Antero Resources Corporation

Greetings and welcome to the Antero Resources Corporation's second quarter 2026 earnings call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow a formal presentation. If anyone should require operator assistance, please press star zero on your telephone keypad. 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 Intero's second quarter 2026 investor conference call. We'll spend a few minutes going through the financial and operating highlights and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at interoresources.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 specialist for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President of Rady Krueger, CFO, Dave Camuago, Senior Vice President of Liquids Marketing and Transportation, Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'll start on slide number three, titled Structural Margin Improvement at Intero. 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 majestic EBITDAX 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 number four, titled Significant Reduction in Cash Costs. The cost reductions we realized during the second quarter was just the beginning of lower cost, comma, and taro. In June, we announced a cost reduction initiative that will significantly improve our margins. We're forecasting our cash costs 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. This shift in strategy that increases our exposure to dry gas and in basin sales is supported by the surge in new regional demand. This higher regional demand is expected to occur at the same time that many of our firm transportation commitments come up for renewal. To be clear, much of our LNG fairway-directed firm transport is attractive and will be retained. However, as we shift from the producer push era to the demand pull era, we are uniquely positioned to review each flow path and choose the highest margin sales point in supply contract for our natural gas and NGLs. Next, on slide number five, we provide details on our margin enhancement. The 70 cent improvement in our cash costs will be partially offset by 35 cents and lower price realizations as we sell more product in basin. This assumes strict pricing for in basin differentials without any tightening of basis that could occur When Regional Man 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 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 30th and resulting in an increase of $60 million of annualized cash flow beginning in the third quarter of 2026. The VPP will expire in July of 27 and result in a $30 million annualized cash flow uplift. Second, optimization of our liquids firm transport is forecast to improve margins by another $105 million. This includes limited needs for recontracting of FAA transport, as well as the refinement of our LPG firm transport. The enhancements to our liquids margin structure are expected to be realized at the end of 2028. And third, the remaining $105 million of margin improvements through 2028 will primarily come through optimizing our natural gas firm transportation portfolio and 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 Entero 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, Contero approaches these negotiations from a uniquely advantaged position. We hold optionality as we already sell our volumes at premium prices along the ONG fairway and are the second largest NGO 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 liquid 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, Now, to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquid Marketing and Transportation, Dave Conolongo, for his comments.

Thanks, Mike. I would like to begin by highlighting the strong realized C3 Plus pricing Entero achieved during the second quarter of this year. Entero's realized C3 Plus price was $44.26 per barrel. and many more. and many more. In addition, propane exports hit a new weekly high of 2.63 million barrels a day this May, with another weekly export number also above 2.6 million barrels a day reached in July, according to the EIA. These new highs surpass the previous record by 300,000 barrels a day and demonstrate that the US 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. Bill, lost Middle East supply across demand markets worldwide. Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels of A capacity, allowing exports to continue to grow over the coming years. On the demand side, key global consumers such as China have been buying more LPG from the U.S. as the Middle East supply remains curtailed and uncertain. China's LPG imports from the U.S. declined last year following the initial imposition of the additional U.S. tariffs, but have rebounded recently due to disruption in Middle East supplies. U.S. LPG market share in China has risen from a low of 10% in June of 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. Let's turn to slide number eight to discuss shipping dynamics. BLGC freight rates have been elevated since epicury due to the global resuppling of ships after the closure of the Strait of Hormuz, creating some headwinds for US LPG exports. However, the order book for new BLGCs is robust and will provide relief to shipping costs in the coming quarters. We anticipate 84 vessels will be added to the fleet in the second half of 2026 and all of 2027. and more. As the nation's second largest NGL producer and the largest producer-exporter, while also remaining unhedged on NGLs, Intero is poised to benefit from rising global demand for U.S. energy and higher Mont Velvie pricing. With that, I'll now turn it over to our Senior Vice President of Gas Marketing, Dustin Valla, for his comments.

Thanks, Dave. I'll start on slide number nine that highlights the strong fundamental outlook for natural gas that we see through 2030. 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 forecast to increase 19 BCF, LNG and Mexico export growth adds another 23 BCF per day of natural gas domain growth by 2030. In combination, this represents 37% of total domain growth for natural gas by the end of the decade. While associated gas from the Permian will fill a portion of this domain growth through announced e-graph expansions, higher prices will be required to incentivize growth from 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 of demand to our regional profile. We've shown this slide in the past and each time the number of projects in 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 Next, let's turn to slide number 11, titled Gas Demand Competition. As Mike detailed earlier, Antero is in an advantage position through our long-haul firm transportation capacity. This firm transport significantly widens the footprint of demand flow projects that we can This optionality is unique to Antero and allows us to be highly selective with our project partners around the best opportunities on a risk-adjusted basis. With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. I will start on slide 12, which highlights our second quarter operational and financial results. Our quarterly production was a company record. An average of all our guidance range coming in at over 4.1 BCFD a day. This represents an increase of 21% year over year. In late 2025, we spun 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 increase our net production by approximately 125 million cubic feet a day equivalent and add 15 net drilling locations. I'll discuss both of these updates in more detail momentarily. Turning to our financial results, on the right-hand side of the slide, our adjusted EBITDAX increased 57% year-over-year, resulting in $220 million of free cash flow. We used a portion of this free cash flow to accelerate our share repurchase program Repurchasing 1.1 million shares for $38 million. Lastly, our total cash operating costs were at the low end of the guidance range, declining 29 cents per MCFE, or 11% from the year-ago period. This first step in realizing lower costs is attributed to the second quarter being our first full quarter incorporating the HG Energy acquisition. Next, let's turn to slide 13, titled Strong Performance in Return to Dry Gas Drilling. This slide compares our well-designed 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 stand use from 800 pounds per foot to 2,000 pounds per foot. Despite these increases, our cost per foot declined 28% to just $900 per foot. Most impressively, our EUR increased 67%. from 1.2 BCF per 1,000 to over 2 BCF per 1,000. On the right, you can see the 90-day cumulative production rates, which increased more than 3x. All of these results exceeded our internal expectations. With over 1,000 dry gas locations, we view this acreage footprint as the largest undrilled Tier 1 dry gas position left in the U.S. Next, slide 14 looks more closely at the acquisitions we closed in July. We invested $315 million on assets in our core West Virginia Marcellus footprint. These transactions immediately add $125 million a day of net production and were acquired at a combined valuation of just four times EBITDAX and a free cash flow yield over 20%. The chart on the right illustrates how we've been able to increase our net production, which has increased from 3.3 BCFE a day at the beginning of 2025 to an expected 2026 exit rate of 4.5 BCFP 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 BCFP a day over that time period. To emphasize a point that we've made in recent discussions, Antero is in its best position in company history. Through accretive transactions and organic growth, our production has increased by a third. We have already achieved nearly half of our targeted 25% reduction in operating costs, and the NGL output is significantly strengthened relative to the beginning of 2026. Further, our share count is down, and our total debt will be back to pre-HG energy acquisition levels in the coming quarters. With that, I will now turn the call over to the operator for questions.

Thank you. And at this time, we will conduct our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, to ask a question, press star 1. We'll pause for a moment while we pull for questions. and our first question comes from Kevin McCurdy with Pickering Energy Partners. Please set your question.

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 of data centers. Obviously, you are in the dominant position or the dominant producer in West Virginia and you touched a little bit on this on your prepared remarks but maybe you can expand a little bit on how you view your gas marketing portfolio in total. and what would make you get more aggressive with long-term sales agreements?

Yeah, I think, you know, we touched on the remarks. I mean, right now we kind of think about how 10 to 15 years back, you know, 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. They actually, you know, have a contract on some of our midstream. So in discussions with them, you know, 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.

Okay, I appreciate the details there. And it's 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 Intero 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?

Yeah, definitely. You saw that in the quarter. You know, 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, you know, production up 20%, cash costs down 10%, liquids pricing up significantly, EBIT up 57%, and you look at the share price and it's the same as last year. So I would say that you could elevate the ranking of that and that it's very attractive to us at these levels.

Appreciate it. Thanks.

Your next question comes from Dave Dowd with Truist. Please state your question.

Hey, thanks, guys. It's Gabe from Truist. We're 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 that growth capital to work. Could we maybe just get an update there?

Yeah, so it's four ones in transition, so it'll be down to three here in the next month. But we are drilling those three paths 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 cases remind everyone it was a billion. Our growth is 1.2 billion of capital this year. Right now we're probably somewhere a bit north of a billion, but not to the 1.2. A lot of that will be completion capital in the fourth quarter, and we still have to be determined whether we deploy that. We've said in the past, $3 plus gas is probably something that we would deploy, but we'll just have to determine that when we get there.

Okay. And so if you complete those wells, and that takes 27, I would imagine, four or six? Yeah. Yeah. Okay. Okay. Thanks, Mike. And then maybe just a follow-up. Curious on the... The cost optimization plan, the 35 cent 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 that just simply just reconfiguring into lower market rates?

Yes, some of that sand 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, you know, it's definitely, you know, coming from the end users. It's a demand poll, 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 7 BCF of Demand, that's 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's baked into this $300 million that we've been talking about. That'd be incremental, but that's something we're 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'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.

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

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 it grows to about $600 million to $700 million.

That's great. And just follow up, Mike, as you sort of see this play out with the 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 two-thirds kind of out of basin at the moment? Like just how do you see that evolving over the next several years?

Yeah, right now we're kind of thinking, you know, a third was FT, 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. The word we like to use, you're going to hear a lot of it, you hear it's a balance. You know, we want to be balanced. We want to be a balanced natural gas liquid producer. We also want to be a balanced seller of the natural gas, about half on the long-haul transport and half local.

That's great. Appreciate it.

Your next question comes from Arun Jayaram with J.P. Morgan. Please see your question.

Yeah, good morning, team. Michael, I was wondering if you could talk us through the timing of further reaching your cost reduction target of 70 cents per MCFE. It sounds like you're halfway or nearly halfway there to the integration of HG, but give us a sense of how that will play out over the next couple of years. And again, I'm asking this question largely trying to think about where your cash operating costs could be in calendar 2027 as you move towards that $2 end of year 28 target.

Yeah, we put in the three buckets. We put some timing around that. That first one we talked about, the override, that starts immediately. That started in July. That's a 4 cent uplift or 4 cent improvement on a cost structure that's $60 million. And we have the VPP in July of 27. That's an incremental $30 million. Throughout that time, you're going to see this optimization of our natural gas firm transport. It's harder to predict the exact timing of that, but were in the negotiations around those type of improvements. So think about that small radical. And then the $105 million I was talking about was that year in 28.

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

Yeah, we're extremely well positioned. Go back 15 years and we were trying to create markets or let's know local gas markets who had to sign up for all the farm transport that came our way. Those are expiring now. So now we get to pick the best ones. You know, some of it ended up in terrific markets. Some of it didn't end up as well as we had hoped. So we'll be able to compare those now to the local demand. So it's perfect timing for us. And that's why in the comments, you know, those opportunities are going to have to compete with the broader energy markets because those LNG markets Buyers are really 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. And then locals are going to have to compete with that. That's why we're highly selective. You're going to see a bunch of announcements that, you know, along the way, you know, 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.

Your next question comes from Doug Legate with Wolf Research. Please, your question.

Thanks, guys. I appreciate you having me on. So, Brendan, this is maybe for you, but in your deck, you're walking through pretty clearly the Reduction of the plan reduction in cash costs. You know, I think it's been beaten pretty well this morning. My question is, why are you offsetting that with price realizations? I'm trying to understand what this implies for your market view of gas going forward.

Yeah, sorry, I didn't hear that last part. Doug, did you repeat that?

Why are you offsetting it with price realizations? I'm trying to understand what that signals for your view on the macro.

Yeah, 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 if 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. 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're quite... Thank you for joining us. and putting it on our natural gas in a big, big way.

I appreciate that, Cutler. Thanks. My follow-up is a quick one, hopefully. So, obviously, you've drilled your first dry gas pads in quite a while. You haven't completed them, obviously, but, you know, 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?

Go back. Oh, we have two pads in there. Kate, well, we put our first one, the Flanagan pad, that Brendan reviewed the results. The next two are Katie and Walter's right next to it. They'll be drilling. Whether we complete them, like you mentioned, will be natural gas price dependent. But I fully anticipate completing them if it's, you know, $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 next question comes from Betty Jang with Barclays. Please say your question.

Good morning. I want to start with a follow-up to Arun's question about costs. So this GP&T piece is, there's many drivers lowering that GP&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 just shifting to HG, and how much of it is growth, further dry gas growth, above and beyond the base level?

No, 50% is the HG, or $15 million this year, I should say, is HG. HG has outperformed our expectations, definitely. Two of the three rigs that we have running right now at Forest and Transit, but two of the three are on HG pads. One of them, though, is the liquids. One of them is the dry gas. So, incrementally, HG is outperforming. We don't have more production than we assumed. So there's a little bit of that, but it's not terribly material. HG does sell. We do sell the majority of those volumes in basin. So those will have lower transport costs associated with them. So that does impact it a bit. But the majority of it is just the shift, like we said, to the man pull and shift to just some dry gas development also with those transactions expiring.

Yeah, if you look at that $300 million that we've laid out there too, Betty, I think about $250 million 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 million Mike mentioned of that $300 million is really just driven by that kind of shift to more dry gas and HG.

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

Well, I think on the GP&T front, so you have, like we said, the $300 million, just to break it down, so we've got $0.35 of margin improvement. $300 million is about $0.20. The other $0.15 comes from HG. So 35 cents of margin improvement. The 20 cents within that $300 million we talked about, 15 cents is HG. And then the other, if you think about it from a cost standpoint, again, we're down 70 cents on cost. Almost all of that 70 cents reduction is going to come in the form of GP&T coming down. I mean, that's the driver of that. Processing costs will be lower. Transport costs will be lower. Gathering will stay the same, the AM on that front, but everything else will be lower.

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% currently?

Yeah, Mike talked about it. So you'll likely go from, you know, what today is two-thirds exposure You know, call it two-thirds, one-third in terms of two-thirds going to the LNG fairway and a third going elsewhere. You'll have that be more 50-50 on a go-forward basis.

So, thank you.

And that'll take some time to play out, though. That'll 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. Please, your question.

Yes, thanks. Good morning. I know Intero Mystery has a separate call, but I was hoping you could talk about the Eastside Express Pipeline, which is the first interstate regional line. Just how does this benefit Intero and just competence in executing a project like this? And then just separately, just what's the interest in difficulties in building an interstate pipeline team? Just thinking shorter distances, like West Virginia to Ohio, for instance, where there should be stronger dam pull in the future.

Yeah, no, we're super excited about that. That goes hand in glove with these acquisitions that we just did, consolidating the dry gas area of our pledge, the housing locations that Brendan talked about. This is our first regional pipeline east-west that will cover approximately over 30 miles of our acreage position and then the dry gas window extend all the way across it and Taro 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. You know, maybe a decade ago we 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 Intero Resources Acre Transition and Strength and Investment. Greg goes with that over a million acres, thousands of these dry gas locations. This will go straight across it and we hope to build more of those at Intero Midstream and for Intero Resources to benefit off that building. The next one's probably north-south. We've got a couple on the drawing board to go to all the demand centers, to go to all these projects, all the interconnects with all these long-haul pipes, just to interconnect this Million Acre position and Tier 1 Marcellus with all the demand that's been publicized. And then Tero Midstream will be the pipeline to build it, and we will not farm those type of opportunities out anymore.

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

We think we already have that. I mean, we've been the top 10 gas marketer in the U.S. for the past decade. We were ahead of the game on that with our firm transport portfolio. I think we have 28 paths that we market along. and also with our liquids 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 effing standpoint. I've been marketing around that. I'm really a market maker over on the Atlantic Basin side of the liquids marketing. So I feel really good about our position there ahead of the game and so now others are kind of getting into that modernization of the product being a very important part of the Business. We were there over a decade ago.

Sounds good. Thanks.

Your next question comes from Jack Cavanaugh with Goldman Sachs.

Please say your question. Morning, team, and thanks for taking my question. I just wanted to ask on hedging between 2027. I'm 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 2027 that would change your Thanks for joining us.

We've been favoring more of the swaps of late. I think you'll see us continue to increase that. We're in a great position, so we're not going to be rushing into down markets, but if you see upticks in the gas price in 27, you may see us add a little bit. When we do acquisitions like this recent one, we do hedge it, so you saw an increase in our volumes there, hedge volumes by, I believe, around $100 million today in 26 and $80 million in 27. So when we do acquisitions, we will hedge them just like we did this one, these couple of acquisitions we did in July.

I appreciate that. And then my follow-up, maybe on the $315 million and the West Virginia property acquisitions for the quarter, I'm 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're seeing in the market.

Yeah, it does. We have a lot of non-op working interest entities out in our basement. When you have a million acres, you have a large opportunity set. A lot of non-op working interest. We're in discussions with them, and they tend to have acreage around their non-op position, too, that they're not able to drill or operate. So as part of the transaction, we want to buy in as much working interest as we can and get the acreage as well. One of our strategies is obviously to increase our production. It's really the interest of the production that's from the gross standpoint already on our acreage. So gross being flat, but intero 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, you know, 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 paths and take advantage of those type of valuations.

Thanks, guys.

Your next question comes from Leo Mariani with Roth Capital. Please see your questions.

Yeah, hi guys. I was hoping you could give a little bit more of an update on HG here. I know that, you know, 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, you know, do you think there could be, you know, more upside to that number, you know, over time?

There will be more upside. It's still at that $80 million 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 as well as schedule. We were contemplating when we underwrote the transaction just one rig. So that's going to accelerate the volumes on the HG, which is going to accelerate the transaction value to us. There's a lot of pad ready there. They've already got all the infrastructure. being able to put those pads on right into the local gas markets in the winter when we think there will be elevated pricing. That's all entered into the decision, and obviously the well results are terrific. We're going to put on the second set of wells from the 1221 pad on August 17th. Those continue to outperform the 1221 North. So we'll continue to update that number, but just for 26 to 80 million is pretty much locked in. But that will go higher in 27 as we put these new pads on.

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

That's actually the detailment that we outlined. That's a new feature for Antero. We talked about the cost structure coming down, but we also have a slide out on our deck that shows the commitments coming down quite dramatically. And a lot of those commitments are on the MVCs, on the liquids. So we now have flexibility to look at our lean pads, kind of an 1150, 1160 BTU, and we don't have to produce them where in years past we would have because there have been MVCs with them. We now have ultimate flexibility, so that's a new feature that we're excited about. The ability to just forecast, hey, look, September could be weak. We mentioned it's under $2. Let's shut in the tailments 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 you've laid out here.

Yeah, we're hopeful to continue to kind of add abilities to take advantage of those opportunities.

Okay, thank you.

Your next question comes from John Annis with Texas Capitol. Please state your question.

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

Yeah, no, it's a terrific result for us. So this 2,000 pounds of sand and the 830-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 10 years in the liquids. We can play with that spacing. I know on the HG dry gas pad, we're going up 1,000, 1,250 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, 830 interlateral spacing and have it be over 2 BCF per thousand was a terrific result for us. The lateral length just adds, actually, to the economics brings that dollar per foot on the CapEx at $13,500. I mean, you're increasing profit by two and a half times, and your well cost is down, you know, 30%. 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 few 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, Keller. For my follow-up, on the lateral of more than 24,000 feet, how does the economics compare with your current average lateral? And excluding least geometry, are there any practical limits to extend laterals beyond that?

No, we just drilled that, so we haven't put that on yet. That's actually on an HG pad, on our 1204 north pad. Such six wells average about 19,000 per well. Those would be terrific for us. 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. That really allows for terrific production profile being flat at 25 million a day for a long time. So that's something we're interested in. We're going to try to replicate that with two different rows and our dry gas does the exact same thing. But we have no limitations right now. I think you'll see the ladder lengths continue to just go longer and longer. Thanks, guys.

Your next question comes from Subhash Chandra with Snownex. Please state your question.

Hey, Mike. I wanted to confirm a couple of things. So, you know, pro forma for everything, the acquisition, the cost reductions, is maintenance capex still at that $1 billion? 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. Subhash, I didn't catch the second part of your question.

Yeah, so the second part of your question.

That would have been at the beginning of the year. Right now, it's where liquid prices are. I still think $3 generally in a mid-cycle case, but that's more in that $35 to $40 NGL realized price. NGLs are well above that. I think today our NGL barrels at $45. Dave's confirming that, so that's good. Currently this morning we're at $45 barrels, so that puts that a bit lower, but our liquids and all of those. So, development's really kind of more on a steady state. The maintenance, 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, you know, if you look at it this way, but, you know, with the second rig, are you, you know, still drilling the pudge out? Have you gone into some, maybe the, you know, the two-key that you thought you might have acquired in the acquisition?

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

Okay, great.

Thank you. Your next question comes from Paul Diamond with Citi. Please go ahead with your question.

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

Yeah, we'll see. I mean right now we do have some legacy patents in that $1,150, $1,160, $1,170 BTU range that generally are uneconomic if you're below, if you're on that $1.50 to $1.75. But You know, those are about the only pads where we have it kind of in that lean gas area right now. So that's about it. It's about 50 million a day, 50 to 100 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 NBCs on it, but we no longer have those NBCs. So that's about all we have right now. The rest is either You know, 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, just talk about a shift in kind of your production cadence through time. I mean, that's how we and I could DCU stuff being in coming years, given, I guess, the demand-pull scenario from kind of start.

We generally have a growth maintenance program, so we want to own more percent of it, but keep the growth volumes. Obviously, if there's incremental projects to that that come along in base and locally that doesn't really meet our transport, we could potentially grow into those, but Generally, what we've planned is three rig program, two 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. Good.

Appreciate the clarity. I'll leave it there. Yep.

Your next question comes from Sunil Simal with Seaport Global Securities. Please state your question.

Yes, hi, good morning, and thanks for sending me in. I just had a big picture question. You know, when you think about your gas sales, you know, obviously you have this, you know, transportation portfolio, which helps you sell gas in fairly liquid markets. And then, you know, as you think about the in-basin demand, how do you think about, you know, the counterparty risk as you shift more on the in-basin demand versus... Was it selling to more liquid?

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

Understood. And then one clarification on your savings slide that you have. I think you talked about $105 million or so of savings from 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 one of five million 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. You know, that's the one that we always cite. That's like 60 million of the 105. That's 20,000 barrels a day of ethane. The price that it charges, I believe, is around 24, 25 cents. Dave's nodding yes again, so that's good. That's ahead of the actual ethane price we receive, so obviously we're not going to sign up for that. We had to do it a decade ago just to get our gas in spec, but since that time, a lot of have been developed around the Shell, ME2, Mariner East, Utopia, a lot of different ethane markets have been developed over that time frame. So we no longer need that. I think we recover 90,000 barrels of net ethane over 100,000 barrels of gross ethane. For our pipeline spec, we can be down in the low 70,000, so we can easily let that 20,000 ethane go. and be within spec and it's completely uneconomic. So that's $60 million in the 105. The rest is just optimizing our already transport that expires at the end of 28.

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

Understood. Thank 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. I'll pardon the disconnect.