Antero Resources Corporation (NYSE:AR) Q2 2025 Earnings Call Transcript

Antero Resources Corporation (NYSE:AR) Q2 2025 Earnings Call Transcript July 31, 2025

Operator: Greetings and welcome to the Antero Resources Second Quarter 2025 Earnings Call. [Operator Instructions] Please note, this conference is being recorded. I will now turn the conference over to our host, Brendan Krueger, Vice President of Finance. Thank you. You may begin.

Brendan E. Krueger: Good morning. Thank you for joining us for Antero’s second 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 www.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, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO and President; Michael Kennedy, 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 Paul.

Paul M. Rady: Thank you, Brandon, and good morning, everyone. Let’s start on Slide #3 titled Efficiencies Reduced Maintenance Capital, which highlights the tangible benefit of our best-in-class capital efficiency. For the second consecutive year, we have increased our production guidance while decreasing CapEx. Looking at the chart on the left side of the slide, since the year 2023, our maintenance production target has increased 5% from under 3.3 Bcf equivalent per day to over 3.4 Bcf equivalent a day. During that same time, our maintenance capital requirements declined by 26% from $900 million to $663 million. The chart on the right-hand side of the slide highlights this capital efficiency relative to our peers. Antero has the lowest maintenance cap per Mcfe of its peer group at just $0.53 per Mcfe.

This is 27% below the peer average of $0.73 per Mcfe. Now let’s turn to Slide #4 to discuss our updated hedges. During the quarter, we added additional wide natural gas costless collars for the year 2026. These wide collars lock in attractive rates of return with a floor price of $3.14 and a ceiling of $6.31. With these new hedges in place, we have hedged approximately 20% of our expected natural gas volumes through 2026. Our hedge book allows us to protect the downside while maintaining significant exposure to rising natural gas prices. These hedges lower our 2026 free cash flow breakeven to $1.75 per Mcf. 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.

Dave?

David A. Cannelongo: Thanks, Paul. I’ll start on Slide #5 titled NGL Pricing Premium. During the second quarter, Antero’s realized C3+ cost price averaged $37.92 per barrel. Looking ahead, we continue to expect realizations to be at attractive premiums to the NGL benchmark in the second half of the year. As a reminder, these differentials are firm in our existing term agreements, and therefore, we have high confidence that differentials will improve going into the third and fourth quarters of this year as winter heating and gasoline blending season ramp up. Additionally, our domestic basis improves for butane beginning in September and for propane beginning in October. Although we reduced our full year NGL price guidance slightly, this was primarily a reflection of our second quarter actuals that was impacted by inventory adjustments.

We continue to expect premiums in the second half of this year to average in the range of $1.50 to $2.50 per barrel, with the fourth quarter anticipated to realize the strongest premium of the year. I will also point out that Antero’s C3+ realizations improved year-over-year as a percentage of WTI, showing strengthening underlying fundamentals in NGL markets. In the second quarter of 2025, Antero’s C3+ realizations averaged 59% of WTI, compared to the second quarter of 2024 when realizations were 50% of WTI. On the export side, Antero has locked in a substantial portion of our export volume at double-digit premiums to Mont Belvieu, and we continue to benefit from those deals. As we’ve talked about in prior earnings calls, when dock capacity is viewed as sufficient and export premiums are modest, benchmark NGL prices typically rise.

This was clearly evident during the second quarter, as reflected in the relative NGL strength versus WTI. We anticipate the new trade deals signed in the coming weeks and months will increase confidence in the reliability of U.S. LPG supply and help strengthen export volumes and benchmark pricing further. Uncertainty surrounding trade negotiations had a significant transitory impact on the global NGL market during the quarter. For LPG, the market saw a shift in trade flows with relatively more U.S. barrels going to Japan, South Korea and Indonesia, and China sourcing more LPG from the Middle East and Canada. These changes were largely anticipated by the market as we discussed on last quarter’s earnings call. Despite the destination reshuffling, overall U.S. propane exports remained strong and increased year-over-year.

Exports have averaged over 1.8 million barrels per day, which is 6% higher than the same period last year. As shown on Slide #6, titled New Capacity to Increase Exports, new Gulf Coast export capacity that has just been placed in service is expected to lead to higher exports, a rebalancing of inventories and further strengthening of Mont Belvieu NGL prices. 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.

Justin B. Fowler: Thanks, Dave. We continue to see the positive demand trends for natural gas both near term and long term. Starting first with the near-term demand growth, the first half of 2025 saw a significantly faster ramp at Venture Global’s Plaquemines LNG facility. This July, the facility achieved a daily record for feedgas of over 2.9 Bcf per day, which represents 120% of Phase 1 nameplate capacity. Now Venture Global is starting LNG production at Phase 2 of the terminal, which will increase nameplate capacity to 3.6 Bcf. This initial production is ahead of prior expectations with full Phase 2 in service expected in late 2025. This accelerated ramp has led to higher demand along our TGP 500 Leg firm transport and driven a higher premium at that delivery point relative to Henry Hub.

As shown on Slide #7, titled, Not All Transport to the U.S. Gulf Coast is Equal. Maintenance along the pipeline restricted the amount of volume that captured that premium during the second quarter. However, we anticipate our premium realizations will improve in the second half of 2025 and in 2026. As a reminder, Antero has 570 MMcf a day of capacity on the TGP 500 Leg. Slide #8 dives a bit further into the LNG market. Over the next 30 months, LNG demand is expected to increase by another 8 Bcf a day, driven by the start-up of Plaquemines Phase 2, Golden Pass, Corpus Christi and Calcasieu Pass Phase 2. Combined with the continued power demand growth, the natural gas market is expected to be materially undersupplied during this period, which we expect to support higher prices next year.

Now let’s shift topics from near-term LNG demand to the medium-term Appalachian regional power demand trends. Turning to Slide #9 titled Regional Natural Gas Demand, the first version of this slide was created for our first quarter earnings call in April. At that time, approximately 3 Bcf of regional power demand had been announced. A short 90 days later, we are now up to almost 5 Bcf of announced projects within our region. While we certainly acknowledge there’s a lot of work to be done, we anticipate the acceleration in power demand announcements to continue, resulting in significant opportunities for Antero. Antero remains advantaged in this power demand story with our extensive resource base, integrated midstream assets and investment-grade balance sheet.

Through our firm transportation to the U.S. Gulf Coast, we are uniquely positioned as the only natural gas company that can meaningfully participate in both the LNG export growth strategy and the expected regional power demand growth. With that, I will turn it over to Mike Kennedy, CFO of Antero Resources.

Michael N. Kennedy: Thanks, Justin. We continue to execute on our plan while doing so in a more capital-efficient manner. During the second quarter, this execution led to $260 million of free cash flow, nearly $200 million of which we used to reduce debt. Once again, we continued our opportunistic share repurchases, accelerating our buybacks during periods, and the stock does not reflect the underlying fundamentals. This was highlighted by our activity April through July when our average share repurchase price came in at an 8% discount to the volume-weighted average price during that same period. Our return of capital strategy is anchored by our low absolute debt position that provides us with substantial flexibility. With this flexibility, we can pivot between share buybacks or debt reduction depending on market conditions.

Year-to-date, we have now reduced total debt by 30% or $400 million while also repurchasing $150 million of shares. Let’s turn to Slide #10 titled Antero Has the Highest Exposure to NYMEX-Linked Pricing. Justin already highlighted this significant demand that is coming later this year and continuing through the end of this decade. We expect regional pricing will remain volatile, with sustained periods trading at a steep discount to NYMEX due to pipeline constraints and seasonality impacts. This chart highlights Antero’s peer-leading exposure to NYMEX. While all of our peers forecast to realize prices well back of NYMEX due to in-basin exposure, we expect realized prices at a premium to NYMEX. Looking forward, we plan to continue to target maintenance capital at future growth opportunities from regional demand increases.

Any future growth would be tied to a direct demand at attractive prices. Given our firm transportation capacity that sells our natural gas at premium to NYMEX, we are unlikely to spend growth capital for in-basin pricing. Slide #11 illustrates that over the last 10 years, any regional basis tightening has been short-lived, given robust Appalachian supply and pipeline takeaway constraints. However, if regional demand were to lead to a sustained improvement in in-basin pricing, we have over 10 years of dry gas drilling inventory where we could accelerate activity to grow volumes in a short time frame and capture that higher regional pricing. With that, I will now turn the call over to the operator for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from Arun Jayaram with JPMorgan.

Arun Jayaram: Maybe for Dave. Dave, I wanted to see if you could maybe elaborate on Slide 6 where we’re going to see some additions to Gulf Coast LPG export capacity. Your thoughts on the implications for Mont Belvieu pricing and just the international versus Mont Belvieu spread next year and how this will maybe shape some of your marketing efforts.

David A. Cannelongo: Yes, Arun, we’ve seen this dynamic play out a few times, as you see in the chart, going back to 2020, 2021 where you have a sizable build-out, new export capacity. And we’ve talked about in the past, during those times, you see the dock premiums be fairly modest and tied to Mont Belvieu pricing. But the result of that is Mont Belvieu as closely linked to the international price as it can be. And so that’s what we expect with the build-out that you see there from parties just there through 2026. And obviously, there’s another consortium that’s working on another large export project in the Gulf. So a significant amount of export dock capacity coming online in the U.S. really should debottleneck us for the foreseeable future.

As a result of that, I think the premiums of the docks will be more modest going forward, but we’ll see overall higher benchmark as a result, which, for Antero, with the domestic exposure that we have, in the end, higher Mont Belvieu prices is net-net better for us than strong [indiscernible].

Arun Jayaram: Got it. And maybe one for Mike. You guys continue to kind of walk and chew gum in terms of reducing — you’re already low debt balances and buyback stock. Based on your view, Mike and Paul, of the fundamental picture, how do you gauge the mix of maybe buybacks and debt reduction going forward?

Michael N. Kennedy: Sure, Arun. We came into the year thinking that the first $600 million of the free cash flow is going to be used to reduce debt. Then we saw some market dislocations over the past 4 or 5 months, which really the Antero Resources stock price is not reflecting our strong fundamentals. So we took advantage of that and started to buyback early. We’ll continue to do that, be opportunistic. We continue to want to reduce debt. We’re at $1.1 billion. We’d like to reduce that further, of course. But also there’s continued dislocations in the stock. We’ll continue to buy that. So it’s kind of a mix, just depending on market conditions. But we are happy to be able to buy in stock where we have so far this year.

Operator: Your next question comes from John Freeman with Raymond James.

John Christopher Freeman: You highlighted the last few years you’ve been able to meaningfully reduce the maintenance CapEx while still moving the production higher. Just at a high level, just how we should think about maybe 2026, do you all have the ability directionally to keep pushing that maintenance CapEx lower?

Michael N. Kennedy: Yes. Yes, we do. This year, I think our well costs are down 3% year-over-year, and we continue to drill them in a quick — and complete them in a very quick fashion. That 3% decline, and that’s on a per foot basis, is actually on a bit shorter laterals than is typical for us. We’re kind of more in the 13,000 foot range this year. But that returns next year more to the 14,000 and 15,000 foot range. So just assuming all things equal, service costs equal, no more efficiencies, which I don’t expect to happen, that would lead to a further 3% decline in well cost next year. So our well costs continue to decline and we continue to drill them faster. And so I think that continues into ’26.

John Christopher Freeman: That’s great. And then my follow-up question, some of your peers this earnings season have talked about kind of the pretty big uplift to cash flow due to the tax impact, the recent tax changes. Are you all able to sort of talk to that?

Michael N. Kennedy: Yes. We have a similar uplift from that as well. We have a lot of tax attributes, to lot of NOLs from the past, a lot of R&D tax credits. But with the new bill, you’re able to expense all of the R&D expenses without some limitations. There’s better interest expense treatment. It’s 30% of EBITDA versus EBIT also 100% bonus depreciation on lease and well equipment. So you combine all that with our — the tax attributes that we carried forward, and we do not expect to pay any material cash taxes for the next 3 years, so it’s pushed out at least until 2028 based on today’s commodity prices.

Operator: Your next question comes from Doug Leggate with Wolfe Research.

Douglas George Blyth Leggate: Actually, I wonder if I could just follow up on the last questions very quickly. I want to make sure we understand this correctly. And so you can understand the context, one of your large peers talked about 10 years of significant deferred tax. Is it fair to say that you guys are not subject to the AMT, the corporate alternative minimum tax, which basically means that the treatment is probably a little different? Or is that — am I thinking about that — am I thinking about that the wrong way?

Michael N. Kennedy: Yes, we’re not subject to AMT. We’re aware of the treatment. We don’t qualify. I think you have to have a 3-year average of $1 billion of TI. So we’re not in that bucket. This bill also makes IDCs deductible for AMT purposes. So that’s further help, so that may be what they’re suggesting. But we are not subject to AMT and do not forecast to be subject to AMT.

Douglas George Blyth Leggate: That’s very helpful. That wasn’t actually my primary question. I’m just opportunistic given the last one. But my primary question is actually back to the sustaining capital issue. We’ve watched this from afar for quite some time get better every year. And my question is, is there anything on mix here that is changing as it relates to what you’re targeting as perhaps the macro gets a little better on the gas side as opposed to on the liquid side. And I guess my end-goal here is to try and figure out how much — is that like a target or a level you can say we think it can get to this level on a sustaining basis going forward? Any color on the magnitude of any continued improvement would be really helpful.

Michael N. Kennedy: Yes. Actually, maintenance capital should continue to improve, everything else equal. I mentioned the lateral length. But also every year you have maintenance capital, your decline rate comes down. I think we’re in the low 20% now, every year it ticks down by about 1%. So when you actually look in the out years to maintain this, you’re below where we’re at, you continue to go lower each year. So that should continue. On target mix, we continue to favor the liquids, 1,275. We had some DUC dry gas pads or lean gas pads that we completed in late first quarter and early third quarter, which has that mix, at least to condensate a bit off, but that should return to kind of in that high around 10,000 barrels a day in Q4 with liquids — the same. So the mix, really just continue to target 1,275 Btu. But our maintenance capital continues to tick lower, not only from our capital efficiencies, but from longer laterals and also lower declines.

Douglas George Blyth Leggate: That’s a great message.

Operator: Your next question comes from Greta Drefke with Goldman Sachs.

Margaret Ellen Drefke: I first just wanted to touch on hedging here a into some more collars this quarter. Given the volatility of the forward curve that we’ve seen in the past couple of months, what’s your current view on potentially layering in incremental hedges in 2026 or 2027 if the forward curve does give you that opportunity?

Michael N. Kennedy: Good question. So ’26 was unique. Never seen in my career where you could get a 2:1 call skew on a contango curve that’s a $1 higher in the front. So we took advantage of that. We had lean gas pads that I just mentioned, but we also have some lean gas pads going forward. So we wanted to lock in. That was kind of the original program. We’ve added to that in the second quarter, now up to 500 million a day, just opportunistic, putting in the $3.25 downside to $7 upside. So that was attractive. If that dynamic would present itself in ’27, that would be something we’re interested in. But we have low debt. We don’t have any in-basin price exposure. We have the lowest maintenance capital. So it’s not something that’s needed. But if you get those type of dynamics in the gas market, it seems prudent to put some hedges on. We’re only 20% hedged, but have upside to $7. That was a good trade.

Margaret Ellen Drefke: Great. I appreciate that color. And then just touch on capital returns a little bit more. As you continue to make progress on deleveraging while also returning cash to shareholders through buybacks, is there a debt level or leverage point at which you would consider ramping up Antero’s return of capital maybe towards 75% or so?

Michael N. Kennedy: Yes, we ramp up really on the stock price compared to underlying fundamentals. We’re now in a position where we could use all of our free cash flow to do that if that was an opportunity for us. We do want to have — continue to have lower debt. We do have a 2030 note that it’s $600 million at 5.38%. So that’s a good piece of paper. We’d like to keep that in our capital structure. So we only really have $500 million of debt that we would pay down right now. So it will just depend on market conditions, but we’re very happy to continue to accelerate our share buyback and actually go higher if there’s an opportunity.

Operator: Your next question comes from David Deckelbaum with Cowen.

David Adam Deckelbaum: Mike, not to belabor the point, but maybe just like if I were to summarize just the return on capital thoughts. Just considering the fact that your outstanding notes, right, are all callable and you can redeem some of those 29 notes, should we just think about it as opportunistically every quarter with free cash, you’ll just be considering the implied return on paying down debt or sort of redeeming those notes versus buying back shares?

Michael N. Kennedy: Yes. When we also look at, David, is just on a forward basis with commodity prices, what’s our kind of cash flow outlook, free cash flow outlook, and then compare that to how the valuation is of Antero. And if that’s an opportunity for us, we’ll act on that. So that’s really what we think about. We could call those notes in right now just under the credit facility. We have so much room under the facility, it’s basically undrawn today. So we could call it in no problem, continue to buyback. But like I said, we’re really just trying to be opportunistic, and it is an opportunity when you see the stock at these levels versus the underlying business.

David Adam Deckelbaum: Appreciate that. Maybe if Dave can take this one. Just curious, Dave, with the benefits in the second half of this year on C3+ realizations, with the added LPG capacity, is the anticipation that premium to Belvieu is pretty sustainable into ’26? Will there be perhaps just a greater mix going international?

David A. Cannelongo: Again, international kind of remains to be contracted. So we’ll be in the market getting what is prevailing prices are at that time. And we do expect it will be lower than what we saw here in ’25. When we talked about here double-digit premiums ’25, you don’t typically see that with ample dock capacity. So you go back to 2020 and ’22, you’re probably averaging $0.06 to $0.07 premiums during that time period. So that will certainly be reflected in our realizations next year. And yes, I would expect that to come down modestly in ’26 versus ’25.

Operator: [Operator Instructions] Your next question comes from Kevin MacCurdy with Pickering Energy Partners.

Kevin Moreland MacCurdy: Production in 2Q was a little gassier compared to the prior quarters, and it looks like the production raise was mostly related to gas volumes. Do you have any comments on what drove the mix this quarter? And any thoughts on how that kind of mix could change throughout the year and into next year?

Michael N. Kennedy: Yes. So we brought on 2 DUC pads that we’ve talked about quite a lot over a number of the past conference calls. One of them was brought on at the end of the first quarter. And these are lean gas pads, more in the 1,200 Btu range. And then the second one was brought on in July. So second and third quarters were always expected to be a bit gassier. But that reverses, like I mentioned, in the fourth quarter, you get back to that 10,000 barrel a day as condensate and liquids continues to increase. So going forward, all the pads we’re bringing on for the remainder of the year are more like the 1,275 Btu. So that will reverse going into the fourth quarter.

Kevin Moreland MacCurdy: Got it. Appreciate the detail on that. And then as a follow-up on the collars, I mean that was a very impressive skew on the ’26 collars. Does that echo kind of your internal view on gas with the more upside to downside in ’26? And just wanted to get your current thoughts on — or any changes to your medium-term macro view based on how kind of storage and production has trended this summer?

Michael N. Kennedy: No, that made sense to us just because the skew is definitely to the upside. The margins today are razor-thin. There is no volumes that are shut in, everything is producing full out. You’ve had a lack of investment in the gas development over the last 2 years. Rig counts are still subdued. So anything could tip this to the upside. If you have an early winter, if you have any sort of winter next year, you could definitely see the gas going much, much higher. So it didn’t make sense to us. But just locking in 20% and taking advantage of that, basically funding your capital program while still maintaining upside to $7 and still maintaining 80% upside exposure with something that appealed to us, lowering our free cash flow breakeven already the lowest down to $1.75.

So we thought we should take advantage of that. Like I mentioned, I’ve never seen that in my 30-plus year career. I kind of call it skew on a contango strip. So that would present itself again. I think we just continue to act just because it’s so attractive, but definitely skewed to the upside.

Operator: Your next question comes from Leo Mariani with ROTH.

Leo Paul Mariani: Obviously, you guys mentioned some of the in-basin demand projects, so appreciate that slide there. Obviously, some new projects recently announced by 1 of your competitors here. Can you maybe provide maybe some color on where Antero is in that sort of scheme here? I assume that you guys are also talking to new in-basin sources of demand. So can you kind of give us a bit of an update on kind of where you guys stand there?

Michael N. Kennedy: Yes. Good question. First, we’ve seen that incremental 2 Bcf a day of natural gas demand just in the last quarter. So that’s exciting to us, and that’s why we kind of put that slide out that’s well ahead of ours and probably everyone’s expectation. How does Antero play a role? I mean we’re so uniquely positioned, some of the attributes we have. We have the integration between the upstream and midstream, one-stop shop there, also importantly, that no one’s kind of focusing on, but it’s a huge attribute for us and kind of sets us apart as we have the water systems and the water that the data centers require and the turbines require. So that is unique to us, and that kind of puts us in a different position. We also — as well as mentioned we have the 500,000 acres decades of core Marcellus inventory right there, HBP legacy production.

So able to satisfy that. We have what we think is the best natural gas marketing team in the business. You’ve got exposure to Justin, they’re terrific over there, so they’ll be able to capture any opportunities. And we also have the investment-grade balance sheet, which is important for long-term kind of arrangements. But with it being a long-term deal, we’re really not attracted to any deals that are based on local pricing. It’s kind of have to be accretive to our overall store and our overall pricing. Doing deals just at local has never been exciting for us. We would always be cautious around putting hundreds of millions of dollars behind development, fund a local pricing deal. This thought has kind of driven our whole strategy from day 1 and what’s created our firm transportation portfolio strategy.

We put that slide there. Any time there’s been local tightening of basis, it’s always been met with the incremental supply and incremental development because it’s — there’s really no barriers to entry to feed that local gas and how prolific the Marcellus is. So anything that we would do would have to be NYMEX based or accretive to our pricing. If we’re wrong and there is attractive local pricing for sustained periods, we’ll just grow into it with our 10-plus years of dry gas inventory. We can turn that on quick, that’s already built, infrastructure already there. So we will be a participant. We’re uniquely advantaged, like I mentioned, with all those attributes. But it’s going to have to be accretive to the story.

Leo Paul Mariani: Okay. I appreciate that. Just wanted to follow up on that there though. Are you guys maybe in any somewhat advanced discussions with in-basin demand sources and you think there’s potential for some announcements in the near future, call it a matter of months as opposed to years? Just trying to see if we can get a little more color around where you guys are in the process.

Michael N. Kennedy: Yes. We wouldn’t put any timing around that. We have set up an internal team. We have a lot of efforts on it, a lot of discussions. But not going to put any timing on that. But to remind you, we have all the firm transport, the vast majority of it, on a percentage basis to the Gulf Coast. And that’s where the demand is going to come, the LNG and natural gas demand growth over the kind of short to midterm. So we’re unique. We have that exposure, but we also are going to have exposure to the local demand from the data center growth. So it’s not like we need to announce deals around that. We’ll be cautious and announce it at the appropriate time and enter into appropriate deals and not rush to enter into any.

Leo Paul Mariani: Okay. Very helpful on that point. And then just quickly on shareholder returns here. Obviously, you don’t have that much more debt to pay off as you’ve enumerated somewhere around $500 million or so. When that’s sort of done, are we going to see just a much more meaningful return of capital? Because obviously, at that point, leverage will be so low, and if gas stays healthy, you’ll just be building a lot of cash. So should people expect that? And obviously, you’ve done the buyback, but could there be a dividend in place at some point as well?

Michael N. Kennedy: Yes, I think you’re already seeing that — we basically already are at the point where we don’t need to reduce that any further. It’s more just being driven by market conditions. So we’ll continue to do that. We continue to buy back in size as we move forward. I haven’t thought about a dividend. That’s also going to be market-based and market conditions. Really just been focused on the debt reduction and getting the share count as low as we can.

Operator: Your next question comes from Phillip Jungwirth with BMO Capital Markets.

Phillip J. Jungwirth: You noted how Cal ’26 for the TGP 500 Leg has increased to $0.60. That’s higher year-on-year, up from your last update. Just with Plaquemines ramping further into next year, wondering if there’s a theoretical ceiling you guys think about for how high this premium could get considering the LNG demand pull and where global gas prices hit? And anything to keep in mind as far as incremental supply going to this price point?

Justin B. Fowler: Phillip, Justin Fowler here. As we look out at the next couple of years, we definitely think that Plaquemines plus the local power gen could continue to pull that basis up. We saw that basis accelerate so quickly. And when we think about our other delivery points, for example, Columbia Gulf Onshore, which is also correlated with Plaquemines LNG, we’ve already seen those basis locations at CGT Onshore, ANR Southeast start to trade a premium as we look out in the forward. So if you just look at history there and understand that there’s only a finite amount of gas that can get to Plaquemines, and then the other LNG facilities that we can, again, highly correlate to Antero’s 2 Bcf of FT delivery to the Gulf Coast, we definitely think that there could be additional upward movement as these new projects come out with new liquefaction capacity.

And you just continue to hear all the deals out of Europe, Asia on long-term LNG contracts. So we do think, yes, it could support that. When you think about the Gulf Coast and the New York City gates, for example, you start seeing this high demand in certain specific locations, and it can drive those specific basis points much higher versus Henry Hub, if you think about it as a city gate type equivalent. So yes, definitely thinking there could be some additional upside here.

Phillip J. Jungwirth: Okay. Great. And then on Appalachian differential still $0.90 back in future years despite a bullish in-basin demand outlook. We have seen a lot of consolidation versus the last 10 years. I know you guys do some of the best work on remaining inventory, not just for Antero, but the overall basin. So just wondering if you think it could be different this time in terms of the industry supply response just given we do have a lot fewer players and generally less runway as far as core inventory.

Michael N. Kennedy: Yes, it could be. Good point. We’ll continue to see what transpires. Always seems to be Appalachian supply to meet any local demand. But it’s a fair point of yours. And if that occurs, we’re just very well positioned. Like I said, our original purchase of the Marcellus was really in this dry gas area window, and it’s all HBP, and we have over 10 years plus drilling locations of the highest quality. So hopefully, you’re right, but we’re not going to plan on that.

Operator: Your next question comes from Betty Jiang with Barclays.

Wei Jiang: I have a follow-up to Paul, your comment earlier about pricing on the power supply deal that anything would need to be NYMEX-based. Is there an appetite from the customer standpoint to sign a NYMEX-linked deal if from our understanding is that the market dynamic for Gulf Coast is very different than local, where they source that gas? So just wondering how competitive is that pricing discussion and appetite for a NYMEX-linked deal?

Michael N. Kennedy: Well, you saw how much demand, like we mentioned, it’s over 5 Bcfs a day. So ultimately, they’re going to have to secure their supply and we’re the second largest producer in the basin with all those attributes that I talked about, and I think only we’re the — there’s only 2 investment-grade counter parties as well and only 2 with upstream and midstream together. So if they want to secure the supply and be with that type of producer, obviously, we would have leverage because all of our other pricing is on NYMEX and really don’t need to sell anything at a local basis.

Wei Jiang: Got it. And would you mind talking a bit about the power dynamic going on in the West Virginia area just because we have seen all the deals happening in Pennsylvania? I understand there’s legislature that’s being signed that’s supporting power development in West Virginia as well. So does that position you guys specifically for the opportunities arising in the region?

Michael N. Kennedy: Yes, they just passed that Microgrid Bill in West Virginia to allow for more ease of development around these data centers in the AI build-out. So that was in direct response to this. So they are trying to position West Virginia favorably, and I think we are in a favorable position.

Operator: And there are no further questions at this time. I’ll hand it back to Brendan Krueger for closing remarks.

Brendan E. Krueger: Yes. Thank you for joining us on today’s call. Please reach out with any further questions. Thank you.

Operator: This concludes today’s conference. All parties may disconnect. Have a good day.