Greetings and welcome to the Antero Resources Second Quarter 2024 earnings call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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'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'm going to start my comments on slide number three, 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 continued 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 five 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 four 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 result in 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 cu ft equivalent per day per well over 60 days. Slide four 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 five, 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 pad from the third quarter until the end of this year. Despite this deferral, we were 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 number six 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 bbl a day. Looking at the broader trend, export volumes have averaged above 1.7 million bbl 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 docks 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 number seven 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 terminal 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 30-60 days reached a high of $0.23 per gal, 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 bbl against international indices, as well as in the spot market, instead of entering into longer Mont Belvieu-linked term deals. Therefore, we have been transacting in the spot market and receiving premiums 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 buildout continues. PDH utilization rates have increased above 70% in recent weeks, compared to approximately 60% over the last two years. Current China PDH demand is estimated at over 500,000 bbl a day, and market consultants project this to grow to over 580,000 bbl 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 bbl 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 five-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 number nine, 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 Plaquemines 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 show premiums exceeding $0.50/MMBtu. When you look back at pricing one year ago, premiums were under $0.10/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 Evangeline Pass Phase One project capacity to the Plaquemines 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 sell 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 one 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 number 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 average 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, crypto mining, and electric vehicles. Factors including another wave of coal plant retirements beginning in 2025 and the market share of this demand 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 number 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 driver is our 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 a $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 this 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 number 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. Ladies and gentlemen, at this time, we will 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. 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. One moment, please, while we pull for questions. 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, of just natural gas prices. We deferred it to turn in line basically at the end of the year, beginning and 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, then we can defer that even further. And the pricing is a spot crew, so we have a general kind of pricing mechanism around commodity prices that it follows. 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 ft. 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-ft laterals instead of one of these 20,000-ft laterals, if you could just put some numbers around that, just anything there. Yeah, I don't know those exact numbers. We haven't drilled a 10,000-ft well in quite some time. So I don't know what those are, but our numbers on those longer laterals are in the low $900 per ft. Gotcha. Makes sense. Thank you. Yep. Our next question comes from Arun Jayaram with JP Morgan Chase & Company. Please state your question. Yeah. 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: SimulFrac, TrimulFrac. 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. Love to see if you can shed some more light on that and what percentage of your mix are you using that for today? Yeah. I think we talked about a certain concept but didn't elaborate on it in the last earnings call. But we have, oh, I don't know about perfected, but modernized the manifold system as we switch back and forth doing zipper Fracs between our laterals on a 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 shift 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. What percentage of your wells, Paul, are you using that process on today? 100%. Okay. Percent. Percent. We only have one completion. Understood. Understood. I had 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. 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? Perhaps we didn't really see the gas curve move on that, but wanted to get your thoughts, Justin, on that. Yeah. Good morning, Arun. It's Justin. When we look out at PJM, MISO, and then SERC, we have been thinking of that as about a BCF of natural gas demand additions toward the end of the decade. So when we total it up, maybe it ends up being around five BCF per day. By 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 Ati Modak with Goldman Sachs. Please state your question. Hi. Good morning, team. 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? Yeah. Just reiterate what we said, which still holds true. First, $500 million-ish of free cash flow. I think it's around $600 million with where our credit facility's at $630 million goes to debt pay down. That would get our credit facility down to zero and then take out that stub 2026s that 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 have a 2030 note out that's got a 5.38% coupon, which will probably still leave outstanding. So once you get through funding those 2029s, then it would be the vast majority would go to shareholder buybacks. So that still holds. Obviously, you hit on it. It's dependent on commodity prices. Commodity prices since last quarter have trended a bit lower, so it doesn't look like that's going to occur in 2024, but definitely at today's commodity prices occur sometime in 2025. 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're thinking of? This is, I'd say, the base innovation. As we said, we just have the one Frac crew, but we've 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'd add one other. We are going to test out on spot fleets, the E fleets. So we'll see how those perform. Right now, we're using a dual fuel, and E fleets generally have less vibration. So maybe that'll lower the downtime even further, but that's kind of the next innovation we're 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. Hey, guys. Thanks. Hey, how are you guys? Thanks for taking my questions today. I wanted to just ask one, just to confirm, the deferred wells 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're going to be completed that quarter anyway? No. They're 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 2025? No, that's the spot fleet we're talking about, so. We may end up swapping out, actually, our current dual fuel for that E fleet if the E fleet performs at or above the dual fuel performance. So that may become the main base fleet, but right now, it's our spot fleet going forward. 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 a more of the liquids-rich window, does that kind of challenge your view that perhaps that $700 million of the CapEx for maintenance declines a little bit in the next couple of years as base decline improves while also this wellhead performance is improving along with cycle times? No. All of our future projections assume that 10.7 completion stages per day. We've averaged close to 12 this first half. Same with the records that Paul was outlining. None of that was incorporated into 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 into future projections, I think that you could see the 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'm on for Doug Leggate, and thank you for taking our questions. Our questions are really good to center around slide number 7, slide number 9, and slide number 11. So for the first question on slide number nine, which we show 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 break-even is for 2024, but you're going to get the higher premiums potentially here from gas prices as you go on to 2025 and 2026. And then there's going to be some sort of offset as more export capacity and for propane comes online. So how do you think about your break-even trending over a three-year period of time? Yeah. Good question. So it all should trend in our favor just because of our exposure to the LNG corridor. That slide you referenced, slide number 9, shows how it increases over the next three 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 2024 is $0-$0.10 premium versus Henry Hub. Next year, it'd be more like $0.10-$0.20, and then the following year is just $0.20-$0.30. So it picks up about a dime each of those years. And that would obviously lower our break-evens 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 time frame. Appreciate it. Thank you very much for taking our questions. Yep. Thank you. And our next question comes from Jacob Roberts with TPH & Company. Please state your question. 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+? And then if you're able to point to, is there a portion of the land capital that's dedicated to extending laterals in the portfolio? Yes. Yeah. 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 that we can beef them 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: 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? Yeah. We've 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'll continue to see how that plays out the rest of the year. But we continue to maintain that ethane production guidance of 76,000-80,000 bbl a day. Perfect. Appreciate the time, guys. Yep. Thanks, Jacob. Thank you. 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 number three, just wanted to confirm the updated production guidance. Is that based on a completion stage run rate of 12 per day? No. 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 drifts lower throughout the rest of the year and thus gets us down to that new production guidance of 3,375-3,425 for the annual amount. Okay. Perfect. And then the second one is on land spend. 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 bid-ask spread 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 have lower commodity prices and low gas prices. So acreage generally trends in that direction, which way commodity prices go. So with lower prices comes lower acreage values generally. Perfect. Thanks, guys. Yep. Thanks, Trafford. Thank you. And our next question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question. Hey, good morning. We appreciate all the details on C3+ pricing and your prepared remarks and the details in the strong international markets. I wonder if you could give some more color on how your ethane is being priced and what kind of uplift you're getting there. Yeah, Kevin, this is Dave Cannelongo. We've alluded to in the past that we've been migrating more towards gas-linked pricing. So I would say today we're probably in that 2/3 gas, 1/3 Mont Belvieu range here in 2024. And then as we move into 2025 and 2026, that 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 bbl that we recover. Gotcha. And that gas price would be at a NYMEX plus or a local price plus price? Yeah. NYMEX is really how we've 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'll 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. This concludes today's conference. I'll pardon me to disconnect. Have a good day. Have a good day.