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Greetings and welcome to the Antero Resources Second Quarter 2024 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brendan Krueger, Vice President of Finance. Thank you. You may begin.

Yes, good morning. Thank you for joining us for Antero’s second quarter 2024 investor conference call. We will 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’m going to start my comments on Slide #3 titled Drilling and Completion Efficiencies. We continue to realize impressive operational efficiency gains. During the second quarter, we exceeded our record performance that we had in 2023, that’s just last year and in the first quarter of this year. Starting with the chart on the top left hand side of our slide, our wells continue to get longer and averaged a quarterly record of over 18,000 lateral feet per well during this second quarter of 2024. This is 16% longer than our prior quarterly record. During the quarter, we completed a 5-well pad that averaged nearly 20,000 lateral feet per well. The ability to drill these long laterals reflects the concentrated acreage position that we have built in West Virginia. We also benefit from our organic leasing efforts that are instrumental in filling in acreage blocks around our development program. On the drilling side, we’ve averaged 4 days from spud to kickoff point during the first half of the year, which is an improvement from the 4.4 days last year 2023. On the completion side, we once again set a quarterly record, averaging 11.9 stages per day during the second quarter. This is an increase from the 10.7 stages per day in 2023. These operational improvements resulted shorter cycle times, as shown on the bottom of the page. Not only are we drilling these wells faster and more efficiently but our well performance continues to be impressive. During the second quarter, we recorded the second highest production rate per well in company history with 1 pad averaging 37 million cubic feet equivalent per day per well over 60 days. Slide #4 highlights Antero’s cumulative well productivity versus our peers. Since 2020, Antero’s wells have outperformed the peer average well performance by 24%, helping drive this outperformance has been improving liquids productivity in our liquids trend over that time. Now let’s turn to Slide #5 titled Antero Capital Efficiency Versus Peers. This slide depicts the tangible benefits from our operational efficiency gains and strong well performance. Antero has the lowest maintenance capital per Mcf equivalent of its peer group at just $0.54 per Mcfe. This is 43% below the peer average of $0.95 per Mcfe. Our capital efficiency provides us with important flexibility in our development plan. Given current natural gas pricing, we were able to defer a payout from the third quarter until the end of this year. Despite this deferral, we are still able to increase our 2024 annual production guidance as a result of the strong productivity and efficiency gains. 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. The second quarter of 2024 saw a continuation of the improved liquids fundamentals that we observed in the first quarter, providing for a strong start to the year. Propane exports continue to drive demand in the U.S. NGL market and rising export premiums have become a major tailwind for Antero’s C3+ price realizations in 2024. Slide #6 shows historical propane exports according to weekly EIA data and highlights the consistent increases we have observed since the COVID pandemic began in 2020. In the second quarter of this year, the U.S. set a new weekly propane export record at 2.34 million barrels a day. Looking at the broader trend, export volumes have averaged above 1.7 million barrels a day on a quarterly basis since the fourth quarter of last year, which is higher than the annual average in 2023. The start of the third quarter has been lower due to the impact of Hurricane Beryl on the Gulf Coast export docs this July, but we expect propane export numbers to recover and surpass previous quarters as we move through the remainder of this year. The high export levels we are seeing in the market are testing the maximum threshold of U.S. dock capacity, particularly in the U.S. Gulf Coast. Slide #7 illustrates existing LPG export capacity in the Gulf Coast in the yellow area and actual LPG exports in the black line. Looking back to 2019 and 2020, we saw a period of tightness at the LPG docks reflected by high utilization rates and low availability of spot cargoes. This, in turn, led to very high premiums to Mont Belvieu pricing for waterborne spot cargoes. Several terminal expansions alleviated these constraints in 2020 and 2021. However, U.S. NGL production and global LPG demand have continued to steadily increase and we are now once again in a period of extremely tight turmoil capacity and high dock premiums. We believe this environment will likely continue until several major expansions come online starting mid-2025 and into 2026. As a reminder, Antero exports over 50% of our C3+ production skewed heavily towards propane directly out of the Marcus Hook terminal in Pennsylvania. As a result, Antero’s export volumes are not impacted by any capacity constraints in the Gulf Coast. Turning to Slide #8. This graph shows the recent actual premiums observed by market participants for FOB waterborne cargoes versus the pricing at Mont Belvieu. This July premiums for cargoes loading in 30 to 60 days reached a high of $0.23 per gallon, the highest levels observed since January of 2020. As we noted on last quarter’s call, this year, Antero has elected to sell a greater portion of our waterborne barrels against international indices as well as in the spot market, instead of entering into longer Mont Belvieu link term deals. Therefore, we have been transacting in the spot market and receiving premium similar to those shown in this graph for the vast majority of our propane export barrels. This has resulted in a significant uplift to our C3+ realized pricing and led to the increase in our NGL price guidance we just announced. In other liquids highlights, China PDH utilization rates have recently returned to healthier levels even as new capacity build-out continues. PDH utilization rates have increased above 70% in recent weeks compared to approximately 60% over the last 2 years. Current China PDH demand is estimated at over 0.5 million barrels a day and market consultants project this to grow to over 580,000 barrels per day by the end of 2024 as more capacity comes online and utilization remains strong. To conclude, Antero is extremely well positioned to take advantage of the current dynamics supporting stronger NGL prices, particularly in the propane market. Our unconstrained export position at Marcus Hook and marketing strategy of leaving more barrels available in the spot market this year have allowed us to capture unprecedented export premiums, and we expect those strong values to largely continue until further Gulf Coast export capacity is added in mid-2025 and 2026. These tailwinds have allowed Antero to increase our NGL pricing guidance to a $1 – $2 per barrel premium to Mont Belvieu for 2024. 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. The recent softness in natural gas pricing is occurring despite record high summer natural gas power burn that has exceeded even the most optimistic forecast. Higher imports from Canada where storage levels are nearly full combined with extended downtime at LNG facilities has resulted in storage levels that are still historically high at over 400 Bcf above the 5-year average. With that said, the surplus in inventory has shrunk by over 200 Bcf since March, and our constructive outlook for 2025 remains relatively unchanged. 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. Now let’s look at Slide #9 titled, Not all Transport to the U.S. Gulf Coast is Equal. I’ve highlighted this slide in prior quarters but thought it would be helpful to provide an update on how pricing has changed since our last update. As we approach the startup of the Venture Global Plaquemine LNG facility, which is expected to be in service this month, we have seen TGP 500L pricing premiums to Henry Hub increase even further. Calendar 2025 through 2027 forward curve shows premiums exceeding $0.50 per MMBtu. When you look back at pricing 1 year ago, premiums were under $0.10 per MMBtu. As a reminder, Antero holds 570,000 MMBtu per day of firm delivery to the 500L pool or 63% of the supply that will feed the Kinder Morgan TGP of Angelin Pass Phase 1 project capacity to the Plaquemine LNG facility. Additionally, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor, while our peers on average saw less than 15% of their natural gas into the LNG corridor. Our firm transportation portfolio provides us with direct exposure to the growing LNG demand along the Gulf Coast and importantly into Tier 1 pricing points in the vicinity of the major LNG facilities. With several new LNG facilities starting up over the next year, we expect to see a widening spread between sales points near Henry Hub and sales points outside of this premium market. Next, let’s turn to the chart on Slide #10 titled, U.S. Power Burn. In addition to the highly anticipated ramp in LNG demand of 20 Bcf by the end of the decade, electric power generation demand continues to be highly topical. During the first half of 2024, natural gas power burn has increased approximately 1.4 Bcf a day compared to the same period last year, while over the last decade, we’ve seen annual increases each year averaged 1.3 Bcf per day. We believe this trend of higher natural gas power burn demand will continue going forward, driven by demand growth from AI data centers, cryptomining and electric vehicles. Factors including another wave of coal plant retirements beginning in 2025 and the market share of this domain growth that is ultimately met by natural gas could lead to meaningful higher demand. Natural gas is the most reliable, accessible and affordable energy resource available today to fill these future demand needs. With that, I will turn it over to Mike Kennedy, Antero’s CFO.

Thanks, Justin. I’d like to start with Slide #11 titled, Lowest Free Cash Flow Breakeven. This slide compares 2024 unhedged free cash flow breakeven levels across our peer group. To add to what Dave just highlighted, the increase in our NGL pricing guidance adds an incremental $60 million to our free cash flow in 2024 and pushes our natural gas breakeven level even lower. Our $2.20 Mcf breakeven level benefits from two primary drivers. First, our low maintenance capital requirements. Driven by the capital efficiency gains that Paul detailed earlier, we were able to reduce our annual drilling and completion budget by over $200 million this year while maintaining flat production. We expect this maintenance capital level in and around $700 million to be sustainable going forward. The second drivers are high exposure to liquids. Despite the weakness in the natural gas price, which averaged just $2.07 per Mcf through the first half of 2024, strong C3+ NGL prices have provided $1.10 per Mcf uplift to our equivalent price realizations during that period. Importantly, this low free cash flow breakeven provides downside protection throughout cycles. The chart on the right-hand side of the slide illustrates first half 2024 unhedged free cash flow. While we just have a small outspend year-to-date, our gas peers with higher breakeven levels show unsustainable outspends. We believe this analysis is the best way to determine the true economics and strength of a company’s development program. The bottom line comes down to who is best positioned to protect the downside with the lowest breakeven price and capture the upside with the greatest exposure to Henry Hub pricing. A further testament to the peer low reinvestment rate was the upgrade to an investment-grade credit rating that we achieved during the second quarter. Essential to this upgrade was the low maintenance capital and $2 billion of debt reduction we have achieved since we began our debt reduction program in 2019. Turning to Slide #12. You can see the credit rating momentum that we had during this time. Following this upgrade, we entered into a new unsecured credit facility that closed earlier this week and expect $15 million in annual interest savings and have realized over $350 million of additional liquidity. With that, I will now turn the call over to the operator for questions.

Thank you. [Operator Instructions] And our first question comes from Bert Donnes with Truist Securities. Please state your question.

Hey, good morning, team. I 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? Did you already have a price locked in? Or will you renegotiate when you go to complete that pad?

Hi, Bert, Mike Kennedy. No, that is still to be determined, really just natural gas prices. We deferred it to turn in line basically at the end of the year, beginning in next, just to try 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 and the pricing gets a spot so we have a general kind of pricing mechanism around commodity prices that have followed. So it is a spot pricing as well for the completion crew.

Okay. Perfect. Thanks. And then the next one, on the longer laterals, to be honest, I was kind of expecting some sort of productivity dip when you go to 20,000 feet. But on a per foot, it looked just in line with your short laterals. Could you maybe talk about the cost savings there? If you were to drill two 10,000-foot laterals instead of one of these 20,000 foot laterals have you just put some numbers around that, just anything there?

Yes. I don’t know those exact numbers. We haven’t drilled a 10,000-foot well in quite some time. So I don’t know what those are, but our numbers on those longer laterals in the low $900 per foot.

Got it, makes sense. Thank you.

Our next question comes from Arun Jayaram with JPMorgan Chase & Company. Please state your question.

Yes. My first question is regarding some of the completion efficiency gains. You mentioned that you’ve averaged 12 stages per day. There’s a lot of different technologies that producers are using simul-frac. I was wondering if you could maybe shed some light on your process, what you’re doing at Antero. I think it’s a continuous pumping technique that you’re using, but love to see if you can shed some more light on that? And what percentage of your mix are you using that for today?

Yes. I think we talked about a certain concept, but didn’t elaborate on it in the last earnings call, but we have perfected, but modernized the manifold system as we switch back and forth doing zipper fracs between our laterals on the pad. So whereas we used to sling a lot of iron, you’d see us banging iron and disconnecting wellheads and reconnecting them in a fairly elaborate manifold. Now it’s more computerized and we can switch on and off and ship back and forth quite quickly. So I give kudos to our operating group to develop this automatic manifold system that can switch back and forth quite readily.

And what percentage of your wells, Paul, are you using that process on today?

100%.

100%. Okay. Understood. Understood. I have a follow-up for Justin. And wanted to get your take on the PJM auction results earlier this week. I know that the results were – the pricing was higher than the Street was anticipating much higher. And I was wondering if you could talk about some of the implications to natural gas because it looks like it is going to give some incremental advantages talking to our electric utility team for dispatchable generation, i.e., natural gas. Do you expect to see some increase in gas-fired capacity peakers from market forces, so to speak, and perhaps we didn’t really see the gas curve move on that, but I wanted to get your thoughts on that?

Yes. Good morning, Arun, it’s Justin. When we look out at PJM, MISO and then CERC, we have been thinking of that as about a Bcf of natural gas demand additions towards the end of the decade. So when we total it up, maybe it ends up being around 5 Bcf per day by 2030. To your point on the auctions and the PJM pricing with all the AI data center growth with the other projects that have been announced in the PJM area, West Virginia and then the Carolinas, we have been categorizing that as the AI data center growth and then that power draw from those locations. So expected the PJM to potentially start trading higher. And then as these power projects continue forward, we’ve chatted to several groups, one in particular, in West Virginia near us, but it seems that, that natural gas need will continue to grow if those projects move forward.

Great. Thanks a lot.

Our next question comes from [indiscernible] with Goldman Sachs. Please state your question.

Hi, good morning, team. So last call, you mentioned that the potential for shareholder returns was maybe in the first half of next year. With the developments around the macro since then, how are you thinking about the trajectory of gas prices now? And then how does that change your timing expectations around return of capital?

Yes, just to reiterate what we said, which still holds true. First, $500 million-ish of free cash flow, I think it’s around $600 million where our credit facility is at $630 million goes to debt pay-down. That would get our credit facility down to zero and then take out that stuff ‘26, so they are still outstanding and it’s just under $100 million. And then from there, it would be 50-50 to shareholder returns in the form of share buybacks most likely and then further debt pay-down. And then we actually – we have 2030 note out that’s got a 5 and 3.8 coupon, which we will probably still leave outstanding. So, once you get through in those ‘29, then it would be – the vast majority would go to shareholder buyback. So, that still holds. It’s obviously, you hit on it. It’s dependent on commodity prices. Commodity prices since last quarter trended a bit lower, so it doesn’t look like that’s going to occur in ‘24, but definitely at today’s commodity prices, it occurs sometime in ‘25.

That’s very helpful. Thank you. And then thanks for the color on the automated manifold system. Just curious in terms of the continued efficiencies from here on, is that going to be driven by other components of the well construction process here, or is there something incremental on top of the automated zipper frac that you are thinking of?

This is, I would say, the base innovation. As we said, we just had the one frac crew, but we have been using the manifold system for the last quarter, at least internally developed. And so I think that’s our main innovation at the moment.

And then I would add one other. We are going to test out on spot fleets, the e-fleets. So, we will see how those will be. Right now, we are using a dual fuel and the e-fleets have, generally have less vibration. So, maybe that will lower the downtime even further, but that’s kind of the next innovation we are going to pilot.

Thank you. Thank you so much for the color.

Our next question comes from David Deckelbaum with TD Cowen. Please state your question.

Hi David.

Thanks. Hey. How are you guys? Thanks for taking my question today. I wanted to just ask like one just to confirm, the deferred TILs into the fourth quarter, I guess should we still think about those as contingent on gas pricing, or are they so included in the program that they are going to be completed in that quarter anyway?

No, they are still to be determined. David, it’s basically on the winter pricing for natural gas.

I appreciate that. And then you mentioned recently, I guess just in the last question about the e-fleet, when is that being deployed into the program, is that the beginning of ‘25?

No, that’s thoughtfully, we are talking about, so. We may end up [indiscernible] actually our current dual fuel for that e-fleet if the e-fleet performs at or above the fuel performance. So, that may become the main base fleet. But right now, it’s our spot fleet going forward.

And then, Mike, just the last one for me, just given all the capital efficiency gains this year, obviously, with longer lateral lengths and a lot of the improvements in cycle times even in more of the liquids-rich window, does that kind of challenge your view that perhaps that $700 million of D&C for maintenance declines a little bit in the next couple of years as base decline improves while also this well hub performance is improving along with cycle times?

No. All of our future projections assume that 10.7 completion stages per day. We have averaged close to 12 this first half. Same with the records that Paul was outlining, none of that was incorporated in those long-term projections. Really that ability to be at 700 in and around that and then trend lower was just based on the decline rates coming down as you just put more and more years of maintenance capital into the stack. So, that’s really what was driving that. If we continue to see these improvements and get comfortable with incorporating them in future projections, I think that you could see a trend lower, not just because of the declines, but also because of these efficiencies.

Appreciate it guys. Thank you.

Thank you.

Our next question comes from John Abbott with Wolfe Research. Please state your question.

Good morning guys. I am on for Doug Leggate and thank you for taking out questions. Our questions are really going to set around Slide #7, Slide #9 and Slide #11. So, for the first question on Slide #9, which we show like the various differentials and premiums towards Henry Hub, how do you think about your premium versus Henry Hub as you head into 2025 and 2026? And then for the second question, you gave us what your cash flow breakeven is in for 2024. But you are going to get the higher premiums potentially here from gas prices as you go on ‘25 and ‘26. And then there could be some sort of offset as more export capacity for propane comes online. So, how do you think about your breakeven trending over a 3-year period of time?

Yes, good questions. That all should trend in our favor just because of our exposure to the LNG corridor. That slide, you referenced, Slide #9 shows how it increases over the next 3 years just because of that demand that’s coming online, so that all accrues to us. When we look at it right now, just putting in these market prices estimates for ‘24, zero to $0.10 premium versus Henry Hub. Next year, it would be more like $0.10 to $0.20, and the following years, it’s $0.20 to $0.30. So, it ticks up about a dime in each of those years. And that would obviously lower our breakeven, almost a one-for-one amount on that. So, that’s definitely something that Antero is exposed to and has in our models going forward, increasing free cash flow over that timeframe.

Appreciate it. Thank you very much for taking our questions.

Yes.

Thank you. And our next question comes from Jacob Roberts with TPH & Company. Please state your question.

Good morning.

Good morning Jacob.

Just wanted to touch on the longer laterals, again, wondering if you could frame the current opportunity in the inventory for the 18,000 plus. And then if you are able to point to, is there a portion of the land capital that’s dedicated to extending laterals in the portfolio?

Yes, if we – when we have an opportunity to go longer, we definitely tie up the leasehold. And so that’s where a lot of it is being spent. We control so much of those units, but we can beat them up just a little bit more when we see the physical opportunity to go longer. So, that is where we are spending our land capital is longer or more of wells and prospects nearby.

Okay. Perfect. And then on the ethane volumes on the quarter seemed a little bit lumpy. Could you just frame what you expect the run rate to be from here going to Shell, please?

Yes. We got more than just Shell, so we don’t guide around Shell, but it’s around our ethane production, and we kept guidance flat on that. We had good performance in the second quarter. So, we will continue to see how that plays out the rest of the year, but we continue to maintain that ethane production guidance of 76,000 barrels to 80,000 barrels a day.

Perfect. Appreciate the time guys.

Thank you. And our next question comes from Trafford Lamar with Raymond James. Please state your question.

Hi guys. Thanks for taking my questions. I guess the first one, looking at Slide #3, just want to confirm the updated production guidance, is that based on a completion stage run rate of 12 per day?

No, that – well, it is because we realized that in the first half, but it’s not incorporating that into the second half schedule. So, that’s really just looking at our outperformance in the first half of the year. We averaged around 3.425 Bcfe a day. That production drift lowered throughout the rest of the year. And that gets us down to that new production guidance of 3.375 Bcfe to 3.425 Bcfe for the annual amount.

Okay. Perfect. And then second one is on land spend, I noticed you all were able to acquire incremental locations at a material discount to 1Q on a per location basis. Is that really – are you all seeing the ground floor with spread as becoming more favorable? Is that acreage comparable to what you all purchased in the first quarter?

It is comparable, and it is becoming more favorable. Obviously, you will have lower commodity prices and low gas prices. So, acreage generally trends in that direction, which way commodity prices go. So, if lower prices comes lower, acreage values generally.

Prefect. Thanks guys.

Thanks Trafford.

Thank you. And our next question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question.

Very good morning. We appreciate all the details on Q3 plus pricing in your prepared remarks and the details on the strong international markets. I wonder if you could give us some more color on how your ethane is being priced and what kind of uplift you are getting there?

Yes, Kevin, this is Dave Cannelongo. We have alluded to in the past that we have been migrating more towards gas linked pricing. So, I would say today, we are probably in that two-thirds gas, one-third Mont Belvieu range here in 2024. And then as we move into ‘25 and ‘26 at Mont Belvieu linked trends down closer to, call it, maybe 20% and the balance really tied to fixing in a gas uplift for the ethane barrels that we recover.

Got it. And that gas price would be at a NYMEX plus or a local price plus price?

Yes. NYMEX is really how we have formed our program over the years.

Thanks. That’s all for me.

Thanks Kevin.

Thank you. There are no further questions at this time. I will turn the floor back to Brendan Krueger for closing remarks.

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