Antero Resources Q3 2023 Earnings Call Transcript

Quartr
Provided by Quartr
October 26, 2023

There are 15 speakers on the call.

Operator

Greetings, and welcome to Antero Resources Q3 2023 Earnings Conference Call. At this time, all participants are in a listen only mode. As a reminder, this conference is being recorded.

Speaker 1

Only mode. I would now like to turn the

Operator

conference over to your host, Brendan Krueger, Chief Financial Officer of Antero Midstream and Vice President of Finance. Only

Speaker 2

mode. Thank you. Good morning, everyone. Thank you for joining us for Antero's Q3 2023 investor conference call. Only mode.

Speaker 2

We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q and 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. Only mode. Today's call may contain certain non GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, only mode, including reconciliations to the most comparable GAAP financial measures.

Speaker 2

Joining me on the call today are Paul Rady, Chairman, CEO and President only. Michael Kennedy, CFO Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul. Open. Thank you, Brendan.

Speaker 3

I'll start my comments on Slide number 3 titled Drilling and Completion Efficiencies. Only. After a record breaking first half of twenty twenty three operationally, we continued to build on this momentum during the Q3. 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.

Speaker 3

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 spudding a open. Turning that entire pad to sales.

Speaker 3

Since 2019, our cycle times have decreased only by an impressive 65% and averaged just 160 days through the 1st 3 quarters of 2023. In June, we had the fastest cycle times in our company history at 129 days. Shorter cycle times means of higher capital efficiency. Highlighting this point, we completed roughly 80% of our 2023 expected completion stages during the 1st 9 months of 2023. Now let's turn to slide number 4.

Speaker 3

Only. Faster cycle times and improving well performance has led to 2 production guidance increases in 20 only. This gain in capital efficiencies is highlighted by our 9% total production growth in the 3rd quarter 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 225,000,000 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.

Speaker 3

We continue to expect materially lower D and C capital in of 2024, driven by operational efficiency gains alone. Lastly, I'd like to discuss our multi decade inventory position. Turning to Slide number 5 titled across our natural gas peer group based on data from a recent third party report. Antero has the most sub of $2.75 per Mcfe Drilling Inventory at 22 years. It's important to note that of this inventory comparison is after our peers spent a combined $17,000,000,000 on acquisitions over the last 2 years.

Speaker 3

Of $340,000,000 over that same time to acquire targeted drilling locations within our development footprint. That is less than half of the over $2,000,000 average cost per location for the peer acquisitions. Touching on the recent flurry of M and A headlines, in our opinion, drivers for M and A usually relate to either 1, limited core inventory 2, a lack of pipeline capacity to move your production out of basin or 3, for balance over the

Speaker 4

next few years. With the

Speaker 3

peer leading low cost inventory position, the largest firm transportation portfolio in the E and P sector and low absolute debt and leverage, Antero can stay focused on improving operations, which we believe drives of the 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 of. Dave Cantelongo for his comments. Dave? Thanks, Paul.

Speaker 5

Of the Middle East have increased the risk premium in the market. The most recent conflict has added volatility to global energy prices, only mode, particularly crude with market fears of war spreading further in the Middle East. Turning to propane, only. 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.

Speaker 5

S. Recently set a new weekly record high for propane exports and printed 2 consecutive weeks above 2,000,000 barrels per day. Over. Overall, propane export demand has been consistently strong in its average 1,600,000 barrels per day year to date. Shown on Slide 6, of about 250,000 barrels per day or 19% above the 2022 full year average.

Speaker 5

Only mode. As we move into 2024, exports are expected to further increase causing potential tightness in U. S. Gulf Coast stock capacity. Only mode.

Speaker 5

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 Antero's export volumes are not impacted by constraints at the Gulf Coast export docks. Only mode. In fact, with tight capacity in the Gulf Coast and strong international pricing, Antares 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 to all levels. As seen on Slide 7, while total propane inventories sit just above the top of the 5 year range, propane days of supply is of the year and are currently just one day above the 5 year average.

Speaker 5

Adding to the strong exports, seasonal demand will also start to increase in the 4th quarter as the market heads into the winter heating season. Strong heating demand this winter could quickly deplete the surplus at the mild 2022 to 2023 winter added to inventory's last withdrawal season. Only mode. Now let's turn to Slide 8 titled China PDH Fillout Continues. A major driver of strong propane

Speaker 1

over the course of this

Speaker 5

year has been growing demand from China, which has seen stronger year over year petrochemical demand despite some macroeconomic headwinds there. Over. This year through August, 120,000 barrels a day of propane dehydrogenation or PDH capacity has been added in China. Only. Industry estimates show that another 340,000 barrels a day of capacity is expected to come online between now and the end of 2024.

Speaker 5

Only. Even with just 1 fourth of PDH capacity additions online that are expected over 2023 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.

Speaker 5

S. Propane cargoes over the course of the year. The results were recorded in the quarter, which was recorded in the quarter. The results were recorded in the quarter, which was only mode. This demonstrates that U.

Speaker 5

S. Exports continue to make up the marginal increase required by Chinese propane demand. Meanwhile, on the U. S. Supply side, rig counts continue to drop, now down 21% year to date as seen on Slide 9.

Speaker 5

On. Permian Basin rig counts are down 40 year to date and have accelerated decreases in recent weeks, falling to just above 300 total rigs, of losing 20 rigs between the end of September and start of October. Additionally, key NGL producing basins only mode such as the Eagle Ford and SCOOPSTACK have seen their rig counts decline 35% 45% year to date. Over the phone and in particular for producers like Antero 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.

Speaker 5

Only mode. Thanks, Dave. I will start on Slide number 10 titled Dramatic Reduction in Activity Will Limit Production Growth. Only mode. 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 over the course of the year.

Speaker 5

This compares to the similar rig decline that we experienced back in 2019. Only mode. As shown on the natural gas production chart at the bottom of the slide, it took over 6 months to materialize. Only mode. However, U.

Speaker 5

S. Natural gas production ultimately declined by as much as 10%. Further, it took almost 2 years to get back to the 20 open. Today, we are just about 6 months out from when rigs began to drop in a meaningful and sustained way. Only mode.

Speaker 5

An important distinction this time around, however, is that over 70% of the rate declines this cycle only mode. We have come from the higher decline Haynesville Basin. A short contrast to 2019 when the majority of rig drops came from the lower decline over the Appalachian Basin. In summary, we believe the sharp decline in rigs and completion crews will curb production growth in 2024, only mode, helping to balance the U. S.

Speaker 5

Natural gas market. As a reminder, we sell substantially all of our natural gas out of basin, only mode, including approximately 75% to the LNG corridor, as shown on Slide number 11, titled of our firm transportation portfolio provides us with direct of exposure to growing LNG demand along the Gulf Coast and importantly into Tier 1 pricing points along the Gulf Coast. Only mode. 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

Speaker 1

of selling your gas at Tier 1 Gulf

Speaker 5

Coast pricing. Based on the current strip, Tier 1 prices reflect of increasing premiums to NYMEX in 2024 2025, including the TGP 500 line, where premiums have increased to $0.29 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 $0.24 back of NYMEX in both 2024 2025. The yellow stars on the map depict Antero sales points, only mode, which were strategically negotiated to bring our volumes directly to the LNG doorstep. As depicted in the pie chart on the top over the course of the year.

Speaker 5

This compares to the average of our peers, which sell 60% 7% of their Gulf Coast directed volume into Tier 2 and 3 pricing. Looking ahead over the next 2 years as LNG export capacity increases by nearly 6 Bcf, only mode. We expect Antero sales points to be priced at even higher premiums to NYMEX as these LNG facilities compete for supply. Only mode. A key competitive advantage between Antero versus our peers.

Speaker 5

With that, I will turn it over to Mike Kennedy,

Speaker 4

over the phone. Thanks, Justin. First, I'd like to add some additional comments on how we view the outlook for natural gas. Over the next few quarters. Slide number 13 examines the historical relationship between storage levels and natural gas prices.

Speaker 4

Over the phone. This chart illustrates the high correlation that storage and pricing have to each other. As you would expect, open. When storage levels are below or above the 5 year average, natural gas prices are low. And when storage levels are below the 5 year average, open.

Speaker 4

When storage levels are flat with the 5 year level, natural gas prices average $4 per Mcf. Over. Looking at 2023, storage levels rose to as high as 25% above the 5 year average, only mode, resulting in negative sentiment and low gas prices. However, during the second half of twenty twenty three, record levels of over the next few quarters. Power burn drove down the storage surplus, which sits at just 5% today.

Speaker 4

Only. With production expected to moderate in the coming months and LNG exports hitting record highs, we anticipate storage levels will balance with of 5 year average in 2024, thus providing support to natural gas prices. Expanding on this point, if you have today's exact over the next year. Your surplus would go from almost 200 Bcf over the 5 year average today to a surplus of just 50 Bcf to next year's 5 year average. Next, of 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 E and Ps.

Speaker 4

While targeting a maintenance capital program, Antero's Q3 2023 production actually grew 9% year over year. Only. Conversely, while our peer group attempted to target a maintenance capital program, their volumes actually declined year over year. Of the most capital efficient operator in Appalachia. As a rule of thumb, internally, we view each $100,000,000 change of of capital to result in approximately 100,000,000 day change in production, both up and down.

Speaker 4

Over the next few quarters. Excluding the exit rate 2020, we expect production growth of $225,000,000 per day, which implies that our capital efficiency gains and well performance have reduced true maintenance capital by roughly $225,000,000 only mode, all else equal. This implies a true maintenance capital budget to hold 20.22 volumes of 3.2 Bcfe a day of approximately $650,000,000 to $700,000,000 Looking ahead to 2024,

Speaker 1

only mode.

Speaker 4

Our improved capital efficiency and well performance provides us with significant flexibility during our upcoming budgeting process to either hold our current 3rd and 4th quarter volumes flat at capital approximately 10% lower than our 2023 capital or to hold our previously communicated maintenance volumes of 3.35 Bcfe to 3.4 Bcfe a day at an even lower capital level. Either way, over the call. This lower capital outlook combined with the higher natural gas strip is expected to lead to substantial of free cash flow in 2024 and beyond. With that, I will now turn the call over to the operator for questions.

Operator

Only mode while we poll for questions. Our first question today comes from Bert Donis of Truist. Please proceed with your question.

Speaker 6

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? Of is it just the efficiencies you're seeing? Is there some sort of investor feedback?

Speaker 6

Or are you looking at the strip and that changed your mind? Or was this always the plan you just laid it off laid it out a little bit simpler for us the first time?

Speaker 4

No, the change is our production is well ahead of expectations. Over. We didn't anticipate to be $225,000,000 a day over exit rate to exit rate. We've now raised our guidance of 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.

Speaker 4

Only mode. And so we have to figure out in this upcoming budget process the assumptions that we use, how we risk those. We typically have of 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 wanted, any capital at the required capital levels. So when you change those assumptions, it changes the of capital.

Speaker 4

So 10% would be holding kind of the current run rate, would be 10% lower. But if we held the previously communicated guidance for maintenance capital, it'd be well below that 10%.

Speaker 6

That's great. And then my follow-up is kind of related, but say that 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 Entero's 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 a bull and bear environment, but of do you stay stable or with your new efficient program maybe you could respond to the strip?

Speaker 1

As all that you need.

Speaker 4

No, it stays stable. We're trying to achieve maintenance capital. It's just as we said, it just continues to improve. So Ultimately, we will 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.

Speaker 6

Only. Thanks so much.

Operator

The next question comes from Mimang Choudhary of Goldman Sachs. Please proceed with your question.

Speaker 7

Hi, good morning and thank you for taking my questions. I 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 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 of supply exceeding EIA expectations of around 50,000 barrels per day for the next year.

Speaker 5

Only. Yes, good morning, Yimang. On the propane side, I would say the biggest risk that we kind of highlighted in our comments on what could happen over the Gulf Coast with Mont Belvieu pricing, if you see those docks really hit full utilization, we even saw here in the 3rd quarter, 3 of the big four facilities had extended planned or unplanned maintenance or I guess Q3 into Q4 that has of 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.

Speaker 5

We had very high utilizations in the U. S. Gulf Coast and the ARBs were wide. They were $0.15 $0.20 to $0.25 a gallon and you saw us capture that. And listen.

Speaker 5

So that's ultimately something that we could see play out this year sorry for 2024 where you could have weaker Mont Belvieu pricing like you've seen here in the Q3, but strong ARBs in Antero. As we move into 2024, we do capture some of that value today. We have of some contracts that are term deals that roll off before the end of the Q1. And so beyond that in 2024, We're fully on contract and able to capture that value. And so I think you'll see that reflected in our NGL realizations if that plays out over.

Speaker 5

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 of publicize low water levels that they have down there. And so that's again something temporary. And if you look at the futures curves over the long term for LPG freight costs.

Speaker 5

Their backwardated U. S. To Asia is about $0.12 per gallon lower by midsummer of 2024 versus now and it's a pretty steady decline in those expected costs. So that will also allow prices in the U. S.

Speaker 5

To rise as well as that freight cost declines. On the oil side, nothing I think that we can provide specific to that. Obviously, there's a lot of moving parts with geopolitical risks in OPEC. I do think we're seeing particular on the NGL side of supply response as we've seen the rig count decline. You saw some very of steep increases in U.

Speaker 5

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 5 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 over the next few years.

Speaker 5

We'll have to see if that plays out on the oil side in 2024.

Speaker 7

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 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?

Speaker 4

Open. Yes. We're not baking in any deflation. My comments earlier were just addressing the operational efficiencies, of capital program efficiencies and well performance that we've experienced this year and assuming those type of 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 is 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.

Speaker 4

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 deflation of the ordinary aspects in that capital budget that would just be upside.

Speaker 7

That's really helpful. Thank you.

Speaker 3

Thank you.

Operator

Only. The next question is from Arun Jayaram of JPMorgan. Please proceed with your question.

Speaker 8

Open. Yes, Mike, I wanted to get your thoughts on, so you said 10% a little bit 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%. So if you can clarify his comments? Yes.

Speaker 8

Okay. 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?

Speaker 4

Yes. It was in the last comments. We always only mode 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 $75,000,000 to $100,000,000 a year. That's our traditional in

Speaker 1

kind of

Speaker 4

customary commodity price environments. So that's why you would assume. This Q3 ratcheted down of $27,000,000 will be down in the 4th quarter from there too. So that run rate is around we're at like $100,000,000 but only. Generally, it's $75,000,000 to $100,000,000 capital budget for land.

Speaker 8

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

Speaker 4

Yes. It's really commodity price of I mean, we pretty much have flat LOE. Next year, we do have an uptick of of about $0.05 on production ad valorem taxes because that's just commodity price. Gas price is up $0.75 So that's how you kind of get to that. And then similar on the GP and T up a nickel as well just on the fuel cost.

Speaker 4

So assuming we have these increased $3.50 type of commodity price next year, which is the strip, we're up about a dime. Only.

Speaker 8

A dime? What about the AM escalator?

Speaker 4

That's baked into that dime.

Operator

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

Speaker 9

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 improvement you've shown in capital efficiencies, without getting too granular to the outlook, What is your expectation on how much further you can go with that?

Speaker 4

Only. That's a good question. What improved from this year is we're assuming coming into the year that we'd average about 8.7 stages of the day in completions and at about 6 to 7 days per 10 ks in drilling and we've improved 2 stages per day or more than that at 11 stages in completions and about a day improvement on the drilling. This time last year, I would have said that we wouldn't have of the call to achieve those improvements. So, we'll probably assume those same levels that I just mentioned going into over the next year, but we're always looking for continuous improvement.

Speaker 4

Paul mentioned the record completion hours of 17 hours per day in the completion. Only. It would be great to improve upon that. If you did, you can maybe get some out of 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.

Speaker 9

No, it's fair. It's certainly been a nice driver within the industry overall, but I'm glad to see you all at the top of the pack. Only. 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 6 months or so, that you would expect changes on realizations across your portfolio, meaning whether it's the gas side or the NGL side or we should just basically look at kind of where we've been and think that's the right way to look at things.

Speaker 4

No, we were wide in Q3 because of the maintenance on Cove Point and Tennessee pipe. So we sold about 15% over the next few quarters. We're going to take a look at the Q3.

Speaker 1

We're going to take a look at the Q3. We're going to take

Speaker 4

a look at the Q3. That has improved quite a bit in Q4. Those maintenance capital events have subsided. So we'll over 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

Speaker 1

slide that interesting slide around the Tier 1 levels and goes

Speaker 4

right in the LNG over the long term. Interesting slide around the Tier one levels and 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, open, which may be up to $0.50 to $1 ahead of Henry Hub right now. And we're bringing 7 wells on in the Utica just in time to enjoy the of Chicago gas prices filling our REX capacity. So I see realizations improving quite a bit in the Q4 and heading into 2024.

Speaker 9

All right. Thank you. I'll leave it there.

Operator

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

Speaker 10

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?

Speaker 10

And I guess as I think about it is, is there a breakeven price? Is it $4 gas that would incentivize you to stay at that higher level? Are 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 of the primary factors that you consider between those two variables?

Speaker 4

Yes. The 650 to 700 was what I would have been required to hold that 3 point of 2 Bcfe a day flat, total 3.3.5 to 3.4 would have been 100,000,000 or so. Higher, as I mentioned, the rule of thumb is every $100,000,000 a day of capital is $100,000,000 a day of production. So Higher than that to hold to 3.35%, 3.4%, but well below that 10%. It's kind of how we think about it.

Speaker 4

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 only. So we do have kind of a 2.5 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.

Speaker 4

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.

Speaker 10

Only. It doesn't sound like as you think about like a multiyear progression, are you inherently more operationally efficient, with sort of that of 3 rig and 2 crew program?

Speaker 4

Yes. We are much more efficient than that. And when you about that. We have the drilling JV, so we really only have 85% of that. And this year is really a 3 rig program and a 1.5 completion crew.

Speaker 4

Over the next year, you're kind of looking at a 2.5 rig and a 1.5 completion crew, again, only having 85% and we can set that down over the following year when the drilling JV ends. So we've just become remarkably efficient just with our contiguous acreage position, having all

Speaker 1

the infrastructure in

Speaker 4

place, having all the structure in place, having all the transport, having all the processing and then working on our operational efficiencies and having of this much success. We just continue to become more and more efficient and drill terrific wells.

Speaker 10

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

Speaker 5

Yes, nothing new to what they've guided publicly on. They're doing some work on 1 of the 3 downstream units that's expected to be only. 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.

Speaker 5

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 of the shelf cracker effect as well as others in the net production in 2024 on the ethane side.

Speaker 4

Yes. And only. Further to that, when it comes to the ethane cracker, we always risk that quite heavily. And that's why you've seen with even with the startup over the long term. We've had this year with the ethane cracker.

Speaker 4

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 for further kind of just start up, Your typical start up issues and then if the ethane cracker actually does perform a little bit better in the year, that will just be outside the volumes.

Speaker 10

Thanks, Mike. You answered my questions. I appreciate it, guys.

Speaker 3

Yes. Thanks.

Operator

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

Speaker 11

Hi, good morning. As you mentioned, we're seeing LPG of 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?

Speaker 5

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 of spring through summer and into the fall. There's times of the year where we're sending 85%, 90% of our propane to of the international talks. So hard to really get much above that, but you want to leave some flexibility only mode for domestic and for variations in production month to month, but we try and maximize that as much as we can during the non heating season.

Speaker 11

Okay. 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 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 is quite full That is when there is any maintenance event, it kind of close out?

Speaker 4

Yes. That is a good way to put it. That was the perfect storm. The backup volumes from Cope Point and over the next few quarters. TECO and then the backup volumes in Tennessee and the TECO just led to really wide basis.

Speaker 4

It was historic. It was the widest basis we've seen at TECO. Open. So, all of that is subsided though going into Q4 with Cove Point being back on and Tennessee flowing. So

Speaker 11

Great. That's all for me. Thanks.

Speaker 1

Only.

Operator

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

Speaker 2

Only mode. Good morning.

Speaker 12

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

Speaker 4

Yes. I mean, only. 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 timeframe you referenced You need more gas and we have the ability to deliver more gas through our dry gas acreage inventory.

Speaker 4

You could see a scenario there. Open. 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 and buying back shares, but there is a possibility if it goes quite high. 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 of maintenance capital.

Speaker 1

Appreciate it. That's all for me.

Speaker 5

Yes.

Operator

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

Speaker 13

Good morning, guys. How do you think about that and optimizing the Antero Midstream business? Only. What's the just could you tell us how you think through that?

Speaker 4

Yes. 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. It's sacred, so very capital efficient.

Speaker 4

But we think from an AR perspective, how do we maximize free cash flow in the commodity price environment we're in. So if you have higher commodity prices that would and that's what the strip suggests, open. Then that would lead most likely to trying to maintain a higher production level. If you had lower commodity prices, more like of 2023 type pricing on natural gas, you would probably favor a lower capital budget. So that's kind of what only mode.

Speaker 4

We definitely want to maximize free cash flow at AR and use it to pay down the debt and return capital.

Speaker 13

And just moving this consolidation, obviously, you've been a big theme as of late. Obviously, you have a huge inventory that you can 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 Entera Midstream fit into that discussion as well, if at all.

Speaker 4

Yes. Well, we're just focused on an organic leasing strategy. That's the best of capital we can spend from an M and A perspective and Antero Midstream gets all the acreage from AR dedicated. Only mode of communication, so it's immediately dedicated to Entera Midstream. So those acreage adds really benefit AM and that's why they have over a 20 year life of inventory behind their midstream assets.

Speaker 4

So the acreage accrues to AM as well.

Speaker 13

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

Speaker 4

No. We're focused on the operational efficiencies. I mean, we've grown 9% year over year without doing M and A. So, we are very operationally efficient. We've got No constraints.

Speaker 4

We've got all the acreage locations, the midstream, the processing, the firm transport to the LNG corridor, the balance sheet. Only mode. So you put that all together, there's really no need for M and A. And then when you look at our operational efficiencies, it's really hard for us 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.

Speaker 13

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 open. I think you have this debt target near term. I believe it's about $1,000,000,000 You made a comment about paying down the debt.

Speaker 13

Only. Is there an actual goal to get debt at Antares Resources to 0 or is $1,000,000,000 the right number?

Speaker 5

Yes. Now you guess, 0 is the target.

Speaker 13

If you were to take a guess as when that would happen by, when do you is that just a function of paying down debt

Speaker 1

as we get

Operator

to the liquidity? Yes, the

Speaker 4

commodity open. I would say that like you mentioned, it's always been 1,000,000,000 for the goal. So the first the free cash flow will go to that first. Then once you get to the $1,000,000,000 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 fifty-fifty, probably a little bit more on the return of capital, It will just depend on commodity prices and where our bonds are priced.

Speaker 4

I mean, our 2030s are 5.38. So that's a good piece of paper, that's $600,000,000 So you may want to kind of keep that in the capital structure and buy back shares or return capital. But

Speaker 13

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

Speaker 5

Open. Thanks, Greg.

Operator

The next question is from Subash Chandra of Benchmark. Please proceed with your question.

Speaker 14

Only. 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 maximize or I should say minimize that variable going forward.

Speaker 4

Yes. We don't really have any waiting on completion. We try to of the plan all of our programs that it's just in time. So 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.

Speaker 4

There may be a week here or there where there's some white we call it white of the schedule, but generally we try to minimize that and be as efficient as possible and not have any DUCs because that's non performing capital.

Speaker 14

Yes. So I guess several years back when it was 400 days plus, etcetera, what was different then?

Speaker 4

We can see on that Slide 3, the pumping hours have almost are up like 65%. Only mode. 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 4.27% to 8.160%, it's on over 60% reduction and that 160% is definitely sustainable.

Speaker 14

Got it. Okay. And just a clarification, I guess, on the debt reduction question. 0, I guess, is the ultimate target. I guess, bank debt only.

Speaker 14

Yes. Is that sort of a priority before there's meaningful share buybacks? Or how do you sort of balance the 2?

Speaker 4

Yes. The goal is always and We had 0 bank debt essentially or near 0 coming into the year. So that would be the first use of the free cash flow is paying down that credit only mode. After that, it would be over 50% to return to shareholders, but we also have the 26 There's less than $100,000,000 on them callable in January. So I would kind of lump that together with the credit facility.

Speaker 14

Only. Thanks,

Speaker 1

Mike.

Operator

Yes. There are no additional questions at this time. I would like to turn the call back to Brendan Krueger for closing remarks.

Speaker 2

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

Operator

Only. Thank you. This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.

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Earnings Conference Call
Antero Resources Q3 2023
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