Antero Resources (NYSE:AR) Q2 2026 Earnings Call

0:01 Greetings and welcome to the Antero Resources Corporation's Second Quarter twenty twenty six Earnings Call. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation.

0:20 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 twenty twenty six investor conference call. We'll spend a few minutes going through the financial and operating highlights, then we'll open it up for Q and 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.

0:57 Joining me on the call today are Michael Kennedy, CEO and President Lenny Krueger, CFO Dave Camelago, Senior Vice President of Liquids Marketing and Transportation Justin Fowler, Senior Vice President of Natural Gas Marketing. Will now turn the call over to Mike. Thank you, Dan, and good morning, everyone. I'll start on Slide three 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 EBITDAX increasing 57% over that period.

1:48 These structural 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 number four titled Significant Reduction in Cash Costs. The cost reductions we realized during the second quarter was just the beginning of lower cost, 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% from 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.

2:47 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.

3:06 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 five, 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.

3:54 In the chart on the right hand side of the slide, we break out the $300,000,000 of annual margin improvements into three categories. First, we have two financial transactions that we entered into early this decade that come to an end, the overriding royalty interest transaction and the BPP. 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 $60,000,000 of annualized cash flow beginning in the third quarter of twenty twenty six. The VPP will expire in July of 'twenty seven and result in a $30,000,000 annualized cash flow uplift. Second, optimization of our liquids firm transport is forecast to improve margins by another $105,000,000 This includes limited needs for recontracting of ethane transport as well as the refinement of our LPG firm transport.

4:56 The enhancements to our liquids margin structure are expected to be realized at the end of twenty twenty eight. And third, the remaining $105,000,000 of margin improvements through 'twenty eight will primarily come through optimizing our natural gas firm transportation portfolio and increasing dry gas development.

5:15 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 and FX. 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.

6:05 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'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Conalongo, for his comments.

6:52 Thanks, Mike. I would like to begin by highlighting the strong realized C3 plus pricing Antero 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 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 six, U. S. Propane exports averaged 2,030,000 barrels a day during the second quarter of twenty twenty six, an increase of 170,000 barrels a day compared to the same period last year.

7:45 Additionally, propane exports hit a new weekly high of 2,630,000 barrels a day this May, with another weekly export number also above 2,600,000 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 lost Middle East supply across demand markets worldwide.

8:40 Going forward, additional LPG terminal expansions through 2027 will add another 1,000,000 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.

9:02 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 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.

9:27 Additionally, we are beginning to see a recovery in Chinese petrochemical demand for LPG. As shown on Slide seven 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 eight to discuss shipping dynamics. BLGC freight rates have been elevated since epicurey due to the global re suppling 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.

10:17 We anticipate 84 vessels will be added to the fleet in the second half of twenty twenty six and all of 2027.

10:24 From now through 2029, the size of the fleet will increase by 31% for 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.

10:56 With that, I'll now turn it over to our Senior Vice President of Gas Marketing, Dustin Vala, for his comments. Thanks, Dave. I'll start on Slide nine that highlights the strong fundamental outlook for natural gas that we see through 2030.

11:10 The two charts on this slide illustrate total U. S. Demand growth. Based on data center and power projects that have been announced today, 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.

11:40 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 two acreage with higher break evens 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 nine Bcf per day of demand. This does not include additional projects that we have spoken to that add an additional incremental three Bcf of demand to our regional,

12:26 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 six 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.

12:54 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 firm transport significantly widens the footprint of demand for 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 seven 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.

13:44 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 twenty twenty five, we spud our first dry gas pad in over twelve 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.

14:17 We also announced $315,000,000 of acquisitions in our core West Virginia Marcellus footprint. In total, these transactions increased our net production by approximately 125,000,000 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 $220,000,000 of free cash flow. We used a portion of this free cash flow to accelerate our share repurchase program, repurchasing 1,100,000 shares for 38,000,000 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.

15:08 This first step in realizing lower costs is attributed to the second quarter being our first full quarter incorporating the HG Energy acquisition.

15:16 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 twelve 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%

15:46 to just $900 per foot. Most impressively, our EUR increased 67% from 1.2 Bcf per thousand to over two Bcf per thousand. On the right you can see the ninety 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 one dry gas position left in The U. S. Next Slide 14 looks more closely at the acquisitions we closed in July. We invested $315,000,000 on assets in our core West Virginia Marcellus footprint. These transactions immediately add $125,000,000 a day of net production and were acquired at a combined valuation of just 4x EBITDAX and a free cash flow yield over 20%.

16:37 The chart on the right illustrates how we've been able to increase

16:41 production, which has increased from 3.3 Bcfe a day at the beginning of twenty twenty five 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.

17:08 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 a third. We have already achieved nearly half of our targeted 25% reduction in operating costs and the NGL outlook is significantly strengthened relative to the beginning of twenty twenty six. 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.

17:41 Thank you. And at this time, we will conduct our question and answer session. And And our first question comes from Kevin McCurdy with Pickering Energy Partners. Please state your question.

18:28 Hey, good morning and thanks for taking my question. There's been some activity in your neck of the woods in recent power deals and talk at 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

18:50 with long term sales agreements? Yes, I think we touched on the remarks. I mean, right now, we kind of think about how ten to fifteen 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 paths are competing with the power deals and comparing them. So it has to compete with the broader energy markets. The one that 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 one. Actually have a contract on some of our midstream.

19:27 So in discussions with them, just the uncertainty around the pricing, the timing, the execution, all that really didn't meet our return hurdles. So when we look at projects, it has to meet all of those three, and that one just wasn't attractive to us.

19:46 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?

20:05 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, that's 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 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. Appreciate it. Thanks. Your

20:42 next question comes from Dave Daud with Truist. Please state your question. Hey, thanks guys. 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. Looks like you're at four rigs currently, maybe already putting some of growth capital to work. Could we maybe just get an update there? Yes. So four, one is in transition. So it will be down to three here in the next month. But we are drilling those three pads that we talked about that are kind of on the difference between maintenance and growth capital. So you will have some capital. So our maintenance case, just to remind everyone, was $1,000,000,000 Our growth is $1,200,000,000 of capital this year.

21:29 Right now, we're probably somewhere a bit north of $1,000,000,000 but not to the 1,200,000,000 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've said in the past, three plus gas, is probably something that we would deploy, but we'll just have to determine that when we get there.

21:50 Okay. And so if you complete those wells, and that takes 27, I would imagine, dollars 3.46?

21:57 Yes. Yes. 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 if we progress through '27 and maybe in basin pricing not really materializing to what you would expect? Would you just still keep some of that FTE? Or is

22:26 that just simply just re contracting into lower market rates?

22:30 Yes, some of that same basin pricing runs 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. 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. And Justin hit on that slide, too. All of that seven Bcf of demand that's along those Feet paths,

23:01 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 Now that's baked into this $300,000,000 that we've been talking about, that'd be incremental. But that's something we're looking at. And 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're hopeful that we'll 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.

23:47 Thanks. Good morning, guys. Just just following up on the, the 300,000,000 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,

24:06 Is it safe to say that that $300,000,000 number would move materially higher if you just extended the timeline?

24:15 Absolutely. We just focused on three years. We thought that was kind of the investment horizon. If you're looking past that to the five years, I think you've joined it growth about 600 to $700,000,000 That's 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

24:47 see that mix sort of changing versus if we call it kind of two thirds kind of out of basin at the moment? Like just how do you see that evolving over the next several years?

24:56 Yeah. Right now we were kind of thinking, you know, a third was FP, long haul, a third liquids and a third is generally local sales. So if you just put that in natural gas terms, it's about $50.50.

25:12 The the word we like to use, you're you're gonna hear a lot of you here, the balance. You know, we wanna be balanced. We wanna be a balanced natural gas liquid producer. We also wanna be a balanced sell seller of the natural gas about half on the long haul transport and half local. That's great. Appreciate it. Mhmm.

25:34 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're halfway or nearly halfway there to the integration of HD, but give us a sense of how that will play out over the next couple of years. And again, I'm asking this question

26:10 largely trying to think about where your cash operating costs could be

26:14 in calendar twenty twenty seven as you move towards that $2 end of year '28 target? Yes, we put in the three 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 $04 uplift or $04 improvement on a cost structure, that's $60,000,000 And we have the VPP in July '27. That's an incremental 30,000,000 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.

26:56 And then the $105,000,000 that we're talking to liquids at year end twenty eighteen. 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 scale natural gas liquids producers will be more driven by kind of demand pull

27:21 versus just being a traditional E and P price taker. I was wondering if you could comment on how you think Antero's positioned for this kind of, call it, shift in market dynamics. Yes, we're extremely well positioned. Go back fifteen years, and we were trying to create markets. There was no local gas markets. 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.

27:55 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 ARP there and our strategy has been to remain on the spot there. So we haven't entered any firm agreements with that price.

28:21 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're not 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. That's clear. Thanks a lot, Mike.

28:52 Your next question comes from Doug Leggate with Wolfe Research. Please state your question. Thanks, guys. I appreciate you having me on. So, Brenda, this is maybe for you, but in your deck, you're walking through pretty clearly the reduction or the planned reduction in cash cost. You know, I think it's been beaten pretty well this morning. My question is, why are you

29:21 are you offsetting that with price realizations?

29:23 I'm trying to understand what the what this implies for your market view of gas going forward.

29:30 Yeah. I'm sorry. Didn't hear that last part. Doug, can you repeat that?

29:33 Yes. Sorry. Someone dialed 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 a 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. Cost coming down $0.70

30:17 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 pull, like Mike mentioned. This market where it used to be we have to find a place for your gas, it's now become, hey, can you deliver us 300,000,000 a day in this area? Can you deliver us 200,000,000 a day in this area?

30:43 And we need by this period of time?

30:45 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're 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 one hopefully. So obviously, you've drilled

31:11 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 roadmap to whether you would go back to growth in 2027?

31:28 Go back. We have two pads in there. Kate, where we put our first one in planning and path to Brendan, review the results. The next two are Katy and Walters right next to it. There'll be drilling, whether we complete them like you mentioned, will be natural gas price dependent.

31:47 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 those 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, then we won't complete them in the fourth quarter. That's really helpful. Thanks a lot. Your

32:17 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's 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's the wells are getting better and

32:51 just shifting to HG and how much of it is further dry gas growth above and beyond the base level? No, 50% is the HG or $15,000,000 this year's, I should say, is the HG. HG has outperformed our expectations definitely. Two of the three rigs that we have running right now have forced in transit, but two of the three are on HG pads. One of them those are liquids, one of them is a dry gas.

33:23 So incrementally, HD is outperforming and will have more production than we assumed. So there's a little bit of that, but it's not terribly material. HD 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 manned pole and shift to just some dry gas development also with those transactions expiring. Yeah. If you look at that two if you look at that 300,000,000 that we have laid out there too, Betty, you know, think two about $250,000,000 of that. So all of the liquids, the BPP, the override, and then about half of the gas, is all just driven by pure kind of optimization. The 50,000,000 Mike mentioned of that 300,000,000 is really just driven by that kind of shift to more dry gas and HG.

34:22 Got it. And then sorry for the so on a per unit basis, if you grow the dry gas piece going forward, how much would that improve your GP and T?

34:33 Well, I think on the GP and T front, so you like we said, the the the 300,000,000, just to break it down. So we've got 35¢ of margin improvement. 300,000,000 is about 20¢. The other $0.15 comes from HG. So $0.35 of margin improvement, point two zero is in that $300,000,000 we talked about, zero one five 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 and T coming down. I mean that's the driver of that. Processing costs will be lower. Transport costs will be lower, gathering the state of saying that AM on that front, but everything else will lower.

35:23 Got it. Thank you. 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 20 Yeah. Percent Mike talked about it. So you'll you'll likely go from what today is two thirds, call it two thirds, one third in terms of two thirds going to the LNG Fairway and third going elsewhere. You'll have that be more fifty-fifty on a go forward basis. Thank you. That will take some time to play out though. That will be over, call it a five year period for that to play out. Got it. Thanks. Your next question comes from Philip Youngworth with BMO.

36:11 Please state your question. Yeah, thanks. Good morning. I know Antero Midstream has a separate call, I was hoping you could talk about the Eastside Express Pipeline, which is the first interstate 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 and difficulties in building an interstate pipeline team? Just thinking shorter distances like West Virginia to 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 acquisitions that we just did, consolidating the dry gas area of our play, 1,000 locations that Brendan talked about.

37:00 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. 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's when we farmed 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 and investment grade goes with that over a million acres, thousands of these dry gas locations. This will go straight across it, we hope to build more of those at Antero Midstream and for Antero Resources to benefit off that building. Maybe the next one's probably North South.

38:00 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. 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 plus We have seen peers increase their focus on the marketing side of late one with the large acquisition. Just when you look at what they're doing, 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?

38:55 So 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 too, Dave and his team has been a leader in that. First one, signing up on ME2, pretty much signed up on every single project, from an LPG or ethane standpoint. I've 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.

39:42 We were there over a decade ago. Sounds good. Thanks. Mhmm. Your next question comes from Jack Kavanaugh with Goldman Sachs. Please state your question. Good morning, team, and thanks for taking my question. I just wanted to ask on hedging, especially in 2027. Just curious how your team's approaching the right hedging levels for next year and if there's anything you're seeing in the macro set for '27 that would change your hedging approach year over year based off the 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 got 34% hedged. I think it's a DCF at three eighty four and then maybe 100,000,000 a day of callers with a three fifty by four fifty.

40:30 We said before we like the 25% swaps and 25% callers, but that's if the callers, if those are attractive levels with a lot of calls queue. We've been favoring more of the swaps of late. I think you'll see us continue to increase that. We're great in 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. They are hedged volumes by, I believe, around $100,000,000 today and 26,000,000 and 80,000,000 in '27. So when we do acquisitions, will hedge them just like we did this one, these couple of acquisitions we did in July.

41:17 I appreciate that. And then my follow-up, maybe on the 315,000,000 in the West Virginia property acquisitions for the quarter. Curious how you and team are 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're seeing in the Yes, it does. We have a lot of non op working interest entities out in our base. I mean, when you have a million acres, 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. As part of the transaction, we want to buy in as much working interest as we can and get the acreage as well.

42:03 Goal one of our strategies is obviously to increase our production. It's really the interest of the production that's from a 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's 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'll continue to look at them. Generally, it's 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'll develop the pads and take advantage of those type of valuations.

42:54 Thanks, guys. Your next question comes from Leo Mariani with ROTH Capital. Please state your question. Yes, 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 kind of how much of the synergies you've captured thus far in 2026? And do you think that there could be more upside to that number over time? There will be more upside. It's still at that $80,000,000 level, but that's not capturing what I mentioned earlier in my remarks. We actually have two rigs of our three on the HG acreage. That's well ahead of schedule.

43:43 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. If there's a lot of pad ready there, they've already got all the infrastructure, being able to put those pads on right into local gas markets in the winter when we think there'll 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. Just for 26,000,000 to $80,000,000 is pretty much locked in. But that will go higher in 2027 as we put these new pads on.

44:30 Okay. 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 cost structure coming down in the but we also have a slide out on our deck that showed the commitments coming quite dramatically. Some of a lot of those commitments around the MVCs on the liquid. So we now have flexibility to look at our lean pads, kind of an eleven fifty, eleven sixty 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.

45:30 The ability just forecast, hey, look, September could be weak. We mentioned it's under $2 Let's shut in curtailments on those wells and bring them on more in the November December timeframe when the prices are higher. We very much have that 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 that you've laid out here. We're hopeful that continue to kind of add and ability to take advantage of those opportunities. Okay. Thank you. Your next question comes from John Annes with Texas Capital. Please state your question. Hey, good morning all. Thanks for taking my questions. For my first one, at Slide 13, can you help us break down what drove the improvement in the dry gas well results?

46:22 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? Yeah, no, it's a terrific result for us. So this 2,000 pounds of sand and eight thirty acre spacing is what we've traditionally done in the liquids. That's what we've done kind of our go to for the last ten years in the liquids. So we can play with that spacing. I know on the HG dry gas pads, going up 1,000, twelve fifty interlaterals and going up to 2,500 to 3,500 pounds of sand and 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 eight and thirty interlateral spacing and have it be over two Bcf per 1,000 was a terrific result for us. The lateral length just adds actually to the economics, brings that dollar per foot on the CapEx at $13,500 I mean, you're increasing proppant by 2.5 times, and your well cost is down 30%.

47:38 That's a lot of that's lateral length as well. So and drilling times and completion times. So feel really good about that. We have 1,000 locations greater than two Bcf. We probably would have had those in our database at 1.8 to 1.9. So above two 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 did the economics compare with your current average lateral? And excluding lease geometry, are there any practical limits extend laterals beyond that? No, we just drilled that. We haven't put that on yet. That's actually on an HG pad. On our 1204 North pad, such six wells average about 19,000 per well.

48:30 So it would 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 one high pressure line with six wells going north, six wells going south as much as the acreage position would allow. It really allows for terrific production profile being flat at 25,000,000 a day for a long time. So that's something we're interested in. We're going to try to replicate that with two different rows and our dry gas do 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. Makes sense. Thanks guys. Your next question comes from Subash Chandra with Stonex.

49:23 Please state your question. Hey, Mike. I wanted to confirm a couple of things. So, you know, pro form a for everything, the acquisition, the cost reductions, is maintenance CapEx still at that $1,000,000,000 and is the growth price, hurdle price for Henry Hub $3 I don't know about the second part, but the first part is correct. It's still a billion dollars. Subash, I didn't catch up the second part of your question. Yeah. So the the second part is Oh, $3. That would have been in the beginning of year. Right now, it's 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.

50:13 NGLs are well above that. I think today our NGL barrel is at $45 based confirming that. So that's good. But so far, yeah. But currently, morning, we have $45 barrel. So that that would put that a bit lower, we now are liquid developments really kind of more on a steady state of 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 the follow-up on HE, if you look at it this way, but with the second rig, are you still drilling the pudges out? Have you gone into some maybe the 2P that you thought you might have acquired in the acquisition? So on the twelve oh four and twelve seventeen pad, the twelve seventeen has been elevated.

51:05 All of them I think were in the approved 12/2003 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 by now those have been improved, but '27 drilling will get some of the 2P portfolio. Into Okay, great. Thank you. Your next question comes from Paul Diamond with Citi. Please go ahead with your question. Thank you. Good morning. Thanks for taking the call. Just a quick one circling back on curtailments. You guys talked about the coming quarter kind of already being baked into guidance. I guess as we think about the kind of a contract optimization you've talked about, how should we think about, I guess, your willingness or ability to do so or to a greater degree over time?

52:01 Or is this kind of like a level you expect to stay at this level of modulation? Yes, we'll see. I mean, right now, we do have some legacy pads in that eleven fifty, eleven sixty, eleven seventy Btu range that generally are uneconomic if you're if you're on 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 $50,000,000 a day, 50,000,100 million dollars a day right now of pads that were drilled in that kind of Btu regime. But in years past, we still would have produced because it would have had NBCs on it, but we no longer have those NBCs.

52:46 So that's about all we have right now. The rest is either 1,200 plus Btu or sub 1,100 Btu. So those really wouldn't qualify 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 reactive do you see your stuff being in coming years given, I guess, the demand pull scenario from kind of based on variability from that kind of fifty-fifty split between dry gas and or gas and liquids? Yeah, we generally have a growth maintenance program. So we want to own more percent of it but keep the gross volumes. Obviously, if there's incremental projects to that that come along in basin locally that that doesn't really need our transport.

53:39 We could potentially grow into those. But generally what we've planned is three 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. Appreciate the clarity. Leave it there. Your next question comes from Sunil Sibal with Seaport Global Securities. Please state your question. Yes. Hi. Good morning and thanks for squeezing me in. I just had a big picture question, you know, when you think about your gas sales, you know, obviously you had this, you know, transportation portfolio, which helped you sell gas in fairly liquid markets.

54:28 And then, you know, 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 we say risk adjusted, probably two of the three parameters I would look at, obviously, one, but also timing and execution is really around the counterparty. So we think a lot about that. If we do the 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, 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 participate.

55:26 Understood. And then one clarification on your savings slide that you have, I think you talked about $105,000,000 or so 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, you know, that's essentially a 2028 kind of timeline. Is that correct? And I presume that $105,000,000 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 is the ATEX. That's the one that we always cite. That's I think $60,000,000 of the 105 That's 20,000 barrels a day of ethane.

56:15 The price that it charges I believe is around $0.24 $0.25 Dave's nodding yes again. So that's good. That's ahead of the actual ethane price we received. So obviously we're not going to sign up for that. We had to do it a decade ago just to get our gas inspect, 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. I think we recover 90,000 barrels of net ethane, over 100,000 barrels of gross ethane. For our pipeline spec, 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.

57:06 So that's $60,000,000 of the $105,000,000 The rest is just optimizing our already transport that expires at the end of twenty eighteen. But then the other piece that Mike had mentioned earlier there too is beyond 2028, which is not on that slide is when you have a lot of the GAAP contracts that come up for renewal where we think you could add another few 100,000,000 on top of the on top of the 300,000,000. Understood. You so much. Thank you. 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.