths nearly doubled, and we increased our sand use from 800 pounds per foot to 2,000 pounds per foot. Despite these increases, our cost per foot declined 28% to just $900 per foot. Most impressively, our EUR increased 67% from 1.2 Bcf per 1,000 to over 2 Bcf per 1,000. On the right, you can see the 90-day cumulative production rates, which increased more than 3x. All of these results exceeded our internal expectations. With over 1,000 dry gas locations, we view this acreage footprint as the largest undrilled Tier 1 dry gas position left in the U.S.

Next, Slide 14 looks more closely at the acquisitions we closed in July. We invested $315 million on assets in our core West Virginia Marcellus footprint. These transactions immediately add 125 million a day of net production and were acquired at a combined valuation of just 4x EBITDAX and a free cash flow yield over 20%. The chart on the right illustrates how we've been able to increase our net production, which has increased from 3.3 Bcfe a day at the beginning of 2025 to an expected 2026 exit rate of 4.5 Bcfe a day or 36% growth over that time period. Notably, we have been able to accomplish this net production growth without impacting the basin's gross production, which you can see has remained essentially flat at 35.5 Bcf a day over that time period.

To emphasize a point that we've made in recent discussions, Antero is in its best position in company history through accretive transactions and organic growth our production has increased by 1/3. We have already achieved nearly half of our targeted 25% reduction in operating costs and the NGL outlook has significantly strengthened relative to the beginning of 2026. Further, our share count is down and our total debt will be back to pre HG Energy acquisition levels in the coming quarters.

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

[Operator Instructions] And our first question comes from Kevin MacCurdy with Pickering Energy Partners.

There's been some activity in your neck of the woods in recent power deals and talk of data centers. Obviously, you are in the dominant position or the dominant producer in West Virginia. And you touched a little bit on this on your prepared remarks, but maybe you can expand a little bit on how you view your gas marketing portfolio in total. And what would make you get more aggressive with long-term sales agreements?

Yes. I think we touched on in remarks. I mean right now, we kind of think about how 10 to 15 years back, we signed up for all the firm transport arrangements just to get our gas out. Now we're at the end of that. And so we can select the best paths and those pads are competing with the power deals comparing them. So it has to compete with the broader energy markets. The one was recently in our backyard. I mean we've been in discussions with them for almost a decade. So we're well aware of that. They actually have a contract on some of our midstream. So in discussions with them, just the uncertainty around the pricing, the timing, the execution, all of that really didn't meet our return hurdles. So when we look at projects, it has to meet all of those 3, and that one just wasn't attractive to us.

Okay. I appreciate the details there. And as my follow-up, you were able to do some buybacks this quarter despite continuing to execute on the bolt-ons. We see a lot of free cash flow potential from Antero in the coming years. With the stock in the kind of mid-30s, are you ranking buybacks a little bit higher among your options for your cash flow?

Yes, definitely. You saw that in the quarter. We weren't planning on buying back shares in the quarter, but where the equity price went obviously very attractive to us I think you heard in Brendan's summary comments, production up 20%, cash costs down 10%. Liquids pricing up significantly. EBITDA up 57% when you look at the share price, and it's the same as last year. So I would say that you could elevate the ranking of that and that is very attractive to us at these levels.

Your next question comes from Dave Daoud with Truist.

It's Gabe from Truist. I was hoping we can maybe just touch on the growth CapEx and how we should be thinking about that impacting 2026. It looks like you're at 4 rigs currently, maybe already putting some of that growth capital to work. Could we maybe just get an update there?

Yes. So it's 4 ones in transition. So it will be down to 3 here in the next month. But we are drilling those 3 pads that we talked about that are kind of on the difference between maintenance and growth capital. So you also have some capital. So our maintenance case is to remind everyone what was $1 billion, our growth is $1.2 billion of capital this year. Right now, we're probably somewhere a bit north of $1 billion, but not to the $1.2 billion. A lot of that will be completion capital in the fourth quarter, and we still -- that's yet to be determined whether we deploy that. We said in the past, $3-plus gas. It's probably something that we would deploy, but we'll just have to determine that when we get there.

Okay. And so if you complete those wells, and that takes '27, would imagine [ 4 6 ]?

Yes. Yes.

Yes. Okay. Okay. And then maybe just a follow-up. Curious on the cost optimization plan, the $0.35 reduction in realization is obviously being offset by the big move lower on the cost side. Just how dynamic is that plan? Just curious like how much flexibility will you have we progressed through '27 and maybe in basin pricing not really materialized to what you would expect. Would you just still keep some of that FTE or is that just simply the recontracting to lower market rates?

Yes. So some of that's in-basin pricing around the dry gas, but the majority of it is just the optimization of our firm transport. I was trying to hit in the comments, it's definitely coming from the end users it's a demand pull. And so when we came out with this cost presentation and strategy a couple of months back, we received so many reverse inquiries along our firm transport paths and Justin hit on that slide, too, all of that 7 Bcf of demand that's along those FT pads, you can assume a lot of those are reaching out to us to try to optimize that transport, put it in their hands, not ours, but also get us a premium that's baked into this $300 million that we've been talking about, that would be incremental. But that's something we're looking at. And you kind of saw the first sign of that with our guidance. We reduced our cash costs also reduced the realized price, but we're hopeful that we'll actually do better than that. Just getting premiums along that path instead of just having the end user to hold that transport.

Your next question comes from John Freeman with Raymond James.

Just following up on the $300 million kind of margin enhancement that you all first unveiled in that presentation last month. Just to clarify if that was extended kind of a few years kind of beyond that 2028 target, is it safe to say that, that $300 million number would move materially higher, if you just extended the time line?

Absolutely. We just focused on 3 years. We thought that was kind of the investment horizon. If you're looking past that for the 5 years, I think it grows about $600 million to $700 million.

That's great. And then just follow up, Mike, as you sort of see this play out with the data centers, the power projects as they come online over the next several years? And you sort of start to move or have the opportunity to sell more gas in basin. Just like rough numbers, like how do you see that mix sort of changing versus if we call it kind of 2/3 kind of out of basin at the moment? Like just how do you see that evolving over the next several years?

Yes. Right now, we're kind of thinking 1/3 was FT long haul, 1/3 liquids and 1/3 is generally local sales. So if you just put that in natural gas terms, it's about 50-50. The word we like to use, you're going to hear a lot of you hear at the balance. We want to be balanced. We want to be a balanced natural gas liquids producer. We also want to be a balanced seller of the natural gas, about half on the long-haul transport and half local.

Your next question comes from Arun Jayaram with JPMorgan.

Mike, I was wondering if you could talk us through the timing of further reaching your cost reduction target of $0.70 per Mcfe. It sounds like you're halfway or nearly halfway there to the integration of HG, but give us a sense of how that will play out over the next couple of years. And again, I'm asking this question, largely trying to think about where your cash operating costs could be in calendar 2027 as you move towards that $2 end of year '28 target?

Yes. We put in the 3 buckets -- we put some timing around that. That first when we talked about the override that starts immediately that started in July, that's a $0.04 uplift or $0.04 improvement on the cost structure at $60 million. And we have the VPP in July of '27. That's an incremental $30 million. Throughout that time, you're going to see this optimization of our natural gas firm transport. It's harder to predict the exact timing of that, but we're in significant negotiations around those type of improvements. So think about that as more ratable and then the $105 million at [indiscernible] liquids at year-end '28.

Got it. Got it. Great. And my follow-up, Mike, clearly, one of the themes from today's earnings is your commentary that the business for large scaling natural gas liquids producers will be more driven by kind of demand pull versus just being a traditional E&P price taker. I was wondering if you could comment on how you think Antero is positioned for this kind of, call it, shift in market dynamics.

Yes, we're extremely well positioned. Go back 15 years, and we were trying to create markets. There was no local gas markets that had to sign up for all the firm transport that came our way. Those are expiring now. So now we get to pick the best ones. Some of it ended up in terrific markets. Some of it didn't end up as well as we had hoped. So we'll be able to compare those now to the local demand. So it's perfect timing for us. And that's why in the comments, those opportunities are going to have to compete with the broader energy markets because those LNG buyers are really in kind of international. There's an art there and our strategy has been to remain on the spot there. So we haven't entered any firm agreements with that price.

And then local is going to have to compete with that. That's why we're highly selective you're going to see a bunch of announcements that along the way, we are participating and then you can be assured that's because our opportunity sets greater than what those opportunities were. So highly selective. It's got to be more near term. It's got to be price certain, and it's got to compete with our firm transport and liquids production.

Your next question comes from Doug Leggate with Wolfe Research.

So Brendan, this is maybe for you. But in your deck, you're walking through pretty clearly the planned reduction in cash costs. I think it's been beating pretty well this morning. My question is, why are you -- hold a second -- why are you offsetting that with price realizations? I'm trying to understand what this implies for your market view of gas going forward?

Yes, sorry, I didn't hear that last part. Doug, do you repeat that?

Sorry, some dialing in my system. Why are you offsetting it with price realizations? I'm trying to understand what that signals for your view on the macro?

Yes. It just goes back to some of that same conversation Mike was having that the world is shifting from this producer push to demand pull. Sometimes what that means is they're willing to take your product in basin you'll, of course, have a lower realized price that they're buying in basin. But from a margin standpoint, you're picking up $0.35 of margin. So they're taking on the transport to move it, but they're giving you a premium on the price versus what you otherwise would have sold if you were just selling in basin. So costs coming down $0.70 offset by realizations coming down by about half. So your margins still are getting picked up by $0.35 overall.

So we're quite enthused by what we're seeing on the demand fall, like Mike mentioned, this market where it used to be you have to find a place of your gas, it's now become, hey, can you deliver us 300 million a day in this area? Can you deliver us 200 million a day in this area that we need by this period of time. And we have to weigh that against our firm transport. What is the cost to get you there? You have to take on that cost or you can pick this back up in basin and then you can take on that cost. But all of these factor in to our decisions, but they're all -- should lead to margin improvement on our natural gas in a big, big way.

I appreciate that color. My follow-up is a quick one, hopefully. So obviously, you've drilled your first dry gas pads in quite a while. You haven't completed them obviously, but whether we end up with a squishy winter or not, what's the kind of road map to whether you would go back to growth in 2027?

Go back. We have 2 pads in there. Well, we put our first one in planning and that the Brendan review the results the next 2 are DadinWalters right next to it. they'll be drilling, whether we complete them, like you mentioned, will be natural gas price dependent. But I fully anticipate completing them, if it's $3 gas plus, and we can hedge that and also hedge kind of local basis at very attractive levels. So right now, based on the markets that we're looking at, you would assume that those would be completed. But if you have a significant down or price movement on the '27 gas, and we won't complete them in the fourth quarter.

Your next question comes from Betty Jiang with Barclays.

I want to start with a follow-up to Arun's question about costs. This GP&T pieces, there's many drivers lowering that GP&T over time. Could you just impact like how much of the reduction is coming from a shift towards the HG dry gas assets like whether that's -- the wells are getting better and just shifting to HG? And how much of it is growth, further dry gas growth above and beyond the base level?

No, 50% is HG. It's over $50 million this year, I should say, HG. HG has outperformed our expectations, definitely. 2 of the 3 rigs that we have running right now that force and transit, but 2 of the 3 are on HG pads. One of them, those liquids, one of them is a dry gas. So incrementally, HG is outperforming and will have more production than we assumed. So there's a little bit of that, but it's not terribly material. HG does sell -- we do sell the majority of those volumes in basin. So those will have lower transport costs associated with them. So that does impact it a bit. But the majority of it is just a shift, like we said, to the demand pull and shift to just some dry gas development also with those transactions expiring.

Yes. If you look at that $300 million that we have laid out there to Betty, I think about $250 million of that. So all of the liquids, the VPP, the override and then about half of the gas is all just driven by pure kind of optimization, the $50 million Mike mentioned that $300 million is really just driven by that kind of shift to order, I guess, in HG.

Got it. And then sorry for -- so on a per unit basis, if you grow the dry gas piece going forward, how much would that improve your GP&T?

Well, I think on the GP&T front, like we said, the $300 million, just to break it down. So we've got $0.35 of margin improvement. $300 million is about $0.20, the other $0.15 comes from HG. So $0.35 of margin improvement. The $0.20 within that $300 million we talked about, $0.15 is HG. And then the other -- if you think about it from a cost standpoint, again, we're down $0.70 on cost. Almost all of that $0.70 reduction is going to come in the form of GP&T coming down. I mean that's the driver of that processing costs will be lower. Transport costs will be lower. Gathering I'll say the same to AM on that front, but everything else will be lower.

Got it. And if I could sneak in one quick one. In your scenario, how much do you -- does your in-basin exposure grow over the next few years from the [ '25 ] currently?

Yes. Mike talked about it. So you'll feel likely go from what today is 2/3, call it, 2/3, 1/3 in terms of 2/3 going to the LNG Fairway and 1/3 going elsewhere. You'll have that be more 50-50 on a go-forward basis. That will take some time to play out. That will be over, call it, a 5-year period for that to play out.

Your next question comes from Phillip Jungwirth with BMO.

I know in term mystery has a separate call, but I was hoping you could talk about the East Side Express Pipeline, which is the first interest state regional line. Just how does this benefit Antero and just confidence in executing a project like this? And then just separately, just what's the interest in difficulties in building and interstate pipeline team. Just thinking like shorter distances like West Virginia and Ohio, for instance, where there should be strong demand pull in the future.

Yes. No, we're super excited about that. That goes hand in glove with these acquisitions that we just did, consolidating the dry gas area of our play 1,000 locations that Brendan talked about. This is our first regional pipeline East West that will cover approximately over 30 miles of our acreage position in the dry gas window, extend all the way across it. Antero Midstream is the industrial builder of Northern West Virginia. And now has the balance sheet to credit, the strength, the expertise to build there over a decade. Maybe a decade ago, we formed this out everyone's kind of familiar with that Stonewall pipeline. That's when we farm that project out because we just didn't have the ability to execute on that. That's no longer the case.

We are the builder of these regional pipelines now in West Virginia. And Antero Resources acreage position and strength in investment grade goes with that over 1 million acres, thousand of these dry gas locations, so they'll straight across it, and we hope to build more of those at Antero Midstream and for Antero Resources to benefit of that building, maybe the next one is probably north, south. We've got a couple on the drawing board to go to all the demand centers to go to all these projects all the interconnects with all these long-haul pipes, just interconnect this million acre position in Tier 1 Marcellus with all the demand that's been publicized and Antero Midstream will be the pipeline to build it, and we will not farm those type of opportunities out anymore.

Okay. Great. And then Antero has also always been a leader in realizations for your products, whether it's gas or C3+. We have seen peers increase their focus on the marketing side of late, one with a large acquisition. Just when you look at what they're doing, is that something that could make sense for Antero to pursue just as less of the dry gas volume in the future is committed? And if so, how do you go about that?

We think we already have that. I mean we've been the top 10 gas marketer in the U.S. for the past decade. We were ahead of the game on that with our firm transport portfolio. I think we have '28 paths that we market along. And also with our liquids to Dave and his team has been a leader in that, first one sign up on ME2, pretty much signed up on every single project from an LPG and ethane standpoint, I've been marketing around that, really a market maker over on the Atlantic Beacon side of the liquids marketing. So we feel really good about our position there ahead of the game. And so now others are kind of getting into that monetization of the product being a very important part of the business. We were there over a decade ago.

Your next question comes from Jack Cavanagh with Goldman Sachs.

I just wanted to ask on hedging simply in 2027, just curious how your team is approaching the right hedging levels for next year. I know there's anything you're seeing in the macro set for '27 that would change your hedging approach year-over-year based off the 60% levels we saw in 2026.

No, we're in a good position. We're actually ahead of where we were this time last year for '27. We've got 34% hedged. I think it's a Bcf at 30.84 and then maybe 100 million a day of collars with the [ 3 50 ] by [ 4 50 ]. We said before, we like the 25% swaps and 25% collars, but that's if the collars, if those are attractive levels with a lot of call skew. We've been faring more of the swaps of late I think you'll see us continue to increase that. We're in a great position. So we're not going to be rushing into down markets.

But if you see upticks in the gas price in '27, you may see us add a little bit. When we do acquisitions like this recent one, we do hedge it. So you saw an increase in our volumes there, hedge volumes by, I believe, around [ 100 million ] a day in '26 and [ 80 million ] in '27. So when we do acquisitions, we will hedge them just like we did this one -- these couple of acquisitions we did in July.

I appreciate that. And then my follow-up -- maybe on the $315 million in the West Virginia property acquisitions for the quarter, curious how you and the team are seeing the near-term opportunity set for incremental bolt-ons in and around your core footprint and whether the current macro is having an impact on the number of opportunities you're seeing in the market?

Yes, it does. We have a lot of non-op working interest and fees out in our basin and when you have 1 million acres, you have a large opportunity set. A lot of non-op working interest. We're in discussions with them, and they tend to have acreage around their non-op position too, that they're not able to drill or operate. So as part of the transaction, we want to buy in as much working interest as we can. And and get the acreage as well. Our goal -- one of our strategies is obviously to increase our production. It's really the interest of the production from the growth standpoint already on our acreage.

So gross being flat, but enter owning more and more of that -- the interest in that production and then obviously consolidating the acreage around the East Side Express. That's where this acreage was, 15 locations, a couple of pads right on that East Side Express. So that was very attractive to us. We continue to see these type of opportunities, and we'll continue to look at them. Generally, it's kind of in around when gas prices go lower, we feel more comfortable and we can hedge out and take advantage of the contango in the future and then know exactly when we'll develop the pads and take advantage of those type of valuations.

Your next question comes from Leo Mariani with ROTH Capital.

I was hoping you could give a little bit more of an update on HG here. I know that kind of last quarter, you guys bumped up your synergy target there. Can you give us a sense of kind of how much of the synergies you've captured thus far in 2026? And do you think there could be more upside to that number over time?

There will be more upside. It's still up that $80 million level, but that's not capturing what I mentioned earlier in my remarks. We're -- we actually have 2 rigs of our 3 on the HG acreage. That's well ahead of schedule. We were contemplating when we underwrote the transaction just one rig. So that's going to accelerate the volumes on the HG, which is going to accelerate the transaction value to us. There's a lot of pad ready there. They've already got all the infrastructure, being able to put those pads on right into the local gas markets in the winter when we think there will be elevated pricing. That's all entered into the decision. And obviously, the well results are terrific. We're going to put on the second set of wells from the 1221 pad on August 17. Those continue to outperform the 1221 north. So we'll continue to update that number. But just for '26 million to $80 million is pretty much locked in, but that will go higher in '27 as we put these new pads on.

Yes. I appreciate that. And in terms of the gas price environment, clearly, it's relatively weak right now. And I guess we're not too far off from the shoulder season. Are you guys thinking about maybe pushing some of your turn in lines kind of over to the winter when pricing is better? Just any thought is just trying to kind of manage production a bit to kind of match price here?

Yes, I'm glad you brought that up. That's actually the curtailments that we outlined. That's a new feature for Antero. We talked about the cost structure coming down in the -- but we also have a slide out on our in our deck that showed the commitments coming down quite dramatically and some -- a lot of those commitments around the MVCs on the liquids. So we now have flexibility to look at our lean pads kind of at 1,150, 1160 Btu, and we don't have to produce them where in years past, we would have because there have been NBCs with them. We now have ultimate flexibility. So that's a new feature that we're excited about. The ability just forecast, a, look, September could be weak. We mentioned it's under $2. Let's shut in or have curtailments on those wells and bring them on more into the November, December time frame when the prices are higher. We very much have to have flexibility now, and that's something positive for us. So we're excited about that.

Okay. And that's kind of basically baked into the guidance you've laid out here.

Yes. We're hopeful to continue to kind of that and ability to take advantage of those opportunities.

Your next question comes from John Annis with Texas Capital.

For my first one, looking at Slide 13. Can you help us break down what drove the improvement in the dry gas well results? For example, how much came from the completion design, longer laterals, better targeting versus other factors? And then given this was your first dry gas pad in more than a decade, how much more room do you see for further improvement as you apply what you've learned to future pads?

Yes. No, it's a terrific result for us. So this 2,000 pounds of sand and the 830-acre spacing is what we traditionally done in the liquids. That's what we've done kind of our go-to for the last 10 years in the liquid. So we can play with that spacing. I know on the HG dry gas pads we're going to 1,000, 1,250 interlateral and going up to 2,500 to 3,500 pounds of sand. The water going in between 35 barrels per foot and 50 barrels per foot. So there's a lot of optimization to occur. But to have a 2,000 pound, 830 interlateral spacing and have it be over 2 Bcf per thousand was a terrific result for us. The lateral length just adds actually to the economics, brings that dollar per foot on the CapEx, that 13,500. I mean you're increasing proppant by and your well cost is down 30%. That's a lot of that lateral length as well, so -- and drilling times and completion times. So we feel really good about that. We have 1,000 locations greater than 2 Bcf, we probably would have had those in our database at 1.8 to 1.9. So above 2 Bcf is a terrific result for us.

I appreciate that color. For my follow-up, on the lateral of more than 24,000 feet, how do the economics compare with your current average lateral? And excluding lease geometry, are there any practical limits to extend laterals beyond that?

No, we just drilled that, so we haven't put that on yet. That's actually on an HG pad. On our 1204 North pad, set 6 wells averaged about 19,000 per well. So those will be terrific for us. So we don't have the results on that yet. But all these longer laterals that we've been drilling Obviously, a lot of them are now coming from HG because they did a really good job of planning along on high-pressure line with 6 wells going north, 6 wells going south as much as the acreage position would allow that really allows for terrific production profile being flat at 25 million a day for a long time. So that's something we're interested. We're going to try to replicate that with 2 different roads in our dry gas to the exact same thing. But we have no limitations right now. I think you'll see the lateral lengths continue to just go longer and longer.

Your next question comes from Subash Chandra with StoneX.

Mike, I wanted to confirm a couple of things. So pro forma for everything, the acquisition, the cost reductions. Is maintenance CapEx still at that $1 billion? And is the growth price hurdle price for Henry Hub?

I don't know about the second part, but the first part is correct. It's still $1 billion. Subash, I didn't catch up the second part of your question.

Yes. So the second part of the question...

That would have been at the beginning of now with where liquids prices are. I still think $3 generally in a mid-cycle case, but that's more in that $35 to $40 NGL realized price. NGLs are well above that. I think today, our NGL barrel is at $45, Dave's confirming that. So that's good. But those currently this morning, we're at $45 a barrel. So that would put that a bit lower, but we -- our liquids development is really kind of more on a steady state than maintenance. So the true kind of growth capital is more around the dry gas. So $3 is probably a good number to think about.

Okay. Great. And a follow-up on HG, if you look at it this way, but with the second rig, are you still drilling the puds out? Have you gotten into some -- maybe the 2P that you thought you might have acquired in the acquisition?

So on the 1204 and 1217 pad, the 1217 has been elevated. All of them, I think, were in the approved 1203 though is on the schedule for '27, and that would have been in the 2P, but that's now been pushed up just with the performance of the results that we've seen. So right now, those have been improved, but '27 drilling will get some of the 2P into the portfolio.

Your next question comes from Paul Diamond with Citi.

Just a quick one, circling back on curtailments. You just talked about the coming quarter kind of already being baked in the guidance. I guess as we think about the kind of the contract optimization you talked about, how should we think about, I guess, your willingness or ability to do so or to a greater degree over time? Or is this kind of like the level you expect to stay at this level of modulation?

Yes. We'll see. I mean, right now, we do have some legacy pads at 1150, 1160, 1170 Btu range that generally are uneconomic, if you're below -- if you're around that $1.50 to $1.75, but those are about the only pads where we have it kind of in that lean gas area right now. So that's about it. It's about [ 50 million ] a day, [ 50 million ] to [ 100 million ] a day right now of pad that were drilled in that kind of BT regime that in years past, we still had to produce because they would have had MVCs on it, but we no longer have those MVCs. So that's about all we have right now. The rest is either 1,200-plus Btu or sub 1100 Btu. So those really weren't qualified for this curtailment strategy.

Got it. Makes perfect sense. And then just talking a bit about -- you just talked about a shift in kind of your production cadence through time. I mean how we acted to us being in coming years, given, I guess, the demand pull scenario from a kind of variability from that kind of 50-50 split between dry gas or gas and liquids.

Yes. We generally have a growth maintenance program. So we want to own more percent of it, of it but keep the gross volumes. Obviously, if there's incremental projects to that, that come along in basin locally that doesn't really meet our transport. We could potentially grow into those. But generally, what we've planned this 3-rig program to completion crew and then continue to increase our percentage ownership of the gross, keeps volumes in the basin flat overall flat, but we just own more of it.

Your next question comes from Sunil Suma with Seaport Global Securities.

I just had a big picture question. When you think about your gas sales, obviously, you had this cross protection portfolio, which helped you sell gas in fairly liquid markets? And then as you think about the in-basin demand, how do you think about the counterparty risk as you shift more on the in-basin demand versus selling to more liquid...

Yes, we think a lot about it, actually. That's one of the -- when I -- when we say risk-adjusted, probably 2 of the 3 parameters that we look at, obviously, price being one, but also timing and execution is really around the counterparty. So we think a lot about that. We do deals and the credit needs to be there, you'll see us get LCs or some sort of credit assurance. We're not credit agnostic. We have a big credit actually a team just around already having significant firm transport for over a decade. So we're very cognizant of the credit and the credibility and the execution of the project really goes into whether or not we can participate.

Understood. And then one clarification on your savings slide that you have. I think you talked about $105 million or so of savings from some of the contracts that are rolling over. And then you also talked about that number growing my understanding was that as far as the contract rollovers are concerned, that's essentially a 2028 kind of time line. Is that correct? And I presume that is kind of split between a number of contracts. Could you talk about that a little bit?

Yes, that's correct. You have that correct. The main one you can think about it is apex. That's the one that we always cite That's, I think, $60 million of the $105 million. That's 20,000 barrels a day, that saying the price that it charges, I believe, is around $0.24, $0.25, Dave's not in [indiscernible]. So it's good. That's ahead of the actual ethane price we receive. So obviously, we're not going to sign up for that. We had to do it a decade ago, just to get our gas in spec. But since that time, a lot of markets have been developed around the shell, ME2, Mariner East Utopia, a lot of different ethane markets have been developed over that time frame. So we no longer need that. We -- I think we recover 90,000 barrels of net ethane, over 100,000 barrels of gross ethane for our pipeline spec, we can be down in the low 70,000. So we can easily let that 20,000 ethane go and be within spec, and it's completely uneconomic. So that's $60 million of the $105 million, the rate is optimizing our already transport that expires at the end of '28.

But then the other piece that Mike had mentioned earlier that to beyond 2028, which is not on that slide is where do you have a lot of the gas contracts that come up for renewal where we think you could add another few hundred million on top of the $300 million.

And there are no further questions at this time. So I'll now hand the floor back to Dan Katzenberg for closing remarks.

Yes. I'd like to thank everybody for joining us on the conference call this morning. If you have any follow-up questions, please reach out. Have a great day. Thank you.

Thank you. And with that, we conclude today's call. All parties may disconnect.

Greetings, and welcome to the Antero Resources Corporation First Quarter 2026 Earnings Conference Call and Webcast. [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's First Quarter 2026 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 anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing.

I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'd like to start my comments by praising our operations team for their success during Winter Storm Fern. Their ability to achieve 100% uptime on our operations throughout the storm is an impressive achievement.

As highlighted on Slide #3, our team's efforts and strong pricing helped us deliver one of the best quarterly results in company history. Also, as highlighted on the slide, we closed on the HG acquisition in the Ohio Utica Shale divestiture. The HG acquisition added substantial production, cash flow and nearly 400,000 net acres and 400 drilling locations to our core West Virginia Marcellus position. Importantly, the acquisition will drive corporate cash costs down $0.30 per Mcfe, which lowers our breakeven costs and drives margin enhancement.

Turning to the integration of HG. We are significantly ahead of schedule. We recently turned in line our first HG pad. This 6-well pad located in the liquids-rich area has 110,000 total lateral feet or average lateral lengths over 18,000 feet per well. Notably, this pad has one of the highest net royalty interest at 89%, further enhancing its rate of return. We expect the pad to produce 150 million per day and remain flat at these levels for quite some time.

On the acquired assets, we have already achieved operating synergies of $15 million to $20 million and are now forecasting over $80 million for the full year, outpacing our initial target of $50 million. Once we closed on the acquisition and took control of operations, we found incremental cost-saving opportunities, which include drilling and completion design changes, water handling optimization and benefits from our economies of scale that are driving faster than forecasted synergies.

Our first quarter production was a record 3.9 Bcfe per day, 13% above the year ago period. This production growth is expected to continue through 2026 with full year production of 4.1 Bcfe per day, a nearly 20% increase from 2025.

Turning to the right-hand side of the slide. Our quarterly financial results were highlighted by our ability to capture substantial premiums to benchmark prices. These high premiums, combined with our terrific operational performance generated free cash flow of $657 million, the second highest level in our company history. We used this free cash flow to accelerate debt reduction following the HG acquisition.

At the time of the acquisition announcement, we had targeted free cash flow available to fund the acquisition from December through the end of the first quarter to be approximately $500 million. We exceeded this target by $250 million. Looking ahead, improved NGL fundamentals are expected to result in us hitting our leverage target of 1x by mid-2026, 6 months ahead of prior expectations.

Next, let's turn to Slide #4, which highlights our latest hedge position. For 2026, over 60% of our natural gas volumes are hedged, and we have 1/3 hedged in 2027. Our strategy continues to be targeting a natural gas hedge position of 25% to 50% of annual production, which reduces the volatility in our cash flow and provides an opportunity to be countercyclical in share buybacks or asset acquisition opportunities.

On the liquids side, we remain unhedged. I'll close my comments today by touching on Antero's advantaged position in today's global backdrop, which is highlighted on Slide #5. The recent geopolitical events have highlighted the advantage of Antero's corporate strategy. We have the highest LNG exposure among Appalachian producers, selling 2.3 Bcf per day of production to sales points along the LNG Fairway. At the same time, we are the largest producer/exporter of NGLs in the U.S., selling the majority of our LPG, which includes propane and butane into international markets.

We expect recent global supply outages and disruptions to lead to increasing risk premiums for U.S. NGL barrels, both in the near term and in the years ahead. These global events are leading to increased demand from international NGL and LNG buyers that are looking to derisk their energy portfolios by diversifying their exposure and increasing purchases of U.S. supply. This shift towards U.S. supply supports higher export utilization and more attractive price premiums at our sales points along the coast. This highlights Antero's unique export strategy and positions us well to benefit from today's rising global demand for U.S. energy.

Now to touch on the current liquids and NGL fundamentals. I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments.

Thanks, Mike. New market volatility has been introduced to global energy flows, particularly affecting NGL and oil products with the ongoing conflict in the Middle East following Operation Epic Fury that began on February 28. We are continually monitoring the Middle East infrastructure attacks, ship transits through the Strait of Hormuz and assessing the resulting commodity price implications for our business.

At this point in time, there are far too many uncertainties for us to be able to provide updated guidance with a high level of confidence. In our opinion, today's financial market does not yet reflect the most significant supply shock witnessed to date. However, as the second largest NGL producer and as Mike indicated, the largest producer/exporter, while also remaining unhedged on NGLs, we are poised to benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing.

Focusing in on the impact to the global NGL market, the graph on the left of Slide #6 shows that the Middle East accounted for about 36% of the global waterborne LPG market in 2025 and virtually all of that volume needs to transit the Strait of Hormuz to reach global buyers. The U.S. is the only other major waterborne LPG supplier. On the demand side, the graph on the right shows the major buyers such as China and India were heavily reliant on the Middle East for supply. These buyers have no other options to replace these barrels, except lifting more volume from the U.S.

Recent U.S. LPG dock expansions couldn't have come at a better time, alleviating bottlenecks seen in recent years and making barrels available to global buyers. The U.S. has added up to 610,000 barrels a day of LPG export capacity over the past year, bringing the total terminal capacity to approximately 3 million barrels a day as illustrated on Slide #7.

Going forward, additional expansions through 2028 will add approximately another 1 million barrels a day of LPG export capacity. The full impact of the recent debottleneck on propane exports has just begun to be realized. Persistent fog in the U.S. Gulf Coast, some mechanical issues and a relatively higher proportion of butane exports in recent months following the closure of the Strait of Hormuz have kept U.S. propane inventories elevated to start.

However, this surplus volume is well positioned to backfill constrained Middle East product as an armada of LPG ships have sailed to the U.S. for their only opportunity to get replacement cargoes. Notably, we have seen a sharp increase in export volumes in recent weeks, reaching 2.3 million barrels a day of propane alone this week, and we expect record level exports to sustain in the months ahead.

Slide #7 also shows the upside potential for propane exports with the new dock capacity online. The purple dotted line on the chart shows the level of propane exports if terminals were running at or near operational maximums of 90% nameplate capacity. This would represent the U.S. averaging over 400,000 barrels a day of incremental propane exports in calendar year 2026 over the third-party case published before the conflict, indicating that there is ample room for more propane across U.S. docks.

Now let's take a closer look at the impact that higher propane exports will have on inventories, which is illustrated on Slide #8. The tan dotted line represents the pre-Epic Fury inventory outlook from the same third-party provider. At that time, expectations were for propane storage to remain elevated throughout 2026. The blue dotted line presumes that new dock capacity will add an additional 100,000 barrels a day of exports for the remainder of this year to replace a small portion of the LPG supply that has already been lost from the Middle East conflict.

Under this scenario, storage would fall below the 5-year average by late summer. The purple dotted line illustrates what happens to U.S. propane storage if dock utilization rates run at 90% for the remainder of 2026. Under this case, we would fall below the 5-year range by the early summer and ultimately need a pricing response to keep barrels in the U.S. to avoid a supply shortfall ahead of this upcoming winter.

As a reminder, Antero produces 46 million net barrels of C3+ NGLs. So an increase in $1 per barrel of C3+ results in $46 million in incremental cash flows. Antero's forecasted realized pricing for C3+ has increased approximately $12 per barrel during this time, reflecting over $550 million of incremental free cash flow in 2026. Uncertainty remains in the global energy markets from here until there are concrete agreements and realized outcomes in the Middle East. However, U.S. energy supply and particularly NGLs remain a consistent supply source to the world in these times of need. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Thanks, Dave. I'll start on Slide #9 titled Near-Term LNG Capacity Additions. LNG export demand is expected to increase by 7 Bcf per day by the end of 2027. Golden Pass shipped its first cargo last week and is expected to ramp up to 1.6 Bcf of capacity in 2026, ultimately exporting 2.4 Bcf per day in 2027. This increase in LNG export demand when combined with higher power demand and increasing exports to Mexico results in an undersupplied U.S. market over the next 2 years. This wave of new LNG export capacity is arriving at a much needed time.

Turning to Slide #10. Let's take a look at the current European storage. The EU exited this past winter at the second lowest storage level on record, falling below 30% at the end of the first quarter. Adding to this storage issue is the EU imports from the Middle East have declined 91% in March and April. Supply outages and disruptions in that region are likely to result in reduced LNG exports throughout 2026.

In order to fill storage to the EU's 80% target ahead of next winter, the EU will need to begin purchasing significant cargoes from the U.S. and Asia is also in a similar position. We expect low storage levels and global supply outages to result in U.S. LNG utilization rates running above historical levels, drawing down U.S. storage this year and supporting prices as we move into this winter.

Now let's turn to regional demand, which is highlighted on Slide #11. The power projects highlighted on this slide are the ones that have been publicly announced in our region to date and amount to over 8 Bcf per day of demand. Based on the conversations we have had, which also include nondisclosed projects, we estimate that regional power demand projects exceed 10 Bcf per day in total.

In just West Virginia in recent weeks, we have had projects announced from a combined data center facility with customers that include Microsoft and NVIDIA, also separately a project that is tied to Google. Late last year, the state of West Virginia announced its 50x50 plan, which is an initiative to increase the state's power generation capacity from 15 gigawatts today to 50 gigawatts by 2050.

Additionally, surrounding states are considering removing tax exemptions for data center facilities that could drive increased opportunities for West Virginia to attract new projects to the state. This incremental 8 Bcf a day of regional demand growth compares to total production in the basin of approximately 36 Bcf per day.

Given the large demand pull from LNG in the coming years, we believe there is only so much gas that producers will be able to commit to long-term deals with these projects. Ultimately, this tightness should provide support in 2 ways: first, more attractive pricing to producers related to long-term supply deals; and second, improved overall local market pricing as a result.

As West Virginia's largest natural gas producer with a significant infrastructure footprint through Antero Midstream, we believe we are well positioned to participate in supplying the natural gas that these projects will require.

With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. I'll start on Slide 12, which highlights our cash cost reductions going forward. We reduced our 2026 cash cost guidance by $0.10 per Mcfe at the midpoint. This reduced range reflects second quarter through fourth quarter 2026 cash production expense reductions of $0.26 per Mcfe or over 10% below the full year average in 2025.

When we include G&A and net marketing expense, cost reductions totaled $0.30 per Mcfe. Beyond 2026, we see opportunities for further cost reductions and margin enhancement through several initiatives that we plan to discuss in the quarters ahead. Many of the initiatives relate to our commercial agreements on natural gas and liquids takeaway as well as taking a more balanced approach to the development of our liquids-rich and dry gas acreage.

We see opportunities to lower our overall transport expense and improve our corporate margins through direct agreements with end users, replacing expiring transport with better netback transactions and simply letting certain contracts that are no longer needed expire. Some of these opportunities will occur in the near future, while others will take place over multiple years as contracts come up for renewal.

Speaking further to the regional demand opportunities that Justin discussed, in just the last few months alone, we have participated in requests to provide proposals for gas supply that total over 5 Bcf a day. While it is still undetermined whether we will participate in these projects, we do believe the demand is only growing for natural gas and particularly natural gas that can be supplied by an investment-grade producer with multiple decades of undeveloped inventory.

Moving to Slide 13. I'd like to finish my comments by touching on the progress we have made with funding the HG acquisition. As shown on the chart, we are ahead of initial expectations of paying down the debt associated with this recent transaction. With the help of the exceptional operations performance that Mike touched on, we were able to generate over $750 million of free cash flow from December of last year through the end of this first quarter, which was used to pay down over 25% of the acquisition cost.

Combining this with the proceeds from the Utica divestiture, we have already funded over half of the transaction. Based on our next 12 months free cash flow at current strip, we expect to have fully funded the transaction by early next year. This updated payoff timing is nearly a year ahead of what we expected when we announced the acquisition in December.

To reiterate what we have said on past calls, after paying off the remainder of the debt associated with the HG acquisition, we will have increased production by more than 700 million cubic feet a day equivalent, added 400 undeveloped locations to our core West Virginia Marcellus inventory and meaningfully reduced our cost structure, which translates into higher sustained free cash flow. Importantly, we accomplished these changes without having to issue a share of AR equity. At the same time, the overall macro environment for natural gas and NGLs has only strengthened with the current geopolitical environment and continued structural demand growth from both power and U.S. LNG.

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

[Operator Instructions] Our first question is coming from Arun Jayaram from JPMorgan Chase & Co.

Dave, maybe starting with you. I was wondering if you could just give us a little bit more color on how your marketing arrangements work regarding your export volumes. I know you printed a $0.94 premium to Mont Belvieu in 1Q for C3+. But give us a little bit of sense of how much international exposure you have to pricing versus Mont Belvieu?

Yes, Arun, we did -- in the first quarter, we had international index pricing in our portfolio. We had Mont Belvieu as well. We have a portfolio of term as well as spot transactions. So we've been participating in some of the run-up that you saw, really, it was following up Epic Fury on the arbs where you could see April and May, you're not going to sell something in March. Typically, when you're already in the first week of March, April is what's trading for a spot cargo.

So you'll see some cargoes that we sold in April and May that were on some of the higher pricing as a result of this. But if you look out even to June, the arbs have already tightened quite considerably. They're now in the $0.10 to $0.15 per gallon premium to Mont Belvieu range. And I think as we look out forward on the year with the inventory situation and what we expect to happen just as the U.S. attempts to meet a portion of what the rest of the world has lost through this conflict in the Middle East, those arbs will tighten further.

So tough to say balance of the year, how tight those arbs will get. But ultimately, that's what we want to see that stronger Mont Belvieu Index pricing. That's really what we're the most constructive on. We think that's really the story of 2026, and we're in a great position to benefit from that, just given that we have not hedged any of our NGL volumes. So we'll see where that goes.

Yes. You mentioned 2.3 million barrels of exports last week. So that's a punchy number. Dave, maybe not to pick on you, but one of your peers did raise their NGL realization guidance. I know they do the entire barrel, not just C3+ up to, call it, a $125 to $250 premium. Not to quibble on that, but you maintained your overall guidance. I was wondering if you could just give us some thoughts around that, the maintenance of your guidance and not a raise given you did book a little bit of a premium in 1Q.

Yes, Arun, I would say we did actually raise guidance on the ethane piece, and that's really maybe the story here to talk about. So I think that's the main -- it's kind of apples and oranges between us and other producers that include ethane in their NGL pricing. We've always historically broken out for transparency purposes. And the reason is really that you can have dramatic swings in the amount of ethane that you recover from quarter-to-quarter, month-to-month.

Could be local crackers are down as we've seen in prior quarters or it could be like we had here in the first quarter where you have very, very strong regional gas pricing and you reduce your ethane recoveries as low as you possibly can. Well, when you're doing that and you're lumping it all together, what's your benchmark index against is? It a static fixed percent of ethane is in the benchmark? I think that's what you see other producers do. So you get into a situation where you actually can end up with a lot of your C3+ barrels getting benchmarked against an ethane price, and that's typically when you see a large beat from a C2+ kind of benchmark producer compared to somebody like us. I think if you put our ethane into it, we would have had a $6 premium to Belvieu on a similar benchmark index to other producers. So for those reasons alone, we just historically have always broken it out for transparency purposes.

I'd also add to that detailed explanation by Dave -- Yes, Arun, I'll also highlight, we're very conservative when it comes to our guidance. There's a lot of uncertainty like there is today. We're not going to try to capture that in a moment in time. We'll just see how it plays out over the year.

Next question today is coming from Kevin MacCurdy from Pickering Energy Partners.

I wanted to ask about the cash production expenses. It looks like you lowered them $0.10. Just maybe for some clarification, how much of that reduction is driven by synergies from the HG acquisition versus just maybe lower gas prices?

Yes, the majority of that is the HG. Lower gas prices were a couple of pennies of that, but $0.07 or $0.08 of it was HG. When we acquired the assets, we underwrote very conservative assumptions around our ability to operate the assets and the integration and how quickly we'd be able to realize the lower costs, and we're well ahead of those assumptions that we announced earlier. So that's why we're comfortable lowering the guidance.

Great. And maybe as a follow-up, looking for some clarification on the CapEx budget. In the 4Q earnings release, you guys talked about the opportunity or the option to spend an extra $200 million growth capital. In this release, it looks like your official guidance is still at $1 billion. Just maybe curious how you're thinking about spending that extra growth CapEx given the current prices in gas and NGLs.

Yes, Kevin, that's unchanged, still $1 billion with the potential to go to $1.2 billion. I think the attractiveness of our program is that's truly incremental capital with no underlying commitments needed. So it is discretionary. It's completing 3 pads in the second half of the year. So that's still TBD. So we get the ability to watch local natural gas prices, see if the demand is there for it and see if it's attractive to complete those. So that's a second half event, and we'll be able to make the call then with more information around the natural gas prices.

Next question is coming from John Freeman from Raymond James.

Brendan, I wanted to follow up on what you highlighted that you all are, I guess, evaluating or looking at 5 Bs a day of various sort of gas supply arrangements. Can you speak to sort of the mix of those between sort of like LNG or data center opportunities or otherwise?

That was all regional, local demand, not only data centers but power projects as well. It didn't have any LNG in that 5 Bcf.

Yes. And I think where we see a lot of the benefit, why we're getting a lot of these requests for proposals on this is just driven by the integrated nature of having both upstream and midstream, AR being an investment-grade producer that can supply the gas and significant undeveloped inventory at AM that can build the pipelines to the areas that need it. So I think that's what's driving a lot of the requests.

Got it. And then obviously, good to see the accelerated free cash flow ability to pay down that term loan even quicker. I know you all are going to try to be opportunistic, but obviously, it looks like the main focus is taking the majority of the free cash flow, vast majority and taking out that term loan by the start of '27.

If we look ahead to '27, am I thinking about it right that once the term loan is gone and you just have basically that 2030, 2036 paper that's, a, very attractively priced, and I think can't even -- neither of it can't even be called until like 2028. Should we just assume once we get to that point where the term loan is gone that nearly all the free cash flow is going toward buybacks?

Yes, that would be a fair assumption. Right now, one of the attractiveness of our hedge position and our growth and our scale is the ability to be countercyclical on buybacks. So if you do see any weakness, we'll be there for that time frame. But assuming current commodity price -- current commodity for '26 and '27 and the early redemption of term loan by early '27, about a year ahead of our initial expectations, I think a good assumption for '27 would be share buybacks for the incremental free cash flow.

Next question is coming from Gabe Daoud from Truist.

Maybe just curious around expectations for future M&A as maybe some additional West Virginia acreage and packages that could be available. So just curious, given HG and how quickly you kind of hit some of the synergies, if there's a continued appetite for more?

Yes, we are the dominant energy producer in West Virginia, produce about half of the natural gas in the state, have close to almost 1 million acres there and decades worth of inventory. And so we are the West Virginia energy producer. So anything within West Virginia, you would assume that we would evaluate. And if it's attractive to us, it would be something we'd be interested in.

Got it. Got it. Okay. That's helpful. And then I guess just as a quick follow-up. You noted this in the past, AM obviously providing some additional benefits in conversations with gas deals. But could you also maybe just highlight or talk about how AM could prove to be a differentiator on the water side with some of these data centers and hyperscalers?

Yes. We always like to say AM is the industrial builder of Northern West Virginia, whether it's gathering for hydrocarbons or water. We do have the most extensive water system in the state and really across the country. So we are an expert in building water and all of these projects do require substantial water needs. So that is a benefit to us and a strategic advantage for AR and AM.

The next question is coming from Jacob Roberts from TPH.

Could you remind us of where you see the liquids cut progressing through this year? And really, I'm curious if you could talk more about the processing cost reduction. Is that solely a function of the higher dry gas volumes? Or is there more to the HG story that we're not seeing?

No, it just doesn't really move the needle. I think it's like 30, 70 -- what's the exact, Brendan...?

Yes, low 30s.

Low 30s on the liquids, and it doesn't really move the needle. We've got one rig right now drilling liquids, one in kind of the blended like liquid/dry gas and 1 rig in the dry gas on the HG acreage. So very balanced profile for development, and it really doesn't move the needle from where we're at today.

Okay. Perfect. And if I could follow up on that comment about some of the recontracting potential coming up. Is part of that thinking that you see the potential for a long-term supply agreement with a utility or data center or something like that, that could help offset some of the FT commitments by way of a supply contract?

Yes. I think that's -- it's a big story going forward. I mean our initial story is lowering the cost for the HG and developing dry gas and optimizing our acreage and portfolio. But on a go-forward basis, a big story on Antero is the optimization of all of our transport arrangements. We had to take out the initial FT because we created this development program in Appalachia in West Virginia, and we needed to underwrite all the takeaway.

But those agreements are 10, 15 years old. And so now going forward, they really need to be in the hands of the end user, and we'll be able to enter into pretty really attractive sales and optimize our margins on a go-forward basis, and we recontract that. Some of them around some liquids very near term are actually ones we're not using and just carrying and you're talking hundreds of millions of dollars of incremental EBITDA to us on an annual basis when these expire.

Great. If I could tack one more on. Is there a counterparty type that seems more amenable to that type of arrangement?

They're all amenable to it. There's very much high demand for our product if you haven't noticed across North America and the world. So there's so much demand for our product that they're all amenable to being the buyer of our product.

Next question is coming from Josh Silverstein from UBS.

Just on the new power capacity coming to the region. I'm curious just maybe on the volume and maybe pricing side. Is this something that you're kind of waiting around to see develop and then you can grow supply into this? And then do you want to get more pricing exposure to local pricing as well? I mean I'm assuming it's -- the power capacity is right around where you guys are, very little transport cost there, so the realizations could be pretty good.

Exactly. We are attracted to the local demand just because it's low cost and able to supply that -- it's all incremental demand, too. So we'll be able to grow into it. So that's part of our low-cost growth strategy.

Okay. And then just on the HG acquisition as well, you highlighted the OpEx cost synergies. The biggest piece of the synergies you outlined previously was on the development optimization. I just wanted to see how that's going, if that's something that we'll start to see more of a benefit of later on this year or more in '27 relative to what you're seeing right now?

Yes, definitely. That is the majority of the synergy. A perfect example is kind of on the completion stages per day. HG was in the 2, 3, 4 stages per day. We averaged over 14 stages per day. So just on this pad that we brought on and the wells going south, they were doing 2 or 3 stages. This week, we've been doing 11 on that. So you can imagine the efficiencies and optimization and cycle times that come with that, and we did not underwrite that in our acquisition valuation. So that all accrues to our shareholders. So that's the biggest one. Also with drilling too, we're under 9 days per well. They were triple, quadruple that. So putting that into the portfolio really brings forward all that value for us and is really going to drive the synergies going forward.

Next question is coming from Neil Mehta from Goldman Sachs.

Slide 7 is really great where you guys talk about the new propane dock capacity. And the base case is -- Slide 8 as well, I should say, most of them. The base case, I think, is pretty clear, but the export case is quite extreme by the summer. And so maybe you could talk about how real is this potential for that -- for the max export case to play out? And what are the biggest gating factors for it not to play out?

Yes, Neil, this is Dave. I'll take that one. I think you really kind of hit it on the head, which is the max export case, while the world would love to see that happen to try and backfill just a portion of the LPG supply that's lost globally. I mean you certainly are seeing reports about shortages, high canister prices in different parts of Central and Southeast Asia already and kind of the effects that's having.

So they would love for the U.S. to try and do the max export case. I guess what we were trying to illustrate was we really don't have the inventory to do that. So let's just say if the war was to get resolved here even in the next few weeks, things reopened by the end of June, let's say the world has lost 120 million barrels or more of LPG, we can probably backfill about 30 million barrels of it here from the U.S. And so that's really ultimately why we're so constructive on Mont Belvieu propane pricing. Even at that max export case, we don't even come close to backfilling the demand -- supply loss and the demand that's out there for global LPG, unfortunately.

And then so much of this is dependent on when the dock capacity is coming online. Can you just talk about as you guys look at future dock expansions and the stuff that's slated for '26, is everything tracking well?

Yes, I would say so. I mean I think one of the large midstream players was talking about the commissioning of one of their projects kind of ongoing. I think that was a little bit ahead of where a few months ago, people would have pegged it kind of more middle of the summer. So I would say ahead here so far year-to-date in '26. And typically, what you see with those projects, those various companies that are building those do a great job of getting those projects online on time. LPG export capacity isn't that complicated to build compared to some of the other like an LNG facility would be, for example.

Next question is coming from Phillip Jungwirth from BMO.

Sticking with the recent announcements in West Virginia. About a year ago, the state, they did sign the microgrids bill. This was meant to attract data centers. Just wondering how much of a help this has been in the conversations with hyperscalers? And then what are some of the other main positives that would favor West Virginia, which is right in your backyard versus other states within Appalachia?

Yes, that has definitely been a help. So we really appreciate that microgrid bill and that kind of put West Virginia front and center for all these discussions. West Virginia's advantage is geographically, we put it in, it's 100 miles to the data center alley. It's got the water. It's obviously got the lowest cost natural gas and energy. It's near the population centers to the East. It's fairly cold. It's got all the advantages. I think there was a report out there by an energy company that's saying all the attributes that you look for, they all converge in West Virginia. So we're uniquely positioned there as well just because we produce over half the state's natural gas. So definitely a good position to be in.

Okay. Great. And then a couple of quarters ago, you included a regional gas demand project list in the deck. I think you had Monarch on here as a 2030 start-up, 430 million a day of demand. Now it looks like it could be bigger and earlier at least the first phase. So without updating this slide, are there any others you could see maybe being pulled forward as far as timing or increase as far as magnitude? And of the 8 Bs a day you're showing on Slide 11, how much of this is either under construction or has reached FID now?

Yes. I think if you look at the map on the -- I don't have the exact figures in terms of what's under construction versus FID. But I think we would say of that 8 Bcf a day based on conversations we're having, and Justin talked about this, we see that well ahead of 10 Bcf a day. I think a lot of these projects and what has been publicly disclosed are the initial phases.

I think to the extent they can continue to build and scale, those numbers will be quite larger. So we're having a lot of those conversations and some are speeding up. And so I think our view is you really see this start to take hold when you get out into that '27, '28, '29 time period in terms of these facilities coming on, and it will be phased over time where you have like Monarch is a good example.

They've talked about their Phase 1, but that will continue to phase and grow. And that microgrid bill that I think was asked about before, it allows you to phase within a 4-mile halo. So some of these sites, they have their 4-mile halo where they can continue to scale up over time within that 4-mile halo and still fall under the microgrid bill in West Virginia.

Our next question today is coming from Leo Mariani from ROTH.

You've been really helpful in terms of providing kind of the production ramp post HG kind of given the guide in 2Q and then into kind of second half. I was hoping to see if maybe you could talk about just kind of something similar on capital. I mean, presumably, maybe first quarter is kind of the low and CapEx kicks up a little bit in the following quarters. I know, obviously, the growth capital could also be a component. And I would assume that all that growth capital would end up in the second half if you decide to spend it. So just any color there would be helpful.

Yes, that's correct. We have a full contribution for capital in the second quarter for HG. So that takes you for the second, third and fourth quarter kind of in the $300 million range, assuming we complete some of those pads we talked about earlier for the growth case. If we don't do that, then it will step back down from the $300 million more to the kind of the $250 million range in the third and fourth quarter.

Okay. That is helpful. And just on the synergies, obviously, you talked about the $80 million target. Would you expect that all to be realized here in 2026? Or can some of that linger into next year? And is the bulk of that just -- it sounded like a lot of it was operating costs and G&A related, but is there a capital portion that will flow through there as well?

Yes. No, that's just for '26, the $80 million. That accelerates actually on the go forward as we continue to improve and continue the synergies and we get the asset integrated into our operations on a go-forward basis. So that's just the '26. I think we talked about synergies up to $1 billion over time. So we're ahead of that right now. So that's $80 million this year. I think it's more like $100 million going forward on an annual basis after that.

Our next question today is coming from Doug Leggate from Wolfe Research.

I wonder if I could come back again to Slide 7 and 8. I just want to make sure I'm not missing something here. So your base case is still -- it looks still quite conservative. What would it take for you to change that? Because it seems, at least based on Enterprise's comments that exports are already running at record levels in April. So what would it take for you to reset that?

Yes, Doug, this is Dave again. It's really just a question of how much inventory the U.S. is -- or how little inventory the U.S. is comfortable having as we enter the winter season. And when you see our base case dipping below the 5-year range, that usually -- when that sort of scenario happens, you see very, very strong demand here in the U.S. to try and keep those barrels onshore so that they are there for our winter season. So you get this tug of war between domestic and international. And that's why we didn't illustrate a stronger base case. But certainly, as I said earlier in my comments to Neil, the world would like us to do the max export case if we could. We just unfortunately don't have enough supply for it.

Not to belabor the point, but I think Neil brought this up earlier. So just to be clear, is your view then on the premium to Mont Belvieu directly related to your view on exports? In other words, if price, say, exports go up, does your Mont Belvieu premium get reset again in the second quarter in terms of your guidance?

We think parties that are selling spot cargoes in the second half of this year will be getting modest premiums to Mont Belvieu as we've seen in other times where there's ample dock capacity and there's not enough inventory to go around for exports and domestic. But you'll have higher Mont Belvieu pricing. Exactly.

All right. Well, this is a moving target. I get that. But my follow-up is going back to the data center comment. I just wanted to -- Mike, maybe it's for you. I wanted to get some clarification. Everybody and their grandmother is trying to basically negotiate a data center supply deal. Obviously, you've got a bit of a geographical advantage if it's in your backyard. But are any of your negotiations exclusive? Or are they all being put up to bid? Can you kind of walk us through what the nature of the negotiations looks like? And I'll leave it there.

Yes. I think for most of them, it's request for proposal to a number of parties. I think at the end of the day, we feel we're well advantaged being an investment-grade producer. But to the extent we don't get these and you still have this demand take place, it should rise -- cause a rise in local prices, which we'll obviously benefit from. So we're certainly supportive of all of these projects to continue to get them off the ground. There's only so much gas that can go around, but we think it just drives ultimately an increase in local pricing, which we'll benefit from, I think, in a pretty significant way as well.

Where I'm going with this is get the deal or not, you're not going to give up market share, right? So presumably, you benefit regardless of who seizes the bid...

Next question today is coming from Paul Diamond from Citi.

Sticking on the AI and power contracts for a moment. Across the space, we've seen some variability in the term structure and where, I guess, all these things settle. Can you talk about what you've seen in your conversations, is like is your emerging like structure that's most common? Or is it more highly variable based on end market needs?

Yes. I think it depends on where the supply is coming from. So some of these deals that we're looking at, we would look to supply off of our firm transport. The pricing for that deal, if it's coming off of our firm transport may be different than if Antero Midstream is building pipeline in state to supply a gas deal.

So depending on the deal, the pricing could change. I think a lot of these guys, they're seeing what we talked about, which is we talked about 5 Bcf a day of demand. We obviously cannot supply 5 Bcf a day of that supply. And so I think they're getting a bit more nervous in terms of where is all the supply going to come from, which we think will ultimately drive better pricing on these deals and rise -- cause a rise in the local pricing. But it can take a local market index or it could be tied to Henry Hub. And I think those are still up in the air at this point.

Got it. Makes perfect sense. And then sticking on, you guys talked a bit about, I guess, the balance between gas and liquids on a medium-term basis. Can you talk a bit about how that structure might be? Is that more like normal cycle reactivity? Or is that a building of DUCs for more short-cycle response? Just how you guys see that playing out?

Yes, it's a bit of both. What was really driving is just a little bit more balance prior. We just put on our first dry gas pad and exceeding expectations, just put it on like a month ago, first dry gas pad in over a decade. We have over 1,000 locations in the premium core of the Marcellus dry gas. So we need to develop that and having it coincide with all this local demand will really drive kind of just one rig there for the foreseeable future.

We'll obviously have one rig in the liquids as well, our western portion of our acreage. And then we'll have one that's on the HG asset, and that kind of flows between dry gas and liquids. So it's more kind of a blend. But just to really have a little bit more balance that will really drive our cost structure lower, it will drive low-cost growth going forward, and really optimize our margins and drive our EBITDA growth. So we're excited about it, but we really just need to tap into that acreage, that legacy acreage position we had and develop that.

Got it. And just one quick follow-up there. Do you see -- I guess do you see any value in building a large DUC inventory? Or is that -- do you kind of like the structure you've been operating under?

Yes, I don't know about a large one, but what we're talking about is 3 pads right now, maybe enter into 2027 with 3 DUC pads. That will be the call we make in the second half just based on local natural gas prices, but that's about where we see our DUC inventory being at on a go-forward basis.

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

I'd like to thank everybody for joining us on the first quarter 2026 conference call. Please feel free to reach out with any further questions. Have a good day.

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

Greetings, and welcome to the Antero Resources Corporation Fourth Quarter 2025 Earnings Call. [Operator Instructions] Please note that this conference is being recorded.

I will now turn the conference over to your host, Dan Katzenberg, Finance Director. Thank you. Please go ahead.

Thank you for joining us for Antero's Fourth Quarter 2025 Investor Conference Call. We'll spend a few minutes going through the financial 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 anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call.

Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing.

I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'd like to start my comments by recognizing the outstanding performance from both our upstream and midstream operation teams during the recent winter storm event. Despite subzero temperatures and significant snowfall, we did not experience any shut-in volumes during the period. In fact, our team was able to turn in line a 7-well pad during that time, a truly remarkable achievement by our people in the field enabling Antero to deliver critical natural gas to the various regions that desperately needed it.

In addition to navigating through the winter, we had a very successful last few months on other fronts. Last week, we announced the closing of the HG Energy acquisition ahead of our original expectations. This acquisition, combined with the sale of our Ohio Utica asset, solidifies Antero as the premier natural gas and NGL producer in West Virginia. We're also excited that in January, we issued our inaugural investment-grade bonds. This offering provides substantial flexibility along with our free cash flow generation during this period that exceeded our initial expectations.

Next, let's turn to Slide #3 titled Antero Strategic Initiatives. Last quarter, we introduced our long-term vision and strategic initiatives. The HG acquisition marked significant progress towards all of the goals we highlighted. These include expanding our core Marcellus position in West Virginia. This transaction added 385,000 net acres and over 400 drilling locations, extending our core inventory life by 5 years, increasing our dry gas exposure. Our larger production and inventory base positions Antero to capture the significant demand opportunities from LNG exports in the Gulf Coast and data centers and natural gas-fired power plants regionally, adding hedges to lock in attractive free cash flow yields, providing high confidence in our free cash flow outlook over the next several years, reducing our cash costs and expanding margins.

The transaction lowers our cost structure by nearly 10%, assuming no changes to commodity prices and expand margins. This, in turn, lowers our peer-leading breakeven prices even further. Lastly, it highlights the benefits of Antero's integrated structure with Antero Midstream.

Now to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments.

Thanks, Mike. The NGL market faced various headwinds in 2025, but many of these issues were singular events or trends that are expected to improve over the coming quarters. When looking back on 2025, 3 main fundamental forces caused propane inventories to move higher than market expectations. Slide #4 titled, U.S. Propane Stocks and Propane Days of Supply identifies these factors on the chart on the left.

As we enter 2025, propane inventory levels were trending with a historic 5-year average. However, U.S. trade tensions with China and the resulting reshuffling of U.S. propane exports to different destinations impacted U.S. export volumes. Additionally, this tariff shakeup came at a time when export expansions and existing terminals in the Gulf Coast were facing start-up delays or operational issues. Importantly, the chart on the right hand of the slide highlights the demand pull that persisted in the propane market last year despite these identified headwinds. Days of supply in 2025 consistently trended within the 5-year range due to strong export and domestic demand.

Turning to the supply side. While NGL supply is expected to continue to increase over the coming years, the rate of growth will likely moderate due to weaker oil prices. As shown on Slide #5, titled U.S. C3+ Supply Growth Slows, the chart on the left displays year-over-year U.S. supply growth decreasing from 328,000 barrels a day in 2024 to 131,000 barrels a day in 2026 and further to 45,000 barrels a day year-over-year in 2027. This deceleration is expected due to the lower oil price environment and the resulting reduction in oil-focused drilling activity, especially in the Permian Basin. This trend is likely to continue in the current WTI price environment.

Turning to exports. Significant LPG export capacity expansion was added in 2025, and there is more to come in 2026, entirely removing any potential market bottlenecks. Slide #6 titled, Timely and Service Dates for LPG Export expansions illustrates that LPG export capacity should be unconstrained through at least 2028 allowing U.S. barrels to continue to clear the market. Slide #7 illustrates the significant global NGL demand growth that is forecast for 2026, following several years of declining demand growth 2026 demand is expected to grow 563,000 barrels a day, the largest annual increase since 2021, driven by LPG increases in the steam crackers, rising PDH demand and annual res/com growth. On the bottom of the slide, you can see the C3+ NGL price going back to 2021. Today, prices are above $35 per barrel, but with the backward-dated strip, the annual average is $33.50 per barrel. To put pricing into context, a $5 move in C3+ NGL pricing equates to $225 million in annual free cash flow.

All of these factors lead third-party analysts to forecast propane storage levels returning to within the normal 5-year range by the end of 2026, which should result in improving prices throughout the year.

With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas markets.

Thanks, Dave. I'll start on Slide #8, which shows the Winner Residential and Commercial Demand. This winter, res/com demand has been extremely strong, with November through February, averaging nearly 42 Bcf per day. This results in an incremental 350 Bcf natural gas demand compared to the 5-year average and is over 1 Bcf above last year.

Further, January demand averaged over 50 Bcf, ranking it as the third strongest January res-com demand on record. January also saw the highest level of industrial natural gas demand on record dating back to 2005, which we believe to be in part related to the continued growth in behind-the-meter power demand for data centers.

Turning to Slide #9 titled Natural Gas Storage. The result of this strong winter demand has been a dramatic flip in storage levels. At the start of the winter in November, storage was approximately 200 Bcf above the 5-year level. Today, we are approximately 140 Bcf below the 5-year loan. This should result in exiting withdraw season below the 5-year average. Last year, we experienced mild summer demand, which drove storage levels to the high end of the 5-year range by the fall. We believe substantially higher LNG demand, which is up over 5 Bcf a day from a year ago even before the imminent startup of Golden Pass. Along with an increase in gas-fired power demand year-over-year will likely moderate storage injections in 2026 relative to historical levels.

Supporting strong LNG export demand this year are the European storage level deficits versus the 5-year average that continue to widen. Currently at approximately 600 Bcf below the average and are now approaching the historic low levels of 2022. This should [indiscernible] robust U.S. LNG exports to Europe throughout this coming summer. Next, on Slide #10, let's look at the pricing improvements at some of the hubs that we sell significant gas to. The chart on the left-hand side of the slide shows the TGP 500L basis streak. With the Plaquemine LNG facility consistently averaging feed gas of over 4 Bcf per day, we've seen increasing demand along our TGP 500L firm transport path, driving a higher premium at the delivery point relative to Henry Hub. For the full year 2026, the premium is now plus $0.66 to Henry Hub, the highest level we have seen on an annualized basis.

Next, the chart on the right of the slide shows local basis pricing relative to Henry Hub. Local pricing for 2026 is currently $0.74 back of Henry Hub compared to the $0.88 differential over the past 5 years on average. We believe this local basis differential could tighten further, driven by East region storage that is more than 13% below the 5-year average. As an example, the recent winter weather event, combined with this low storage in the East, led to February TCO prices settling at just approximately $0.15 differential to Henry Hub, the tightest February differential in 10 years. Our acquisition of HG Energy substantially increases our exposure to strengthening local prices, driven by the significant regional demand growth. Historically, low storage in the East combined with this regional demand growth could result in a need for increased supply, supporting a decision for our growth capital option that Mike detailed earlier. This significant regional demand growth is driven by new natural gas power generation and data center projects being announced throughout our region and along our firm transportation corridor.

All of these projects will be competing for natural gas that could face supply challenges in that short time frame. The HG acquisition increases Antero's dry gas production and drilling inventory, boosting our exposure to this regional demand. Our coordination with the Antero Midstream's ability to build out infrastructure and it supply the substantial water needs at these facilities, combined with our extensive land team puts Antero at a competitive advantage and participating in these projects.

With that, I will turn over to Brendan Krueger, CFO of the Antero Resources.

Thanks, Justin. I'll start with Slide #11, which highlights our 2025 financial and operating results. Our operational performance in 2025 was one of our best years yet, as we set numerous company records.

During the fourth quarter, we achieved a new stages per day company record for a single completion group hitting 19 stages in a day. For the full year, we averaged over 14 stages per day, an 8% increase from the 2024 average. Our drilling team achieved its best annual rate averaging under 5 drilling days per 10,000 feet, 4% faster [indiscernible]. The chart on the right-hand of the slide highlights our 2025 financial highlights. During the year, we generated over $750 million in free cash flow. We used this free cash flow to reduce debt by over $300 million, repurchased $136 million of stock and invest more than $250 million in accretive acquisitions. The strength of our balance sheet and the consistency of our free cash flow operation supports an opportunistic return of capital strategy where we can pivot between debt reduction, buybacks and accretive transactions or a portfolio approach to all of these in order to drive shareholder value.

Next, Slide 12 highlights our 2026 production and capital outlook. Starting with the capital table at the top of the slide. Our drilling and completion capital budget is $1 billion. This includes $900 million for maintenance capital and $100 million from the higher working interest as a result of foregoing a drilling joint venture partner this year. Additionally, we have an incremental 3 pads that we could develop in 2026 that would add up to $200 million of growth capital during the year and drive further 2027 production growth. The bottom of the slide highlights our production outlook. In 2025, we averaged 3.4 Bcfe a day. For 2026, we forecast 4.1 Bcfe a day of production. This maintenance production level reflects the early February close of the HG acquisition and the expectation that the Ohio Utica divestiture closes in February.

Next, as we have discussed, we laid out growth to 4.3 Bcfe a day in 2027 due to not having a drilling JV this year and a growth option that could increase our 2027 production up to 4.5 Bcfe a day. This discretionary growth option will be based on the outlook for natural gas prices and in-basin demand during the year.

Now let's turn to Slide 13 to discuss our updated hedge program. To derisk the acquisition of HG, we hedge those volumes to provide a clear path to funding the transaction in just 3 years, using the free cash flow from those hedges along with the divestiture of our Ohio Utica assets. In 2027, we are hedged with a combination of swaps and white collars. We have approximately 40% of our 2026 natural gas volumes hedged with swaps at a price of $3.92 per MMBtu. We have another 20% hedged with wide collars between $3.24 and $5.70 per MMBtu. Our hedge book allows us to protect the downside by locking in a portion of our free cash flow, while at the same time, maintaining attractive exposure to higher natural gas prices.

I will close by commenting that while our equity value remains near levels from before the HG acquisition, our company is much stronger today. Through the transaction, we increased our production base by over 30%, extended our Marcellus core inventory by 5 years, reduced our cash cost by nearly 10% and substantially increased our free cash flow. We achieved all of this without using any of our equity, and we expect leverage by the end of 2026 to be similar to where we were prior to the HG acquisition, which was just below 1x. Looking forward, we are well positioned to capitalize on the significant natural gas demand growth expected both on the LNG front and the Gulf Coast and from the significant power demand that we see occurring regionally.

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

[Operator Instructions] Your first question comes from John Freeman with Raymond James.

The first topic just on the growth capital, just wanted to know if you could kind of provide a little bit more color on sort of what kind of in base demand, gas price assumptions you all would need to kind of support that growth plan kind of relative to the current strip and outlook?

Yes, John, our goal is always to have the most capital-efficient development program, and we do have that. But what that leads us to is to try to have a steady-state program. So we're running 3 rigs and 2 completion crews right now. So maintaining that wood resulting growth not only in '27, at a couple of hundred million a day, but also in the further out years, but an attraction of this though is that is flexible. We have the ability just to do our maintenance capital program with leading and drilling 2 or 3 less pads and still maintaining production and then deferring those pads in the future years. You saw us do that in 2024 when you had kind of a $2 gas environment or [ teller ] plus. But then when the natural gas return to more kind of the $3-plus level. We completed those paths. So that's kind of the expectation here.

All of that is -- has the ability to be deferred. It's all second half capital. So we can call a multiple then. But if you saw a $3-plus gas, and as Brendan mentioned in his comments, the local differentials being so tight, that continues. You'd probably see us complete those pads and drill those pads, but if it was lower gas environment, we defer those into future years. The other nice thing on this capital and this growth, it's not based on any commitments. So it truly is flexible. It truly is an option value for us. No commitments with that, it is all local gas. And with the discussions we're having and the prices we're seeing, and we've actually already entered into some sales to utilities off of MVP as those continue we'll complete those pads into those opportunities.

That's great, very helpful. And then just my follow-up. On Slide 11, you'll show kind of the breakdown of the uses of the free cash flow last year, roughly about 20% of the free cash flow went to buybacks. And as -- Brendan, as you mentioned, the leverage will be back below 1x before the end of the year. Is there any sort of like just sort of absolute debt target or something like that, that we should be looking at to where you would then potentially maybe more aggressively shift toward buybacks? And I know you're being opportunistic, but if there's just some sort of metrics we should be following.

No, there's no metrics. I think we're better positioned now than ever to be countercyclical in buying back shares with our hedge position, our size and scale, very comfortable buying back shares regardless of where our debt is right now.

But with that said, paying down the debt is normally when we actually perform the best from an equity standpoint, derisking the business, getting it under 1x as a result of this year's activity. But if there is an ability to opportunistically buy back shares and be countercycle, that's something that we would take advantage of.

Your next question comes from Arun Jayaram with JPMorgan.

Mike, you've had -- it's been just over 60 days since you announced the HG deal. And I was wondering as you look a little bit more under the hood thought on potential upside potential to the synergy number. I think you identified $950 million of PV-10 synergies. Just maybe thoughts on where you stand regarding synergies and how do you think about potential upside or better capital efficiency even as we look at 2026.

Yes, Arun, it's actually better than our expectations. I was actually out there last week. It's really apparent when you go out there. It is part of our field. It's adjacent. It should have -- we're the natural developer of it, just extends our field south to that southern row of dry gas and liquids opportunities, a little flatter down there, bigger pads and ability to have wider space and do bigger completions have terrific recoveries.

The other thing that's come to our attention is just an improvement in our cost structure. And that's coinciding with all this local gas demand and better in-basin pricing, which we didn't underwrite and didn't have. So there'll be some upside on the pricing, I think. And then I think there'll be further upside on the cost structure and recoveries and expanding our margins.

Great. Great. Mike, just maybe a follow-up. I believe on the third quarter call, you highlighted how Antero was completing one of its kind of first dry gas pads in a number of years. And I was wondering if you could give us any sense if you have enough data to maybe to give us some thoughts on how the results played out relative to your expectations? And does this set up more of an opportunity for AR on the dry gas side?

The completion crew right now is on that pad, the [indiscernible] pad. So it just went on there this week, Arun, moving from the [indiscernible] pad over to that. So still early on that, but we have high expectations for it and very confident in its results.

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

It's Kevin MacCurdy. As we look at the production ramp this year, you end up at the same spot, but the ramp is maybe a touch lower than we were expecting. I wonder if you could maybe touch on the variables that impact that ramp. And does that ramp mainly on the acquired assets?

Yes. On the production, it's not a touch lower. It's as expected. We gave some quarterly performance. We closed it quicker than we thought when we mentioned the [ 4 2 ] on the initial call, that was from Q2 to Q4, it's still 4 2. It's 4 1 now in Q2 with a turn in line happening in the middle of the quarter that pushes that up to 4 2. So it's as expected. So the cadence is terrific and then goes to 43 in '27. And then with the growth capital that we have if we execute on that plan, we'd be at 4 5 in '27.

Great. And maybe shifting to NGLs. As we track the C3 prices for Antero, it looks like domestic prices haven't moved much this year. But international prices have been driving your forecast as C3 price for the year up a little bit. I wonder if you can touch on maybe what you think is driving that arbitrage and how you think that progresses through the year? And maybe is Mont Belvieu fully debottleneck now? Or are we waiting on further expansions this year?

Yes, Kevin, this is Dave. I'll take that one. So on your first question on the -- what's driving the international pricing, typically, we see this time of the year in the winter, propane prices really kind of rise relative to naphtha. So we're seeing levels that are kind of in line with what we've seen in prior winters. But certainly, some of the issues that we had on the U.S. export infrastructure side, kind of a lower or a later start on some of the expansion capacity that maybe we had anticipated, some challenges at some bullet refrigeration units.

As I mentioned in my comments, kind of led us to see the inventories in the U.S. kind of go a little higher than what folks were modeling and expecting at that point in time. So I think here in the first quarter, we're seeing those issues resolve. We typically have some fog challenges, the winner as we always do, but strong domestic demand is kind of keeping that from being too noticeable in the inventory levels. But just the usual international markets having a strong desire for U.S. LPG. And when they see any kind of hiccup of the dock and kind of the peak demand season of the winter, you see that flow through in the pricing, while we always see that appreciation versus naphtha.

And then yes, on the export side, I would say, really seeing -- even though we kind of talked about expansions in 2025, didn't really see the effect of those until we get into calendar year 2026 and then further expansion is coming. So kind of view us really at the front end of that debottlenecking in the Gulf Coast right now.

Your next question comes from Greta Drefke with Goldman Sachs Asset Management.

My first is just on the winter gas realizations. Given the volatility in both the Gulf Coast and Northeast pricing this winter we've seen so far, can you speak a little bit more about your outlook for gas realizations in this quarter in particular? And just key considerations to keep in mind in the context of your scale of volumetric exposure at the Gulf Coast and the moving pieces of the 2 transactions?

Greta , I mentioned in my initial comments, we didn't have any curtailment. So obviously, we've anticipated in the pricing that occurred in region and on the Gulf Coast in the first quarter. So we typically have 80% first of month and 20% on the day. So we were able to sell 20% daily pricing during the quarter.

Great. And then a quick follow-up as well just on hedges. Given the amount of volatility we see start of the year, can you just talk a little bit about your current view on potentially layering in incremental hedges in 2027 or beyond if the forward curve gives you that opportunity?

Yes. I think you said that well, '26 were set 60% hedged in the high $3 level and some white collars. '27, we have some room to go. We're about 900 million a day hedged. So about 30% hedged in that high $3 level. I think a high $3 level is a good area to target. The other thing to note is the M2 basis has really come in. I think it's the tightest it's been on a forward-looking curve in 10 years, ability to hedge at about 75, 76 back level. So you have high $3 and hedge the local basis at 75, 76, lock in $3 realizations at the wellhead locally that's an attractive level for us. So I think we continue to layer some of those in.

And your next question comes from Josh Silverstein with UBS.

Just going back to the cost structure. Can you talk about how this may change throughout the course of the year? I believe you talked about the $0.25 per Mcf margin improvement. Do GP&T costs start higher than decline? So you also see a benefit into 2027 versus 1Q of this year? Any sort of direction there would be helpful.

I think you touched on it, $0.25 is a good level. Obviously, there's some variable component to our cost structure. You recall, every dollar up in the natural gas price is about a $0.10 variable just on production taxes and transport costs on RFP. So you had a little bit of that up compared to that when we mentioned in December because the gas curve is actually up $0.60 of '26. So you saw about a $0.06 increase from there. But conversely, our realizations as well are still in that $0.10 to $0.20 premium whereas we thought would be more flat. So the ability at 800 million a day of local dry gas and still have a $0.10 to $0.20 premium to NYMEX for '26 is terrific. So looking good there, but I think you hit on it about a 10% reduction in our cost structure, about $0.25.

Got it. And then I just wanted to shift over towards any sort of potential power supply deals that [indiscernible] others are progressing with the new HG volumes and some of the interconnects that you now have are a little bit better in West Virginia, however those may be developing? And you've talked about now improving kind of local basis as well, how you been able to structure these?

Josh, this is Brendan. So overall, I think on the power side, as Mike mentioned, I think it is prepared remarks, we're selling some of that gas already to utilities that are buying for a lot of this gas-fired power demand that we're seeing. I think on top of that, we continue to see RFPs come in quite frequently on additional gas supply in the next several years. I think as they get closer to being in service, they then turn to some of the larger gas producers and particularly investment-grade gas producers in the region to look to lock in some of that supply [indiscernible] pricing over time here.

And your next question comes from Phillip Jungwirth with BMO Capital Markets.

Your FT portfolio, it's always delivered leading realizations, smooth out price volatility. Most of this has signed up a long time ago. So I was just hoping you could talk about how you see yourself managing this FT position through the decade, including that associated with ethane, C3+. Is there any you don't feel the need to keep? And is there just a long-term margin optimization story here through recontracting or maybe even picking up different FTs from others who don't have inventory?

Yes, good question. Definitely in optimization. I mean, we're so well positioned right now. We can pick and choose the best path going forward, also now with flexibility in the local dry gas. So we can do both. And that's an opportunity for us over the next couple of years as some of these long-term agreements come to the end of their original agreement, we'll assess whether it makes sense. But that's a great story for us on a go forward and definitely upside our ability to optimize those transport paths and optimize our cost structure.

Okay. Great. And then as we think about the organic leasing program, I was just hoping you could kind of frame the competitive moat you have here in terms of existing footprint or infrastructure. There's still some smaller players in and around you. And just -- what's the pathway for some of these smaller E&Ps to efficiently develop their position? Or have you made it pretty prohibitive for them to do that given your large foot and surrounding footprint?

No, we are, obviously, the West Virginia natural gas and NGL producer and our size and scale makes a lot more efficient for us to develop the asset compared to others. So I think you'll continue to see us build upon that, whether through organic leasing or small transactions, but continue to just consolidate our position in West Virginia, and that will continue to drive our capital efficiency and lower cost structure and margins.

Your next question comes from Leo Mariani with ROTH.

Just wanted to follow up a little bit on the growth CapEx question. Obviously, you guys kind of cited that this $3-plus world is sufficient for you guys to go ahead and spend some of that growth CapEx. Just wanted to kind of clarify, is that a $3 Henry Hub price? Or is that more of a $3 kind of in-basin price, which seems like you're fairly close to that, given the tightening basis as we roll into next year? And then if you do decide to spend the capital, could you just provide a little bit of color in terms of what that looks like in the second half? Is most of that CapEx kind of fourth quarter and the production starts to ramp kind of early in '27? Just any kind of moving pieces around that would be great.

Yes. First part, it's more NYMEX-based. Like he cited, we can -- right now the market would say, $3 in basin for '27. But even if you had $3 NYMEX and that $0.70 back, you'd be in the mid-2s in basin and you're talking a dollar cost structure on this gas to our $1.50 margin even in that level. And it's $0.50 F&D. So you're still having terrific returns. These are all local dry gas pads. The optionality here is kind of one of the key points and flexible. There's no commitments around it. So we can judge you at the time and we can hedge it as we have been as well. So $3 plus kind of NYMEX is more where our head was at with that tight basis.

The second part is it's all second half capital. You won't see any of the production ramp until '27. Obviously, you have a 6- to 9-month kind of cycle on drilling, completing and turn in line dates. So there will be second half capital. We looked at it, it's almost all second half capital. It's like 95% all second half on these 2 to 3 pads and then the production comes on in the first half of '27.

Okay. I appreciate that. And just with respect to the buyback here, I was getting a sense, correct me if I'm wrong, I want to put words in your mouth, that the debt pay down is maybe a little bit more of a priority just given the fact that you kind of added some leverage, but you obviously have some nice hedges to take care of that. And the buyback is going to be maybe a little bit secondary and fairly opportunistic as well.

Yes, it's fair at this level. But if you do see any sort of opportunities on the equity, you should be pretty confident we'd take advantage of that.

Your next question comes from Kalei Akamine with Bank of America.

My first question is on the growth option. I'm wondering if that investment sets you up for 4.5 bcfed early in 2027 and what the new maintenance capital number is associated with that volume level?

That would be early in '27 and that's not a maintenance capital, running 3 rigs and 2 completion groups would add a couple of hundred million a day of growth in '28 and '29. So you continue to grow at that kind of $1.2 billion capital. Our maintenance capital would still continue to be $900 million-ish. That's kind of what we were looking at this morning. It's pretty remarkable. So maintenance capital stays relatively flat even at those levels. just highly capital-efficient development program.

Got it. I appreciate that. And for my second question, just kind of based on your comments, it sounds like the growth option will be on the dry gas acreage, whether that's legacy Harrison county or [ HGS ] that you picked up. Just kind of wondering if there's sufficient egress to move those growth volumes around the basin or if you'll be spending additional in capital at AM?

AM does have some capital to get around $20 million this year to build out our dry gas Eastern to connect all of the various pipes [indiscernible] and there's so much local demand that you'll be able to sell the gas locally.

And your next question comes from Subash Chandra with [indiscernible].

So just curious, maybe the question for Dave. What's the PDH outlook in China in '26?

Yes. So right now, I mean, current infrastructure is running in the 65% to 70% utilization range. We did have 4 plants that came on in 2025. So we're kind of continuing to see the absolute amount of volume that's capacity that's available in the ramps in that 300,000 to 400,000 barrel a day range and then 2 additional plants right now on the schedule to turn in line -- or come online, sorry, in 2026, and those totaled another 55,000 barrels a day of application [indiscernible].

Excellent. And then on -- it seems like the completions in '26 guidance is longer laterals than '25. Just curious if -- is any of that HG related? Or is that going to be more influential in '27?

It's pretty much all HG related, actually. That's one of the attractions here. I mentioned it in a row, but the they were able to design it as very efficient row that basically goes to [indiscernible] sale 20,000 feet both ways. It's kind of their average. So that takes us up to that 15,000 feet level from our kind of typical 13,000 feet. So definitely accretive on a lateral length HG development.

[Operator Instructions] And your next question comes from [ John Abbott ] with Wolfe Research.

I want to go back to the question, and I'll go back to growth. And the HG transaction has added to your inventory, I mean we've already sat here and discussed that you have the option to get to 4.5 Bcf per day in 2027, you could grow beyond that. I guess when you sort of think about your inventory in hand and when you think about NGLs and dry gas, how do you think about the extent that you are willing to grow just given your visibility [indiscernible]?

Yes, quite a bit. I mean, we are the ones that should grow. We have the most capital-efficient program. We have the FT that goes to the LNG exports. We have a local dry gas where it goes to where all the data centers and natural gas-fired generation is coming. So all the demand centers that everyone projects that's coming over the next 5 years. We're the best positioned for it and we have the best rock. So that's kind of where our head was why would we navigate through this by strictly enforcing ourselves at maintenance capital. We want to be the most capital-efficient developer, and that's always our goal. And so a steady-state program is always the way to achieve that.

So just running 3 rigs and two, completion crude flat would result in the most capital-efficient development and to toggle away from that based on monthly spot prices is not something that we probably do. And when you put that into our development plan, that results in this growth. So that's kind of where we came to on this. We are the ones that should be growing and meeting this upcoming demand, and we are the best positioned for it.

I appreciate it. And then the follow-up question here, I guess, it would be for Justin. So you were in the slide, you're highlighting the tightening of basin basis. I mean, I guess, the growth option here from bringing on the dry gas wells you're going to hedge that. But I guess when you sort of look at basin you tightening, how do you think about basis and growing into that base? How do you think about your impact to basis and the decision to grow?

Yes, I mean, we're talking a couple of hundred million a day of growth. I mean the demand members you're seeing are well in excess of that. So on a percentage basis, it's probably -- we're actually probably not adding to the or detracting from the supply and demand picture. So this isn't terrifically material. You're talking 200 million a day of gas production growth versus B and B a day of gas demand.

Your next question comes from Sam Margolin with Wells Fargo.

Back to your point on capital efficiency. It looks like just from your production guidance and your activity guidance that HG was -- had a positive impact on your corporate decline rate. Is that accurate? And if so, could you help quantify that a little bit? I'm just looking at the production from this spending.

Yes, our capital decline actually was in the low 20s. There is a little bit above that kind of mid-20s. But what we have is -- you have a flatter production file, you have some pent HG flatter. The midstream system has more of a kind of a flat production profile on the wells in the first couple of years, whereas ours is more well plumbed. So it's fairly similar, but a lot of their production had a constraint is around midstream. And so it's got a flatter production profile in the first couple of years.

Got it. Okay. And then just on the commercial side, there's a lot of focus on power, but the industrial piece along some of your firm transport destinations also has growth prospects? Are there any commercial or fixed gas supply opportunities in that category?

This is Justin. We've spoken about this in previous calls, but Antero's firm transport book is set up with approximately 2 Bcf that heads down to the Gulf Coast, which Mike mentioned that gets into the LNG corridor. And within that path, not to mention what the local growth will be, and we have different capacity that will pass by those end users, just if you think geographically, Kentucky, Tennessee, Mississippi, all the way down to the LNG corridor, we've identified potentially 4, 6 Bcf of different demand that would be a potential fit with the Antero firm transport delivery. So we continue to have those conversations.

As Brendan mentioned, we continue to get RFPs for different supply for these data centers and power projects. And we've touched on this in the past as well. But the competition for that volume outbound will continue to increase over the next couple of years.

And we have reached the end of our question-and-answer session. So I'll now hand the floor back to Dan Katzenberg for closing remarks.

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

This concludes today's call. All parties may disconnect.

Greetings, and welcome to Infinity Natural Resources acquisition of Antero's Ohio Utica Shale assets. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, David Sproule. Thank you. You may begin.

Thank you, operator, and good morning. Thank you for joining us today for this special conference call to discuss our acquisition of the Ohio Utica assets from Antero Resources and Antero Midstream. Joining me today on the call is Zack Arnold, President and CEO. We have also posted a presentation to our website to accompany our remarks today. Before we get started, I will remind everyone that the remarks on this call reflect the financial and operational outlook as of today, December 8, 2025.

I'd like to remind you that today's call may contain forward-looking statements. All statements that are not historical facts are forward-looking statements. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control that could cause actual results to materially differ from these forward-looking statements. Please review our press release and the risk factors discussed in our SEC filings. We will also be referring to certain non-GAAP financial measures. Please refer to our press release and investor presentation for report disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures. Now over to Zack.

Thank you, David, and thank you for joining the call today. We are extremely excited to announce Infinity's transformational and accretive acquisition of Antero Resources and Antero Midstream's assets in the Ohio Utica. During our IPO process, less than 1 year ago, we talked extensively about how complementing our high-growth, high-return asset base with accretive bolt-on acquisitions would be core to our strategy. Today, we are delivering on that promise. With this acquisition, we are taking the first significant step in this important part of our journey as a public company.

Let me share the transaction structure and financing details upfront. Total consideration being paid for the assets is $1.2 billion, and we have strategically partnered with Northern Oil and Gas on this transaction. More specifically, Infinity will acquire a 51% interest in the assets for $612 million and Northern will acquire the remaining 49% for $588 million. We expect the transaction to close in Q1 2026 and plan to fund it with cash on hand and borrowings under an expanded $875 million credit facility. Most importantly, we are not issuing any equity to pay for our stake.

Now turning to the strategic rationale. Put simply, we are confident that the combination of Infinity and Antero's Ohio Utica upstream and midstream assets is poised to deliver shareholder value, both in the near and long term. This transaction represents a truly unique opportunity in Ohio for Infinity for 3 main reasons. First, the asset is highly complementary to our existing operational footprint with approximately 71,000 net acres located adjacent to our core position in Guernsey County, Ohio. Second, these assets provide a high-quality inventory across multiple phase windows from volatile oil to dry gas. And third, and a factor that is particularly differentiating is that by also acquiring a strategically important midstream system we are optimizing our ability to control costs and development timing while simultaneously driving operational efficiencies and delivering high return, disciplined growth over the years to come.

Let me provide some additional details. From an operational perspective, these assets truly fit hand in glove creating significant scale and synergies that are substantially enhanced our already best-in-class capital efficiency among our Appalachian peers. Combined with our existing Ohio Utica position, the acquisition creates a pro forma position of approximately 102,000 Ohio net horizontal Utica Shale acres with approximately 1.4 Tcfe of undeveloped net reserves in Ohio and a total of 3.2 Tcfe reserves for the company. The acquired assets include approximately 71,000 net acres in the core of the Ohio Utica Shale concentrated in Guernsey, Monroe, Noble, Belmont and Harrison Counties, providing development opportunities across volatile oil, rich gas and dry gas windows.

These assets produced approximately 133 Mcfe per day during Q3 2025 from 255 producing laterals. With 111 undeveloped laterals totaling 1.6 million lateral feet with 764 Bcf of net undeveloped reserves to INR. This acquisition is not merely about scaling up. It's about enhancing the quality and depth of our portfolio. The acquired inventory provides more than $1.1 billion of capital projects with a discounted return on investment or DROI greater than 2x. Additionally, the midstream system we are acquiring spans over 140 miles and is capable of gathering volumes in excess of 600 million cubic feet of gas per day. The midstream system has an estimated replacement value in excess of $500 million.

We expect Antero's assets to seamlessly integrate into our existing operations competing effectively for capital within our portfolio immediately. We're tremendously excited to execute on this opportunity, and it is immediately accretive to key financial metrics, including adjusted EBITDA margins, cash flow per share and net asset value per share. The anticipated strong free cash flow generation creates a path to a net leverage ratio that is at or below 1x by year-end 2027.

Post closing, Infinity expects to increase its operated rig count to 2 rigs. This enhanced drilling program is designed to deliver leading production growth in 2026 while maintaining a continued focus on high return, low breakeven locations, optimizing development across Infinity's combined portfolio and achieving enhanced capital efficiency through operational synergies. We expect to deliver $25 million of synergies in 2026 alone. The contiguous nature of the acquired acreage enables optimized development planning, shared infrastructure utilization and operational cost reductions.

Other opportunities include longer laterals through the highly contiguous acreage, shared facilities, shorter rig and frac crew moves, reduced operating costs through the acquired midstream infrastructure and enhanced control over product, transportation and pricing through RexZone3 marketing contract. We're also excited about the significant opportunities to enhance the acquired assets by leveraging our technical expertise, operating capabilities and regional know-how. As we execute this transformational acquisition, it's important to note that it builds upon an already exceptional 2025 performance. Through the first 9 months of the year, we delivered more than 30% production growth while executing our nearly evenly split oil and natural gas drilling program.

This strong operational momentum demonstrates the unique optionality that our strategic positioning provides across the Appalachian Basin. With our proven ability to optimize development across both our Ohio Utica oil properties and Pennsylvania Marcellus natural gas assets. We're tremendously excited about expanding our Ohio Utica position through this acquisition and complementing it with our high-quality Pennsylvania Marcellus and deep dry gas assets. The combination of our proven execution capabilities across both areas, enhanced by this accretive acquisition positions Infinity to deliver sustained growth and exceptional returns across our diversified Appalachian portfolio in any commodity environment. We look forward to updating you on our integration progress and the value creation opportunities ahead. Operator, over to you for Q&A.

[Operator Instructions] First question comes from Michael Scialla with Stephens.

Congrats on the deal. I wanted to see if you could talk about the development plans for the new assets. Will you stay focused initially on the volatile oil window? Or do you have plans to develop the gas assets as well?

Thanks. That's a great question. We're going to -- we'll talk a lot more about our 2026 development plan later. But I think as you sit here today and think about how we approach this asset, there are some locations that are currently being developed that are closer to that volatile oil window, and we'll begin to work with the assets and the regulatory process to permit wells across the entire position. So it's difficult for me to steer you to exactly how we'll allocate capital across the phase windows immediately, but we see a great amount of value and ability to drill some of those gassier projects early in the development life.

Great. And I wanted to ask on midstream assets with the throughput capacity there of 600 million a day. Was that just overbuilt? And you mentioned in your slide deck some attractive third-party gathering opportunity. Can you provide a little bit more detail on what that looks like?

Sure, sure. So if you go back and -- and Michael, this is David. If you go back and you look at Antero's history with this asset, you'll see them that they had ramped up production and then had slowed production for whatever reason that they decide to do that. So the system was built to move as much volumes as they were doing in the past. But I think as you look to the future here, to answer your kind of both the questions, we intend to utilize that system quite robustly. We will be -- we intend to be highly active on the development across all phase windows in earnest. I think the other thing that it brings, given that it's 140 to 141 miles of gathering lines as it brings a unique opportunity to bring in other volumes associated with nonoperated or third-party gas volumes.

And you can see that as it lays out just the regional expansion and the strategic nature of it. The other side of it is, it's also got a 90 miles of water systems in there water lines that allow us to complement our ongoing and accelerated development options. So we're really excited about that. It gives us an extremely competitive advantage and controls our midstream aspect, controlling costs, controlling operational time lines. It is a key asset for us, both near and extended terms.

Another point to share with you when you think about third-party volumes in Ohio with the statutory unitization process, in many of the units we develop, we will have working interest partners other than us in NOG in those units, which will provide some cash generation from the gathering of those molecules.

Our next question comes from Tim Rezvan with KeyBanc Capital Markets.

I want to follow up a little bit on Mike's question on the inventory number. You mentioned you're across the different phase windows. Should we think about this inventory as roughly split kind of going from the liquids-rich gas to the dry gas area? I'm just curious if you can provide any context on inventory in the different phase windows.

I would say that we can -- we'll look at providing additional information around that. I think where we are today, there's about 60 to 80 locations that are gas weighted on this. So while it does cover all 3 windows, it does have a weighting towards more dry gas windows than the volatile oil windows. What's exciting for us is, if you look at the map and you see the -- some people talk about it being in relative proximity. This is literally adjacent. You step off our line, you're on to theirs. And where we bring a lot of extensions and capacity and inventory out of volatile oil window, this accentuates that, it elongates that and then complements it both from additional inventory in that volatile oil window, but then provides rich gas and extensive dry gas inventory base as well there.

Okay. Okay. That's helpful context. And then maybe this is for you as a follow-up, David. Can you talk about how you landed on that, that 51% working interest? Was there sort of an upper end year to your willingness to lean on the credit facility. Just kind of curious how you ended at that working interest.

Yes. And sorry for the noise in the background, there's some construction going on outside. But I think for us, we looked at managing and maintaining the strength of our balance sheet. As you look out into the future, we anticipate that balance sheet coming back down relatively quickly to our target leverage of being under 1. I think from our standpoint, maintaining a healthy balance sheet and with your development allows you to not only exploit the asset that you're acquiring, but also lets you lean in and capture additional opportunities that become available. And so we're cognizant of both the near-term transactions as well as the future transaction, future development that we have.

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

I guess what stands out to me on this deal is the runway on the midstream FT at 600 million cubic feet per day. It looks like a solid fit with your growth strategy. So my question is, how is that FT being used today? As you guys grow, are you going to back out marketing volumes and therefore, third-party revenues?

So say that again, Kalei. I just want to...

So this piece comes with 600 million cubic feet of FTE on the REX pipeline. My question is, how is that FTE being used today? Is it being leased out to other parties in the region? And if other parties are using it, then there's already volumes on it, and therefore, it's generating third-party revenues. So my question is, as you guys grow, will those third-party revenues on the FT piece fall?

Yes. I think -- so first and foremost, we're acquiring 300 million a day of FT with this. That's our RexZone3 contract. One of the interesting things about this contract is our ability to utilize it not only for the volumes that we're moving that we're acquiring, but also for the volumes that we have that we push into the Seneca plant in Eastern Ohio. So there's a considerable amount of synergistic aspects there of high-grading that. As we look to accelerate development here on the target asset, we are highly confident of our ability to step into additional FT as we need it, but do not anticipate needing that for the near-term horizon.

So again, this transaction came with a significant FT that we're able to utilize. Moreover, it is a very attractive contract that we have a RexZone3 contract that provides a material uplift for us. And so we were excited to grab that contract, again, to leverage not only the volumes and the development of the asset that we're acquiring, but also our legacy assets that are in Guernsey County, Ohio.

Kalei, maybe just to clarify a point for you to separate the 2. David described the REX FT. That contract associated with that premium pricing on those molecules. The system has a physical capability of moving 600 million cubic feet a day. So those are sort of 2 separate statistics. One is the pipe capacity and the size of our -- of the midstream position that we bought. And then the second is the FT contract.

That makes sense. My apologies. For my second question, I want to ask about inventory depth. So here, you called out 110 undrilled locations. Is there any upside to this number from perhaps exploring deeper zones or other zones in the area? I know some folks are testing the Marcellus. Do you guys have any intention of doing that?

So first and foremost, we bought this -- bought about 111 locations. It's about 1.6 million lateral feet. So when you kind of adjust it, again, not all -- not everybody's inventory is created equal, and ours is consistently longer than our peers, broadly speaking. So in this scenario, the 111 would reflect kind of 164 adjusted lateral locations. Those are all just the Utica laterals. We underwrote this associated with that development, but are cognizant that there could be additional opportunities in shallower zones.

The other thing I'd point to you, Kalei, is the slide that we had in the deck, it's Slide 8. And I think this one really goes to show you that we have one of the interesting and exciting aspects of Infinity. If you look at what we bought, those would be that sort of pinkish orange-ish color that we have acquired. And when you look at that chart, we acquired over $1.1 billion worth of development opportunities that generate over 2x discounted return on investment. That is extremely rare and extremely exciting for our company.

It's a good deal, guys. Thank you.

Our next question comes from Nicholas Pope with ROTH Capital Partners.

Curious, you kind of talked a lot on the production side on an 8/8 basis. Curious what the royalty rate is running up there because I assume that's not part of these -- the numbers provided. And also, is Northern also 49% of the acquisition on the midstream asset. Just clarifying some stuff.

Yes. So typical royalties in Ohio range from 18% to 20% depending upon where you are, et cetera, et cetera. And then your second question asked with regards to the midstream, yes, Northern is 49% of both the upstream and the midstream assets that we acquired.

Our next question comes from Neal Dingmann with William Blair.

My first question is just really looking at what I'd call sort of the pro forma CapEx specifically, could you talk about -- David, you laid out nicely just the perspective for the midstream, how that fits in well. So when you look at '26 plans, I know you don't have fully guide out there yet. How much will you all have to allocate just in broad strokes, sort of upstream versus midstream when you think about that working together?

I think more near term, one of the unique things about the system being as expansive as it is, is the limited need to expanded further for near-term development. So we do not anticipate a significant stat with regards to that system in 2026. I think that Zack kind of noted, we will provide additional color in the first quarter with regards to our 2026 guidance, but we anticipate being extremely active on the development of this area of Ohio.

But I think what David was saying is spot on in which this midstream system because of it's the way they've been built out historically, we get to lever for a ton of development. So when you think about what midstream capital is going to be, I don't want to say there's none because that's not going to be the truth, but it's going to be -- the capital allocation to the upstream is going to far outweigh the midstream, while we're able to lever the existing water pipe and compression infrastructure that Antero invested in historically.

Exactly. That's what I was getting at, Zack. It feels like they've already spent a lot of money there. That's exactly where I was going. Does it appear like you all have to spend a ton on this to have the growth that you want.

That's exactly right.

Got it. And then just a second one, just looking at that sort of thinking about future production growth, does this deal change how you all think about kind of what you'll target, meaning sort of liquids or dry gas, you're fortunate to have the ability to sort of target what you like and how to go about it. Does this deal sort of change anyway what you'll kind of what you'll be targeting in the future growth?

I think one of the things that we liked about this deal is the complementary aspects of all phases of our development, right? It has volatile oil, has rich gas and has dry gas assets. We -- historically, and this is no different than any time going forward, we'll start the year with more of a balanced approach and then we might skew one way or the other. We are cognizant of the fact that natural gas returns look a little bit more elevated than our oil-weighted returns in the current commodity environment. And so we shall look to skew that development accordingly. As you think about our overall growth, we talked about adding -- maintaining a second rig at closing. And so you should anticipate that to manifest into the 2026 development that we embark upon. And so as a result of all of that, we expect to have to maintain our industry-leading growth profile, developing these assets out of cash flow.

[Operator Instructions] Our next question comes from Noel Parks with Tuohy Brothers.

Just one thing I was wondering, is the acquired acreage all HBP from pit production?

That's a great question. So a large percentage of the acquired acreage is HBP, and we see additional opportunities in which we can go out and organically lease to continue to augment this position.

It is not a material part of the acreage that we got that is non-HBP and candidly, we do not anticipate any of those acres expiring on us with our development.

Okay. Great. And you were asked a little earlier about alternate horizons in the plan and emphasized that it was underwritten -- the deal was underwritten just on the Utica. Is there -- and you also talked about lateral length. Are there any spacing adjustments that you might make as far as density. I'm just wondering if you sort of philosophically were well aligned with how Antero had developed the assets to date or whether you had any differences there?

That's a great question. And I think it's the spacing question, the alternate horizon questions, I think all of these are really interesting. When we step back and kind of look at this deal, feel like we bought 3 things all at the same time. We bought a really great production base. It's low decline. Will let us continue to build our development on top of that. I think we've got that at an attractive multiple. We get the midstream at an attractive multiple, and we have this undeveloped inventory that we're really excited about, and we underwrote that inventory very conservatively. So working with Northern, making sure they understood our development approach we have underwritten fewer laterals than what we may, at some point, decide to drill on the assets as we would -- at certain commodity prices, we may choose to drill some wells at tighter spacing.

But historically, it's been our view that spacing them appropriately yields better economic results. That's the case that we've underwritten. But our team always identifies ways to add on additional lateral length, additional laterals to the flanks of the units that we drill, and we'll be watching very closely the development of the Marcellus near our Eastern acreage in this position.

Michael, are you there, you're live with our speakers.

Sorry. Yes, I just want to follow up. You mentioned the RexZone3 FT and the improvement in price realization. Just wanted to see if you could quantify that in any way.

Yes. It just depends on the time of month or I should say the month of the year. But on average, it would be somewhere between $0.15 and $0.20.

Okay. Great. And then looking at Slide 7, you show a 4-year outlook there on the midstream assets or the gathering assets, 33% compounded annual growth rate. Is that based on your activity alone? Or does that include some third party? And can you talk about the general assumptions that underpin that forecast?

Yes. Michael, that is all of our development that we're talking about there.

And is that just assuming the 1 rig on the Antero assets? Or does that have some...

No, as part of the excitement of this asset is the nature of the wells allow you to gain significant growth in cash flow just on a 1 rig program. Would we accelerate that further? Yes. It's something that we evaluate, but what you see there is a 1 rig development cadence.

We have reached the end of the question-and-answer session. I'd now like to turn the call back over to Zachary Arnold for closing comments.

Thank you. We are excited about these assets. Thank you for joining us today, and we look forward to continued success together.

This concludes today's conference. You may disconnect your lines at this time, and we thank you for your participation.

Greetings and welcome to the Antero Resources Third Quarter 2025 Earnings Call. [Operator Instructions] Please note, this conference is being recorded.

I will now turn the conference over to your host, Dan Katzenberg, Director of Investor Relations. Thank you. You may begin.

Thank you for joining us for Antero's Third Quarter 2025 Investor Conference Call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Power, Senior Vice President of Natural Gas Marketing. .

I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'd like to start on Slide #3 titled Antero Strategic Initiatives. We are entering an exciting time period for the natural gas market rarely have we witnessed such a visible step change in demand. This significant demand growth is driven by increasing U.S. LNG exports combined with the surge in natural gas power generation that is accelerating from the build-out of new data centers. Antero is poised to benefit from the structural demand changes through our long-term vision and recent strategic initiatives, which includes adding to our core Marcellus position in West Virginia. We accomplished this through both bolt-on transactions and continuing our organic leasing program to increase our position in the West Virginia Marcellus fairway. Returning to West Virginia dry gas development to highlight our ability to quickly respond to the regional demand that is beginning to show up in Appalachia.

We can either supply directly into future demand projects or grow into a local market if the local basis tightens. Also used hedging as a tool to lock in attractive free cash flow yields to support our dry and milling gas development program and our efforts to be countercyclical in transactions and share repurchases. We believe the execution of these strategic initiatives will enhance our ability to capitalize on the significant demand increases that are expected for natural gas over the long term. Now let's turn to Slide #4, which highlights our third quarter operating results. Continuing our trend of improving our drilling and completion results, the third quarter was our most impressive operating performance to date.

We set numerous company records and achieved significant progress. The right-hand side of the slide highlights the various company records [indiscernible] feet. On the completion side, our completion stages per day continues to climb higher, averaging another quarterly record at 14.5 stages per day or 2,900 feet per day. And as Patterson-UTI highlighted on the call last week, we set what we believe to be a world record for continuous pumping hours -- 15 days of nonstop pumping hours, a truly remarkable fee. Next, let's turn to Slide #5, titled Marcellus Core Fairway expansion. Our additional land investment is driven by the ongoing success we are seeing from our development plan and on the ground from our organic leasing effort.

Strong well performance continues to expand our view of where the Marcellus core boundaries extend. The map on the left of this slide depicts what we believe to be the Marcellus core at the time of our IPO [indiscernible]. As you can see, we built our position focused on Doddridge and Harrison Counties, which we believe will deliver the best drilling results. However, over the past decade as our development focus shifted into the neighboring counties and our well performance continued to strengthen. These results have driven an increased organic leasing program into those counties.

Antero's organic leasing efforts have been a tremendous success over the years. We continue to acquire acreage at attractive levels per location with the incremental locations more than offsetting our annual turn-in lines. Further, this program allows us to maintain our development focus in close proximity to our current footprint reducing geologic risk while leveraging the benefits of Antero Midstream. Now to touch on the current liquids and NGL fundamentals. I'm going to turn it over to our Senior Vice President of Liquids Marketing Transportation, Dave Cannelongo for his comments.

Thanks, Mike. Several market trends are pointing to improving NGL fundamentals and higher prices in the coming quarters, following several years of substantial year-over-year supply increases, multiple third-party data providers are forecasting a slowing of NGL production growth across the U.S. due to the current low oil price environment and sharp reduction in oil-directed rig counts. -- due drilling activity in oil basins will have an impact on associated rich gas and NGL production, particularly in the Permian Basin, which accounts for more than half of total U.S. seizures supply. As shown on Slide #6, titled, U.S. C3+ supply growth slows. The chart on the left shows projected NGL supply growth in the Permian slowing down dramatically in 2026 compared to previous years.

At the same time, the chart on the right shows total U.S. C3+ production growth in 2026 is nearly flat with only 11,000 barrels a day of incremental supply expected. This indicates that while the Permian should continue to rise, albeit at a slower rate. This increase is being offset by even slower growth or outright declines and less economic Tier 2 producing regions, including the Bakken, Rockies and Mid-Continent. The declining expectations for Sirius supply growth comes at a time when exports from the U.S. are now able to ramp up aided by a debottlenecking of terminal capacity. Year-to-date, propane exports have increased by over 120,000 barrels a day, averaging 1.85 million barrels a day compared to 1.72 million barrels a day for the same period last year.

This increase occurred despite current global trade uncertainty, illustrating the continued call on U.S. barrels. At the same time, LPG export terminal expansions have started to come online beginning this summer and ample export capacity will be available for the foreseeable future, as shown on Slide #7, titled New capacity to ramp up exports. Going forward, unconstrained dock capacity will allow U.S. barrels to efficiently clear the market and bring Mont Belvieu prices as close as possible to premium international LPG prices. In the past, Antero has often benefited during times of U.S. Gulf Coast terminal constraints with our ability to export barrels out of market book and capture iDock premiums.

The ability to execute this strategy has served as a differentiator for Antero versus almost all other NGL producers in the U.S. However, it is important to remember that Antero benefits more from higher Mont Belvieu prices than from high dock premiums. This is because higher Mont Belvieu prices lift both our export sales and all of our domestic sales. the latter of which are exclusively priced on a Mont Belvieu index. Antero on average exports less than 45% of its gross C3+ production and sells the remainder of the C3+ volumes in the domestic market. Therefore, an uplift in domestic sales prices is much more impactful for Antero's NGL realizations.

In conclusion, the key challenges of 2025 all trend in our favor moving forward as reduced producer activity combined with higher export capacity and international demand pool is expected to bring propane storage inventories from the top of the 5-year range to near the 5-year average by early 2026. These fundamentals will support Mont Belvieu prices in 2026 and strength in C3+ prices as a percentage of WTI. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing Justin followed and discuss the natural gas market.

Thanks, Dave. As we approach winter, we see seasonal and overall positive fundamental demand trends coming from natural gas. I'll start on Slide #8, titled TTP 500 basis shrink. LNG export demand is expected to increase by 4.5 Bcf a from the beginning of 2025 to exit 2025. This increase is almost entirely due to the successful and quick ramp-up of the Plaquemines LNG facility. This week, the facility achieved a new daily record for feed gas at approximately 3.9 Bcf per day. With the first 18 trains now complete, Venture Global will begin Plaquemine 2, which will increase the capacity by an incremental 2.4 Bcf per day with the first phase in 2026 followed by the second phase in 2027. The significant demand pull for this LNG facility has led to higher demand along our TGP [indiscernible] fund transport path and has driven a higher premium at that delivery point relative to Henry Hub.

Looking ahead to the winter, this premium to Henry Hub has increased to nearly $0.80 and -- and in 2026, the premium is now at $0.64 for the full calendar year, the highest level seen to date. As a reminder, approximately 25% of Antero's gross natural gas is sold at the TGP's 500 pricing hub. Our exposure to TTP 500 is expected to lead to higher natural gas realizations. Slide #9 takes a closer look at the significant natural gas demand surge that is coming over the next 24 months from the new LNG capacity additions. Over this short period, LNG demand is expected to increase by another 10 Bcf per day, driven by the start-up of Plaquin 2 Golden Pass, Corpus Christi III and CalcashiPass 2. These new LNG facilities are expected to continue to drive higher price premiums along the LNG fairway hubs where we sell 75% of our natural gas.

In addition to the substantial LNG demand growth, power demand is also expected to increase significantly over the next 5 years. The map on Slide #10 illustrates all of the competition for natural gas supply in our development region and down our firm transportation corridor. Based on announcements that have been made to date, regional demand is expected to increase by 8 Bcf per day. As Mike has discussed in the past, Antero has 1,000 gross dry gas locations that we could accelerate activity on if there is a regional call for higher supply. A long firm transportation fairway, there has been more than 3 Bcf of power demand projects announced to date. Additionally, there is an incremental 13 Bcf per day of expected demand between LNG facilities and power projects announced along the LNG Gulf Coast fairway. All of these projects will be competing for natural gas supply that could face supply challenges in that short time frame. Antero is uniquely positioned to participate in each of these 3 regions with our ability to increase dry gas activity for local demand or to use our firm transportation portfolio to access increasing demand all the way down to the LNG fairway. With that, I will turn it over to Brendan Kruger, CFO of Antero Resources.

Thanks, Justin. Our capital-efficient program that Mike highlighted resulted in attractive free cash flow of over $90 million during the quarter. Year-to-date, we have generated almost $600 million of free cash flow. Slide 11 highlights the uses of our 2025 free cash flow. Year-to-date, we have paid down debt by approximately $180 million, purchased $163 million of stock and invested $242 million in asset acquisitions. We believe this portfolio approach to uses of free cash flow will drive attractive shareholder value creation as we continue to compound this effort going forward. .

As we've proven historically, we will be disciplined in our transactions. The transactions we completed during the third quarter were accretive to the key metrics that we prioritize, including free cash flow and net asset value per share. Importantly, we were able to fund this activity entirely with our free cash flow in 2025 and therefore, do not have to issue equity at today's levels in our financing efforts. Now let's turn to Slide 12 to discuss our updated hedge program. During the quarter, we added natural gas swaps for the fourth quarter of 2025 and full year 2026 to 2027. We also restructured our wide natural gas collars for 2026 raising the floor price.

As Mike touched on during his comments, these hedges support our strategic initiatives. We have now hedged 24% of our expected natural gas volumes in 2026 with swaps at $3.82 per MMBtu and 28% with wide collars, between $3.22 and $5.83 per MMBtu. Our hedge book allows us to protect the downside by locking in a portion of our free cash flow yield. This is illustrated on Slide #13, titled reduced cash flow volatility. Power hedges have locked in base level free cash flow yields of 6% to 9% at natural gas prices between $2 and $3 while at the same time, we maintained significant exposure to rising natural gas prices.

Further, these headers result in a 2026 free cash flow breakeven at just $1.75 per Mcf, assuming year-to-date NGL prices. Looking forward, our return of capital and transaction strategy is anchored by our low absolute debt position that provides us with substantial flexibility to pivot between accretive transactions in our core Marcellus West Virginia footprint, debt reduction and share repurchases. We will continue to evaluate accretive opportunities to increase our net production in core inventory, while importantly, waiting to increase gross volumes until the broader natural gas market calls for it. While we continue to target maintenance capital we are well positioned with substantial dry gas inventory for future growth opportunities from the regional demand increases that are expected.

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

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

Gentlemen, I wanted to maybe start with the decision to commence D&C operations on the gas side and Harrison County. I was wanted to know if you could talk about what the catalyst was for that kind of decision, did data centers, power deals down the road, did that play into kind of the calculus about doing something you had done in 10 years or so?

Yes, Arun, that's exactly kind of the catalyst. We've been active in those discussions. And came clear to us all these discussions really related to kind of the eastern portion of our acreage position and where those opportunities would be located, also where the local demand is. And so we thought looking at our position, we have 100,000 acres. We have significant historical activity there. We have the midstream infrastructure. So we have a proof-of-concept pad. It's already a pad that exists with wells going south. So it is still North and it will be very low-cost wells and highly productive, and we're excited to get back at it at the -- in the Harrison County area.

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

Yes.tilBut we're still a maintenance capital around. This is just 1 pad. -- really, the fourth quarter production level were in the 3.5% to [indiscernible] range. That's the level we'll hold generally in '26. So we're still there. This is just more of a proof-of-concept pad -- on the drilling JV, that's still to be determined. We'll see where kind of the market is related to that, we could have -- we could continue that in '26, but we haven't made that decision yet.

Your next question comes from John Freeman with Raymond James.

Just a follow-up on a range question with the following the acquisitions and the higher production level now that you cited that you're going to have in 4Q. Just kind of how does that impact kind of the prior commentary about maintenance CapEx? I just think previously, you've kind of talked about kind of flattish CapEx to maintain production. Just wondering if this has an impact?

It is at the same ratio that the increase -- the production increased by 3%. So Falotico to expect a 3% increase in your maintenance capital. So that's like an incremental $20 million from that $675 million level.

Got it. And then looking at the acquisitions, the $260 million of acquisitions in the quarter, -- just trying to get a better feel for if this is not kind of a bigger focus of the company? Or was this sort of kind of one-off in nature and just you happen to have all these sort of transactions, Domino during the quarter? Just kind of how to think about that going forward.

Yes. I don't know if it's a bigger focus. I just think with our position in the West Virginia Marcellus. These type of transactions come to us and are available to us if it makes sense at the time. When you look at our acreage position contiguous nature of it, we are the liquids developer in West Virginia. And so we get opportunities from time to time. And so we evaluate them and these ones make sense. .

Your next question comes from David Deckelbaum with TD Cowen.

I guess as we get into 26, obviously, you guys just drilled a record lateral length, and we saw the impacts to the average lateral length in the quarter. I guess just given some of the land spend that you have this year, how do you see that progressing on average into '26 given that you guys have had some pretty significant efficiency gains ?

Yes. No, it actually goes up. It's a good -- I think it goes up to 14,000. I think we're generally around this year in the low 13,000. Next year is up a 1,000, you highlighted the very efficient nature of our leasing program. David, that's exactly what it's doing. He's trying to optimize those lateral lengths and also expand our position. So next year is up about 1,000 foot per well.

I guess -- I appreciate that color, Mike. My follow-up is just -- we saw obviously the acquisition this quarter. It looked like it was an increase in existing working interest, which I guess is -- I don't know if you would view that as aberrational or view this as a trend that likely continues perhaps into next year?

I don't know if we'll have those opportunities. It was [indiscernible] Separate transactions, all like with working at trust -- another one is royalty interest, another one with more acreage based. So hopefully, they continue into next year, but it's hard to forecast. But like I mentioned, we have such a dominant position in this area of the Marcellus. These types of transactions tend to be available to us if they -- if they make sense and if they're accretive.

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

The hedges you added this quarter were unlike past quarters and that you aggressively hedged the next quarter or fourth quarter in this instance. -- and you opt for swaps for next year instead of the wide collars before. Has your strategy on hedging changed? Or was this just opportunistic? And should we expect you to have a certain hedge level heading forward from here?

I think it's probably both. If we could replicate what we have next year where it's -- these are approximate numbers a quarter with wide collars, protecting at 3.25 with exposure up to 6 and a quarter in that high $3, $4 range and then 50% unhedged. That's actually a good model for us. I don't know if that will be available going forward. But that's a good level for us when we looked at. The program, as Brendan mentioned in his comments, the ability to lock in above 5% free cash flow yields. I think it's 6% to 9% in the $2 to $3 range, but then expose ourselves completely to the upside, up to a 20% free cash flow yield. That feels like a prudent way to manage the business.

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

Yes, Kevin, this is Dave Kilang. Really just a function of customers and when they're up and running and taking full volumes and then also or the spreads into the Gulf Coast on ATEX have been improving here in the back half of the year. So just taking advantage of our capacity on that system. .

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

On the dry gas acreage in Harrison County, there's been a lot of operational improvements and advancements in drilling and completion technology since you last drilled here. So I was wondering if you could talk to your expectations as to how much of an uplift you'd expect versus kind of the historical type curves from the wells that you had drilled here previously?

Yes, we expect about a 50% improvement in field wells in that area. It's more like 1.3 Bcf per day, but with today after 12 years, we've gotten a lot better at it, and I think we have approximately 1,500 wells now, and those are one of our first. So we're excited about optimizing the completion of those wells. And so was 1.3 Bcf per day expectation is 2 Bcf. I mean, 2 Bcf per 1,000 foot now. .

Okay. Great. And then I wanted to come back to something you referenced last quarter. But with your water systems, I was wondering if you could expand upon the data center cooling opportunity for Antero Resources in Antero Midstream. Just what would this look like? And how would you look to play a role?

Yes. I think just to build on what we said last quarter, we think we are well positioned and uniquely positioned having that upstream midstream integration being fifth largest gas producer in Appalachia. We've invested about $600 million or so in the water system -- so that provides Appalachia in West Virginia in particular with an advantage, I think, relative to other areas. The terrain is a bit more difficult in West Virginia, but we think the advantages of being close to fuel supply being close to water having the upstream bitstream integration, really do position Antero well.

So having a lot of discussions there, nothing to announce at this time, but continue to have quite a bit of discussions there. And then I think in terms of -- as we look at just the regional demand overall, I think we view this as -- it could take a few different forms. You've got either behind-the-meter power for data centers. There's been quite a few announcements just on natural gas-fired power generation, both in West Virginia and the region at large. And then I think just local prices tightening to the extent you have regional demand and local price is tightening as Mike had mentioned, we've got that significant dry gas inventory to take advantage of all those various opportunities.

The other thing I would just note is, we are intentionally being a bit patient on this as well. I mean I think -- as you look at our LNG portfolio, for example, we had many opportunities on Plaquemine, for example, to do long-term deals at certain prices with Plaquemine that were much lower than what we're seeing basis trade at as that LNG facility is ramped up. So we do think patients is a bit of a key here. And as you as you let this play out and the scarcity of supply continues to build. We think the ability to do margin-enhancing deals will become greater for Antara. So having a lot of discussions, but also taking a patient approach and we want to do the right thing versus just coming out with announcement just for the sake of coming out with an announcement.

Your next question comes from Doug Leggate with Wolfe Research.

For having me on Mike, I wonder if I could pick up on this topic of not ceding market share, if you like, in the basin. What's your decision point for growth? And I guess I kind of frame the question like, what are the conditions you need to see? Do you need to see basis improve? Or is it just about local demand increasing before you decide to step into dry gas growth in your backyard? .

Yes, interesting question. We've been talking about that. Obviously, this is a proof of concept. So we'll see the results on this, but we're highly encouraged currently. So you mentioned seeding the base. And we are the dominant producer in West Virginia. I think we produced over 40% of the state's natural guests. We have the dominant acreage position. We have the midstream. We have the acreage HPP. We have investment-grade balance sheet, I mean, everything you'd want for developing it. So why shouldn't we develop it.

So it's proof of concept, we'll prove out the resource. And then when you look local demand, absolutely, would encourage us to grow into that. Also, if you kind of look out the curve, if [indiscernible] natural gas and you could hedge basis in the future years, that may be something we would entertain as well. So a lot of kind of different decision points there. But like I said, we're uniquely positioned for this and we're very encouraged and we look forward to this pad.

I appreciate that. And of course, given the depth of the inventory you have, you've got a lot of optionality, but it does raise the question and you got to forgive me for this one, about the rest of your portfolio and the potential for asset sales and going with this in Ohio. Can you offer any color, compromatory or otherwise as to where you are in that process?

Yes. We're just in the middle of that process, Doug. We're highly encouraged there as well. as you can imagine, I mean, that's a highly desirable or coveted asset with the contiguous agrees position, all the midstreams in place, the ability to access the firm transport to price it outside of the basin, the liquids portion, the dry gas portion, it's kind of a ready-made asset or company. So also all the data centers over in Ohio as well and all the power demand over there. So it's highly coveted. So that's kind of why we wanted to do a market check. We're just in the middle of it, but we are encouraged. .

Your next question comes from Betty Jiang with Barclays.

I want to go back to the data center proof of concept -- it seems to me that you don't need to prove to the market that you can grow dry gas and grow it very cost effectively. And so this proof of concept is really for the customers and people you're speaking to on the other hand. So my question is that these customers and entities, what are they looking to derisk with your proof-of-concept pad -- is it the speed at which you can deliver volume? Is it the capacity of resources that you can deliver to? And was that pad is online? Could that catalyze the conversation that you're having on the power and data center side?

I think the proof of concept is twofold for us, and then I'll let Brendan talked about his discussions with the counterparties. But for us, it's one, let's the EURs, what's the deliverability just so we know we haven't drilled a well over here in 12 years. So is it the 2 Bcf? Is it higher than that? Is it lower? So we'll see on how to optimize that development. But also in the midstream, a lot of midstream capacity over there showing that we can flow it into these local kind of sites where these data centers are potentially being located just the ease of our ability to deliver gas straight to the actual facility. .

I'll let Brendan talk about other customers.

Yes. I think just to add on Doota, I think from the standpoint, we haven't drilled a well over here in 10 years. It just shows we've got the inventory over here. It will give them good perspective on the ability to quickly ramp up. And I think having the ability to have that residue gas, not only at the processing facilities and in the eastern -- or I'm sorry, in the western part of our play, but also on the eastern part of the play, where you're seeing some announcements out there on gas-fired generation.

It provides us more flexibility in discussions as I mentioned, we're having multiple discussions and the ability to have flexibility around these discussions and what could be best for Antero as it relates to kind of margin enhancement. This just gives us more flexibility in different parts of the play producing in larger ways.

Got it. That's helpful. My follow-up is on the land budget. You have increased it for 2025. But I'm wondering if the land budget would just be higher for longer, given that you have expanded the scope the boundaries of what you define as core. And can you just speak to the attractiveness of the organic leasing initiative versus potentially what you see in the private space in that area?

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

This year, we've just seen a lot of opportunities because our wells continue to strengthen in East these areas that we're developing, and there's more acreage in those areas than they have been kind of in the middle of the field. So our opportunity set continues to grow as our wells and our continue to support that. So right now, I'd probably go into next year, and I think most people's models have about $100 million. But if we continue to see opportunities throughout next year, that could be higher kind of in the back half of '26 if this level of activity continues.

Your next question comes from Jacob Roberts with TPH.

Good morning. I want to wanted to ask about cash taxes. I think on the last update, you gave the market, it was a 2028 time frame those commodity prices. Just wondering if that math has changed at all given where we sit today?

No, no change there. No material cash taxes through 2027 to 2028 would be that first year we'd expect to pay some. .

Okay. Perfect. And then circling back to the dry gas activity, this 6-well pad or the activity going on currently to get to that 50% uplift relative to a decade ago, should we be expecting some iterative completion design? Or is this ready to go into manufacturing mode ?

Ready to go. I mean, like I mentioned, I think we've -- since that time, drilled over 1,000 wells. So it was primitive back in 2013 when you look at it. So would just be doing our typical 36 barrels of water per foot, 200 feet stages and spacing on it is like a 30-foot spacing. So lateral between the laterals. So it's just our typical design in the liquids, but just applying it to the dry gas for the first time in 12 years. .

Your next question comes from NitKumar with Mizuho Securities. .

I want to start on the hedging. You addressed earlier, it's a little bit more prudent sort of financial management, and I agree. As you've kind of put a floor on your free cash flow yield, what are your thoughts on the cash return profile? You've kind of not that a dividend, like some of your peers as you're stabilizing your cash flow. Is that part of the discussion going forward?

I don't think it's evident, but I think we can be very countercyclical in share repurchases with walking that in, also evaluating transactions even in a low commodity price environment. We always want to be countercyclical, and we have really no debt very low debt, no maturities for years and years. So we want to be countercyclical, but if you don't have the hedges in place when the countercyclicality happens and low commodity prices, the free cash flow is not there as well.

So we wanted to lock in a baseline of free cash flow and then be able to use it for share repurchases or transactions is what we're thinking.

Great. Great. I appreciate that. And then the topic of M&A has been covered quite a bit, but you confirmed earlier that you're marketing the Ohio assets. Just curious, as you mentioned, you don't have a lot of near-term debt or a big balance sheet. -- what do you think will be the use of proceeds if you were successful in getting the price you want?

Yes. No, it's a good question, and that's why it's a high bar for us because the most likely case, I would still say it's the whole case, but we'll see where that -- the marketing goes, but the use of proceeds right now is, like you mentioned, a square at $1.3 billion of debt. We have $300 million on our credit facility, and we have, I think, $400 million on the $29 million that's kind of callable par. So we really only have $700 million of prepayable debt at the $600 million is a 2030 maturity.

I think 53.8.So that's a good piece of paper. So that -- but then you also look at where our equity trades and the type of valuations that you're going to see for the Utica as well in excess of where our equity trades. So that could be a use of proceeds as well as we wouldn't be bad trade if you sell your Utica for well in excess of where your equity trades to use that to buy in the shares.

Your next question comes from Leo Mariani with Roth MKM.

I just wanted to follow up a bit more on this concept of growing net volumes without growing sort of gross in the near term. Obviously, you talked about M&A. It sounds like you're undecided on the drilling partnership here. But just in terms of the M&A strategy other than undeveloped acreage are there opportunities to continue to pick up minerals, working interest? Are you generally trying to do this kind of ahead of the drill bit over the next kind of 12 to 24 months. I mean you said that these 3 deals kind of came up recently, are you seeing just kind of more deals in the basin? Just want to get a little bit more color around some specifics on kind of the M&A strategy here and kind of growing the net without growing the gross.

Yes, I think you hit on it. These are all small bolt-on transactions increasing interest. When we talk about gross versus net, all of our processing is full. I think we're at 106% of processing capacity all the FTEs fall. So on the liquid side, it's a challenge to grow growth because all the facilities are full. So in order to grow that net, you have to look to the working interest and the royalty and all of these are highly free cash flow accretive. So that's where it heads that. So as they come up, we assess them and see if it makes sense. based on that. And then like we've been talking about a lot on this call, the ability to grow the dry gas is really and then on regional demand on a local basis. And so that is an opportunity for growth there. But really just trying to grow the net and maintain the gross volumes. .

Okay. That's helpful. And then you obviously highlighted a number of kind of operational records on the quarter. with some very strong improvements in terms of frac stages and cycle times and everything, can you just give us any thoughts on whether or not you think there's a decent amount, kind of more improvement to come here? Or do you think you're starting to kind of maybe bump up on some of the limits, I guess, 15 days in a row without stopping on the frac side? It seems like it may be hard to do a lot better than that.

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

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

Maybe to start, I'd like you to talk to Slide #5, when that illustrates the expansion of what you consider to be core in the Marcellus -- so activity in the East in areas like Waste and Tyler, that's been for bots for quite a while, and it's easy to see how that is now core. But activity to the South and the East has been a little bit less frequent. What gives you confidence that the core is expanding to those areas?

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

Got it. Mike, I appreciate that. For the second question, I look at Slide #10 here. So gas demand has expanded across that pipeline fair way. So 2 questions. pipes in that direction are quite full. Do you guys have visibility on maybe new FT opportunities to push more gas into that region? And then it feels like given the demand pull, there's increased competition in the Gulf to lock piece volumes down. Do you see any direct-to-consumer opportunities along this route that you could participate in?

Yes. I think Justin, correct me like 2.1 Bcf a day going down into the Gulf and we've intentionally been floating like Brendan's comments suggested we've carried this for quite some time. We're going to see where the actual basis goes. And when you look at these types of opportunities and demand growth, 25 Bcf a day, 17 of it being in the Gulf Coast or along that path. We think there will be a lot of opportunities, but I can let Jeff and on that.

This is Justin Power. So the way we think about this, Mike and Brennan's previous comments, The local demand, if all these projects go forward, it's going to be there. So that's going to drain gas out of various local pipes, various local pools and then to Mike's point, when you think about the Antero 2.1 or so BCF itself, there was approximately 10 Bcf reversed over the years since the shale revolution took off. So right there, we're about 20% of that volume heading cells. And then when you really zoom in on some of our pipelines, which we're calling mid-path Antero owns rights pass those potential projects as well. So we are evaluating different projects in Kentucky, Tennessee, Mississippi, where we cross. And then to your point on just the LNG market, yes, the LNG groups are going to have to potentially start to lock in supply just as there will be scarcity across the summer season, winter season, et cetera, that could cause peak situation.

So we have been talking to a lot of those groups as well. But to Brendan's point, patients is key at the moment and there's a lot still to be developed. If I understood your first part of your question correctly, in terms of new capacity being added self-bond, it's just such high cost. and any of those projects are going to be toward the end of the decade. So Antero is in a good situation here to continue to watch the basis locally and just that behavior locally. And then also just working with these various groups in the mid-path delivery points of those projects move forward.

And the only thing I would add just on the point about end users, there has seemed to be a bit of a shift in terms of the demand pull side of things when the basin took off. It was more of a producer push there has been a lot more significant interest from a demand pull perspective and folks wanting to get the actual supply due to some of that scarcity of supply that I think is starting to take hold in the market. .

Your next question comes from Neil Mehta with Goldman Sachs. .

Yes. And my congratulations on stepping into the CEO role. I just love your perspective early on, it's been a couple of months now of just observations as you step into this new role. And the business has done very well over the last couple of years, particularly coming out of COVID. But what do you think the next frontiers are from a strategy perspective as you look to the next end of this decade?

Yes, I think you saw that in the strategic initiatives. -- we have such a terrific asset and West Rock, some of the best rock in North America, definitely the best rock for liquids development in midstream access, midstream capacity, balance sheet, investment grade so it kind of ticks all the boxes and now the strategic initiatives going forward are just trying to enhance that, doing bolt-on acquisitions in West Virginia, trying to enhance our exposure there, some dry gas development we talked about that's a good opportunity for us and then using hedging as a tool that's 1 thing that, like I mentioned, we want to be countercyclical. The only way to do that is to have some sort of certainty of cash flow there in low commodity price times. So -- that's kind of the next frontier that we're looking at, but we're excited about it. And I can mention, we are at the dominant position in West Virginia, so we should expand upon that. .

Very clear, Mike. And then just wanted to go to the macro on NGLs. And as we walk to your pricing sheet, it's a tougher environment right now. I guess not so bad when you look at it as a percentage of TTI, but on an absolute basis, it's pretty challenging. So just talk about the path for recovery in 2016. Do you think that recovery is going to be more supply driven or demand driven on the supply side. I saw you put out some interesting numbers in terms of volume growth, it's probably below where I think consensus is for volume growth in the Permian for NGLs next year. So is that not a consensus view that you guys have that we can offset sort of the prevailing view that even if black oil flat that NGLs will still be growing significantly.

Yes, Neal, this is Dave Kenalog. I'll take that one. So I guess to your first question, I'm looking forward to 2026, certainly, oil prices do play a key role in what happens with NGL pricing as you alluded to as a percentage of WTI, it's been improving here in 2025 despite some of the market headwinds that were out there. So we kind of look back at 2024. -- through the first 9 months of the year, a little less than 54% WTI, 60% WTI here in 2025. So that really kind of speaks to the value for NGLs is still there, driven by rescom, in elasticity and pet-chem demand.

Looking forward to 26, obviously, we're very optimistic about the trade uncertainties getting resolved here. Obviously, some announcements here this morning that we think will certainly saw some of that. If you look back to what was being exported in particular to China prior to the tariff announcements in early April is around 600,000 barrels a day or 1/3 of U.S. LPG exports headed that direction of propane exports -- and in June, it was a little less than 100,000 barrels a day and since we do about 300. So certainly, some following there, but we'd like to see that continue to improve. That will help with efficiencies on freight pricing, which will also drive Mont Belview higher. So those are kind of the key things we're looking to. I don't know how long the world can sustain at something per barrel WTI as well. So we're -- you expect at some point, that's going to resolve itself and also become a tailwind for NGL prices on an absolute basis.

Coming back to the supply picture and your questions on that, that view is a third-party view that we put in our presentation. I think that there's a lot of different groups that are out there. There's been some consolidation in the third-party analytical groups. So there aren't as many people out there providing views. It seems to be a belief around gas oil ratios increasing, and that really seems to be what's behind some of the higher NGL supply growth views. But undoubtedly, I don't think anybody is disputing in this oil price environment and lower rig count environment. The NGL supply growth is going to be as strong as it was if you're looking at the chart in the prior years.

And your next question comes from Paul Diamond with Citi.

Just wanted to touch quickly on kind of capital allocation, given current conditions. With your hedge book, you guys put out a pretty decent for under free cash flow next year. and have used kind of evenly between stock repurchases, debt repayment and acquisitions. I guess in a -- in kind of a bull scenario, how much cash would you be willing to build if you want to really maintain kind of cyclicality assuming that you have limited debt to really buy back now? And if your stock starts to run, what level of cash is comfortable.

Yes, that will be a good problem to have. But I think I mentioned earlier, we have $700 million of debt that we can pay down. Of course, we'd be buying shares all along that way as well. So in a real bull case scenario where you get into a couple of billion of free cash flow a year, you would start to build some cash, but I think you'd be unless you didn't really have any other transaction opportunities. I think you kind of be where we're at right now, where it's kind of like a 1/3 repay of debt or equity purchases and 1/3 in transactions.

Got it. And just kind of switching to the other side of that coin. Some of your peers have really started to do production management, whether the curtailments or choking or anything along those lines. Given your FT, I know it's less of an opportunity for you, but just wanted to see if you saw how Antero would play in that on the margins. Is that something you have worked into or...

Well, when we do it, we just don't talk about it. It's already built into kind of our guidance, and it's really kind of -- they may say it's curtailment practices, but I think it's really economics based and the gas prices are low in the basin. So it would make economic sense to flow to that. When that all that occurs, which is rare, like you mentioned with the SP and the liquids, we don't really have that much local basis exposure but we do have it from time to time, but we are always fill that in the risking of our guidance. .

Thank you. And ladies and gentlemen, there are no further questions at this time. So I'll turn the floor back to Dan Katzenberg for closing remarks. .

Thank you, and thanks, everyone, for joining the call today. Please feel free to reach out with any questions that you have. Have a good day. .

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