Antero Resources Corporation

Greetings and welcome to Antero Resources Q3 2023 Earnings Conference 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. I would now like to turn the conference over to your host, Brendan Kruger, Chief Financial Officer of Antero and Vice President of Finance.

Thank you. Good morning, everyone. Thank you for joining us for Antero's third quarter 2023 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, Dave Canalongo, Senior Vice President of Liquid 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. I'll start my comments on slide number three, titled Drilling and Completion Efficiencies. After a record-breaking first half of 2023 operationally, We continued to build on this momentum during the third quarter. As an example, our completion pumping hours per day increased to over 17 hours per day, up nearly 50% from a year ago. In June, we set a company record pumping on average for over 22 hours a day. This increase in pumping hours per day contributes to higher completion stages per day. Year to date completion stages per day have averaged 11 stages a day, a 35% improvement compared to the 2022 average, and is a nearly 90% increase from our 2019 levels. The net impact of all of our operational improvements has led to significantly shorter cycle times as shown on the bottom of the page. These cycle times reflect the total number of days it takes on average from first spotting a pad to turning that entire pad to sales. Since 2019, our cycle times have decreased by an impressive 65% and averaged just 160 days through the first three quarters of 2023. In June, we had the fastest cycle times in our company history at 129 days. Shorter cycle times means higher capital efficiency. Highlighting this point, we completed roughly 80% of our 2023 expected completion stages during the first nine months of 2023. Now let's turn to slide number four. Faster cycle times and improving well performance has led to two production guidance increases in 2023. This gain in capital efficiencies is highlighted by our 9% total production growth in the third quarter compared to the year-ago period. Our production growth was driven by an 18% liquids growth, while natural gas volumes increased 4% year over year. Looking at this on an annual basis, we now expect production this year to increase by 225 million cubic feet equivalent per day, or 7%, from the exit rate in 2022 to the exit rate in 2023. Importantly, these capital efficiency gains also reduce our maintenance capital budget. We continue to expect materially lower DNC capital in 2024, driven by operational efficiency gains alone. Lastly, I'd like to discuss our multi-decade inventory position. Turning to slide number five, titled AR has the largest low-cost inventory. This chart compares inventory positions across our natural gas peer group based on data from a recent third party report. Antero has the most sub $2.75 per MCFE drilling inventory at 22 years. It's important to note that this inventory comparison is after our peers spent a combined $17 billion on acquisitions over the last two years. In contrast, we remain focused on our organic leasing efforts where we've invested some $340 million over that same time to acquire targeted drilling locations within our development footprint. On average, we've been able to add locations for approximately a million dollars per location through this program. That is less than half of the over $2 million average cost per location for the pier acquisitions. Touching on the recent flurry of M&A headlines, in our opinion, drivers for M&A usually relate to either, one, limited core inventory, two, a lack of pipeline capacity to move your production out of basin, or three, for balance sheet repair. With a peer-leading low-cost inventory position, the largest firm transportation portfolio in the E&P sector, and low absolute debt and leverage, Antero can stay focused on improving operations, which we believe drives ultimate shareholder value. 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 Cantalongo, for his comments. Dave?

Thanks, Paul. In the second half of 2023, we have seen an uptick in crude pricing as the macroeconomic concerns in the first half of the year have eased and new geopolitical concerns in the Middle East have increased the risk premium in the market. The most recent conflict has added volatility to global energy prices, particularly crude, with market fears of war spreading further in the Middle East. Turning to propane, While absolute propane inventories are high and prices as a percent of WTI lower than usual, fundamentals are painting a better picture in recent weeks. The U.S. recently set a new weekly record high for propane exports and printed two consecutive weeks above 2 million barrels per day. Overall, propane export demand has been consistently strong in its average 1.6 million barrels per day year-to-date, shown on slide 6. about 250,000 barrels per day or 19% above the 2022 full year average. As we move into 2024, exports are expected to further increase causing potential tightness in U.S. Gulf Coast stock capacity. As a reminder, Antero exports over 50% of our C3 Plus production skewed heavily towards propane in particular, directly out of the Marcus Hook Terminal in Pennsylvania, And therefore, Anterra's export volumes are not impacted by constraints at the Gulf Coast export docks. In fact, with tight capacity in the Gulf Coast and strong international pricing, Anterra will be able to take advantage of its capacity out of Marcus Hook to capture these wide arbitrage opportunities. The growing call on propane exports has kept propane days of supply in line with historical levels. As seen on slide seven, while total propane inventories sit just above the top of the five-year range. Propane days of supply is currently just one day above the five-year average. Adding to the strong exports, seasonal demand will also start to increase in the fourth quarter as the market heads into the winter heating season. Strong heating demand this winter could quickly deplete the surplus that the mild 2022 to 2023 winter added to inventories' last withdrawal season. Now let's turn to slide 8, titled China PDH Still Up Continues. A major driver of strong propane exports this year has been growing demand from China, which has seen stronger year-over-year petrochemical demand despite some macroeconomic headwinds there. This year through August, 120,000 barrels a day of propane dehydrogenation, or PDH capacity, has been added in China. Industry estimates show that another 340,000 barrels a day of capacity is expected to come online between now and the end of 2024. Even with just one-fourth of PDH capacity additions online that are expected over 2023 and 2024, the ramp in imports to China from the U.S. year over year has been substantial. For January through August this year, the amount of U.S. propane cargoes delivered to China increased by 44% year-over-year, compared with a 19% increase year-over-year from the Middle East. This demonstrates that U.S. exports continue to make up the marginal increase required by Chinese propane demand. Meanwhile, on the U.S. supply side, rate counts continue to drop, now down 21% year-to-date, as seen on slide 9. This represents a drop of 163 rigs across both oil and gas-directed rigs. Permian basin rig counts are down 40 year-to-date and have accelerated decreases in recent weeks, falling to just above 300 total rigs, losing 20 rigs between the end of September and start of October. Additionally, key NGL-producing basins such as the Eagleford and Scoop stack have seen their rig counts decline 35% and 45% year-to-date. Overall, we believe that with supportive fundamentals domestically and positive demand signals from China, there are signs of improvement for NGLs heading into 2024, and in particular for producers like Intero with direct access to international markets. With that, I'll turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Thanks, Dave. I will start on slide number 10 titled, Dramatic Reduction in Activity Will Limit Production Growth. Starting with the rig count chart at the top of the slide, we have seen the Appalachia plus Haynesville rig count decline by approximately 50 drilling rigs since the beginning of this year. This compares to the similar rig decline that we experienced back in 2019. As shown on the natural gas production chart, to materialize. However, U.S. natural gas production ultimately declined by as much as 10%. Further, it took almost two years to get back to the 2019 highs. Today, we are just about six months out from when rigs began to drop in a meaningful and sustained way. An important distinction this time around, however, is that over 70% of the rig declines this cycle have come from the higher-decline Hainesville Basin. A short contrast to 2019 when the majority of rig drops came from the lower decline Appalachian Basin. In summary, we believe the sharp decline in rigs and completion crews will curb production growth in 2024, helping to balance the U.S. natural gas market. As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor. as shown on slide number 11, titled Firm Transportation to the LNG Fairway. Our firm transportation portfolio provides us with direct exposure to growing LNG demand along the Gulf Coast, and importantly, into Tier 1 pricing points along the Gulf Coast. Next, I'll turn to slide number 12, titled Not All Firm Transportation to the Gulf Coast is Equal. This slide illustrates the significant benefit in selling your gas at Tier 1 Gulf Coast pricing. Based on the current strip, Tier 1 prices reflect increasing premiums to NYMEX in 2024 and 2025, including the TGP 500 line, where premiums have increased to 29 cents above NYMEX in 2026. Meanwhile, some peers claim they can move their gas to the Gulf Coast but they're actually stuck in Tier 3, selling their gas at 24 cents back of NYMEX in both 2024 and 2025. The yellow stars on the map depict Ontario sales points, which were strategically negotiated to bring our volumes directly to the LNG doorstep. As depicted in the pie chart on the top left of the slide, Ontario sells 90% of its gas at Tier 1 pricing. This compares to the average of our peers, which sell 67% of their Gulf Coast directed volume into Tier 2 and 3 pricing. Looking ahead over the next two years, as LNG export capacity increases by nearly 6 BCF, we expect Antero sales points to be priced at even higher premiums to NYMEX as these LNG facilities compete for supply. A key competitive advantage between Antero versus our peers. With that, I will turn it over to Mike Kennedy, Antero's CFO. Thanks, Justin.

First, I'd like to add some additional comments on how we view the outlook for natural gas. Slide number 13 examines the historical relationship between storage levels and natural gas prices. This chart illustrates the high correlation that storage and pricing have to each other. As you would expect, when storage levels are below or above the five-year average, natural gas prices are low. And when storage levels are below the five-year average, prices trend higher. Since 2020, which is essentially when the industry moved to maintenance production, when storage levels are flat with the five-year level, Natural gas prices averaged $4 per MCF. Looking at 2023, storage levels rose to as high as 25% above the five-year average, resulting in negative sentiment and low gas prices. However, during the second half of 2023, record levels of power burn drove down this storage surplus, which sits at just 5% today. With production expected to moderate in the coming months and LNG exports hitting record highs, we anticipate storage levels will balance with the five-year average in 2024, thus providing support to natural gas prices. Expanding on this point, if you have today's exact storage level at this same time next year, your surplus would go from almost 200 BCF over the five-year average today to a surplus of just 50 BCF to next year's five-year average. Next, I'd like to go a little deeper on the capital efficiency improvements that Paul touched on in his comments. The scatter plot on slide number 14 illustrates the year-over-year change in production on the y-axis and the year-over-year change in drilling and completion capital on the x-axis for the Appalachian EMTs. While targeting a maintenance capital program, Antero's third quarter 2023 production actually grew 9% year over year. Conversely, while our peer group attempted to target a maintenance capital program, their volumes actually declined year over year. When you compare the production growth to the drilling and completion capital invested to deliver that growth, We have been far and away the most capital efficient operator in Appalachia. As a rule of thumb internally, we view each hundred million dollar change of capital to result in approximately a hundred million day change in production, both up and down. Exit rate 2022 to exit rate 2023, we expect production growth of 225 million per day. which implies that our capital efficiency gains and well performance have reduced true maintenance capital by roughly $225 million all else equal. This implies a true maintenance capital budget to hold 2022 volumes of 3.2 BCFE a day of approximately $650 to $700 million. Looking ahead to 2024, Our improved capital efficiency and well performance provides us with significant flexibility during our upcoming budgeting process to either hold our current third and fourth quarter volumes flat at capital approximately 10% lower than our 2023 capital or to hold our previously communicated maintenance volumes of 3.35 to 3.4 BCFP a day at an even lower capital level. Either way, this lower capital outlook combined with the higher natural gas strip is expected to lead to substantial free cash flow in 2024 and beyond. With that, I will now turn the call over to the operator for questions.

Thank you. At this time, we'll be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment while we poll for questions. Our first question today comes from Bert Donis of Truist. Please proceed with your question.

Hi. Good morning, guys. On the difference between the 10% lower capital program versus the meaningfully lower capital, you just addressed some of the questions, but what spurred the change in the messaging? Is it just the efficiencies you're seeing? Is there some sort of investor feedback, or are you looking at the strip and that changed your mind, or was this always the plan? You just laid it out a little bit simpler for us the first time.

Another change is our production is well ahead of expectations. We didn't anticipate to be $225 million a day over exit rate to exit rate. You know, we've now raised our guidance twice throughout the year, and we expect gross wellhead volumes in Q4 to be higher than Q3 as well. And so just the well performance, the capital efficiency, all those assumptions underlying those have improved. And so we have to figure out and this upcoming budget process, the assumptions that we use, how we risk those. We typically have some risking. That's why we always hit our numbers and go from there and see which levels we want to hit. We can dial in pretty much any production we want at any capital at the required capital levels. So when you change those assumptions, it changes the capital. So 10% would be holding kind of the current run rate. we'd be 10% lower. But if we held the previously communicated guidance for maintenance capital, it'd be well below that 10%.

That's great. And then my follow-up is kind of related, but say the strip plays out, maybe we actually get a few cold winters, LNG demand doesn't get pushed out, you see an attractive growth environment. Does Interos kind of stable operations plan change or do you maybe stair step just up to a higher level and maybe hedge some of that risk away? I have a feeling some of your peers would probably try to respond to, you know, a bull and bear environment, but you know, do you stay stable or with your new, you know, efficient program, maybe you could, you know, respond to the strip. That's all.

No, we'd stay stable. We're trying to achieve maintenance capital. It's just, as we said, it just continues to improve. So, um, Ultimately, we'll get to a level where the maintenance capital assumptions we have equate to actuals, and so we'll stay at that maintenance capital program and then pay down the remainder of our debt and return capital to shareholders.

Thanks so much.

The next question comes from Imang Tridari of Goldman Sachs. Please proceed with your question.

Hi. Good morning, and thank you for taking my questions. Appreciate all the details on the propane macro. I wanted to circle back on your thoughts around upside and both downside risk to propane prices heading into next year. Like you said, you are positive on propane demand for 2024 with the build out of PDH facility. But I wanted to understand if you see any downside risk there, and also on the supply side, given healthy oil prices, do you see any risk of supply exceeding EIA expectations of around 50,000 barrels per day of good luck next year?

Yeah, good morning, Aman. On the propane side, I would say the biggest risk we kind of highlighted in our comments on what could happen you know, in the Gulf Coast with Mount Bellevue pricing, if you see those docks really hit full utilization. We even saw here in the third quarter, three of the big four facilities had extended planned or unplanned maintenance, or I guess third quarter into fourth quarter. That has driven some lower propane export numbers despite the records that we've reported. So, I think we would have seen higher overall export numbers here in recent months and lower lower inventories than where we stand today had that not happened, but it points to the fact that those facilities are becoming increasingly higher utilized, and that's really a big differentiator for Antero. If you go back to, I think it was back in 2019, the first kind of full year we had Mariner East online, we had very high utilizations in the U.S. Gulf Coast, and the arms were wide. They were, you know, 15, 20 to 25 cents a gallon, and you saw us capture that, and so that's that's ultimately something that we could see play out this year, sorry, for 2024, where you could have weaker Montbelvi pricing, like you've seen here in the third quarter, but strong ARBs and Intero. As we move into 2024, we do capture some of that value today. We have some contracts that are term deals that roll off before the end of the first quarter. And so beyond that in 2024, we're we're fully uncontracted and able to capture that value. And so I think you'll see that reflected in our NGL realizations if that plays out like it's looking right now on the propane side. I think the other tailwind is just on the freight costs. You've seen freight costs stay elevated this year. We hit record levels a month or so ago, and that's been driven by some delays getting through the Panama Canal, the well-publicized low water levels that they have down there. And so that's, again, something temporary. And if you look at the futures curves for LPG freight costs, they're backward-dated. U.S. to Asia is about $0.12 per gallon lower by mid-summer of 2024 versus now, and that's a pretty steady decline in those expected costs. So that'll also allow prices in the U.S. to rise as well as that freight cost declines. On the oil side, you know, nothing I think that we can provide specific to that. Obviously, there's a lot of moving parts with geopolitical risks and OPEC. I do think we're seeing, you know, particularly on the NGL side, a supply response as we've seen the rig count decline. You saw some very – steep increases in U.S. propane inventories back in the spring, even though exports were strong. And as we move through the back half of the year with similar levels on exports, you've seen those propane increases wane. We've come back into the five-year range. So I think that, to me, points to what we talked about with the rig counts, where things are responding on the supply side here domestically as well. And we'll have to see if that plays out on the oil side in 2024.

Very helpful. Thank you so much for all the color. I guess the next question which I had is I just wanted to follow up on the operation momentum which has been really strong here recently. Would love your initial thoughts on 2024 production and capital spending outlook and also if you can touch a little bit on deflation and what you're expecting there too which can probably add some upside to the 10% reduction number which you were talking about from a capital spending perspective.

Yeah, we're not baking in any deflation. My comments earlier were just addressing the operational efficiencies, capital program efficiencies and well performance that we've experienced this year. And assuming those type of efficiencies and performance will allow us to kind of dial in which capital we want, depending on whether we want to keep today's production flat or what we communicated earlier, the kind of the annual average from last time of 3.35 to 3.4. So that's what we're in the process of doing this quarter. So we'll go through our typical process and then come out with those. Generally, we come out with the budget and with the February release, with the year-end release. So we'll just work through that and continue to watch the market, but we're not assuming any deflationary aspects in that capital budget. That would just be upside.

That's really helpful. Thank you.

The next question is from Arun Jharam of JP Morgan. Please proceed with your question.

Yeah, Mike, I wanted to get your thoughts on, so you said 10% lower CapEx next year, and that would be to keep the current production outlook, what you're doing today, relatively flat. And then if you drill down to 3.35 to 3.4, it would be more than 10%. I just wonder if you can clarify those comments. Got it. Got it. And then just, I know it's hard to estimate land spend because you're opportunistic on that front, but if you're recommending kind of a placeholder for land spend in 2024, any just broad thoughts on that?

Yeah, it was the last comment. We always target in a non, in a traditional year unlike 2022 when we had a pretty big effort to increase that land position with the amount of free cash flow we had. But we typically always target $75 million to $100 million a year. That's our traditional and kind of customary commodity price environments. So that's why you would assume, you know, this third quarter, you know, ratcheted down to $27 million. We'll be down in the fourth quarter from there, too. So that run rates around, we're at like $100 million, but Generally, it's $75 to $100 million capital budget for land.

Great. And just my follow-up, Mike, is how do you think we should think about production costs next year? Obviously, fuel costs, maybe some of the savings are transitory, but you've got CPI inflators, the AM escalator. But just give us a broad strokes around thinking about kind of production costs as we move into 2024.

Yeah, it's really commodity price dependent. You know, I mean, we pretty much have flat LOE. Next year, we do have an uptick of about five cents on production ad valorem taxes, because that's just commodity price, gas prices up, you know, 75 cents. So that's how you kind of get to that. And then similar on the GP&T up, you know, a nickel as well, just on the fuel cost. So Assuming we have these increased, you know, a 350 type of commodity price next year, which is the strip, we're up about a dime.

A dime? What about the AM escalator?

That's baked into that dime.

That's baked into that? Okay.

Yeah.

Thanks, guys.

Yep.

Thank you.

The next question is from Roger Reed of Wells Fargo. Please proceed with your question.

Hey, good morning. Thanks. I guess a couple of things I'd like to just dig into a little bit as you think about the the improvement you've shown in capital efficiencies. Without getting too granular into the outlook, what is your expectation on how much further you can go with that?

Well, you know, that's a good question. You know, what improved from this year is we were assuming Coming into the year that we'd averaged about eight point seven stages per day and completions and about six to seven days per 10k and drilling and we've improved two stages per day Or more than that at 11 stages and completions and about a day improvement on the drilling This time last year. I would have said that we wouldn't have been able to achieve those improvements so We'll probably assume those same levels I just mentioned going into next year, but we're always looking for continuous improvement. Paul mentioned the record completion hours, the 17 hours per day on the completion. It would be great to improve upon that. If you did, you could maybe get some out of the completion stages per day, but those are still probably industry-leading levels, so I wouldn't assume any improvement from there, but we're always trying to achieve it.

No, that's fair. It's certainly been a nice driver within the industry overall, but I'm glad to see all at the top of the pack. The only other question I've got really is, is there anything we should think about as we look into, let's just say the next six months or so, that you would expect changes on realizations across your portfolio? Meaning, you know, whether it's the gas side or the NGL side, Or we should just basically look at, you know, kind of where we've been and think that's the right way to look at things.

No, we were wide in Q3 because of the maintenance on Cove Point, Tennessee pipe. So we sold about 15% to TECO, and that was wide in the third quarter. It's always weak in the third and fourth quarters during the shoulder months going into winter. That has improved quite a bit in Q4. Those maintenance capital events have subsided. So we'll sell a lot more on the Gulf Coast. And then when you look at the Gulf Coast going into the winter, those are actually at premium prices to Henry Hub, like Justin mentioned on his slide, that interesting slide around the Tier 1 levels. And it goes right into the LNG corridor where there's a lot of demand for the gas. We also have quite a bit going to Chicago during the winter, which may be up to $0.50 a dollar ahead of Henry Hub right now. And we're bringing seven wells on in the Utica just in time to enjoy those Chicago gas prices filling our RECs capacity. So, you know, I see realizations improving quite a bit in the fourth quarter and heading into 2024. All right.

Thank you. I'll leave it there.

The next question is from David Deckelbaum of Cohen. Please proceed with your question.

Thanks for getting me on the call, guys. I appreciate the time. Mike, you threw out some exciting numbers, I think, for the street for next year. The 650, I guess, true maintenance versus maybe an 800 to stay at that 3.5 level or so. Can you just talk about the variables that are influencing that decision? And I guess as I think about it, is there a break-even price? Is it a $4 guess that would incentivize you to stay at that higher level level? Are you being influenced by perhaps like some of the revolver balance that you have right now and wanting to accelerate max free cash in the beginning of the year? I guess what would be the primary factors that you consider between those two variables?

Yeah, the 650 to 700 was what I would have been required to hold that 3.2 BCFE a day flat. To hold 335 to 34 would have been $100 million or so. Higher, as I mentioned, the rule of thumb is every 100 million a day of capital is 100 million a day of production. So higher than that to hold the 3.35, 3.4, but well below that 10%. That's kind of how we think about it. It's going to be somewhat commodity price dependent, David. We're obviously heavily influenced by generating free cash flow and paying down all our debt and returning capital to shareholders. So that's ultimately the number one filter we use. We also want to be extremely capital efficient. So we do have kind of a two and a half rigs signed up for next year. So that's kind of the men case. And then we kind of have a floating, we have one completion crew and then a floating completion crew. So that's kind of how we manage capital. So we have the flexibility to do whichever program we choose or a variation in between. And that's something we'll have to consider as we go through this budgeting process and watch commodity prices over the next couple of months.

It doesn't sound like – as you think about, like, a multi-year progression, are you inherently more operationally efficient with sort of that three-rig and two-crew program?

Yes, we're – much more efficient than that. And when you think about that, we have the drilling JV, so we really only have 85% of that. And this year is really a three rig program and a one and a half completion crew. Next year, you're kind of looking at a two and a half rig and a one and a half completion crew, again, only having 85%. And we can set that down the following year when the drilling JV ends. So we've just become remarkably efficient just with our continuous acreage position, having all the infrastructure in place, having all the transport, having all the processing, and then working on our operational efficiencies and having this much success. We've just continued to become more and more efficient and drill terrific wells.

Would you guys just mind updating us? It's all very helpful, and just the shellcracker progression and some of the assumptions that we should be thinking about your ethane volumes for next year.

Yeah, nothing new to what they've guided publicly on. They're doing some work on one of the three downstream units that's expected to be wrapped up by the end of the year. So 2024, we expect to see significantly higher and more stable volumes from us going to that facility. So you would expect to see that show up in our net production. We also have a handful of other customers that will be calling on us for more ethane on contracts that are ramping up in 2024 as well. So I think you'll see a combination of the shellcracker effect as well as others in the net production in 2024 on the ethane side.

Yeah, and then further to that, when it comes to the ethane cracker, we always risk that quite heavily, and that's why you see even with the startup companies delays that we've had this year with the ethane cracker. We're still well ahead of production guidance, and we actually guided our ethane volumes down recently, so the production that we're talking about levels will be risked, you know, for further kind of just startup, your typical startup issues, and then if the ethane cracker actually does perform a little bit better in the year, that will just be upside the volumes.

Thanks, Mike. You answered my question this morning. I appreciate it, guys.

The next question is from Jean Ann Salisbury of Bernstein. Please proceed with your question.

Hi. Good morning. As you mentioned, we're seeing LPG export capacity tightness along the Gulf Coast. How much flexibility does ANTERO have to export more from the East Coast, which I think has a little bit more spare capacity?

Well, we do a pretty good job with that, in particular in the time of the year where you want to export as much as possible, which is the shoulder months, spring through summer and into the fall. There's times of the year where we're sending 85-90% of our propane to the international dock, so hard to really get much above that, but you want to leave some flexibility for domestic and for variations in production month to month, but we during the non-heating season.

OK. That makes sense. And then you kind of touched on this on an earlier question, but your local gas realizations were a little bit lower due to maintenance at Cove Point in Tennessee. Was that kind of this perfect storm where it was also kind of poor basis because of the high storage? And is that like a lot more maintenance than usual in the season? Or do you view it as just everything is more volatile now that everything's quite full, that when there's any maintenance event, it kind of blows up?

No, that's a good way to put it. That was the perfect storm. The backup volumes from Cove Point and the TECO and then the backup volumes from Tennessee and the TECO just led to really wide bases. It was historic. It was the widest bases we've seen at TECO. So all of that has subsided, though, going into Q4 with Cove Point being back on and Tennessee flowing.

Great. That's all for me.

Thanks. Yep.

The next question is from Jacob Roberts of Tudor Pickering and Holt. Please proceed with your question.

Good morning. Good morning. We appreciate the macro commentary and the detail you guys give in the near to medium term. Just curious, in maybe a 2025-plus timeframe, what you would need to see in the forward curve to potentially allocate more capital to drier areas?

Yeah, I mean, Good question. It's obviously always relative to liquids, but liquids does have some constraints around processing. So you could envision a scenario if there is a call on gas, which we believe could very much occur with the build out of the LNG during that time frame you referenced, that you would need more gas and we have the ability to deliver more gas through our dry gas acreage inventory. You could see a scenario there. But right now, we just program in maintenance capital, holding these levels flat, and then enjoying the higher commodity prices and the free cash flow and paying down debt and buying back shares. But there is a possibility if it goes quite high. You know, we essentially have over 1,000 locations of premium dry gas inventory held by production over in our eastern half of the field. So we have that optionality. But right now, when you model it out, we're just at maintenance capital.

Appreciate it. That's all for me. Yep.

The next question is from Greg Brody of Bank of America. Please proceed with your question.

Good morning, guys. Hi, Greg. Just on the volume decision, whether you keep 3Q, 4Q flat or what you originally thought you would be, how do you think about that and optimizing the entire midstream business? Tell us how you think through that.

Yeah, we don't really think about Antero Midstream. We think about Antero Resources and its free cash flow profile. Antero Midstream is just a beneficiary of the growth and capital efficiencies, and that all translates to them as well because they're getting much more production per well, and it's very continuous acreage, so very capital efficient. But We think of it from an AR perspective. How do we maximize free cash flow and the commodity price environment we're in? So if you have higher commodity prices, that's what the strip suggests, then that would lead most likely to trying to maintain a higher production level. If you had lower commodity prices, more like 2023 type pricing on natural gas, you would probably favor a lower capital budget. So that's kind of what we think. We definitely want to maximize free cash flow at AR and use it to pay down the debt and return capital.

And just moving to consolidation, obviously, it's been a big theme as of late. Obviously, you have a huge inventory that you can access, so there isn't necessarily a need to buy anything. But how are you thinking about that today? And then how does interim midstream fit into that discussion as well, if at all?

Yeah, well, we're just focused on that organic leasing strategy. That's the best capital we can spend from an M&A perspective. And Intero Midstream gets all the acreage from AR dedicated. And when we acquire the acreage, we work really hard. And 99% of the time, it comes with free and clear from any midstream dedication. So it's immediately dedicated to Intero Midstream. So those acreage ads really benefit AM, and that's why they have over a 20-year life of inventory behind their midstream assets. So the acreage accrues to AM as well.

But then just to give you a bigger picture, you're seeing a lot of peers get – maybe there's discussions of peers getting bigger. I'm curious if that's making you think a little harder about M&A or status quo.

No, we're focused on the operational efficiencies. I mean, we've grown 9% year over year without doing M&A. So we are very operationally efficient. We've got the no constraints. We've got all the acreage locations, the midstream, the processing, the firm transport to the LNG corridor, the balance sheet. So you put that all together, there's really no need for M&A. And then when you look at our operational efficiencies, it's really hard for us to think of any play that would compete for capital compared to our future programs. So That's why we're focused on the organic leasing.

All makes sense and consistent with the past. And just one last one, something you said on the call, which I think is consistent with what you've implied in the past, but I think you have this debt target near term. I believe it's about a billion dollars. You made a comment about paying down the debt. Is there an actual goal to get debt at Ontario Resources to zero, or is a billion the right number? Yeah.

Now, yes, zero is the target.

If you were to take a guess as to when that would happen by, is that just a function of paying down debt as it gets to... Yeah, some of the commodity prices.

You know, I would say that, like you mentioned, it's always been billions the goal. So the free cash flow will go to that first. Then once you get to the billion and below, that would get you out of the credit facility in the 26 notes that are callable in January. Then you look at it and say, well... maybe, you know, 50-50, probably a little bit more on the return of capital, but it'll just depend on commodity prices and where our bonds are priced. I mean, our 20-30s are, you know, five and three-eighths, so that's a good piece of paper. That's $600 million, so you may want to kind of keep that in the capital structure and buy back shares or return capital, but the other debt pieces are at pretty high interest rates that we'd like to take out.

I appreciate the time, guys, and all the color. Thanks.

All right. Thanks, Jeffrey. The next question is from Subha Chandra of Benchmark. Please proceed with your question.

Good morning. On the spot to sales improvement there over the years, I think a big element of that is just, well, sort of waiting on completion. So I guess my question is, Can you describe sort of the path you took to reduce that time and if you think that the program is going to, you know, maximize or I should say minimize that variable going forward?

Yeah, we don't really have any waiting on completion. We try to plan all of our programs that it's just in time. When you're done drilling the well, you're on that pad completing it as soon as possible. So that's how we do it. You know, there may be a week here or there where there's some white, we call it white space in the schedule, but generally we try to minimize that and be as efficient as possible and not have any ducks because that's non-performing capital.

Yeah. So I guess, you know, several years back when it was, you know, 400 days plus, et cetera, What was different then?

We can see on that slide three, the pumping hours are up like 65%. That's an 86% increase in completion stages per day. And then the drilling times, too, have greatly improved. So it's a combination of both. But to go from 427 to 860, it's an over 60% reduction. And that 160 is definitely sustainable.

Okay. And just a clarification, I guess, on the debt reduction question. Zero, I guess, is the ultimate target. I guess bank debt is there, I would assume, as a top priority to reduce to zero first. And is that sort of... Yeah, is that sort of a priority before there's meaningful share buybacks, or how do you sort of balance the two?

Yes, the goal is always, you know, we had zero bank debt essentially, or near zero coming into the year, so that would be the first use of the free cash flow is paying down that credit facility, then after that it would be, you know, over 50% to return to shareholders, but we also have the 26 notes There's less than $100 million on them callable in January, so I would kind of lump that together with the credit facility.

Thanks, Mike.

Yeah.

There are no additional questions at this time. I would like to turn the call back to Brendan Kruger 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. You may disconnect your lines at this time. Thank you for your participation.