Q3 2023 Antero Resources Corp Earnings Call

Greetings and welcome to Antero resources Q3, 2023 earnings conference call.

At this time all participants are in a listen only mode of.

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 Brendon Brendon Kruger Chief Financial Officer of Antero Midstream and Vice President of Finance.

Thank you good morning, everyone. Thank you for joining us for Antero <unk> third quarter 2023, Investor Conference call, we'll spend a few minutes going through the financial and operating highlights and then I'll open it up for Q&A.

I would also like to direct you to the homepage of our website at Www Dot Antero resources Dot 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 and CEO and President.

Michael Kennedy CFO.

They've got a long ago, senior Vice president of liquids marketing and transportation.

And Justin Fowler Senior Vice President of natural gas marketing.

I'll 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 or.

35% improvement compared to the 2022 average and there's a nearly 90% increase from our 2020 2020 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 should reflect the total number of days. It takes on average from first studying a pal.

Add 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 as highlighted by our 9% total production growth in the third quarter compared to the year ago period.

Our production growth will be 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 'twenty to 'twenty three.

Importantly, these capital efficiency gains also reduce our maintenance capital budget.

We continue to expect materially lower D&C capital and 2024, driven by operational efficiency gains alone.

Lastly, I'd like to discuss our multi decade decade inventory position.

Turning on to slide number five titled a or has the lowest.

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 or M. Cfe 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 costs per location for the peer acquisitions.

Touching on the recent flurry of M&A headlines in our opinion drivers for M&A, usually relate to either one limited car inventory to 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 can along go for his comments Dave.

Thanks, Paul.

In the second half of 2023, we have seen an uptick in crude pricing is the macroeconomic concerns in the first half of the year have eased and new geopolitical concerns and the middle East have increased the risk premium in the market the.

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 WT I 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 about 2 million barrels per day.

Overall propane export demand has been consistently strong and has averaged $1 6 million barrels per day year to date as shown on slide six about 250000 barrels per day or 19% above the 2022 full year average.

As we move into 2020 for exports are expected to further increase causing potential tightness in U S Gulf Coast dock capacity.

As a reminder, antero exports over 50% of our C. Three plus production skewed heavily towards propane in particular directly out of the Marcus Hook terminal in Pennsylvania, and therefore in Paris export volumes are not impacted by constraints at the golf coast export docks.

In fact with tight capacity in the Gulf Coast, and strong international pricing and tariff 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.

On slide seven while total propane inventories are just above the top of the five year range.

Pain 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.

<unk> heating demand this winter goods quickly deplete the surplus that the mild 2022 to 2023 winter added to inventories last withdrawal season.

Now, let's turn to slide eight titled China, PVH Buildout 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 120000 barrels a day of propane dehydrogenation or PTH capacity, that's been added in China.

Industry estimates show that another 340000 barrels a day of capacity is expected to come online between now and the end of 2024.

Even with just one fourth of PTH capacity capacity additions online that are expected over 2023, and 2020 for the ramp in imports to China from the U S year over year, it's been substantial for.

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 rig counts continue to drop now down 21% year to date as seen on slide nine.

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.

Italy key NGL producing basins, such as the Eagle Ford and Scoop stack have seen their rig counts declined 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 Antero with direct access to international markets.

With that I'll turn it over to our senior Vice President of natural gas marketing, Justin <unk> 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 declined 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 at the bottom of the slide it took over six months 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 Haynesville basin.

A sharp contrast in 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 2020 for 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.

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 one 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.

Operator: 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.

This slide illustrates the significant benefit in selling your gas a tier one Gulf coast pricing.

Based on the current strip tier one prices reflect increasing premiums to Nymex in 2024 and 2025.

Operator: 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.

Including the <unk> 500 line.

Our premiums have increased to 29 above Nymex in 2026.

Brendan Krueger: I would now like to turn the conference over to your host, Brent Brendan Krueger, Chief Financial Officer of Antero, Mitch, 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.

Meanwhile, some peers claim they can move their gas to the Gulf coast, but theyre actually stock in tier three selling their gas at 24 back of Nymex in both 2024 and 2025.

The yellow stars on the map depicts antero 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.

And taro sells 90% of its gas a tier one pricing.

This compares this compares to the average of our peers, which saw 60% 7% of their Gulf coast directed volume into tier two and three pricing.

Brendan Krueger: Today's call may contain certain non-gap financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliation for the most comparable gap financial measures. Joining me on the call today are Paul Rady, Chairman, CEO, and President, Michael Kennedy, CFO, Dave Cannellongo, Senior Vice President of Liquid's Marketing and Transportation, and Justin Fowler. Senior Vice President of Natural Gas Marketing.

Looking ahead over the next two years as LNG export capacity increases by nearly six 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.

Paul Rady: 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 Eficiencies. 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 is 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.

With that I will turn it over to Mike Kennedy Antero 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 at or below or above the five year average natural gas prices are low and.

And when storage levels are below the five year average prices trend higher.

Paul Rady: 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. It is a nearly 90% increase from our 2020-2019 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 sputting a pall to turning that entire pad to sales.

Since 2020, which is essentially when the industry moved the maintenance production when storage levels are flat, but 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.

Paul Rady: 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 mean higher capital efficiency.

Thus, providing support to natural gas prices.

Expanding on this point if you have today is exact storage level at this same time next year.

Your surplus would go from almost 200 Bcf over the five year average today too.

To a surplus of just 50 Bcf to next years five year average.

Paul Rady: , 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.

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 E&ps.

While targeting a maintenance capital program.

<unk> 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.

Paul Rady: 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.

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 $100 million change of capital to result in approximately $100 million day change in production, both up and down.

Exit rate 2020 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.

Paul Rady: Lastly, I'd like to discuss our multi-decade inventory position. Turning to slide number five titled AR has the lowest 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 or MCFE drilling inventory at 22 years. It's important to note that this inventory comparison is after our peers that they combined $17 billion on acquisitions over the last two years.

Sequel.

This implies a true maintenance capital budget to hold 2022 volumes of three two Bcf 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 up 33, 5% to three four Bcf a day at an even lower.

Paul Rady: 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 peer 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 to a lack of pipeline capacity to move your production out of basin or three for balance sheet repair. With the peer-leading low cost inventory position, the largest firm transportation portfolio in the ENP sector and low absolute debt and leverage. Antero can stay focused on improving operations, which we believe drives ultimate shareholder value.

Your 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.

Confirmation tone will indicate your line is in the question queue.

Press Star two if you would like to remove yourself from the queue for.

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One moment, while we poll for questions.

Our first question today comes from Dennis up Truest. Please proceed with your question.

Hi, Good morning, guys on the difference between the 10% lower capital program versus the meaningful meaningfully lower capital. If you just address some of the questions, but what what spurred the change in the messaging is it is it just the efficiencies you're seeing is there some sort of investor.

Dave Cannellongo: Now, to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquid's Marketing and Transportation, Dave Cannellongo for his comments. Thanks Paul. In the second half of 2023, we have seen an updick and crude pricing at the macroeconomic concerns in the first half of the year have eased and new geopolitical concerns in the Middle East have increased the risk pretty much in the market.

Feedback or are you looking at the strip and that changed reminder, or was this always the plan you just laid it all laid it out a little bit simpler for us the first time.

No. Other changes are production is well ahead of expectations.

Dave Cannellongo: 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 US recently said a new weekly record high for propane exports and printed two consecutive weeks above two million barrels per day.

We didnt anticipate to be 225 million a day over exit rate to exit rate.

We've now raised our guidance twice throughout the year.

We expect gross wellhead volumes in Q4 to be higher than Q3 as well.

And so just the well performance capital efficiency all of those assumptions underlying those have improved.

So we have to figure out in this upcoming budget process. This.

Dave Cannellongo: Overall, propane export demand has been consistently strong in its average 1.6 million barrels per day a year today, shown on slide 6, about 250,000 barrels per day or 19 percent above the 2022 full year average. As we move into 2024, exports are expected to further increase causing potential tightness in US Gulf Coast stock capacity. As a reminder, Antero exports over 50 percent 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 docs.

<unk> will use.

Howie risks those we typically have some risking that's why we always hit our numbers.

And go from there and see what levels, we want to hit it we can dial in pretty much any production, we want at any capital at the required capital levels. So when you changed those assumptions.

It changes the capital 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.

Be well below that 10%.

That's great and then my follow up is kind of related but see the strip plays out maybe we actually get a few cold winters.

Dave Cannellongo: In fact, with tight capacity in the Gulf Coast and strong international pricing, Antero 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 7, 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.

LNG demand it doesn't get pushed out.

In attractive growth environment does and Taro is kind of stable operations plan change or do you, maybe stair step 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 how do you stay stable or with your new <unk>.

Can't program, maybe you could.

Respond to the strip.

No it stays stable, where we're trying to achieve maintenance capital that's just.

Dave Cannellongo: 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 at the mild 2022 to 2023 winter added to inventories last withdrawal season.

As we said it just continues to improve so.

Ultimately we will.

Get it to a level, where the maintenance capital assumptions we have.

Equate to actuals and so we'll stay at that maintenance capital program and pay down the remainder of our debt and return capital to shareholders.

Dave Cannellongo: Now let's turn to slide a titled China PDA still have 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 PDA capacity has been added in China. Industry estimates show that another 340,000 barrels a day of capacity is expected to come a line between now and the end of 2024.

Thanks, so much.

Dave Cannellongo: Even with just one-on-fourth of PDA capacity additions online that are expected over 2023 and 2024, the rampant imports to China from the US year over year has been substantial. For January through August this year, the amount of US propane cargo delivered to China increased by 44% year over year compared with a 19% increase year over year from the middle.

The next question comes from Imam <unk> of Goldman Sachs. Please proceed with your question.

Hi, good morning, and thank you for taking my questions.

I appreciate it I appreciate all the details on the propane macro.

Wanted to circle back on your thoughts around upside and downside risks to propane prices heading into next year.

Like you said you are positive on propane demand.

For 2024.

The <unk> facility.

But I wanted to understand if you've seen any downside risk to that end and also on the supply side given healthy oil prices do you see any risk of supplier exceeding EIA expectations of around 50000 barrels per day.

Could have next year.

Yes, good morning, and Mark on.

On the propane side I would say the.

The biggest risks that we kind of highlighted in our comments on what could happen on the Gulf coast with Mont Belvieu pricing. If you see those docs really hit full utilization we were <unk>.

Dave Cannellongo: Police. This demonstrates that U.S, exports continue to make up the marginal increased required by Chinese propane demand.

Even saw here in the third quarter are three of the big four facilities have extended planned or unplanned maintenance or I guess third quarter into fourth quarter that is driving some lower propane export numbers. Despite the records that we've reported so I think we would've seen higher overall export numbers here in recent months and lower lower inventories and where.

Dave Cannellongo: Meanwhile, on the U.S.

Dave Cannellongo: supply side, rig 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.

Dave Cannellongo: 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.

We stand today had that not happened, but it points to the fact that those facilities are becoming increasingly higher utilized in 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 have Mariner East online, we had very high utilizations in the U S Gulf Coast and the arms were.

Dave Cannellongo: Additionally, key NGL-producing basins, such as the Eagle Ferdin Scoopstack, have seen their rig counts decline 35% and 45% year-to-date. Overall, we believe that with supported fundamentals domestically and positive demands signals from China, there are signs of improvement for NGL's heading into 2024, and in particular for producers like Antero, with direct access to international markets.

Why they were 15, 2% to 25, a gallon and you saw us capture that and so that's that is ultimately something that we can see play out this year, sorry for 2024, where you could have weaker Mont belvieu pricing like you've seen here in the third quarter, but strong arbs and antero as we move into 'twenty.

Justin Fowler: 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.

24, 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, where we're fully contracted the neighborhood are able to capture that value and so I think youll see that reflected in our NGL realizations at that.

Justin Fowler: I will start on slide number 10, entitled, 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 at the bottom of the slide, it took over six months to materialize.

If that plays out ways looking right now on the propane side I think the other tailwind is just on the freight costs, you've seen freight cost stay elevated this year, we hit record levels.

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.

Justin Fowler: 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 Haynesville basin. A short contrast to 2019 when the majority of rig drops came from the lower decline Appalachian basin.

So that's again something temporary and if you look at the futures curves for LP.

LPG freight costs, they're backward dated U S to Asia is about 12 per gallon lower.

By mid summer of 2024 versus now and it's a pretty steady.

Decline in those those expected cost so that will also allow.

Rices in the U S to.

The rise as well is that freight cost declines.

On the oil side, but 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.

Justin Fowler: In summary, we believe the sharp decline in rigs and completion crews will curb production growth in 2024, helping to balance the U.S, gas market.

Particularly around the NGL side of supply response, as we've seen the rig count decline you.

Justin Fowler: As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor.

You saw some very steep.

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 Wayne.

Justin Fowler: 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 Gold Coast, and importantly, into tier one pricing points along the Gold Coast.

And we'd come back into the five year range. So.

I think that to me points to what we talked about with the rig counts, where 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.

Justin Fowler: Next, all turn to slide number 12 titled, not all firm transportation to the Gold Coast is equal. This slide illustrates the significant benefit in selling your gas at tier one Gold Coast pricing. Based on the current strip, tier one prices reflect increasing premiums to 9x in 2024 and 2025. Including the TGP 500 line, where premiums have increased to 29 cents above 9x and 2026. Meanwhile, some peers claim they can move their gas to the gold coast, but they're actually stuck in tier 3, selling their gas at 24 cents back of 9x, in both 2024 and 2025.

Very helpful. Thank you so much for the for all the color I guess the next question Michel had is I just wanted to follow up.

On the operational momentum, which has been really strong here recently.

Would love your initial thoughts on 2020 for production and capital spending outlook.

But on deflation and what you're expecting there, which can probably add some upside but that 10% reduction number which you were talking about from a capital spending perspective.

Yes, 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.

Justin Fowler: But 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 sells 60%, 7% of their gold coast directed volume into tier 2 and 3 pricing. Looking ahead over the next two years, as LNG export capacity increases by nearly 6bcf, we expect Ontario sales points to be priced at even higher premiums to 9x, as these LNG facilities compete for supply. A key competitive advantage between Ontario vs, our peers.

Assuming those type of efficiencies and performance.

We 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 that kind of the annual average from last time of 335 to three four 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 would come out with the budget and with the February release with the yearend release so.

Well that's worked through that and continue to watch the market, but we're not assuming any deflation area aspects in that capital budget that would just be upside.

So that's very helpful. Thank you.

Thank you.

The next question is from around <unk> of J P. Morgan. Please proceed with your question.

Michael Kennedy: With that, I will turn it over to Mike Kennedy and Tara CFO. Thanks, Justin. First, I'd like to add some additional comments on how we view the outlook for natural gas.

Yeah, Mike I wanted to get your thoughts on.

So you said, 10%.

Capex next year and that would be to keep the current production outlook, what youre doing today.

Michael Kennedy: 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 above the 5-year average, natural gas prices are low. And when storage levels are below the 5-year average, prices trend higher. Since 2020, which is essentially when the industry moved the maintenance production, when storage levels are flat with the 5-year level, natural gas prices average $4 per MCF.

Relatively flat and then if you drill down to 335 to $3 four it would be more than 10% somewhat if you can clarify those comments yeah.

Got it got it and then just I know, it's hard to estimate land spend because you're opportunistic on that front, but.

Youre recommending kind of a placeholder for land spend.

In 2020 for any just broad thoughts on that.

Yes. It was the last comments we always.

Target.

And our 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.

Michael Kennedy: Looking at 2023, storage levels rose to as high as 25% above the 5-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 5-year average in 2024, thus providing support to natural gas prices.

We always target at $75 million $100 million a year.

Michael Kennedy: Spending 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 5-year average today, to a surplus of just 50 BCF to next year's 5-year average.

That's our traditional kind.

Kind of customary commodity price environments.

So that's why you would assume that that's third quarter ratcheted down the $27 million will be down in the fourth quarter from there too so.

That run rate's around we're at like $100 million, but.

Generally at $75 million to $100 million capital budget for land.

Great and then just as my follow up.

Mike is how how do you think.

Well, we should think about production costs.

Next year obviously.

Fuel costs, maybe some of the savings are transitory but are.

You guys CPI inflator as the Ams escalator, but just give us a broad strokes around thinking about kind of production costs as we move into 2024.

Michael Kennedy: 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-AX. Access, and the year-over-year change in drilling and completion capital on the X-axis for the Appalachian EMPs. 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.

Yes, it's really my price dependent.

Much have flat Hello.

Next year, we do have an uptake of our <unk> production AD valorem taxes, because that's just the commodity price gas prices up 75.

So that's how you kind of get to that and then similar on the GP and tee up a nickel as well just on the fuel cost. So assuming we have these increase cutting out at $3 50 type of commodity price next year, which is the strip we're up about a dime.

And what about the AAM escalator.

Michael Kennedy: 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 100 million dollar change of capital to result in approximately 100 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 dollars all out of SQL.

And that's baked into that dime.

Okay.

Thanks, guys.

Yes.

The next question is from Roger read 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 and capital efficiencies.

Without getting too granular to the outlook what is your expectation on how much further you can go with that.

Well that's a good question.

<unk> improved from this year as we were assuming come.

Michael Kennedy: This implies a true maintenance capital budget to hold 2022 volumes of 3.2 BCF a day of approximately $650 to $700 million dollars. 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 BCF 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.

Coming into the year that we would average about $8 seven stages per day and completions and in about six to seven days per 10-K in drilling and even improved two stages per day.

More than that at 11 stages in completions in 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 would probably assume those same levels I just mentioned going into next year, but we're always looking for continuous improvement.

Paul mentioned, a record completion out into 17 hours per day and the completion.

It would.

It'd 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 where.

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 at the top of the pack.

Brendan Krueger: With that, I will now turn the call over to the operator for questions. Thank you.

The only other question I've got really is is there anything we should think about.

Operator: 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 call for me to 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 pull for questions.

As we look into it let's just say the next six months or so.

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.

Now we were wide in Q3 because of the maintenance on Cove point, Tennessee pipe. So we.

Bert Donas: Our first question today comes from Bert Donas of Truist. Please proceed with your question.

We sold about 15% to the teco and that was wide in the third quarter. It is always weak.

Michael Kennedy: Good morning, guys. On the difference between the 10% lower capital program versus the meaningful, meaningfully lower capital, you just addressed some of the questions. 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? of the first time.

And 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 will sell a lot more on the Gulf Coast, and then and then when you look at the Gulf Coast going into the winter those are actually a premium prices. The Henry hub like Justin mentioned on this slide that interesting slide around the tier one levels and that was.

Michael Kennedy: Another change is our productions 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 well head 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 in this upcoming budget process the assumptions that we use, how we risk those.

Right and the LNG corridor, where there's a lot of demand for the gas. We also have quite a bit going into Chicago during the winter.

Maybe up to 50 dollar ahead of Henry hub, right now and we're bringing seven wells on in the Utica just in time to enjoy the Chicago gas prices filling our Rex capacity so.

See realizations, improving quite a bit in the fourth quarter and heading into 2024.

Alright, Thank you I'll leave it there.

Yeah.

The next question is from David <unk> of Cowen. Please proceed with your question.

Michael Kennedy: 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 we 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%.

Yeah.

Thanks for getting me on the call guys I appreciate the time.

Hey, this is Mike.

Throughout some exciting numbers I think for the street for next year.

650, I guess true maintenance versus maybe an 800 to stay at that three five level or so.

Can you just talk about the variables that are.

In saying that decision.

Yes, as I think about it is.

Is there a breakeven price is at $4 gas that would incentivize you to stay at that higher level are you being influenced by perhaps like some of the revolver balance that you have right now on wanting to accelerate Max free cash in the beginning of the year I guess what would be.

Michael Kennedy: That's great. And then my follow up is kind of related. But you know, say the district plays out. Maybe we actually get a few cold winters. LNG demand, you know, doesn't get pushed out. You see an attractive growth environment. Does in taros 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.

The primary factors that you consider between those two variables.

Yes, the $6 50 to $700, what it would've been required to hold that three two bcf a day of flat.

335 to three four would have been $100 million or so.

Higher as I mentioned the rule of thumb as every 100 million a day of capital's 100 million a day of production so high.

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

Higher than that to hold the 33534, but well below that 10% that's kind of how we think about it.

It's going to be somewhat commodity price dependent David were obviously heavily influenced by generating free cash flow and paying down 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.

Michael Kennedy: Thanks so much.

Ma'am Tudari: The next question comes from you, Ma'am Tudari of Goldman Sachs. Please proceed with your question. 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 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 EI expectations of around 50,000 barrels per day?

<unk> 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 crews. So that's kind of how we manage capital so.

We have the flexibility to do whichever program, we choose or 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 it doesn't sound like as you think about like a multiyear progression.

Are you are you inherently more operationally efficient.

That that three rig and two crew program yes.

Yes, we are.

Much more efficient that and when you think about that we have the drilling JV. So we really only have 85% of that in this year is really a three rig program and a one five completion crew next.

Ma'am Tudari: I'll look next year. Yeah, good morning, Ma'am. On the propane side, I would say the biggest risk that we kind of highlighted in our comments on what could happen in the galt coast with Monk Bell be pricing. If you see those docs 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.

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 and so we've just become remarkably efficient just with our.

Contiguous acreage position, having all the infrastructure in place having all the transport having all the processing.

Ma'am Tudari: That has driven some lower propane export numbers despite the records that we reported. So either we would have seen higher overall export numbers here in recent months and 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 Antaro. If you go back to, I think it was back in 2019, the first kind of full year we had Mariner East online.

And then working on our operational efficiencies and having this much success. We've just continued to become more and more efficient and drill a terrific wells.

When would you guys just mind updating us that's all very helpful and just the shell cracker progression in some of the assumptions that we should thinking about your your ethane volumes for next year.

Yes, nothing new to what they've guided publically on Theyre doing some work on one of the 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 a significantly higher and more stable volumes.

Ma'am Tudari: We had very high utilizations in the US galt coast and the ARBS were wide. They were 15, 20 to 25 cents a gallon and you saw us capture that. And so that's ultimately something that we can see play out this year, sorry, for 2024, where you could have weaker Monk Bell be pricing, like you've seen here in the third quarter, but strong ARBS in Antaro. As we move into 2024, we do capture some of that value today.

From us go into 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.

Ma'am Tudari: 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 fully on the contract and able to capture that value. And so I think you'll see that reflected in our NGL realizations at that at that plays out when it's looking right now on the propane side. I think the other tailwind is just on the freight costs you've seen.

Ramping up in 2024 as well so I think youll see a combination of the shell cracker effect as well as others.

And the net production in 'twenty four on the other side and then further to that when it comes to the ethane cracker, we always risk that quite heavily.

What you've seen with even with the startup.

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.

Ma'am Tudari: 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 they're fact gradated US to Asia is about 12 cents per gallon lower by mid-summer of 2024 versus now.

Recently, so the production that we're talking about levels.

We will be risk for further kind of just startup youre typical startup issues and then if the ethane cracker actually it does perform.

A little bit better in the year that would just be upside to volumes.

Thanks, Mike answered my questions I appreciate it guys.

Yep. Thanks.

Ma'am Tudari: And it's a pretty steady decline in those those expected costs. So that'll also allow prices in the US to rise as well as that freight cost decline, on the oil side that, 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, particular on the GLCI to supply responses. We've seen the rate count decline.

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

Hi, Good morning, as you mentioned.

Being LPG export capacity tightness, along the Gulf coast and 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 were.

Want to export as much as possible, which is the shoulder months spring through summer and all those times of the year, where we're spending 80, 590% of our propane.

Ma'am Tudari: You saw some very deep increases in US propane inventories, you know, 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, Wayne, we've come back into the, you know, the five year range. So I think that, to me, points to what we talked about with the rate 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.

International Docs, so hard to really get get much above that.

While we have some flexibility.

For domestic and for variations in production month to month, but we.

We try to maximize that as much as we can.

During the non heating season.

Okay and that makes sense and then and you can tend to turn this on an earlier question, but your local.

Gas realizations were a little bit lower due to maintenance at Cove point in Tennessee and was that kind of this perfect storm, where it was also kind of core basis because of the high storage.

Ma'am Tudari: Very helpful. Thank you so much for the, 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 to, which can probably add some upside to that 10% reduction number, which you were talking about from a capital spending perspective.

Is that like a lot more maintenance than usual in the season or do you view it as just everything and it's more volatile now that everything is quite full.

And so it kind of plays out.

It's a good way to put it that so that was the perfect storm in the backup volumes from Cove point, and the Tico and in the backup volumes in Tennessee, and the Teco, just led a really wide basis.

It was an historic high.

A wireless basis, we've seen at Pico so.

Ma'am Tudari: 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 3534. So that's what we're in the process doing this quarter.

All of that has subsided, though going into Q4 with Cove point being back on in Tennessee flowing so.

Great. That's all for me thanks.

Yes.

Yeah.

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

Good morning.

Good morning.

We appreciate the macro commentary and did you guys give and in the near to medium term just curious and it may be a 2025 plus time frame, what you would need to see in the forward curve to potentially allocate more capital to drier areas.

Ma'am Tudari: So we'll go through our typical process and then come out with those generally to 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 area aspects in that capital budget. That would just be upside. So that's three ahead for this. Thank you.

Yes.

Yeah.

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.

We believe could very much occur with the build out of the LNG during that timeframe you referenced.

Michael Kennedy: The next question is from Arun Girard 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%. So if you can clarify those comments. Yeah. 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, and he just brought thoughts on 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 are.

We just program in maintenance capital holding these levels flat and then enjoying the the higher commodity prices and that free cash flow and paying down debt and buying back shares, but there is a possibility if it goes quite high.

Essentially have over 1000 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.

I appreciate it that's all for me.

Yeah.

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

Michael Kennedy: 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 pre cash flow we had. But we typically always target $75 million, $100 million, of the year. That's our traditional kind of customary commodity price environments. So that's what you would assume. You know, this third quarter, you know, ratcheted down the $27 million will be down in the fourth quarter from there too. So that run rate around, we're at like a hundred million, but generally it's $75 million to a hundred million dollars capital budget for land.

Good morning, guys.

Just on the volume decision, whether you keep <unk> flat or or what you.

Originally you thought you would be how do you how do you think about that and optimizing the antero midstream.

Business, what's the.

How do you think through that.

I don't really think about Antero midstream as we think about Antero resources.

And its free cash flow profile Antero midstream just a beneficiary of the growth.

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 for very capital efficient, but we think of it from an AUR perspective, how do we maximize free cash flow and the commodity price environment. We're in so if you have higher commodity prices that would.

Michael Kennedy: Great. And just my follow up, Mike, is how do you think we should think about production costs next year? Obviously, you know, fuel costs, you know, maybe some of the savings are transitory, but you 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 L.O.E, next year, we do have an uptake of about five cents on production ad blower and taxes because that's just commodity price gas prices up, you know, 75 cents.

And that's what the strip suggests then that would lead most likely to trying to maintain a higher production level and 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 when we look at we definitely want to.

Maximize free cash flow it and use it to pay down the debt and return capital.

And just just.

Michael Kennedy: So that's how you kind of get to that. And then similar on the GPNT 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 the dime. Okay.

This consolidation, obviously had been a big theme as of late.

Michael Kennedy: Thanks, guys.

Obviously, you have a huge inventory that you can access so there isn't necessarily a need to buy anything.

How are you thinking about that today, and then how does antero midstream fit into that discussion as well if at all.

Yeah.

Just focus on that organic leasing strategy. That's the best capital, we can spend from an M&A perspective.

And then Taro midstream gets all the acreage from AAR dedicated and when we acquired the acreage we work really hard and 99% of the time it comes with a.

Roger Reed: Yep. 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 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? Well, you know, that's a good question. You know, what improvement this year is we were assuming coming in a year that we'd average about 8.7 stages per day in completions and about six to seven days per 10k in drilling.

Free and clear from any midstream dedication. So its immediately dedicated 10 taro midstream. So those acreage adds really benefit AAM and thats why they have over a 20 year life of of inventory behind their midstream assets.

The acreage accrues to them as well.

But then just maybe bigger picture just youre seeing a lot of peers kept maybe this discussion up here is getting bigger.

I'm curious if that's making you think a little harder about M&A.

Roger Reed: And you can prove two 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 been able to achieve those improvements. So, you know, we'll probably assume those same levels I just mentioned going in the next year, but we're always looking for continuous improvement. Paul mentioned the record completion out of the 17 hours per day in the completion.

Just status quo.

Now 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 and we've got no.

No constraints, we've got all of the acreage locations the midstream the processing the firm transport to the LNG corridor the balance sheet. So when 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 <unk>.

Future program. So that's why we're focused on the organic leasing.

Roger Reed: You know, 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. 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.

All makes sense and consistent with the past and just just one one last one something you said on the call.

Assistant what you've implied in the past but.

I think you have this debt target near term I believe it's about $1 billion.

You made a comment about paying down the debt.

Is there a natural go to get it.

I didn't hear it resources to zero or is it billions.

Michael Kennedy: 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. Thanks.

Now you get zero as the target.

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

The prices you know I would say that like you mentioned thats always been billions the goals of the first free cash flow will go to that first and then once you get to the $1 billion and below that would get you out of the credit facility and the 'twenty six notes that are callable. In January then you can look at it and say well.

Michael Kennedy: Now we're wide in Q3 because of the maintenance on co-point Tennessee pipe. So we sold about 15% to Tico and that was wide in the third quarter. It's always weak in the third and fourth quarters during the shoulder months going in the winter. That has improved quite a bit in Q4. Those maintenance capovans have subsided. So we'll sell a lot more in the Gulf Coast and then when you look at the Gulf Coast going in the winter, those are actually a premium price to Henry Hub, like Justin mentioned on his slide, that interesting slide around the Tier 1 levels.

Maybe 50 50, probably in a little bit more on the return of capital, but it will just depend on commodity prices and where our bonds are priced I mean, our our 2000 thirty's or.

Five and three eighths. So that's a good piece of paper that 600 million. So he 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 pick out.

I appreciate the time guys.

All the color. Thanks.

Thanks, Craig.

Michael Kennedy: And it's right in the L and G 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 at 50 cents a dollar ahead of Henry Hub right now. And we're bringing seven wells on in the U to cut just in time to enjoy the Chicago gas prices, filling our wrecks capacity. So I see realizations improving quite a bit in the fourth quarter and heading in the 2024. All right.

The next question is from Subaru Shandra benchmark. Please proceed with your question.

Michael Kennedy: Thank you.

Good morning.

The sales.

Improvement there over the years I think a.

A big element of that as 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.

David Deckelbaum: 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 know, he threw out some exciting numbers, I think, for the 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?

The program is going to maximize or I should say minimize that variable.

Going forward.

Yes, we don't really have any waiting on completion, we try to.

David Deckelbaum: And I guess, as I think about it, is there a break even price? Is it $4 gas that would incentivize you to stay at that higher 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.

Plan all of our programs and it's just in time so.

When youre done drilling while you're on that pad completing it.

As soon as possible so.

That's how we do it there may be a week here or there where theres some whites, 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 nonperforming capital.

Yes, So I guess you know several years back when it was 400 days plus et cetera.

What.

What was different then.

You can see on that slide three the pumping hours of almost are up like 65%.

You know an 86% increase in completion stages per day and in the drilling times too.

David Deckelbaum: Total 335 to 34 would have been 100 million or so. Higher, as I mentioned, the role of thumb is every 100 million a day of capitals, 100 million a day of production. So, higher than that, to hold the 335, 340, but well below that 10%. It'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.

Greatly improved.

So it's a combination of both.

To go from 427 year to date $1 60.

Over 60% reduction in that 160 is definitely sustainable.

Got it okay.

And just a clarification I guess on the debt reduction question.

Hum.

Zero I guess is the ultimate target I guess bank debt.

<unk> is there.

David Deckelbaum: 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.

I'd assume it's a top priority.

Zero person.

Is that sort of thing.

Is that sort of a priority before theres meaningful share buybacks or how.

Do you sort of balance.

The goal is always we had zero bank debt essentially are 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.

Over 50% to return to shareholders, but we also have to 'twenty six notes, there's less than $100 million callable in January so I kind of lump that together with the credit facility.

David Deckelbaum: 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 programs? Yes, we're much more efficient than when you think about that, we have the drilling JV, so we really only have 85% of that.

Thanks, Mike.

Yeah.

Okay.

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.

David Deckelbaum: 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 continuing with 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.

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

Hmm.

[music].

Michael Kennedy: We just continue to become more and more efficient and drill terrific wells.

Hum.

Michael Kennedy: With you guys just 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 essay and volumes for next year. Yeah, nothing new to what they've guided publicly on. They're doing some work on one of the 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.

Hum.

[music].

Michael Kennedy: 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 shell cracker effect as well as others in the net production in 24 on the other side. Yeah, and then further to that, when it comes to the ethane cracker, we always risk that quite heavily.

Hum.

Uh huh.

[music].

Michael Kennedy: And that's why you've seen with even with the startup 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 risk, you know, for further kind of just start up your typical startup issues. And then if the ethane cracker actually does perform a little bit better in the year that will just be outside the volumes.

Hum.

[music].

Michael Kennedy: Thanks Mike, answer my questions. I appreciate it guys. Yeah, nice.

Uh huh.

[music].

Jean Ann Falsberry: The next question is from Jean Ann Falsberry, a burn scene. 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 Antaro 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, you know, spring through summer and the fall.

Uh huh.

[music].

Jean Ann Falsberry: There's times of the year where we're sending, you know, 85, 90% of our propane to the international box. So hard to really get, get much above that, but you know, you want to leave some flexibility for domestic and for variations and production month and month. But we try and maximize that as much as we can during the non-heating season.

Okay.

Hmm.

Michael Kennedy: Okay, that makes sense. And then you can touch on this on an earlier question, but your local gas realizations were a little bit lower due to maintenance at Coast Point and 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 of it kind of blows out?

Michael Kennedy: Yeah, that was a good way to put it. That was the perfect storm. The backup volumes from Coast Point and the TCO and the backup volumes from Tennessee and the TCO just led to really wide base. It was a historic, it was the widest basis we've seen at Tico, so all of that is subsided though, going in the Q4 with co-point being back on in Tennessee flowing, so.

Michael Kennedy: Great, that's all for me, thanks. Yep.

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

Jacob Roberts: 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 time frame, 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 always 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 have 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.

Jacob Roberts: 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 that by neck shares, but there is a possibility if it goes quite high, you know, we essentially have over a thousand 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 having it's capital.

Jacob Roberts: Appreciate it.

Jacob Roberts: That's all for me.

Jacob Roberts: Yep.

Greg Brody: The next question is Greg Brody of Bank of America. Please receive with your question. Good morning, guys. It's just up under the volume decision, you know, whether you you keep 3Q 4Q flat or what you what you originally thought you would be. How do you how do you think about that and optimizing the entire midstream business? What's the it took us how you think through that. Yeah, we don't really think about on tarot midstream.

Greg Brody: We think about entire resources and it's free cash flow profile and tarot midstream just a benefit share of the growth and capital efficiencies and you know that all translates to them as well because they're getting much more production per well. And it's very continue sacred, 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 would and that's what the strip suggests.

Greg Brody: Then that would lead most likely to trying to maintain a higher production level. If you had lower commodity prices more like, you know, 2023 type pricing on natural gas, you would probably favor a lower capital budget. So that's kind of what we we look at. We definitely want to maximize free cash flow at AR and use it to pay down the debt and return cow, and just moving to consolidation obviously had been a big theme as of late.

Greg Brody: 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 an interimitrium 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 antero midstream gets all the acreage from A.R, dedicated and when we acquire the acreage we work really hard and 99% of the time it comes with a free and clear from any midstream dedication so it's immediately dedicated to antero midstream.

Greg Brody: 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 maybe bigger picture just you're seeing a lot of peers get bitters, 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. Now we're focused on the operational efficiencies, I mean we've grown 9% year over year without doing M&A.

Greg Brody: So we are very operational 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 we put that all together, there's really no need for M&A and 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 location. All makes sense and consistent with the past and just one last one, something you said on the call, they could consistent with what you've implied in the past, but you have this debt target in your term, I believe it's about a billion dollars, you made a comment about paying down the debt, is there, is there an actual goal to get debt at entire resources to zero or is a billion the right number?

Michael Kennedy: Yes, now you guess zero is the target. If you were to take a guess is when that would happen by, is that just a function of paying down debt? I would say that like you mentioned, it's always been billions the goal, so the free cash low 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 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 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 a pretty high interest rate that we'd like to take out. I appreciate the time, guys, and all the color. Thanks. All right, thanks very much.

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

Michael Kennedy: Good morning. I'm going to spot the sales, um, improvement there over the years. You know, I think a, a big element of ad is as well sort of waiting on completion. And so I guess my question is, um, can you describe sort of the path you took to reduce that time? And if you think that, um, the, the program is going to, you know, maximize or I should say minimize that variable going forward.

Michael Kennedy: Yeah, we don't really have any waiting on completion. We try to plan all of our programs. It's just in time. So, uh, 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.

Michael Kennedy: Yeah. So I guess, you know, several years back when it was, you know, 400 days plus, et cetera. What, uh, what was different then? We can see our, you know, on that slide, three, the pumping hours of almost are up like 65%. That's, you know, an 86% increase completion stages per day and in the drilling times to have greatly improved. So it's a combination of both, but, you know, to go for 427 years, a 160, you know, it's an over 60% reduction, and that 160 is definitely sustainable.

Michael Kennedy: Yeah. Okay. And just a classification, I guess I'm a reduction question. Zero, I guess, is the ultimate target. I guess bank debt is there. I would assume it's a top priority to reduce the zero first. And is that sort of, yeah, is that sort of a priority before there's meaningful share by back. So 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.

Michael Kennedy: So that would be the first use of the free cash flow is paying down that credit facility didn't 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 a 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.

Brendan Krueger: I would like to turn the call 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. You may disconnect your lines at this time. Thank you for your participation. Thank you.

Operator: [inaudible] Neil Mehta, David Cannelongo, Neil Mehta, David Cannelongo,[inaudible]