Antero Resources Corporation (AR) Earnings Call Transcript & Summary

Greetings and welcome to the Antero Resources Corporation Second Quarter 2026 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce Dan Katzenberg, Vice President of Investor Relations. Thank you. You may begin.

Thank you for joining us for Antero's Second Quarter 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; and David CAnnelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike.

Thank you, Dan, and good morning, everyone. I'll start on Slide #3 titled Structural Margin improvement at Antero. This structural improvement has strengthened our financial performance and, importantly, reduced earnings volatility. The results of this strategy can be seen in the table on the right side of the slide, while Henry Hub natural gas prices were down 16% from a year ago, the impact of increased scale product diversity and lower cash operating expense led to our adjusted EBITDA increasing 57% over that period. The structural and sustainable improvements in our business will reduce volatility in our future cash flow. Staying on the topic of cost reductions, let's turn to Slide #4 titled Significant reduction in cash costs. The cost reductions we realized during the second quarter was just the beginning of a lower cost 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% in 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 and supply contract for our natural gas and NGLs. Next, on Slide #5, we provide details on our margin enhancement. The $0.70 improvement in our cash costs will be partially offset by $0.35 and lower price realizations as we sell more product in basin. This assumes strip pricing for in-basin differentials without any tightening of basis that could occur when regional demand starts to ramp up. In the chart on the right-hand side of the slide, we break out the $300 million of annual margin improvements in the 3 categories. First, we have 2 financial transactions that we entered into early this decade that come to an end. The overriding royalty interest transaction and the VPP. The overriding royalty interest transaction return threshold to the counterparty was met in the second quarter, leading to the Martica entity being dissolved on June 30, resulting in an increase of $60 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 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. And third, the remaining $105 million of margin improvements for '28 will primarily come to optimizing our natural gas firm transportation portfolio and increasing dry ad 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 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 lipids 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 #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 Epic Fury illustrate that propane and butane are fiercely competing for terminal space to backfill loss 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 to 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 date. Additionally, we are beginning to see a recovery in Chinese petrochemical demand for LPG as shown on Slide #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 #8 to discuss shipping dynamics. VLGC 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 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 -- fleet will increase by 31% or 138 ships. Given the imminent export expansions and new build terminals coming online, readership availability will facilitate more cargoes leaving the U.S. and continue to support Mont Belvieu prices. As the nation's second largest NGL producer and the largest producer exporter, while also remaining unhedged on NGLs and [indiscernible] 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 #9 that highlights the strong fundamental outlook for natural gas that we see through 2030. The 2 charts on this slide illustrate total U.S. demand growth. Based on data center and power projects that have been announced to date, natural gas demand is forecasted to increase 19 Bcf LNG and Mexico export growth adds another 23 Bcf per day of natural gas being growth by 2030. In combination, this represents 37% of total main growth for natural gas by the end of decade. While associated gas from the Permian will fill a portion of this demand growth through announced egress expansions, Higher prices will be required to incentivize growth from nontraditional gas basins and Tier 2 acreage with higher breakevens to ultimately meet this demand. . Now let's look at regional demand in our Appalachian Basin, which is highlighted on Slide #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've spoken to you to add an additional incremental 3 Bcf demand to our regional profile. We've shown this slide in the past, and each time the number of projects and implied regional demand estimate has increased. But what is exciting to us today is that we now have 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 #11, titled Gas Demand Competition. As Mike detailed earlier, Antero is in an advantaged position through our long-haul firm transportation capacity. This fund transports 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 increased 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 $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 and return to dry gas drilling. This slide compares our well design and production performance from when we last role on our dry gas acreage over 12 years ago. So 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 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 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 1/3. 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.

[Operator Instructions] And our first question comes from Kevin MacCurdy with Pickering Energy Partners.

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?

Yes. I think we touched on in remarks. I mean right now, we kind of think about how 10 to 15 years back, we signed up for all the firm transport arrangements just to get our gas out. Now we're at the end of that. And so we can select the best paths and those pads are competing with the power deals comparing them. So it has to compete with the broader energy markets. The one 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. They actually have a contract on some of our midstream. So in discussions with them, just the uncertainty around the pricing, the timing, the execution, all of that really didn't meet our return hurdles. So when we look at projects, it has to meet all of those 3, and that one just wasn't attractive to us.

Okay. I appreciate the details there. And as my follow-up, you were able to do some buybacks this quarter despite continuing to execute on the bolt-ons. We see a lot of free cash flow potential from Antero in the coming years. With the stock in the kind of mid-30s, are you ranking buybacks a little bit higher among your options for your cash flow?

Yes, definitely. You saw that in the quarter. We weren't planning on buying back shares in the quarter, but where the equity price went obviously very attractive to us I think you heard in Brendan's summary comments, production up 20%, cash costs down 10%. Liquids pricing up significantly. EBITDA up 57% when you look at 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 is very attractive to us at these levels.

Your next question comes from Dave Daoud with Truist.

It's Gabe from Truist. I was hoping we can maybe just touch on the growth CapEx and how we should be thinking about that impacting 2026. It looks like you're at 4 rigs currently, maybe already putting some of that growth capital to work. Could we maybe just get an update there?

Yes. So it's 4 ones in transition. So it will be down to 3 here in the next month. But we are drilling those 3 pads that we talked about that are kind of on the difference between maintenance and growth capital. So you also have some capital. So our maintenance case is to remind everyone what was $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 billion. A lot of that will be completion capital in the fourth quarter, and we still -- that's yet to be determined whether we deploy that. We said in the past, $3-plus gas. It's 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, would imagine [ 4 6 ]?

Yes. Yes.

Yes. Okay. Okay. And then maybe just a follow-up. Curious on the cost optimization plan, the $0.35 reduction in realization is 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 we progressed through '27 and maybe in basin pricing not really materialized to what you would expect. Would you just still keep some of that FTE or is that just simply the recontracting to lower market rates?

Yes. So 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 of 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 pads, 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 would be incremental. But that's something we're looking at. And you kind of saw the first sign of that with our guidance. 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 to hold that transport.

Your next question comes from John Freeman with Raymond James.

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 time line?

Absolutely. We just focused on 3 years. We thought that was kind of the investment horizon. If you're looking past that for the 5 years, I think it grows about $600 million to $700 million.

That's great. And then just follow up, Mike, as you sort of see this play out with the data centers, the power projects as they come online over the next several years? And you sort of start to move or have the opportunity to sell more gas in basin. Just like rough numbers, like how do you see that mix sort of changing versus if we call it kind of 2/3 kind of out of basin at the moment? Like just how do you see that evolving over the next several years?

Yes. Right now, we're kind of thinking 1/3 was FT long haul, 1/3 liquids and 1/3 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 you hear at 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.

Your next question comes from Arun Jayaram with JPMorgan.

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?

Yes. We put in the 3 buckets -- we put some timing around that. That first when we talked about the override that starts immediately that started in July, that's a $0.04 uplift or $0.04 improvement on the cost structure at $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 we're in significant negotiations around those type of improvements. So think about that as more ratable and then the $105 million at [indiscernible] liquids at year-end '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 scaling 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.

Yes, we're extremely well positioned. Go back 15 years, and we were trying to create markets. There was no local gas markets that had to sign up for all the firm transport that came our way. Those are expiring now. So now we get to pick the best ones. Some of it ended up in terrific markets. Some of it didn't end up as well as we had hoped. So we'll be able to compare those now to the local demand. So it's perfect timing for us. And that's why in the comments, those opportunities are going to have to compete with the broader energy markets because those LNG buyers are really in kind of international. There's an art 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 local is going to have to compete with that. That's why we're highly selective you're going to see a bunch of announcements that along the way, we are 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.

Your next question comes from Doug Leggate with Wolfe Research.

So Brendan, this is maybe for you. But in your deck, you're walking through pretty clearly the planned reduction in cash costs. I think it's been beating pretty well this morning. My question is, why are you -- hold a 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?

Yes, sorry, I didn't hear that last part. Doug, do you repeat that?

Sorry, some 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?

Yes. It just goes back to some of that same conversation Mike was having that the world is shifting from this producer push to demand pull. Sometimes what that means is they're willing to take your product in basin you'll, of course, have a lower realized price that they're buying in basin. But from a margin standpoint, you're picking up $0.35 of 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 costs 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 enthused by what we're seeing on the demand fall, like Mike mentioned, this market where it used to be you have to find a place of 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 or you can pick this back up in basin and then you can take on that cost. But all of these factor in to our decisions, but they're all -- should lead to margin improvement on our natural gas in a big, big way.

I appreciate that color. 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 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?

Go back. We have 2 pads in there. Well, we put our first one in planning and that the Brendan review the results the next 2 are DadinWalters 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 $3 gas plus, and we can hedge that and also hedge kind of local basis at very attractive levels. So right now, based on the 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, and we won't complete them in the fourth quarter.

Your next question comes from Betty Jiang with Barclays.

I want to start with a follow-up to Arun's question about costs. This GP&T pieces, there's many drivers lowering that GP&T over time. Could you just impact 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 HG. It's over $50 million this year, I should say, HG. HG has outperformed our expectations, definitely. 2 of the 3 rigs that we have running right now that force and transit, but 2 of the 3 are on HG pads. One of them, those liquids, one of them is a dry gas. So incrementally, HG is outperforming and will 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 a shift, like we said, to the demand pull and shift to just some dry gas development also with those transactions expiring.

Yes. If you look at that $300 million that we have laid out there to 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 that $300 million is really just driven by that kind of shift to order, I guess, in HG.

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

Well, I think on the GP&T front, 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 $0.35 of margin improvement. The $0.20 within 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 of that $0.70 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 I'll say the same to AM on that front, but everything else will be lower.

Got it. 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 [ '25 ] currently?

Yes. Mike talked about it. So you'll feel likely go from what today is 2/3, call it, 2/3, 1/3 in terms of 2/3 going to the LNG Fairway and 1/3 going elsewhere. You'll have that be more 50-50 on a go-forward basis. That will take some time to play out. That will be over, call it, a 5-year period for that to play out.