Second Quarter 2026 Earnings Call

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 press release for important disclosures regarding flex measures. Joining me on the call today are Michael Kennedy, CEO and President, Freddie Krueger, CFO, Dave Canelago, Senior Vice President of Liquids Marketing and Transportation, Justin Fowler, Senior Vice President. 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 Entero. This structural improvement has strengthened our financial performance and, importantly, reduced earnings volatility. The results of this strategy can be seen in the table on the right side of the slide. While Henry Hub natural gas prices were down 16% from a year ago, the impact of increased scale product diversity and lower cash operating expense led to our adjusted EBITDA increasing 57%. These structural and sustainable improvements in our business will reduce volatility in our future cash flow on the topic of cost reductions. Let's turn to slide number four, titled Significant Reduction in Cash Costs. The cost reductions we realized are in the second comment, Entero. In June, we will significantly improve our margins. We are forecasting our 25% from 2025 to year-end 2028 to $2 per MCFE. This dramatic change in our cost structure will be achieved, 100% liquids development and 100% out-of-basin product sales to a much more balanced, rich, and dry gas development. Having sales in-basin and out-of-basin, 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. Our LNG fairway-directed firm transport is attractive and will be retained. Producer Push 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 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 strip pricing for in-basin differentials without any tightening of basis that could occur when regional demand starts. On the right-hand side of the slide, we break out the $300 million of annual margin improvements into three categories. Two financial transactions that we entered into early this decade that come to an end, the overriding royalty interest transaction and the VPP. The overriding royalty interest transaction return threshold to the counterparty was met in the second quarter, leading to the Mardica 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 improved margin by another $105 million. This includes limited needs for recontracting of ethane transport, as well as the refinement of our LPG firm transport. The enhancements to our liquid 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 Intero 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 continue to be actively engaged in conversations with all of these projects, these negotiations from a uniquely advantaged position. We hold optionality as we already sell our volumes at premium prices along the LNG fairway and are the second largest NGL producer in the country, which provides margin uplift. This means that local power projects must compete with the broader energy markets on return. 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 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 liquid marketing and transportation dave conalongo for his comments continue to be influenced with supply has been calling on slide number six additionally

these new highs surpass and demonstrate that they've driven in part additionally bypassing the previous through 2027 on the demand side key global consumer line last year have rebounded recently due to disruption in middle east supplies us lpg market share in china has risen from a low of 10% in June of 2025 to an average of 51%. Additionally, we are beginning to see around slide number 7 titled, China PDH demand is at all-time high levels not seen since before the disruption. Higher demand should support more U.S. import. Turn to slide number 8 to discuss shipping dynamics. BLGC freight rates have been elevated since Epic Fury due to the global resuppling of ships after the closure of the Strait of Hormuz, creating some headwinds for U.S. LPG exports. However, the order booked for new BLGCs is robust and will provide relief to shipping. We anticipate 84 by 27. From now through 2029, the size of the fleet will increase by 31 percent, given the imminent export expansions and new-built terminals coming up, and second-largest NGL remaining unhedged on NGLs. Intero is poised to that. I'll now turn it over to our Senior Vice President of Gas Marketing, Justin Bollett, for his comment.

Slide number nine that highlights the strong fundamental outlook for natural gas that we the two charts on this slide illustrate total u.s. demanding 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 prediction this represents 37% of the Permian will fill a portion of this demand cases will be required highlighted on this slide this does not include additional projects that we have all three BCF at demand to our regional, which highlights our second quarter operational and financial results.

Our quarterly production was a company record and averaged above our guidance range coming in at over 4.1 BCFE a day. This represents an increase of 21% year over year. In late 2025, we spot our first dry gas pad in over 12 years, and today we announced the results of that pad. This pad That delivered a more than 67% improvement in EUR and a nearly 30% decrease in costs 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 of a equivalent and add 15 net drilling locations. I'll discuss both of these updates in more detail momentarily. Turning to our financial results on the right-hand side of the slide, our adjusted EBITDAX increased 57% year-over-year, resulting in $220 million of free cash flow. We used a portion of this free cash flow to accelerate our share repurchase program, repurchasing 1.1 million shares for $38 million. Lastly, our total cash operating costs were at the low end of the guidance range, declining $0.29 per MCFE, or 11% from the year-ago period. This first step in realizing lower costs is attributed to the second quarter being our first full quarter incorporating the HG Energy Acquisition. Next, let's turn to slide 13 titled Strong Performance 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 thousand to over 2 BCF per thousand. On the right, you can see the 90-day cumulative production rates, which increased more than 3x. All of these results exceeded our internal expectations. With over 1,000 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 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 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 growth. T has remained essentially flat at 35.5 BCF a day over that time period. To emphasize a point that we've made in recent discussions, Antero is in its best position in company history. Through accretive transactions and organic growth, our production has increased by 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 in 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 sit 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 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 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, and 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 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 discussions with them. You know, just the uncertainty around the pricing, the timing, the execution, and all of that really didn't meet our return hurdles. So when we look at projects, it has to meet all of those three.

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. We weren't planning on buying back shares in the quarter, but where the equity price went, obviously, that was very attractive to us. I think you heard in Brendan's summary comments, production liquids pricing up significantly, EBIT up 57%, and you look at the share price, and it's the same as last year. The ranking of that and that is very attractive to us at these levels.

Appreciate it. Thanks.

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

Hey, thanks, guys. as 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. One's 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, the difference between maintenance and growth capital. So you also have some capital. So our maintenance case, just to 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 the billion, but not to the $1.2. A lot of that will be completion capital in the fourth quarter, and we still have yet to be determined whether we deploy that. We've said in the past that we would deploy, but we'll just have to determine that when we get there.

Okay. Yeah. And so, if you complete those wells, I mean, that takes 27, I would imagine, 4, 6. Yeah.

Yeah.

Okay. Okay. Thanks, Mike. And then maybe just a follow-up. Curious on 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 FT? Or is that just simply just recontrading into lower market rates?

Yeah, sorry. Some of that's in basin pricing around the dry gas, but the majority of it is just the optimization of our firm transport. I was trying to hit in the comments, you know, it's definitely, you know, coming from the end. 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 know, you can assume a lot of those are reaching out to us to try to, you know, 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, and you kind of saw the first sign of that with our guys just getting premiums along that path instead of just having it.

Okay, that makes sense. Thanks, guys.

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

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

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

That's great. And then 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's liquids, and a third is generally local sales. The word we like to use, you're going to hear a lot of, you hear the balance. You know, we want to be balanced. We want to be a balanced natural gas liquids producer. We also want to be a balanced seller of the natural gas, about half on the long haul transport and half local.

That's great. Appreciate it.

Your next question comes from Arun Jairam with J.P. Morgan. Please do your question.

Yeah, 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 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. But first, when we talk about the override, that starts immediately. That started in July. That's a $0.04 uplift or $0.04 improvement on $50 million. And we have the VPP in July of 27. That's an incremental $30 million. Throughout that time, you're going to see this optimization of our natural gas firm transport. It's harder to predict the exact timing of that, but we're in significant negotiations around those type of improvements. So think of – and then the $105 million that we're talking to liquids, that's year-end 28.

Got it. Great. In my follow-up, Mike, clearly one of the themes from today's earnings is your commentary that the business for large, scaly, natural gas liquids producers will be more driven by kind of demand pull versus just being a traditional E&P price taker. I was wondering if you could comment on how you think Antero'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. There was no local gas market, so we 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 buyers are really kind of international. There's an ARP there, and our strategy has remained on the spot there. So we haven't entered any firm agreements with that price. And then local is going to have to compete with that. That's why we're highly selective. You're going to see a bunch of announcements that, you know, along the way, you know, were an 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 see 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 or the plan reduction in cash costs. 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.

Sorry, I didn't hear that last part. Did you repeat that?

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

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 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 basins. So cost coming down 70 cents, realizations coming down by about half. So what's like this market where it used to be you have to find a place for your gas, it's now become, hey, can you deliver us $300 million a day in this area? Can you deliver us $200 million a day in this area that we need by this period of time? And we have to weigh that against our firm transport. What is the cost to get you there? You have to take on that cost to take on that cost in our decisions. But they all should lead to margin improvement on our natural gas in a big, big way.

I appreciate that, Culler. 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?

Well, we have two pads in there. The first one, the planning and pad that Brennan reviewed the results. The next two are – they'll be drilling. Whether we complete them, like you mentioned, will be dependent. But I fully anticipate completing them if it's $3 gas plus. And we can – those markets that we're looking at, you would assume that those would be completed. But if you have a significant – moving on the 2027, That's really helpful.

Your next question comes from Betty Jang with Barclays. Please see your question.

Good morning. I want to start with a follow-up to Arun's question about cost. This GPNT piece, there's many drivers lowering that GPNT 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?

50% is the HG, or $50 million this year's, I should say, is HG. HG has outperformed our expectations, definitely. Two of the three are the force in transit, but two of them, one of them, those are liquids, one of them is the dry gas. Mentally, HG is outperforming. We'll have more production than we assume. HG does sell. We do sell the majority of those volumes in basin. So that does impact it and shift to just some dry gas development also with those transactions expiring.

Yeah, if you look at that $300 million that we have laid out there too, Betty, I think about $250 million of that. So all of the liquids, the VPP, the override, and then about half of the gas is all just driven by pure kind of optimization. The $50 million, Mike mentioned, of that $300 million is really just driven by that kind of shift.

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

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

And if I could sneak in one quick one, in your scenario, how much does your in-basin exposure grow over the next few years, around the 20% currently?

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

Thank you.

So that will be over, call it a five-year period for that to play out.

Got it.

Your next question comes from Philip Youngworth with BMO. Please do your question.

Yeah, thanks. 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 Antero and just confidence 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 like shorter distances, like West Virginia to Ohio, for instance, where there should be strong demand 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 play, the thousand locations that Brendan talked about. This is our first regional pipeline east-west. It will cover approximately over 30 miles of our acreage position in the dry gas window, extend all the way. It is the industrial builder of northern West Virginia and now has the balance sheet, the credit, the strength, the expertise to build there over a decade. Maybe a decade ago, we farmed this out, 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' acreage position and strength and investment, great million acres, thousands of these dry gas locations 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, just to interconnect this million-acre position in Tier 1, Marcella, that's been publicized. And Intero Midstream will be the pipeline to build it. We will not farm those type of opportunities out anymore.

Okay, great. And then Intero 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 when with the large acquisition. Just when you look at what they're doing, is that something that could make sense for Intero to pursue just as less of the dry gas volume in the future is committed? And if so, how do you go about that?

You know, we think we already have that. I mean, we've been the top 10 gas marketer in the U.S. for 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 MNLPG or Ethane standpoint. I've been marketing around that, marketing. So now others are kind of getting into that monetization of the business.

Sounds good. Thanks.

Your next question comes from Jack Cavanaugh with Goldman Sachs. Please take your question.

Morning, team, and thanks for taking my question. I just wanted to ask on hedging, specifically in 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 setup for 2027 that would change your hedging approach year over year based off the 60% levels we saw in 2026.

We're actually ahead of where we were this time last year for 27. We've got 34% hedge. I think it's a BCF at 384 and then maybe 100 million a day of callers with a 350 by 450. 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 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 and $26 million 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 the number of opportunities you're seeing in the market.

Yeah, it does. We have a lot of non-off working interest entities out in our basin. When you have a million acres, you have a large opportunity set. But 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, as part of the transaction, we want to buy in as much working interest as we can and get the acreage as well. Our goal, one of our strategies is obviously to increase our production. It's really the interest of the production that's from the growth standpoint already on our acreage. So, gross being flat, but Antara 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, a couple pads, right on that Eastside Express. We continue to see these type of opportunities, and we'll continue to look at them. 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 paths.

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 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. That's well ahead of scalpelating 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 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 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 million to $80 million is pretty much locked in. But that will go higher in $27 million as we put these new pads on.

I appreciate that. And in terms of, you know, the gas price environment, clearly it's relatively weak, you know, right now. And 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 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.

Yeah, I'm glad you brought that up. That's actually the tailments that we outlined. That's a new feature for Antero. We talked about the cost structure coming down, but we also in our deck that showed the commitments coming down quite dramatically. And 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 1150, 1160 BTU, and we don't have to produce them where in years past we would have because there have been NBCs with them. We now have ultimate flexibility, so that's a new feature that we're excited about. The ability 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 time frame 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. Okay, thank you.

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

Hey, good morning, all. Thanks for taking my questions. For my first one, looking at slide 13, can you help us break down what drove the improvement in the dry gas well results? For example, how much came from the completion design, longer laterals, better targeting versus other factors?

And then given this was your first dry gas pad in more than a decade, how much more room do you see for further improvement as you apply what you learned to future pads? yeah no it's a terrific result for us and in the 830 acre spacing is what we traditionally done in the liquid that is in the liquid so we can play with that spacing i know on the hg dry gas pad for 500 to 3 500 pounds of sand and the water going in between 35 barrels per foot and 50 barrels per station that curb 830 interlateral spacing and have it be over 2 bcf per thousand was a terrific result for us to the economics. Brings that dollar per foot on the CapEx, that $13,500. I mean, you're increasing profit by two and a half times, and you're well, you know, 30% as well. So, and drilling times and completion times, locations, eight to one nine. So, above two 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 did 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 H-1204 north pad. It's averaged about $19,000 per well, 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, while 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 did the exact same thing. We have no limitations right now. I think you'll see the ladder lengths continue to just go longer and longer.

Makes sense. Thanks, guys.

Your next question comes from Subhash Chandra with Stonex. Please take 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, 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.

Yeah, so the second part is...

That would have been in the beginning of the year right now with where liquids prices are. I still think $3 generally in a mid-cycle case, but that's more in that $35 to $40 NGL realized price. NGLs are well above that. I think today our NGL barrel is at $45. Dave's confirming that, so that's good. Apparently this morning we're at $45 barrel. Put that a bit lower, but our liquid development is really kind of more on a steady state of 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 a 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 pudges out? Have you gone into some, maybe the, you know, the 2P 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, the 003, though, is on the schedule for 27, and that would have been in the 2P. But that's now been pushed up, the results that we've seen. All those have been improved, but 27 drilling will get some of the 2P into the portfolio.

Okay, great.

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

Thank you. 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 to a greater degree over time? Or is this kind of like the level you expect to stay at, this level of modulation?

Yeah, we'll see. I mean, right now we do have some legacy pads in that 1150, 1160, 1170 BTU range that generally are uneconomic 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 had BCs on it, but we no longer had those NBCs. So that's about all. It's either 1,200-plus BTU or sub-1,100 BTU. So those really wouldn't qualify for this curtailment strategy.

That makes perfect sense. And then just talking a bit about – you guys talked about a shift in kind of your production cadence through time. I mean, how reacted these to your stuff being in coming years, given, I guess, the demand-pulse scenario from kind of variability from that kind of 50-50 split between dry gas or gas and liquids?

Yeah, 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 basin locally, that doesn't really need our transport to completion crew and then continue to increase in the basin flat, overall flat, but we just own more of it.

Appreciate the clarity. I'll leave it there.

Your next question comes from Sunil Simal 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. 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. And then, you know, as you think about the in-base and demand, how do you think about, you know, the counterparty risk as you shift more on the in-base and demand versus selling to more liquid?

Yeah, we think a lot about it, actually. That's one of the, when we say risk-adjusted, two of the three parameters that we look at, obviously price being one, but also timing and execution is really around the counterparty. If we do do deals and the credit needs to be there, you'll see us get LCs or some sort of credit assurance. We're not credit agnostic. We have a big credit, actually, team. Confirm transport probability and the execution.

Understood. And then one clarification on your savings slide that you have. I think you talked about 105 million or so of savings from some of the contracts that are rolling over. And then you also talked about that number growing. My understanding was that as far as the contract rollovers are concerned, that's essentially a 2028 kind of timeline. line. 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, I think, 60 million of the 105. That's 20,000 barrels a day. That's saying 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 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 in spec, but since that time, a lot of markets have been developed around the Shell, ME2, Marineries, 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 2018.

But then the other piece that Mike had mentioned earlier, too, is beyond 2028, which is not on that slide, is when you have a lot of the gas costs, a few hundred million on top of that.

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.

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.

Thank you. And with that, we conclude today's call. I'll pardon you to make a disconnect.