Prepared remarks
Greetings, and welcome to the Antero Resources Corporation Second Quarter 2026 Earnings Call. At this time, participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce Daniel Philip 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 will spend a few minutes going through the financial and operating highlights, and then we will 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 N. Kennedy, CEO and President; Brendan E. Krueger, CFO; David Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing.
Thank you, Daniel, and good morning, everyone. I will 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. 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 4 titled Significant Reduction in Cash Costs. The cost reductions we realized during the second quarter were 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% 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 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 direct 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. A $0.70 improvement in our cash costs will be partially offset by $0.35 in lower price realizations as we sell more product in-basin. This assumes strip pricing for in-basin differentials without any tightening of the basin 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 have two financial transactions that we entered into earlier 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, 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 2027 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 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 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 am going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, David Cannelongo, for his comments.
Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing 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, 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 per day during the second quarter of 2026, an increase of 170 thousand barrels per day compared to the same period last year. Additionally, propane exports hit a new weekly high of 2.63 million barrels per day this May, with another weekly export number also above 2.6 million barrels per day reached in July, according to the EIA. These new highs surpassed the previous record by 300 thousand barrels per 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 thousand barrels per day in April, the most recent month of EIA data, surpassing the previous record of 661 thousand barrels per day set in March. The record levels achieved for both LPG products since the start of Epic Fury illustrate that propane and butane are fiercely competing for terminal space to backfill lost Middle East supply across demand markets worldwide. Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels per day of 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. The Middle East supply remains curtailed and uncertain. China's LPG imports from the U.S. declined last year following the initial imposition of additional U.S. tariffs but have rebounded recently due to disruptions in Middle East supplies. U.S. LPG market share in China has risen from a low of 10% in June 2025 to an average of 51% during the second quarter of this year, according to third-party shipping data—levels not seen since before Liberation Day. 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, and 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 prices. As the nation's second largest NGL producer and the largest producer exporter, while also remaining largely unhedged on NGLs, Antero is poised to benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing. With that, I will now turn it over to our Senior Vice President of Gas Marketing, Justin Fowler, for his comments.
Thanks, David. I will start on Slide 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 per day; 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 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 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 per day demand to our regional profile. We have 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 per day 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 advantaged 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 E. 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 per 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 equivalent per day and add 15 net drilling locations. I will discuss both of these updates in more detail momentarily. Turning to our financial results, on the right-hand side of the slide, our adjusted EBITDA 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 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 thousand to over 2 Bcf per thousand. On the right, you can see the 90-day cumulative production rates which increased more than three times. 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 Western Virginia Marcellus footprint. These transactions immediately add 125 MMcf per day of net production and were acquired at a combined valuation of just 4x EBITDA and a free cash flow yield over 20%. The chart on the right illustrates how our net production has increased from 3.3 Bcfe per day at the beginning of 2025 to an expected 2026 exit rate of 4.5 Bcfe per 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 has remained essentially flat at 35.5 Bcf per day over that time period. To emphasize a point that we have 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.
Questions and answers
Thank you. And at this time, we will conduct our question-and-answer session. Our first question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question.
Hey, good morning and thanks for taking my question. There has been some activity in your neck of the woods in recent power deals and talk of data centers. Obviously, you are the dominant producer in West Virginia. You touched a little bit on this in 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 it in our remarks. Right now we think about how 10 to 15 years ago we signed up for all the firm transport arrangements just to get our gas out. Now we are at the end of that and we can select the best paths, and those paths are competing with the power deals. So it has to compete with the broader energy markets. The one that was recently in our backyard, we have been in discussions with them for almost a decade, so we are well aware of that one. They actually have a contract on some of our midstream. In discussions with them, the uncertainty around price, timing, and execution did not meet our return hurdles. So when we look at projects, they have to meet all three: price, timing, and execution, and that one just was not 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 from the coming years. With the stock in the 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 were not planning on buying back shares in the quarter, but the equity price 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 the share price is the same as last year. So I would say that you could elevate the ranking of buybacks; it is very attractive to us at these levels. Appreciate it, thanks.
Your next question comes from Truist. Please state your question.
Good morning. I was hoping we could maybe just touch on the growth CapEx and how we should be thinking about that impacting 2026. It looks like you are at four rigs currently, maybe putting some of that growth capital to work. Could we get an update there?
We are at four rigs; one is in transition, so it will be down to three here in the next month. We are drilling those three pads that we talked about, and they are kind of on the difference between maintenance and growth capital. To remind everyone, our maintenance case was $1 billion and our growth target was $1.2 billion of capital this year. Right now, we are 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 it is yet to be determined whether we deploy that. We have said in the past that $3-plus gas is probably something that would prompt deployment, but we will determine that when we get there.
If you complete those wells, then that pushes it into 2027, I imagine.
Yes, correct. The completions would push the timing and likely impact 2027 volumes.
Maybe a follow-up: curious on the cost optimization plan, the $0.35 reduction in realizations obviously being offset by the big move lower on the cost side. How dynamic is that plan? How much flexibility will you have as we progress through 2027 if in-basin pricing does not materialize as you expect? Would you keep some of that firm transport, or would you recontract into lower market rates?
Some of that impact is in-basin pricing around the dry gas, but the majority of it is just the optimization of our firm transport. We indicated that when we came out with this cost presentation and strategy a couple months back, we received many reverse inquiries along our firm transport paths. Justin touched on that as well; a lot of those seven Bcf of demand are reaching out to optimize that transport and put it in their hands, but also pay a premium to us, which is baked into the $300 million we have been discussing. That would be incremental. You saw the first sign of that with our guidance, where we reduced our cash costs and also reduced the realized price, but we are hopeful we will actually do better than that by capturing premiums along the transport path instead of the end user holding that transport.
Got it. Thanks, guys.
Your next question comes from John Freeman with Raymond James. Please state your question.
Following up on the $300 million of margin enhancement you first unveiled last month: just to clarify, if that was extended a few years beyond the 2028 target, is it safe to say that $300 million would move materially higher if you extended the timeline?
Absolutely. We focused on a three-year horizon initially. If you look out five years, I think that broader view drives growth of about $600 to $700 million in total opportunities.
As you see this play out with data center and power projects over the next several years and you have the opportunity to sell more gas in-basin, how do you see that mix changing versus today where roughly two-thirds is out-of-basin? How do you see that evolving over the next several years?
Right now, we are thinking roughly one-third long-haul firm transport, one-third liquids, and one-third local sales. Put another way, about 50-50 in natural gas terms between long-haul and local. We want to be balanced: a balanced natural gas and liquids producer, about half on long-haul transport and half local. That balance may evolve over time as projects come online.
Your next question comes from Arun Jayaram with JPMorgan. Please state your question.
Good morning. Mike, could you talk us through the timing of further reaching your cost reduction target of $0.70 per Mcfe? It sounds like you are halfway or nearly halfway there with the integration of HG Energy. Give us a sense of how that will play out over the next couple years and where your cash operating costs could be in calendar 2027 as you move toward the $2 target at year-end 2028.
We laid this out in three buckets with timing. The first is the override, which starts immediately—July—resulting in a $60 million uplift, about $0.04 improvement on the cost structure. The VPP lifts $30 million in July 2027. The optimization of our natural gas firm transport is the harder-to-predict element, but we are in significant negotiations and expect that to be ratable over time. The $105 million of liquids improvements is targeted to be realized by year-end 2028.
My follow-up: one theme is the market shifting to demand-pull versus being a price taker. How is Antero positioned for that shift in market dynamics?
We are extremely well positioned. Fifteen years ago we were creating markets and had to sign up for firm transport to get gas out. Those commitments are expiring now, so we can pick the best ones. Some of those contracts ended up in terrific markets; some did not. Now we can compare those contracts to local demand, and local projects must compete with the broader energy markets because LNG buyers and international buyers are often willing to pay premiums. Our strategy has been to remain on the spot where appropriate and be highly selective with local projects. Opportunities must be near term, price-certain, and compete with our firm transport and liquids production before we participate.
Your next question comes from Doug Leggate with Wolfe Research. Please state your question.
Thanks. Brendan, this is for you. In your deck you walk through the planned reduction in cash cost, which has been beat by results this morning. Why are you offsetting that with price realizations? I'm trying to understand what this implies for your market view of gas going forward.
It ties back to our earlier discussion: the market is moving from producer-push to demand-pull. Sometimes that means buyers will take product in-basin at a lower realized price, but from a margin standpoint, you pick up optimization benefits and premiums on transport and contracts. So the cost improvement we forecast is $0.70 per Mcfe, partially offset by an assumed $0.35 decrease in realized price because of in-basin sales. Even with that, margins still improve by about $0.35 overall. We are enthused by demand-pull dynamics—projects are reaching out to secure supply and timing, which should lead to margin improvement for natural gas.
Quick follow-up: you drilled your first dry gas pad in quite a while and haven't completed them yet. Regardless of winter strength, what's the roadmap to returning to growth in 2027?
We have two additional pads in that area—Katy and Walters—adjacent to the Flanagan results Brendan reviewed. Whether we complete them will be natural-gas-price dependent. I fully anticipate completing them if we see $3 gas plus, and we can hedge that and local basis at attractive levels. If there is a significant downside move in 2027 gas, then we will defer completions. So the decision will be market-driven.
Your next question comes from Barclays. Please state your question.
Good morning. A follow-up on costs: the GP&T piece has many drivers lowering it over time. Could you unpack how much of the reduction is coming from a shift toward the HG dry gas assets versus how much is from further dry gas growth beyond the base level?
HG has outperformed expectations—over $50 million of incremental benefit this year from HG outperforming. Two of the three rigs running right now are on HG acreage. HG volumes are selling in-basin, which reduces transport costs. But the majority of the expected GP&T improvements are from the broader shift to demand-pull and optimization of firm transport alongside increased dry gas development and the expiration of certain transactions.
To quantify, of the $300 million we laid out, about $250 million is from the liquid transactions, the VPP, the override, and about half of the gas optimization is driven by pure optimization. The roughly $50 million Mike mentioned of the $300 million is driven by the shift to more dry gas and HG. On a per-unit basis, the $0.35 of margin improvement is roughly $0.20 from the $300 million items and $0.15 from HG. Almost all of the $0.70 reduction in costs will come through GP&T declines—processing and transport costs will be lower; gathering will remain roughly the same.
Thanks. One more quick question: how much does your in-basin exposure grow over the next few years from the roughly 20% currently?
Today the split is roughly two-thirds to the LNG fairway and one-third elsewhere. Over time, we expect that to move more to about 50-50, but that will take some time—call it a five-year period for that to play out.
Your next question comes from Phillip Jungwirth with BMO. Please state your question.
Good morning. I know Antero Midstream has a separate call, but could you talk about the Eastside Express pipeline, the first intrastate regional line? How does this benefit Antero and what's your confidence in executing a project like this? Separately, what's the interest and difficulty in building intrastate pipelines—shorter distances, West Virginia to Ohio for example—where there should be strong demand pull?
We are very excited about that. The Eastside Express goes hand in glove with the acquisitions we just completed, consolidating the dry gas area of our play. This is our first regional east-west pipeline covering approximately over 30 miles of our acreage in the dry gas window, extending across it. Antero Midstream is the industrial builder of Northern West Virginia; it now has the balance sheet, credit, and expertise to build regional pipelines. A decade ago we farmed projects out because we did not have the ability to execute; that is no longer the case. We are now the builder of these regional pipelines in West Virginia. Antero Resources' acreage position and investment-grade strength—over 1 million acres and 1,000 dry gas locations—means this pipeline will directly serve a large portion of our dry gas window. We hope to build more regional pipelines and interconnect our acreage to demand centers and long-haul pipes. Antero Midstream will be the pipeline builder; we will not farm those types of opportunities out anymore.
Antero has been a leader in realizations for gas and C3+. Peers have increased focus on marketing recently. Is pursuing a larger marketing or monetization business something that makes sense for Antero as less dry gas volume is committed? If so, how would you pursue that?
We believe we already have a strong marketing position. We've been a top-10 gas marketer in the U.S. for the past decade and have an extensive firm transport portfolio. We market significant volumes along our 28 transport paths, and David's liquids marketing team has been a market maker in the Atlantic Basin for LPG and ethane. We feel very good about our position; we were ahead of the curve a decade ago and continue to have strong marketing capability.
Your next question comes from Jacob Roberts with Goldman Sachs. Please state your question.
Good morning. On hedging for 2027, how is your team approaching hedge levels for next year and is there anything in the macro setup for 2027 that would change your hedging approach year over year given the 60% levels we saw in 2026?
We are in a good position and actually ahead of where we were this time last year for 2027. We have about 34% hedged: roughly 1 Bcf at a $3.84 swap equivalent and then collars in the $3.50 to $4.50 range. We have historically favored 25% swaps and 25% collars, but with call skews in collars, we've been favoring more swaps of late. You will see us increase hedges over time, but we won't rush into down markets. When we do acquisitions, we hedge the incremental volumes, as we did with the July acquisitions; those volumes were hedged into 2026 and 2027.
Regarding the $315 million Western Virginia property acquisitions, how do you see the near-term opportunity set for incremental bolt-ons around your core footprint? Is the macro impacting the number of opportunities you're seeing?
We see many non-op working interest entities in our basin with acreage they aren't operating. We often acquire both working interest and surrounding acreage in bolt-ons. Our strategy includes increasing our percentage ownership of gross production—gross has been flat while Antero's share has risen—and consolidating acreage around projects like Eastside Express. Opportunities do exist and tend to pick up when gas prices are lower and we can hedge and lock in future values strategically.
Your next question comes from Leo Mariani with ROTH Capital. Please state your question.
Hi. Could you give an update on HG? Last quarter you bumped up synergy targets—how much of the synergies have you captured thus far in 2026 and is there upside to that number over time?
There will be upside. The synergy target remains at $80 million, but that doesn't capture the incremental benefits we mentioned earlier. We have two rigs of three on HG acreage now, well ahead of schedule—when we underwrote the deal we assumed one rig. That accelerates HG volumes and the value to us. HG has pad-ready locations and existing infrastructure that allow us to bring volumes into local gas markets, especially in winter. Well results have been terrific. For 2026, the $80 million is largely locked in, and we expect the benefit to increase in 2027 as we bring additional pads online.
Given the relatively weak gas price environment approaching shoulder season, are you thinking about pushing some turn-in-lines to winter when pricing could be better? How do you manage production timing?
Yes, that's addressed via curtailments—a new feature for Antero. We outlined commitments declining dramatically and gained flexibility. Many legacy pads in the 61-71 Btu range that in the past we'd have to produce due to MVCs no longer have those MVCs, giving us the option to curtail. That allows us to delay lower-Btu production into higher-priced winter months if needed. So we have the flexibility now to manage timing and volume to take advantage of price seasonality.
Your next question comes from John Abbott with Texas Capital. Please state your question.
Good morning. Looking at Slide 13, can you help break down what drove the improvement in the dry gas well results? How much came from completion design, longer laterals, better targeting versus other factors? Given this was the first dry gas pad in more than a decade, how much more room is there for further improvement as you apply learnings to future pads?
The result was excellent. The 2,000 pounds per foot proppant and 38-acre spacing are similar to our liquids design, and to achieve over 2 Bcf per thousand at that design was terrific. Lateral length increases and higher sand intensity helped greatly, and cost per foot declined 28% as drilling and completion efficiencies improved. On HG pads, we are testing 1,060-foot interwell spacing and raising proppant to 2.5 thousand to 3.5 thousand pounds per foot with water rates of 35 to 50 barrels per foot—so further optimization is possible. These longer laterals add to economics by lowering dollar-per-foot CapEx through efficiencies. We feel very comfortable there's room for continued improvement as we replicate successful designs.
On laterals of more than 24 thousand feet, how do the economics compare with your current average lateral and are there limits to extending laterals beyond that?
We just drilled a long lateral on an HG pad, averaging about 19 thousand feet per well across six wells. We haven't turned those results to sales yet, but the plan is to replicate that approach—two rows with longer laterals to maintain a strong production profile over a longer plateau. We don't see operational limits at the moment; laterals are likely to continue to get longer as planning and infrastructure permit.
Next question comes from Stonex. Please state your question.
Hi, Mike. A couple confirmations: pro forma for acquisitions and cost reductions, is maintenance CapEx still $1 billion? And is the growth hurdle price for Henry Hub $3?
Yes, maintenance CapEx is still $1 billion.
On the growth hurdle, $3 Henry Hub is a reasonable mid-cycle number to consider, though actual decisions depend on liquids prices as well. In a mid-cycle case with $35 to $40 NGL realized price, $3 is a useful guide. Today our NGL realized price is about $45 per barrel, so liquids economics influence development decisions significantly. Overall, liquids development is more steady-state maintenance and true growth capital is driven by dry gas economics.
Follow-up on HG: are you still drilling the PUDs out and have you moved into the 2P category you anticipated acquiring? For instance, is the 1,200 and 17 pad schedule impacted?
On the 1,220 and 17 pads, results have improved. Some items that would have been in 2P are being accelerated based on well performance. The 1,200 pad is on the schedule for 2027 but better-than-expected results are allowing us to consider earlier development of some locations. The 2027 drilling program will convert some of the 2P into proved categories as we execute.
Your next question comes from Paul Diamond with Citi. Please state your question.
Thanks. Circling back on curtailments: you talked about coming-quarter curtailments being baked into guidance. How should we think about willingness or ability to curtail to a greater degree over time? Is this the level you expect to stay at?
Right now, the main pads we could curtail are legacy lean-gas pads in the 61-71 Btu range. That represents about 50 MMcf per day of pads where production in the past would have been required due to MVCs; we no longer have those MVCs. The rest of our inventory is either higher Btu or more valuable liquids-rich acreage that we would continue to produce. So the curtailment flexibility exists primarily for that lean portion and we will use it opportunistically to manage prices and timing.
Thanks. Also, how reactive do you see yourself being in coming years given demand-pull variability and the move to a 50-50 mix between dry gas and liquids?
We plan to run a steady-state program: a three-rig program with two completion crews and continue increasing our ownership percentage of gross production. That keeps gross basin volumes essentially flat while Antero's share grows. If incremental in-basin projects appear that don't require long-haul transport, we could scale, but our base plan is to be measured and to prioritize returns and risk-adjusted decisions.
Your next question comes from Nitin Kumar with Mizuho Securities. Please state your question.
Good morning. When you think about your gas sales shifting more to in-basin demand, how do you think about counterparty risk versus selling into more liquid markets?
Counterparty risk is central to our risk-adjusted decisions. Price is one parameter, but timing and execution tied to counterparty credit are critical. We think a lot about credit; we will require letters of credit or other assurances if necessary. We are not credit agnostic; the credibility of a project is a major determinant in whether we participate.
One clarification: on the savings slide you talked about $105 million of contract rollovers—was that tied to a 2028 timeline and split among several contracts? Could you elaborate?
Yes, that's correct. A major component is the ATEX ethane commitment, which represents about $60 million of the $105 million. That commitment dates back to when we needed to meet an ethane spec; with markets and infrastructure developed since then, we can let roughly 20 thousand barrels of ethane go and remain in spec, making that commitment uneconomic. The rest of the $105 million is optimization of transport that expires around the end of 2028. Beyond 2028, we see further opportunity where a significant portion of gas contract renewals could add another $200 million to the opportunity set beyond the $300 million discussed.
There are no further questions at this time. I will now hand the floor back to Daniel Philip Katzenberg for closing remarks.
I would like to thank everybody for joining us on the conference call this morning. If you have any follow-up questions, please reach out. Have a great day. Thank you.
Thank you. With that, we conclude today's call. All parties may disconnect.