Antero Resources Corporation (NYSE:AR) Q4 2024 Earnings Call Transcript

Antero Resources Corporation (NYSE:AR) Q4 2024 Earnings Call Transcript February 13, 2025

Operator: Greetings and welcome to the Antero Resources Fourth Quarter 2024 Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. 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.

Brendan Krueger: Good morning. Thank you for joining us for Antero Resources Corporation’s fourth quarter 2024 investor conference call. We will spend a few minutes going through the financial and operating highlights, and then we will open it up for Q&A. I would also like to direct you to the homepage of our website, at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today’s call. Today’s call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO, and President; Michael Kennedy, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.

Paul Rady: Thank you, Brendan, and good morning, everyone. Let me start on slide number three. 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 guide 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 number four titled Drilling and Completion Efficiencies, which details the drivers behind our exceptional operating performance during 2024.

We have 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 two years. On the drilling side, shown in the top of the left side of the slide, we reduced the time it takes to drill a well to just ten days in 2024. This is a nearly 30% improvement compared to the fourteen 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 13.2 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 two rigs on average and just over one 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 fundamental side, I’m going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments. Dave?

Dave Cannelongo: Thanks, Paul. 2024 was a better year for Antero Resources Corporation, realizing record differentials to Mont Belvieu driven by high LPE export premiums and stronger domestic price differentials in our market area. As seen on the left hand side of slide number five, in 2024, Antero realized a $1.41 per barrel premium over Mont Belvieu, the best C3 plus 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, are allowing us to set our guidance for 2025 at levels even higher than 2024’s record year, resulting in a range for our C3 plus NGLs of $1.50 to $2.50 per barrel premium to Mont Belvieu prices.

As we head into 2025, we are forecasting export 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 US 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 plus sales as well. On the domestic marketing front, as seen on the right hand side of slide number five, 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 1st that was historically priced at a steep discount to Mont Belvieu that we have now locked in at nearly Mont Belvieu flat pricing. 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 on all of our C3 plus 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 US continues to steadily grow with exports averaging 1.8 million barrels per day year-to-date in 2025, as shown on slide number six.

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, of 3.8 million barrels per day for the week ended January 24th. 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 US propane market. A sustained strong demand this year has brought propane inventories from the top of the five-year range to below the five-year average in a matter of weeks, as shown on the left hand side of slide number six.

US inventories entered the year 10% above the five-year average, but several weeks of strong demand and robust withdrawals decreased stocks to 1% below the five-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 24th. With that, I’ll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Justin Fowler: Thanks, Dave. I’ll start on slide number seven titled 2025 Natural Gas Storage versus the Five-Year Average. Since our third quarter conference call, we’ve seen a significant move lower in our natural gas storage balance relative to the five-year average. At that time in late October, we were 167 Bcf above the five-year average. Today, we sit at 111 Bcf below the five-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 five-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 number eight illustrate the record power burn and res comm demand we have observed. At the top of the slide, US natural gas demand from power burn has hit monthly records each month of the winter. At the bottom of the slide, you will see US natural gas demand from res comm was also a January record at over 50 Bcf. Another positive update since our last quarterly call was the highly anticipated startup of the first export cargo at Plaquemines, which was achieved on December 26th, and the ramp-up since that time has been faster than 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 number seven and number eight, and with the request for block number nine filed with the FERC on Tuesday.

The pricing impact following the startup of Plaquemines can be seen on the chart on slide number nine titled TGP500L Basis Performance. Looking at the TGP 500L basis, which is the basis hub with the most current exposure to Plaquemines, 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 that TGP 500L basis increases even further, going from a $0.14 per MMBtu premium in March of 2025 to a $0.50 premium in calendar year 2026. This 2026 premium reflects a more than $0.20 increase as compared to strip pricing one 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 of Angel and Pass phase one project capacity into Gatorick press, the pipeline that feeds Plaquemines.

This 570,000 per day represents nearly 25% of Antero’s total natural gas production and is a 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 a $0.02 premium in 2024. Looking out to 2026, we expect this premium to increase further as the continued ramp-up of Plaquemines, as well as Corpus Christi phase three and the startup of Golden Pass, are expected to significantly increase the call on natural gas along the LNG corridor. With that, I will turn it over to Mike Kennedy, Antero’s CFO.

Michael Kennedy: Thanks, Justin. Now let’s turn to slide number ten 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 two 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 is 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 outspend. 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 in down cycles, as we experienced in 2024, and to capture significant increases in free cash flow in 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 two lean gas pads in 2024, we added natural gas hedges that tied to the volumes associated with those two 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 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, representing a compelling 12% free cash flow yield. In 2025, we intend to use free cash flow to first pay down our credit facility and the remaining 2026 senior notes, which as of December 31, 2024, totaled 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 provide us with the greatest exposure to rising prices. We anticipate a significant call on natural gas over the next twelve 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.

Q&A Session

Operator: Thank you. And at this time, we’ll conduct our question and answer session. Our first question comes from Arun Jayaram with JPMorgan. Please state your question.

Arun Jayaram: Tim, I want to ask you a little bit about just the gas macro situation. You know, given Justin’s commentary around the ramp in demand from utility demand as well as the startup of some of the LNG facilities, truly 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 a call to market call needing, you know, more gas volumes to meet the increase in demand.

Michael Kennedy: Hi, Arun. This is Mike. You know, good question. For us at least, you know, 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 one. So for us, the ability to grow to meet that is not really even possible unless it’s in the local basin or right next to our field.

Arun Jayaram: Great. Clear answer there. And then just a follow-up. Mike, in the 10-Ks, you guys highlighted inking a drilling partnership with an unnamed operator where it looks like, you know, they’re going to be paying about 15% of your program or receiving a 15% working interest but funding a 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?

Michael Kennedy: Yeah. Well, 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, a benefit besides the carry is also the ability to operate a two-rig consistent program. Have one completion crew and a spot crew now and again for the maintenance capital. It allows efficiencies around that to have that. And then from a water and handling perspective, to be able to have optimal water handling within the field 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 2021 to 2024. So it’s a disproportionate carry like the 10-K says and just an upfront carry instead of a back-ended one.

Arun Jayaram: Any more kind of details on the magnitude of the carry?

Michael Kennedy: Oh, no. You know, 15% of our what is it? $650 to $700, it’s like $100 million net to them and they’re paying a little bit more than that, obviously, for their interest.

Arun Jayaram: Great. Thanks a lot.

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

John Freeman: First question I had, you all have been pretty clear about, you know, y’all were anticipating having about roughly twelve ducts with the other two pads that y’all deferred. And I’m just trying to reconcile with it looks like you all had seventeen net wells that were sort of in progress at year-end. So just trying to get some color if it was still twelve ducts and just a handful of wells in various stages of drilling or if the duct Yeah. That’s right.

Michael Kennedy: Correct. We brought on sixteen wells in January. Throughout the month. And then we still have one duct pad like you mentioned, seven wells that’ll be Q3.

John Freeman: Got it. And then the other topic, we’ve obviously, y’all are in, you know, 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 feet 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 y’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?

Michael Kennedy: No. We, you know, we’ve got a full portfolio. We are a virtual 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.

John Freeman: Got it. Thank you.

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

Carlos: Hey, good morning, gentlemen. 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, you have a captive market to add those liquid-rich acreage contracts, so and leases. So wonder what your outlook there is.

Michael Kennedy: Yeah. Now we got a good inventory. You know, that’s what our organically program one with the benefits, not only does it increase near-term working interest, but also the strategy behind it is to replace in the exact areas where we’re drilling with further acreage in the liquids window in 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, you know, finds its way to us. So able to replace what we’ve drilled every year. I think last year, you know, it’s around fifty-nine locations and we put up sales like forty-five. Typical years, you know, around sixty is how we think about it. So every year we can replace the sixty locations we grow.

It’s kind of the strategy around the organic leasing. So when you do that, kind of look at our position, it’s well over a decade of liquids drilling and then assuming we don’t add any more acreage then you would transition to drilling though well over a decade gas position. So over twenty years plus from an inventory standpoint, long duration, long runway. So we’re well positioned.

Carlos: Thank you. I appreciate the answer. Now I’d like to address real quick in reconciling your completions for this year versus 2024 because in 2024, you completed net forty-one wells at an average length of fifteen thousand seven hundred feet and for 2025, your outlook suggests sixty-two and a half of the net point 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 pleasing? As it may be counterintuitive for what we expect an industry that is going to longer laterals and just to build on that, there’s some you mentioned sixteen wells that have been drilled here in January. That there’s some CapEx presumably pre-spent in 2024 that doesn’t hit in 2025 for obvious reasons. So I wonder if you can quantify that capital number.

Michael Kennedy: Yeah. All those sixteen wells, the vast majority of that capital is in 2024 those were put on in January turn to sales. So they’d already been drilled and completed in 2024. A little bit of capital obviously for January but the vast amounts were in 2024 related to those sixteen wells. So you kind of put that together with the low forties, the forty-two wells we put on 2024. Know, versus this year and then there’s obviously some carryout of 2025. But that’s why I referenced the sixty wells. It’s generally sixty wells per year. You can see that in our proved reserve database. We know we have two eighty-nine PUD locations over five years. So when you do the math there, it’s around sixty wells. So we do about sixty wells a year.

Lateral lengths, we’re already the longest I mean, it was over fifteen thousand feet for 2024. Which may have been our longest year. Generally, though, it’s around thirteen thousand to fourteen thousand feet is our typical well. I think this year we’re at eight hundred feet. When you look in the crude reserve database, I think it’s a similar number. So thirteen to fourteen 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.

Carlos: Thank you, guys.

Operator: Your next question comes from Bert Donnes with Truist Security. Please state your question.

Bert Donnes: Hey, good morning guys. Just wanted to brush on Slide eleven. I know not necessarily a new slide, but just wondering if you’ve changed any assumptions there. Maybe you could elaborate on, you know, if you’re baking in some of this differential upside that you expect from, you know, maybe Plaquemines and other LNG facilities or maybe a shift to liquids? Just any moving parts in that outlook for free cash flow over four years? Thanks.

Michael Kennedy: Oh, but the that you know what we really look to is on that left hand side of the page. When we think about it. So you think about our C3 plus You know, it’s over forty million barrels a year. So you can do the math on that if versus the forty dollar kind of baseline that we put in there. And then when you do the the natural gas, For every twenty-five cents, it was two hundred and twenty million But when you kind of bring that all together, you know, what we really think about is every ten cents of equivalent to one hundred million dollars of incremental free cash flow. So when you look at 2024 at two dollars and twenty cents was kind of our breakeven. At two twenty-seven, we had seventy-three million dollars of free cash flow.

I think when we came in here today, it was three eighty-five. For 2025. So that ten cents per one hundred million, you get that one point six billion that I referenced over So those are kind of good rules of thumb and kind of just illustrative on that chart showing the sensitivities but way we think about it every $0.10 equivalent pricing is $100 million plus of free cash flow.

Bert Donnes: That’s helpful. Just want to clarify. I mean, I think you were saying 2026 different you expect to get better than 2025. I just was wondering if that was baked into to that, or are you holding 2025 assumptions? No. That was just trying to be a list

Michael Kennedy: less drip on that. You know, trying to give you a sensitivity analysis. But though we do see higher because I think in 2026, it’s plus fifty cents. That five hundred and seventy million a day we send to Plaquemines you know, versus twenty cents thirty cents this year.

Bert Donnes: Perfect. That makes sense. And then just to address the the hedging that you guys going, I know it was strategically done for the the DUCs. Is does that should we read through to more of a strategic thought from from management? Are you guys looking at it? Hey. Maybe now they’re any opportunistic moments we’ll add for for any periods where our production might be higher than our normal maintenance, or is it was just a one time off and and other than that, you’ll probably remain unhitched?

Michael Kennedy: But we have lean gas pads in the future, so we’ll we’ll see what the price is there. The great thing about twenty-six and beyond, you can protect at that three dollar 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 three dollars plus gas. You can put a three dollar floor and get very wide collars on it. So that’s something that look to for lean gas pads in the future.

Bert Donnes: Makes sense. Thanks, guys.

Operator: Your next question comes from Neil Mehta with Goldman Sachs Asset Management. Please state your question.

Neil Mehta: 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, you know, the cadence of what you think it makes sense to start talking about incremental returns capital or how do you think about the optimal capital structure?

Michael Kennedy: The optimal capital structure, we think, is to have zero debt. Be able to run this business and have flexibility and be able to get exposure to the upside for natural gas prices. With that said, we have about five hundred million dollars of repayable current debt either on our credit facility or calling our twenty-six notes. There’s ninety-seven million outstanding there. That’ll get you down about nine hundred million dollars of debt. Then you have some twenty-nine, about three hundred million ish. That also are 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, you know, the first use is the five hundred million. Free cash flow, then after that, it’ll be fifty-fifty buying in twenty-nine and then share buybacks then we have a piece of paper, the 2030s, which is, I believe, around six hundred million dollars.

That’s at five three eights trade 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-twenty thirty notes are extinguished.

Neil Mehta: Yep. Okay. Moving towards that fortress balance sheet. Appreciate that. And that the all of it just more of a theoretical question, which is it’s a very dynamic gas environment globally. The US is starting to firm up from an inventory and pricing standpoint, but one of the questions is how does PTS play into it? Just your thoughts on, you know, if we get to closer to peace in Europe, and pricing gas potentially flows into the market. How does that affect the way that you think about the US gas balance, the linkage between US pricing and European pricing, just your framework for thinking around what is a very dynamic situation?

Michael Kennedy: Yeah. I’ll kick it over to Justin for his comments. But we tracked a formula on when it’s economic for LNG to go offshore, and we’re well above that. I know 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?

Justin Fowler: Sure. Good morning. This is Justin. To Mike’s point, as we look out, you know, balance of twenty-five through Cal twenty-seven, spreads are very healthy. You know, Henry Hub versus less liquefaction cost, less shipping. So very supportive. Currently, you know, the Europeans continue to set the FSRUs to bring additional gas volumes in. So just overall, we see it very supportive and, you know, time being.

Neil Mehta: I get the question. It’s just how does that evolve potentially if the curve does backwardate? For TPS and just your perspective on how do you think about that?

Justin Fowler: Yeah. So I mean, any backwardation just continues to support Henry in the front. So we’ll continue to see that strength as the car goes load. You know, for example, we’re at fifteen point eight Bcf today per the publications on LNG feed gas. So, you know, Henry versus TTF on the outer years, again, very healthy spread. If you see backwardation, on in the fronts, we see that very supportive and should continue to pull up entry prices as well.

Michael Kennedy: Yeah. Right now, I mean, we’re talking ten dollars an ammo of cushion, so it’d have to be a significant decline. Correct? And PTS to levels that they haven’t seen. So and a lot of it’s contracted anyway, so we continue to see it be supportive for the exports.

Neil Mehta: Perfect. Thanks, guys.

Operator: Your next question comes from Kevin McCarthy with Pickering Energy Partners. Please state your question.

Kevin McCarthy: Hi. Good morning, team. My question is on well cost. I appreciate Paul’s comments on the 2024 well cost. How do your current wall 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?

Michael Kennedy: Yeah. Well, costs are twenty-four. We’re on that nine twenty-five 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 twenty twenty-five at lower rates. We’re in the low nine hundreds right now, so we’re lower than we were in twenty twenty-four. The twenty twenty-five plan does capture our efficiencies that we achieved in twenty-four. So we are assuming, you know, that twelve to thirteen stages per day. And ten days for a well around five thousand feet per ten days the way we think about it. So we are baking in those assumptions. We continue to achieve those on a daily basis. And then we have the service costs like I mentioned. Our bid down just because we had our drilling our legacy drilling contracts roll off and new ones come into place for twenty-five.

Kevin McCarthy: Appreciate that detail. Second question is on ethane production and pricing. If I remember correctly, you know, you guys have talked about a small uplift in Bellevue previously, and your twenty twenty-five guidance had a pretty material uplift to Bellevue. So curious what changed on that front and if the beat that we saw in the fourth quarter for ethane production is repeatable?

Dave Cannelongo: Yeah. Kevin, this is Dave. Yes, fourth quarter we if you look at it on a gross basis, we were probably ninety-seven percent, ninety-eight percent utilized our de ethanolers. So very strong quarter as we looked back at twenty-four, there was some ramp up in volume is really related to some sales. It will be a stronger pricing to Bellevue. So as those are now online and doing well, we would expect that to be a tailwind for twenty twenty-five differentials. And then we also do have a contract that is expiring, again here in about three months or sorry, end of the quarter, that will also it you know, the expiration will improve our overall average premium for our ethane sales as well. So pretty good visibility on that guide there and you know, feel confident that we’re going to be able to deliver.

Kevin McCarthy: Thank you.

Operator: And our next question comes from Leo Mariani with ROTH MKM. Please state your question.

Leo Mariani: Hi. Good morning. Wanted to see if you could provide just a little bit of color on perhaps the CapEx and production trends here in twenty twenty-five. Just trying to get a sense if we should, you know, maybe continue to see a pivot of a first half weighted, you know, CapEx budget, you know, this year and then just on your production trend. Obviously, you got, you know, some winter weather and things 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 in production trends would be helpful.

Michael Kennedy: Yeah. Not much variance, you know. First quarter probably, you know, in and around the guide the midpoint of the guidance, we did just bring on a lot of wells, but they’re really just ramping up now. You’re really not going to get that benefit for the second quarter. So maybe a tad higher, you know, in the second quarter. We’re talking maybe, you know, one percent. You know, very low variance and similar on capital. Pretty even out over the quarter. When we do that duct pad and started in the late first quarter really second quarter, it’ll raise capital in the second quarter versus the first. So maybe up one completion crew in the, you know, 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 two rig program. One completion crew with one spot pad that’s the whole program and that spot pads in the second quarter. And then the production is very consistent. Just we did bring on sixteen wells at the end of January kind of ramping into February.

Leo Mariani: Okay. That that’s helpful. And I just wanted to shift a little bit back over to the JV. You know, 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 seven hundred million. You’ve got a partner that’s coming in for, looks like, a little bit more than fifteen percent. Of the capital here in twenty twenty-five. So I guess if I just did the simple math on that and, you know, lopped off fifteen percent of the maintenance capital that would put the budget for D and C may be closer to six hundred than what the current guidance is. So can you help me out all over the math there?

Michael Kennedy: Yeah. I don’t think your math’s correct. You know, I think, you know, what the way we think about it is we’re running a two rig program and a one completion crew plus a spot. And that’s generally, you know, that’s probably around eight twenty-five. But that amount would have you grow. And so when we looked at our program, we wanted to continue those because it’s a 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 be flat and have the lowest capital possible. So when you put those two 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 the manufacturing play and the results are so terrific, you’re able to get opportunistic terms.

Leo Mariani: Okay. Very helpful. Thank you.

Operator: Your next question comes from Kalei Akamina with Bank of America. Please state your question.

Kalei Akamina: Hey, good morning, guys. Thanks for getting me on. My first question is to follow-up on production guidance and let’s see. You called out a fifty million cubic feet increase year over year. Wondering if that’s intended to stay in the space, or did you guys actually secure additional takeaway to move it out?

Michael Kennedy: No. That’s within the basin. We have, you know, we’re approximately at a hundred percent. We do sell some locally to TECO and have some flexibility there. So that’s still within, you know, with outside the base and not selling anything within?

Kalei Akamina: Understood. This one is on free cash. So when we look at it, you’re going to end the year around net at zero? What are your thoughts around implementing some kind of return of capital via the dividend or a buyback?

Michael Kennedy: Yeah. Once we get the five hundred million paid back, we’ll start buying back shares and then it’ll be fifty-fifty on buybacks. Versus taking in the twenty-nine. And then once the twenty-nine are in, it’ll be share buybacks.

Kalei Akamina: Great. Thanks.

Operator: Your next question comes from David Deckelbaum with TD Cowen. Please state your question.

David Deckelbaum: Thanks for taking my questions guys. Curious, you know, Mike, maybe you could give a little bit of color of, you know, you made the earlier points, I think, around lateral lengths 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, you know, 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 two thousand twenty-four in addition to kind of the accelerated cycle times, it’s helping you perhaps offset that, you know, degradation in lateral length?

Michael Kennedy: Yes. That’s exactly right. That’s correct. We have achieved those amounts, those efficiencies in twenty-four so many times, like I said, on a day in day out basis that we felt comfortable making them twenty-five and although it’s a slightly, you know, a thousand feet or fifteen hundred feet less lateral length, those efficiencies offset that.

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

Michael Kennedy: 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 three facilities in the Gulf Coast twenty twenty-five 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 differentials 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.

David Deckelbaum: Thanks, Mike.

Operator: And your next question comes from Roger Read with Wells Fargo. Please state your question.

Roger Read: Yes. Thank you. Good morning. I just like to ask on the CapEx guidance, 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, you know, contingency built into the CapEx thinking just higher steel costs or anything like that.

Michael Kennedy: Yeah. The tariffs, you know, are within our six fifty to seven hundred when you look at our program, a lot of it’s pre-bought. All the pipe and casing pre-bought, same with the midstream. You already have a lot of that already in house. For the amount that’s not and other items that would be subject to the tariffs you had a twenty-five percent increase, it’d be about five to ten million dollars total. Increase in our capital. So it’s well within that fifty million dollars threshold or band we have for our capital guidance.

Roger Read: And then I know you don’t give twenty-six guidance at this fine. But not having things pre-bought for twenty-six, there’d be a little more pressure at that assuming ten that’s not bad money. Yeah.

Michael Kennedy: Yeah. Maybe. It could be it. Fifteen million dollars twenty. It’s just not that impactful to us.

Roger Read: 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, you know, the idea adding capacity inside of PJM on the gas side.

Michael Kennedy: You know, 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.

Justin Fowler: Yeah. Good morning, Roger. We’ve said this on previous calls, but Antero owns the toggle between local Appalachia and using our FP to the goal. So if the local spreads and pricing widened versus golf, then we do have that option to take advantage of any markets, you know, that are more local in base, and as, you know, power needs, etcetera, develop.

Roger Read: It’d be fun to watch. Thank you, guys.

Operator: Our next question comes from Betty Jiang with Barclays. Please state your question.

Betty Jiang: Want to ask about the propane outlook. It’s the twenty twenty-five premium definitely giving a 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 we’d love to get your thoughts on just how you think about the longer-term propane C3 plus. And y’all premium, given the increased focus on in-house marketing efforts, do you see that premium ultimately improving even on a normalized basis? Thanks.

Dave Cannelongo: Yeah. This is Dave Betty. A couple of things that were baked into that twenty twenty-five guide as you talked about the arms. So if you look back at twenty twenty-four, it’s kind of the, you know, opposite maybe of what we could see this year where it started it started low and then it kind of ramped as you got into the third and fourth quarter. And you look at it on an annual average, it was somewhere around fifteen cents per gallon or a little less. As we look at twenty twenty-five, we think that you can certainly achieve those levels in the market today for twenty-five 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 twenty-four in the first quarter, of twenty-four, we did not have our marketing plan that we put in place, really, the domestic contracting season is April first through March thirty-first.

So first quarter of twenty-four really didn’t have those benefits. And we have those here at twenty-five, 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 twenty-six, we would think, would look, you know, better than what we had in, you know, years prior to twenty-three and maybe even twenty-four. But the export, you know, market will still play a role in that, and we’ll see just how that evolves. You know, demand continues to be very strong, but you know, we’ll never complain about low ARPS and high mount value prices either. So, you know, at the end of the day, the absolute price we’re selling at the dock is really what drives our economics.

Betty Jiang: Sure. That makes a lot of sense. My follow-up is on your liquids mix. It’s I think four Q or you guys are closer to thirty-eight percent might be a record for the company. 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?

Michael Kennedy: It’s similar to that. I think, you know, some of the liquids that you saw in the fourth quarter was what Dave mentioned on the ethane on the ninety-eight percent running at that, but you know, thirty-eight percent is a good number for us.

Operator: Your next question comes from Paul Diamond with Citi. Please state your question.

Paul Diamond: Hi. Good morning. Thanks for taking my call. I just wanted to touch around, I know you guys added a few incremental pieces of the hedge book. You talked about being somewhat opportunistic in twenty twenty-six and beyond. Wanna get a bit more clarity on that if you guys kind of have a target level, you know, for the ideal piece you wanna be given the expectations around, you know, lean gas production.

Michael Kennedy: No. No target level. We just look at our plan. And when the lean gas run those twelve hundred BT wells, we’ve decided you really don’t wanna leave those to a two dollar gas environment. So when you can put in a three dollar floor and lock about it and then get a wide collar upside, that seems like a reasonable position.

Paul Diamond: Got it. And just one quick follow-up. More around the kind of the pricing curve around TGP five hundred l. Is how much how do you guys look at the risks around the trend? I mean, obviously, the twenty-five and twenty-six numbers look pretty solid. But do you guys see any volatility coming down the pipe, or is that pretty locked in in your view?

Michael Kennedy: No. I mean, you know, there’s gonna 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 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. Know, we’ve had it for almost a decade before these and it was a good piece of pipe then and now with these facilities now, it’s actually probably the premium pipe to be on.

Paul Diamond: Understood. Thanks for your time over there.

Operator: Thank you. Your question comes from Nitin Kumar with Mizuho Securities. Please state your question.

Nitin Kumar: Good morning everyone and thanks for taking my question. I just want to start on the cost environment, particularly on service cost. I think earlier you mentioned that you’re seeing service flat. Any early impact from the tariffs that present Trump has indicated, particularly on the steel side?

Michael Kennedy: No. No impact. Like I said on the earlier if it is implemented at twenty-five percent, it’s about five to ten million dollars for twenty twenty-five.

Nitin Kumar: Oh, got it. And then I just wanted to also just follow-up on, you know, 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 where which you did end up in twenty twenty-four. Even though you have some ducks coming on earlier in the year, sorry for the in the weeds question, but is this an issue of timing? Or is it as we were talking about earlier, lateral ends? How do you kind of look at that trajectory, especially as you think about twenty-six?

Michael Kennedy: Yeah. I know gross is up. You can look at the Antero Midstreams release. I think that’s two or three percent gross volumes up. It’s really around the ethane that Dave was mentioning. We have ten thousand 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, you know, Henry Hub plus twenty cents. So economically much better, but on the equivalent that ten thousand equates to about sixty million a day. Ten thousand barrels per day. And when you do it with the gas shrink, it’s about thirty million a day of lower production it would have been with that with that thing, contract in place.

Nitin Kumar: Great. Thanks for the clarification.

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

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

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