Antero Resources Corporation (AR) Q4 2025 Earnings Report, Transcript and Summary

Greetings, and welcome to the Antero Resources Corporation Fourth Quarter 2025 Earnings Call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the conference over to your host, Dan Katzenberg, Finance Director. Thank you. Please go ahead.

Thank you for joining us for Antero's Fourth Quarter 2025 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 our 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; and 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'd like to start my comments by recognizing the outstanding performance from both our upstream and midstream operation teams during the recent winter storm event. Despite subzero temperatures and significant snowfall, we did not experience any shut-in volumes during the period. In fact, our team was able to turn in line a 7-well pad during that time, a truly remarkable achievement by our people in the field, enabling Antero to deliver critical natural gas to the various regions that desperately needed it. In addition to navigating through the winter, we had a very successful last few months on other fronts. Last week, we announced the closing of the HG Energy acquisition, ahead of our original expectations. This acquisition, combined with the sale of our Ohio Utica asset, solidifies Antero as the premier natural gas and NGL producer in West Virginia. We're also excited that in January, we issued our inaugural investment-grade bonds. This offering provides substantial flexibility along with our free cash flow generation during this period that exceeded our initial expectations. Next, let's turn to Slide #3 titled Antero's Strategic Initiatives. Last quarter, we introduced our long-term vision and strategic initiatives. The HG acquisition marked significant progress towards all of the goals we highlighted. These include expanding our core Marcellus position in West Virginia. This transaction added 385,000 net acres and over 400 drilling locations, extending our core inventory life by 5 years, increasing our dry gas exposure. Our larger production and inventory base positions Antero to capture the significant demand opportunities from LNG exports in the Gulf Coast and data centers and natural gas-fired power plants regionally, adding hedges to lock in attractive free cash flow yields, providing high confidence in our free cash flow outlook over the next several years reducing our cash costs and expanding margins. The transaction lowers our cost structure by nearly 10%, assuming no changes to commodity prices and expands margins. This, in turn, lowers our peer-leading breakeven prices even further. Lastly, it highlights the benefits of Antero's integrated structure with Antero Midstream. 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. The NGL market faced various headwinds in 2025, but many of these issues were singular events or trends that are expected to improve over the coming quarters. When looking back on 2025, 3 main fundamental forces caused propane inventories to move higher than market expectations. Slide #4 titled U.S. Propane Stocks and Propane Days of Supply identifies these factors on the chart on the left. As we entered 2025, propane inventory levels were trending with the historic 5-year average. However, U.S. trade tensions with China and the resulting reshuffling of U.S. propane exports to different destinations impacted U.S. export volumes. Additionally, this tariff shakeup came at a time when export expansions and existing terminals in the Gulf Coast were facing start-up delays or operational issues. Importantly, the chart on the right hand of the slide highlights the demand pull that persisted in the propane market last year despite these identified headwinds. Days of supply in 2025 consistently trended within the 5-year range due to strong export and domestic demand. Turning to the supply side. While NGL supply is expected to continue to increase over the coming years, the rate of growth will likely moderate due to weaker oil prices. As shown on Slide #5 titled U.S. C3+ Supply Growth Slows, the chart on the left displays year-over-year U.S. supply growth decreasing from 328,000 barrels a day in 2024 to 131,000 barrels a day in 2026 and further to 45,000 barrels a day year-over-year in 2027. This deceleration is expected due to the lower oil price environment and the resulting reduction in oil-focused drilling activity, especially in the Permian Basin. This trend is likely to continue in the current WTI price environment. Turning to exports. Significant LPG export capacity expansion was added in 2025, and there is more to come in 2026, entirely removing any potential market bottlenecks. Slide #6 titled Timely In-Service Dates for LPG Export Expansions illustrates that LPG export capacity should be unconstrained through at least 2028, allowing U.S. barrels to continue to clear the market. Slide #7 illustrates the significant global NGL demand growth that is forecast for 2026. Following several years of declining demand growth, 2026 demand is expected to grow 563,000 barrels a day, the largest annual increase since 2021, driven by LPG increases in the steam crackers, rising PDH demand and annual ResComm growth. On the bottom of the slide, you can see the C3+ NGL price going back to 2021. Today, prices are above $35 per barrel, but with the backwardated strip, the annual average is $33.50 per barrel. To put pricing into context, a $5 move in C3+ NGL pricing equates to $225 million in annual free cash flow. All of these factors lead third-party analysts to forecast propane storage levels returning to within the normal 5-year range by the end of 2026, which should result in improving prices throughout the year. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Thanks, Dave. I'll start on Slide #8, which shows the winter-to-date residential and commercial demand. This winter, ResComm demand has been extremely strong with November through February averaging nearly 42 Bcf per day. This results in an incremental 350 Bcf of natural gas demand compared to the 5-year average and is over 1 Bcf above last year. Further, January demand averaged over 50 Bcf, ranking it at the third strongest January ResComm demand on record. January also saw the highest level of industrial natural gas demand on record dating back to 2005, which we believe to be in part related to the continued growth in behind-the-meter power demand for data centers. Turning to Slide #9 titled Natural Gas Storage. The result of this strong winter demand has been a dramatic flip in storage levels. At the start of the winter in November, storage was approximately 200 Bcf above the 5-year level. Today, we are approximately 140 Bcf below the 5-year level. This should result in exiting withdraw season below the 5-year average. Last year, we experienced mild summer demand, which drove storage levels to the high end of the 5-year range by the fall. We believe substantially higher LNG demand, which is up over 5 Bcf a day from a year ago even before the imminent startup of Golden Pass, along with an increase in gas-fired power demand year-over-year will likely moderate storage injections in 2026 relative to historical levels. Supporting strong LNG export demand this year are the European storage level deficits versus the 5-year average that continue to widen, currently at approximately 600 Bcf below the average and are now approaching the historic low levels of 2022. This should incentivize robust U.S. LNG exports to Europe throughout this coming summer. Next, on Slide #10, let's look at the pricing improvements at some of the hubs that we sell significant gas to. The chart on the left-hand side of the slide shows the TGP 500-L basis strength. With the Plaquemines LNG facility consistently averaging feed gas of over 4 Bcf per day, we've seen increasing demand along our TGP 500-L firm transport path, driving a higher premium at the delivery point relative to Henry Hub. For the full year 2026, the premium is now plus $0.66 to Henry Hub, the highest level we have seen on an annualized basis. Next, the chart on the right of the slide shows local basis pricing relative to Henry Hub. Local pricing for 2026 is currently $0.74 back of Henry Hub compared to the $0.88 differential over the past 5 years on average. We believe this local basis differential could tighten further, driven by East region storage that is more than 13% below the 5-year average. As an example, the recent winter weather event, combined with this low storage in the East led to February Tico prices settling at just approximately $0.15 differential to Henry Hub, the tightest February differential in 10 years. Our acquisition of HG Energy substantially increases our exposure to strengthening local prices, driven by the significant regional demand growth. Historically, low storage in the East, combined with this regional demand growth could result in a need for increased supply, supporting a decision for our growth capital option that Mike detailed earlier. This significant regional demand growth is driven by new natural gas power generation and data center projects being announced throughout our region and along our firm transportation corridor. All of these projects will be competing for natural gas that could face supply challenges in that short time frame. The HG acquisition increases Antero's dry gas production and drilling inventory, boosting our exposure to this regional demand. Our coordination with Antero Midstream's ability to build out infrastructure and to supply the substantial water needs at these facilities, combined with our extensive land team puts Antero at a competitive advantage in participating in these projects. With that, I will turn over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. I'll start with Slide #11, which highlights our 2025 financial and operating results. Our operational performance in 2025 was one of our best years yet as we set numerous company records. During the fourth quarter, we achieved a new stages per day company record for a single completion crew, hitting 19 stages in a day. For the full year, we averaged over 14 stages per day, an 8% increase from the 2024 average. Our drilling team achieved its best annual rate, averaging under 5 drilling days per 10,000 feet, 4% faster than the 2024 average. The chart on the right-hand side of the slide highlights our 2025 financial highlights. During the year, we generated over $750 million in free cash flow. We used this free cash flow to reduce debt by over $300 million, repurchased $136 million of stock and invest more than $250 million in accretive acquisitions. The strength of our balance sheet and the consistency of our free cash flow generation supports an opportunistic return of capital strategy, where we can pivot between debt reduction, buybacks and accretive transactions or a portfolio approach to all of these in order to drive shareholder value. Next, Slide 12 highlights our 2026 production and capital outlook. Starting with the capital table at the top of the slide. Our drilling and completion capital budget is $1 billion. This includes $900 million for maintenance capital and $100 million from the higher working interest as a result of foregoing a drilling joint venture partner this year. Additionally, we have an incremental 3 pads that we could develop in 2026 that would add up to $200 million of growth capital during the year and drive further 2027 production growth. The bottom of the slide highlights our production outlook. In 2025, we averaged 3.4 Bcfe a day. For 2026, we forecast 4.1 Bcfe a day of production. This maintenance production level reflects the early February close of the HG acquisition and the expectation that the Ohio Utica divestiture closes in February. Next, as we have discussed, we laid out growth to 4.3 Bcfe a day in 2027 due to not having a drilling JV this year and a growth option that could increase our 2027 production up to 4.5 Bcfe a day. This discretionary growth option will be based on the outlook for natural gas prices and in-basin demand during the year. Now let's turn to Slide 13 to discuss our updated hedge program. To derisk the acquisition of HG, we hedged those volumes to provide a clear path to funding the transaction in just 3 years using the free cash flow from those hedges along with the divestiture of our Ohio Utica assets. In 2026 and 2027, we are hedged with a combination of swaps and wide collars. We have approximately 40% of our 2026 natural gas volumes hedged with swaps at a price of $3.92 per MMBtu. We have another 20% hedged with wide collars between $3.24 and $5.70 per MMBtu. Our hedge book allows us to protect the downside by locking in a portion of our free cash flow, while at the same time, maintaining attractive exposure to higher natural gas prices. I will close by commenting that while our equity value remains near levels from before the HG acquisition, our company is much stronger today. Through the transaction, we increased our production base by over 30%, extended our Marcellus core inventory by 5 years, reduced our cash cost by nearly 10% and substantially increased our free cash flow. We achieved all of this without using any of our equity, and we expect leverage by the end of 2026 to be similar to where we were prior to the HG acquisition, which was just below 1x. Looking forward, we are well positioned to capitalize on the significant natural gas demand growth expected, both on the LNG front in the Gulf Coast and from the significant power demand that we see occurring regionally. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] Your first question comes from John Freeman with Raymond James.

The first topic just on the growth capital, just wanted to know if you all could kind of provide a little bit more color on sort of what kind of in-basin demand gas price assumptions you all would need to kind of support that growth plan kind of relative to the current strip and outlook.

Yes, John, our goal is always to have the most capital-efficient development program, and we do have that. But what that leads us to is to try to have a steady-state program. So we're running 3 rigs and 2 completion crews right now. So maintaining that would result in growth, not only in '27 at that couple of hundred million a day, but also in the further out years. But an attraction of this, though, is that is flexible. We have the ability just to do our maintenance capital program with completing and drilling 2 or 3 less pads and still maintaining production and then deferring those pads in the future years. You saw us do that in 2024 when you had kind of a $2 gas environment or $2 plus. But then when the natural gas returned to more kind of the $3-plus level, we completed those pads. So that's kind of the expectation here. All of that is -- has the ability to be deferred. It's all second-half capital. So we can call an audible then. But if you saw a $3-plus gas, and as Brendan mentioned in his comments, the local differentials being so tight, that continues, you'd probably see us complete those pads and drill those pads. But if it was a lower gas environment, we defer those into future years. The other nice thing on this capital and this growth is it's not based on any commitments. So it truly is flexible. It truly is an option value for us. No commitments with that. It is all local gas. And with the discussions we're having and the prices we're seeing, and we've actually already entered into some sales to utilities off of MVP as those continue, we'll complete those pads into those opportunities.

That's great. Very helpful. And then just my follow-up on Slide 11, you'll show kind of the breakdown of the usage of the free cash flow last year, roughly about 20% of the free cash flow went to buybacks. And as Brendan, as you mentioned, the leverage will be back below 1x before the end of the year. Is there any sort of like just sort of absolute debt target or something like that, that we should be looking at to where you would then potentially maybe more aggressively shift toward buybacks? I mean I know you're being opportunistic, but if there's just some sort of metrics we should be following?

No, there's no metrics. I think we're better positioned now than ever to be countercyclical in buying back shares with our hedge position, our size and scale, very comfortable buying back shares regardless of where our debt is right now. But with that said, paying down the debt is normally when we actually perform the best from an equity standpoint, derisking the business, getting it under 1x as a result of this year's activity. But if there is an ability to opportunistically buy back shares and be countercyclical, that's something that we would take advantage of.

Your next question comes from Arun Jayaram with JPMorgan.

Mike, you've had -- it's been just over 60 days since you announced the HG deal. And I was wondering as you look a little bit more under the hood, thoughts on potential upside potential to the synergy number. I think you identified $950 million of PV-10 synergies. Just maybe thoughts on where you stand regarding synergies and how do you think about potential upside or better capital efficiency even as we look at 2026?

Yes, Arun, it's actually better than our expectations. I was actually out there last week. What's really apparent when you go out there, it is part of our field. It's adjacent. It should have -- we're the natural developer of it. It just extends our field south to that southern row of dry gas and liquids opportunities, a little flatter down there, bigger pads, ability to have wider spacing, do bigger completions, have terrific recoveries. The other thing that's come to our attention is just the improvement in our cost structure, and that's coinciding with all this local gas demand and better in-basin pricing, which we didn't underwrite and didn't have. So there'll be some upside on the pricing, I think. And then I think there'll be further upside on the cost structure and recoveries and expanding our margins.

Great. Great. Mike, and just maybe a follow-up. I believe on the third quarter call, you highlighted how Antero was completing one of its kind of first dry gas pads in a number of years. And I was wondering if you could give us any sense if you have enough data to maybe to give us some thoughts on how the results played out relative to your expectations? And does this set up more of an opportunity for AR on the dry gas side?

The completion crew right now is on that pad, the Flanagan Pad. So it just went on there this week, Arun, moving from the Shinn Pad over to that. So still early on that, but we have high expectations for it and very confident in its results.

Your next question comes from Mike MacCurdy with Pickering Energy Partners.

It's Kevin MacCurdy. As we look at the production ramp this year, you end up at the same spot, but the ramp is maybe a touch lower than we were expecting. I wonder if you could maybe touch on the variables that impact that ramp? And is that ramp mainly on the acquired assets?

Yes. On the production, it's not a touch lower. It's as expected. We gave some quarterly performance. We closed it quicker than we thought. When we mentioned the 4.2 on the initial call, that was from Q2 to Q4. It's still 4.2. It's 4.1 now in Q2 with a turn-in line happening in the middle of the quarter that pushes that up to 4.2. So it's as expected. So the cadence is terrific and then goes to 4.3 in '27. And then with the growth capital that we have, if we execute on that plan, we'd be at 4.5 in '27.

Great. And maybe shifting to NGLs. As we track the C3 prices for Antero, it looks like domestic prices haven't moved much this year, but international prices have been driving your forecasted C3 price for the year up a little bit. I wonder if you can touch on maybe what do you think is driving that arbitrage and how you think that progresses through the year? And maybe is Mont Belvieu fully debottlenecked now? Or are we waiting on further expansions this year?

Yes, Kevin, this is Dave. I'll take that one. So on your first question on the what's driving the international pricing, Typically, we see this time of year at the winter, propane prices really kind of rise relative to naphtha. So we're seeing levels that are kind of in line with what we've seen in prior winters. But certainly, some of the issues that we had on the U.S. export infrastructure side, kind of a lower or a later start on some of the expansion capacity than maybe we had anticipated, some challenges that some folks have with refrigeration units. As I mentioned in my comments, kind of led us to see the inventories in the U.S. kind of go a little higher than what folks were modeling and expecting at that point in time. So I think here in the first quarter, we're seeing those issues resolve. You typically have some fog challenges in the winter as we always do, but strong domestic demand is kind of keeping that from being too noticeable in the inventory levels. But just the usual international markets having a strong desire for U.S. LPG. And when they see any kind of hiccup at the dock and kind of the peak demand season of the winter, you see that flow through in the pricing while we always see that appreciation versus naphtha. And then yes, on the export side, I would say, really seeing -- even though we kind of talked about expansions in 2025, didn't really see the effect of those until we get into calendar year 2026 and then further expansions coming. So kind of view us really at the front end of that debottlenecking in the Gulf Coast right now.

Your next question comes from Greta Drefke with Goldman Sachs Asset Management.

My first is just on the winter gas realizations. Given the volatility in both the Gulf Coast and Northeast pricing this winter we've seen so far, can you speak a little bit more about your outlook for gas realizations in this quarter in particular? And just key considerations to keep in mind in the context of your scale of your volumetric exposure at the Gulf Coast and the moving pieces of the 2 transactions.

Greta, yes, I mentioned in my initial comments, we didn't have any curtailments. So obviously, we participated in the pricing that occurred in the region and on the Gulf Coast in the first quarter. So we typically have 80% first of the month and 20% on the day. So we were able to sell 20% daily pricing during the quarter.

Great. And then a quick follow-up as well. Just on hedges, given the amount of volatility that we've seen at the start of the year, can you just talk a little bit about your current view on potentially layering in incremental hedges in 2027 or beyond if the forward curve gives you that opportunity?

Yes, I think you said that well. '26, we're set 60% hedged in the high $3 level and some white collars. '27, we have some room to go. We're about 900 million a day hedged. So about 30% hedged in that high $3 level. I think a high $3 level is a good area to target. The other thing to note is the M2 basis has really come in. I think it's the tightest it's been on a forward-looking curve in 10 years, ability to hedge that at about the 75, 76 back level. So you have high $3, you can hedge the local basis at 75, 76, lock in $3 realizations at the wellhead locally. That's an attractive level for us. So I think we continue to layer some of those in.

And your next question comes from Josh Silverstein with UBS.

Just going back to the cost structure. Can you talk about how this may change throughout the course of the year? I believe you talked about a $0.25 per Mcfe margin improvement. Do P&C costs start higher, then decline. So you also see a benefit into 2027 versus 1Q of this year? Any sort of direction there would be helpful.

I think you touched on it, $0.25 is a good level. Obviously, there's some variable component to our cost structure. You recall, every dollar up in the natural gas price is about a $0.10 variable just on production taxes and transport costs on our FT. So you had a little bit of that up compared to that when we mentioned in December because the gas curve is actually up $0.60 for '26. So you saw about a $0.06 increase from there. But conversely, our realizations as well are still in that $0.10 to $0.20 premium, whereas we thought it would be more flat. So the ability to add 800 million a day of local dry gas and still have a $0.10 to $0.20 premium to NYMEX for '26 is terrific. So looking good there, but I think you hit on it, about a 10% reduction in our cost structure, about $0.25.

Got it. And then I just wanted to shift over towards any sort of potential power supply deals and see how those are progressing with the new HG volumes and some of the interconnects that you now have are a little bit better in West Virginia, how those may be developing? And you've talked about now improving kind of local basis as well, how you may look to structure these.

Josh, this is Brendan. So overall, I think on the power side, as Mike mentioned, I think in his prepared remarks, we're selling some of that gas already to utilities that are buying for a lot of this gas-fired power demand that we're seeing. I think on top of that, we continue to see RFPs come in quite frequently on additional gas supply in the next several years. I think as they get closer to being in service, they then turn to some of the larger gas producers and particularly investment-grade gas producers in the region to look to lock in some of that supply. So we're seeing a lot of interesting conversations there, and we'll look to continue to lock in some of that pricing over time here.

And your next question comes from Phillip Jungwirth with BMO Capital Markets.

Your FT portfolio, it's always delivered leading realizations, smooth out price volatility. Most of this was signed up a long time ago. So I was just hoping you could talk about how you see yourself managing this FT position through the decade, including that associated with ethane C3+. Is there any you don't feel the need to keep? And is there just a long-term margin optimization story here through re-contracting or maybe even picking up different FT from others who don't have inventory?

Yes. Good question. Definitely an optimization. I mean we're so well positioned right now. We can pick and choose the best path going forward also now with the flexibility in the local dry gas. So we can do both. And that's an opportunity for us over the next couple of years as some of these long-term agreements come to the end of their original agreement, we'll assess whether it makes sense. But that's a great story for us on a go forward and definitely upside our ability to optimize those transport paths and optimize our cost structure.

Okay. Great. And then as we think about the organic leasing program, I was just hoping you could kind of frame the competitive moat you have here in terms of existing footprint or infrastructure. There's still some smaller players in and around you. And just what's the pathway for some of these smaller E&Ps to efficiently develop their position? Or have you made it pretty prohibitive for them to do that given your large footprint and surrounding footprint?

No, we are obviously the West Virginia natural gas and NGL producer and our size and scale makes it a lot more efficient for us to develop the asset compared to others. So I think you'll continue to see us build upon that. whether through organic leasing or small transactions, but continue to just consolidate our position in West Virginia, and that will continue to drive our capital efficiency and lower cost structure and margins.

Your next question comes from Leo Mariani with ROTH.

Just wanted to follow up a little bit on the growth CapEx question. Obviously, you guys kind of cited that this $3-plus world is sufficient for you guys to go ahead and spend some of that growth CapEx. Just wanted to kind of clarify, is that a $3 Henry Hub price? Or is that more of a $3 kind of in-basin price, which seems like you're fairly close to that given the tightening basis as we roll into next year? And then if you do decide to spend the capital. Can you just provide a little bit of color in terms of what that looks like in the second-half? Is most of that CapEx kind of fourth quarter and the production starts to ramp kind of early in '27? Just any kind of moving pieces around that would be great.

Yes. First part, it's more NYMEX based. Like you cited, we can -- right now, the markets would say $3 in-basin for '27. But even if you had $3 NYMEX and that's $0.70 back, you'd be in the mid-2s in basin and you're talking $1 cost structure on this gas. So your $1.50 margin even in that level and it's $0.50 F&D. So you're still having terrific returns. These are all local dry gas pads. The optionality here is kind of one of the key points. It's flexible. There's no commitments around it. So we can judge it at the time and we can hedge it as we have been as well. So $3 plus kind of NYMEX is more where our head was at with that tight basis. The second part is it's all second-half capital. You won't see any of the production ramp until '27. Obviously, you have a 6- to 9-month kind of cycle on drilling, completing and turn-in-line dates. So it will be second-half capital. We looked at it. It's almost all second-half capital. It's like 95%, all second-half on these 2 to 3 pads and then the production comes on in the first half of '27.

Okay. Appreciate that. And just with respect to the buyback here, I was getting a sense, correct me if I'm wrong, I want to put words in your mouth that the debt paydown is maybe a little bit more of a priority just given the fact that you kind of added some leverage, but you obviously have some nice hedges to take care of that. And the buyback is going to be maybe a little bit secondary and fairly opportunistic as well.

Yes, that's fair at this level. But if you do see any sort of opportunities on the equity, you should be pretty confident, we'd take advantage of that.

Your next question comes from Kalei Akamine with Bank of America.

My first question is on the growth option. I'm wondering if that investment sets you up for 4.5 Bcfe/d early in 2027 and what the new maintenance capital number is associated with that volume level?

Yes, it would be early in '27, and that's not a maintenance capital running 3 rigs and 2 completion crews would add a couple of hundred million a day of growth in '28 and '29. So you continue to grow at that kind of $1.2 billion capital. Our maintenance capital would still continue to be $900 million-ish. That's kind of what we were looking at this morning. It's pretty remarkable. So maintenance capital stays relatively flat even at those levels, just highly, highly capital-efficient development program.

Got it. I appreciate that. And for my second question, just kind of based on your comments, it sounds like the growth option will be on the dry gas acreage, whether that's legacy Harrison County or the new HG assets that you picked up. Just kind of wondering if there's sufficient egress to move those growth volumes around the basin or if you'll be spending additional midstream capital at AM.

No, AM does have some capital. I think it's around $20 million this year to build out our dry gas Eastern to connect to all the various pipes, and that will provide enough egress, and there's so much local demand that you'll be able to sell the gas locally.

And your next question comes from [ Subash Chandra ] with [ Dolan X ].

So just curious, maybe the question is for Dave. What's the PDH outlook in China in '26?

Yes. So right now, I mean, the current infrastructure is running in the 65% to 70% utilization range. We did have 4 plants that came on in 2025. So kind of continuing to see the absolute amount of volume that's -- capacity that's available to ramp into is in that 300,000 to 400,000 barrel a day range. And then 2 additional plants right now on the schedule to turn in line or come online, sorry, in 2026, and those total about another 55,000 barrels a day of PDH demand.

Perfect. Excellent. And then on -- it seems like the completions in '26 guidance is longer laterals than '25. Just curious if -- is any of that HG related? Or is that going to be more influential in '27?

It's pretty much all HG related, actually. That's one of the attractions here. I mentioned it's a row, but they were able to design it as very efficient row that basically goes north and south 20,000 feet both ways is kind of their average. So that takes us up to that 15,000 feet level from our kind of typical 13,000 feet. So definitely accretive on a lateral length HG development.

[Operator Instructions] And your next question comes from John Abbott with Wolfe Research.

I want to go back to the question on -- go back to growth. And the HG transaction has added to your inventory. I mean we've already sat here and discussed that you have the option to get to 4.5 Bcf per day in 2027, you could grow beyond that. I guess when you sort of think about your inventory in hand and when you think about NGLs and dry gas, how do you think about the extent that you are willing to grow, just given your visibility...

Yes, quite a bit. I mean we are the ones that should grow. We have the most capital-efficient program. We have the FT that goes to the LNG exports. We have the local dry gas where it goes to where all the data centers and natural gas-fired generation is coming. So all the demand centers that everyone projects that's coming over the next 5 years, we're the best positioned for it, and we have the best rock. So that's kind of where our head was at is why would we navigate through this by strictly enforcing ourselves at maintenance capital. We want to be the most capital-efficient developer, and that's always our goal. And so a steady-state program is always the way to achieve that. So just running 3 rigs and 2 completion crews flat would result in the most capital-efficient development and to toggle away from that based on monthly spot prices is not something that we would probably do. And when you put that into our development plan, that results in this growth. So that's kind of where we came to on this. We are the ones that should be growing and meeting this upcoming demand, and we are the best positioned for it.

I appreciate it. And then the follow-up question here, I guess, would be for Justin. So you were in the slide, you're highlighting the tightening in basis, I mean, I guess, the growth option here from bringing on the dry gas wells, you're going to hedge that. But I guess when you sort of look at basis and tightening, how do you think about basis and growing into that basis? How do you think about your impact to basis and the decision to grow?

Yes, we're not -- I mean, we're talking a couple of hundred million a day growth. I mean the demand numbers you're seeing are well in excess of that. So on a percentage basis, it's probably -- we're actually probably not adding to the -- or detracting from the supply and demand picture. So this isn't terrifically material. You're talking 200 million a day of gas production growth versus [indiscernible] a day of gas demand.

Your next question comes from Sam Margolin with Wells Fargo.

Back to your point on capital efficiency, it looks like just from your production guidance and your activity guidance that HG was -- had a positive impact on your corporate decline rate. Is that accurate? And if so, could you help quantify that a little bit? I'm just looking at the production outcome from the spending outcome.

Yes, our capital decline actually was in the low 20s. This is a little bit above that kind of mid-20s. But what we have is you have a flatter production file, you have some HG flatter, the midstream system has more of a kind of a flat production profile on the wells in the first couple of years, whereas ours was more well plumbed. So it's fairly similar, but a lot of their production has had, and constrained just around midstream. And so it's got a flatter production profile in its first couple of years.

Got it. Okay. And then just on the commercial side, there's a lot of focus on power, but the industrial piece along some of your firm transport destinations also has some growth prospects. Are there any commercial or fixed gas supply opportunities in that category?

Yes. This is Justin. We've spoken about this in previous calls, but Antero's firm transport book is set up with approximately 2 Bcf that heads down to the Gulf Coast, which Mike mentioned, that gets into the LNG corridor. And within that path, not to mention what the local growth will be, and we have different capacity that will pass by those end users, just if you think geographically, Kentucky, Tennessee, Mississippi, all the way down to the LNG corridor, we've identified potentially 4 or 6 Bcf of different demand that would be a potential fit with the Antero firm transport delivery. So we continue to have those conversations. As Brendan mentioned, we continue to get RFPs for different supply for these data centers and power projects. And we've touched on this in the past as well, but the competition for that volume southbound will continue to increase over the next couple of years.

And we have reached the end of our question-and-answer session. So I'll now hand the floor back to Dan Katzenberg for closing remarks.

Thank you for joining us on the conference call today. Please reach out with any further questions that you have. Have a good day.

This concludes today's call. All parties may disconnect.