Release Date: August 01, 2024
For the complete transcript of the earnings call, please refer to the full earnings call transcript.
Positive Points
- Antero Resources Corp (AR, Financial) achieved record operational efficiency gains, with wells averaging over 18,000 lateral feet per well, a 16% increase from the previous record.
- The company set a quarterly record in completion stages, averaging 11.9 stages per day, up from 10.7 stages per day in 2023.
- Antero Resources Corp (AR) recorded the second highest production rate per well in company history, with one pad averaging 37 million cubic feet equivalent per day per well over 60 days.
- The company has the lowest maintenance capital per Mcf equivalent among its peers at $0.54 per MCFE, 43% below the peer average.
- Antero Resources Corp (AR) increased its 2024 annual production guidance due to strong productivity and efficiency gains.
Negative Points
- Natural gas prices have been soft, impacting the company's revenue and leading to deferred payouts.
- The start of the third quarter saw lower propane export numbers due to Hurricane impacts, although recovery is expected.
- Despite operational improvements, the company still faces high storage levels and extended downtime at LNG facilities, affecting natural gas pricing.
- The company's free cash flow breakeven level is dependent on commodity prices, which have trended lower, delaying potential shareholder returns.
- Antero Resources Corp (AR) has deferred some well completions to the end of the year, contingent on natural gas pricing, adding uncertainty to production timelines.
Q & A Highlights
Q: Just wanted to start off on the deferred pad that you disclosed, is that timing set in stone for year end? Or is that a wait and see if prices improve situation? And then maybe logistically, how does that work for the service cost side? Did you already have a price locked in or will you renegotiate when you go to complete that?
A: The timing is still to be determined, really just dependent on natural gas prices. We deferred it to turn-in-line basically at the end of the year, beginning of next, trying to get into the winter pricing season. But of course, natural gas prices are dynamic and fluid. So if those change and we can defer that even further, we will. The pricing is spot-based, so we have a general pricing mechanism around commodity prices that follow.
Q: On the longer laterals, I was expecting some sort of productivity dip when you go to 20,000 feet, but on a per foot basis, it looked just in line with shorter laterals. Could you maybe talk about the cost savings if you were to drill 10,000 foot laterals instead of 20,000 foot laterals?
A: We haven't drilled a 10,000 foot well in quite some time, so I don't have those exact numbers. However, our numbers on the longer laterals are in the low $900 per foot.
Q: Regarding some of the completion efficiency gains you mentioned, averaging 12 stages per day, could you shed some light on your process? What percentage of your mix are you using that for today?
A: We have modernized the manifold system, allowing us to switch back and forth between laterals on a pad quickly. This system is computerized and can switch on and off readily. We are using this process on 100% of our wells.
Q: Wanted to get your take on the PJM auction results earlier this week. Do you expect to see an increase in gas-fired capacity peakers from market forces?
A: We have been thinking of that as about a Bcf of natural gas demand additions toward the end of the decade. With AI data center growth and other projects in the PJM area, we expect natural gas demand to continue growing if those projects move forward.
Q: How are you thinking about the trajectory of gas prices now, and how does that change your timing expectations around return of capital?
A: The first $500 million of free cash flow goes to debt paydown, and then it would be 50/50 to shareholder returns and further debt paydown. Given current commodity prices, it doesn't look like this will occur in 2024, but definitely sometime in 2025.
Q: Is the updated production guidance based on a completion stage run rate of 12 per day?
A: The updated guidance is based on our outperformance in the first half of the year. We averaged around 3.425 BCFE a day, and production is expected to drift lower throughout the rest of the year, leading to the new production guidance.
Q: Could you give some more color on how your ethane is being priced and what kind of uplift you're getting there?
A: We have been migrating more towards gasoline pricing. Today, we're probably in that two-thirds gas, one-third Mont Belvieu range. As we move into 2025 and 2026, Mont Belvieu linked trends down closer to 20%, with the balance tied to fixing in the gas uplift for the ethane barrels.
Q: How do you think about your premium versus Henry Hub as you head into 2025 and 2026?
A: Our estimates for 2024 show a 10% premium versus Henry Hub. Next year, it would be more like 10 to 20 cents, and the following years, 20 to 30 cents. This should trend in our favor due to our exposure to the LNG corridor.
Q: Could you frame the current opportunity and the inventory for the 18,000 plus laterals? Is there a portion of the land capital dedicated to extending laterals in the portfolio?
A: When we have an opportunity to go longer, we definitely tie up the leasehold. We control so much of those units, but we can sum up just a little bit more when we see the physical opportunity to go longer. So that is where we're spending our land capital.
Q: Could you frame what you expect the ethane production run rate to be from here?
A: We continue to maintain our ethane production guidance of 70 to 76,000 barrels, 80,000 barrels a day. We had good performance in the second quarter and will continue to see how that plays out for the rest of the year.
For the complete transcript of the earnings call, please refer to the full earnings call transcript.
