Q4 2024 Antero Resources Corp Earnings Call
of Columbia.
Speaker Change: Greetings and welcome to the NTERO Resources fourth quarter 2024 earnings call. At this time all participants are in a listen-only mode. A question and answer session will follow a formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note that this conference is being recorded.
Speaker Change: I will now turn the conference over to your host, Brendan Krueger, Vice President of Finance. Thank you.
Brendan Krueger: 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.
Brendan Krueger: 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 makers.
Brendan Krueger: Please refer to our earnings press release for important disclosures regarding such measures.
including reconciliations to the most comparable gap financial measures.
Michael Kennedy: 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.
Michael Kennedy: Thank you for watching. Please subscribe to my channel. See you next time.
Speaker Change: Let me start on slide number three. And as I introduce this, let me point out that last year, 2024, was a remarkable year for us.
Speaker Change: 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.
Speaker Change: This was $55 million, or 8% below our initial guidance, and nearly $300 million below our 2023 CapEx of $909 million.
Speaker Change: 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.
Thank you.
Speaker Change: Let's move on to slide number 4, titled Drilling and Completion Efficiencies, which details the drivers behind our exceptional operating performance during 2024.
Speaker Change: We've highlighted some of these drilling and completion stats in prior calls.
Speaker Change: 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.
Speaker Change: 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 10 days in 2024.
Speaker Change: This is a nearly 30% improvement compared to the 14 days that we averaged a couple of years ago. That is 2022
Speaker Change: 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.
Speaker Change: The annual average represents a 53% increase compared to the completion stages back in 2022.
Speaker Change: 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.
Speaker Change: 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.
Thank you.
Speaker Change: 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.
Speaker Change: 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.
Speaker Change: As seen on the left-hand side of slide number 5, in 2024, Antero realized a $1.41 per barrel premium over Mont Belvieu, the best C3 Plus differentials in our company's history.
Speaker Change: The fourth quarter of 2024 was Intero's strongest quarter, with our premium to Mount Bellevue averaging $3.09 per barrel.
For 2025, we are still expecting high annual export premiums.
Speaker Change: 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 Plus NGLs of $1.50 to $2.50 per barrel premium to Mt. Belvue prices.
Speaker Change: As we head into 2025, we are forecasting export dock premiums to be higher on a year-over-year basis.
Speaker Change: We expect more DOT 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. ferrules will be pulled into the export market, resulting in stronger prices at Mont Belvieu.
Speaker Change: Stronger Mount Belvue prices directly benefit the realized pricing on Intero's domestic C3 Plus sales as well.
Speaker Change: On the domestic marketing front, as seen on the right-hand side of slide number 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.
Speaker Change: 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.
Speaker Change: On butane, we have a long-term contract rolling off on April 1st that was historically priced at a steep discount to Mt. Bellevue that we have now locked in at nearly Mt. Bellevue flat pricing.
Speaker Change: The shift in pricing in one contract alone will result in approximately $10 million in incremental cash flow.
Speaker Change: We believe this marketing strategy will drive premium pricing on our Purity products and contribute to our attractive premiums to Mt. Bellevue in 2025 and beyond, as illustrated again by our guidance range of $1.50 per barrel to $2.50 per barrel premium to Mt. Bellevue on all of our C3 Plus volumes.
Speaker Change: So far this year, we have observed constructive fundamentals that illustrate how sticky propane demand is for both exports and domestic use.
Speaker Change: 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 number 6. This is 9% above the same period last year.
Speaker Change: 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.
Speaker Change: 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.
Speaker Change: 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.
Speaker Change: A sustained strong demand this year has pulled 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.
Speaker Change: U.S. inventories entered the year 10% above the 5-year average, but several weeks of strong demand and robust withdrawals decreased stocks to 1% below the 5-year average by the end of January.
Speaker Change: Additionally, we saw the second largest weekly withdrawal on record per EIA data at 7.9 million barrels for the weekend of January 24.
Speaker Change: 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 National Gas Storage vs. the Five-Year Average.
Speaker Change: 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.
Speaker Change: At that time, in late October, we were 167 BCF above the five-year average.
Speaker Change: Today we sit at 111 BCF below the 5 year average and nearly 200 BCF below this time last year.
Speaker Change: 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.
Speaker Change: We expect these supportive fundamentals will lead to higher prices in 2025 and 2026.
Speaker Change: The charts on slide number 8 illustrate the record power burn and res comp demand we have observed.
Speaker Change: At the top of the slide, U.S. natural gas demand from power burn have hit monthly records each month of the winter.
Speaker Change: At the bottom of the slide, you will see U.S. national gas demand from ResCom was also a January record at over 50 BCF.
Speaker Change: Another positive update since our last quarterly call was the highly anticipated startup of the Venture Global Plaquemine LNG facility.
Speaker Change: The first export cargo at Plaquemines was achieved on December 26th, and the ramp-up since that time has been faster than the market expectations.
Speaker Change: Today, the facility is exporting an average of approximately 1.5 BCF per day.
Speaker Change: We anticipate this increasing in the near term following this week's FERC commissioning approvals for liquefaction blocks number 7 and number 8 and with the request for block number 9 filed with the FERC on Tuesday.
Speaker Change: The pricing impact following the startup of Plaquemines can be seen on the chart on slide number 9 titled TGP 500L Basis Performance.
Speaker Change: Looking at the TGP-500L basis, which is the basis hub with the most current exposure to plaquemine.
Speaker Change: 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.
Speaker Change: As the facility ramps up further, you can see the TGP 500L basis increases even further, going from a $0.14 per MMBT premium in March of 2025 to $0.50 premium in calendar year 2026.
Speaker Change: This 2026 premium reflects a more than 20 cent increase as compared to strip pricing one year ago.
Speaker Change: As a reminder, Antero holds 570,000 MMBT per day of firm delivery to the 500L pool, or 63% of the supply that feeds the Kinder Morgan TGP Evangeline Pass Phase I project capacity into Gator Express.
pipeline that feeds Plaquemine.
Speaker Change: 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.
Speaker Change: We expect our premium to NYMEX to be in the range of $0.10 to $0.20 up from $0.02 premium in 2024.
Speaker Change: Looking out to 2026, we expect this premium to increase further as the continued ramp-up of Plaquemine, as well as Corpus Christi Phase III and the start-up of Golden Pass are expected to significantly increase the call on natural gas along the LNG corridor.
Speaker Change: With that, I will turn it over to Mike Kennedy, Antero CFO.
Mike Kennedy: Thanks, Justin. Now let's turn to slide number 10 titled Lowest Free Cash Flow Breakeven.
We've updated this slide for the full year 2024.
Mike Kennedy: The slide compares 2024 unhedged free cash flow break-even levels across our peer group.
Mike Kennedy: 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.
Speaker Change: and second, our high exposure to liquids and ability to capture premium pricing that both Dave and Justin touched on.
Speaker Change: The result of these attributes are shown on the left-hand side of the slide.
Speaker Change: 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 break-even levels show significant outspends.
Speaker Change: 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.
Speaker Change: 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.
Speaker Change: 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 in higher price environments as we see from today's 2025 natural gas strip.
Speaker Change: 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 1200 BTU gas pads.
Speaker Change: Locking in prices above $3.00 per MCF assured us that we would capture attractive rates of return from these wells.
Speaker Change: In addition, this operational certainty provides continuity in our plan, resulting in the most efficient development program and optimizes our midstream infrastructure.
Speaker Change: We placed the sales of the first duck pad in late January, and the second duck pad is expected in the third quarter of 2025.
Speaker Change: During 2025, we intend to add some additional wide collars for 2026 to sync with the expected volumes from our lean gas pads.
Speaker Change: I'll finish with comments on our compelling free cash flow outlook.
Speaker Change: 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.
Speaker Change: 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.
Speaker Change: 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.
are low absolute debt.
Speaker Change: 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.
Speaker Change: We anticipate a significant call on natural gas over the next 12 months as new LNG facilities ramp up.
Speaker Change: 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.
Thank you.
Speaker Change: And at this time, we'll conduct our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue.
Speaker Change: You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys.
Thank you.
Speaker Change: Our first question comes from Arun Jayaram with J.P. Morgan. Please state your question.
Thank you.
Arun Jayaram: Yeah, good morning. Team, I wanted to ask you a little bit about just the gas macro situation. You know, given, you know, Justin's commentary around the ramp
and demand from
Arun Jayaram: Utility demand, as well as the startup of some of the LNG facilities, clearly gonna be a call.
Arun Jayaram: The market will call for higher natural gas volumes. I was wondering if you could talk about the ability of the Appalachia Basin
Arun Jayaram: as well as Antero to respond to a market call needing more gas volumes to meet the increase in demand.
Speaker Change: Hi Ernest, Mike, you know good question you know for us at least you know the maintenance capital where it's where we're comfortable at.
All of our firm transport under this plan is filled.
Speaker Change: 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 it's not really even possible unless it's in the local basin or right next to our field
Great.
Speaker Change: with an unnamed operator where it looks like they're going to be paying about 15% of your program.
Speaker Change: are receiving a 15% working interest but funding a greater than 15% portion of your development capital this year. Can you provide some details on that and just the overall strategic benefits you see from an AR perspective?
Speaker Change: Yeah, well, we've had a drilling JV of some sort in place since 2021.
Speaker Change: 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.
Speaker Change: and a spot crew now and again for the maintenance capital. So it allows efficiencies around that.
Speaker Change: To have that and then from a water and handling perspective to be able to have optimal water handling within the field
I'd still be at maintenance capital, so.
Speaker Change: We enjoyed that, and so when we came into the second half of 2024,
Speaker Change: We went out to see if there was appetite to continue that drilling, J.B., 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 10K says, and just an up-front carry instead of a back-ended one.
Speaker Change: Any more kind of details on the magnitude of the of the carry?
Speaker Change: Now you know 15% of our what is it 650 to 700 it's like a hundred million dollars net to them and they're paying a little bit more than that obviously for their interest.
Great. Thanks a lot.
Speaker Change: Your next question comes from John Freeman with Raymond James. Please state your question.
Yeah, good morning, guys.
Speaker Change: First question I had, I've been pretty clear about, you know, y'all were anticipating having about roughly 12 ducks with the other two pads that y'all deferred. And I'm just trying to reconcile with
Speaker Change: It looks like y'all 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 ducts and just a handful of wells in various stages of drilling, or if the duct numbers are higher.
Speaker Change: Correct, we brought on 16 wells in January throughout the month.
Speaker Change: And then we still have one duck pad, like you mentioned, with seven wells. That'll be Q3.
Speaker Change: 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?
Speaker Change: Now, you know, 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 pipes. So we're happy where we're at and just filling our current firm transport portfolio.
Got it. Thank you.
Dave? Reagan.
Speaker Change: Your next question comes from Doug Legge with Wolf Research. Please state your question.
Hey, good morning, gentlemen. This is Carlos here for Doug.
Speaker Change: 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,
Speaker Change: How do you see your midstream runway, given that you have a captive market to add those liquid, rich acreage contracts and leases? I wonder what your outlook there is.
Speaker Change: Yeah, now we've got a good inventory. You know, that's what our organic leasing program, one of the benefits, not only does it increase, you know, 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 of the Marcellus.
Speaker Change: because of our dominant position owning the midstream, owning all the acreage.
in that area.
Speaker Change: We're really the only one that can develop in those areas. So the acreage, you know finds its way to us. So
We're able to replace what we've drilled.
Speaker Change: every year. I think last year, you know, it was around 59 locations and we put up sales like 45.
Speaker Change: Typical years, you know, 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 organic leasing.
Speaker Change: And 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 the well over a decade of our dry gas position. So over 20 years plus.
Speaker Change: from an inventory standpoint, long duration, long runway, so we're well positioned.
Speaker Change: Thank you, I appreciate the answer. Now, I'd like to address real quick, in reconciling your
Speaker Change: 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.
Speaker Change: 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 foliage per well and why this is decreasing, as it may be counterintuitive for...
Speaker Change: what we expect in an industry that is going into longer laterals.
Speaker Change: And just to build on that, there's some, you mentioned 16 wells that have been drilled here in January, that there's some capex presumably pre-spent in 2024 that doesn't hit in 25 for obvious reasons, so I wonder if you can quantify that capital number.
Speaker Change: Yeah, all those 16 wells, the vast majority of that capital is in 24. Those were put on in January turn of 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.
Speaker Change: You kind of put that together with the low 40s, the 42 wells we put on with 24, you know, versus this year and then, you know, there's obviously some carry out of 25.
Speaker Change: But that's why I referenced the 60 wells. It's generally 60 wells per year. You can see that in our approved reserve database You know, we have 289
Speaker Change: which may have been our longest year. Generally, though, it's around 13,000 to 14,000 feet.
Speaker Change: It's our typical... Well, I think this year we're at 13,800 feet. When you look in the Prude Reserve Database, I think it's a similar number. So 13 to 14 is kind of where we're at. Every year it's gonna be a slight difference, but in and around that number is a great number for us, and probably the longest laterals in the basin.
Thank you, guys.
Thank you.
Speaker Change: Your next question comes from Bert Danes with Truist Security. Please state your question.
Bert Danes: Hey, good morning, guys. Just wanted to brush on slide 11. I know it's not necessarily a new slide, but just wondering if you've, you know, 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.
Bert Danes: Oh, that, you know, what we really look to is on that left-hand side of the page when we think about it. So when you think about our C-3 Plus
Bert Danes: It's over 40 million barrels a year, so you can do the math on that 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...
Bert Danes: You know, what we really think about is every $0.10 of equivalence, $100 million of incremental free cash flow. So, when you look at 2024, at $2.20 was kind of our break-even. At 2027, we had $73 million of free cash flow.
Bert Danes: I think when we came in here today, it was $3.85 for 2025, so that $0.10 per $100 million, you get that $1.6 billion that I referenced over.
Bert Danes: 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 ten cents equivalent pricing is a hundred million dollars plus a free cash flow.
Bert Danes: That's helpful. Just want to clarify, I mean, I think you were saying 2026 differentials you expect to get better than 2025. I just was wondering if that was baked into that or are you holding 2025 assumptions? No, that was just trying to be illustrative on that, you know, trying to give you a sensitivity analysis.
Bert Danes: But though we do see higher because I think in 26 it's plus 50 cents for that 570 million a day we send the Plaquemines, you know versus 20 cents 30 cents this year
Speaker Change: And then just to address the hedging that you added on, I know it was strategically done for the ducks.
Speaker Change: 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 one-time-off, and other than that, you'll probably remain unhedged?
Speaker Change: Well, we have lean gas pads in the future, 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 collar, 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.
Speaker Change: 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 get very wide collars on it So that's something that we'd look to for lean gas pads in the future
Next time. Thanks guys.
Thank you.
Speaker Change: Your next question comes from Neil Mehta with Goldman Sachs Asset Management. Please state your question.
Yeah, it's Neil Beda here with the research side.
Neil Mehta: First question is just about return of capital, you know, in the current environment the business is thrown off a ton of cash.
Neil Mehta: balance sheet has been restored to close to optimal levels. 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?
Neil Mehta: 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.
Neil Mehta: With that said, we have about $500 million of repayable current debt either on our credit facility or calling.
Neil Mehta: are 26 notes, there's 97 million outstanding there. That'll get you down to about $900 million of debt.
Then you have some 29s, about $300 million-ish.
Neil Mehta: also a 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 500 million free cash. So then after that, it'll be 50-50.
Neil Mehta: buying in 29s and then share buybacks. But then we have a piece of paper, the 2030s, which is, I believe, around $600 million. That's at five and three eighths.
Neil Mehta: 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.
Yep.
Speaker Change: Okay Moving towards that Fortress Pound, she'd appreciate that. Oh, there's just more of a theoretical question, which is it's a very dynamic gas environment globally
Speaker Change: The U.S. is starting to firm up from an inventory and pricing standpoint, but one of the questions is...
Speaker Change: How does TTF play into it? Just your thoughts on, you know, if we get closer to peace in Europe and Russian gas potentially flows into the market.
Speaker Change: How does that affect the way that you think about the U.S. gas balance, the linkage between U.S. pricing and European pricing, just your framework for thinking around what is a very dynamic situation?
Speaker Change: Yeah, I'll kick it over to Justin for his comments, but we track this formula on when it's economic.
Speaker Change: for LNG to go offshore, and we're well above that. It would take a pretty drastic reduction in TTF, which wouldn't occur.
Justin Fowler: considering their storage levels to get there. But Justin, maybe you want to comment on that? Sure. Good morning. This is Justin. To Mike's point, as we look out, you know, balance at 25 through Cal 27,
The spreads are very healthy, you know, Henry Hub verse.
Justin Fowler: 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, bullish, you know, time being.
Justin Fowler: I guess the question is just how does that evolve potentially if the curve does backward eight for TTF and just your perspective on how do you think about that?
Yeah, so...
Justin Fowler: I mean, any backwardation just continues to support Henry in the front, so...
We'll continue to see that strength as the cargoes load.
Justin Fowler: For example, we're at 15.8 BCF today per the publications on LNG feed gas.
Justin Fowler: Henry Burst TTF on the outer ears, again, very healthy spread. If you see backwardation on TTF in the front.
Justin Fowler: We see that very supportive and should continue to pull up entry prices as well. Yeah, right now, I mean, we're talking $10 an annum of cushions, so it'd have to be a significant decline in TTF to levels that they haven't seen.
Justin Fowler: And a lot of it's contracted anyway, so we continue to see it be supportive for the exports.
Perfect. Thanks, guys.
Thank you.
Speaker Change: Your next question comes from Kevin McCurdy with Pickering Energy Partners. Please state your question.
Kevin McCurdy: Hi, good morning, team. My question is on well cost. I appreciate Paul's comments on the 2024 well cost. 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 depletion or efficiency gains?
Speaker Change: Yeah, well cost for 24, we're on that $9.25 per foot range that we talked about.
in prior calls.
Speaker Change: with the efficiencies that we're seeing and we also have drilling contracts that came up and are in place for 2025 at lower
Speaker Change: 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
Speaker Change: achieved in 24. So we are assuming, you know, that 12 to 13 stages per day and 10 days for a well, it's around 5,000 feet per 10 days the way we think about it. So we are baking in those assumptions as we continue to achieve those on a daily basis.
Speaker Change: And then we have the service costs, like I mentioned, are a bit down just because we had our legacy drilling contracts roll off and new ones come into place for 2025.
I appreciate that detail.
Second question is on ethane production and pricing.
Speaker Change: If I remember correctly, you know, you guys have talked about a small uplift in Bellevue previously, and your 2025 guidance had the pretty material uplift to Bellevue. So, I'm curious what changed on that front, and if the beat that we saw in the fourth quarter for ethane production is repeatable.
Yeah, Kevin, this is Dave
Speaker Change: It's fourth quarter. We, if you look at it on a gross basis, we were probably 97, 98% utilized our deethanizers. So very, very strong quarter.
Speaker Change: As we looked back at 24, there was some ramp-up in volume, it was really related to some sales that will be at stronger pricing to Bellevue, so as...
Speaker Change: Those are now online and doing well. We would expect that to be a tailwind for 2025 differentials.
Speaker Change: 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...
Speaker Change: 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.
Thank you.
Thank you.
Thank you. Bye.
Thank you.
Speaker Change: And our next question comes from Leo Mariani with Roth MKM. Please state your question.
Leo Mariani: Good morning. I 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, you know, maybe continue to see
Leo Mariani: a bit of a first half-weighted, you know, CapEx budget, you know, this year and then just
Leo Mariani: On your production trend, obviously you've got, you know, 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 one queue versus four queue, 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.
Leo Mariani: Yeah, not much variance, you know, first quarter, probably, you know, in and around the midpoint of the guidance.
Leo Mariani: even out over the quarter when we do that duck pad and started in the late first quarter really second quarter a little race.
Capital in the second quarter versus the first, so.
Leo Mariani: maybe up one completion crew in the second quarter versus the first for a bit.
Leo Mariani: So, maybe a bit higher in the second quarter, but like I said, it's pretty evened out. It's a two-rig program, one completion crew with one spot pad. That's the whole program, and that spot pad's in the second quarter. And then the production is very consistent. We did bring on 16 wells at the end of January, kind of ramping in the February.
Speaker Change: Okay, that's helpful. 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...
Speaker Change: 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
Speaker Change: The simple math on that, and you know, lopped off 15% of the maintenance capital, that would put the budget for DNC maybe closer to $600 than what the current guidance is. So can you help me out at all with the math there?
Speaker Change: Yeah, I don't think your math's correct. You know, I think, you know what, the way we think about it...
Speaker Change: is we're running a two-rake program and a one-completion group plus a spot.
And that's generally, you know, that's probably around 825.
but that amount would have you grow.
Speaker Change: 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.
Speaker Change: But we also wanted to be really at maintenance capital and have our net production be flat.
Speaker Change: and have the lowest capital possible. So when you put those two together,
Speaker Change: It really suggests that we should go out and get a JB partner.
Speaker Change: 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.
Okay, very helpful. Thank you.
Speaker Change: Your next question comes from Kalei Akamine with Bank of America. Please state your question.
Speaker Change: cubic feet increase year over year. I'm wondering if that's intended to stay in this basin or did you guys actually secure additional takeaway to move it out?
Speaker Change: No, that's within the basin. We have, you know, we're approximately at 100%. We do sell some locally to TECO and have some flexibility there. So, that's still within, outside the basin and not selling anything within.
Speaker Change: Understood. This one is on free cash, so when we look at it, you're going to end the year around net zero. What are your thoughts around implementing some kind of return of capital, be it a dividend or a buyback?
Speaker Change: Yeah, once we get the 500 million paid back we'll start buying back some shares and it'll be 50-50 on buybacks versus taking in the 29s and once the 29s are in it'll be share buybacks.
Great, thanks.
Thank you.
Speaker Change: Your next question comes from David Dekelbaum with TD Cowan. Please state your question.
Thanks for taking my questions, guys.
David Dekelbaum: I'm 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 length and where your natural average lateral length is going to be in the program.
David Dekelbaum: There's a lot of different variables that feed into that, but can you give some color on what sort of productivity
David Dekelbaum: 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?
David Dekelbaum: 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 in 25.
David Dekelbaum: although it's a slightly, you know, 1,000 feet or 1,500 feet less lateral length, those efficiencies offset that.
Speaker Change: Appreciate that. And then just to follow up on the guidance around
Speaker Change: premium to Henry Hub for natural gas. Obviously, you're benefiting from your takeaway to TGP 500. You know, as you see sort of the impact of Plaquemines and some other LMG facilities coming online.
Speaker Change: You know, was there an internal thought around, you know, maybe changing some commercial agreements or signing?
Speaker Change: direct offtakes with shippers, is that opportunity available to you all? Is that something that you have interest 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?
Speaker Change: No, we evaluate all opportunities with our transport. Of course, we get offered those, but we found the best. Just, you know, retain the optionality for us. Don't enter in the firm sales.
Speaker Change: We're now getting I think three facilities in the Gulf Coast in 2025 coming on. They're going to have to compete for that gas.
Speaker Change: 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.
See where the gas prices go
Thank you. And thank you. Thank you.
Thanks, Mike. You bet.
Speaker Change: And your next question comes from Roger Reed with Wells Fargo. Please state your question.
Yeah, thank you. Good morning.
Speaker Change: I'd just like to ask, on the CAPEX guidance, I understand the service cost efficiency that we do have now tariffs on.
Speaker Change: imported materials and raw materials just wondering if there's any risk or you know contingency built into the capex thinking just higher steel costs or anything like that
Speaker Change: Yeah, the tariffs within our $650 to $700, you know, when you look at our program, a lot of it's pre-bought, all the pipe encasings pre-bought, same with the midstream. You already have a lot of that already in-house.
Speaker Change: for the amount that's not in other items that would be subject to the tariff.
Speaker Change: If you had a 25% increase, it'd be about $5 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.
Speaker Change: And then, I know you don't give 26 guidance at this point, but not having things pre-bought for 26, there'd be a little more pressure at that point, assuming... That's not a bad line, yeah.
Speaker Change: Yeah, maybe. It could be $15 million, $20 million. It's just not that impactful to us.
Speaker Change: 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 of adding capacity inside of PJM on the gas side?
Speaker Change: You know, I'll kick again over to Justin, but of course with our position in transport and being the low-cost.
Speaker Change: provider with the longest inventory, you know, we're in all those discussions, but
Speaker Change: They're still kind of ongoing. Yeah, good morning, Roger. You know, we've said this on previous calls, but Antero owns the toggle between local Appalachia and using our FT to the goal, so if the local spreads
Speaker Change: 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, etc., develop.
It'll be fun to watch. Thank you, guys.
Thank you.
Speaker Change: Our next question comes from Betty Jung with Barclays. Please state your question.
Betty Jung: I want to ask about the propane outlook. The 2025 premium definitely came in better than expected, and we were under the 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+.
Betty Jung: 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
Speaker Change: Yeah, this is Dave Betty. You know, a couple of things that were baked into that, that 2025 guide, as you talked about the export arms, so if you look back at 24, it's kind of the opposite maybe of what we could see this year where
Speaker Change: It started 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 15 cents per gallon or a little less
Speaker Change: As we look at 2025, we think that you can certainly achieve those levels.
Speaker Change: I'm 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
Speaker Change: The other piece, if you look back at 24, in the first quarter of 24, we did not have our marketing plan.
Speaker Change: that we put in place, the domestic contracting season is April 1st through March 31st. So the first quarter of 24 really didn't have those benefits and we have those here in 25, so that's another tailwind.
Speaker Change: And then the butane contract that I talked about in my comments is kind of that third tailwind.
Speaker Change: 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 just how that evolves.
Speaker Change: You know, 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.
Speaker Change: Sure, that makes a lot of sense. My follow-up is on your liquid mix.
Speaker Change: I think 4Q, you guys are closer to 38% 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 liquids mix evolve over time?
Speaker Change: 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 FA and under 98% running at that but you know 38% is a good number for us.
Great, thank you.
Speaker Change: Your next question comes from Paul Diamond with Citi. Please state your question.
Paul Diamond: 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 wanted to get a bit more clarity on that, if you guys kind of have a target level, you know, for the ideal piece you want to be given the expectations around, you know, lean gas production.
Paul Diamond: No, no target level. We just look at our plan and with the lean gas around those 1200 BTU wells
We decided you really don't want to leave those.
Paul Diamond: It's a $2 gas environment, so when you can put in a $3 floor and lock it at it and get a wide collar upside, that seems like a reasonable position.
Speaker Change: Got it. And just one quick follow-up, more around the kind of pricing, pricing curve around TGP 500 L. 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?
Thank you.
Speaker Change: Now, I mean, you know, there's going to be a lot of demand in the Gulf Coast, so we think it's probably, you know, 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...
Speaker Change: We feel good about it. 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.
Understood. Thanks for your time, I'll leave it there.
Thank you.
Speaker Change: Thank you. Your next 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 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.
Nitin Kumar: No impact. Like I said on that earlier, if it is implemented at 25%, it's about $5 to $10 million for 2025.
Speaker Change: Got it. And then I just wanted to also just follow up on
Speaker Change: 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 what you did end up in 2024, 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 2026?
Speaker Change: Yeah, no, growth is up. You can look at the entire midstreams.
Speaker Change: release. I think that's two or three percent 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.
Speaker Change: that will now be in the gas stream getting NYMEX, you know, Henry Hub plus 20 cents, so economically much better, but on the equivalence that $10,000 equates to about $60 million a day.
Speaker Change: 10,000 barrels of methane 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 methane contract in place.
Great. Thanks for the clarification. Sure.
Extended
Speaker Change: 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.
Speaker Change: This concludes today's call. All parties may disconnect. Have a good day.