Q4 2023 Antero Resources Corp Earnings Call

Operator: The Ultimate Parody Site! Hello, and welcome to the Antero Resources fourth quarter 2023 earnings conference call and webcast. If anyone should require operator assistance, please press star zero on your telephone keypad. A question and answer session will follow the formal presentation. You may be placed on the question queue at any time by pressing star one on your telephone keypad.

Hello, and welcome to the Antero resources fourth quarter 2023 earnings conference call and webcast. If anyone should require operator assistance. Please press star zero on your telephone keypad.

A question and answer session will follow the formal presentation you may be places the question queue at any time by pressing star one on your telephone keypad. As a reminder, this conference is being recorded its now my pleasure to turn the call over to Brendan Kruger Vice President of Finance. Please go ahead Brendan.

Operator: As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to Brendan Krueger, Vice President of Finance. Please go ahead, Brendan.

Brendan Kruger: Thank you good morning, everyone. Thank you for joining us for Antero <unk> fourth quarter 2023 Investor Conference call.

Brendan Krueger: Thank you. Good morning, everyone. Thank you for joining us for Antero's fourth quarter 2023 investor conference. Page PAGE of NUMPAGES www.verbalink.com Page PAGE of NUMPAGES www.verbalink.com. I would also like to direct you to the homepage of our website at www.anteroesources.com, where we have provided a separate earnings call presentation that will be reviewed during today's conference. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO, and President. Michael Kennedy, CFO; Dave Cantelongo, 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 you. Thanks, Brendan. Good morning, everyone.

Brendan Kruger: I will spend a few minutes going through the financial and operating highlights and then we'll open it up for Q&A I would also like to direct you to the homepage of our website at Www Dot Antero resources Dot Com, where we've provided a separate earnings call presentation that will be reviewed during today's call.

Today's call may contain certain non-GAAP financial measures.

Brendan Kruger: Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.

Brendan Kruger: Joining me on the call today are Paul Rady, Chairman and CEO and President Michael Kennedy CFO.

Brendan Kruger: Dave can along senior Vice president of liquids marketing and transportation and Justin Fowler Senior Vice President of the natural gas marketing I will now turn the call over to Paul.

Paul M. Rady: Thanks, Brendan good morning, everyone.

Paul M. Rady: I'll start my comments on slide number three of our presentation titled drilling and completion efficiencies.

Paul M. Rady: I'll start my comments on slide number three of our presentation titled Drilling and Completion Efficiency. 2023 was a transformational year for Antero as our operating performance made significant advances. Our drilling and completions teams set a number of company and industry records throughout the year. As an example, days per 10,000 feet of lateral drill averaged five and a half days in 2023, a decline of 14% since 2019.

Paul M. Rady: 123 was a transformational year for Antero as our operating performance made significant advances.

Paul M. Rady: Our drilling and completions teams set a number of company and industry records throughout the year.

Speaker Change: As an example days per 10000 feet of lateral drilled averaged five five days in 2023, a decline of 14% since 2019.

Paul M. Rady: On the completion side, 2023 completion stages per day averaged nearly 11 stages a day, a 35% improvement compared to the 2022 average, and more than an 80% increase from the 2019 level. The result of these operational improvements was 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 putting a pad to turning that entire pad to sale.

Speaker Change: On the completion side 2023 completion stages per day averaged nearly 11 stages a day.

Speaker Change: 35% improvement compared to the 2022 average and more than an 80% increase from 2019 levels.

Speaker Change: The result of these operational improvements was significantly shorter cycle times as shown on the bottom of the page. These cycle times to reflect the total number of days. It takes on average from first studying a pad to turning that entire pad to sales.

Speaker Change: Since 2019, our cycle times have decreased by an impressive 65% and averaged just 160 days in 2023.

Paul M. Rady: Since 2019, our cycle times have decreased by an impressive 65% and averaged just 160 days in 2023. Shorter cycle times mean higher capital efficiency, of course. In addition, our well performance continues to improve. This operating momentum is highlighted by the fact that, while targeting a maintenance capital program this last year, our volumes actually grew 6% in 2023 compared to 2022. Most importantly, these capital efficiencies and well productivity gains drive a reduced maintenance capital budget.

Speaker Change: Shorter cycle times means higher capital efficiency of course.

Speaker Change: In addition, our well performance continues to improve.

Speaker Change: This operating momentum as highlighted by the fact that while targeting a maintenance capital program. This last year, our volumes actually grew 6% in 2023 compared to 2022.

Most importantly, these capital efficiency and well productivity gains drive a reduced maintenance capital budget.

Speaker Change: Now, let's turn to slide number four titled efficiencies translate to lower maintenance capital in 2024.

Paul M. Rady: Now let's turn to slide number four, titled efficiencies translate to lower maintenance capital in 2024. In 2024, we expect production to be flat, averaging between 3.3 and 3.4 BCF equivalent a day. Meanwhile, our drilling and completion capital is expected to be down over 25% compared to the prior year. Our maintenance capital budget midpoint of $675 million is over $225 million below the $909 million that we spent in 2023.

Speaker Change: In 2024, we expect production to be flat, averaging between three three and 3.4 Bcf equivalent a day means.

Speaker Change: Meanwhile, our drilling and completion capital is expected to be down over 25% compared to the prior year or.

Speaker Change: Our maintenance capital budget midpoint of $675 million to is over $225 million below the $909 million that we spent in 2023 the.

Speaker Change: The operating efficiency gains captured in 2023 allowed us to drop one drilling rig at the end of last year and then to draft. A completion crew at the beginning of this year. We now plan to average two drilling rigs and just over one completion crew for our maintenance capital program in 2024.

Paul M. Rady: The operating efficiency gains captured in 2023 allowed us to drop one drilling rig at the end of last year and then to drop a completion crew at the beginning of this year. We now plan to average two drilling rigs and just over one completion crew for our maintenance capital program in 2024. Also contributing to our reduced capital budget is a lower base decline rate. As we enter year four of a maintenance capital program, our decline rate is substantially lower, in the mid to low 20 percent range. This low decline rate requires less capital to hold production flat. In addition, our land capital budget midpoint of $88 million is down over $60 million compared to 2023. In total, this will result in $275 million to $300 million of reduced capital spending compared to last year while maintaining the same production.

Also contributing to our reduced capital budget is a lower base decline rate as we enter year four of our maintenance capital program. Our decline rate is substantially lower in the mid to low 20% range. This low decline rate requires less capital to hold.

Speaker Change: Reduction flat.

Speaker Change: In addition, our land capital budget midpoint of $88 million is down over $60 million compared to 2023.

Speaker Change: In total this will result in 275 million to $300 million of reduced capital spending compared to last year, while maintaining the same production level.

Paul M. Rady: This significant reduction in capital highlights the high-quality asset base at Antero and the flexibility that we have. As we look ahead to 2024, these significant capital savings, combined with the recent increase in NGL prices, are expected to generate free cash flow during the year. This positive free cash flow generation is expected to occur despite being unhedged in today's challenging natural gas price environment. This positive free cash flow outlook is even more impressive when considering that the current strip is at the lowest natural gas price for any calendar year outside of the COVID year in the last 25 years. 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 Canalongo, for his comments. Thanks, Paul.

Speaker Change: This significant reduction in capital highlights the high quality asset base at Antero and the flexibility that we have.

As we look ahead to 2020 for these significant capital savings combined with the recent increase in NGL prices is expected to generate free cash flow during the year. This positive free cash flow generation is expected to occur despite being unhedged in today's challenging natural gas.

Speaker Change: <unk> price environment.

Speaker Change: This positive free cash flow outlook is even more impressive when considering that the current strip is at the lowest natural gas price for any calendar year outside of the Covid year in the last 25 years.

Speaker Change: Now to touch on the current liquids NGL fundamentals I'm going to turn it over to our senior Vice President of liquids marketing and transportation, Dave <unk> for his comments.

Dave: Thanks, Paul.

Dave Canalongo: The macro picture for NGLs has improved materially this winter due to a combination of strong domestic demand and consistently high export levels. Specifically, focusing on propane, as a result of the strong exports during winter weather, inventories have declined by 45 million barrels since October.

Dave: Macro picture for Ngls has improved materially this winter due to a combination of strong domestic demand and consistently high export levels. Despite the challenges seen in the global waterborne shipping environment.

Focusing on propane as a result of the strong exports and winter weather and inventories have declined by 45 million barrels since October and just a few months propane stocks have moved from the high end of the five year range. The five year average levels as shown on slide number five.

Dave Canalongo: In just a few months, propane stocks have moved from the high end of the five-year range to five-year average levels, as shown on slide number five. This return of propane inventories to the historical average has tightened the market and driven bullish sentiment, with C3 Plus NGL prices, as a percent of WTI, increasing from 43 percent last fall to 57 percent today, driven largely by propane prices rising to above 90 cents a gallon. Slide number six illustrates the strengthening relationship we've seen between WTI and C3 plus NGLs in recent months, as Antero's NGL price has increased from $38 per barrel on average during 2023 to over $43 per barrel currently. In addition to the strong domestic fundamentals, propane exports have continued to impress.

Dave: This return of propane inventories to the historical average as tightened the market and driven bullish sentiment with <unk> plus NGL prices as a percent of <unk>, increasing from 43% last fall to 57% today, driven largely by propane prices rising to above 90 cents a gallon.

Dave: Slide number six illustrates the strengthening relationship we've seen between <unk> and <unk> plus Ngls in recent months as Antero <unk> NGL price has increased from $38 per barrel on average during 2023 to over $43 per barrel currently.

Dave: In addition to the strong domestic fundamentals propane exports have continued to impress.

Dave: Last year was a record year for propane exports, which average 162 million barrels per day for the full year 2023.

Dave Canalongo: Last year was a record year for propane exports, which averaged 1.62 million barrels per day for the full year 2023, as shown on slide number seven. 2024 has also started off strong, with exports averaging 1.72 million barrels per day year-to-date, an increase of nearly 200,000 barrels per day above the same weeks last year. These strong exports are occurring despite major volatility in global shipping routes, including restrictions on passage through the Panama Canal and rising geopolitical risks in the Middle East affecting passages through the Suez Canal and Red Sea.

Dave: As shown on slide number seven.

Dave: 124 has also started off strong with exports, averaging 172 million barrels per day year to date, an increase of nearly 200000 barrels per day above the same weeks last year.

Dave: These strong exports are continuing are occurring despite major volatility in global shipping routes.

Dave: Putting restrictions on passage through the Panama Canal and rising geopolitical risks in the middle east affecting passages through the Suez Canal Red Sea.

Dave Canalongo: The Baltic LPG rate, which is a metric of the shipping cost of liquefied petroleum gas on a VLG system, or Very Large Gas Carrier, increased to record levels at the end of 2023, primarily due to limitations on Panama Canal transits that resulted in shipping capacity being tied up in longer routes around the Cape of Good Hope, as shown on the graph on the right of slide number 8. However, this trend has reversed recently as the effects of the Panama Canal restrictions on LPG carriers have worsened, with canal passages increasing in January as a result of the global shipping reshuffle. Additionally, last year was a banner year for VLGC New Build, with 41 deliveries in 2023, as seen on the graph on the left of slide number eight, which is more than double the typical yearly delivery.

Dave: The Baltic LPG rate, which is a metric of the shipping cost of liquefied petroleum gas LDC or very large gas carrier increased to record levels at the end of 2023, primarily due to limitations on Panama Canal transits that resulted in shipping capacity being tied up in longer routes around the <unk>.

Dave: A good hope as shown on the graph on the right of slide number eight however.

Dave: However, this trend has reversed recently as the effects of the Panama Canal restrictions on LPG carriers have eased with canal passengers increasing in January as a result of the global shipping reshuffling.

Dave: Additionally, last year was a banner year for VLCC Newbuild deliveries with 41 deliveries in 2023 as seen on the graph on the left of slide number eight which is more than double the typical yearly delivery.

Dave Canalongo: VLGC supply is expected to continue to grow in 2024, with 21 more ships being delivered. These deliveries are occurring at the right time in the market, with US LPG export growth and the current challenges facing global shipping that have increased transit times and altered routes. As a reminder, Antero exports over 50% of its C3 Plus production, skewed heavily towards propane emissions, directly out of the Marcus Hook Terminal in Pennsylvania and has the ability to price our barrels on the international... Antero will benefit from the current lower shipping rates by being able to capture more of the spread between domestic and international pricing for propane. Also, Antero's export volumes are not impacted by potential constraints at the Gulf Coast export docks, which are at high utilization rates.

Dave: VLCC supply is expected to continue to grow in 2024 with 'twenty, one more ships being delivered.

Dave: These deliveries are occurring at the right time in the market with U S. LPG export growth and the current challenges facing global shipping that have increased transit times and altered routes.

Dave: As a reminder, antero exports over 50% of our <unk> plus production skewed heavily towards propane and butane directly out of the Marcus Hook terminal in Pennsylvania and has the ability to price our barrels on international indices.

Dave: Antero will benefit from the current lower shipping rates by being able to capture more of the spread between domestic and international pricing for propane and butane.

Dave: Also antero as export volumes are not impacted by potential constraints at the Gulf Coast export Docs, which are at high utilization rates with current export levels and limited capacity expansion is expected until 2025.

Dave Canalongo: Current Export Levels and Limited Capacity Expansions Expected Until 2025. I'll conclude my remarks this morning acknowledging that with these fundamentals I have just discussed, 2024 is poised to be yet another year in which our exposure to NGL pricing will be a supportive differentiator when compared to other natural gas producers. With that, I'll turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss natural gas. Thanks, Dave.

Dave: I'll conclude my remarks. This morning, acknowledging that with these fundamentals I have just discussed 2024 is poised to be yet another year in which our exposure to NGL pricing will be a supportive differentiator when compared to other natural gas producers.

Dave: 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.

Justin Fowler: I will start on slide number 9, titled Growing Global LNG Markets. This is a slide that we have shown in the past, but it's updated to reflect the potential impacts from the recent pause on LNG facility approvals from the U.S. government. Regardless of the duration of this pause, we expect very little impact on LNG demand growth into the end of this decade. In fact, only three LNG facilities in our stack, chart, could be impacted. You see those highlighted by a red box?

Justin Fowler: I will start on slide number nine titled growing Global LNG market.

Justin Fowler: This is a slide that we've shown in the past, but is updated to reflect the potential impacts from the recent pause on LNG facility approvals from the U S government.

Justin Fowler: Regardless on the duration of this pause we expect very little impact on LNG demand growth into the end of this decade.

Justin Fowler: In fact, only three LNG facilities in our stack.

It could be impacted you see those highlighted by the red boxes.

Justin Fowler: The remaining projects still result in over 10 BCF of incremental demand by the end of 2027. This would bring the current US LNG export capacity of 14.5 BCF per day to nearly 25 BCF per day during that time. This is a substantial demand increase that we expect to tie U.S. natural gas prices more closely to higher international prices. Antero is uniquely positioned to benefit from these higher expected U.S. natural gas prices, particularly prices linked to LNG demand growth near Henry Hub. Next, let's turn to slide number 10, titled Not All Transport to the U.S. Gold Coast is Equal.

Justin Fowler: The remaining projects still result in over 10 Bcf of incremental demand by the end of 2027.

Justin Fowler: This would bring the current U S. LNG export capacity of $14 five Bcf per day to nearly 25 Bcf per day during that time.

Justin Fowler: This is a substantial demand increase that we expect to tie U S natural gas prices more closely to the higher international prices.

Justin Fowler: Antero is uniquely positioned to benefit from these higher expected U S natural gas prices.

Justin Fowler: Particularly prices linked to LNG demand growth near Henry hub.

Next let's turn to slide number 10, titled not all transport to the us Gulf coast as equal.

Justin Fowler: As a reminder, we sell substantially all of our natural gas out of basin include.

Justin Fowler: As a reminder, we sell substantially all of our natural gas out of base, including approximately 75% to the LMG corridor. Our firm transportation portfolio provides us with direct exposure to growing LNG demand along the Gulf Coast and, importantly, at Tier 1 pricing points along the LNG corridor. This slide illustrates the significant benefit in selling our gas at Tier 1 Gulf Coast pricing. Based on the current strip, Tier 1 prices reflect increasing premiums to NYMEX in 2025 and beyond, including the TGP 500 index, which represents 30% of the 2.0 BCF per day of Antero-directed Gulf firm transportation, where premiums have increased to 29 cents above NYMEX in 2026. Antero also delivers to A&R Southeast and Columbia Gulf Onshore Point, which represents an additional 60% of premium delivery that will also appreciate with the current LNG export build out.

Justin Fowler: Including approximately 75% percent to the LNG corridor.

Justin Fowler: Our firm transportation portfolio provides us with direct exposure to growing LNG demand along the Gulf Coast and importantly in the tier one pricing points along the LNG corridor.

Justin Fowler: This slide illustrates the significant benefit in selling our gas at tier one Gulf coast pricing.

Justin Fowler: Based on the current strip tier one prices reflect increasing premiums to Nymex in 2025 and beyond.

Justin Fowler: Including the PGP 500 index, which represents 30% of the two point or <unk>.

Justin Fowler: Bcf per day of Antero directed Gulf firm transportation, where premiums have increased to 29 above Nymex in 2026.

Justin Fowler: Interior also delivers to Anr southeast and Columbia Gulf onshore points.

Justin Fowler: Which represents an additional 60% of premium delivery that over time will also appreciate with the current LNG export buildout.

Justin Fowler: Meanwhile, there are a number of peers that sell their gas in tier three which is currently trading almost 25 since back of Nymex in both 2025 and 2020.

Justin Fowler: Meanwhile, there are a number of peers that sell their gas in Tier 3, which is currently trading almost 25 cents back of NYMEX in both 2025 and 2026. Furthermore, we think Tier 3 pricing could continue to widen as LNG facilities are placed in service and Tier 1 pricing pushes higher. The yellow stars on the map highlight Ontario sales, which were strategically negotiated to bring our volumes directly to the LNG doorstep, as depicted in the pie chart on the top left-hand side of the slide.

Justin Fowler: Further we think tier three pricing to continue to widen as LNG facilities are placed in service in tier one pricing pushes higher.

Justin Fowler: The yellow stars on the map highlight antero sales points, which were strategically negotiated to bring our volumes directly to the LNG doorstep.

Justin Fowler: As depicted in the Pie chart on the top left hand side of the slide Antero, so 90% of its gas at tier one pricing.

Justin Fowler: Antero sold 90% of its gas at Tier 1 prices. This compares to the average of our peers, which sell 67% of their goals directed volumes at Tier 2 and Tier 3 prices. Looking ahead, as LNG export capacity increases by nearly 6 BCF, we expect Antero sales points to be priced even higher versus NYMEX at these LNG facilities as they compete for supply.

Justin Fowler: This compares to the average of our peers, which saw 67% of their Gulf directed volumes in tier two and tier three pricing.

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

We expect the interior sales.

Justin Fowler: <unk> to be priced even higher burst nymex with these LNG facilities.

Justin Fowler: They compete for supply.

Justin Fowler: The premium received at these sales points could also see further upside due to the delays on certain downstream pipelines that had previously been expected in the Haynesville by the end of this year. Delays into 2025 or 2026 would make our already existing burn transportation that much more valuable in the growing LNG market. Lastly, I would like to touch on power burn demand trends. Slide number 11 is titled, Power Burn Demand Continues to Outperform. This slide illustrates power burn demand over the last 10 years.

Justin Fowler: The premium received on these sales points could also see further upside due to the delays on certain downstream pipelines that had previously been expected in the haynesville by the end of this year.

Justin Fowler: Delays into 2025, or 2026 would make our already existing firm transportation that much more valuable in the growing LNG market.

Justin Fowler: Lastly, I would like to touch on power burn demand trends.

Justin Fowler: Slide number 11 titled Power Burn demand continues to outperform.

Justin Fowler: This slide illustrates tolerable in demand over the last 10 years.

Justin Fowler: Continued coal-to-natural gas switching, along with higher electrification demand for everything from electric vehicles to high-powered AI data centers, leads to increasing natural gas power generation demand. Despite the majority of forecasts that you see, which project flat or even lower power burn demand, power burn demand in 2024 is once again outperforming expectations. We believe there has been a structural shift toward reliable, clean, and affordable natural gas that will continue to increase power burn demand annually going forward. This demand growth, combined with rising LNG and Mexico exports, creates a significantly higher base demand level than we have ever experienced in the past. While there are certainly near-term storage challenges, we expect these fundamentals will provide support for natural gas prices and lead to periods of higher prices in the coming years. With that, I will turn it over to Mike Kennedy, Antero's CFO. Thanks, Justin.

Justin Fowler: <unk> coal to natural gas with gene along with higher electrification demand for everything from electric vehicles to high powered AI data centers leads to increasing natural gas power generation demand.

Justin Fowler: Despite the majority of forecast that you see which project flat or even lower power burn demand power burn demand in 2024 is once again outperforming expectations.

Justin Fowler: We believe there has been a structural shift toward reliable clean and affordable natural gas that will continue to increase power burn demand annually going forward.

Justin Fowler: This demand growth combined with rising LNG and Mexico exports creates a significantly higher base demand level than we have ever experienced in the past.

Justin Fowler: While there are certainly near term storage challenges. We expect these fundamentals will provide support to natural gas prices and lead to periods of higher prices in the coming years.

Justin Fowler: With that I will turn it over to Mike Kennedy Antero CFO.

Michael N. Kennedy: Justin first I'd like to discuss our multi decade inventory position.

Michael N. Kennedy: First, I'd like to discuss our multi-decade inventory. Turning to slide number 12, titled, AR has the largest low-cost image. This chart compares inventory positions across our natural gas peer group, based on data from a third-party report. Antero has the most sub-275 per MCFE drilling inventory at 22 years.

Michael N. Kennedy: Turning to slide number 12 titled.

Michael N. Kennedy: Or has the largest low cost inventory.

Michael N. Kennedy: This chart compares to inventory positions across our natural gas peer group based on data from a third party report.

Michael N. Kennedy: Antero has the most sub $2 75 per Mcf drilling inventory at 22 years.

Michael N. Kennedy: It is important to note that this inventory comparison is after our peers have spent a combined $30 billion on acquisitions over the past three years. In contrast, through our organic leasing efforts, we have invested $340 million over that time to acquire targeted drilling locations within our development footprint. On average, we have been able to add locations for less than $1 million per location through this program.

Michael N. Kennedy: It is important to note that this inventory comparison is after our peers, who spent a combined $30 billion on acquisitions over the past three years.

In contrast through our organic leasing efforts, we have invested $340 million over that time to acquire targeted drilling locations within our development footprint.

Michael N. Kennedy: On average we have been able to add locations for less than $1 million per location through this program.

Michael N. Kennedy: This is less than half of the nearly $2 million average cost per location for the pier acquisition. In 2023, Antero organically added over 100 premium core locations at an average cost per location of less than $1 million, more than offsetting its 2023 drilling program. Next, I'd like to go a little deeper on the capital efficiency improvements that Paul touched on in his comments. The chart on slide 13 compares capital efficiency of the natural gas peer group for the amount of capital required to achieve production targets. Antero has the lowest capital per MCFP of its peer group at just $0.55 per MCFP, 40% below the peer average of $0.92 per MCF. This capital efficiency measure is important when comparing asset quality and operating capabilities of each company.

Michael N. Kennedy: This is less than half of the nearly $2 million average cost per location for the peer acquisitions.

Michael N. Kennedy: In 2023, Antero organically added over 100 premium core locations at an average cost per location.

Michael N. Kennedy: Less than $1 million.

Michael N. Kennedy: More than offsetting its 2023 drilling program.

Michael N. Kennedy: Next I'd like to go a little deeper on the capital efficiency improvements that Paul touched on in his comments.

Michael N. Kennedy: The chart on Slide number 13 compares capital efficiency of the natural gas peer group where the.

Michael N. Kennedy: The amount of capital required to achieve production targets.

Antero has the lowest capital per Mcf fee of its peer group at just 55 per Mcf.

Michael N. Kennedy: This is 40% below the peer average of 92 per Mcf.

Michael N. Kennedy: This capital efficiency measures important when comparing asset quality and operating capabilities of each company.

Michael N. Kennedy: The scatter plot on slide number 14, really magnifies, the peer leading capital efficiency and Antero.

Michael N. Kennedy: The scatterplot on slide number 14 really magnifies the peer-leading capital efficiency at Intero. This chart shows 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, X-axis for the natural gas piers. These estimates are based on company guidance for those that have announced 2024 guidance and consensus estimates for those that have not.

Michael N. Kennedy: This chart shows 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.

Michael N. Kennedy: <unk> access for the natural gas peers.

Michael N. Kennedy: These estimates are based on company guidance for those that have announced 2020 for guidance and consensus estimates for those that are not.

Michael N. Kennedy: When you compare the production targets to the drilling and completion capital invested to deliver that production, we are by far and away the most capital efficient operator in Appalachia.

Michael N. Kennedy: When you compare the production targets to the drilling and completion capital invested to deliver that production, we are, by far and away, the most capital efficient operator in. Let's turn to slide number 15, titled Free Cash Flow Breakeven, which summarizes the benefits of our combined capital efficiency gains and high NGL exposure. Beginning at the top left-hand side of the slide, our total capital budget, drawing in completion plus land capital, is expected to be down nearly $300 million in 2024 compared to last year. Moving down to the bottom left-hand side of the slide.

Michael N. Kennedy: Let's turn to slide number 15, titled free cash flow breakeven, which summarizes the benefits of our combined capital efficiency gains and high NGL exposure.

Michael N. Kennedy: Beginning at the top left hand side of the slide our total capital budget drilling and completion plus land capital.

Michael N. Kennedy: This is expected to be down nearly $300 million in 2024 compared to last year.

Michael N. Kennedy: Moving down to the bottom left hand side of the slide the 2020 for NGL strip has more than $3 per barrel higher than in 2023.

Michael N. Kennedy: The 2024 NGL strip is more than $3 per barrel higher than in 2023. As a rule of thumb, every dollar change in NGL prices results in a $40 million change in cash flow. That's higher NGL prices in 2024 drive a $135 million increase in cash. In combination, the result is approximately $430 million of incremental cash flow in 2024 compared to 2023 from our capital efficiencies and NGLs and more than offsets the weakness in the natural gas, even while being unheard. Turning to slide number 16, this slide compares free cash flow breakeven, which low maintenance capital requirements and high exposure to liquids result in the lowest unhedged free cash flow breakeven price among our natural gas peers. As we look ahead, we believe Antero is best positioned to create significant shareholder value.

Michael N. Kennedy: As a rule of thumb every dollar change in NGL prices results in $40 million change in cash flow.

Michael N. Kennedy: And thus higher NGL prices in 2024 drive $135 million increase in cash flow.

Michael N. Kennedy: In combination. The result is approximately $430 million of incremental cash flow in 2024, compared to 2023 from our capital efficiencies and NGL focus and more than offsets the weakness in the natural gas market, even while being unhedged.

Michael N. Kennedy: Turning to slide number 16. This slide compares to free cash flow breakeven levels are low maintenance capital requirements and high exposure to liquids results in the lowest unhedged free cash flow breakeven price among our natural gas peers.

Michael N. Kennedy: As we look ahead, we believe antero is best positioned to create significant shareholder value.

Michael N. Kennedy: We have Product Diversity, the largest NGL producer and exporter of LPGs, the highest exposure of natural gas production to the LNG demand center, and The Lowest Amount of Hedge Volumes, which creates substantial leverage to rising Henry Hill. In addition, our realized prices have basis upside due to our premium sales points along the LNG fairway. Finally, we are the most capital efficient natural gas producer in the US with the lowest free catch low break. The combination of downside protection from our liquids production, a strong balance sheet, and the Lowest Breakeven Price, combined with the upside exposure through our takeaway to the LNG Demand Center places Antero at a significant competitive advantage, and many more.

Michael N. Kennedy: We have product diversity as the largest NGL producer and exporter of LPG.

Michael N. Kennedy: The highest exposure of natural gas production to the LNG demand center and the lowest amount of hedge volumes, which creates substantial leverage to rising Henry hub prices.

Michael N. Kennedy: In addition, our realized prices have basis upside due to our premium sales points along the LNG fairway.

Michael N. Kennedy: Finally, we are the most capital efficient natural gas producer in the U S with the lowest free cash flow breakeven.

Michael N. Kennedy: The combination of downside protection from our liquids production.

Michael N. Kennedy: <unk> balance sheet and lowest breakeven price combined with the upside exposure through our takeaway to the LNG demand center.

Michael N. Kennedy: <unk> Antero and a significant competitive advantage as we move towards the substantial increase in demand expected from near term LNG projects with that I will now turn the call over to the operator for questions.

Michael N. Kennedy: A substantial increase in demand is expected from near-term L&G projects. With that, I will now turn the call over to the operator for questions. Thank you. We will now be conducting a question and answer session. If you would like to be placed in the question queue, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue.

Speaker Change: Thank you, we'll now be conducting a question and answer session if you'd like to be placed in the question queue. Please press star one on your telephone keypad.

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Operator: You may press star 2 if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing star 1. One moment, please, while we poll for questions. Our first question today is coming from Arun Jayaram from JPMorgan Chasing Company. Your line is now live. Good morning, gentlemen.

Speaker Change: First question today is coming from Arun Jairam from Jpmorgan Chase <unk> Company. Your line is now live.

Arun Jairam: Yes, good morning, gentlemen.

Arun Jairam: My first question.

Arun Jayaram: My first question is related to LPG pricing, perhaps for Dave. Dave, I'm looking at your weekly pricing update that you provided on Monday. And it shows kind of your mix between Mont Belvieu and global pricing being about a 50-50 mix. Given your strength in the international market, do you have any flexibility to increase, call it your leverage, just given the strong export trends? And if so, can you maybe quantify what that could mean for your realizations?

Arun Jairam: Is it related to LPG pricing.

Arun Jairam: Perhaps for Dave Dave I'm looking at your weekly pricing.

Arun Jairam: Update that you provided on Monday.

Arun Jairam: And it shows kind of your mix between Mont Belvieu and global pricing being about a 50 50 mix.

Arun Jairam: Given the strength in the international market.

Arun Jairam: Do you have any flexibility to increase call. It your leverage just given the strong export trends and if so can you maybe quantify what that could mean for your your realizations.

Arun Jairam: Yeah. So we when we talk about that exposure, it's really on the overall future plus barrel that we've talked about on prior calls Theres times, even in the summer, where we're exporting 85% to 90% of our propane.

Dave Canalongo: Yeah, so when we talk about that exposure, it's really on the overall C3 plus barrel that we talked about in prior calls. There are times, even in the summer, where we're exporting 85, 90% of our propane. So we do utilize that flexibility that we have, you know, with our marketing plan to do that. But no, I mean, other than that, the isobutane, and the pentanes, we're not exporting those products. So that's always going to stay in the domestic pool, which is why you're going to see that 50-50 relationship that you're talking about.

So we do utilize that flexibility that we have.

Arun Jairam: With our marketing plan to do that.

But no I mean other other than that the ISO butane the pentane, we're not exporting those products. So that's always going to stay that domestic coal, which is why youre going to see that that 50 50 relationship that you're talking about.

Dave Canalongo: And then just looking at the last pricing update, there's about a four to five cent per gallon delta between propane between International and Mont Belvieu. How much of the international realizations are impacted by net shipping costs? And as those net shipping costs, as you show, normalize, you know, what kind of uplift could that provide? Yeah, quite a bit. I mean, we've seen that just here recently you saw that the Baltic rates collapsed pretty dramatically, and so we've benefited from that. I think you've seen, you know, the propane trading balance this morning was 94 cents a gallon. So a lot of that's been driven by the fact that freight costs have decreased. If you look at destination pricing, in Asia, you're not seeing propane prices at strong levels this winter, relative to NAFTA; it's actually, you know, similar pricing to what we would see in the summertime.

Arun Jairam: And then just looking at the last pricing update there was about a four to five cents per gallon delta between propane.

Arun Jairam: Between international and <unk>.

Arun Jairam: And Mont Belvieu, how much of the international.

Arun Jairam: Realizations are impacted by net shipping cost and as those net shipping cost as you show normalized what kind of uplift could that provide.

Arun Jairam: Yeah, so quite a bit I mean, we've seen that just here recently, you've seen at the Baltic rates collapsed pretty dramatically.

Arun Jairam: And so we benefited from that I think you've seen propane.

Arun Jairam: Today. This morning trading balance of Mark 94 cents per gallon so a.

Arun Jairam: A lot of that's been driven by the fact that the freight costs have decreased if you'll look at destination pricing in Asia, but youre not seeing propane price at strong levels. This winter relative to naphtha is actually a similar pricing to what we would see in the summer time. So the run up in Mont Belvieu pricing has been really driven by the.

Dave Canalongo: So the run-up in Mount Bellevue pricing has been really driven by the collapsing freight rates that have allowed Bellevue to rise. The other piece I think that we see, you know, with our portfolio is the Gulf Coast docks, as we've talked about, are very highly utilized. And so as you move into the spring and summer seasons, domestic demand wanes, we think you'll see more pressure to try and export out of those facilities.

Arun Jairam: Collapsing freight rates that have allowed bellevue to rise.

Arun Jairam: Other piece I think that we see with our portfolio as the golf coast docks as we've talked about are very highly utilized and so as you move into.

Arun Jairam: The spring and summer season.

Arun Jairam: Domestic demand wanes, we think youll see.

Arun Jairam: More pressure to try and export out of those facilities and until they expand in 2025 that'll be limited and so that value premium that you get at the dock will rise and our ability to access that directly with our firm capacity out of Marcus hook will be able to take advantage of that more as well so kind of two things working in our favor.

Justin Fowler: And until they expand in 2025, that'll be limited. And so that value premium that you get at the dock will rise. And our ability to access that directly with our firm capacity out of Marcus Hook, we'll be able to take advantage of that more as well. So, kind of two things working in our favor, the ability to get to the waterborne price, not just somewhat landlocked at Mount Bellevue, as other producers are, and then the improved freight dynamics have allowed us to benefit more than others. Okay, and I have one quick one for Justin. Justin, if the momentum pipeline is delayed by, you know, given some of the issues in terms of timing there, what kind of impact do you see on tier one pricing in that Louisiana LNG corridor? Good morning, Arun.

Arun Jairam: The ability to get to the waterborne price not just.

Somewhat landlocked at Mont Belvieu with other producers are and then the.

Arun Jairam: Improved freight dynamics.

Have allowed us to benefit.

Arun Jairam: More than others.

Speaker Change: Okay and I have one quick one for Justin Justin if the momentum pipeline is delayed by given some of the.

Speaker Change: The issues in terms of timing there what kind of impact do you see to call it tier one pricing.

Speaker Change: In the Louisiana LNG corridor.

Justin Fowler: You know, once we start seeing the Plaquemine... facility, once they start to introduce gas, you know, sometime later this year, we would expect to see that forward basis continue to increase. You know, keeping an eye on A&R Southeast basis right now, it's showing a positive versus Henry, and it can range anywhere from seven to nine cents over at the moment. And, you know, any of those delays that are going to bring less gas down to that Henry Hub region, we would just expect to see that the base has continued to increase as more competition enters the market with Golden Pass and Plaquemine. Great, thanks a lot.

Justin Fowler: Yeah, Good morning Arun.

Speaker Change: Once we start seeing the plaque iman.

Justin Fowler: Facility once they start to introduce gas sometime later in this year.

Arun Jairam: We would expect to see that forward basis continue to increase.

Arun Jairam: Keeping an eye on Anr southeast basis, right now, it's showing a positive first Henry and it can range anywhere from seven to nine cents over at the moment.

Arun Jairam: And any of those delays that are going to bring less gas down to that Henry hub.

Arun Jairam: Region, we would just expect to see that that base has continued to increase.

Arun Jairam: More competition enters into the market with with Golden pass and Plaquemines coming on.

Speaker Change: Great. Thanks, a lot.

Brooklyn, Donna: Thank you. Our next question today is coming from Brooklyn, Donna's from cruise Securities. Your line is now live.

Bertrand Donnis: Thank you. Our next question today is coming from Bertrand Donnis from Cruise Security. Your line is now live. Hey, good morning, guys.

Donna: Hey, good morning, guys.

Donna: Good morning.

Paul M. Rady: All right. On slide 12, you outline your low-cost inventory, and I'd, you know, say a while ago, 15 years of inventory was enough, maybe it moved to 10 at one point, but when you're sitting at 22 years, you could split the company in half and still not be in the running out of inventory group, so the natural question would be, you know, is there some interest in maybe divesting some of the inventory that's at the end of the And then just the broader question is, can you really get two parties to the table in this current gas-priced contango, or does one party just simply refuse to look to the other? On the first one, no, we are a consolidator of the Liquids Fairway in West Virginia, and that's been 22 years.

Donna: On Slide 12, you outlined your low cost inventory and I'd say, a while ago 15 years of inventory with enough maybe maybe move to 10 at one point, but when youre sitting at 22 years, you could you could split the company in half and still not be in the running out of inventory group. So the natural question would be.

Donna: Is there some interest in maybe divesting some of the inventory that that's at the end of the stack and then just broader question is can you really get two parties to come to the table in this current gas price contango or or just one party just simply refused to look to the outer years.

Speaker Change: On the first one no we are a consolidator of the liquids fairway of West, Virginia, and that 'twenty two years about half of its liquids. The other half is our dry gas option, which is on the eastern side of our field.

Paul M. Rady: About half of it's liquids, and the other half is our dry gas option, which is on the eastern side of our field. So, that provides a good dry gas option and allows us the flexibility to toggle between liquids and dry gas. Liquids are obviously very creative today; I think we get over a $1.10 uplift from liquids compared to the Henry Hub price, so we've been focused on that. So we want to continue to consolidate that, and with our scale and the liquids midstream we own and the transport, the barriers to entry are very high. No one could really develop that outside of having those attributes, continue to consolidate, and look to own more and more of the inventory.

Speaker Change: So that provides a good dry gas option allows us flexibility to toggle between liquids and dry gas liquids is obviously very accretive today I think we get over $1.10 uplift.

Speaker Change: From the liquids compared to the Henry hub price. So we've been focused on that so we want to continue to consolidate that and with our scale and liquids midstream we own in the transport the barriers to entry are very high so no one really could develop that outside of having those attributes so.

Speaker Change: To consolidate and look to own more and more of the inventory.

Speaker Change: And on your second question I really didn't quite understand that.

Paul M. Rady: And on your second question, I really didn't quite understand that on the contango of natural gas. We're really, as I said, more looking at the liquid prices driving the economy. We look forward to working with you. The Bulletproof Executive 2013, Yeah, sorry. I was just wondering, in any negotiations you're doing, maybe even on the acquiring side, are both parties able to kind of agree on a higher gas price in the future? Or does the buyer always say, you know, I see only the near-term lower price, and I won't, you know, give you value for the whole year?

Speaker Change: On the contango.

Speaker Change: Of natural gas, we're really more looking at the liquids prices driving the economics. So that's what we look more to the liquids in the gas.

Speaker Change: Yes, sorry, I was just wondering any negotiations you're doing maybe even on the acquiring side.

Speaker Change: Our both parties able to kind of agree on the higher gas prices in the future or does the buyer always say I see only been near term lower priced I won't give you a value for the outer years.

Paul M. Rady: Yeah, we really haven't been in any discussions. We're focused on our, where it would be at. The most value, as I mentioned, is less than a million dollars per location. $2 million per location. You're not really in those types of negotiations when you're doing, Brick-by-brick, you know, the ground game of organic leasing. Dealing with leaseholders that enjoy, They're men.

Speaker Change: Yeah, we really haven't been any discussions were focused on organic leasing that's where we add.

Speaker Change: The most value as I mentioned before.

Less than $1 million per location than M&A over $2 million per location. So not really in those type of negotiations when youre doing.

Speaker Change: Brick by brick ground game of organic leasing you're just dealing with leaseholders that enjoy that you've developed are there minerals.

Speaker Change: Makes sense and the second question just some of your peers are earmarking a.

Paul M. Rady: Makes sense. And the second question is just some of your peers are earmarking a significant amount of capital for, you know, infrastructure build out over the next few years. And I would assume this lower full year 24 guidance doesn't have that much included in it. So, you know, could you maybe talk about how you're able to operate efficiently without that kind of overhead that your peers have? Yeah, it's Antero Midstream.

Speaker Change: The amount of capital for infrastructure build out over the next few years and I would assume this lower.

Speaker Change: Full year 'twenty four guidance doesn't have that much included into it so.

Speaker Change: Could you maybe talk about how you were able to operate efficiently without that kind of overhead that you put yourself.

Speaker Change: Yeah, and Taro midstream, we owned 30% of Antero midstream Perimetrium spilt out this the largest liquid system in Appalachia, and we have all the processing and high pressure and low pressure than the firm transport connects to that so we've already made all of those investments.

Paul M. Rady: We own 30% of Antero Midstream, which has built out this largest liquid system in Appalachia. And we have all the processing and high pressure and low pressure, and then the firm transport connects to that. So we've already made all those investments. Antero Midstream has, and they own 30%, but Antero Midstream came out with their capital and their capital, much lower as well, because it's just in time, really, building that last mile of low pressure in water.

Speaker Change: And Param midstream has.

Around 30% that Antero midstream came out with their capital and their capital is much lower as well because it's just in time really building that last mile of low pressure in water. So we've already made all those midstream investments. It's one of the reasons, where the unconstrained E&P, we don't have midstream constraints.

Paul M. Rady: We've already made all those midstream investments. It's one of the reasons we're the unconstrained E&P. We don't have midstream constraints.

Jacob Roberts: Everything's already done, I appreciate it. Thanks. Thank you. Next question is coming from Jacob Roberts from Tudor Pickering Holt. Your line is now live. Good morning.

Speaker Change: Everything is already in the ground.

Speaker Change: I appreciate it thanks.

Speaker Change: Thanks Jacob.

Speaker Change: Thank you. Your next question is coming from Jacob Roberts from Tudor Pickering Holt. Your line is now live.

Jacob Roberts: Good morning.

Jacob Roberts: Good morning.

Paul M. Rady: We appreciate the pricing outlook you guys have given and baked into the guide. But curious, should the need arise, is there an ability to further reduce activity without running into contract issues, or any other commentary on other actions that might be preferred that could further lower the capital? Yeah, of course, you know, when we construct the capital plan, the first filter is always to generate pre-cash flows. So we're very focused on that. We're down to two rigs from three rigs; we stacked one of our rigs.

Jacob Roberts: We appreciate the pricing outlook, you guys have given and baked into the guide, but curious should the need arise is there an ability to further reduce activity without running into contract issues or any other commentary on other actions might be preferred that could for further lower the capital plan for 2024.

Speaker Change: Yes of course, you know when we construct the capital plan. The first filter is always to generate free cash flow. So we're very focused on that.

Speaker Change: The two rigs from three rigs, we stacked one of our rigs.

Paul M. Rady: So down to two rig programs and one completion crew, one of our completion crews who made it a spot crew. That spot crew does have one pad that it is scheduled to complete in the third quarter, and that's highly flexible. The Bulletproof Executive 2013, gas prices have gone down a bit, but more to liquids prices. Uh, so we do have the ability to toggle lower, uh, that's about, you know, 50 million dollars, call it that, so you could definitely toggle lower than that, today's gas prices, which is about 225. We're still generating free cash flow, so that's quite amazing, and it's really due to the liquid prices in the capital. This price is due at about $1.10 to $1.15 right now in popular demand, really driven by liquids prices, and so we'll continue to... Great, thank you. The second question we were hoping you could answer was...

Speaker Change: So down the two rig program and one completion crew.

Just released one of our completion crew submitted a spot.

Speaker Change: Crew.

Speaker Change: That spot crude does have one pad that it.

Speaker Change: It's scheduled to complete in the third quarter, and that's highly flexible and dependent on liquids prices.

Speaker Change: Natural gas prices, a bit but more to liquids prices.

Speaker Change: So we do have the ability to toggle lower.

Speaker Change: That's about $50 million call. It so you could definitely toggle lower than that.

Today's gas prices, which by the $2 25 strip, we're still generating free.

Speaker Change: Free cash flow, so that's quite amazing and it's really due to the liquids prices and the capital efficiency and I mentioned the liquids prices do at about $1 10 to $1 15, right now on top of that $2 25. So.

Driven by the liquids.

Speaker Change: Prices and so we'll continue to monitor those and really focus on generating free cash flow.

Speaker Change: Great. Thank you.

Speaker Change: Second question, we were hoping you could provide some commentary on the potential upside to volumes heading towards the shell facility and if that materializes, what it could mean for the product mix as we progress through this year.

Paul M. Rady: This slide provides some commentary on the potential upside to volumes heading toward the Shell facility and, if that materializes, what it could mean for the product mix as we progress forward. Yeah, no, we're just assuming flat to last year. I mean, our ethane guidance is, you know, around 70,000 barrels a day. And that's where we were at last year. That assumes Shell performs like it did last year.

Speaker Change: Yeah, No. We're just assuming flat to last year I mean, our ethane guide.

Speaker Change: Guidance is around 70000 barrels a day and Thats, what where we were at last year that assumes shell performs like it did last year, which is kind of in the low teens, so not not really thinking about increased ethane volumes around that and it's not material.

Dave Canalongo: It's kind of in the low teens, so not really thinking about increased ethane volumes around that. And it's not material to the pricing, it's a Henry Hub-based price. So it's very similar to what we get if it remains in the stream. I would have a little bit of volume tailwind if it performed better than last year, but not making that. Appreciate the time.

Speaker Change: Material and the pricing, it's a Henry hub based price.

Speaker Change: So it's very similar to what we get if it remains in the stream so.

Speaker Change: We'd have a little bit of volume tailwind if it performs.

Speaker Change: Better than last year, but not making that in the guidance.

Speaker Change: Thanks appreciate the time.

Okay.

Roger Reed: Thank you. The next question is coming from Roger Reed from Wells Fargo. Your line is now live. Yeah, thank you. Good morning.

Roger Read: Thank you next question is coming from Roger read from Wells Fargo. Your line is now live.

Roger Read: Yes, Thank you and good morning.

Paul M. Rady: I'm going to come back to a question I asked on the last call, the third quarter, you know, the charts here, you know, page three is probably the best example. You know, just continued improvements in D&C efficiency, looking at your best performances, right? 16 stages in a day, or the cycle times reduced to 122 relative to the averages for both. How, without asking, can you achieve those best-case scenarios on a regular basis going forward? What was the difference between, say, the average and the best performance?

Roger Read: I'm Gonna come come back to a question I asked in the last call the third.

Roger Read: Third quarter, yes.

Roger Read: The charts here page three is probably the best example.

Roger Read: Just continued improvements in D&C efficiencies.

Roger Read: Looking at your past performance is right 16 stages in a day or the cycle times reduced to 122 relative to the averages for both.

Roger Read: Well.

Speaker Change: Without asking can you achieve those best case scenarios on a regular basis going forward what was the difference between say the average in the past performance.

Paul M. Rady: Is that a seasonal thing? Or is it, you know, just good luck? I'm just curious, kind of the difference between the two can maybe help us think about how we bridge the gap between those two, you know, continuing D&C efficiency. Yeah, no, I mean, it's really around reducing hours on the completions. And when we get above 20 hours a day, we generally hit 13, 14 stages. When you hit the 16, it just hits just right, and the pump maintenance on that day was much lower, and your pumping hours were much greater. That's really where it's at, and what was amazing in 23 was we started consistently hitting the high teens pumping hours and really consistently hitting 12, 13, 14 stages a day, and then you'd maybe have one day where there were some issues, but that would all culminate in an average of 11 stages per day, which compared to our prior average of 8 to 9, and that's what was in the guidance, was amazing. And then same thing on the drilling We are drilling 2,000 feet greater laterals in 2024, so we do think that improves. That's already amazing.

Speaker Change: The thing is it just.

Speaker Change: Good luck.

Speaker Change: Curious kind of the difference between the two maybe help us think about how we bridge the gap between those two continuing D&C efficiencies.

Speaker Change: Yeah, No I mean, it's really around pumping hours on the completions and when we get above 20 hours a day, we generally hit 13 14 stages and when you hit the 16 inches hit just right in the pump maintenance on that day was much lower than your pumping hours for much greater so that's really where it's at.

Speaker Change: Well, it's amazing in 'twenty threes, we started consistently hitting that high teens pumping hours and really consistently hitting 12 13 14 stages. A day and then you would maybe have one day, where there was some issues, but that would all culminated in an average of 11 stages per day, which compared to our pre.

Speaker Change: <unk> average of eight to nine and that's what was in the guidance.

Speaker Change: It was amazing and then same thing on the drilling we are drilling 2000 feet greater laterals in 2024. So we do think that improves this already amazing on.

Paul M. Rady: Drilling Days per 10K Improvements. So we have gone from about seven days per 10K now down to five, and that's continuing to drill longer and longer laterals. Yeah, it's been amazing what everybody has been able to do. You know, the way you guys are leading it. Definitely impressive. Yeah, we're up to 15,000 feet per lateral. By far, I've... Yeah, yeah, well, one of these days, we'll get gas prices to agree with us on the other side.

Speaker Change: Drilling days per 10-K improvements so we have gone.

Speaker Change: <unk> gone from about seven days per 10-K, now down to five and Thats continuing to drill.

Longer and longer laterals and that really helps those averages.

Speaker Change: Yes, it's been amazing what everybody.

Speaker Change: He has been able to do that.

Speaker Change: Our lead minutes definitely impressive yeah, we're up to Sydney over.

Speaker Change: Over 15000 feet per laterals in 2024, which is by far highest in company's history.

Yeah, Yeah, well what.

Speaker Change: One of these days, we'll get gas prices to agree with us on the other side.

Michael N. Kennedy: And along those lines, what is the right way to think about, you know, the use of cash going forward? Obviously, you should get the balance sheet where you want it this year, if it's not already. Once that's done, dividend share repo, variable dividend, what is the way you want to think about the return of excess cash going forward? Yeah, like we said, you know, first is to continue to pay down debt. We paid down, and then in the fourth quarter with our free cash flow, we'll do it with our free cash flow in the first quarter as well, and get it down at the credit facility at the year-end.

Speaker Change: And along those lines what is what is the right way to think about.

Speaker Change: Use of cash going forward, obviously, you should get the balance sheet, where you want it this year, if it's not already.

Speaker Change: Once that's done dividends and share repo variable dividend what is the way you want to think about the return of excess cash going forward.

Speaker Change: Yeah, like we said first continue to pay down debt.

Speaker Change: We paid down.

Speaker Change: That in the fourth quarter of our free cash flow will do it with our free cash flow in the first quarter as well.

Speaker Change: Get it down the credit facility at year.

Speaker Change: Year end.

Speaker Change: Had close I think it was $420 million 430 slightly the FERC.

Speaker Change: Use of our free cash flow then we have 2026 is in the $100 million range. You saw Aro are all approximate numbers would also kind of be included in that credit facility amount.

Michael N. Kennedy: I think it was $420 million, $430 million, so that would be the first. www.globalonenessproject.org. We've set a majority of the pre-cash flow at a share. We tend to favor shared buybacks at these levels. So, that's kind of the order in which the free cash flow will be used, pay down debt for the next half a billion dollars, call it that, and then the majority after that. Appreciate the clarification. Thanks, guys. Thank you. As a reminder, that's star number one to be placed in the question queue. Our next question is coming from Nitin Kumar from Azuho Securities. Your line is now live. Hey, good morning, guys, and thanks for getting me on.

Is that kind of gets down to the $1 billion debt level and then once that's achieved and we set a majority of the free cash flow will go to share buybacks, we tend to favor to share buybacks at these levels at these valuations.

Speaker Change: So that's kind of the order of the free cash flow use pay down debt for the next half a billion dollars call. It and then a majority after that goes to share buybacks.

I appreciate the clarification thanks guys.

Speaker Change: Yep.

Speaker Change: Thank you as a reminder, Thats star one to be placed in the question queue. Our next question is coming from Nathan Kumar from Mizuho Securities. Your line is now live.

Nathan Kumar: Hey, good morning, guys and thanks for getting me on.

Nathan Kumar: I guess.

Nitin Kumar: I certainly appreciate the work that you've done on improving capital efficiencies for 2024. If I could maybe delve into what 2025 looks like, right? So you had pretty strong momentum going into the end of 2023, but you're reducing activity. Just trying to understand, without looking for guidance, what would the impact of this decline in activity have on your 2025 trajectory, if any? Not really any, it's the maintenance capital level. When we think about maintenance capital, it's 3.3 to 3.4. We obviously outperformed last year with the completion efficiencies and cycle times; we were better than we had forecast, and so now that we've wrapped those efficiencies in our forecast going forward, it's very similar to this year. B. Sheffy per day, www.globalonenessproject.org Yeah, that's helpful.

Nathan Kumar: Certainly appreciate will's because you've done on improving capital efficiencies for 2024.

Nathan Kumar: If I could.

Nathan Kumar: Maybe delve into what does 2025 look like right. So you had some pretty strong momentum going into the end of 2023.

Nathan Kumar: Seeing activity just trying to understand without looking for guidance.

Nathan Kumar: The impact of this decline in activity have on your clean 25 trajectory if any.

Not really I mean, it's the maintenance capital level, when we think about maintenance capital. It's three three to three four we obviously.

Nathan Kumar: Outperformed last year with the completion efficiencies and cycle times, where we are.

Nathan Kumar: Better than we had.

Nathan Kumar: Forecast and so now that we've wrapped those efficiencies in our forecast going forward. It's very similar to this year you know hold that three three to three four.

Nathan Kumar: Bcf per day, and the $700 million range ish.

Speaker Change: Got it that's helpful.

Hey, Paul.

Paul M. Rady: You know, Paul, when you started the company, you certainly targeted the LNG corridor and were strategic in sort of signing up for phone transportation to the market. Really good slides on the power generation market here. Any opportunities to link up with those demand centers with long-term contracts that could kind of solidify your realizations? You know, we've looked at those. They come with fairly hefty commitments.

Paul M. Rady: He started the company.

Paul M. Rady: We certainly targeted LNG corridor, and where were strategic and sort of signing up for.

Paul M. Rady: From transportation to the market.

Paul M. Rady: Really good slides on the power Gen market here.

Paul M. Rady: Opportunities to link up with those demand centers with long term contracts that could kind of solidify your realizations.

Paul M. Rady: We've looked at those they come with a fairly hefty commitments. We've already made the commitment than as you know with all of that firm transport that we control and have for quite some time so.

Paul M. Rady: We've already made the commitments. And as you know, with all that firm transport that we control and have had for quite some time, so, The Bulletproof Executive 2013 Absolutely. Hopefully, they will take the money.

Paul M. Rady: We've kind of.

Paul M. Rady: She'd those prices through our firm transport commitments and think we will be the beneficiary of those they will accrue to us we're all spot pricing, we're not signing up for any Henry hub type deals long term, we're just going to flow our gas down to this corridor and let people compete for it and we'll see what the price is but we think we will.

Paul M. Rady: But we have to show them that we're not just going to... MOR07... monastery. I just want to make a quick, quick remarks because I don't have all the time, but my community admires us and likes us. We wanted to jump in and adventure a little bit with you, kind of, where we get our connection at an international-linked price. Great, thanks for the answers.

Paul M. Rady: Realize a lot of that uplift without having these kind of international linked pricing.

Speaker Change: Great. Thanks for the answers Yep Yep. Thank you.

Neal Dingmann: Thank you. Our next question is coming from Neal Mata from Goldman Sachs. Your line is now live.

Speaker Change: Our next question is coming from Neil Mehta from Goldman Sachs. Your line is now live.

Neal Dingmann: Yeah, thanks, team. And congrats on the improvement in capital efficiency in the guide. I have some macro questions.

Neal Dingmann: Yes, thanks team and congrats on the improvement in capital efficiency in the guide it's a macro questions I guess the first one is.

Dave Canalongo: I guess the first one is on propane. Can you talk a little bit about slide five? And what do you think has been the main driver of getting the inventories back to five years? And as we think about propane markets, Asia continues to be really important, and sometimes harder for us as an investment community to get visibility out there. So talk about how you think about China; China and Asia feed into the propane ounces of 20.

Neal Dingmann: On propane can you talk a little bit about slide five and what do you think in the main driver.

Getting the inventories back to the five year and as we think about propane markets Asia continues to be really important and it's sometimes harder for us as an investment community to get visibility out there. So talk about how you think about China, China and Asia feeds into protein analysis of 2024.

Speaker Change: Yeah, I think there are a couple of things I'll talk about in the propane inventory level of a one off there was a surprise adjustment from the EIA. They had they had a really since mid November through call. It mid to late December they had a calculation error. So they were overstating propane inventories. So we got a <unk>.

Dave Canalongo: Yeah, I think there are a couple of things I'll talk about at the propane inventory level. I mean, one, there was a surprise adjustment from the EIA. They had really since mid-November through, call it mid to late December, they had a calculation error.

Dave Canalongo: So they were overstating propane inventories. So we got an initial nice bump there, you know, but better late than never. And then as we moved into January, we continued to see exports stay strong all of December and January.

Speaker Change: So a nice bump there.

Speaker Change: You know, but better late than ever and that as we moved into January we continued to see the exports stay strong all of December and January and we started to get some cold weather maybe out of call. It a week and a half of cold weather.

Dave Canalongo: And we started to get some cold weather. We maybe had to call it a week and a half of cold weather, which resulted in some production losses as well, at the same time that demand was strong domestically and the export docks weren't affected. So I think that's what you see in that chart there is, you know, the December adjustment, as well as a couple of good weeks of data in January. And now we're just seeing things trend very much in line with the five-year average.

Speaker Change: It resulted in some production losses as well at the same time that demand was strong domestically and the export docks, where it affected so I think that's what you see in that chart. There is like you know the.

Speaker Change: The December adjustment as well as a couple of good good weeks of data in January and now we're just seeing things trending very much in line with the five year average.

Dave Canalongo: And so if that continues, we would expect to be, you know, call it down to the 45 to 48 million barrel range at the end of withdrawal season. So I think that, you know, moving from the top of the five-year range to the five-year average took the narrative from some of the bears out there that, you know, propane stocks were in dire circumstances. We didn't see that ourselves, but we were pleased to see it play out the way that it ultimately did. An international question.

Speaker Change: So if that continues we would expect to be you know call. It down to the 45 to 48 million barrel range at the end of withdrawal season. So I think that you know moving from the top of the five year range. The five year average they took the the narrative from some of the bears out there propane stocks were or in dire circumstances.

Speaker Change: We didn't we didn't see that ourselves and we used to see it play out the way that it ultimately did on the <unk>.

Speaker Change: International question.

Dave Canalongo: You know, we used to have a slide here that talked about propane going to China, where it showed absolute demand kind of moving steadily up to the right, but utilization moving lower, as they added big chunks of PDH capacity. And that's what we've seen happen. You know, PDH utilization rates are down in the 60 to 65% range. Petchem margins in the east are low, which isn't surprising given all the capacity that has come online. But overall, absolute demand has continued to move up.

Speaker Change: We used to have a slide in there that talked about.

Propane go into China, where it showed absolute demand kind of moving steadily up into the right, but utilization moving lower as they added big chunks of PTH capacity and that's what we've seen happen PTH utilization rates are down in the 60% to 65% range.

Speaker Change: Pet Chem margins in the east are low which isn't surprising given all the capacity that has come online, but overall absolute demand has continued to move up and so again, we remain optimistic that with that amount of capacity in place I'm ready to be ramped up should things improve economic.

Dave Canalongo: And so, again, we remain optimistic that with that amount of capacity in place, ready to be ramped up, should things improve economically, you know, in particular in China. They've not had things bounce back, you know, post-COVID reopening as many of us thought they would. We think there's a lot of upside there. You know, whether or not the U.S. will be able to supply it all instantaneously is a function of whether or not the Gulf Coast docks can expand in time. We think if that call for demand is here in 2024, they probably won't be able to get all of it from the U.S., but we'll certainly benefit being out of the east coast with our capacity. So those are the things we look at the most. You know, there is RETCOM demand growing globally. That's certainly stickier.

Speaker Change: You know in particular in <unk>.

Speaker Change: China, they've not had things bounce back post COVID-19 reopening is as many of US thought they would I would think theres a lot of upside there you know whether or not the U S will be able to supply at all instantaneously I think is a function of the Gulf coast Oxycodone can expand in time.

We think of that call for demand is here in 2024, they probably won't be able to get all of it from that from the U S. But we will certainly benefit being out of the east coast with our capacity. So that's.

Speaker Change: That's the thing as we look at the most there.

Speaker Change: There is rest com demand growing globally.

Speaker Change: That's certainly stickier.

Dave Canalongo: You know, harder to give you visibility on that; it's more, you know, over time looking at things coming out of individual countries, talking about initiatives or expansions of import terminals, but the big obvious things have been the Petco expansions, and those are real. They've resulted in higher demand despite the lower utilization rate just because they've turned on so much capacity. Yeah, that's really helpful. And then on the dry gas side, I realize you're more of a liquid story. So you might have the most objective view on this.

Speaker Change: Harder to give you visibility on that use more.

Speaker Change: You know over time looking at things coming out of individual country is talking about initiatives or expansions of import terminals, but the big obvious things that had been the pet Chem expansions and those are our real they resulted in higher demand despite.

Speaker Change: Despite the lower utilization rate, just because they've turned out so much capacity.

Speaker Change: That's really helpful and then on.

Speaker Change: The dry gas side, recognizing you're more of a liquid story. So you might have the most objective view on this but we've been really surprised at.

Justin Fowler: But we've been really surprised at US production. It's great showing it month to date close to 105 with two bees up in the Permian and two bees in Appalachia. What do you make of that? And do you believe this data and the extent that US production is surprising on the upside? What's driving it, and how does it resolve itself?

Speaker Change: U S production, great showing at month to date close to 105 with two b's up in the Permian in two piece in Appalachia.

What do you make of that and.

Speaker Change: Do you believe this data and to the extent that.

Speaker Change: Production has surprised to the upside what's driving that and how does it resolve itself.

Justin Fowler: Yeah, we weren't surprised. We had slides out there thinking that, you know, after the nine to 12 month kind of time period from when the rigs really started to drop last May, you'd start to see a response in production. That's historically kind of the timeframe that's required to work through that high rig count level. You haven't seen that yet. You actually saw the opposite.

Speaker Change: Yes, we havent surprised at slides out there thinking that you know after the nine to 12 month kind of time period from when the rigs really started the drop last may.

Speaker Change: To see a response in production Thats historically kind of the timeframe that's required to work through that high rig count level.

Speaker Change: Havent seen I actually saw the opposite so that has been surprising to us where we're hoping that that's kind of one last.

Justin Fowler: So that has been surprising us. We're hoping this is kind of the last one. Potion and Gas Production.

Speaker Change: Push in gas production you do historically see the rise in Appalachian gas during the winter months, because that's when there is demand and then it falls off kind of heading into the shoulder season. So hopefully that occurs and then you continue to see lower rig counts in the Permian and oil window. So hopefully that has some effect but.

Justin Fowler: You do historically see the rise in Appalachian gas during the winter months, but of Permian and Oil, https://www.youtube.com.uk/watch?v=LZwKZmL, I need to see some shot ends either from..., lower activity levels. Lower Gas Production from Lower Activity Levels or shut-ins during the... Time will tell whether that 105-piece, Yep, makes sense. Thanks again, team

Speaker Change: Now that's kind of the question you know that 105 Bcf market, it's not really 105 Bcf market, so you'll need to see some shut ins either from.

Speaker Change: Lower activity levels or not shut ins lower gas production from lower active wells are shut in during the shoulder season, the balance of the market. So time will tell whether that 105 Bcf oleds.

Speaker Change: Yeah makes sense. Thanks again.

David Adam Deckelbaum: Thank you. The next question is coming from David Deckelbaum from TD Cowen. Your line is now live.

Speaker Change: Mhm.

Speaker Change: Thank you. Your next question is coming from David <unk> from TD Cowen. Your line is now live.

David: Thanks, Paul and Mike for the time.

David Adam Deckelbaum: Thanks, Paul and Mike, for the time. I just wanted to touch on, hey, good to hear from you guys. I wanted to just bring up the NGL growth into 24. And obviously, you know, maybe there's some benefits on the FAA side.

David: I just wanted to touch on that because it's good to hear from you guys.

David: I wanted to just bring up the NGL growth and so.

24.

David: And obviously you know maybe there was some benefits on the ethane side. So wanted to get a little bit of color on just the breakdown you know.

Michael N. Kennedy: So I wanted to get a little bit of color on, Just a breakdown of, you know, what's driving that NGL growth, because obviously you're directing a little bit more activity to the NGL heavy corridor, but you still look like overall completing around 10% fewer lateral feet this year. So, is this a well performance situation, or is this really some of the incremental contribution from the ethane processing side? No, we're really just flat. I mean, when you kind of look at it, David, I think we're up 2%. That's just continued focus in the 1275. Corridors that continue to be more and more of our well-counted. You know, those types of, well...

What's driving that NGL growth, because obviously, you're directing a little bit more activity to the NGL heavy corridor.

David: But you're still looks like overall completing around 10% fewer ER lateral feet. This year. So is this a is this a well performance situation or is this really some of the incremental contribution from the ethane processing side.

Speaker Change: Oh, it's just we're really.

Speaker Change: Really just flat I mean, when you kind of look at it David I think we're up 2%.

Speaker Change: And that's just continued focus in the $12 75 to 1300 Btu corridor as that continues to be more and more of our well count as you know those type of wells.

Michael N. Kennedy: Your gas is declining. I mean, that's kind of the more interesting part of the story is where, Um, but growing Calculation. But you've kind of seen that our last year when we grew by 23, it was really MGL growth, we grew 14%.

Speaker Change: Gas declining I mean, that's kind of the more more of the story is we're allowing her that gas declined 3%.

Speaker Change: But growing liquids are a little bit and that maintenance capital calculation, but you've kind of seen that our last year. When we grew in 2003. It was really NGL growth, we grew 14% on the liquids.

Michael N. Kennedy: The Bulletproof Executive 2013, So. It's kind of just a natural outcome, really focus on liquid well, Natural Gas, the drier areas. I appreciate that. I guess if there was a scenario where you were to get back to three rigs and two completion crews at some point in the future, would that inherently lead to just a greater gas mix in the portfolio? Or should we be thinking about the mix that you're looking at in 2020?

Speaker Change: And gas is only up 2%. So it's kind of just a natural outcome of really focusing on the 1300 Btu.

Speaker Change: Type liquid wells and just letting the natural gas the dryer areas of our field decline.

Speaker Change: I appreciate that.

Speaker Change: I guess, if there was a scenario where you were to get back to three rigs and two completion crews at some point in the future.

Speaker Change: Would that inherently lead to just a greater guest mix in the portfolio or should we be thinking about the mix that you're looking at in twin not initially we got the liquids inventory. They had for 10 years. After 10 years, yes, it would be.

Michael N. Kennedy: Not initially, you know, we got the liquid inventory there for 10 years after 10 years. You know, it would be dry gas, but for the next 10 years, this is a good kind of mix where we're at. So, the three rigs, they would kind of have similar outcomes to last year where you grow the liquids and probably the double-digit range for the gas. And if I could just sneak one in, just be, the reduced lands budget this year, is that an intentional restraint, or is it just more limited opportunity after you guys, you know, were very successful there last year? Now, I mean, it's also a result of our completion efficiencies and kind of development of, you know, when you have fewer wells that you're drilling each year, that maintenance capital decreases, like I said, down to, The Bulletproof Executive 2013, So you do have a big land component where you try for the next two years to really build up those working interests, build up the NRI, really focusing on that. And so And then it's not the, you know, we are the consolidator of the liquids fairway in West Virginia. So, you know, it's very, very hard. Capture those locations other than us; we have. It's very contiguous and small.

Or I guess, but.

For the next 10 years. This is a good kind of mix where we're at.

Speaker Change: So.

Speaker Change: Three rigs to tie up similar outcomes to last year, where you grow the liquids and probably the double digit range, but the gas is flat.

I appreciate that and if I could just sneak one in just the reduced land budget. This year is that intentional restraint or is it just more limited opportunity. Yes, you guys were very successful there last year.

Speaker Change: No I mean, it's also a result of our completion efficiencies and kind of development of you know when you have less wells that youre drilling each year that maintenance capital decreases like we said it was down about $50 million this year and last year. What it was at 75 to 100. So you do have a big land component that where youre trying for the next few years.

Speaker Change: Time call it really built up those working interest buildup the NRI.

Speaker Change: Really focusing on that and so when you have less wells in that two year period, you have less land and then it's not.

Speaker Change: The consolidated liquids fairway in West Virginia.

Speaker Change: So it's very hard for anyone to come in.

Speaker Change: Capture those locations other than us we have the midstream like I said, we have a very contiguous smelling the mom or just gone right next door and leasing these locations. So we're the natural consolidator.

Michael N. Kennedy: We're just going right next door and leasing these locations, so we're the natural consolidator. So those opportunities aren't less, it's just we have fewer wells over the next two years, only running a few rigs.

Speaker Change: So those opportunities arent less it's just we have less wells over the next two years, when you're only running two rigs and one completion crew.

Kevin Moreland MacCurdy: Thanks, Mike. Thanks, Paul. Thank you. Next question is coming from Kevin MacCurdy from Pickering Energy Partners. Your line is now live. Hey, good morning and congratulations on the well-received 2024 guidance. I just have one question, and it's kind of a follow-up to the gas macro question that was asked earlier.

Speaker Change: Thanks, Mike Thanks, Paul.

Kevin Moreland MacCurdy: Thank you next question is coming from Kevin Mccarthy from Pickering Energy Partners. Your line is ally.

Kevin Mccarthy: Hey, good morning, and congratulations on the well received 2024 guidance.

Kevin Mccarthy: I just have one question and it's kind of a follow up to the gas macro question that was asked earlier.

Paul M. Rady: In your opinion, how do you think the gas markets will get solved? Do you have an opinion on where or who will be shutting down gas production or where the production declines will come from? Which should come from across all natural gas stations because, in today's strip, I don't think there are many natural gas plays that are economical. You have to have liquids like we have, www.globalonenessproject.org. So, I would say any basin that doesn't have liquids and also works.

Kevin Moreland MacCurdy: In your opinion, how do you think the gas markets get solved do you have an opinion on where or who will be shutting in gas production or world, where the production declines will come from.

Kevin Moreland MacCurdy: What should come from across all natural gas stations because at today's strip.

Kevin Moreland MacCurdy: I don't think Theres. Many natural gas plays that are economic yeah to have liquids like we have to make any sort of economics in today's gas price environment.

Kevin Moreland MacCurdy: I would say any basin that doesn't have liquids and also where there's substantial basis and theres no real takeaway.

Paul M. Rady: Subash Chandra. Takeaway. So, you know, that's pretty much all natural gas. You know, right now, probably should have.

Kevin Moreland MacCurdy: So that's pretty much all natural gas space and you know right now probably should have less activity. So I think that will naturally occur because economics at the end of the day always went out so I think that'll occur I think the liquids plays will continue to see activity, but if it's a dry natural gas play that's constrained.

Paul M. Rady: I think that will naturally occur because economics, at the end of the day, always wins out. I think the liquids plays will continue to see activity, but if it's a dry natural gas play, that's constrained and is most likely going to have lower activity, and plus, as we go in the shoulder season, whatever, you always see some economic. I'm dictating some shut-ins, so that 105 BCF, although in a spot day-to-day, seems like it's there. Over time, you'll see...

Kevin Moreland MacCurdy: It's most likely going to have lower activity and plus as we go into shoulder seasons, whatever you always see kind of economics that.

Kevin Moreland MacCurdy: Dictating some shut in so that 105 Bcf, although on a spot day to day. It seems like its there over time Youll see some.

Kevin Moreland MacCurdy: Occasionally she spends her.

Paul M. Rady: Occasional, Great, thank you for the detail. Sure. Thank you. We have reached the end of our question and answer session. I'd like to turn the floor back over to Brendan for any further closing comments. Thank you for joining us on today's call. Please reach out with any further questions. Thank you. Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.

Kevin Moreland MacCurdy: There are occasional events that will decrease that.

Speaker Change: Great. Thank you for the detail.

Speaker Change: Kevin. Thank you we reached end of our question and answer session I'd like to turn the floor back over to Brendan for any further closing comments.

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

Speaker Change: Thank you that does conclude today's teleconference and webcast you may disconnect. Your lines at this time and have a wonderful day, we thank you for your participation today.