Antero Resources Corporation (AR) Q2 2026 Earnings Report, Transcript and Summary

Greetings, and welcome to the Antero Resources Corporation Second Quarter 26 Earnings Call. At this time, participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce Daniel Philip Katzenberg, Vice President of Investor Relations.

Thank you, you may begin. Thank you for joining us for Antero's second quarter 26 investor conference call. We will spend a few minutes going through the financial and operating highlights, and then we will open it up for Q&A. I would also like to direct you to the homepage of our website at 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 N. Kennedy, CEO and President Brendan E. Krueger, CFO 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, Daniel, and good morning, everyone. I will 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 These 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 lower cost to come 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% 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 direct 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. NGLs. Next, on Slide number 5, we provide details on our margin enhancement. $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 basin. 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 into 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. 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, and resulting in an increase of $60 million of annualized cash flow beginning in third quarter of 26. The VPP will expire in July of 2027 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 28. And third, the remaining $105 million of margin improvements through 2028 will primarily come through optimizing our natural gas firm transportation portfolio increasing dry gas 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 that 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 liquids 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 am going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, David Cannelongo for his comments.

Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing achieved during the second quarter of this year. Antero's realized C3 plus price was $44.26 per barrel, up $6.41 per barrel compared to the second quarter of last year 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 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 number 6, U.S. propane exports averaged 2.03 million barrels per day during the second quarter of 26. Increase of 170 thousand barrels per day compared to the same period last year. Additionally, propane exports hit a new weekly high of 2.63 million barrels per day this May, with another weekly export number also above 2.6 million barrels per day reached in July. According to the EIA. These new highs surpassed the previous record by 300 thousand barrels per 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 thousand barrels per day in April, the most recent month of EIA data. Surpassing the previous record of 661 thousand barrels per 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 lost Middle East supply across demand markets worldwide. Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels per day of 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. 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 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 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 Day Additionally, we are beginning to see a recovery in Chinese petrochemical demand for LPG. As shown on Slide number 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 number 8 to discuss shipping dynamics. VLGC freight rates have been elevated since Epic Fury, due to the global reshuffling of ships after the closure of the Strait of Hormuz. Creating some headwinds for U.S. LPG exports. However, 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 26 and all of 2027. From now through 2029, the size of the fleet will increase by 31% or 138 ships. Given the imminent export expansions and new build terminals coming online, greater ship 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 Antero is poised to benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing. With that, I will now turn it over to our Senior Vice President of Gas Marketing, Justin Fowler, for his comments.

Thanks, David. I will 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 demand growth by 2030. In combination, this represents 37% of total demand growth for natural gas by the end of the 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 number 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 have spoken to that add an additional incremental 3 Bcf demand to our regional profile. We have 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 number 11 titled Gas Demand Competition. As Mike detailed earlier, Antero is in an advantaged position through our long haul firm transportation capacity. This firm transport 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 E. 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 25, 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 equivalent per day and add 15 net drilling locations. I will discuss both of these updates in more detail momentarily. Turning to our financial results. On the right hand side of the slide, Our adjusted EBITDA 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 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 drilled on our dry gas acreage over 12 years ago. To 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 thousand to over 2 Bcf per 1 thousand. 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 thousand 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 Western Virginia Marcellus footprint. These transactions immediately add 125 million per day of net production and were acquired at a combined valuation of just 4x EBITDA and a free cash flow yield over 20%. The chart on the right illustrates how we have been able to increase our net production has increased from 3.3 Bcfe per day at the beginning of 25 to an expected 2026 exit rate of 4.5 Bcfe per day. Or 36% growth over that time period. Notably, we have been able to accomplish this net production growth without impacting the basins gross production. Which you can see has remained essentially flat at 35.5 Bcf per day over that time period. To emphasize a point that we have made in recent discussions, Antero is in its best position in company history. Through accretive transactions and organic growth, our production has increased by a third. We have already achieved nearly half of our targeted 25% reduction in operating costs and the NGL outlook significantly strengthened relative to the beginning of 2026. Further, our share count is down 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.

Thank you. And at this time, we will conduct our question-and-answer session. And our first question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question.

Hey, good morning and thanks for taking my question. there is 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 market gas marketing portfolio in total what would make you get more aggressive with long term sales agreements?

Yes. I think we touched on in our 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 are at the end of that and so we can select the best pass and those paths are competing with the power deals and comparing them. So it has to compete with the broader energy markets. The 1 that was recently in our backyard, I mean, we have been in discussions with them for almost a decade. So we are well aware of that 1. They actually, you know, have a contract on some of our midstream. So in discussions with them, you know, just the uncertainty around the price the timing, the execution, all of that, really did not meet our return hurdles. So when we look at projects, it has to meet all of those 3, and that 1 just was not attractive to us.

Okay. 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 the coming years. With the stock in the 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 were not planning on buying back shares in the quarter, but the equity price went, obviously, that was 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% and you look at the share price and it is the same as last year. So I would say that you could elevate the ranking of that and that it is very attractive. to us at these levels. Appreciate it. Thanks.

Your next question comes from David Daoud with Truist. Please state your question.

it is 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 are at 4 rigs currently, maybe putting some of that growth capital to work. Could we maybe just get an update there?

Yeah. So it is 4. 1's 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, but are on the-- kind of on the difference between maintenance and growth capital. So you also have some capital. So our maintenance case just to remind everyone was $1 billion. Our growth is $1.2 billion of capital this year. Right now, we are 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 is yet to be determined whether we deploy that. We have said in the past, $3+ gas that is probably something that we would deploy but we will just have to determine that when we get there. Okay. And so if you complete those wells, then that takes 2027, I imagine, for-- Yeah. Yeah. Yeah. Okay. Okay. Thanks, Mike. And then maybe just a follow-up. Curious on the cost optimization plan, the $0.35 reduction in realizations 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 as we progress through 2027 and maybe in basin, pricing not really materializing to what you would expect. Would you just still keep some of that FTE, or is that or is that just simply just recontracting into lower market rates? Yes. So some of that is 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 is definitely you know, coming from the end users it is a demand pull. And so when we came out with this cost presentation, and strategy a couple months back, we received so many reverse inquiries along our firm transport paths in Justin hit on that slide too, all of that 7 Bcf of demand that is along those FT paths. 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 is baked into this 300 million that we have been talking about, that would be incremental. But that is something we are looking at. You kind of saw the first sign of that with our guidance, how we reduced our cash costs also reduced the realized price, but we are hopeful that we will actually do better than that. Just getting premiums along that path instead of just having the end user hold that transport. Got it. Got it. Okay. That makes sense. Thanks, guys.

Your next question comes from John Freeman with Raymond James. Please state your question.

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

Absolutely. We just focus on 3 years. We thought that was kind of the investment horizon. If you are looking past that, for the 5 years, I think it drove growth of about 6 to $700 million that is great.

And then just follow-up, Mike, as you sort of see this play out with data center, 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-thirds 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 are kind of thinking a third with FT long-haul, a third is liquids and a third is generally local sales. So if you just put that in natural gas terms, it is about 50-50. The word we like to use you are going to hear a lot of you hear the balance. We want to be balanced. We want to be a balanced natural gas liquids producer. We also want to be a balanced cell of the natural gas, about half on the long haul transport and half local. that is great. Appreciate it. Mhmm.

Your next question comes from Arun Jayaram with JPMorgan. Please state your question.

Yes. Good morning, team. 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 are halfway or nearly halfway there. The integration of HD, but give us a sense of how that will play out over the next couple of years. And, I am 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 2028 target?

Yes. We put in the 3 buckets. We put some timing around that. That first 1 we talked about the override. That starts immediately. That started in July. that is a $0.04 uplift. $0.04 improvement on the cost structure at $60 million And we have the VPP in July 2027. that is an incremental $30 million Throughout that time, you are going to see this optimization of our natural gas firm transport. it is harder to predict the exact timing of that, but we are in significant negotiations around those type of improvements. So that is more ratable. Then the $105 million of total liquids at year-end 2028. Got it. Got it. Great.

And my follow-up, Mike, clearly 1 of the themes from today's earnings is your commentary that the business for large scale natural gas liquids producers will be more driven by demand-pull versus just being a traditional E and P price taker wondering if you could comment on how you think Antero's positioned for this, call it, shift in market dynamics?

Yes. We are extremely well positioned. Go back 15 years and we were trying to create markets. There was no local gas markets. So we 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 did not end up as well as we had hoped. So we will be able to compare those now to the local demand So it is perfect timing for us. that is why in the comments, those opportunities are going to have to compete with the broader energy markets because those LNG buyers are really in the kind of international. there is an arb there, in our strategy has been to remain on the spot there. So we have not entered into firm agreements with that price. Then local is going to have to compete with that. that is why we are highly selective. You are going to see a bunch of announcements that along the way we are not participating and then you can be assured that is because our opportunity set is greater than what those opportunities were. So highly selective, it is got to be more near term, it is got to be price certain and it is got to compete with firm transport and liquids production. that is clear. Thanks a lot, Mike.

Your next question comes from Doug Leggate with Wolfe Research. Please state your question.

Thanks guys. I appreciate you having me on. So Brendan, this is maybe for you, but in your deck, you are walking through pretty clearly the reduction or the planned reduction in cash cost, and then it is been beaten pretty well this morning. But My question is, why are you, hold on 1 second. Why are you offsetting that with price realizations? I am trying to understand what this implies for your market view of gas going forward.

Yes. Sorry, I did not hear that last part. Doug, could you repeat that? Yeah. Sorry. Someone's dialing in my system. Why are you offsetting it with price realizations? I am 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 are willing to take your product in basin You will, of course, have a lower realized price that they are buying in basin. But from a margin standpoint, you are picking up $0.35 a margin. So they are taking on the transport to move it, but they are giving you a premium on the price versus what you otherwise would have sold if you were just selling in basin. So cost 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 are quite enthused by what we are seeing on the demand-pull, like Mike mentioned. This market where it used to be we have to find a place for your gas, it is 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? 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 you can take on that cost. But all of these factor into our decisions, but they are all should lead to margin improvement on our natural gas in a big, big way. I appreciate that color. Thanks.

My follow-up is a quick 1 hopefully. Obviously you have drilled your first dry gas pad in quite a while. You have not completed them, obviously, but whether we end up with a squishy winter or not, what is the kind of road map to whether you would go back to growth in 2027?

Go back-- we have 2 pads in there. Kate-- well, our first 1, the Flanagan pads that Brendan reviewed the results. The next 2 are Katy and Walters right next to it. They will be drilling whether we complete them like you mentioned. Will be natural gas price dependent But I fully anticipate completing them if it is $3 gas plus. And we can hedge that and also hedge local basis at very attractive levels. So right now, based on those markets that we are looking at, you would assume that those would be completed. But if you have a significant down or price movement on the 2027 gas, then we will not complete them in the fourth quarter. that is really helpful. Thanks a lot. Mhmm.

Your next question comes from Betty Jiang with Barclays. Please state your question.

Good morning. I want to start with a follow-up to Arun's question about costs. This GP and T piece is there are many drivers lowering that GP and T over time. Could you just unpack like how much of the reduction is coming from a shift towards the HG dry gas assets like whether that is 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, it is 50% of it-- it is over $50 million this year, I should say, is HG has outperformed our expectations definitely 2 of the 3 rigs that we have running right now the 4 is in transit, but 2 of the 3 are on HT pads. 1 of them those are liquids, 1 of them is a dry gas. So incrementally HG is outperforming and will have more production than we assumed. So there is a little bit of that. But it is 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 the shift, like we said, to the demand pull and shift to just some dry gas development also with those transactions expiring? Yeah.

If you look at that too, if you look at that $300 million that we have laid out there too, Betty, I think about 250 million of that. So all of the liquid the VPP, the override, and then about half of the gas is all just driven by pure optimization. The 50 million Mike mentioned of that 300 million is really driven by that shift to more dry gas and 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 and T? Well, I think on the GP and T front, so you are like we have said that the $300 million just to break it down, so we have got $0.35 of margin improvement, $300 million is about $0.20. The other $0.15 comes from HG. $0.35 of margin improvement, $0.20 is in 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 are down $0.70 on cost. Almost all of that $0.70 reduction is going to come in the form of GP and T coming down I mean, that is the driver of that. Processing costs will be lower Transport costs will be lower. Gathering will stay the same to AM on that front, but everything else will be lower. Got it. Thank you. And if I could sneak in 1 quick 1. In your scenario, how much do you, does your in-basin exposure grow over the next few years? From the 20% currently? Yes. Mike talked about it. So you will likely go from what today is 2-thirds call it 2-thirds, 1-third in terms of 2-thirds going to the LNG fairway, a third going elsewhere. You will have that be more 50-50 on a go forward basis. Thank you. That will take some time to play out though. That will be over. Call it, a 5 year period for that to play out. Got it. Thanks.

Your next question comes from Phillip Jungwirth with BMO. Please state your question.

Yes, thanks. Good morning. I know Antero Midstream has a separate call, but I was hoping you could talk about the Eastside Express pipeline, which is the first intrastate regional line. Just how does this benefit Antero and just confidence in executing a project like this. And then just separately, just what is the interest and difficulties in building an intrastate pipeline? Just thinking like shorter distances, like West Virginia to Ohio, for instance, where there should be strong demand pull in the future. Yes.

No, we are 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 thousand 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, and it will extend all the way across it. Antero Midstream is the industrial builder of Northern West Virginia. It now has the balance sheet, the credit, the strength, the expertise to build there over a decade. Maybe a decade ago, farmed this out Everyone's kind of familiar with that Stonewall Pipeline. that is when we farmed that project out because we just did not have the ability to execute on that. that is no longer the case. We are the builder of these regional pipelines now in West Virginia. And Antero Resources acreage position and strength investment grade goes with that over 1 million acres, 1 thousand of these dry gas locations. This will go straight across it, and we hope to build more of those. At Antero Midstream and for Antero Resources to benefit off that building, maybe the next 1 is probably North South We have 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 is been publicized. And Antero Midstream will be the pipeline to build it. 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 gas or C3 plus We have seen peers increase their focus on the marketing side of late, 1 with a large acquisition. Just as you look at what they are 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?

Yes. We think we already have that. I mean we have been 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. Think we have 28 pads that we market along. And also with our liquids too, David and his team has been a leader in that. First 1, signing up on ME 2, pretty much signed up on every single project From an LPG or ethane standpoint, I have been marketing around that. Really a market maker over on the Atlantic Basin side of the liquids marketing. 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. Sounds good. Thanks. Mhmm.

Your next question comes from Jacob Roberts with Goldman Sachs. Please state your question.

Good morning, team, and thanks for taking my question. I just wanted to ask on hedging, specifically in 2027. Just curious how your team is approaching the right hedge levels for next year and if there is anything you are seeing in the macro set up for 2027 that would change your hedging approach year over year based off the 60% levels we saw in 2026?

No, we are in a good position. We are actually ahead of where we were this time last year for 2027. We have got 34% hedged. I think it is a Bcf at 3.84% and then maybe $100 million a day of collars with a $3.50 by $4.50. We said before, we like the 25% swaps and 25% collars but that is if the collars, if those are attractive levels with a lot of call skew, we have been favoring more of the swaps of late. I think you will see us continue to increase that We are in great position, so we are not going to be rushing into down markets. But if you see upticks in the gas price in 2027, you may see us add a little bit When we do acquisitions like this recent 1, we do hedge it, so you saw an increase in our volumes They are hedged volumes by, I believe, around $100 million today and 26 million and 80 million in 2027. So when we do acquisitions, will hedge them just like we did this 1, these couple of acquisitions we did in July. I appreciate that.

And then my follow-up maybe on the $315 million in the Western 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 any impact on, you know, the number of opportunities you are seeing in the market?

Yes, does. We have a lot of non-op working interest entities out in our basin. I mean, you have 1 million acres, you have a large opportunity set, a lot of non-op working interest. We are in discussions with them, and they all tend to have acreage around their non-op position too that they are 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 get the acreage as well. Our goal 1 of our strategies is obviously to increase our production it is really the interest of production that is from the growth standpoint already on our acreage. So gross being flat, but Antero owning more and more of that the interest in that production. And then obviously consolidating the acreage around the Eastside Express, that is where this acreage was. 15 locations, couple pads, right on that Eastside Express. So that was very attractive to us. We continue to see these type of opportunities, and we will continue to look at them. Generally, you know, it is kind of been 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 will develop the pads and take advantage of those type of valuations. Thanks, guys. Mhmm.

Your next question comes from Leo Mariani with ROTH Capital. Please state your question.

Hi, guys. 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 how much of the synergies you have captured thus far in 2026. And do you think that could be more upside to that number over time?

Will be more upside. it is still at that $80 million level. But that is not capturing what I mentioned earlier in my remarks. We actually have 2 rigs of our 3 on the HG acreage. that is well ahead of schedule. We were contemplating when we underwrote the transaction, just 1 rig. So that is going to accelerate the volumes on the HG, which is going to accelerate the transaction value to us. But there is a lot of pad ready there. They have already got all the infrastructure. Being able to put those pads on right into the local gas markets in the winter. We think there will be elevated pricing. that is all entered into the decision. And obviously, the well results are terrific. We are going to put on the second set of wells from the 1.22 thousand pad on 17. Those continue to outperform the 1.2 thousand North. So we will continue to update that number. But just for 2026, the $80 million is pretty much locked in. But that will go higher in 2027 as we put these new pads on.

Okay. Appreciate that. And in terms of the gas price environment, clearly, it is relatively weak right now. And I guess, we are 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 thoughts on just trying to manage production a bit, to kind of match price here?

Yeah. I am glad you brought that up. that is actually the curtailments that we outlined. that is a new feature for Antero. We talked about 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 on the liquids. So we now have flexibility to look at our lean pads in that 61, 71 Btu and we do not have to produce them where in years past we would have because there would have been MVCs with them. We now have ultimate flexibility, so that is a new feature that we are excited about. The ability just forecast, hey. look, September could be weak. We mentioned it is under $2, to shut in or have curtailments on those wells and bring them on more into November, December timeframe when the prices are higher. We very much have that flexibility now and that is something positive for us. So we are excited about that. Okay. And that is kind of basically baked into the guidance you have laid out here. We are hopeful that we continue to add abilities to take advantage of those opportunities. Okay. Thank you.

Your next question comes from John Abbott with Texas Capital. Please state your question.

Hey, good morning all. Thanks for taking my questions. For my first 1, 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 have learned to future pads?

Yeah. No. it is a terrific result for us. So this 2,000 pounds of sand and 38 acre spacing is what we traditionally done in the liquids. that is what we have done kind of our go to for the last 10 years in the liquids. So we can play with that spacing. I know on the HG dry gas pads, we are going 1.06 thousand interlaterals and going up to 2.5 thousand to 3.5 thousand pounds of sand. The water going in between 35 barrels per foot and 50 barrels per foot. So a lot of optimization to occur. But to have a 2,000-pound, 38 interlateral spacing and have it be over 2 Bcf per thousand was a terrific result for us. The lateral length just adds to the economics, brings that dollar per foot on the CapEx at $1.35 thousand. I mean, you are increasing proppant by 2.5 times. And your well cost is down 30% that is a lot of that is lateral length as well. So drilling times and completion times So feel really good about that.

We have 1 thousand 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 thousand feet, how do the economics compare with your current average lateral? And excluding lease geometry, are there any limits to extend laterals beyond that?

No. We just drilled that. We have not put that on yet. that is actually on an HG pad. On our 12 o 4 north pad. it is it is 6 wells, average about 19 thousand per well. So it will be terrific for us. So we do not have the results on that yet. But all these longer laterals that we have been drilling obviously, lot of them are now coming from HG because they did a really good job of planning along 1 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 is something we are interested in. We are going to try to replicate that with 2 different rows in our dry gas to do the exact same thing. But we have no limitations right now. I think you will see the lateral lengths continue to just go longer and longer. Makes sense. Thanks guys.

Next question comes from Subash Chandra with Stonex. Please state your question.

Hey, Mike. I wanted to confirm couple of things. So pro form a 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 $3?

I do not know about the second part, but the first part, correct. it is still $1 billion Subhash, I did not catch it, the second part of your question.

Yes. So the second part is Oh, right. No, it is a real world question would have been in the beginning of the year. Right now, it is where liquids prices are? I still think $3 generally in a mid cycle case, but that is more in that $35 to $40 NGL realized price. NGLs are well above that. Think today, our NGL barrel is at 45 doll dollars. David's confirming that. So that is good. But that is okay. Look. Currently, this morning, we are $45 per barrel. So that would put that a bit lower. You know, our liquids development is really kind of more on a steady state of maintenance. So the true 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 it is a second rig, are you still drilling the PUDs out? Have you gone into somewhat maybe the 2P that you thought you might have acquired with the acquisition? So on the 1.2 thousand and 17 pad, the 17 has been elevated All of them I think were in the proved. 1.2 thousand though, is on the schedule for 27, and that would have been in the 2 p but that is now been pushed up just with the performance of the results that we have seen. So right now those have been improved, but 27 drilling will get some of the 2P into the portfolio. Okay, great. Thank you. Mhmm.

Your next question comes from Paul Diamond with Citi. Go ahead with your question.

Thank you. Good morning. Thanks for taking the call. Just a quick 1 circling back on curtailments. I guess talked about the coming quarter is kind of already being baked in the guidance. I guess as we think about the contract optimization you talked about, how should we think about, I guess, willingness or ability to do so to a greater degree over time, or is this, like, the level you expect to stay at? This level of modulation?

Yeah, we will see. I mean, right now, we do have some legacy pads in that 61, 71, 81 Btu range. That generally are uneconomic if you are below if you are around that 1.50 to $1.75 But those are about the only pads where we have it in that lean gas area. Right now. So that is about it. it is about 50 million a day, right now of pads that were drilled in that kind of BTU regime that in years past we still would have produced because it would have had MVCs on it, but we no longer have those MVCs. So that is about all we have right now. The rest is either 1.2 thousand plus Btu or sub-1.1 thousand Btu. So those really would not qualify for this curtailment strategy.

Got it. Makes perfect sense. And then just talking a bit about-- you guys talked about a shift in your production cadence through time. I mean, how reactive do you see yourself being in coming years, given, I guess, the demand pull scenario from its own variability from that 50-50 split between dry gas and gas and liquids Yes.

We generally have a growth maintenance program. So we want to own a more percent of it, but keep the gross volumes Obviously, if there is incremental projects to that, that come along, in basin locally that does not really need our transport. We could potentially grow into those. But generally, what we have planned is 3 rig program, 2-completion crew and then continue to increase our percentage ownership of the gross, which keeps volumes in the basin flat, overall flat, but we just own more of it. Good. Appreciate the clarity. I will leave it there. Yep.

Your next question comes from Nitin Kumar with Mizuho Securities. Please state your question.

Yes, hi, good morning and thanks for squeezing me in. I just had a big picture question. When you think about your gas sales, obviously, you have had this transportation 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?

Yeah. We think a lot about it. Actually, that is 1 of the when we say risk adjusted, probably 2 of the 3 parameters I would look at, obviously, price being 1, but also timing and execution is really around the counterparty So we think a lot about that. If we do deals, the credit needs to be there, you will see us get LCs or some sort of credit assurance We are not credit agnostic. We have a big credit actually, team just around already having significant firm transport for over a decade. So we are very cognizant of the credit and the credibility of the project really goes into whether or not we participate. Understood. And then 1 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. Then you also talked about that number growing. My understanding was that as far as the contract rollovers are concerned, you know, that essentially a 2028 kind of timeline. Is that correct? And I presume that $105 million is kind of split between a number of contracts. Could you talk about that a little bit? Yes, that is correct. You have that correct. Main 1 you can think about is the ATEX. You know, that is the 1 that we always cite. that is I think $60 million of the 105. that is 20 thousand barrels a day. that is saying the price that it charges, I believe, is around $0.24, $0.25. David's nodding yes again. So it is good. that is ahead of the actual ethane price we received. So obviously we are 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 timeframe. So we no longer need that We, I think, we recover 90 thousand barrels of net ethane over 100 thousand barrels of gross ethane. For our pipeline spec we can be down in the low 70 thousand. So we can easily let that 20 thousand of ethane go and be within spec and it is completely uneconomic. So that is $60 million of the $105 The rest is just optimizing our already transport that expires at the end of 2028. And then the other piece that Mike had mentioned earlier there too is beyond 2028, which is not on that slide, when you have a lot of the gas contracts that come up for renewal where we think you could add another $200 million on top of on top of the $300 million. Understood. Thank you so much.

Thank you. And there are no further questions at this time. So I will now hand the floor back to Daniel Philip Katzenberg for closing remarks.

Yes. I would 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.