Antero Resources Corporation (AR) Q3 2024 Earnings Report, Transcript and Summary

Greetings. Welcome to Antero Resources Third Quarter 2024 Earnings Call. [Operator Instructions]. As a reminder, this call is being recorded. It is now my pleasure to introduce Brendan Krueger, CFO of Antero Midstream and Vice President of Finance. Thank you. You may begin.

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

Thank you, Brendan, and good morning, everyone. I'll start my comments on Slide number 3 titled Drilling and Completion Efficiencies. Our 2024 operating performance continues to set new records. I'd like to highlight the significant gains that we've achieved over the past 2 years. Faster drilling times have reduced the required time it takes for us to drill a well. Now, it's below 11 days from 14 days in 2022. This is a 22% reduction from 2022. And on the completion side, we again set a new quarterly record, averaging 12.1 stages per day. And in this last August, we set a new monthly record at 13.3 completion stages per day. The quarterly average represents a 51% increase compared to the complete -- completion stages per day average in 2022. These improvements in drilling and completion rates result in reduced cycle times. Shown in the chart on the bottom of the slide, our cycle times have declined to 126 days, which is 23% below the 2022 level of 163 days. Overall, these improvements have reduced our total well cost by 8% since last year to their lowest level since 2021. These step changes in operating efficiencies directly result in reduced capital expenditure requirements. This is shown on Slide number 4, titled Reduced Capital Budget. For this year 2024, we reduced our drilling and completion capital budget to $650 million at the midpoint, a 28% decrease from 2023, while holding production flat. A significant driver behind this lower capital is that today, we are able to sustain maintenance production with just 2 rigs and approximately 1 completion crew. Looking ahead to 2025, we will continue to focus on improving our efficiency. We recently switched to an e-fleet for our completion activity. Early results have been encouraging, and we estimate potential future well cost savings could be upwards of $150,000 to as much as $200,000 per well driven by increased pumping time and lower fuel costs. Now to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments. Dave?

Thanks, Paul. Realizing strong export premiums for our LPG sales highlighted our third quarter liquids results. The expected dynamic resulting from U.S. Gulf Coast export dock constraints discussed last earnings call, ultimately played out to our benefit as we continue to execute on our strategy to target international prices and market the vast majority of our export barrels in the spot market. Because export cargoes are being marketed at 30 to 60 days before actual ship loadings, we have great visibility into our C3+ realizations for the remainder of 2024 and expect these premiums to remain in place for the next several quarters. Slide number 5 shows historical propane exports and highlights the consistent increases we have observed over the past 4 years. Export volumes have averaged over 1.7 million barrels a day, year-to-date, setting up for another record export year. Since 2021, exports have increased 46%, driven by resilient international demand particularly from Asia. As seen on Slide number 6, titled Antero Holds Northeast LPG Export Advantage. Export capacity additions in the U.S. are not expected until the second half of 2025. Over this time frame, we expect to continue benefiting from robust export premiums that are likely to persist until new export capacity comes online. In addition to the export recovery, overall total U.S. propane demand exceeded 3 million barrels a day recently, a high going back to February as seasonal crop drying demand picked up in October. As colder weather begins to arrive, the market will look to increases in heating demand to continue the strong October demand. Slide number 7 quantifies the propane export premiums that Antero realized in the third quarter with a $0.22 per gallon average premium to Mont Belvieu. This is up from premiums of $0.08 to $0.09 per gallon to start this year and $0.05 to $0.09 per gallon in 2022 and 2023, respectively. Current markets show these premiums should improve in the fourth quarter to nearly $0.27 per gallon on average. Butane premiums are similarly showing their value with recent export differentials averaging in the mid to high teens above Mont Belvieu prices. To conclude, with unconstrained access at the Marcus Hook terminal in Pennsylvania through our firm commitments. Antero is well positioned to continue realizing these high export premiums for the balance of 2024 and into 2025. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Thanks, Dave. First, let's look at the year-to-date power burn trends that are shown on Slide number 8. 2024 has once again been a record-setting year for natural gas power burn demand. Year-to-date, natural gas power burn is averaging 1.4 Bcf higher than last year. While over the last 10 years, natural gas power burn demand has increased 15 Bcf per day. Looking ahead, we believe this trend of higher annual natural gas power burn will continue to be driven by demand growth from AI data centers, crypto mining and electric vehicles. This power demand growth provides an incremental uplift on top of the highly anticipated second wave of LNG demand that is expected to add in combination 20 Bcf of incremental demand by the end of the decade. Antero is uniquely positioned to benefit from these expected step changes in demand. Our firm transportation portfolio delivers 75% of our natural gas to the LNG corridor and provides us with direct exposure to growing LNG demand. While our asset position in West Virginia is within the region where a significant number of new data centers are expected to be built. Further, our firm transportation portfolio provides the necessary infrastructure to connect our natural gas to data centers and utilities in need of reliable supply. Turning to Slide number 9, let's review the current natural gas storage level. The record natural gas power burn, I just highlighted, combined with continued producer discipline, has resulted in the surplus and inventory shrinking by nearly 500 Bcf since the highs in March of this year. Today, we sit at just 167 Bcf above the 5-year average, a level that supports our constructive outlook for 2025. We continue to believe low rig counts combined with an upward step change in demand will support a continued tightening of inventories and lead to higher prices in 2025 and beyond. With that, I will turn it over to Mike Kennedy, Antero's CFO.

Thanks, Justin. I'd like to start with Slide number 10, titled Lowest Free Cash Flow Breakeven. This slide compares 2024 unhedged free cash flow breakeven levels across our peer group. Our approximate $2.20 breakeven level benefits from 2 primary drivers. First, our low maintenance capital requirements. This is driven by our operational improvements as highlighted by the reduction in our drilling and completion capital guidance for this year. The second driver is our high exposure to liquids. Despite the weakness in natural gas prices, which averaged just $2.10 through the first 9 months of 2024, strong C3+ NGL prices have provided a $1.10 uplift to our equivalent price realizations during that period. The chart on the right-hand side of the slide illustrates unhedged free cash flow through the first 9 months of the year. While we have just a small outspend year-to-date, our peers with higher breakeven levels have unsustainable outspends. In our opinion, this is the best way to determine the quality of a company's asset base and operations. Turning to Slide number 11, titled Peer-Leading Capital Efficiency. This chart depicts the tangible benefits from our operational gains that Paul detailed earlier. Antero has the lowest maintenance capital per Mcfe of its peer group at just $0.52 per Mcfe. This is 41% below the peer average of $0.88 per Mcfe. Further, most of our peers have declining production, suggesting true maintenance capital requirements that are higher than illustrated on that slide. Antero's capital program provides us with important flexibility in our future development plans. Given current natural gas pricing, we elected to defer the completion of a pad from the third quarter until the end of the year while still maintaining our previously raised production guidance. In addition, we now plan to defer completion of a second pad that has been drilled and was originally scheduled to be completed in the first quarter of 2025. These 2 pads are dryer gas pads with less liquids and therefore, require higher natural gas prices to incentivize us to complete the wells. Let's turn to Slide number 12 titled Free Cash Flow Uplift that summarizes the benefits of what we've highlighted on the call today. Beginning at the top left graph on the slide, our total capital budget, which is drilling and completion plus land capital is expected to be down over $300 million in 2024 compared to last year while maintaining production. Moving down to the bottom left-hand graph on the slide, 2024 C3+ NGL prices are expected to average more than $4 per barrel higher than in 2023. We produce approximately 40 million barrels per year. So every $1 change in C3+ NGL prices results in a $40 million change in cash flow. Thus, higher C3+ NGL prices has driven an approximate $175 million increase in cash flow. In combination, the result is nearly $500 million of incremental cash flow being generated in 2024 compared to 2023, while maintaining our asset base. These attributes allow us to remain approximately free cash flow neutral in 2024 despite being unhedged and a $2.25 natural gas price environment while providing significant free cash flow upside in 2025 based on today's strip. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] Our first question is from Bert Donnes with Truth Securities.

I just wanted to take a stab at your guidance right now. It looks like you are not building that many DUCs this year, obviously, you're delaying those DUC pads. But what are your views on maybe mirroring some of your peers where they're building a backlog of either DUCs or turn in lines and maybe providing a spring in the future for higher prices?

Well, that's actually what's happened, Bert, in 2024. We've built -- right now, we have 2 pads, 2 DUC pads with 12 wells on them that we're not completing this year. One was scheduled to be completed in the third quarter, the other one in the first. Right now, those are to be determined when we complete them based on natural gas prices.

Okay. And that would be the extent you don't want to really go past 2 pads and build kind of some sort of larger program?

Well, we just run a 2-rig program. So whatever that generates versus a one completion crew program is how the DUCs build, and that's how we build 2 pads this year. So if we continue just to run on completion crude next year, we'll continue to build further pads.

That makes perfect sense. And then could you maybe elaborate on your buyback strategy? Obviously, this year has been pretty rough on the gas side. I think your liquids have done great holding you up. But we, and the Street as well, forecast a pretty strong full year '25. Are you guys champing up a bit, waiting for that to come? Or is there any logic to maybe buying before the free cash flow shows up? Or is that maybe fiscal year responsible?

No. We've -- we are just made investment grade this year, and part of that, the plan was communicated that the first $600 million of free cash flow will be to reduce debt. That's essentially to take our credit facility down to 0, and then we have 2026 notes of approximately $97 million, I think, that are still outstanding. So in combination at $600 million of debt, and that's the first call on the free cash flow. Then after that, the majority of free cash flow will be for buybacks.

Our next question is from Arun Jayaram with JPMorgan.

Arun Jayaram with JPM. I had a question just on the Northeast LPG kind of export advantage slide. Dave, in terms of maintaining or sustaining this nice premium that you benefited from for the last couple of quarters, what's your expectation in terms of the timing of the Gulf Coast export capacity increases? And how do you think about how the premium will play out in 2025?

Yes. Thanks, Arun. So in that slide, the first step-up you see we've got illustrated there is July 1. I think it's currently guidance of around mid '25 or second half of '25 from that particular midstream party. And then the other, the next big step is shown there is January 1, '26. So we certainly think until you see some expansion capacity, there's -- we're running at max here in the U.S. with NGL production up year-over-year. So that pressure is there, and we think it will continue until there's some kind of relief of that constraint. Another thing I would just pass you people on look at that LPG export capacity growth, coming in '25 and '26. A lot of that capacity is able to do multiple products. So first, they may do LPG, but we think over time, you'll see a lot of that migrate to more like ethane. So the additional capacity is going to be needed to be built in the U.S. to kind of keep this from continuing to happen. But certainly, for us being in the Northeast, that's one of the benefits we have when these type situations occur, we're not constrained. As we talked about on prior calls, we can get everything we want to the market, so the export market. So we'll continue to do that. And yes, see what we can do with our strategy. But so far, they've done a good job when these have appeared of always capturing it.

Okay. Mike, maybe one for you. A couple of questions from the buy side in terms of building some DUCs just given, right now, there's not a large kind of call on U.S. gas volumes today, just given the storage -- modest storage overhang. But what type of conditions are you guys looking for? Is it price in terms of this 12 DUCs that you're building in this current software commodity present? Just is there a price signal? Help us understand what would cause you to complete those wells?

Yes. Arun, obviously, we really focus on the very high Btu liquids in our typical program. That's 1,275 Btu plus. And with that, and $40 C3+ NGLs. That's really kind of our breakeven level at $2.20. With these pads are more along the 1,200 Btu spectrum. So when you do that on $40 C3+ NGLs, you need 250 gas and higher. That's where the strip is. So it would suggest that we complete those in 2025, but we're cautious around the strip and being unhedged. We wait and it's pretty immediate response when you want to complete them. It's about a 60-day time frame. So you have the ability to look at front month pricing and see where that's headed and your confidence in that. And we're confident that it'll be over 250 gas will complete them. .

Our next question is from Leo Mariani with ROTH Capital.

Just wanted to get a little better sense of how you guys are thinking about maintenance capital obviously, you guys have reduced CapEx a handful of times during the year. It sounds like a lot of that is efficiencies, which is kind of nice to see I mean, generally speaking, should we expect production to be relatively flat next year? And is that kind of 2024 CapEx level of around $650 million like a reasonable number at this point for maintenance?

Yes. Right now, what we've maintained, if you recall, in 2022, we produced 3.2 Bcfe a day, and we went to maintenance capital in 2020 and 2021 at those levels. '23, we spent $900 million, but we actually grew 6% to 7% up into the high 3.3 Bcfe a day, but our maintenance capital has always been centered around 3.3 Bcfe a day to 3.4 Bcfe a day. We've been ahead this year based on our efficiencies and well performance, but we still on the long-term plans are targeting that 3.3 to 3.4 Bcfe a day. And when you look out to next year and the year beyond, that's around $700 million of capital. You could be at the $650 million level, but you'd be in the low 3.3s and the $700 million level you're more in the mid-3.3s. So -- what we think about it is about $700 million of capital to hold 3.3 to 3.4 flat being at the midpoint.

Okay. That's very helpful for sure. And then just in the near term, I understand some of the caution here on bringing back some of these dry gas patch, so it makes sense to wait for better returns. But if that strategy sort of plays out, can you just give us some directionality in terms of production? I mean, should we expect it to kind of tick down the next couple of quarters as you guys are maybe waiting for a little better gas market?

Yes. I think the guidance at the midpoint would suggest 3.35 for the fourth quarter. That would get you to the midpoint of 3,400 and then that's about where we're at in '25 as well.

Our next question is from Ati Modak with Goldman Sachs.

As you think of the gas price realizations, anything you can provide on how you are thinking about the marketing strategy over the next few quarters and what we should expect to see?

Same marketing strategy that we currently have, which is flow all of our guests as much as we can in the Gulf Coast and to the LNG corridor in the LNG facilities. That's about 75% of the gas and then the remainder really goes to TCO and the Midwest. So all the gas molecules get out of the basin and all of our transport is relatively -- is full. So similar gas strategy and we expect those premiums to increase as we move forward and the LNG comes on in '25.

Got it. And then you talked about the price level for completions of the DUCs that you're deferring into '25. But maybe -- any incremental color on whether anything you're drilling right now could be potentially deferred? Or is that relatively more liquids focused?

Yes, it's a good question. It's more liquids focused. Those wells that we drilled were -- the 1,200 were some of our last inventory kind of in that middle of our field in the North Canton area. Now we're really -- and we have been really focused on Wetzel County in Tyler County, which is higher Btu content.

Our next question is from Josh Silverstein with UBS.

You mentioned before, 100,000-plus savings we moved to an e-fleet. Are you guys now looking to lock in this is for next year? Or is there something else that you want to continue testing with it before locking then for next year?

Yes, it's a 2 pad trial. We've done one pad that went well. We're on our second pad. So once that's completed, we'll evaluate and potentially lock that in for next year.

Got it. And then just on the hedging strategy, you remain unhedged in the forward outlook right now. I understand not wanting to be hedged next year with the strip almost down at $3. But what about 2026 with pricing still over the 350 mark? Do you foresee an opportunity to start locking some gains for them or try to just remain on hedged going forward?

Well, we're keeping an eye on the curve, of course, and there's some contango in the curve, as you know, early on before it flattens out to give some optimism. So we're watching it, and we may lock in no promises, but we continue to watch it and look for threshold gas prices that will improve the economics.

Our next question is from Kevin MacCurdy with Pickering Energy Partners.

With yesterday's release, you brought the midpoint of your 2024 CapEx down by $25 million. I wonder if you have the rough breakout of how much of that reduction was driven by efficiencies compared to the deferred turn in lines.

Yes, $15 million is efficiencies, $10 million is the turn in lines. The $650 million assumes a 50-50 chance whether we complete that pad at year-end versus the first quarter. So about $10 million of it is a deferral and then $15 million is the completion efficiencies and drilling efficiencies. .

That's helpful. And what are the impacts of those 2 items on your 2025 budget? That $700 million D&C maintenance CapEx number you mentioned kind of earlier, I think that's a little better than you had communicated previously. I just want to confirm that, that $700 million number kind of includes DUCs and the efficiency gains?

It does. We feel confident in incorporating that now. So those efficiencies. I mean, our well costs in the third quarter were the lowest well cost per foot we've had since 2021. So we're rolling that into 2025. 2025, the lateral lengths are slightly shorter than this year. So on a per foot basis, it equates to '24, but we have rolled those efficiencies in 12 stages per day, drilling the 10,000 feet of lateral in less than 5 days that we achieved in '24 in the very efficient rig moves and completion crew moves. So we're excited about it, and it has resulted in lower capital in '25.

Our next question is from David Deckelbaum with Cowen.

Mike, just a quick one. Can you just refresh us on the delta on the benefit of the drilling carry that was in '24 that's not recurring in '25, I guess, for apples-to-apples and that maintenance program is around $50 million?

Yes, it's actually $30 million, is what our latest calculation on that. You're $50 million may be at the 20% level. And when we think about it, we think about it more in the 15% level, which is where it was at before the weakness in prices in '24. So it's about $30 million. So the $700 million-ish numbers and the low $700 million doesn't assume a drilling JV.

Perfect. And then just a comment on the maintenance levels. The 3.35 I know this year, obviously, there were periods where you were over 3.4 well in excess, and you experienced quite a bit of productivity gains, should we think about that forward maintenance level is not necessarily capitalizing those or continuing those efficiency assumptions or performance assumptions? Or is it more of a function of shifting more activity towards higher Btu content.

No, we're just lowering levels of activity needed to try to get capital in as low as possible to maintain that 3.3 to 3.4. Paul mentioned in his comments of cycle times, we didn't necessarily have those when we are pouring our capital budgets in '23 and '24. We have captured those for '25 and thus, we can have lower capital activity and maintain that production level. So we are capturing it. We're just trying to solve for what's the lowest capital possible to maintain that 3.3 to 3.4 Bcfe a day.

This will conclude our question-and-answer session. I would like to turn the conference back over to Brendan for closing remarks. .

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

Thank you. This will conclude today's conference. You may disconnect your lines at this time, and thank you for your participation.