ANTERO RESOURCES Corp Q4 FY2025 Earnings Call

Greetings and welcome to the Antero Resources Corporation fourth quarter 2025 earnings call. And at this time, our participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note that this conference is being recorded. I will now turn the conference over to your host, Dan Kassenberg, Finance Director. Please go ahead.

Thank you for joining us for Intero'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 interoresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important destroyers regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President, Brennan Krueger, CFO, Dave Candelago, 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. 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 sub-zero 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 seven-well pad during that time. A truly remarkable achievement by our people in the field, enabling Anterra 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 number three titled, Entero 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 five years, increasing our dry gas exposure, our larger production and inventory base positions and terror 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 Entero's integrated structure with Entero 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 Canalongo, for his Looking back on 2025, three main fundamental forces, line number four titled U.S.

Propane. As we entered 2025, propane inventory levels were trending with the history of 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 startup delays. Importantly, the demand pool that persisted in the process, despite these identified heads, supply in 2025 consistently trended within the five-year range due to strong export. And 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, as shown on slide number five, title. The chart on the left displays year-over-year U.S. supply growth decreasing 131,000 and further to 45,000. Significant LPG export, there is more to come, and service dates for LPG should be unconstrained. Number 7 illustrates several years of declining demand growth. 2026 demand is expected to grow 563,000 barrels a day, the largest annual increase.

Today, prices are above their pricing into context, extremely strong, with November through February averaging nearly 42 BCF per day. Natural gas demand compared to the five-year average, and is over 1 BCF above last year. ranking it as the third strongest January RESCOMM demand on record. Natural gas demand on record, dating back to 2005, in part related to the continued growth in behind-the-meter power demand for data centers. Starting to slide number nine, titled Natural Gas Storage, the result of this strong winter demand has been a dramatic flip in storage level, BCF above the five-year level. Today, we are approximately 140 BCF. This should result in exiting withdrawal season below the five-year average, which drove substantially higher LNG demand, which is up over even before the imminent start, along with an increase in gas-fire power demand year-over-year, will likely moderate storage injections in 2026 relative to historical levels. Strong LNG exports are the European storage-level deficits versus the five-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 year. Slide number 10, let's look at the price that we sell significant gas to. The chart on the left-hand side of the slide shows that with the Plaquemine LNG facility consistently averaging feed gas of over 4 BCF per day, we've seen increasing demand along our TGP 500 at the delivery point relative to Henry Hub. In 2016, the premium is now plus 66 cents to Henry Hub, the highest level we have seen on an annualized basis. 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 five years on average. I believe this local basis differential could tighten further, driven by east region storage that is more than 13% below the five-year average. As an example, the recent winter weather event combined with this low storage in the east led to February TECO 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 timeframe. The HG acquisition increases Ontario's dry gas production and drilling inventory, boosting our exposure to this regional demand. Our coordination with Ontario's midstream's ability to build out infrastructure and its supply the substantial water needs at these facilities, combined with our extensive land team, puts Ontario at a competitive advantage in participating in these projects. With that, I will turn it over to Brendan Krueger, CFO of Intero Resources.

Thanks, Justin. I'll start with slide number 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 fourth 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 for 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 use this free cash flow to reduce debt by over $300 million, repurchase $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 three paths 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've discussed, we laid out growth to 4.3 BCFV 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 BCFV 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 de-risk the acquisition of HG, we hedged those volumes to provide a clear path to funding the transaction in just three 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 MNVTU. We have another 20% hedged with wide collars between $3.24 and $5.70 per MNVTU. 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 five years, reduced our cash costs 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 one-times. Looking forward, we are well-positioned to capitalize on the significant natural gas demand growth expected, both on the LNG front and 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.

Thank you. And at this time, we'll conduct a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Your first question comes from John Freeman with Raymond James. Please state your question.

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

Yeah, John, you know, 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 three rigs and two completion crews right now, so maintaining that wood resulting growth, not only in 27 at that couple 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 pleading and drilling two or three 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 a $3 plus level, we completed those pads. So that's kind of the expectation here. you know 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, 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, you know, on slide 11, you all showed kind of the breakdown of the uses of the free cash flow last year. You know, roughly about 20% of the free cash flow went to buybacks. And, Brendan, as you mentioned, you know, leverage will be back below one times 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, you know, there's no metrics. I think we're better positioned now than ever to be counter-cyclical in buying back shares, you know, 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, de-risking the business, getting it under one times as a result of this year's activity. But if there is an ability to operatively buy back shares and be countersickled, that's something that we would take advantage of.

Thanks. Appreciate it.

Your next question comes from Arun Jayaram with J.P. Morgan. Please state your question. Yeah.

Good morning, gentlemen. Mike, you've had, you know, it's been just over 60 days since you announced the HG deal. And I was wondering if, 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 PV 10 synergies.

Just maybe thoughts on where you stand regarding synergies and you know how do you think about potential upside or better capital efficiency even as we look at 2026 yeah 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 you know part of our field you know 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.

Mike, and just maybe a follow-up, I believe on the third quarter call, you highlighted how Entera 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, you know, 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 around moving from the shin pad over to that. So still early on that, but we have high expectations for it and very confident in its results.

Great. I jumped the gun on that question. Thanks a lot, Mike. Appreciate it.

Next quarter.

Your next question comes from Mike McCurdy with Pickering Energy Partners. please to your question.

Hey, it's Kevin McCurdy. Thanks for taking my question. 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?

Yeah, on the production, it's not a touch lower. It's as expected. We did 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 and 27. And then with the growth capital that we have, if we execute on that plan, we'd be at 4-5 and 27.

Great. Thank you for the detail on that. 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 forecast as 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 Mount Bellevue fully de-bottlenecked now, or are we waiting on further expansions this year?

Yeah, Kevin, this is Dave. I'll take that one. So, you know, on your first question.

I appreciate the answer.

Your next question comes from Greta Dreska with Goldman Sachs Asset Management. Please do your question.

Good morning, all, and thank you for taking my questions. My first is just on the winter gas realizations. Given the volatility in both the Gulf Coast and Northeast pricing this winter recently and 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 with the two transactions.

Hi, Greta. Yeah, I mentioned in my initial comments, we didn't have any curtailment, 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, thank you. 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?

Yeah, I think you said that well. You know, 26% were set, 60% hedged, the high $3 level and some white collars. 27%, we have some room to go. We're about $900 million a day 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 if you have high $3 and 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 need to layer some of those in.

Thank you.

Thank you. And your next question comes from Josh Silverstein with UBS. Please state your question.

Yeah, thanks. Good morning, guys. Just going back to the cost structure, can you talk about how this may change throughout the course of the year? You know, I believe you talked about a 25 cent per arm safety margin improvement. Do GP and C costs start higher, the decline, so you also see a benefit into 2027 versus 1Q this year. Any sort of direction there would be helpful, thanks.

I think you touched on it. $0.25 is a good level. Obviously, there's some variable components 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 December because the gas curve is actually up $0.60. for $26,000, 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 $26,000 is terrific. So looking good there, but I think you hit on it, about a 10% reduction in our cost structure.

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

Hey, Josh, this is Brendan. So overall, I think on the power side, as Mike mentioned, I think in his prepared remarks, You know, 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. You know, 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.

Thank you. And your next question comes from Philip Jungworth with BMO Capital Markets. Please take your question.

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

Yeah, good question. Definitely an optimization. I mean, we're so well positioned right now, we can pick and choose the best paths going forward, also now with flexibility in a local dry gas, so we can do both, and that's an opportunity for us over the next couple of years that 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 when I go forward and definitely upside our ability to optimize those transport paths and optimize our cost Okay, great.

And then as we think about the organic leasing program, 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, but what's the pathway for some of these smaller EMPs 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.

Great.

Your next question comes from Leo Mariani with Ross. Please state your question.

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, you know, 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, you know, 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 as 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.

Yeah, first part, it's more NYMEX-based. Like you cited, we can – right now the market's at, say, $3 in-basin for $0.27. But even, you know, if you had $3 NYMEX and that's $0.70 back, you'd be in the mid-$2 in-basin. And you're talking $1 cost structure on this gas, you know, 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. 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 six to nine month kind of cycle on drilling, completing, and turn in line dates. So it'll be second half capital. We looked at it. It's almost all second half capital. It's like 95% all second half on these two to three paths, 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. you know, as well.

Yeah, 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. Okay, thank you.

Your next question comes from Kalei Akamina with Bank of America. Please do your question.

Hey, good morning, guys.

Thanks for taking my question. My first question is on the growth option. I'm wondering if that investment set you up for 4.5 BCFED early in 2027, and what the new maintenance capital number is associated with that volume level.

Early in 27, and that's not a maintenance capital. Running three rigs and two completion crews would add a couple 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 HGS 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 interim capital at AM.

AM does have some capital, it's around $20 million this year to build out our egress and there's so much local demand that you'll be able to sell together. Thank you, Mike.

Thank you, and your next question comes from Subhash Chandra with Dolan X. Please see your question.

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

Yeah. So right now, I mean, the current infrastructure is running in the 65% to 70% utilization.

Four plants that came on in 2025 is available, or admin two is in that three to 400,000 per And then on, it seems like, you know, the completions in 26 guidance is longer laterals than 25. Just curious, is any of that HG-related, or is that going to be more influential in 27?

That'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 a very efficient row that basically goes north and south 20,000 feet both ways. It's 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 creative on a lateral length, the HG development.

Thanks. And a reminder to the audience to ask a question, press star 1 on your phone. To withdraw your question, press star 2. And your next question comes from John Abbott with Wolf Research. Please state your question.

Hey, good morning, and thank you for taking our questions. I want to go back to the question, go back to growth. and the HGE 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 DCF today, and 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? Yeah, no, I think about that.

Yeah, 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 LMG exports. We have a local dry gas where it goes to where all the data centers and natural gas fire generation is coming. So all the demand centers that everyone projects that's coming over the next five years, we're the best position for it, and we have the best rock. So that's kind of where our head was at is why would we, you know, navigate through this by strictly enforcing ourselves? and 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 three rigs and two completion crews flat would result in the most capital-efficient development, and to toggle away from that based on monthly swap 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 position for it.

I appreciate it. Then the follow-up question here, I guess it would be for Justin. So you were in the slide. You're highlighting the tightening of 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?

Yeah, we're not talking, I mean, we're talking a couple hundred million a day of 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 know, you're talking 200 million a day of gas production growth versus Bs and Bs a day of gas demand.

All right, appreciate it. Thank you for taking our questions.

Your next question comes from Sam Margolin with Wells Fargo. Please get your question.

Hi, thanks for taking the question. Back to your point on capital efficiency, it looks like just from your production guidance and your activity guidance that HG 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 from this spending on capital decline actually was in the low 20s there's is a little bit above that kind of mid 20s but what we have is you have a flatter production file you have some at an HG flatter the the midstream system has more of a kind of a flat production profile on the wells in the first couple years where ours was more well plumbed so it's it's It's fairly similar, but a lot of their production has had been constrained just around midstream, and so it's got a flatter production profile in its first couple of years. Got it.

And then just on the commercial side, you know, 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? yeah good morning this is just approximately two BCF that heads down to the Gulf Coast that gets into the LNG corridor and within that path you know not to mention what the local growth if you think geographically Kentucky Tennessee Mississippi all the way down to the LNG corridor we've identified you

know potentially for 60 different demand that would be a potential fit with the and Terabri.

So we continue to have those conversations. As Brendan mentioned, you know, we continue to get RFPs for different supply for these data centers and power projects. And, you know, 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.

Thanks so much.

Thank you. And we have reached the end of our question and answer session, so I'll We'll now hand the floor back to Dan Kastenberg 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.