Antero Resources Corporation (AR) Earnings Call Transcript & Summary

Greetings, and welcome to the Antero Resources Fourth Quarter 2024 Earnings Call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the conference over to your host, Brendan Krueger, Vice President of Finance. Thank you. You may begin.

Good morning. Thank you for joining us for Antero's Fourth Quarter 2024 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.

Thank you, Brendan and good morning, everyone. Let me start on Slide #3. And as I introduce this, let me point out that last year, 2024, was a remarkable year for us. The name of the slide is reduced maintenance capital. The chart on the left side shows our full drilling and completion capital that came in at just $620 million as illustrated by the dark green bar in the center of the display. This was $55 million or 8% below our initial guidance and nearly $300 million below our 2023 CapEx of $909 million. Despite this lower spend, our production came in 2% above our initial guidance range, averaging over 3.4 Bcf equivalent per day, as shown on the right hand of the slide. Let's move on to Slide #4 titled Drilling and Completion Efficiencies, which details the drivers behind our exceptional operating performance during 2024. We've highlighted some of these drilling and completion stats in prior calls. The results have continued to improve each subsequent quarter in 2024. And here, we show the full year as compared to the prior 2 years. On the drilling side, shown in the top of the left side of this slide, we reduced the time it takes to drill a well to just 10 days in 2024. This is a nearly 30% improvement compared to the 14 days that we averaged a couple of years ago, that is 2022. On the completion side, shown on the top right-hand side of the slide, we averaged 12.2 completion stages per day in 2024 while once again setting new quarterly records, averaging 15.2 completion stages per day in the fourth quarter of 2024. The annual average represents a 53% increase compared to the completion stages back in 2022. Moving to the chart on the bottom of the slide. These improvements in drilling and completion rates reduced our cycle times to just 123 days, which is 25% below the 2022 level of 163 days. This performance allows us to run a very lean program with just 2 rigs on average and just over 1 completion crew on average in order to hold 3.4 Bcf equivalent per day of production flat. Now to touch on the current liquids and NGL fundamentals side, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo for his comments. Dave?

Thanks, Paul. 2024 was a banner year for Antero, realizing record differentials to Mont Belvieu driven by high LPG export premiums and stronger domestic price differentials in our market area. As seen on the left-hand side of Slide #5, in 2024, Antero realized a $1.41 per barrel premium over Mont Belvieu, the best C3+ differentials in our company's history. The fourth quarter of 2024 was Antero's strongest quarter with our premium to Mont Belvieu averaging $3.09 per barrel. For 2025, we are still expecting high annual export premiums. Those premiums, coupled with our domestic marketing efforts is allowing us to set our guidance for 2025 at levels even higher than 2024's record year, resulting in a range for our C3+ NGLs of $1.50 to $2.50 per barrel premium to Mont Belvieu prices. As we head into 2025, we are forecasting export dock premiums to be higher on a year-over-year basis. We expect more dock capacity to be placed in service at several terminals later in the year However, we believe that as international demand continues to grow and new terminal capacity comes online, more U.S. barrels will be pulled into the export market, resulting in stronger prices at Mont Belvieu. Stronger Mont Belvieu prices directly benefit the realized pricing on Antero's domestic C3+ sales as well. On the domestic marketing front, as seen on the right-hand side of Slide #5, we have continued to enhance our marketing strategy by selling more of our products to key distributors and end users, driving stronger overall pricing. In 2025, we have locked in almost all of our domestic propane sales and a sizable portion of our export sales at an attractive premium to Mont Belvieu. On butane, we have a long-term contract rolling off on April 1 that was historically priced at a steep discount to Mont Belvieu that we have now locked in at nearly Mont Belvieu flat pricing. The shift in pricing in 1 contract alone will result in approximately $10 million in incremental cash flow. We believe this marketing strategy will drive premium pricing on our purity products and contribute to our attractive premiums to Mont Belvieu in 2025 and beyond, as illustrated again by our guidance range of $1.50 per barrel to $2.50 per barrel premium to Mont Belvieu and all of our C3+ volumes. So far this year, we have observed constructive fundamentals that illustrate how sticky propane demand is for both exports and domestic use. On the export side, the U.S. continues to steadily grow with exports averaging 1.8 million barrels per day year-to-date in 2025, as shown on Slide #6. This is 9% above the same period last year. On top of the growing exports, we have observed that during the winter months, domestic propane prices must increase to keep supply from being sold into international markets, ultimately lifting Mont Belvieu prices as well. Last month, the EIA reported a new weekly record for total overall demand, including both domestic and exports, up 3.8 million barrels per day for the week ended January 24. This eclipsed the previous overall demand record by over 250,000 barrels per day and shows that domestic demand still plays an important role in the U.S. propane market. The sustained strong demand this year has pulled propane inventories from the top of the 5-year range to below the 5-year average in a matter of weeks, as shown on the left-hand side of Slide 6. U.S. inventories entered the year 10% above the 5-year average with several weeks of strong demand and robust withdrawals decreased stocks to 1% below the 5-year average by the end of January. Additionally, we saw the second largest weekly withdrawal on record per EIA data at 7.9 million barrels for the week ended January 24. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler to discuss the natural gas market.

Thanks, Dave. I'll start on Slide #7 titled 2025 Natural Gas Storage versus the 5-Year Average. Since our third quarter conference call, we've seen a significant move lower in our natural gas storage balance relative to the 5-year average. At that time, in late October, we were 167 Bcf above the 5-year average. Today, we sit at 111 Bcf below the 5-year average and nearly 200 Bcf below this time last year. We believe today's low rig count, combined with an upward step change in demand will support a continued tightening of inventories that is likely to fall meaningfully below the 5-year range in the second half of 2025. We expect these supportive fundamentals will lead to higher prices in 2025 and 2026. The charts on Slide #8 illustrate the record power burn and ResComm demand we have observed. At the top of the slide, U.S. natural gas demand from power burn have hit monthly records each month of the winter. At the bottom of the slide, you will see U.S. natural gas demand from ResComm was also a January record at over 50 Bcf. Another positive update since our last quarterly call was the highly anticipated startup of the Venture Global Plaquemine LNG facility. The first export cargo at Plaquemines was achieved on December 26 and the ramp-up since that time has been faster than the market expectations. Today, the facility is exporting an average of approximately 1.5 Bcf per day. We anticipate this increasing in the near term following this week's FERC commissioning approvals for liquefaction blocks #7 and #8 and with the request for block #9 filed with the FERC on Tuesday. The pricing impact following the start-up of Plaquemines can be seen on the chart on Slide #9 titled TGP 500L Basis Performance. Looking at the TGP 500L basis, which is the basis hub with the most current exposure to Plaquemine, the quicker than anticipated ramp up of the facility has already lifted summer 2025 pricing by $0.10 per MMBtu compared to the strip pricing before the startup. As the facility ramps up further, you can see the TGP 500L basis increases even further going from a $0.14 per MMbtu premium in March of 2025 to $0.50 premium in calendar year 2026. This 2026 premium reflects a more than $0.20 increase as compared to strip pricing 1 year ago. As a reminder, Antero holds 570,000 MMbtu per day of firm delivery to the 500L pool or 63% of the supply that feeds the Kinder Morgan TGP Evangeline Pass Phase 1 project capacity into Gator Express pipeline that feeds Plaquemine. This $570,000 per day represents nearly 25% of Antero's total natural gas production and is the primary driver behind the increase in our realized natural gas price premium relative to NYMEX in 2025. We expect our premium to NYMEX to be in the range of $0.10 to $0.20, up from $0.02 premium in 2024. Looking out to 2026, we expect this premium to increase further as the continued ramp-up of Plaquemine as well as Corpus Christi Phase 3 and the start-up of Golden Pass are expected to significantly increase the call on natural gas along the LNG portal. With that, I will turn it over to Mike Kennedy, Antero's CFO.

Thanks, Justin. Now let's turn to Slide #10 titled Lowest Free Cash Flow Breakeven. We've updated this slide for the full year 2024. The slide compares 2024 unhedged free cash flow breakeven levels across our peer group. In past calls, we've highlighted our approximate $2.20 breakeven level which benefits from 2 things: first, the low maintenance capital requirements that Paul highlighted in his remarks; and second, our high exposure to liquids and ability to capture premium pricing that both Dave and Justin touched on. The result of these attributes are shown on the left-hand side of the slide. Despite being unhedged at a $2.27 natural gas price, we generated positive free cash flow of $73 million in 2024. Meanwhile, our gas peers with higher breakeven levels show significant outspends. The efficiency gains that we have achieved have a meaningful impact on our operating and financial outlooks, as you can see with our 2025 guidance. We now expect production to be $50 million a day higher than our prior targets while our capital budget is $25 million lower than the maintenance capital program that we had previously communicated in past calls. This low maintenance capital positions us to generate positive free cash flow and down cycles as we experienced in 2024 and to capture significant increases in free cash flow and higher price environments as we see from today's 2025 natural gas strip. I would also like to comment on the hedges that we added during the fourth quarter. After deferring 2 lean gas pads in 2024, we added natural gas hedges that tied to the volumes associated with those 2 1,200 BTU gas pads. Locking in prices above $3 per Mcf assured us that we would capture attractive rates of return from these wells. In addition, this operational certainty provides continuity in our plan, resulting in the most efficient development program and optimizes our midstream infrastructure. We placed the sales of the first DUC pad in late January and the second DUC pad is expected in the third quarter of 2025. During 2025, we intend to add some additional wide collars for 2026 to sync with the expected volumes from our lean gas pads. I'll finish with comments on our compelling free cash flow outlook. We expect 2025 to deliver a substantial year-over-year step change in free cash flow. Based on today's current strip, our guidance would suggest over $1.6 billion of free cash flow in 2025, which represents a compelling 12% free cash flow yield. In 2025, we intend to use free cash flow to first pay down our credit facility in the remaining 2026 senior notes, which as of December 31, 2024, totals just under $500 million. Once this debt reduction has been achieved, we expect to return to our 50-50 debt reduction and capital return strategy via share buybacks. Antero is incredibly well positioned as we enter 2025. Our low absolute debt, minimal hedges and firm transportation that delivers premium price realizations relative to NGL and natural gas benchmarks provides us with the greatest exposure to rising prices. We anticipate a significant call on natural gas over the next 12 months as new LNG facilities ramp up. The ability for supply to respond to this increase in demand is likely to be challenged given the low industry activity levels we have today. With that, I will now turn the call over to the operator for questions.

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

Team, I wanted to ask you a little bit about just the gas macro situation. Given Justin's commentary around the ramp in demand from utility demand as well as the start-up of some of the LNG facilities, clearly going to be a call on -- the market will call for higher natural gas volumes. I was wondering if you could talk about the ability of the Appalachia Basin as well as Antero to respond to, call it, a market call needing more gas volumes to meet the increase in demand?

Arun, this is Mike. Good question. For us, at least the maintenance capital is where we're comfortable at. All of our firm transport under this plan is filled. So -- and we're not really selling any local gas and that's been our strategy since day 1. So for us, the ability to grow to meet that it's not really even possible unless it's in the local basin or right next to our field.

Great. Clear answer there. And then just to follow up, Mike. In the 10-K, you guys highlighted inking a drilling partnership with an unnamed operator, where it looks like they're going to be paying about 15% of your program, are receiving a 15% working interest but funding at greater than 15% portion of your capital -- development capital this year. Can you provide some details on that and just the overall strategic benefits you see from an AR perspective?

Yes, we've had a drilling JV of some sort in place since 2021, the original one concluded in 2024. What we found with the drilling JV benefit besides the carry is also the ability to operate a 2-rig consistent program, have 1 completion crew and a spot crew now and again, for the maintenance capital. So it allows efficiencies around that to have that. And then from a water handling perspective to be able to have optimal water handling within the field and still be at maintenance capital. So we enjoyed that. And so when we came into the second half of 2024, we went out to see if there was appetite to continue that drilling JV and what the terms were. The terms were better than what we found in '21 to '24. So it's a disproportionate carry like the 10-K says and just an upfront carry instead of a back-ended one.

Any more kind of details on the magnitude of the carry?

No, 15% of our -- what is it, $650 million to $700 million, it's like $100 million net to them and they're paying a little bit more than that, obviously, for their interest.

Your next question comes from John Freeman with Raymond James.

First question I had, you all have been pretty clear about -- you all were anticipating having about roughly 12 DUCs with the other 2 pads that you all deferred. And I'm just trying to reconcile with -- it looks like you'll had 17 net wells that were sort of in progress at year-end. So just trying to get some color if it was still 12 DUCs and just a handful of wells in various stages of drilling or if the DUC [indiscernible]

Yes, that's correct. Correct. We brought on 16 wells in January throughout the month. And then we still have 1 DUC pad, like you mentioned, with 7 wells that will be Q3.

Got it. And then the other topic, we've -- obviously all are in a terrific standpoint when it comes to takeaway relative to the peers. We did see some peers this earnings season already that have been able to pick up some incremental FT from some operators as maybe those operators didn't have the inventory or whatever to be able to renew those contracts. Obviously, you're in a great position but is that something that you all are focused on in terms of kind of picking up some of those as they become available to kind of enhance your already strong position.

No. We've got a full FT portfolio. We are a first mover. It goes to all the various regions at very attractive rates and on the best pipe. So we're happy where we're at and just filling our current firm transport portfolio.

Your next question comes from Doug Leggate with Wolfe Research.

This is Carlos in for Doug. First of all, congrats on the quarter. I guess what we'd like to address first is maybe take a moment to revisit your inventory with a specific focus on your liquids runway. So I wonder if you can parse at this point in time, given where we are in the gas macro, how you see your midstream runway given that you have a midstream -- the midstream, you have a captive market to add those liquid rich acreage contracts and leases. So I wonder what your outlook there is.

Yes. Now we've got a good inventory. That's what our organic leasing program. One of the benefits, not only does it increase near-term working interest but also the strategy behind is to replace in the exact areas where we're drilling with further acreage in the liquids window of the Marcellus because of our dominant position owning the midstream, owning all the acreage in that area. We're really the only one that can develop in those areas, so the acreage finds its way to us. So we're able to replace what we've drilled every year. I think last year, it was around 59 locations and we put on sales like 45. Typical years, around 60 is how we think about it. So every year, we can replace the 60 locations we drill is kind of the strategy around the organic leasing. And so when you do that kind of look at our position, it's well over 1 decade of liquids drilling and then assuming we don't add any more acreage, then you would transition to drilling the well over 1 decade of our dry gas position. So over 20 years plus from an inventory standpoint, long duration, long runway. So we're well positioned.

I appreciate the answer. Now I'd like to address real quick and reconciling your completions for this year versus 2024 because in '24, you completed net 41 wells at an average length of 15,700 feet. And for 2025, your outlook suggests 62.5 at the midpoint with shorter laterals than that. So maybe first, if you can address what you're seeing in terms of lateral footage per well and why this is decreasing as it may be counterintuitive for what we expect in the industry that is going into longer laterals. And just to build on that, there's some -- you mentioned 16 wells that have been drilled in January that there's some CapEx presumably prespent in 2024 that doesn't hit in '25 for obvious reasons. So I wonder if you can quantify that capital number.

Yes, all those 16 wells, the vast majority of that capital is in '24. Those were put on in January, turned to sales. So they'd already been drilled and completed in '24. A little bit of capital, obviously, for January but the vast amounts were in '24 related to those 16 wells. So you kind of put that together with the low 40s, the 42 wells we put on with '24 versus this year. And then there's obviously some carry out of '25. But that's why I referenced the 60 wells. It's generally 60 wells per year. You can see that in our proved reserve database. We have 289 PUD locations over 5 years. So when you do the math there, it's around 60 wells. So we do about 60 wells a year. Lateral lengths, we're already the longest. I mean it was over 15,000 feet for '24 which may have been our longest year. Generally, though, it's around 13,000 to 14,000 feet is our typical well. I think this year, we're at 13,800 feet. When you look in the proved reserve database, I think it's a similar number. So 13,000 to 14,000 feet is kind of where we're at. Every year is going to be a slight difference but in and around that number is a great number for us and probably the longest laterals in the basin.

Your next question comes from Bert Donnes with Truist Securities.

Just want to brush on Slide 11. I know it's not necessarily a new slide but just wondering if you've changed any assumptions there. Maybe you could elaborate on if you're baking in some of this differential upside that you expect from maybe Plaquemines and other LNG facilities or maybe a shift to liquids, just any moving parts in that outlook for free cash flow for 4 years.

That -- what we really look to is on the left-hand side of the page when we think about it. So when you think about our C3+, it's over 40 million barrels a year. So you can do the math on that if -- versus the $40 kind of baseline that we put in there. And then when you do the natural gas for every $0.25, it was $220 million. But when you kind of bring that all together, what we really think about is, every $0.10 of equivalent is $100 million of incremental free cash flow. So when you look at 2024 at $2.20 was kind of our breakeven. At $2.27, we had $73 million of free cash flow. I think when we came in here today, it was [ $3.85 ] for 2025. So that $0.10 per $100 million, you get to that $1.6 billion that I referenced over. So those are kind of good rules of thumb. And it's kind of just illustrative on that chart showing the sensitivities but the way we think about it, every $0.10 equivalent pricing to $100 million plus of free cash flow.

That's helpful. Just want to clarify. I mean, I think you were saying 2026 differentials you expect to get better than 2025. I was just wondering if that was baked into that or are you holding 2025 assumptions?

No, no, I was just trying to be illustrative on that and trying to give you a sensitivity analysis. But we do see higher because I think in '26, it's plus $0.50 for that $570 million a day we send to Plaquemines versus $0.20, $0.30 this year.

Perfect. That makes sense. And then just to address the hedging that you add on, I know it was strategically done for the DUCs, does that -- should we read through to more of a strategic thought from management? Are you guys looking at it, hey, maybe now there are any opportunistic moments we'll add for any periods where our production might be higher than our normal maintenance? Or is it -- it was just a onetime off and other than that, you'll probably remain unhedged?

We have lean gas pads in the futures. So we'll see what the price is there. The great thing about '26 and beyond, you can protect at that $3 level we talked about and do very wide collars. So you're really just getting a huge window of opportunity for natural gas prices and for cash flow generation but not really locking in the price. So it is attractive when you got lean gas pads that generate very healthy returns at $3 plus gas, you can put a $3 floor and then get very wide collars on it. So that's something that we'd look to for lean gas pads in the future.

Your next question comes from Neil Mehta with Goldman Sachs Asset Management.

Yes. It's Neil Mehta here with the research side. We appreciate all the color here today. The first question is just about return of capital. In the current environment, the business is throwing off a ton of cash. Balance sheet has been restored to close to optimal levels. So I'm just curious, your perspective of the cadence of when you think it makes sense to start talking about incremental returns of capital or how do you think about the optimal capital structure?

The optimal capital structure, we think, has had 0 debt, be able to run this business and have flexibility and be able to get exposure to the upside for natural gas prices. But that said, we have about $500 million of repayable current debt, either on our credit facility or calling our '26 notes. There's $97 million outstanding there. That will get you down to about $900 million of debt. Then you have some '29s, about $300 million-ish that also kind of high coupon that we could call and bring in this year as well. So that's something that we'd look to do. But the first use is the $500 million free cash flow. Then after that, it will be 50-50 buying in '29s and then share buybacks. But then we have a piece of paper for the 2030s, which is, I believe, around $600 million. That's at [indiscernible] that's trading below par. It's actually below where we could issue today. So we'll probably leave that outstanding and then kind of shift to more share buybacks once all of the non-2030 notes are extinguished.

Yes. Okay. Moving towards that fortress balance sheet. Appreciate that. And the follow-up is just more of a theoretical question, which is it's a very dynamic gas environment globally. The U.S. is starting to firm up from an inventory and pricing standpoint. But one of the questions is, how does TTF play into it? Just your thoughts on if we get to closer to peace in Europe and Russian gas potentially flows into the market, how does that affect the way that you think about the U.S. gas balance, the linkage between U.S. pricing and European pricing? And just your framework for thinking around what is a very dynamic situation.

Yes, I'll kick it over to Justin for his comments. But we track this formula on when it's economic for LNG to go offshore and we're well above that and it would take a pretty drastic reduction in TTF, which wouldn't occur considering their storage levels to get there. But Justin, maybe you want to comment on that?

Sure. This is Justin. To Mike's point, as we look out balance of '25 through cal '27, the spreads are very healthy, Henry Hub versus TTF, less liquefaction costs, less shipping. So very supportive. Currently the Europeans continue to set the FSRUs to bring additional gas volumes in. So just overall, we see it very supportive and bullish of, time being.

I guess the question is just how does that evolve potentially as the curve does backwardate for TTFs? And just your perspective on how do you think about that?

Yes. So I mean, any backwardation just continues to support Henry in the front. So we'll continue to see that strength as the cargoes load. For example, we're at 15.8 Bcf today per the publications on LNG feed gas. So Henry versus TTF on the outer years, again, very healthy spreads. If you see backwardation on TTF in the front, we see that very supportive and should continue to pull up Henry prices as well.

Yes. Right now, I mean we're talking $10 an MM of cushion. So it'd have to be a significant decline in TTF to levels that they haven't seen. So -- and a lot of it is contracted anyway. So we continue to see it be supportive for the exports.

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

My question is on well costs. I appreciate Paul's comments on the 2024 well costs. How do your current well costs compare to your 2024 average? And what is built into the 2025 guidance for well costs and days per wells? And do you have a view on whether you see further service cost deflation or efficiency gains?

Yes. Well costs for '24 were around that $925 per foot range that we talked about in prior calls with the efficiencies that we're seeing and we also have drilling contracts that came up and are in place for 2025 at lower rates. We're in the low $900s right now, so we're lower than we were in 2024. The 2025 plan does capture our efficiencies that we achieved in '24. So we are assuming that 12 to 13 stages per day and 10 days for a well, it's around 5,000 feet per 10 days, is the way we think about it. So we are baking in those assumptions as we continue to achieve those on a daily basis. And then we have the service costs, like I mentioned, are bit down just because we had our drilling -- our legacy drilling contracts roll off and new ones come into place for '25.

Appreciate that detail. And second question is on ethane production and pricing. If I remember correctly, you guys have talked about a small uplift to Mont Belvieu previously and your 2025 guidance had a pretty material uplift to Belvieu. So curious what changed on that front? And if the beat that we saw in the fourth quarter for ethane production is repeatable?

Yes. Kevin, this is Dave. Yes, fourth quarter, we -- if you look at it on a gross basis, we were probably 97%, 98% utilized our de-ethanizers. So very, very strong quarter. As we looked at back at '24, there was some ramp-up in volumes really related to some sales that will be a stronger pricing to Belvieu. So as those are now online and doing well, we would expect that to be a tailwind for 2025 differentials. And then we also do have a contract that is expiring again here in about 3 months -- or, sorry, end of the quarter that will also -- the expiration will improve our overall average premium for our ethane sales as well. So pretty good visibility on that guide there and feel confident that we're going to be able to deliver.

And our next question comes from Leo Mariani with ROTH MKM.

Wanted to see if you could provide just a little bit of color on perhaps the CapEx and production trends here in 2025. Just trying to get a sense if we should maybe continue to see a bit of a first half weighted CapEx budget this year? And then just on your production trend, obviously, you got some winter weather and things like that to deal with in the first quarter. Do you expect production to tick down a little bit maybe in 1Q versus 4Q and then kind of tick up the rest of the year? Just any color on any of those kind of spending and production trends would be helpful.

Yes, not much variance. First quarter, probably in and around the guide -- at the midpoint of the guidance. We did just bring on a lot of wells but they're really just ramping up now. So you're really not going to get that benefit to the second quarter. So maybe a tad higher in -- on the second quarter, we're talking maybe 1%, very low variance. And similar in capital, pretty evened out over the quarter. When we do that DUC pad and started in the late first quarter, really, second quarter, it will raise capital in the second quarter versus the first. So maybe up 1 completion crew in the second quarter versus the first for a bit. So maybe a bit higher in the second quarter. But like I said, it's pretty evened out. It's a 2-rig program, 1 completion crew with 1 spot pad. That's the whole program and that's spot pads in the second quarter. And then the production is very consistent, just we did bring on 16 wells at the end of January, kind of ramping into February.

Okay. That's helpful. And I just wanted to shift a little bit back over to the JV for the year. I guess I'm struggling a little bit with the numbers here. Maybe you guys can clarify this. I think you guys have been kind of saying for a while that maintenance CapEx is right around $700 million. You've got a partner that's coming in, for it looks like a little bit more than 15% of the capital here in 2025. So I guess if I just did the simple math on that and lopped off 15% of the maintenance capital that would put the budget for D&C maybe closer to $600 million than what the current guidance is. So can you help me out at all with the math there?

Yes, I don't think your math is correct. I think the way we think about it is we're running a 2-rig program and a 1 completion crew plus a spot. And that's generally -- that's probably around $825 million but that amount would have you grow. And so when we looked at our program, we wanted to continue those because it's consistent. I mentioned the continuity of the program and allows us to handle the water in the field efficiently. But we also wanted to be really at maintenance capital and have our net production to be flat and have the lowest capital possible. So when you put those 2 together, it really suggests that we should go out and get a JV partner. And when they looked at our program and how consistent it is and how it's a manufacturing play and the results are so terrific you're able to get opportunistic terms.

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

My first question is the follow-up on the production guidance. And, let's say you called out a $50 million cubic feet increase year-over-year. Wondering if that's intended to stay in this space in? Or did you guys actually secure additional takeaway to move it out?

No, that's within the basin. We have -- we're approximately at 100%. We do sell some locally to TCO and have some flexibility there. So that's still within -- outside the basin and not selling anything within.

Understood. This one is on free cash. So when we look at it, you're going to end the year around net debt 0. What are your thoughts around implementing some kind of return of capital, be it dividend or buyback?

Yes. Once we get the $500 million paid back, we'll start buying back some shares and then it will be 50-50 on buybacks versus taking in the '29s and once the '29s are in, it will be share buybacks.

Your next question comes from David Deckelbaum with TD Cowen.

I was curious, Mike, maybe you could give a little bit of color of -- you made the earlier points, I think, around lateral length and where your natural average lateral length is going to be in the program. But you've obviously highlighted like a higher base level of production and there's some -- there's a lot of different variables that feed into that. But can you give some color on what sort of productivity variables you're baking into the guide this year? Are you locking in what you had achieved in 2024 in addition to kind of the accelerated cycle times that's helping you perhaps offset that degradation in lateral length?

Yes, that's exactly right. That's correct. We have achieved those amounts and those efficiencies in '24 so many times, like I said, on a day in, day out basis that we felt comfortable baking them into '25. And although it's a slightly 1,000 feet or 1,500 feet less lateral length, those efficiencies offset that.

appreciate that. And then just a follow-up on the guidance around premium to Henry Hub for natural gas. Obviously, you're benefiting from your takeaway to TGP 500. As you see sort of the impact of Plaquemines and some other LNG facilities coming online, was there an internal thought around maybe changing some commercial agreements or signing direct offtakes with shippers? Is that opportunity available to you all? Is that something that you have interested in? Or do you still find that the open basis markets are sort of your best course for managing risk and sort of maximizing your margins?

No, we evaluate all opportunities with our transport. Of course, we get offered those. But we found the best just to retain the optionality for us, don't enter in the firm sales. We're now getting, I think, 3 facilities in the Gulf Coast in 2025 coming on. They're going to have to compete for that gas. We have the vast majority of the transport and the capacity. We think the actual differential to premiums will be higher than what the market is. That guidance is just based on market. So we're going to retain that optionality for us and see where the gas prices go.

And your next question comes from Roger Read with Wells Fargo.

I'd just like to ask on the CapEx guidance, I understand the service cost efficiency but we do have now tariffs on imported materials and raw materials. Just wondering if there's any risk for contingency built into the CapEx, thinking just higher steel costs or anything like that?

Yes, the tariffs within our $650 million to $700 million, when you look at our program, a lot of it's prebought, all the pipe and casing is pre-bought, same with the midstream. You already have a lot of that already in-house, for the amount that's not in other items that would be subject to the tariffs. If you had a 25% increase, it would be about $5 million to $10 million total increase in our capital. So it's well within that $50 million threshold or band we have for our capital guidance.

And then I know you don't give '26 guidance at this point but not having things prebought for '26, there'd be a little more pressure at that point, assuming tariffs...

No, it's not that -- yes, maybe it could be a $15 million, $20 million, just not that impactful to us.

Okay. Appreciate that. And then the other -- this question was sort of asked earlier. But I was just curious, in-basin opportunities, as you look at them in terms of demand, specifically the idea of adding capacity inside of [ PJM ] on the gas side?

I'll kick again over to Justin. But of course, with our position in transport and being the low-cost provider with the longest inventory, we're in all those discussions but they're still kind of ongoing.

Yes. Roger, we've said this on previous calls, that Antero owns the toggle between local Appalachia and using our FT to the Gulf. So if the local spreads and pricing widened versus Gulf, then we do have that option to take advantage of any markets that are more local, in basin, as power needs, et cetera develop.

Our next question comes from Betty Jiang with Barclays.

I want to ask about the propane outlook. It's -- the 2025 premium definitely came in better than expected. And we were under an assumption that, that premium is going to moderate sometime in the second half as the Gulf Coast exports ramp up. So would love to get your thoughts on just how you think about the longer-term propane C3+ NGL premium. Given the increased focus on in-house marketing efforts, do you see that premium ultimately improving even on a normalized basis?

Yes. This is Dave, Betty. A couple of things that were baked into that 2025 guide, as you talked about the export ARB. So if you look back at '24, it's kind of the opposite maybe of what we could see this year where it started low and then it kind of ramped as you got into the third and fourth quarter. And if you look at it on an annual average, it was somewhere around $0.15 per gallon or a little less. As we look at 2025, we think that you can certainly achieve those levels in the market today for '25. As we talked about, we locked in a sizable portion of our export volumes already. So we've got good visibility into that. The other piece, if you look back at '24, in the first quarter of '24 we did not have our marketing plan that we put in place, really the domestic contracting season is April 1 through March 31. So the first quarter of '24 really didn't have those benefits and we have those here in '25. So that's another tailwind. And then the butane contract that I talked about in my comments is kind of that third tailwind. So that said, certainly, '26, we would think would look better than what we had in years prior to '23 and maybe even '24. But the export market will still play a role in that and we'll see how that evolves. Demand continues to be very strong but we'll never complain about low ARBs and high Mont Belvieu prices either. So at the end of the day, the absolute price we're selling at the dock is really what drives our economics.

Sure. That makes a lot of sense. My follow-up is on your liquids mix. It's -- I think of 4Q, you guys are closer to 38% might be a record for the company. It sounds like there's a few more lean gas pads in the future as well. So how do you guys think about your long-term mix, liquids mix evolve over time?

It's similar to that. I think some of the liquids that you saw in the fourth quarter was what Dave mentioned on the ethane and the 98% running at that but 38% is a good number for us.

Your next question comes from Paul Diamond with Citi.

I just wanted to touch around -- I know you guys added a few incremental pieces of the hedge book and you talked about being somewhat opportunistic in '26 and beyond. I just want to get a bit more clarity on that. If you guys kind of have a target level for the ideal piece you want to be given the expectations around lean gas production.

No, no target level. We just looked at our plan. And with the lean gas around those 1,200 Btu wells, we've decided you really don't want to leave those to a $2 gas environment. So when you can put in a $3 floor and lock about it and then get a wide collar upside, that seems like a reasonable position.

Got it. And just one quick follow-up, more around the kind of the pricing curve around TGP 500L, just how much -- how do you guys look at the risks around the trend? I mean, obviously, the '25 and '26 numbers look pretty solid. But do you guys see any volatility coming down the pipe? Or is that pretty locked-in, in your view?

No. I mean there's going to be a lot of demand in the Gulf Coast. So we think it's probably more to the upside than what we see right now in the market. So -- and you've seen that over the past couple of years as these facilities continue to come on, the market moves higher and higher and those spreads move higher. So we feel good about it. We've had it for almost 1 decade before these and there was a good piece of pipe then. And now with these facilities now, it's actually probably the premium pipe to be on.

Your next question comes from Nitin Kumar with Mizuho Securities.

I just want to start on the cost environment, particularly on service costs. I think earlier you mentioned that you're seeing service costs flat. Any early impact from the tariffs that President Trump has indicated, particularly on the steel side?

No impact. Like I said on the earlier, if it is implemented at 25%, it's about $5 million to $10 million for 2025.

Got it. And then I just wanted to also just follow-up on -- as I look at your capital plan for next year, production is flat at the aggregate level. But both gas and liquids are a little bit lower from what you did end up in 2024 even though you have some DUCs coming on earlier in the year. Sorry for in the weeds question but is this an issue of timing? Or it is as we were talking about earlier, lateral wells? How do you kind of look at that trajectory, especially as you think about '26.

Yes. No, growth is up. You can look at Antero Midstream's release. I think that's 2% or 3% gross volumes up. It's really around the ethane that Dave was mentioning. We have 10,000 barrel a day contract that expires at the end of this quarter that was well out of the money. That will now be in the gas stream, getting NYMEX Henry Hub plus $0.20. So economically much better. But on the equivalents, that 10,000 equates to about $60 million a day, 10,000 barrels of ethane. And when you do it with the gas shrink, it's about $30 million a day of lower production than it would have been with that the contract in place.

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

Yes. Thank you for joining us on today's call. Please reach out with any further questions. Thank you.

This concludes today's call. All parties may disconnect. Have a good day.