Thank you for joining us for Antero's second quarter 2026 investor conference call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A.

I would also like to direct you to the homepage of our website at anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures.

Please refer to the earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing.

I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'll start on slide number 3, titled "Structural Margin Improvement at Antero."

This structural improvement has strengthened our financial performance and, importantly, reduced earnings volatility. The results of this strategy can be seen in the table on the right side of the slide.

While Henry Hub natural gas prices were down 16% from a year ago, the impact of increased scale, product diversity, and lower cash operating expense led to our adjusted 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 4, titled "Significant Reduction in Cash Costs." The cost reductions we realized during the second quarter was just the beginning of lower costs to come at Antero.

In June, we announced a cost reduction initiative that will significantly improve our margins. We are forecasting our cash cost to decline by over 25% 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-basin 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 high regional demand is expected to occur at the same time that many of our firm transportation commitments come up for renewal. To be clear, much of our LNG fairway directed firm transport is attractive and will be retained.

However, as we shift from the producer-push era to the demand-pull era, we are uniquely positioned to review each flow path and choose the highest-margin sales point and supply contract for our natural gas and NGLs. Next, on slide number 5, we provide details on our margin enhancement.

The 70 cents improvement in our cash cost will be partially offset by 35 cents in lower price realizations as we sell more product in-basin. This assumes strip pricing for in-basin differentials without any tightening of basis that could occur when regional demand starts to ramp up.

In the chart on the right-hand side of the slide, we break out the $300 million of annual margin improvements into three categories. First, we had 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 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 re-contracting of ethane transport, as well as the refinement of our LPG firm transport.

The enhancements to our liquids margin structure are expected to be realized at the end of 2028. Third, the remaining $105 million of margin improvements through '28 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 Antero and the natural gas industry in Appalachia. We are encouraged by the power deals that have been publicly announced to date, as they further validate the significant regional demand growth that we are expecting.

We continue to be actively engaged in conversations with all of these projects. However, Antero approaches these negotiations from a uniquely advantaged position.

We hold optionality as we already sell our volumes at premium prices along the LNG fairway and are the second largest NGL producer in the country, which provides margin uplift. This means that local power projects must compete with the broader energy markets on returns to attract our volumes.

This compares with many of our peers who lack the firm transportation portfolio or liquids production and are looking for projects for nearly 100% of their production. These attributes allow us to be highly selective in which projects we ultimately partner with.

The projects that we elect to participate in will have to be accretive on a risk-adjusted basis, which includes pricing, timing, and certainty. Now to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments.

Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing Antero achieved during the second quarter of this year.

Antero's realized C3+ price was $44.26 per barrel, up $6.41 per barrel compared to the second quarter of last year, and our highest quarterly realized price since 2022. Liquids prices continue to be influenced by geopolitical events as uncertainty remains over the flow of products through the Strait of Hormuz and other critical transit routes.

U.S. liquid supply has been called on by international buyers looking to replace Middle East cargoes.

As shown on slide number 6, U.S. propane exports averaged 2.03 million barrels a day during the second quarter of 2026, an increase of 170,000 barrels a day compared to the same period last year.

Additionally, propane exports hit a new weekly high of 2.63 million barrels a day this May, with another weekly export number also above 2.6 million barrels a day reached in July, according to the EIA. These new highs surpassed the previous record by 300,000 barrels a day and demonstrate that the U.S.

can reach previously unseen export levels, driven in part by recently added terminal capacity. Additionally, exports of normal butane reached a new monthly record of 815,000 barrels a day in April, the most recent month of EIA data, surpassing the previous record of 661,000 barrels a day set in March.

The record levels achieved for both LPG products since the start of Operation Epic Fury illustrate that propane and butane are fiercely competing for terminal space to backfill lost Middle East supply across demand markets worldwide. Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels a day capacity, allowing exports to continue to grow over the coming years.

On the demand side, key global consumers such as China have been buying more LPG from the U.S. as the Middle East supply remains curtailed and uncertain.

China's LPG imports from the U.S. declined last year following the initial imposition of the additional U.S.

tariffs, but have rebounded recently due to disruption in Middle East supplies. U.S.

LPG market share in China has risen from a low of 10% in June 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.

Next, let's turn to slide number 8 to discuss shipping dynamics. VLGC freight rates have been elevated since Epic Fury due to the global reshuffling of ships after the closure of the Strait of Hormuz, creating some headwinds for U.S.

LPG exports. However, the order book for new VLGCs is robust and will provide relief to shipping costs in the coming quarters.

We anticipate 84 vessels will be added to the fleet in the second half of 2026 and all of 2027. From now through 2029, the size of the fleet will increase by 31% or 138 ships.

Given the imminent export expansions and new build terminals coming online, greater ship availability will facilitate more cargoes leaving the U.S. and continue to support Mont Belvieu pricing.

As the nation's second largest NGL producer and the largest producer exporter while also remaining unhedged on NGLs, Antero is poised to benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing.

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

Thanks, Dave. I'll start on slide number 9 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 to date, natural gas demand is forecasted to increase 19 Bcf. LNG and Mexico export growth adds another 23 Bcf per day of natural gas demand growth by 2030.

In combination, this represents 37% of total demand growth for natural gas by the end of the decade. While associated gas from the Permian will fill a portion of this demand growth through announced egress expansions, higher prices will be required to incentivize growth from non-traditional gas basins and tier two acreage with higher breakevens to ultimately meet this demand.

Now let's look at regional demand in our Appalachian Basin, which is highlighted on slide number 10. The power projects highlighted on this slide represent the projects that have been publicly announced in our region to date and amount to over 9 Bcf per day of demand.

This does not include additional projects that we have spoken to that add an additional incremental 3 Bcf of demand to that profile. We've shown this slide in the past, and each time the number of projects and implied regional demand estimate has increased.

What is exciting to us today is that we now have 6 Bcf of projects that are either FID or under construction. This increases our visibility into which projects will come to fruition and allows us to prioritize our conversations.

Next, let's turn to slide number 11, titled "Gas Demand Competition." As Mike detailed earlier, Antero is in an advantageous position through our long-haul firm transportation capacity.

This firm transport significantly widens the footprint of demand-pull projects that we can select to participate in. Our firm transport portfolio opens up opportunities into the Midwest and further south, where in total, another 7 Bcf per day of power projects are being forecasted.

This optionality is unique to Antero and allows us to be highly selective with our project partners around the best opportunities on a risk-adjusted basis. With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. I will start on slide 12, which highlights our second quarter operational and financial results.

Our quarterly production was a company record and averaged above our guidance range, coming in at over 4.1 Bcfe a day. This represents an increase of 21% year-over-year.

In late 2025, we spud our first dry gas pad in over 12 years, and today we announced the results of that pad. This pad delivered a more than 67% improvement in EUR and a nearly 30% decrease in cost per foot.

We also announced $315 million of acquisitions in our core West Virginia Marcellus footprint. In total, these transactions 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 design and production performance from when we last drilled on our dry gas acreage over 12 years ago to the pad we turned to sales this year using modern drilling and completion methodologies. Our lateral lengths nearly doubled, and we increased our sand use from 800 pounds per foot to 2,000 pounds per foot.

Despite these increases, our cost per foot declined 28% to just $900 per foot. Most impressively, our EUR increased 67% from 1.2 Bcf per 1,000 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, pure-play dry gas position left in the U.S. Next, slide 14 looks more closely at the acquisitions we closed in July.

We invested $315 million on assets in our core West Virginia Marcellus footprint. These transactions immediately add 125 million a day of net production and were acquired at a combined valuation of just 4x EBITDAX and a free cash flow yield over 20%.

The chart on the right illustrates how we've been able to increase our net production, which has increased from 3.3 Bcfe a day at the beginning of 2025 to an expected 2026 exit rate of 4.5 Bcfe a day, or 36% growth over that time period. Notably, we have been able to accomplish this net production growth without impacting the basin's gross production, which you can see has remained essentially flat at 35.5 Bcf a day over that time period.

To emphasize a point that we've made in recent discussions, Antero is in its best position in company history. Through accretive transactions and organic growth, our production has increased by a third.

We have already achieved nearly half of our targeted 25% reduction in operating costs, and the NGL outlook has significantly strengthened relative to the beginning of 2026. Further, our share count is down, and our total debt will be back to pre-HG Energy acquisition levels in the coming quarters.

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

Hey, good morning, and thanks for taking my question. There's been some activity in your neck of the woods and 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.

I think we touched on our remarks. Right now we kind of think about how 10 to 15 years back, we signed up for all the firm transport arrangements just to get our gas out.

Now we're at the end of that, and so we can select the best paths, and those paths are competing with the power deals and comparing them. It has to compete with the broader energy markets.

The one that was recently in our backyard, we've been in discussions with them for almost a decade. We're well aware of that one.

They actually have a contract on some of our midstream. In discussions with them, just the uncertainty around the pricing, the timing, the execution, all that really didn't meet our return hurdles.

When we look at projects, it has to meet all of those three. That one just wasn't attractive to us.

Appreciate the details there. As my follow-up, you were able to do some buybacks this quarter despite continuing to execute on the bolt-ons.

We see a lot of free cash flow potential for Antero in the coming years. With the stock in the kind of mid-30s, are you ranking buybacks a little bit higher among your options for your cash flow?

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 up 20%, cash costs down 10%, liquids pricing up significantly, EBITDA up 57%, and you look at the share price and it's the same as last year.

I would say that you could elevate the ranking of that, and that is very attractive to us at these levels.

Appreciate it. Thanks.

Mhm.

Hey, thanks, guys. It's Gabe from Truist.

We was hoping we can maybe just touch on the growth CapEx and how we should be thinking about that impacting 2026. Looks like you're at four rigs currently, maybe already putting some of that growth capital to work.

Could we maybe just get an update there?

It's four, one's in transition, it'll be down to three here in the next month. We are drilling those three pads that we've talked about that are kind of on the difference between maintenance and growth capital.

You also have some capital. Our maintenance case just to remind everyone is $1 billion, our growth is $1.2 billion of capital this year.

Right now, we're probably somewhere a bit north of $1 billion, but not to the $1.2. A lot of that will be completion capital in the fourth quarter, and that's yet to be determined whether we deploy that.

We've said in the past, you get $3+ gas, that's probably something that we would deploy, but we'll just have to determine that when we get there.

Okay. If you complete those wells, that takes '27, would imagine, 4.4, 4.6?

Okay. Thanks, Mike.

Then maybe just a follow-up, curious on the cost optimization plan, the 35 cents reduction in realizations obviously being offset by the big move lower on the cost side. Just how dynamic is that plan?

Just curious how much flexibility will you have as 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 re-contracting into lower market rates?

Some of that's in-basin pricing around the dry gas, but the majority of it is just the optimization of our firm transport. I was trying to hit in the comments, it's definitely coming from the end users, it's a demand pull, and so when we came out with this cost presentation and strategy a couple months back, we received so many reverse inquiries along our firm transport paths, and Justin hit on that slide too, all 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.

That's something we're looking at, and you kind of saw the first sign of that with our guidance, how we reduced our cash costs, also reduced the realized price, but we're hopeful that we'll actually do better than that, just getting premiums along that path instead of just having the end user hold that transport.

Got it. That makes sense.

Thanks, guys.

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 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 3 years.

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

That's great. 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 have the opportunity to sell more gas in-basin, just rough numbers, how do you see that mix sort of changing versus if we call it kind of 2/3 kind of out-of-basin at the moment?

Just how do you see that evolving over the next several years?

Right now we're kind of thinking a third was FT long-haul, a third's liquids, and a third is generally local sales. If you just put that in natural gas terms, it's about 50/50.

The word we'd like to use, you hear the balance, we want to be balanced, we want to be a balanced natural gas liquids producer, we also want to be a balanced seller of the natural gas, about half on the long-haul transport and half local.

That's great. Appreciate it.

Mhm.

Good morning team. Mike, 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 through the integration of HG, but give us a sense of how that will play out over the next couple of years. 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.

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 cents uplift or 4 cents improvement on the cost structure, that's $60 million.

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, think about that's more ratable. Then the $105 million of target on liquids, that's year-end '28.

Got it. Right, and then my follow-up, Mike, clearly one of the themes from today's earnings is your commentary that the business for large, scale-y natural gas liquids producers will be more driven by kind of demand pull, versus just being a traditional E&P price taker.

I was wondering if you could comment on how you think Antero is positioned for this kind of, call it, shift in market dynamics.

We're extremely well-positioned. Go back 15 years, and we were trying to create markets.

There was no local gas market, we had to sign up for all the firm transport that came our way. Those are expiring now, now we get to pick the best ones.

Some of it ended up in terrific markets, some of it didn't end up as well as we had hoped. We'll be able to compare those now to the local demand, it's perfect timing for us.

That's why in the comments, those opportunities are going to have to compete with the broader energy markets, cuz those LNG buyers are really kind of international, there's an arb there, and our strategy has been to remain on spot there, we haven't entered into any firm agreements with that price. Then local's going to have to compete with that.

That's why we're highly selective. You're going to see a bunch of announcements that along the way we're not participating in, and you can be assured that's because our opportunity set's greater than what those opportunities were.

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.

Mhm.

thanks, guys. I appreciate you having me on.

Brendan, this is maybe for you, but in your deck, you're walking through pretty clearly the reduction or the planned reduction in cash costs. Now, I think it's been beaten pretty well this morning.

My question is why are you, Hold on 1 second. Why are you offsetting that with price realizations?

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

Sorry. I didn't hear that last part, Doug.

Could you repeat that?

Sorry. Someone was 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.

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 35 cents of margin. They're taking on the transport to move it, but they're giving you a premium on the price versus what you otherwise would have sold if you were just selling in-basin.

Cost coming down 70 cents, offset by realizations coming down by about half. Your margin still are getting picked up by 35 cents overall.

We're quite enthused by what we're seeing on the demand pull, like Mike mentioned. This market where it used to be we have to find a place for your gas, it's now become, "Hey, can you deliver us 300 million a day in this area?

Can you deliver us 200 million a day in this area? We need by this period of time."

We have to weigh that against our firm transport, what is the cost to get you there. You have to take on that cost or you can pick this back up in-basin and you can take on that cost.

All of these factor into our decisions, but they're all should lead to margin improvement on our natural gas in a big, big way.

I appreciate that color. Thanks.

My follow-up is a quick one, hopefully. Obviously you've drilled your first dry gas pads in quite a while.

You haven't completed them, obviously, but whether we end up with a squishy winter or not, what's the kind of road map to whether you would go back to growth in 2027?

Oh, we have two pads in there, three. We put our first one, the Flanagan pad, that Brendan reviewed the results.

The next two are Katie and Walters right next to it. They'll be drilling.

Whether we complete them, like you mentioned, will be natural gas price dependent. I fully anticipate completing them if it's $3 gas plus, and we can hedge that, and also hedge kind of local basis at very attractive levels.

Right now, based on those markets that we're looking at, you would assume that those would be completed. 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.

Mhm.

Good morning. I want to start with a follow-up to Arun's question about costs.

There's many drivers lowering that GP&T over time. Could you just unpack how much of that reduction is coming from a shift towards the HG dry gas assets, whether that's the wells are getting better and just shifting to HG, and how much of it is further dry gas growth above and beyond the base level?

It's

50% is HG, it's or $50 million this year's, I should say, is HG. HG is outperformed our expectations, definitely.

Two of the three rigs that we have running right now, the fourth's in transit, but two of the three are on HG pads, one of them goes to liquids, one of them's a dry gas. Incrementally, HG is outperforming, it will have more production than we assumed, there's a little bit of that.

It's not terribly material. We do sell the majority of those volumes in-basin, those will have lower transport costs associated with them.

That does impact it a bit, but the majority of it is just the shift, like we've said, to demand pull and shift to just some dry gas development, also with those transactions expiring.

If you look at that $300 million that we've laid out there, too, Betty, I think two about $250 million of that, 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 to more dry gas in HG.

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

I think on the GP&T for us, like we said, the $300 million, just to break it down, we've got 35 cents of margin improvement, $300 million is about 20 cents, the other 15 cents comes from HG. So 35 cents of margin improvement, 20 the 20 cents is in 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 costs.

Almost all of that 70 cents reduction is going to come in the form of GP&T coming down. That's the driver.

Processing costs will be lower, transport costs will be lower, gathering will stay the same to the AM on that front, but everything else will be lower.

Got it. Thank you.

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

Mike talked about it, you'll likely go from what today is 2/3, call it 2/3, 1/3, in terms of 2/3 going to the LNG fairway, a third going elsewhere, you'll have that be more 50/50 on a go-forward basis. Got it.

Thank you.

That'll take some time to play out, though. That'll be over, call it, a 5-year period for that to play out.

Got it. Thanks.

Thanks. Good morning.

I know Antero Midstream has a separate call, but was hoping you could talk about the East Side Express pipeline, which is the first intrastate regional line. Just how does this benefit Antero, and just confidence in executing a project like this?

Then just separately, just what's the interest in difficulties in building an interstate pipeline team, just taking shorter distances like West Virginia to Ohio, for instance, where there should be strong demand pull in the future?

No, we're super excited about that. That goes hand-in-glove with these acquisitions that we just did, consolidating the dry gas area of our play, 1,000 locations that Brendan talked about.

This is our first regional pipeline, east-west, that will cover approximately over 30 mi of our acreage position in the dry gas window, extend all the way across it. Antero Midstream is the industrial builder of northern West Virginia and now has the balance sheet, the credit, the strength, the expertise to build there over a decade.

Maybe a decade ago we farmed this out. Everyone's kind of familiar with that Stonewall pipeline, that's one 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.

Antero Resources acreage position and strength and investment grade goes with that over 1,000 or million acres, 1,000 of these dry gas locations. This'll go straight across it, and we hope to build more of those at Antero Midstream, and for Antero Resources to benefit off that.

Building maybe the next 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 interconnect this million-acre position in the tier one Marcellus with all the demand that's been publicized.

Antero Midstream will be the pipeline to build it, and we will not farm those type of opportunities out anymore.

Great. Then Antero has also always been a leader in realizations for your products, whether it's gas or C3+.

We have seen peers increase their focus on the marketing side of late, one with a large acquisition. Just when you look at what they're doing, is that something that could make sense for Antero to pursue just as less of the dry gas volume in the future is committed, and if so, how do you go about that?

We think we already have that. We've been the top 10 gas marketer in the U.S.

for the past decade. We're ahead of the game on that with our firm transport portfolio.

I think we have 28 paths that we market along. Also with our liquids, too, Dave and his team's been a leader in that.

First one signing up on ME2, pretty much signed up on every single project from an LPG or ethane standpoint, have been marketing around that. Really a market maker over on the Atlantic Basin side of the liquids marketing.

Feel really good about our position there ahead of the game, and so now others are kind of getting into that monetization of the product being a very important part of the business. We were there over a decade ago.

Sounds good. Thanks.

Mhm.

Morning, team, and thanks for taking my question. I just wanted to ask on hedging.

Going into 2027, just curious how your team is approaching the right hedging levels for next year and if there's anything you're seeing in the macro setup for '27 that would change your hedging approach year-over-year based off the 60% levels we saw in 2026?

We're in a good position. We're actually ahead of where we were this time last year for '27.

We got 34% hedged. I think it's a Bcf at $3.84, and then maybe 100 million a day of collars with a $3.50 by $4.50.

We said before we like the 25% swaps and 25% collars, but that's if those are attractive levels with a lot of call skew. 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, we're not going to be rushing into down markets.

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, you saw an increase in our volumes there, hedge volumes by, I believe, around 100 million a day in '26 and 80 million in '27.

When we do acquisitions, we will hedge them, just like we did these couple of acquisitions we did in July.

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

It does. We have a lot of non-op working interest entities out in our basin.

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.

As part of the transaction, we want to buy in as much working interests 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. Gross being flat, but Antero owning more and more of that, the interest in that production.

Then obviously consolidating the acreage around the East Side Express, that's where this acreage was, 15 locations, a couple pads, right on that East Side Express, so that was very attractive to us. We continue to see these type of opportunities and we'll continue to look at them.

Generally, it's kind of been around when gas prices go lower, we feel more comfortable and we can hedge out and take advantage of the contango in the future, and then know exactly when we'll develop the pads and take advantage of those type of valuations.

Thanks, guys. Mhm.

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?

Do you think there could be more upside to that number over time?

There will be more upside. It's still at that $80 million level.

That's not capturing what I mentioned earlier in my remarks. We actually have two rigs of our three on the HG acreage, that's well ahead of schedule.

We were contemplating when we underwrote the transaction just one rig. 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'll be elevated pricing. That's all entered into the decision, and obviously the well results are terrific.

We're going to put on the second set of wells from that 1221 pad on August 17th. Those continue to outperform the 1221 North.

We'll continue to update that number, but just for 2026, the $80 million is pretty much locked in, but that will go higher in '27 as we put these new pads on.

I appreciate that. In terms of the gas price environment, clearly it's relatively weak right now.

I guess we're not too far off from the shoulder season. Are you guys thinking about maybe pushing some of your turn-in-lines kind of over to the winter when pricing is better?

Just any thought is just trying to kind of manage production a bit to kind of match price here?

I'm glad you brought that up. That's actually the curtailments that we outlined, that's a new feature for Antero.

We talked about the cost structure coming down, but we also have a slide out in our deck that showed the commitments coming down quite dramatically, and a lot of those commitments around the MVCs on the liquids. We now have flexibility to look at our lean pads kind of in that 1150, 1160 BTU, and we don't have to produce them where in years past we would have because there would have been MVCs with them.

We now have ultimate flexibility, so that's a new feature that we're excited about. The ability just forecast, "Hey, look, September could be weak," we mentioned it's under $2.

Let's have curtailments on those wells and bring them on more into November, December timeframe when the prices are higher. We very much have that flexibility now, and that's something positive for us, we're excited about that.

That's kind of basically baked into the guidance that you've laid out here on 3Q?

We're hopeful to continue to kind of add and build these to take advantage of those opportunities.

Thank you.

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?

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?

No, it was a terrific result for us. This 2,000 lb of sand in the 830-acre spacing is what we traditionally done in the liquids, that's what we've done kind of our go-to for the last 10 years in the liquids.

We can play with that spacing. I know on the HG dry gas pads, we're going 1,000, 1,250 interlaterals and going up to 2,500 to 3,500 lb of sand, and the water going in between 35 barrels per foot and 50 barrels per foot, there's a lot of optimization to occur.

To have a 2,000 lb, 830 interlateral spacing and have it be over 2 Bcf per 1,000 was a terrific result for us. The lateral length just adds actually to the economics, brings that dollar per foot on the CapEx, that 13,500, you're increasing proppant by 2.5 times, and your well cost is down 30%.

That's a lot of that's lateral length as well, and drilling times and completion times. Feel really good about that.

We have 1,000 locations. Greater than 2 Bcf, we probably would have had those in our database at 1.8 to 1.9, above 2 Bcf is a terrific result for us.

I appreciate that color. For my follow-up, on the lateral of more than 24,000 ft, how do the economics compare with your current average lateral?

Excluding lease geometry, are there any practical limits to extend laterals beyond that?

No, we just drilled that, we haven't put that on yet. That's actually on an HG pad on our 1204 North pad.

That's six wells, average about 19,000 per well. Those will 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. That's something we're interested in.

We're going to try to replicate that with two different rows in our dry gas, do the exact same thing. We have no limitations right now.

I think you'll see the lateral lengths continue to just go longer and longer.

Makes sense. Thanks, guys.

Mhm.

Hey, Mike. I wanted to confirm a couple of things.

Pro forma for everything, the acquisition, the cost reductions, is maintenance CapEx still at that $1 billion? Is the hurdle price for Henry Hub $3?

I don't know about the second part, but the first part is correct. It's still $1 billion.

Subash, I didn't catch it the second part of your question.

The second part is, is $3 sort of the hurdle

rate? That would have been at the beginning of the year, but 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 barrels at $45, Dave's confirming that, so that's good.

Currently this morning, we're at $45 a barrel, so that would put that a bit lower. Our liquids development's really kind of more in a steady state, the maintenance.

The true kind of growth capital's more around the dry gas, $3 is probably a good number to think about.

Great. The follow-up on HG, if you look at it this way, but it's a second rig, are you still drilling the PUDs out?

Have you gotten into some of maybe the 2P that you thought you might have acquired in the acquisition?

On the 1204 and 1217 pad, the 1217's been elevated. All of them, I think, were in the proved.

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. Right now, those have been improved, but '27 drilling we'll get some of the 2P into the portfolio.

Great. Thank you.

Mhm.

Thank you. Good morning, all.

Thanks for taking the call. Just a quick one circling back on curtailments.

You just talked about the coming quarter kind of already being baked into guidance. I guess as we think about the kind of the contract optimization you talked about, how should we think about, I guess, your willingness or ability to do so or to a greater degree over time?

Or is this kind of the level you expect to stay at, this level of modulation?

We'll see. Right now we do have some legacy pads in that 1150, 1160, 1170 BTU range that generally are uneconomic if you're around that $1.75, $1.50 to $1.75.

Those are about the only pads where we have it kind of in that lean gas area right now. 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 MVCs on it, but we no longer have those MVCs. That's about all we have right now.

The rest is either 1200+ BTU or sub-1100 BTU, those really wouldn't qualify for this curtailment strategy.

Got it. Makes perfect sense.

Then you just talked about a shift in kind of your production cadence through time. How reactive do you see yourself being in coming years, given I guess the demand-pull scenario from a kind of is how much variability from that kind of 50/50 split between gas and liquids?

We generally have a gross maintenance program, we want to own more percent of it, but keep the gross volumes. Obviously, if there's incremental projects that come along in-basin locally that doesn't really need our transport, we could potentially grow into those.

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.

Understood. Appreciate the clarity.

I'll leave it there.

Yep.

Yes, hi. Good morning, and thanks for squeezing me in.

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

We think a lot about it, actually. That's one of 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.

We think a lot about that. If we do deals and the credit needs to be there, you'll see us get LCs or some sort of credit assurance.

We're not credit agnostic. We have a big credit team just around already having significant firm transport for over a decade.

We're very cognizant of credit, and the credibility and the execution of the project really goes into whether or not we participate.

Understood. Then one clarification on your savings slide that you had, 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. Is that correct?

I presume that $105 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 could think about is the ATEX, that's the one that we always cite. That's, I think, $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, obviously we're not going to sign up for that.

We had to do it a decade ago just to get our gas in spec, but since that time, a lot of markets have been developed around the Shell, ME2, Mariner East, Utopia, a lot of different ethane markets have been developed over that time frame, 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, we can easily let that 20,000 ethane go and be within spec, and it's completely uneconomic, so that's $60 million of the 105. The rest is just optimizing our already transport that expires at the end of '28.

Then

the other piece that Mike had mentioned earlier there, too, is beyond 2028, which is not on that slide, is when you have a lot of the 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.

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.