Q2 2025 Antero Resources Corp Earnings Call
Operator: Greetings and welcome to the ANTERO RESOURCES Second Quarter 2025 earnings call. At this time, all 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 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.
Greetings and welcome to the Antero resources, second quarter to 2025 earnings call.
At this time, all 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 *0 on your telephone keypad.
Please note this conference is being recorded.
Brendan 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; David Cannelongo, Senior Vice President of Liquid Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.
I will now turn the conference over to our host, Brendan Krueger Vice President of Finance. Thank you. You may begin.
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 like to direct you to the homepage of our website at www.to resources.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 Longo
Paul Rady: Thank you, Brendan, and good morning, everyone. Let's start on slide number three titled Efficiencies Reduce 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, the 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 53 cents per MCFE. This is 27% below the peer average of 73 cents per MCFE.
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
Thank you, Brandon and good morning everyone.
Let's start on. Slide number, 3 titled efficiencies, reduce maintenance capital.
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 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 9, 900 million dollars to 663 million.
The chart, on the right hand side of the slide highlights, this Capital efficiency relative to our peers.
And Antero has the lowest maintenance cap per Mcf of its peer group at just $0.53 per Mcfe.
Paul Rady: Now, let's turn to slide number four 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 break-even 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, Dan Cannelongo, for his comments. Dave.
This is 27% below, the peer average of 73 cents per mcfe.
Now, let's turn to slide number. 4 to discuss our updated hedges.
During the quarter, we added additional wide natural, gas Costless collars.
For the year 2026.
These white collars lock in attractive rates of return, with a floor price of $3.14 and a ceiling of $631.
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 Civic significant exposure to rise in that natural gas prices.
These Hedges lower, our 2026 free cash flow Break Even to a $1.75 per mcf.
David Cannelongo: Thanks, Paul. I'll start on slide number five titled NGL Pricing Premium. During the second quarter, ANTERO's realized C3 plus 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.
Now, to touch on the current liquids and NGO fundamentals, I'm going to turn it over to our senior vice president of liquids marketing and transportation. Dan can Longo for his comments today.
Thanks Paul.
I'll start on slide number 5 titled, NGL pricing premium.
During the second quarter and to realize C3 plus plus 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 from butane beginning in September and for propane, beginning in October.
David Cannelongo: 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 plus realizations improve year over year as a percentage of WTI, showing strengthening underlying fundamentals in NGL markets. In the second quarter of 2025, ANTERO's C3 plus 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 mock value, 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.
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 a dollar per.
The $2.50 per barrel with the fourth quarter, anticipated to realize the strongest premium of the year.
I will also point out that in terms of C3 Plus realizations improve year-over-year as a percentage of WTI.
Showing strengthening underlying fundamentals and NGL markets.
And the second quarter of 2025 in to C3 plus realizations, average. 59% of WTI compared to the second quarter of 2024 when realizations were 50% of WTI,
On the export side in Tarot is locked, in a substantial portion of our export volume, at Double Digit premiums, to mod value, and we continue to benefit from those deals.
David Cannelongo: This was clearly evident during the second quarter, as reflected in the relative NGL strength versus WTI. We anticipate that new trade deals signed in the coming weeks and months will increase confidence in the reliability of US LPG supply and help strengthen export volumes and benchmark pricing further. Uncertainty surrounding trade negotiations had a significant but transitory impact on the global NGL market during the quarter. For LPG, the market saw a shift in trade flows with relatively more US 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 US 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 we've talked about in Prior earnings calls when doc 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 that new trade deals signed in the coming weeks and months will increase confidence in the reliability of us. LBG Supply and help strengthen export volumes and Benchmark pricing further
Uncertainty surrounding trade negotiations, had a significant but transitory impact on the global NGL market during the quarter.
For LPG. We the market saw a shift in trade flows from with relatively more us. Barrels going to Japan, South Korea and Indonesia and China sourcing more at LPG from the Middle Eastern Canada.
These changes were largely anticipated by the market as we discussed on last quarter's earnings call.
Despite the destination reshuffling overall us. Propane, exports remain, strong and increased year-over-year.
David Cannelongo: As shown on slide number six 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 in mock value 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.
Average over 1.8 million barrels per day which is 6% higher than the same period last year.
Brendan Krueger: 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 Plaquemine LNG facility. This July, the facility achieved a daily record for feed gas at over 2.9 BCF per day, which represents 120% of phase one nameplate capacity. Now, Venture Global is starting LNG production at phase two of the terminal, which will increase nameplate capacity to 3.6 BCF. This initial production is ahead of prior expectations, with full phase two 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 number seven titled Not All Transport to the US Gulf Coast is Equal.
Coast export capacity that has just been placed in service is expected to lead to higher exports, a rebalancing of inventories, and further strengthening amount value 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.
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 plaque and LNG facility.
This July the facility achieved a daily record for feed gas at over 2.9 BCF per day.
Which represents 120% of phase 1 name plate capacity.
Now, Venture Global is starting LNG. Production at Phase 2 of the terminal, which will increase increase name plate capacity, to 3.6 BCF.
This initial production is ahead of prior expectations, with full Phase 2 and 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.
Brendan Krueger: 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 number eight 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 startup of Plaquemine Phase Two, Golden Pass, Corpus Christi, and Calcasieu Pass Phase Two. 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 Appalachia regional power demand trends.
As shown on slide number 7, titled "Not All Transport to the US 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, Ontario has 570 MNC a day of capacity on the TTP 500 left.
Slide number 8 guides 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 startup of plaque and Phase 2, golden pass.
Corpus Christi and kalashi. 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.
Brendan Krueger: Turning to slide number nine 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 is 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 a firm transportation to the US 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.
Now, let's shift, topics from near-term LNG, demand to the medium-term, Appalachia Regional power demand trends.
Turning to slide number 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 is a lot of work to be done. We anticipate the acceleration and power demand announcements to continue.
resulting in significant opportunities for onto
And Taro remains advantage in this power demand story with our extensive resource base integrated Midstream assets and investment. Grade balance sheet.
Brendan Krueger: With that, I will turn it over to Mike Kennedy, CFO of ANTERO Resources.
Through our firm transportation, to the US 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.
Paul Rady: 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 when 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.
With that, I will turn it over to Mike. Kennedy CFO of the Interior resources.
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 dollars of free cash flow, nearly 200, million of which we used to reduce that.
Once again, we continued our opportunistic share repurchases. Accelerating our BuyBacks during periods when 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, which provides us with substantial flexibility.
With this flexibility, we can pivot between share buybacks or debt reduction depending on market conditions.
Paul Rady: Let's turn to slide number 10 titled ANTERO has the highest exposure to NYMEX linked pricing. Justin already highlighted the 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 realized prices well back of NYMEX due to inbasement 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 premiums to NYMEX, we are unlikely to spend growth capital for inbasement pricing.
Year to date. We have now reduced total debt by 30% or 400 million dollars. While also repurchasing 150 million dollars of shares
Let's turn the slide. Number 10 is titled and to has the highest exposure to 9x, linked pricing.
Ing, through the end of this decade.
We expect Regional pricing will remain volatile.
with with sustained periods, trading at a steep discount, the 9x due to pipeline constraints and seasonality impacts
this chart highlights in Tara's peer leading, exposure to 9x.
Realized price is well, back of 9x due to in-base and exposure. We expect real realized prices at a premium to Nyx,
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 at sells our natural gas at premiums to Nyx.
Paul Rady: Slide number 11 illustrates that over the last 10 years, any regional basis tightening has been short-lived, given robust Appalachia supply and pipeline takeaway constraints. However, if regional demand were to lead to a sustained improvement in inbasement pricing, we have over 10 years of dry gas drilling inventory where we could accelerate activity to grow volumes in a short timeframe and capture that higher regional pricing. With that, I will now turn the call over to the operator for questions.
We are unlikely to spend growth capital for in-base and pricing.
Slide number 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 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,
Operator: Thank you. And at this time, we will conduct our question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star followed by two 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. Our first question comes from Arun Jayaram with JP Morgan. Please state your question.
With that, I will now turn the call over to the operator for questions.
Thank you.
And at this time, we will conduct our 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 followed by 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.
Our first question comes from a room jaram with JP Morgan. Please State your question.
Arun Jayaram: Yeah. Good morning, gentlemen. Maybe for Dave. Dave, I wanted to see if you could maybe elaborate on slide six, where we're going to see some additions to Gulf Coast LPG export capacity. Your thoughts on the implications for Mount Bellevue pricing and just the international versus Mount Bellevue spread next year and how this will maybe shape some of your marketing efforts?
David Cannelongo: Yeah. Good morning, Arun. You know, 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 buildout in new export capacity. And we've talked about in the past, you know, during those times, you see the DOT premiums be fairly modest and tied to Mount Bellevue pricing. But the result of that is Mount Bellevue is as closely linked to the international price as it can be. And so that's what we expect with the buildout 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 DOT capacity coming online in the US really should de-bottleneck us for the foreseeable future.
Yeah, good morning gentlemen. Um maybe for 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 uh export capacity, your thoughts on the implications for mont Bellevue pricing and just the international versus uh Mountain Belleview spread next year and how this will maybe shape, you know, some of your marketing efforts.
Yeah, good Morning Maroon. Um,
you know, we've seen this this uh Dynamic play out a few a few times as you see in the chart going back to 2020 2021 where you have
David Cannelongo: As a result of that, you know, I think the premiums of the DOTs will be more modest going forward, but we'll see overall higher benchmark as a result, which, you know, for ANTERO, with the domestic exposure that we have, in the end, higher Mount Bellevue prices is net net better for us than strong arms.
A sizable build out, new export capacity, and we've talked about in the past, you know, during those times, you see the dot premiums, be fairly modest, um, and trying to, uh, to mount belly pricing, but the result of that is, Bob, belly was, as, as closely linked to the international price as it can be. And so, that's what we expect with the, the build app that you see there from, uh, parties to stay there through 2026. And obviously, there's another um, uh, Consortium that's working on another. Another large export project in the Gulf. So a significant amount of export dock capacity coming online in the US really should be bottled like us for the, the foreseeable future. Um, as a result of that, if you know, I think the uh the premiums of the docks will be will be more modest going forward. But we'll see overall higher Benchmark as a result which, you know, for onto with the domestic exposure that we have in the end, higher amount value prices. It's uh net net better for us than strong arms.
Arun Jayaram: Got it. Got it. And maybe one for Mike. You guys continue to kind of walk and chew gum in terms of reducing your already, you know, low debt balances and buyback stock. You know, based on your view, Mike and Paul, of the fundamental picture, how do you, you know, how do you gauge, you know, the mix of maybe buybacks and debt, you know, reduction going forward?
Got it, got it. Uh, and maybe 1 for for Mike uh you guys continue to kind of walk and chew gum in terms of reducing you're already, you know, low debt balances and and and buy back stock uh you know, based on your view Mike and and Paul of the fundamental picture. How how do you how do you, you know, how do you gauge?
Paul Rady: 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, you know, four or five months, which really, you know, the ANTERO Resources stock price was not reflecting our strong fundamentals. So we took advantage of that and started to buy back 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, if 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.
You know, the mix of maybe BuyBacks and debt uh, you know, reduction going forward.
Sure, Ren, we we came into the year thinking that first 600 million of the free cash flow is going to be used to.
Uh, reduce that.
Uh, then we saw some Market dislocations.
Over the past, you know, 4 or 5 months, which really the, you know, the interior Resources stock price was not reflecting our our strong fundamentals. So we took advantage of that and started to buy back early. Uh we'll continue to do that the opportunistic. Uh, we continue want to reduce that, we're at 1.1 billion, we'd like to reduce that further, of course,
Continue this locations in the stock but we'll continue to buy that. So it's kind of a mix just depending on market conditions.
Arun Jayaram: Great. I'll turn it back.
uh, but we were happy to be able to buy in stock where we have so far this year
Great, I'll turn it back.
Operator: Your next question comes from John Freeman with Raymond James. Please state your question.
John Freeman: Thanks. Good morning. You know, y'all highlighted, you know, the last few years, y'all have 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, you know, maybe 2026, do y'all have the ability, you know, directionally to keep pushing that maintenance CAPEX lower?
Your next question comes from John Freeman. With Raymond James, please State your question.
Paul Rady: Yeah. Yes, we do. You know, 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 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 costs next year. So our well costs continue to decline, and we continue to drill them faster. And so I think that continues into '26.
Thanks, good morning. Um, you know, y'all highlighted uh, you know, the last few years y'all been able to, to meaningfully, reduce the, uh, the maintenance capex while uh, still moving the production higher, uh, just at a high level, just how we should think about you maybe 2026. Do you all have the ability, you know, directionally to keep pushing that that maintenance capex lower.
Yeah, yes we do. Um,
You know, this year, I think are well costs are down, 3% year-over-year and we continue to drill them in a in a quick and complete. I'm in a very quick fashion um, that 3% Decline. And that's on a per foot basis, is actually on a bit shorter, laterals, and it's 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 and 15,000 foot range. So just assuming all things equal, uh service costs equal no more efficiencies which I don't expect to happen. Uh that would lead to a further 3%. Decline in what cost next year. So you're well cost continue to decline. I'm going to continue.
John Freeman: That's great. And then my follow-up question, you know, 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 y'all able to sort of talk to that?
You need to drill them faster. And so I, I think that continues in the 26th.
Paul Rady: Yeah. We have a similar uplift from that as well. We have a lot of tax attributes, a lot of NOLs from the past, a lot of R&D tax credits. But with the new bill, you know, you're able to expense all the R&D expenses without some limitations. There's better interest expense treatment. It's 30% of EBITDA versus EBIT, also a 100% bonus depreciation on lease and well equipment. So you combine all that with our tax attributes that we carried forward, and we do not expect to pay any material cash taxes for the next three years. So it's pushed out at least until 2028 based on today's commodity prices.
That's great. And then uh my follow-up question. Uh you know some of your peers uh this earning season have talked about kind of the uh the pretty big uplift to cash flow. Uh due to the toxin pakta, the recent tax changes are, uh, are you all able to sort of talk to that?
Yeah, we have a similar.
John Freeman: Great. Thanks. Appreciate it.
Uplift from that as well. We have a lot of tax attributes, a lot of benefits, uh, from the past a lot of R&D, uh, tax credits, uh, but with the new bill, you know, you're able to expense all of our and the expenses without some limitations, uh, there's better, uh, interest expense treatment, it's 30% of ibida versus ebit also, 100% bonus depreciation on lease and well equipment. Uh, so you combine all that with our, the tax attributes. So we carried forward and we did not expect to pay any material cash taxes for the next 3 years. So it's pushed out at least until 2028 uh, based on today's commodity prices.
David Cannelongo: Sure.
Great, thanks. Appreciate it.
Arun Jayaram: Your next question comes from Doug Leggate with Wolf Research. Please state your question.
Doug Leggate: Good morning, guys. Thanks for having me on the call. 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, you know, 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 different? Am I thinking about that the wrong way?
Your next question comes from. Doug legate with wolf research. Please State your question.
Uh good morning guys. Thanks for having me on the call. Um 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 and so you can understand the context 1 of your large peers talked about 10 years of
You know significant deferred tax. Um is it fair to say that you guys are not subject to the AMT?
Paul Rady: Yeah. We're not subject to AMT. We're aware of the treatment. We don't qualify. I think you have to have a three-year average of $1 billion of PI, so we're not in that bucket. This bill also makes IDCs deductible for AMT purposes, so that further helps. So that may be what they're suggesting, but we are not subject to AMT. I do not forecast to be subject to AMT.
Um, the corporate Alternative Minimum Tax, which basically means that the treatment is probably a little different or is that am I thinking about that different? Am I thinking about that the wrong way?
Yeah, we're not subject to the AMT. We're aware of the treatment.
Um we don't qualify. I think you have to have a 3 year average of a billion dollars.
Doug 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 a mix here that is changing as it relates to what you're targeting as perhaps the macro gets a little better on the on the gas side as opposed to on the liquid side? But, and I guess my end goal here is to try and figure out how much is it like a target or a level you can say, "We think it can get to this level on a sustained basis going forward." Any color on on the magnitude of any continued improvement would be really helpful.
Of ghee. So uh, we're not in that bucket. This bill also makes idc's deductible for a AMT purposes, so that further helps so that maybe what they're suggesting, but we are not subject to a and he did not forecast to be subject to AMT.
No, it's very helpful. That wasn't actually my primary question. I was just opportunistic given the last 1, but my, my primary question is, is actually back to the sustaining Capital issue that we we've watched this from a far for quite some time, get better every year and my my question is um,
Paul Rady: Yeah. Actually, maintenance capital should continue to improve. Everything else is equal. I mentioned the lateral lengths, but also every year you're at 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 you're below where we're at, and you continue to go go lower each year. So that should continue on a on a target mix. We continue to favor the the liquids 1,275. We had some DUT 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.
Is there, is there anything a mix here? That is changing, as it relates to what you're targeting. As perhaps the macro gets a little better on the on the gas side as opposed to on the liquid side. But um and I I guess my my um end end goal here is to try and figure out how much is, is there a like a Target or a level? You can say, we think it can get to this level on a system basis, going forward? Any, any color on on the magnitude of any continued Improvement? That'd be really helpful.
yeah, actually maintenance Capital should
Paul Rady: But that should return to kind of in that high, you know, around 10,000 barrels a day in the Q4 with liquids staying, you know, 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.
Doug Leggate: That's a great message, guys. Thanks so much.
And so, when you actually look in the out years to maintain this, you're you're below where we're at and you continue to go, go lower each year. So that should continue on a on a Target mix. We continue to favor the the liquids 1275, we had some duck dry, gas pads or lean gas pads that we completed in late first quarter and early, third quarter, uh, which has that mix at least the condensate a bit off. Um, but that should return to kind of that high, you know, around 10,000 barrels a day and the Q4 with liquids. Staying, you know, the same. So uh, the mix uh, really just talk to continue to Target 1275 BTU but our maintenance Capital continues to thick low or not only from our Capital efficiencies, but from longer laterals. And also lower declines.
Paul Rady: Thank you.
That's a great message guys. Thanks so much.
Operator: Your next question comes from Greta Dreska with Goldman Sachs. Please state your question.
Thank you.
Betty Zhang: Good morning, and thank you for taking my questions. I first just wanted to touch on hedging here a little bit, given that you leaned into some more callers 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?
Your next question comes from Greta. Dresa with Goldman Sachs, please State your question.
Good morning, and thank you for taking my call.
Paul Rady: Yeah. Good question. So '26 was unique. Never seen in my career where you could get a two-to-one call skew on a contango curve that's a dollar 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. It's putting in, you know, the $3.25 downside to $7 upside. So, that was attractive. If that dynamic would present itself in '27, that'd be something we're interested in. But, you know, we have low debt. We don't have any inbasement price exposure. We have the lowest maintenance capital.
call. I first just wanted to touch on hedging here a little bit given that you leaned into some more callers 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 Ford curve does give you that opportunity
I got a question for 26 with a unique, never-seen-in-my-career opportunity where you could get a 2-to-1 call SKU on a contango curve. That's a dollar 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. 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.
Paul Rady: So it's not something that's needed, but if you get those types of dynamics in the gas market, it seems prudent to, you know, put some hedges on. You know, we're only 20% hedged, but to have upside to $7, that was a good trade.
Betty Zhang: Great. I appreciate that, caller. And then to 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?
It's putting in, you know, the 3 quarter, uh, downside to 7, uh, upside. So, uh, that was attractive if that Dynamic would present itself in 27, that'd be something we're interested in but, you know, we don't we have low debt. We don't have any Invasion price exposure. We have the lowest maintenance Capital, so it's not something that's needed but if you're if you get those type of Dynamics in the gas market, seems prudent to you know put some Hedges on you know we're only 20% hedge but have upside to 7 dollars. That was a good trade.
Paul Rady: Yeah. We'd ramp up really on the 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 continue to have a lower debt. We do have a 2030 note that it's 600 million at five and three-eighths. 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'll 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.
Great. Appreciate that caller. And let's 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 into a return of capital and maybe towards 75% or so?
Yeah, we drop a ramp up really on the the, the stock price compared to underlying fundamentals. We're now in a position where we can, we could use all of our free cash flow to do that. If that was an opportunity for us,
Uh, we do want to continue to have lower debt, uh, we do have a 2030 note that it's 600 million at, uh, 5 and 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 uh, we would pay down right now.
Betty Zhang: Great. Thank you.
Um so it'll just depend on market conditions but we're very uh happy to continue to accelerate our share buyback and actually go higher. If if there's an opportunity
Great. Thank you.
Operator: Your next question comes from David Dekelbaum with Cowan. Please state your question.
David Dekelbaum: Morning, everyone. Thanks for taking my questions today. Mike, not to belabor the point, but maybe just like if I were to summarize just the return of capital thoughts, just considering the fact that your outstanding notes for it are all callable, you know, and you can redeem, you know, 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?
Your next question comes from David Deco bomb with Cowen. Please stay your question.
Uh, morning everyone. Thanks for taking my questions today.
Um, you know, Mike not to belabor the point but maybe just like if I were to summarize, it's just the returner Capital thoughts. Um just considering the fact that you're you're outstanding notes, right are all callable. Um,
Paul Rady: Yeah. You know, what we'll 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. You know, we have so much room under the facility. It's basically undrawn today. So we could call it in, no problem, continue to buy back. 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.
You know, and you can redeem, you know, 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.
Yeah you know but 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
David Dekelbaum: Appreciate that. Maybe if Dave can take this one. I'm just curious, Dave, you know, with the benefits in the second half of this year on C3, excuse me, C3 plus realizations, with the added LPG capacity, is the anticipation that that premium to Bellevue is pretty sustainable into '26, where there'd be perhaps just a greater mix going international?
valuation is of Ontario. And if that's an opportunity for us, uh, we'll act on that. So that's really what we think about. We could call those notes in right now. Uh, just under the credit facility. You know, we have so much room under the facility. It's basically on Drawn today so we could call it in no problem continued to buy back. But like I said, we're really just trying to be opportunistic and it's it is an opportunity when you see the stock at these levels versus the underlying business.
David Cannelongo: Yeah. I think, you know, for Bounce 25, obviously, we've got things locked in, but '26, domestic and international kind of remains to be contracted. So we'll be in the market, you know, getting what those prevailing prices are at that time. And we do expect it'll be lower than what we saw here in '25 when we talked about, you know, double-digit premiums in '25. You don't typically see that with ample dock capacity. So you go back to, you know, 2020 to '22, you're probably averaging, you know, 6 to 7 cent premiums during that time period. So that'll certainly be reflected in our realizations next year. And, yeah, I would expect that to come down modestly in '26 versus '25.
Excuse me, C3 plus realizations with the added LPG capacity, is the anticipation that the premium, the value view, is pretty sustainable into 2026? Will there be perhaps just a greater mix going international?
David Dekelbaum: Appreciate it, guys.
Yeah, I think, uh, you know, for, for balance 25. Obviously, we, we've got things locked in, but, but 26, uh, domestic and international kind of remains to be contracted, so we'll be in the market. Um, you know, getting what, what is prevailing prices are at that time? And we do expect, it'll be, uh, lower than what we saw here in 25. When we talked about, you know, double digit premiums 25, you don't typically see that with ample doc capacity. So you go back to, you know, 2020 and 222. You're probably averaging, you know, 6 to 7 Cent premiums during that time period. So that'll certainly uh, be reflected in our, uh, realizations next year. And, uh, you know, I would expect that to come down modestly in 26 versus 25.
Paul Rady: Thank you.
Appreciate it, guys.
Operator: Thank you. And just a reminder, to ask a question, press star one. Your next question comes from Kevin McCurdy with Pickering Energy Partners. Please state your question.
Thank you.
Arun Jayaram: Hey. Good morning. Production in 2Q was a little gassier compared to the prior quarters, and it looks like the production raise was most 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?
Thank you and just a reminder to to ask a question. Press star 1, your next question comes from Kevin.
Paul Rady: Yeah. So we brought on two DUT pads that we talked about quite a lot over the past conference calls. One of them was brought on at the end of the first quarter, and these were lean gas pads, more in the 1,200 BTU range. And then the second one was brought on in July. So second and third quarter were always expected to be a bit gassier, but that reverses, like I mentioned, into the fourth quarter. You get back to that 10,000 barrel a day of condensate and liquids continues to increase. So, you know, 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.
Hey, good morning. Um production in 2q was a little gassier compared to the prior quarters and it looks like the production rate is most related to to gas volumes. Uh 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?
yeah, so we brought
A pads that we've talked about quite a lot of them over the past conference calls 1 of them was brought on at the end of the first quarter and these were lean gaps pads.
Arun Jayaram: Got it. Appreciate the detail on that. And then as a follow-up on the, you know, on the callers, I mean, that was a very impressive skew on the '26 callers. You know, does that echo kind of your internal view on gas with the, you know, the more upside to downside in '26? And just wanted to get your, you know, your current thoughts on any changes to your medium-term macro view based on how kind of storage and production has trended this summer.
I'm more than 12200, BP range and then the second 1 was brought on in July. So second and third quarter were always expected to be a bit gassier. Uh, but that reverses like I mentioned in the fourth quarter you get back to that 10,000 Barrel day if K as condensate and liquids continues to increase. So you know going forward all the all the pads were bringing on. For the remainder of the year, are more like the 1275 B2 so that'll reverse going into the fourth quarter.
Paul Rady: Yeah. No, that made sense to us just because the skew is definitely to the upside. The margins today are razor thin. There are, there is no volumes that are shut in. Everything's producing full out. You've had a lack of investment in the gas development over the last two years. Rate 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 did make sense to us. But, you know, we're just locking in 20% and taking advantage of that and basically funding your capital program while still maintaining upside to $7 and still maintaining 80% upside exposure was something that appealed to us, lowering our free cash flow break-even already the lowest down to $1.75.
Got it, appreciate the DCL on that and then as a follow-up on the you know on the collars. I mean that that was a very impressive SKU on the 26th collars. Um, you know, does that Echo kind of your internal view on gas with the, you know the more upside to downside in 26 and just wanted to get your you know your current thoughts on or any changes to your medium-term macro view based on how kind of storage and production is trended this summer.
Yeah, I don't know that made sense to us just because the skew is definitely to the upside of the margin today or razor thin. There are there is no volumes that are shut in. Everything's producing full out, you've had a lack of uh, investment in the gas uh, development over the last 2 years. Recounts are still subdued. So
Anything could, uh, could tip this to the upside.
Paul Rady: So we thought we should take advantage of that. And like I mentioned, I've never seen that in my 30-plus-year career, that kind of call skew on a contango strip. So if that would present itself again, I think we'd just continue to act just because it's so attractive, but definitely skewed to the upside.
Arun Jayaram: Appreciate that. Thank you.
If you have an early winter, if you have any sort of winter next year, you could definitely see the uh, gas going much much higher so it didn't make sense to us, but, you know, we just locking in 20% and taking advantage of that and basically funding your Capital program. Uh, while still maintaining upside to 7 dollars and still maintaining 80% upside exposure with some something that appealed to us lowering our free cash flow Break Even already the lowest down to a1.75. So we thought we should take advantage of that and like I mentioned, I've never seen that in my 30 plus year career, that kind of calls you on a, a Tango, uh, strip. So, uh, if that would present itself, again, I think we could just continue to act just because it's so attractive, but definitely skewed to the upside.
Paul Rady: Sure.
Appreciate that. Thank you.
Operator: Your next question comes from Leo Mariani with Roth. Please state your question.
Arun Jayaram: Yeah. Hi. Obviously, you guys mentioned some of the, you know, inbasement demand projects. Really appreciate that slide there. Obviously, some new projects recently announced by one of your competitors here. You maybe provide maybe some some color on where ANTERO is in that, you know, sort of scheme here. I assume that you guys are also talking to new inbasement sources of demand. So can you kind of give us a bit of an update on kind of where you guys stand there?
Your next question comes from Leo. Marani with Ross, please get your question.
Paul Rady: Yeah. No, good question. You know, 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. You know, how does ANTERO play a role? I mean, we're so uniquely positioned. You know, some of the attributes we have, you know, 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 is 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.
Yeah. Hi. Um, obviously, you guys mentioned some of the uh, you know, in Basin uh demand projects. Really appreciate that slide there. Uh obviously some some new projects recently announced uh by 1 of your competitors here. You maybe uh, provide maybe some some color on wear and Tarot is uh, in that uh, you know, sort of scheme here. I assume that you guys are also talking to, to new in Basin, uh, you know, sources of demand. So can you kind of give us a bit of a, an update on kind of where you guys stand there?
You know, how does Intel play a role? I mean we're so uniquely positioned. You know, some of the attributes we have you know we have the integration between the upstream and midstream
Paul Rady: We also, as we always mentioned, we have the 500,000 acres, you know, decades of core Marcel's 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, and they're terrific over there, so they'll be able to capture any opportunities. And we also have the investment-grade balance sheet, which, you know, which is important for long-term kind of arrangements. But, you know, with it being a long-term deal, we're really not attracted to any deals that are based on local pricing. It's going to have to be accretive to our overall store and our overall pricing. Doing deals just at local has never been exciting for us. You know, we would always be cautious around putting hundreds of millions of dollars behind development to fund a local pricing deal.
Uh, 1-stop shop. There also importantly that no 1's, uh, 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, uh, 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. Uh, we also as well as mentioned we have the 500,000 Acres, you know, Decades of core Marcel's inventory right there, hvp, uh, Legacy production. So, uh, able to satisfy that, uh, we, we, we have what we think is the best Natural, Gas marketing team in the business. You've got exposure to Justin, um, and they're terrific over there, so they'll be able to capture any opportunities, and we also have the investment grade balance sheet, which, you know, which is, uh, important for long term, kind of arrangements. But, you know, with it being a long-term deal, uh, we're really not attracted to any deals that are based on local pricing.
Paul Rady: This thought has kind of driven our whole strategy from day one and what's created our firm transportation portfolio strategy. We put that slide there. Anytime there's been local tightening of basis, it's always been met with incremental supply and incremental development because there's really no barriers to entry to to feed that local gas and how prolific the Marcel's is. So anything that, you know, we would do would have to be NYMEX-based or accretive to our pricing. If it 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. Paths are already built. Infrastructure is 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.
Um it's going to have to be a creative to our overall store and our our overall pricing um, doing deals, just at local has never been exciting for us. You know, we would always be cautious around putting hundreds of millions of dollars behind development to fund a local pricing deal.
Um this is thought it's kind of driven our whole strategy from day 1 and what's created our firm Transportation portfolio strategy. We put that slide there. Any 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 to feed that local gas and how prolific the Marcellus is. So um anything that you know we would do would have to be 9x based or creative to our pricing if it 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. Paths are already built infrastructure already there,
um, so we will be a participant. We're uniquely advantaged like, I mentioned with all those attributes.
Arun Jayaram: Okay. I appreciate that. Just wanted to follow up on that there, though. You know, are you guys maybe in any, you know, somewhat advanced discussions with inbasement demand sources, and you think there's potential for some, you know, 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?
Um, but it's going to have to be a creative story.
Paul Rady: Yeah. 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, you know, 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 the natural gas demand growth over the kind of short to midterm. So, you know, 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, you know, it's not like we need to announce deals around that. We'll be cautious in announcing at the appropriate time and entering the appropriate deals and not rush to enter into any.
Okay, I appreciate that. Um just wanted to to follow up on that there though. Uh you know are you guys maybe in any you know somewhat Advanced discussions with in Basin demand sources and you think there's potential for some uh you know announcements and in the near future call in a matter of months as opposed to to years just trying to see if we can get a a little more color around where you guys are in the process.
Yeah, 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
Arun Jayaram: 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, you know, 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?
To remind you you know we have all the firm transport or 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 the natural gas demand growth over the the kind of short to mid-term. So you know where unique we have that exposure but we also are going to have exposure to the local demand from the data center uh growth. So you know, it's not like we need to announce deals around. That will be cautious and announcements appropriate time and enter in the appropriate deals and not rush to enter into any
Okay, very helpful on that point, and then just quickly on, um, shareholder returns here. Um, obviously you don't have that much more debt to pay off as you be. Enumerated somewhere around, you know, 500 million or so. Um, 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
Paul Rady: Yeah. I think you're already seeing that, you know, we basically are already 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. And yeah, we'll continue to buy back in size as we move forward. 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.
Obviously, you've done the buyback, but could there be a dividend in place at some point as well?
Arun Jayaram: Thank you.
Yeah, I think you're already seeing a, you know, we basically already are at the point where we don't need to reduce debt any further, it's more just being, uh, driven by market conditions, uh, so we'll continue to do that. And, you know, we we, we continue to buy back in size, uh, as we move forward, uh, I haven't thought about a dividend that's also going to be Market based and market conditions. Uh, really just been focused on uh, that that reduction in getting the share count as well as we can.
Thank you.
Operator: Your next question comes from Philip Jungworth with BMO Capital Markets. Please state your question.
Thank you.
Arun Jayaram: Thanks. Good morning. You noted how CAL 26 for the TPG 500 leg has increased to 60 cents. That's higher year-on-year up from your last update. Just with Plaquemine's 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 sit, and anything to keep in mind as far as incremental supply going to this price point?
Your next question comes from Philip Jeong worth with BMO Capital markets. Please your question.
David Cannelongo: Yeah. Good morning, Philip. Justin Fowler here. As we look out at the next couple of years, we definitely think that, you know, Plaquemine 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 Plaquemine LNG, we've already seen those basis locations at CGT Onshore and our southeast start to trade a premium as we look out in the forward.
Increased to 60 cents. Um, the tire year on year uh, up from your last update, um, just with plaque and ramping further into next year. Wondering if there's a theoretical stealing, you guys think about, for how high this premium could get considering the LNG demand pole and we're a global gas. Price has said and anything to keep in mind as far as incremental Supply, uh, going to this price point.
David Cannelongo: So if you just look at history there and understand that there's only a finite amount of gas that can get to Plaquemine 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 on 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. You know, 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, you know, as a city gate type equivalent.
Yeah, good morning. Philip, Justin Fowler here. Um, as we look out at the next couple of years, we definitely think that, you know, plaque and plus the local power gin could continue to pull that basis up. Um, we saw that basis accelerate so quickly and when we think about our other delivery points for example, Columbia Golf onshore which is also correlated with plaque and LNG, we've already seen. Um, those basis locations at cgp onshore and our Southeast start to, um, train a premium as we look out in the forward. So if you just look at history there and and understand that there's only a finite amount of gas that can get to proc them in and then the other um LNG facilities that we can again, highly correlate.
David Cannelongo: So yes, definitely thinking there could be some additional upside here.
Arun Jayaram: Okay. Great. And then on Appalachia differential, still 90 cents back in future years despite a bullish inbasement 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.
To anteros to DCF of FP, delivery to the Gulf Coast. Um, we definitely think that there could be uh, additional upward movement as these new projects. Come on with new, liquefaction capacity and use continue to hear all the deals out of Europe. Asia, on long-term, uh, LNG contracts. Um, so we, we do think. Yes. Um, it could support that, you know, when you think about the Gulf Coast and, uh, the New York City gates, for example. Um, you start seeing this high demand, uh, in in certain specific locations and it can drive those specific basis points much higher, first Henry Hub. If you think about it, you know, as a City Gate type equivalent, so yes. Um definitely thinking there could be some additional upside here.
Paul Rady: Yeah. It could be, you know, a good point. We'll continue to see, you know, what transpires. It always seems to be Appalachian supply to meet any local demand. So, but it's a fair point of yours. And if that occurs, you know, we're just very well positioned. Like I said, our original purchase of the Marcel's was really in this dry gas area window, and it's all HBP. And we have, you know, over 10 years-plus drilling locations of the highest quality. So hopefully, you're right, but we're not going to plan on that.
Hey, great. And then on Appalachia differentials still 90% back and and future years despite a a bullish Invasion, demand Outlook. Uh, we have seen a lot of consolidation versus the last 10 years. Uh, I know you guys do. Some of the best work around. Remaining inventory. Uh, not just for enta but the overall Basin. So, uh, just wondering if you think it could be different this time, in terms of the industry Supply response just given we we do have a lot fewer players and and generally less less Runway as far as core inventory.
Yeah, could be, you know, good point. Uh, we'll continue to see, you know, what transpires. Uh, always seems to be Appalachian Supply to meet any local demand. So
Um but it's a fair point of yours. And if is that a curse, you know, we're just very well positioned like set our, our original purchase of
Uh, the Marcellus was really in this dry gas area window and it's all HPP. And we have, you know, over 10 years plus drilling locations of the highest quality. So,
Uh, hopefully you're right, but we're not going to plan on that.
Arun Jayaram: Thanks.
Thanks.
Operator: And your next question comes from Betty Zhang with Barclays. Please state your question.
Betty Zhang: Good morning. Thank you for taking my question. 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 link deal if, from our understanding, 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 link deal?
And your next question comes from Betty Jiang with Barclays, please State your question.
Good morning. Thank you for taking my question. Um I have a follow-up to Paul you comment earlier about pricing on. Um the power supply deal that anything would need to be 9x based um
Is their appetite for the customer standpoint to sign a 9x link deal. If um, from our understanding is that the market dynamics for Gulf Coast is very different
That local where they source that gas.
so just wondering,
Paul Rady: Well, you saw how much demand, like we mentioned, it's over 5 BCF 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 two investment-grade counterparties as well, and only two 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's on NYMEX and really don't need to sell anything at a local basis.
How competitive is that pricing discussion and and appetite for a nmax link deal.
We saw how much the man, like we mentioned. It's over 5 BC FS a day. So, um, ultimately, they're going to have to secure their supply. And uh, we're the second largest producer in the Basin. Um, with all those attributes I talked about in 1, in my pick only,
where the, there's only 2 investment grade counterparties as well and only 2 with upstream and Midstream together. So,
Betty Zhang: Got it. Thanks. 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.First
Uh if they want to secure the supply and and be with that type of producer, obviously we would have leverage because all of our other pricing is on non, don't need to sell anything at a local basis.
Operator: legislature that's being signed that's reporting power development in West Virginia as well. So does that position you guys specifically for the opportunities arising in the region?
Conference Specialist: Yeah. They just passed that micro bid bill in West Virginia to allow for more ease of development around these data centers and the AI buildout. 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.
We have seen all the deals happening in Pennsylvania, by understand. There's legislature, that's, um, being signed that's supporting power development, um, in West Virginia, as well. So does that, um, position you guys specifically for the opportunities arising in the region?
Operator: Okay. Got it. Thanks.
Yeah, they just passed that micro data bill in West Virginia to allow for a more ease of development around these data centers in the AI buildout. 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.
Okay, got it. Thanks.
Rachel Smith: Thanks, Betty.
Brendan Krueger: Thank you. And there are no further questions at this time. I'll hand it back to Brendan Krueger for closing remarks.
Rachel Smith: Yes. Thank you for joining us on today's call. Please reach out with any further questions. Thank you.
Thank you. And there are no further questions at this time. I'll hand it back to Brendan Krueger for closing remarks.
Brendan Krueger: This concludes today's conference. All parties may disconnect. Have a good day.
Yes, thank you for joining us on today's call. Please reach out with any further questions. Thank you.
This includes today's conference, all parties. May disconnect have a good day.