Q2 2026 Antero Resources Corp Earnings Call

July 30, 2026

Speaker #1: Greetings and welcome to the ANTERO RESOURCES Corporation second quarter 2026 earnings call. At this time, I'll participants are in a listen-only mode. A question and answer session will follow the formal presentation.

Operator 3: Greetings and welcome to the Antero Resources Corporation Q2 2026 earnings call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce Dan Katzenberg, Vice President of Investor Relations. Thank you. You may begin.

Speaker #1: If anyone should require operator assistance, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce Dan Katzenberg, Vice President of Investor Relations.

Speaker #1: Thank you. You may begin.

Speaker #2: Thank you for joining us for ANTERO's second quarter 2026 investor conference call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A.

Dan Katzenberg: Thank you for joining us for Antero's Q2 2026 investor conference call. We will spend a few minutes going through the financial and operating highlights, and then we will open it up for Q&A. I would also like to direct you to the homepage of our website at anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to the earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike.

Daniel Katzenberg: Thank you for joining us for Antero's Q2 2026 investor conference call. We will spend a few minutes going through the financial and operating highlights, and then we will open it up for Q&A. I would also like to direct you to the homepage of our website at anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to the earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike.

Speaker #2: I would also like to direct you to the home page of our website at anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call.

Speaker #2: Today's call may contain certain non-GAAP financial measures. Please refer to the earnings press release for important disclosures regarding select measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing.

Speaker #2: I will now turn the call over to Mike.

Speaker #3: Thank you, Dan, and good morning, everyone. I'll start on slide number three, titled "Structural Margin Improvement at Antero." This structural improvement has strengthened our financial performance and, importantly, reduced earnings volatility.

Michael Kennedy: Thank you, Dan, and good morning, everyone. I will start on slide number three, titled Structural Margin Improvement at Antero. This structural improvement has strengthened our financial performance and importantly reduced earnings volatility. The results of this strategy can be seen in the table on the right side of the slide. While Henry Hub natural gas prices were down 16% from a year ago, the impact of increased scale, product diversity, and lower cash operating expense led to our adjusted EBITDAX increasing 57% over that period. These structural and sustainable improvements in our business will reduce volatility in our future cash flow. Staying on the topic of cost reductions, let us turn to slide number four, titled Significant Reduction in Cash Costs. The cost reductions we realized during the Q2 was just the beginning of lower costs to come at Antero.

Speaker #3: The results of this strategy can be seen in the table on the right side of the slide. While Henry Hub Natural Gas prices were down 16% from a year ago, the impact of increased scale, product diversity, and lower cash operating expense led to our adjusted EBITDA increasing 57% over that period.

Speaker #3: These structural and sustainable improvements in our business will reduce volatility in our future cash flow. Staying on the topic of cost reductions, let's turn to slide number four titled Significant Reduction in Cash Costs.

Speaker #3: The cost reductions we realized during the second quarter was just the beginning of lower cost at ANTERO. In June, we announced a cost reduction initiative that will significantly improve forecasting our cash cost to decline by over 25% from 2025 to year-end 2028 to $2 per MCFE.

Michael Kennedy: In June, we announced a cost reduction initiative that will significantly improve our margins. We are forecasting our cash costs to decline by over 25% from 2025 to year-end 2028 to $2 per Mcfe. This dramatic change in our cost structure will be achieved as our company evolves from being 100% liquids development and 100% out-of-basin product sales, to a much more balanced, rich and dry gas development program, as well as having sales in-basin and out-of-basin. This shift in strategy that increases our exposure to dry gas and in-basin sales is supported by the surge in new regional demand. This higher regional demand is expected to occur at the same time that many of our firm transportation commitments come up for renewal. To be clear, much of our LNG fairway directed firm transport is attractive and will be retained.

Speaker #3: This dramatic change in our cost structure will be achieved as our company evolves from being 100% liquids development and 100% out-of-basin product sales to a much more balanced, rich, and dry gas development program.

Speaker #3: As well as having sales in basin and out of basin. This shift in strategy that increases our exposure to dry gas and in basin sales is supported by the surge in new regional demand.

Speaker #3: This higher regional demand is expected to occur at the same time that many of our firm transportation commitments come up for renewal. To be clear, much of our LNG fairway-directed firm transport is attractive and will be retained.

Speaker #3: However, as we shift from the producer-push era to the demand-pull era, we are uniquely positioned to review each flow path and choose the highest-margin sales point and supply contract for our natural gas and NGLs.

Michael Kennedy: However, as we shift from the producer push era to demand pull era, we are uniquely positioned to review each flow path and choose the highest margin sales point and supply contract for our natural gas and NGLs. Next, on slide number five, we provide details on our margin enhancement. The $0.70 improvement in our cash costs will be partially offset by $0.35 and lower price realizations as we sell more product in basin. This assumes strip pricing for in-basin differentials without any tightening of basis that could occur when regional demand starts to ramp up. In the chart on the right-hand side of the slide, we break out the $300 million of annual margin improvements into three categories. First, we have two financial transactions that we entered into early this decade that come to an end. The overriding royalty interest transaction and the VPP.

Speaker #3: Next, on slide number five, we provide details on our margin enhancement. The 70% improvement in our cash costs will be partially offset by $0.35 in lower price realizations as we sell more product in-basin.

Speaker #3: This assumes strip pricing for in-basin differentials without any tightening of basis that could occur when regional demand starts to ramp up. In the chart on the right-hand side of the slide, we break out the $300 million of annual margin improvements into three categories.

Speaker #3: First, we have two financial transactions that we entered into early this decade that come to an end. The overriding royalty interest transaction and the VPP.

Speaker #3: The overriding royalty interest transaction return threshold to the counterparty was met in the second quarter, leading to the Martika Entity being dissolved on June 30th, resulting in an increase of 60 million dollars of annualized cash flow beginning in the third quarter of 2026.

Michael Kennedy: The overriding royalty interest transaction return threshold to the counterparty was met in Q2, leading to the Martica entity being dissolved on 30 June, and resulting in an increase of $60 million of annualized cash flow beginning in Q3 2026. The VPP will expire in July 2027 and result in a $30 million annualized cash flow uplift. Second, optimization of our liquids firm transport is forecast to improve margins by another $105 million. This includes limited needs for recontracting of SA transport, as well as the refinement of our LPG firm transport. The enhancements to our liquids margin structure are expected to be realized at the end of 2028. Third, the remaining $105 million of margin improvements through 2028 will primarily come through optimizing our natural gas firm transportation portfolio and increasing dry gas development.

Speaker #3: The VPP will expire in July of '27 and result in a 30 million dollar annualized cash flow uplift. Second, optimization of our liquids firm transport is forecast to improve margins by another 105 million dollars.

Speaker #3: This includes limited needs for re-contracting of ethane transport, as well as the refinement of our LPG firm transport. The enhancements to our liquids margin structure are expected to be realized at the end of 2028.

Speaker #3: And third, the remaining $105 million of margin improvements through 2028 will primarily come through optimizing our natural gas firm transportation portfolio and increasing dry gas development.

Speaker #3: The increased demand for natural gas is shifting the market from a producer push market to a demand pull market. This is expected to drive meaningful improvements in our overall natural gas netbacks.

Michael Kennedy: The increased demand for natural gas is shifting the market from a producer push market to a demand pull market. This is expected to drive meaningful improvements in our overall natural gas Netbacks. These are exciting times for Antero and the natural gas industry in Appalachia. We are encouraged by the power deals that have been publicly announced to date as they further validate the significant regional demand growth that we are expecting. We continue to be actively engaged in conversations with all of these projects. However, Antero approaches these negotiations from a uniquely advantaged position. We hold optionality as we already sell our volumes at premium prices along the LNG fairway and are the second largest NGL producer in the country, which provides margin uplift. This means that local power projects must compete with the broader energy markets on returns to attract our volumes.

Speaker #3: These are exciting times for ANTERO and the natural gas industry in Appalachia. We are encouraged by the power deals that have been publicly announced to date as they further validate the significant regional demand growth that we are expecting.

Speaker #3: We continue to be actively engaged in conversations with all of these projects. However, ANTERO approaches these negotiations from a uniquely advantaged position. We hold optionality as we already sell our volumes at premium prices along the LNG fairway and are the second largest NGL producer in the country.

Speaker #3: Which provides margin uplift. This means that local power projects must compete with the broader energy markets on returns to attract our volumes. This compares with many of our peers who lack the firm transportation portfolio or liquids production, and are looking for projects for nearly 100% of their production.

Michael Kennedy: This compares with many of our peers who lack the firm transportation portfolio or liquids production and are looking for projects for nearly 100% of their production. These attributes allow us to be highly selective in which projects we ultimately partner with. The projects that we elect to participate in will have to be accretive on a risk-adjusted basis, which includes pricing, timing, and certainty. Now to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments.

Speaker #3: These attributes allow us to be highly selective in which projects we ultimately partner with. The projects that we elect to participate in will have to be accretive on a risk-adjusted basis which includes pricing, timing, and certainty.

Speaker #3: 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, David Cannelongo, for his comments.

Speaker #4: Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing Antero achieved during the second quarter of this year. Antero's realized C3+ price was $44.26 per barrel, up $6.41 per barrel compared to the second quarter of last year, and our highest quarterly realized price since 2022.

David Cannelongo: Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing Antero achieved during Q2 of this year. Antero's realized C3+ price was $44.26 per barrel, up $6.41 per barrel compared to Q2 of last year and our highest quarterly realized price since 2022. Liquids prices continue to be influenced by geopolitical events as uncertainty remains over the flow of products through the Strait of Hormuz and other critical transit routes. US liquid supply has been called on by international buyers looking to replace Middle East cargoes. As shown on slide six, US propane exports averaged 2.03 million barrels a day during Q2 2026, an increase of 170,000 barrels a day compared to the same period last year.

Speaker #4: Liquids prices continue to be influenced by geopolitical events as uncertainty remains over the flow of products through the Strait of Hormuz and other critical transit routes.

Speaker #4: U.S. liquids supply has been called on by international buyers looking to replace Middle East cargoes. As shown on slide number six, U.S. propane exports averaged 2.03 million barrels per day during the second quarter of 2026, an increase of 170,000 barrels per day compared to the same period last year.

Speaker #4: Additionally, propane exports hit a new weekly high of 2.63 million barrels a day this May, with another weekly export number also above 2.6 million barrels a day reached in July, according to the EIA.

David Cannelongo: Propane exports hit a new weekly high of 2.63 million barrels a day this May, with another weekly export number also above 2.6 million barrels a day reached in July, according to the EIA. These new highs surpass the previous record by 300,000 barrels a day and demonstrate that the US can reach previously unseen export levels, driven in part by recently added terminal capacity. Exports of normal butane reached a new monthly record of 815,000 barrels a day in April, the most recent month of EIA data, surpassing the previous record of 661,000 barrels a day set in March. The record levels achieved for both LPG products since the start of Epic Fury illustrate that propane and butane are fiercely competing for terminal space to backfill lost Middle East supply across demand markets worldwide.

Speaker #4: These new highs surpassed the previous record by 300,000 barrels a day, and demonstrate that the US can reach previously unseen export levels driven in part by recently added terminal capacity.

Speaker #4: Additionally, exports of normal butane reached a new monthly record of 815,000 barrels a day in April, the most recent month of EIA data, surpassing the previous record of 661,000 barrels a day set in March.

Speaker #4: The record levels achieved for both LPG products since the start of Epic Fury illustrate that propane and butane are fiercely competing for terminal space to backfill lost Middle East supply across demand markets worldwide.

Speaker #4: Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels a day capacity, allowing exports to continue to grow over the coming years.

David Cannelongo: Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels a day capacity, allowing exports to continue to grow over the coming years. On the demand side, key global consumers such as China have been buying more LPG from the US as the Middle East supply remains curtailed and uncertain. China's LPG imports from the US declined last year following the initial imposition of the additional US tariffs, but have rebounded recently due to disruption in Middle East supplies. US LPG market share in China has risen from a low of 10% in June 2025 to an average of 51% during Q2 of this year, according to third-party shipping data, levels not seen since before Liberation Day. We are beginning to see a recovery in Chinese petrochemical demand for LPG.

Speaker #4: On the demand side, key global consumers such as China, have been buying more LPG from the US as the Middle East supply remains curtailed and uncertain.

Speaker #4: Chinese LPG imports from the US decline last year, following the initial imposition of the additional US tariffs, but have rebounded recently due to disruption in Middle East supplies.

Speaker #4: US LPG market share in China has risen from a low of 10% in June of 2025 to an average of 51% during the second quarter of this year, according to third-party shipping data, levels not seen since before liberation day.

Speaker #4: Additionally, we are beginning to see a recovery in Chinese petrochemical demand for LPG. As shown on slide number seven, titled "China PDH Demand on the Rise," China PDH demand has increased 40% from April to July.

David Cannelongo: As shown on slide seven, titled China PDH Demand on the Rise. China PDH demand has increased 40% from April to July. August demand is forecast to increase further, returning to all-time high levels not seen since before the disruptions in the Middle East. This higher demand should support more US imports into China in the near term. Let's turn to slide eight to discuss shipping dynamics. VLGC freight rates have been elevated since Epicury due to the global resupplying of ships after the closure of the Strait of Hormuz, creating some headwinds for US LPG exports. However, the order book for new VLGCs is robust and will provide relief to shipping costs in the coming quarters. We anticipate 84 vessels will be added to the fleet in H2 2026 and all of 2027.

Speaker #4: August demand is forecast to increase further, returning to all-time high levels not seen since before the disruptions in the Middle East. This higher demand should support more U.S. imports into China in the near term.

Speaker #4: Next, let's turn to slide number eight to discuss shipping dynamics. DLGC freight rates have been elevated since Epic Fury, due to the global reshuffling of ships after the closure of the Strait of Hormuz, creating some headwinds for US LPG exports.

Speaker #4: However, the order book for new BLGCs is robust and will provide relief to shipping costs in the coming quarters. We anticipate 84 vessels will be added to the fleet in the second half of 2026, and all of 2027.

Speaker #4: From now through 2029, the size of the fleet will increase by 31%, or 138 ships. Given the imminent export expansions and new-build terminals coming online, greater ship availability will facilitate more cargoes leaving the U.S. and continue to support Mont Belvieu prices.

David Cannelongo: From now through 2029, the size of the fleet will increase by 31% or 138 ships. Given the imminent export expansions and new build terminals coming online, greater ship availability will facilitate more cargoes leaving the US and continue to support Mont Belvieu prices. As the nation's second-largest NGL producer and the largest producer exporter, while also remaining unhedged on NGLs, Antero is poised to benefit from rising global demand for US energy and higher Mont Belvieu pricing. With that, I'll now turn it over to our Senior Vice President of Gas Marketing, Justin Fowler, for his comments.

Speaker #4: As the nation's second-largest NGL producer and the largest producer-exporter, while also remaining unhedged on NGLs, Antero is poised to benefit from rising global demand for U.S. energy and higher Mont Belvieu pricing.

Speaker #4: With that, I'll now turn it over to our senior vice president of gas marketing, Justin Fowler, for his comments.

Speaker #5: Thanks, Dave. I'll start on slide number nine that highlights the strong fundamental outlook for natural gas that we see through 2030. The two charts on this slide illustrate total US demand growth.

Justin Fowler: Thanks, Dave. I'll start on slide number nine that highlights the strong fundamental outlook for natural gas that we see through 2030. The two charts on this slide illustrate total US demand growth. Based on data center and power projects that have been announced to date, natural gas demand is forecasted to increase 19 Bcf. LNG and Mexico export growth adds another 23 Bcf per day of natural gas demand growth by 2030. In combination, this represents 37% of total demand growth for natural gas by the end of the decade. While associated gas from the Permian will fill a portion of this demand growth through announced egress expansions, higher prices will be required to incentivize growth from non-traditional gas basins and tier 2 acreage with higher breakevens to ultimately meet this demand. Now let's look at regional demand in our Appalachian Basin, which is highlighted on slide number 10.

Speaker #5: Based on data center and power projects that have been announced today, natural gas demand is forecasted to increase 19 BCF, LNG in Mexico export growth adds another 23 BCF per day of natural gas demand growth by 2030.

Speaker #5: In combination, this represents 37% of total demand growth for natural gas by the end of the decade. While associated gas from the Permian will fill a portion of this demand growth through announced egress expansions, higher prices will be required to incentivize growth from non-traditional gas basins and Tier 2 acreage with higher break-evens to ultimately meet this demand.

Speaker #5: Now, let's look at regional demand and our Appalachian Basin, which is highlighted on slide number 10. The power projects highlighted on this slide represent the projects that have been publicly announced in our region to date and amount to over 9 Bcf per day of demand.

Justin Fowler: The power projects highlighted on this slide represent the projects that have been publicly announced in our region to date and amount to over 9 Bcf per day of demand. This does not include additional projects that we have spoken to that add an additional incremental 3 Bcf of demand to our regional profile. We've shown this slide in the past, and each time, the number of projects and implied regional demand estimate has increased. What is exciting to us today is that we now have 6 Bcf of projects that are either FID or under construction. This increases our visibility into which projects will come to fruition and allows us to prioritize our conversations. Next, let's turn to slide number 11, titled Gas Demand Competition. As Mike detailed earlier, Antero is in an advantaged position through our long-haul firm transportation capacity.

Speaker #5: This does not include additional projects that we have spoken to that add an additional incremental 3 Bcf of demand to our regional profile. We've shown this slide in the past, and each time, the number of projects and implied regional demand estimate has increased.

Speaker #5: But what is exciting to us today is that we now have 6 BCF of projects that are either FID or under construction. This increases our visibility into which projects will come to fruition and allows us to prioritize our conversations.

Speaker #5: Next, let's turn to slide number 11 titled "Gas Demand Competition." As Mike detailed earlier, ANTERO is an advantaged position through our long-haul firm transportation capacity.

Speaker #5: This firm transports significantly widens the footprint of demand pull projects that we can select to participate in. Our firm transport portfolio opens up opportunities into the Midwest and further south, where in total another 7 BCF per day of power projects are being forecasted.

Justin Fowler: This firm transport significantly widens the footprint of demand pull projects that we can select to participate in. Our firm transport portfolio opens up opportunities into the Midwest and further south, where in total, another 7 Bcf per day of power projects are being forecasted. This optionality is unique to Antero and allows us to be highly selective with our project partners around the best opportunities on a risk-adjusted basis. With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Speaker #5: This optionality is unique to ANTERO and allows us to be highly selective with our project partners around the best opportunities on a risk-adjusted basis.

Speaker #5: With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Speaker #2: Thanks, Justin. I will start on slide 12, which highlights our second quarter operational and financial results. Our quarterly production was a company record, an average above our guidance range coming in at over 4.1 BCFE a day.

David Cannelongo: Thanks, Justin. I will start on slide 12, which highlights our Q2 operational and financial results. Our quarterly production was a company record and averaged above our guidance range, coming in at over 4.1 Bcfe a day. This represents an increase of 21% year over year. In late 2025, we spot our first dry gas pad in over 12 years, and today we announced the results of that pad. This pad delivered a more than 67% improvement in EUR and a nearly 30% decrease in cost per foot.

Brendan Krueger: Thanks, Justin. I will start on slide 12, which highlights our Q2 operational and financial results. Our quarterly production was a company record and averaged above our guidance range, coming in at over 4.1 Bcfe a day. This represents an increase of 21% year over year. In late 2025, we spot our first dry gas pad in over 12 years, and today we announced the results of that pad. This pad delivered a more than 67% improvement in EUR and a nearly 30% decrease in cost per foot.

Speaker #2: This represents an increase of 21% year over year. In late 2025, we split our first dry gas pad in over 12 years, and today we announced the results of that pad.

Speaker #2: This pad delivered a more than 67% improvement in EUR and a nearly 30% decrease in cost per foot. We also announced 315 million of acquisitions in our core West Virginia Marcellus footprint.

Brendan Krueger: We also announced $315 million of acquisitions in our core West Virginia Marcellus footprint. In total, these transactions increase our net production by approximately 125 million cubic feet a day equivalent and add 15 net drilling locations. I'll discuss both of these updates in more detail momentarily. Turning to our financial results on the right-hand side of the slide, our adjusted EBITDAX increased 57% year over year, resulting in $220 million of free cash flow. We used a portion of this free cash flow to accelerate our share repurchase program, repurchasing 1.1 million shares for $38 million. Lastly, our total cash operating costs were at the low end of the guidance range, declining $0.29 per Mcfe or 11% from the year ago period. This first step in realizing lower costs is attributed to the Q2 being our first full quarter incorporating the HG Energy acquisition.

Speaker #2: In total, these transactions increase our net production by approximately 125 million cubic feet a day equivalent and add 15 net drilling locations. I'll discuss both of these updates in more detail momentarily.

Speaker #2: Turning to our financial results, on the right-hand side of the slide, our adjusted EBITDAX increased 57% year over year, resulting in 220 million of free cash flow, we used a portion of this free cash flow to accelerate our share repurchase program, repurchasing 1.1 million shares for 38 million.

Speaker #2: Lastly, our total cash operating costs were at the low end of the guidance range, declining 29 cents per MCFE or 11% from the year ago period.

Speaker #2: This first step in realizing lower costs is attributed to the second quarter being our first full quarter incorporating the HG Energy acquisition. Next, let's turn to slide 13, titled "Strong Performance and Return to Dry Gas Drilling." This slide compares our well design and production performance from when we last drilled on our dry gas acreage over 12 years ago.

Brendan Krueger: Next, let us turn to slide 13, titled Strong Performance and Return to Dry Gas Drilling. This slide compares our well design and production performance from when we last drilled on our dry gas acreage over 12 years ago to the pad we turned to sales this year using modern drilling and completion methodologies. Our lateral lengths nearly doubled, and we increased our sand use from 800 pounds per foot to 2,000 pounds per foot. Despite these increases, our cost per foot declined 28% to just $900 per foot. Most impressively, our EUR increased 67%, from 1.2 Bcf per thousand to over 2 Bcf per thousand. On the right, you can see the 90-day cumulative production rates, which increased more than 3x. All of these results exceeded our internal expectations.

Speaker #2: So the pad we turned to sales this year using modern drilling and completion methodologies. Our lateral links nearly doubled and we increased our sand use from 800 pounds per foot to 2,000 pounds per foot.

Speaker #2: Despite these increases, our cost per foot declined 28% to just $900 per foot. Most impressively, our EUR increased 67% from 1.2 Bcf per 1,000 to over 2 Bcf per 1,000.

Speaker #2: On the right, you can see the 90-day cumulative production rates, which increased by more than 3x. All of these results exceeded our internal expectations. With over 1,000 dry gas locations, we view this acreage footprint as the largest undrilled Tier 1 dry gas position left in the U.S.

Brendan Krueger: With over 1,000 dry gas locations, we view this acreage footprint as the largest undrilled Tier 1 dry gas position left in the US. Next, slide 14 looks more closely at the acquisitions we closed in July. We invested $315 million on assets in our core West Virginia Marcellus footprint. These transactions immediately add 125 million a day of net production and were acquired at a combined valuation of just 4x EBITDAX and a free cash flow yield over 20%. The chart on the right illustrates how we've been able to increase our net production, which has increased from 3.3 Bcfe a day at the beginning of 2025 to an expected 2026 exit rate of four and a half Bcfe a day, or 36% growth over that time period.

Speaker #2: Next, slide 14 looks more closely at the acquisitions we closed in July. We invested $315 million on assets in our core West Virginia Marcellus footprint.

Speaker #2: These transactions immediately add 125 million a day of net production and were acquired at a combined valuation of just 4 times EBITDAX, with a free cash flow yield over 20%.

Speaker #2: The chart on the right illustrates how we've been able to increase our net production, which has grown from 3.3 BCFE per day at the beginning of 2025 to an expected 2026 exit rate of 4.5 BCFE per day.

Speaker #2: Or 36% growth over that time period. Notably, we have been able to accomplish this net production growth without impacting the basin's gross production, which you can see has remained essentially flat at 35.5 Bcf a day over that time period.

Brendan Krueger: Notably, we have been able to accomplish this net production growth without impacting the basin's gross production, which you can see has remained essentially flat at 35.5 Bcf a day over that time period. To emphasize a point that we've made in recent discussions, Antero is in its best position in company history. Through accretive transactions and organic growth, our production has increased by a third. We have already achieved nearly half of our targeted 25% reduction in operating costs, and the NGL outlook is significantly strengthened relative to the beginning of 2026. Our share count is down, and our total debt will be back to pre-HG Energy acquisition levels in the coming quarters. With that, I will now turn the call over to the operator for questions.

Speaker #2: To emphasize a point that we've made in recent discussions, ANTERO is in its best position in company history. Through a creative transactions and organic growth, our production has increased by a third.

Speaker #2: We have already achieved nearly half of our targeted 25% reduction in operating costs, and the NGL outlook is significantly strengthened relative to the beginning of 2026.

Speaker #2: Further, our share count is down, and our total debt will be back to pre-HG Energy acquisition levels in the coming quarters. With that, I will now turn the call to questions.

Speaker #3: Thank you. At this time, we will conduct our question and answer session. If you would like to ask a question, please press star one on your telephone keypad.

Operator 3: Thank you. At this time, we will conduct our question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, to ask a question, press star one. We'll pause for a moment while we pull for questions. Our first question comes from Kevin McCurdy with Pickering Energy Partners. Please state your question.

Speaker #3: A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue.

Speaker #3: For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, to ask a question, press star 1.

Speaker #3: We'll pause for a moment while we poll for questions. And our first question comes from Kevin McCurdy with Pickering Energy Partners. Please state your question.

Speaker #4: Hey, good morning, and thanks for taking my question. There's been some activity in your neck of the woods in recent power deals and talk of data centers.

Kevin McCurdy: Hey, good morning, thanks for taking my question. There's been some activity in your neck of the woods in recent power deals and talk of data centers. Obviously, you are in the dominant position or the dominant producer in West Virginia, and you touched a little bit on this on your prepared remarks, but maybe you can expand a little bit on how you view your gas marketing portfolio in total and what would make you get more aggressive with long-term sales agreements.

Speaker #4: Obviously, when you were in the dominant position or the dominant producer in West Virginia and you touched a little bit on this on your prepared remarks, but maybe you can expand a little bit on how you view your gas marketing portfolio in total, and what would make you get more aggressive with long-term sales agreements?

Speaker #2: Yeah, I think we touched on in remarks. I mean, right now, we kind of think about how 10 to 15 years back, we signed up for all the firm transport arrangements just to get our gas out.

Brendan Krueger: Yeah, I think we touched on the remarks. Right now, we think about how 10 to 15 years back, we signed up for all the firm transport arrangements just to get our gas out. Now we're at the end of that, we can select the best paths, and those paths are competing with the power deals and comparing them. It has to compete with the broader energy markets. The one that was recently in our backyard, we've been in discussions with them for almost a decade. We're well aware of that one. They actually have a contract on some of our midstream. In discussions with them, just the uncertainty around the pricing, the timing, the execution, all of that really didn't meet our return hurdles.

Speaker #2: Now we're at the end of that, and so we can select the best paths. And those paths are competing with the power deals, and comparing them, so it has to compete with the broader energy markets.

Speaker #2: The one that was recently in our backyard—I mean, we've been in discussions with them for almost a decade. So we're well aware of that one.

Speaker #2: They actually have a contract on some of our midstream, so in discussions with them, just the uncertainty around the pricing, the timing, the execution—all of that really didn't meet our return hurdles.

Speaker #2: So, when we look at projects, it has to meet all of those three, and that one just wasn't attractive to us.

Brendan Krueger: When we look at projects, it has to meet all of those three, and that one just wasn't attractive to us.

Speaker #4: Okay, I appreciate the details there. And it's my follow-up. You were able to do some buybacks this quarter despite continuing to execute on the bolt-ons.

Kevin McCurdy: Okay. I appreciate the details there. As my follow-up, you were able to do some buybacks this quarter despite continuing to execute on the bolt-ons. We see a lot of free cash flow potential from Antero in the coming years. With the stock in the mid-30s, are you ranking buybacks a little bit higher among your options for your cash flow?

Speaker #4: We see a lot of free cash flow potential from Antero in the coming years. With the stock in the mid-$30s, are you ranking buybacks a little bit higher among your options for your cash flow?

Speaker #2: Yeah, definitely. You saw that in the quarter. We weren't planning on buying back shares in the quarter, but where the equity price went, obviously, that was very attractive to us.

Brendan Krueger: Yeah, definitely. You saw that in the quarter. We weren't planning on buying back shares in the quarter, where the equity price went, obviously, that was very attractive to us. I think you heard in Brendan's summary comments, production up 20%, cash cost down 10%, liquids pricing up significantly.

Speaker #2: I think you heard in Brendan's summary comments, production up 20%, cash cost down 10%, liquids pricing up significantly. EBIT up 57%. Then you look at the share price and it's the same as last year.

Michael Kennedy: EBIT up 57%, you look at the share price, and it's the same as last year. I would say that you could elevate the ranking of that, and that it's very attractive to us at these levels.

Speaker #2: So I would say that you could elevate the ranking of that and that is very attractive to us at these levels.

Speaker #4: Appreciate it. Thanks.

Kevin McCurdy: Appreciate it. Thanks.

Speaker #3: Your next question comes from Dave Dowd, with Truist, please state your question.

Operator 3: Your next question comes from Gabe Daoud with Truist. Please state your question.

Speaker #5: Hey, thanks, guys. It's Gabe from Truist. I was hoping we can maybe just touch on the growth capex and how we should be thinking about that impacting 2026.

Gabe Daoud: Hey, thanks, guys. It's Gabe from Truist. I was hoping we could maybe just touch on the growth CapEx and how we should be thinking about that impacting 2026. Looks like you're at four rigs currently, maybe already putting some of that growth capital to work. Could we maybe just get an update there?

Speaker #5: Looks like you're at four rigs currently, maybe already putting some of that growth capital to work. Could we maybe just get an update there?

Speaker #2: Yeah. So it's four ones in transition. So it'll be down to three here in the next month. But we are drilling those three paths that we talked about that are kind of on the difference between maintenance and growth capital.

Michael Kennedy: Yeah. It's four. One's in transition, it'll be down to three here in the next month. We are drilling those three pads that we talked about that are kind of on the difference between maintenance and growth capital. You will have some capital. Our maintenance cases, to remind everyone, was a billion. Our growth is $1.2 billion of capital this year. Right now, we're probably somewhere a bit north of a billion, not to the $1.2 billion. A lot of that will be completion capital in Q4, that's yet to be determined whether we deploy that. We've said in the past, even $3 plus gas, that's probably something that we would deploy. We'll just have to determine that when we get there.

Speaker #2: So you also have some capital. So our maintenance case just remind everyone who's a billion, our growth is 1.2 billion of capital this year.

Speaker #2: Right now, we're probably somewhere a bit north of $1 billion, but not to the $1.2. A lot of that will be completion capital in the fourth quarter, and that's still yet to be determined whether we deploy that.

Speaker #2: We said in the past, even $3-plus gas, that's probably something that we would deploy. But we'll just have to determine that when we get there.

Speaker #5: Okay. And so if you complete those wells, I mean, that takes 27, I would imagine, to four or six. Yeah. Yeah. Okay. Okay. Thanks, Mike.

Gabe Daoud: Okay. If you complete those wells, that takes 2027, would imagine four, six?

Michael Kennedy: Yeah.

Gabe Daoud: Yeah.

Michael Kennedy: Yeah.

Gabe Daoud: Okay. Thanks, Mike. Maybe just a follow-up. Curious on the cost optimization plan, the $0.35 reduction in realization is obviously being offset by the big move lower on the cost side. Just how dynamic is that plan? Just curious, how much flexibility will you have as we progress through 2027 and maybe in-basin pricing not really materializing to what you would expect? Would you just still keep some of that FT, or is that just simply recontracting into lower market rates?

Speaker #5: And then maybe just a follow-up. Curious on the cost optimization plan, the 35 cent reduction in realizations obviously being offset by the big move lower on the cost side.

Speaker #5: Just how dynamic is that plan? I'm just curious, how much flexibility will you have if we progress through '27 and maybe in-basin pricing is not really materializing to what you would expect for that FT, or is that just simply recontracting into lower market rates?

Speaker #2: Yeah, sorry. Some of that's in basin pricing around the dry gas, but the majority of it is just the optimization of our firm transport.

Michael Kennedy: Yeah, sorry. Some of that's in-basin pricing around the dry gas, but the majority of it is just the optimization of our firm transport. I was trying to hit in the comments, it's definitely coming from the end users. It's a demand pull. When we came out with this cost presentation and strategy a couple of months back, we received so many reverse inquiries along our firm transport paths. Justin hit on that slide too. All of that 7 Bcf of demand that's along those FT paths. You can assume a lot of those are reaching out to us to try to optimize that transport, put it in their hands, not ours, but also get us a premium. None of that's baked into this $300 million that we've been talking about. That would be incremental.

Speaker #2: I was trying to hit in the comments. It's definitely coming from the end users. It's a demand pull. And so when we came out with this cost presentation, and strategy a couple of months back, we received so many reverse inquiries.

Speaker #2: Along our firm transport paths and Justin hit on that slide too, all of that 7BCF of demand, that's along those FT paths. You can assume a lot of those are reaching out to us to try to optimize that transport, put it in their hands, not ours, but also get us a premium that's baked into this 300 million.

Speaker #2: That we've been talking about, that'd be incremental. But that's something we're looking at. And you kind of saw the first sign of that with our guidance—how we reduced our cash costs and also reduced the realized price. But we're hopeful that we'll actually do better than that, just getting premiums along that path instead of just having the end user hold that transport.

Michael Kennedy: That's something we're looking at, and you kind of saw the first sign of that with our guidance, how we reduced our cash costs. Also reduced the realized price. We're hopeful that we will actually do better than that. Just getting premiums along that path instead of just having the end user hold that transport.

Speaker #5: Got it. Got it. Okay, that makes sense. Thanks, guys.

Gabe Daoud: Got it. Okay. That makes sense. Thanks, guys.

Speaker #3: Your next question comes from John Freeman with Raymond James. Please state your question.

Operator 3: Your next question comes from John Freeman with Raymond James. Please state your question.

Speaker #6: Thanks. Good morning, guys. Just following up on the $300 million kind of margin enhancement that y'all first unveiled in that presentation last month. Just to clarify if that was extended kind of a few years, kind of beyond that 2028 target.

John Freeman: Thanks. Good morning, guys. Just following up on the $300 million kind of margin enhancement that y'all first unveiled in that presentation last month. Just to clarify, if that was extended kind of a few years kind of beyond that 2028 target, is it safe to say that that $300 million number would move materially higher if you just extended the timeline?

Speaker #6: Is it safe to say that that 300 million dollar number would move materially higher if you just extended the timeline?

Speaker #2: Absolutely. We just focused on three years. We thought that was kind of the investment horizon. If you're looking past that to the five years, I think it grows to about 6 to 7 hundred million dollars.

Michael Kennedy: Absolutely. We just focused on three years. We thought that was kind of the investment horizon. If you're looking past that to the five years, I think it grows to about $600 to 700 million.

Speaker #6: That's great. And then just follow up, Mike, as you sort of see this play out with the data center, the power projects as they come online over the next several years and you sort of start to move or have the opportunity to sell more gas in basin, just like rough numbers, how do you see that mix sort of changing versus if we call it kind of two-thirds kind of out of basin at the moment?

John Freeman: That's great. Just follow up, Mike, as you sort of see this play out with the data center, the power projects as they come online over the next several years, and you sort of start to move or have the opportunity to sell more gas in basin. Just like rough numbers, how do you see that mix sort of changing versus if we call it kind of two-thirds kind of out of basin at the moment? Just how do you see that evolving over the next several years?

Speaker #6: How do you see that evolving over the next several years?

Speaker #2: Yeah, right now we're kind of thinking a third was FT long haul, a third's liquids, and a third is generally local sales. So if you just put that in natural gas terms, it's about 50/50.

Michael Kennedy: Yeah, right now we're kind of thinking a third was FT long haul, a third's liquids, and a third is generally local sales. If you just put that in natural gas terms, it's about 50/50. The word we like to use, you're going to hear a lot, you hear the balance. We want to be balanced. We want to be a balanced natural gas liquids producer. We also want to be a balanced seller of the natural gas, about half on the long-haul transport and half local.

Speaker #2: The word we like to use—you’re going to hear a lot of it—you hear, is 'balance.' We want to be balanced. We want to be a balanced natural gas liquids producer, and we also want to be a balanced seller of the natural gas—about half on the long-haul transport and half local.

Speaker #6: That's great. Appreciate it.

John Freeman: That's great. Appreciate it.

Speaker #3: Your next question comes from Arun Jayaram with J.P. Morgan. Please state your question.

Operator 3: Your next question comes from Arun Jayaram with J.P. Morgan. Please state your question.

Speaker #5: Yeah, good morning. Team, Mike, I was wondering if you could talk us through the timing of further reaching your cost reduction target of $0.70 per Mcfe.

Arun Jayaram: Yeah, good morning, team. Mike, I was wondering if you could talk us through the timing of further reaching your cost reduction target of $0.70 per Mcfe. It sounds like you're halfway or nearly halfway there through the integration of HG, give us a sense of how that will play out over the next couple of years. Again, I'm asking this question largely trying to think about where your cash operating costs could be in calendar 2027 as you move towards that $2 end of year 2028 target.

Speaker #5: It sounds like you're halfway or nearly halfway there. So the integration of HG, but give us a sense of how that will play out over the next couple of years and again, I'm asking this question largely trying to think about where your cash operating costs could be in calendar 2027 as you move towards that $2 end-of-year 28 target.

Speaker #2: Yeah, we put in the three buckets. We put some timing around that, that first one we talked about the override. That starts immediately. That started in July.

Michael Kennedy: Yeah. We put in the three buckets. We put some timing around that. That first one we talked about the override. That starts immediately. That started in July. That's a $0.04 uplift. Our 4% improvement on a cost structure, that's $60 million. We have the VPP in July of 2027. That's an incremental $30 million. Throughout that time, you're going to see this optimization of our natural gas firm transport. It's harder to predict the exact timing of that, we're in significant negotiations around those type of improvements, think about that's more ratable. The $105 million that we're talking on liquids, that's year-end 2028.

Speaker #2: That's a 4 cent. Uplift, or 4 cent improvement on the cost structure. That's $60 million and we have the VPP in July of '27.

Speaker #2: That's an incremental 30 million. Throughout that time, you're going to see this optimization of our natural gas firm transport. It's harder to predict the exact timing of that, but we're in a significant negotiations around those type of improvements.

Speaker #2: So think about that as more rateable. And then the $105 million that we're talking to liquids, that's year-end '28.

Speaker #5: Got it. Got it. Great. And my follow-up, Mike, clearly one of the themes from today's earnings is your commentary that the business for large-scale natural gas liquids producers will be more driven by kind of demand pull.

Arun Jayaram: Got it. Great. My follow-up, Mike, clearly one of the themes from today's earnings is your commentary that the business for large-scale natural gas liquids producers will be more driven by demand pull versus just being a traditional E&P price taker. I was wondering if you could comment on how you think Antero's positioned for this kind of, call it, shift in market dynamics.

Speaker #5: Versus just being a traditional E&P price taker, I was wondering if you could comment on how you think Antero is positioned for this, call it, shift in market dynamics.

Speaker #2: Yeah, we're extremely well positioned. Go back 15 years and we were trying to create markets or as no local gas markets. So we had to sign up for all the firm transport that came our way.

Michael Kennedy: Yeah, we're extremely well-positioned. Go back 15 years. We were trying to create markets. There was no local gas market. We had to sign up for all the firm transport that came our way. Those are expiring now. Now we get to pick the best ones. Some of it ended up in terrific markets. Some of it didn't end up as well as we had hoped. We'll be able to compare those now to the local demand. It's perfect timing for us. That's why in the comments, those opportunities are going to have to compete with the broader energy markets because those LNG buyers are really in the international. There's an arb there. Our strategy has been to remain on the spot there. We haven't entered any firm agreements with that price. Local's going to have to compete with that.

Speaker #2: Those are expiring now. So now we get to pick the best ones. Some of it ended up in traffic markets. Some of it didn't end up as well as we had hoped.

Speaker #2: So we'll be able to compare those now to the local demand, so it's perfect timing for us. And that's why, in the comments, those opportunities are going to have energy markets, because those LNG buyers are really in the kind of international.

Speaker #2: There's an ARP there, and our strategy has been to remain on the spot there, so we haven't entered any firm agreements at that price.

Speaker #2: And then local is going to have to compete with that. That's why we're highly selective. You're going to see a bunch of announcements along the way that we're not participating in, and you can be assured that's because our opportunity set is greater than what those opportunities were.

Michael Kennedy: That's why we're highly selective. You're going to see a bunch of announcements that along the way, we're not participating in, and you can be assured that's because our opportunity set's greater than what those opportunities were. Highly selective. It's got to be more near term, it's got to be price certain, and it's got to compete with our firm transport and liquids production.

Speaker #2: So, highly selective. It's got to be more near-term, it's got to be price certain, and it's got to compete with our firm transport and liquids production.

Speaker #5: That's clear. Thanks a lot, Mike.

Arun Jayaram: That's clear. Thanks a lot, Mike.

Speaker #3: Your next question comes from Doug Legate with Wolf Research. Please state your question.

Operator 3: Your next question comes from Doug Leggate with Wolfe Research. Please state your question.

Speaker #7: Thanks, guys. I appreciate you having me on. So Brendan, this is maybe for you, but in your deck, you're walking through pretty clearly the reduction or the planned reduction in cash costs.

Doug Leggate: Thanks, guys. I appreciate you having me on. Brendan, this is maybe for you, but in your deck, you're walking through pretty clearly the reduction or the planned reduction in cash costs. I think it's been beaten pretty well this morning. My question is Hold on one second. Why are you offsetting that with price realizations? I'm trying to understand what this implies for your market view of gas going forward.

Speaker #7: I think it's been covered pretty well this morning. My question is, why are you—sorry, one second. Why are you offsetting that with price realizations?

Speaker #7: I'm trying to understand what this implies for your market view of gas going forward.

Speaker #2: Yeah, I'm sorry. I didn't hear that last part, Doug. Could you repeat that?

Brendan Krueger: Yeah, sorry, I didn't hear that last part, Doug. Could you repeat that?

Doug Leggate: Yeah, sorry. Something dialing in my system. Why are you offsetting it with price realizations? I'm trying to understand what that signals for your view on the macro.

Speaker #7: Yeah, sorry. Someone's dialing in my system. Why are you offsetting it with price realizations? I'm trying to understand what that signals for your view on the macro.

Speaker #2: Yeah, it just goes back to some of that same conversation Mike was having, that the world is shifting from this producer push to demand pull.

Brendan Krueger: Yeah, it just goes back to some of that same conversation Mike was having, that the world is shifting from this producer push to demand pull. Sometimes what that means is they're willing to take your product in basin. You'll of course have a lower realized price if they're buying in basin. From a margin standpoint, you're picking up $0.35 a margin. They're taking on the transport to move it, but they're giving you a premium on the price versus what you otherwise would have sold if you were just selling in basin. Cost coming down $0.70, offset by realizations coming down by about half. Your margins still are getting picked up by $0.35 overall. We're quite enthused by what we're seeing on the demand pull, like Mike mentioned.

Speaker #2: Sometimes what that means is they're willing to take your product in basin you'll, of course, have a lower realized price if they're buying in basin, but from a margin standpoint, you're picking up 35 cents of margin.

Speaker #2: So they're taking on the transport to move it, but they're giving you a premium on the price versus what you otherwise would have sold if you were just selling in basin.

Speaker #2: So costs coming down 70 cents offset by realizations coming down by about half. So your margins still are getting picked up by 35 cents overall.

Speaker #2: So we're quite enthused by what we're seeing on the demand pull. Like Mike mentioned, this market where it used to be we have to find a place for your gas.

Brendan Krueger: This market where it used to be you have to find a place for your gas, it's now become, Okay, can you deliver us 300 million a day in this area? Can you deliver us 200 million a day in this area that we need by this period of time? We have to weigh that against our firm transport. What is the cost to get you there? You have to take on that cost, or you can pick this back up in basin and you can take on that cost. All of these factor into our decisions, but they all should lead to margin improvement on our natural gas in a big, big way.

Speaker #2: It's now become hey, can you deliver us 300 million a day in this area? Can you deliver us 200 million a day in this area that we need by this period of time?

Speaker #2: And we have to weigh that against our firm transport. What is the cost to get you there? You have to take on that cost or you can pick this back up in basin and you can take on that cost.

Speaker #2: But all of these factors into our decisions, and they all should lead to margin improvement on our natural gas in a big, big way.

Doug Leggate: I appreciate that color. Thanks. My follow-up is a quick one, hopefully. Obviously, you've drilled your first dry gas pads in quite a while. You haven't completed them, obviously, but whether we end up with a squishy winter or not, what's the kind of roadmap to whether you would go back to growth in 2027?

Speaker #7: I appreciate that color. Thanks. My follow-up is a quick one, hopefully. So, obviously, you've drilled your first dry gas pads in quite a while.

Speaker #7: You haven't completed them, obviously, but whether we end up with a squishy winter or not, what's the kind of roadmap to whether you would go back to growth in 2027?

Speaker #2: Go back. Oh, we have two pads in there. Well, we put our first one in the planning and pad that Brendan reviewed the results.

Michael Kennedy: Go back. We have two pads in there. Well, we put our first one, the Flanigan Well Pad that Brendan reviewed the results. The next two are Katie and Walters right next to it. They'll be drilling. Whether we complete them, like you mentioned, will be natural gas price dependent. I fully anticipate completing them if it's $3 gas plus. We can hedge that and also hedge local basis at very attractive levels. Right now, based on those markets that we're looking at, you would assume that those would be completed, but if you have a significant down or price movement on the 2027 gas, we won't complete them in the Q4.

Speaker #2: The next two are Canadian Walters, right next to it. They’ll be drilling, whether we complete them, like you mentioned. We’ll be natural gas price dependent.

Speaker #2: But I fully anticipate completing them if it's $3 gas, plus we can hedge that and also hedge kind of local basis at very attractive levels.

Speaker #2: So right now, based on those markets that we're looking at, you would assume that those would be completed. But if you have a significant down or price movement on the '27 gas, then we won't complete them in the fourth quarter.

Doug Leggate: That's really helpful. Thanks a lot.

Speaker #7: That's really helpful. Thanks a lot.

Speaker #3: Your next question comes from Betty Jang with Barclays. Please state your question.

Operator 3: Your next question comes from Betty Jiang with Barclays. Please state your question.

Speaker #8: Good morning. I want to start with a follow-up to Arun's question about costs. This GP&T piece—there are many drivers lowering that GP&T over time.

Betty Jiang: Good morning. I want to start with a follow-up to Arun's question about cost. This GP&T piece is, there's many drivers lowering that GP&T over time. Could you just unpack how much of the reduction is coming from a shift towards the HG dry gas assets, like whether that's the wells are getting better and just shifting to HG, and how much of it is growth, further dry gas growth above and beyond the base level?

Speaker #8: Could you just unpack how much of the reduction is coming from a shift towards the HG dry gas assets? Whether that's the wells are getting better and just shifting to HG and how much of it is growth further dry gas growth above and beyond the base level?

Speaker #2: No, it's 50% is the HG. It's or 50 million dollars this year's, I should say, is HG. HG is outperformed our expectations definitely. Two of the three rigs that we have running right now, that Forest and Transit, but two of the three are on HG pads.

Michael Kennedy: No. 50% is the HG. It's over $50 million. This year's, I should say, is HG. HG has outperformed our expectations, definitely. Two of the three rigs that we have running right now have force and transit, but two of the three are on HG pads. One of them does the liquids, one of them's a dry gas. Incrementally, HG is outperforming. We'll have more production than we assumed. There's a little bit of that, but it's not terribly material. HG does sell. We do sell the majority of those volumes in basin, those will have lower transport costs associated with them. That does impact it a bit, but the majority of it is just the shift, like we said, to the demand pull and shift to just some dry gas development also with those transactions expiring.

Speaker #2: One of them knows the liquids. One of them is a dry gas. So, incrementally, HG is outperforming and will have more production than we assumed.

Speaker #2: So there's a little bit of that, but it's not terribly material. HG does sell we do sell the majority of those volumes in basin.

Speaker #2: So those will have lower transport costs associated with them. So that does impact it a bit, but the majority of it is just the shift like we said to the man pull and shift to just some dry gas development also with those transactions expiring.

Speaker #2: Yeah, and if you look at that if you look at that 300 million that we have laid out there too, Betty, I think two of about 250 million of that.

Brendan Krueger: Yeah, if you look at that $300 million that we have laid out there too, Betty, I think about $250 million of that. All of the liquids, the VPP, the override, and then about half of the gas, is all just driven by pure optimization. The $50 million Mike mentioned of that $300 million is really just driven by that kind of shift to more dry gas and HG.

Speaker #2: So all of the liquids the VPP, the override, and then about half of the gas is all just driven by pure kind of optimization.

Speaker #2: The $50 million Mike mentioned of that $300 million is really just driven by that kind of shift to more dry gas and HG.

Speaker #8: Got it. And then sorry for so on the per unit basis, if you grow the dry gas piece going forward, how much would that improve your GP&T?

Betty Jiang: Got it. On a per unit basis, if you grow the dry gas piece going forward, how much would that improve your GP&T?

Speaker #2: Well, I think on the GP&T front, so like we said, the $300 million—just to break it down. So we've got 35 cents of margin improvement.

Brendan Krueger: Well, I think on the GP&T front, you. Like we said, the $300 million, just to break it down. We've got $0.35 of margin improvement. $300 million is about $0.20. The other $0.15 comes from HG. $0.35 of margin improvement. The $0.20 is in that $300 million we talked about. $0.15 is HG. The other, if you think about it from a cost standpoint, again, we're down $0.70 on costs. Almost all of that $0.70 reduction is going to come in the form of GP&T coming down. That's the driver. That processing cost will be lower. Transport costs will be lower. Gathering will stay the same to AM on that front, but everything else will be lower.

Speaker #2: 300 million is about 20 cents. The other 15 cents comes from HG. So 35 cents of margin improvement. The 20 cents is in that 300 million we talked about.

Speaker #2: 15 cents is HG. And then the other if you think about it from a cost standpoint, again, we're down 70 cents on cost. Almost all of that 70 cents reduction is going to come in the form of GP&T coming down.

Speaker #2: I mean, that's the driver—processing costs will be lower, transport costs will be lower. Gathering will stay the same to AM on that front, but everything else will be lower.

Speaker #8: Got it. Thank you. And if I could sneak in one quick one. In your scenario, how much do you does your in basin exposure grow over the next few years?

Betty Jiang: Got it. Thank you. If I could sneak in one quick one. In your scenario, how much does your in-basin exposure grow over the next few years? It's around 20% currently.

Speaker #8: From the 20% currently?

Speaker #2: Yeah, Mike talked about it. So you'll likely go from what today is two-thirds—call it two-thirds, one-third—in terms of two-thirds going to the LNG fairway, a third going elsewhere.

Brendan Krueger: Yeah. Mike talked about it. You'll likely go from what today is two-thirds, call it two-thirds, one-third in terms of two-thirds going to the LNG fairway, a third going elsewhere. You'll have that be more 50/50 on a go-forward basis.

Speaker #2: You'll have that be more 50/50 on a go forward basis.

Speaker #8: Understood. Thank you.

Betty Jiang: Understood. Thank you.

Brendan Krueger: That'll take some time to play out, though. That'll be over, call it a 5-year period for that to play out.

Speaker #2: And that'll take some time to play out, though. That'll be over, call it, a five-year period for that to play out.

Brendan Krueger: That'll take some time to play out, though. That'll be over, call it a 5-year period for that to play out.

Speaker #8: Got it. Thanks.

Betty Jiang: Got it. Thanks.

Speaker #3: Your next question comes from Philip Youngworth, with BMO, please stay your question.

Operator 3: Your next question comes from Phillip Jungwirth with BMO. Please state your question.

Speaker #7: Yeah, thanks. Good morning. I know internal mystery has a separate call, but was hoping you could talk about the east side express pipeline, which is the first interest state.

Phillip Jungwirth: Yeah, thanks. Good morning. I know Antero Midstream has a separate call, but was hoping you could talk about the East Side Express, which is the first interstate regional line. Just how does this benefit Antero and just confidence in executing a project like this? Just separately, just what's the interest and difficulties in building an interstate pipeline team? Just thinking shorter distances like West Virginia to Ohio, for instance, where there should be strong demand pull in the future.

Speaker #7: Regional line—just how does this benefit Antero, and what's the confidence in executing a project like this? And then separately, what's the interest in and difficulties of building an interstate pipeline team?

Speaker #7: Just thinking shorter distances—West Virginia to Ohio, for instance—where there should be strong demand pull in the future.

Speaker #2: Yeah, no, we're super excited about that. That goes hand in glove with these acquisitions that we just did, consolidating the dry gas area of our play 1,000 locations that Brendan talked about.

Michael Kennedy: Yeah, no, we're super excited about that. That goes hand in glove with these acquisitions that we just did, consolidating the dry gas area of our play, the 1,000 locations that Brendan talked about. This is our first regional pipeline east-west, so it will cover approximately over 30 miles of our acreage position in the dry gas window, extend all the way across it. Antero Midstream is the industrial builder of Northern West Virginia. It now has the balance sheet, the credit, the strength, the expertise to build there over a decade. Maybe a decade ago, we farmed this out. Everyone's kind of familiar with that Stonewall pipeline. That's when we farmed that project out because we just didn't have the ability to execute on that. That's no longer the case.

Speaker #2: This is our first regional pipeline east-west that will cover approximately over 30 miles of our acreage position in the dry gas window extend all the way across it.

Speaker #2: Antero Midstream is the industrial builder of northern West Virginia. And now has the balance sheet to credit the strength, the expertise, to build there over a decade.

Speaker #2: Maybe a decade ago, we farmed this out. Everyone's kind of familiar with that stonewall pipeline. That's when we farmed that project out because we just didn't have the ability to execute on that.

Speaker #2: That's no longer the case. We are the builder of these regional pipelines now in West Virginia, and Antero Resources' acreage position and strength—and investment grade—goes with that, over a million acres.

Michael Kennedy: We are the builder of these regional pipelines now in West Virginia, and Antero Resources acreage position and strength and investment grade goes with that over 1 million acres, 1,000 of these dry gas locations. This will go straight across it, and we hope to build more of those at Antero Midstream and for Antero Resources to benefit off that building. Maybe the next one's probably north-south. We've got a couple on the drawing board to go to all the demand centers, to go to all these projects, all the interconnects with all these long-haul pipes. Just interconnect this 1 million-acre position in Tier 1 Marcellus with all the demand that's been publicized, and Antero Midstream will be the pipeline to build it. We will not farm those type of opportunities out anymore.

Speaker #2: 1,000 of these dry gas locations, this will go straight across it. And we hope to build more of those. At Antero Midstream and for Antero Resources, the benefit off that building maybe the next one's probably north-south.

Speaker #2: We've got a couple on the drawing board to go to all the demand centers. To go to all these projects, all the interconnects with all these long-haul pipes, just interconnect this million-acre position and tier-one Marcellus with all the demand that's been publicized.

Speaker #2: And Antero Midstream will be the pipeline to build it. We will not farm those types of opportunities out anymore.

Speaker #7: Okay, great. And then Antero has also always been a leader in realizations for your products, whether it's gas or C3+. We have seen peers increase their focus on the marketing side of light NGL with the large acquisition.

Phillip Jungwirth: Okay, great. Antero has also always been a leader in realizations for your products, whether it's gas or C3+. We have seen peers increase their focus on the marketing side of late, one with the large acquisition. Just when you look at what they're doing, is that something that could make sense for Antero to pursue, just as less of the dry gas volume in the future is committed? If so, how do you go about that?

Speaker #7: Just when you look at what they're doing, is that something that could make sense for Antero to pursue just as less of the dry gas volume in the future is committed?

Speaker #7: And if so, how do you go about that?

Speaker #2: Yeah, we think we already have that. I mean, we've been the top 10 gas marketer. In the US for the past decade, we were ahead of the game on that with our firm transport portfolio.

Michael Kennedy: Yeah. We think we already have that. We've been the top 10 gas marketer in the US for the past decade. We were ahead of the game on that with our firm transport portfolio. I think we have 28 paths that we market along. Also with our liquids too, Dave and his team's been a leader in that. First one signing up on ME2, pretty much signed up on every single project, from an LPG or ethane standpoint, have been marketing around that. Really a market maker over on the Atlantic Basin side of the liquids marketing. Feel really good about our position there ahead of the game. Now others are kind of getting into that monetization of the product being a very important part of the business. We were there over a decade ago.

Speaker #2: I think we have 28 paths that we market along. And also with our liquids too, Dave and his team have been a leader in that first one, signing up on ME2, pretty much signed up on every single project from an LPG or ethane standpoint, and have been marketing around that.

Speaker #2: Really a market maker over on the Atlantic basin side of the liquids, marketing. So feel really good about our position there, ahead of the game.

Speaker #2: And so now others are kind of getting into that monetization of the product, being a very important part of the business. We were there over a decade ago.

Speaker #7: Sounds good. Thanks.

Phillip Jungwirth: Sounds good. Thanks.

Speaker #2: And.

Speaker #3: Your next question comes from Jack Cavanaugh, with Goldman Sachs, please state your question.

Operator 3: Your next question comes from Jack Cavanaugh with Goldman Sachs. Please state your question.

Operator 3: Your next question comes from Jack Cavanagh with Goldman Sachs. Please state your question.

Speaker #5: Morning, team, and thanks for taking my question. I just wanted to ask about hedging, specifically in 2027. I'm just curious how your team's approaching the right hedging levels for next year, and if there's anything you're seeing in the macro setup for '27 that would change your hedging approach year-over-year based off the 60% levels we saw in 2026.

Jack Cavanaugh: Morning, team. Thanks for taking my question. I just wanted to ask on hedging, specifically in 2027. I'm just curious how your team's approaching the right hedging levels for next year if there's anything you're seeing in the macro set up for 2027 that would change your hedging approach year over year based off the 60% levels we saw in 2026.

Jack Cavanagh: Morning, team. Thanks for taking my question. I just wanted to ask on hedging, specifically in 2027. I'm just curious how your team's approaching the right hedging levels for next year if there's anything you're seeing in the macro set up for 2027 that would change your hedging approach year over year based off the 60% levels we saw in 2026.

Speaker #2: No, we're in a good position. We're actually ahead of where we were this time last year for '27. We've got 34% hedged. I think it's a Bcf at $3.84, and then maybe 100 million a day of collars with a $3.50 by $4.50.

Michael Kennedy: No, we're in a good position. We're actually ahead of where we were this time last year. For 2027, we've got 34% hedged. I think it's a BCF at 384 and then maybe 100 million a day of collars with a 350 by 450. We said before, we like the 25% swaps and 25% collars, that's if the collars, if those are attractive levels with a lot of calls skew. We've been favoring more of the swaps of late. I think you'll see us continue to increase that. We're in a great position, we're not going to be rushing into down markets. If you see upticks in the gas price in 2027, you may see us add a little bit.

Speaker #2: We said before we like the 25% swaps and 25% callers, but that's if the callers, if those are attractive levels with a lot of calls queue.

Speaker #2: We've been favoring more of the swaps of late. I think you'll see us continue to increase that. We're in a great position, so we're not going to be rushing into down markets.

Speaker #2: But if you see upticks in the gas price in '27, you may see us add a little bit. When we do acquisitions like this recent one, we do hedge it.

Michael Kennedy: When we do acquisitions like this recent one, we do hedge it, so you saw an increase in our volumes there, hedged volumes by, I believe, around 100 million a day in 2026 and 80 million in 2027. When we do acquisitions, we will hedge them just like we did this one, these couple of acquisitions we did in July.

Speaker #2: So, you saw an increase in our volumes there—hedge volumes by, I believe, around 100 million a day in '26 and 80 million in '27.

Speaker #2: So, when we do acquisitions, we will hedge them just like we did these couple of acquisitions we did in July.

Speaker #3: I appreciate that.

Jack Cavanaugh: I appreciate that. My follow-up, maybe on the $315 million in the West Virginia property acquisitions for the quarter. I'm curious how you and the team are seeing the near-term opportunity set for incremental bolt-ons in and around your core footprint, and whether the current macro is having any impact on the number of opportunities you're seeing in the market.

Jack Cavanagh: I appreciate that. My follow-up, maybe on the $315 million in the West Virginia property acquisitions for the quarter. I'm curious how you and the team are seeing the near-term opportunity set for incremental bolt-ons in and around your core footprint, and whether the current macro is having any impact on the number of opportunities you're seeing in the market.

Speaker #5: And then my follow-up, maybe on the $315 million and the West Virginia property acquisitions for the quarter. I'm curious how you and the team are seeing the near-term opportunity set for incremental bolt-ons in and around your core footprint, and whether the current macro is having any impact on the number of opportunities you're seeing in the market.

Speaker #2: Yeah, it does. We have a lot of non-off working interest entities out in our basin. When you have a million acres, you have a large opportunity set a lot of non-off working interest where in discussions with them and they tend to have acreage around their non-off position too that they're not able to drill or operate.

Michael Kennedy: Yeah, it does. We have a lot of non-op working interest entities out in our base. When you have 1 million acres, you have a large opportunity set. A lot of non-op working interest. We're in discussions with them, and they tend to have acreage around their non-op position too, that they're not able to drill or operate. As part of the transaction, we want to buy in as much working interest as we can and get the acreage as well. One of our strategies is obviously to increase our production. It's really the interest of the production that's from the growth standpoint already on our acreage. Growth being flat, but Antero owning more and more of the interest in that production. Obviously consolidating the acreage around the East Side Express. That's where this acreage was. 15 locations, couple pads right on that East Side Express.

Speaker #2: So it's part of the transaction. We want to buy in as much working interest as we can and get the acreage as well. Our goal, one of our strategies is obviously to increase our production it's really the interest of the production that's from the gross standpoint already on our acreage.

Speaker #2: So gross being flat, but Antero owning more and more of that, the interest in that production, and then obviously consoling the acreage around the East Side Express.

Speaker #2: That's where this acreage was 15 locations, couple pads, right on that east side express. So that was very attractive to us. We continue to see these type of opportunities and we'll continue to look at them.

Michael Kennedy: That was very attractive to us. We continue to see these type of opportunities, and we'll continue to look at them. Generally, it's kind of been around when gas prices go lower, we feel more comfortable, and we can hedge out and take advantage of the contango in the future and then know exactly when we'll develop the pads and take advantage of those type of valuations.

Speaker #2: Generally, it's kind of been around—when gas prices go lower, we feel more comfortable, and we can hedge out and take advantage of the contango in the future, and then know exactly when we'll develop the pads and take advantage of those types of valuations.

Speaker #5: Thanks, guys.

Jack Cavanaugh: Thanks, guys.

Jack Cavanagh: Thanks, guys.

Speaker #3: Your next question comes from Leo Mariani with Roth Capital. Please state your question.

Operator 3: Your next question comes from Leo Mariani with Roth Capital. Please state your question.

Speaker #4: Yeah, hi guys. I was hoping you could give a little bit more of an update on HG here. I know that last quarter you guys bumped up your synergy target there.

Leo Mariani: Yeah. Hi, guys. I was hoping you could give a little bit more of an update on HG here. I know that, kind of last quarter, you guys bumped up your synergy target there. Do you think there could be more upside to that number over time?

Speaker #4: Can you give us a sense of how much of the synergies you've captured thus far in 2026? And do you think there could be more upside to that number over time?

Michael Kennedy: There will be more upside. It's still at that $80 million level. That's not capturing what I mentioned earlier in my remarks. We actually have two rigs of our three on the HG acreage. That's well ahead of schedule. We were contemplating when we underwrote the transaction, just one rig. That's going to accelerate the volumes on the HG, which is going to accelerate the transaction value to us. There's a lot of pad ready there. They've already got all the infrastructure. Being able to put those pads on right into the local gas markets in the winter when we think there'll be elevated pricing. That's all entered into the decision, and obviously, the well results are terrific. We're going to put on the second set of wells from the 1221 pad on 17 August. Those continue to outperform the 1221 North.

Speaker #2: There will be more upside. It's still at that $80 million level, but that's not capturing what I mentioned earlier in my remarks. We actually have two rigs out of our three on the HG acreage.

Speaker #2: That's well ahead of schedule. When we underwrote the transaction, we were contemplating just one rate. So that's going to accelerate the volumes on the HG, which is going to accelerate the transaction value to us.

Speaker #2: There's a lot of pad ready there. They've already got all the infrastructure. Being able to put those pads on right into local gas markets in the winter when we think there'll be elevated pricing.

Speaker #2: That's all entered into the decision. And obviously, the well results are terrific. We're going to put on the second set of wells from the 1221 pad on August 17.

Speaker #2: Those continue to outperform the 1221 North. So we'll continue to update that number, but just for '26 to 80 million is pretty much locked in.

Michael Kennedy: We'll continue to update that number, just for 2026, $80 million is pretty much locked in. That will go higher in 2027 as we put these new pads on.

Speaker #2: But that will go higher in '27 as we put these new pads on.

Speaker #4: Okay, appreciate that. And in terms of the gas price environment, clearly it's relatively weak right now, and I guess we're not too far off from the shoulder season. Are you guys thinking about maybe pushing some of your turn-in-lines over to the winter, when pricing is better?

Leo Mariani: Okay. Appreciate that. In terms of the gas price environment, clearly it's relatively weak right now, and I guess we're not too far off from the shoulder season. Are you guys thinking about maybe pushing some of your turning lines over to the winter when pricing is better? Just any thought as to trying to manage production a bit to match price here?

Speaker #4: Just any thought as to trying to kind of manage production a bit to kind of match price here?

Speaker #2: Yeah, I'm glad you brought that up. That's actually the curtailments that we outlined. That's a new feature for Antero. We talked about the cost structure coming down, but we also have a slide out in our deck that showed the commitments coming down quite dramatically.

Michael Kennedy: Yeah, I'm glad you brought that up. That's actually the curtailments that we outlined. That's a new feature for Antero. We talked about the cost structure coming down. We also have a slide out in our deck that showed the commitments coming down quite dramatically. A lot of those commitments around the MVCs on the liquids. We now have flexibility to look at our lean pads, kind of in that 1,150, 1,160 BTU, and we don't have to produce them, where in years past we would have because there have been MVCs with them. We now have ultimate flexibility, that's a new feature that we're excited about. The ability to just forecast, Hey, look, September could be weak. We mentioned it's under $2.

Speaker #2: And a lot of those commitments around the MVCs on the liquid. So we now have flexibility to look at our lean pads kind of in 1150, 1160 BTU.

Speaker #2: And we don't have to produce them where in years past we would have because there have been NBCs with them we now have ultimate flexibility.

Speaker #2: So that's a new feature that we're excited about: the ability to just forecast, hey, look, September could be weak. We mentioned it's under $2. Let's shut in, have curtailments on those wells, and bring them on more into the November-December timeframe, when the prices are higher.

Michael Kennedy: Let's shut in, have curtailments on those wells and bring them on more into the November, December timeframe when the prices are higher. We very much have that flexibility now, that's something positive for us. We're excited about that.

Speaker #2: We very much have that flexibility now, and that's something positive for us. So we're excited about that.

Speaker #4: Okay. And that's basically baked into the guidance that you've laid out here.

Leo Mariani: Okay. That's kind of basically baked into the guidance that you've laid out here on Q2.

Michael Kennedy: Yeah. We're hopeful to continue to kind of add abilities to take advantage of those opportunities.

Speaker #2: Yeah, we're hopeful to continue to kind of that and build these to take advantage of those opportunities.

Speaker #4: Okay. Thank you.

Leo Mariani: Okay. Thank you.

Speaker #3: Your next question comes from John Annis with Texas Capital. Please state your question.

Operator 3: Your next question comes from John Annis with Texas Capital. Please state your question.

Speaker #6: Hey, good morning. Thanks for taking my questions. For my first one, looking at slide 13, can you help us break down what drove the improvement in the dry gas well results?

John Annis: Hey, good morning, all. Thanks for taking my questions. For my first one, looking at slide 13, can you help us break down what drove the improvement in the dry gas well results? For example, how much came from the completion design, longer laterals, better targeting, versus other factors? Given this was your first dry gas pad in more than a decade, how much more room do you see for further improvement as you apply what you learned to future pads?

Speaker #6: For example, how much came from the completion design, longer laterals, better targeting, versus other factors? And then, given this was your first dry gas pad in more than a decade, how much more room do you see for further improvement as you apply what you learned to future pads?

Speaker #2: Yeah, no, it's terrific results for us. So, this 2,000 pounds of sand and the 830-acre spacing is what we traditionally have done in the liquids.

Michael Kennedy: Yeah, no, it was a terrific result for us. This 2,000 pounds of sand and 830 acre spacing is what we'd traditionally done in the liquids. That's what we've done kind of our go-to for the last 10 years in the liquids. We can play with that spacing. I know on the HG dry gas pads, we're going 1,000, 1,250 interlaterals into going up to 2,500 to 3,500 pounds of sand, and the water going in between 35 barrels per foot and 50 barrels per foot. There's a lot of optimization to occur. To have a 2,000 pound, 830 interlateral spacing and have it be over 2 Bcf per thousand, was a terrific result for us. The lateral length just adds actually to the economics. Brings that dollar per foot on the CapEx, that $13,500.

Speaker #2: That's what we've done kind of our go-to for the the last 10 years in the liquids. So we can play with that spacing. I know on the HG dry gas pads, we're going 1,000, 1,250 inner laterals and going up to 2,500 to 3,500 pounds.

Speaker #2: And the water going in between 35 barrels per foot and 50 barrels per foot. So there's a lot of optimization to occur, but to have a 2,000-pound 830 inner lateral spacing and have it be over two BCF per 1,000 was a terrific result for us.

Speaker #2: The lateral length just actually adds to the economics. It brings that dollar per foot on the capex to $13,500. I mean, you're increasing profit by two and a half times.

Michael Kennedy: You're increasing proppant by 2 and a half times, and your well cost is down 30%. That's a lot of lateral length as well, and drilling times and completion times. Feel really good about that. We have 1,000 locations. Greater than 2 Bcf, we probably would have had those in our database at 1.8 to 1.9. Above 2 Bcf is a terrific result for us.

Speaker #2: And you're well cost is down 30%. That's a lot of that's lateral length as well. So and drilling times and completion times so feel really good about that.

Speaker #2: We have 1,000 locations. Greater than 2 Bcf, we probably would have had those in our database at 1.8 to 1.9. So, above 2 Bcf is a terrific result for us.

Speaker #6: I appreciate that color. For my follow-up, on the lateral of more than 24,000 feet, how does the economics compare with your current average lateral?

John Annis: I appreciate that color. For my follow-up, on the lateral of more than 24,000 feet, how did the economics compare with your current average lateral? Excluding lease geometry, are there any practical limits to extend laterals beyond that?

Speaker #6: And excluding least geometry, are there any practical limits to extend laterals beyond that?

Speaker #2: No, we just drilled that. So we haven't put that on yet. That's actually on an HG pad. On our 1204 North pad, set six wells, average about 19,000 per well.

Michael Kennedy: No, we just drilled that. We haven't put that on yet. That's actually on an HG pad, on our 1204 north pad. Set 6 wells, average about 19,000 per well. Those will be terrific for us. We don't have the results on that yet. All these longer laterals that we've been drilling, obviously a lot of them are now coming from HG because they did a really good job of planning along one high pressure line, with 6 wells going north, 6 wells going south as much as the acreage position would allow. That really allows for terrific production profile being flat at 25 million a day for a long time. That's something we're interested in. We're going to try to replicate that with 2 different rows in our dry gas, do the exact same thing. We have no limitations right now.

Speaker #2: So those would be terrific for us. We don't have the results on that yet, but all these longer laterals that we've been drilling—obviously a lot of them are now coming from HG because they did a really good job of planning along one high-pressure line, with six wells going north and six wells going south, as much as the acreage position would allow.

Speaker #2: That really allows for terrific production profile being flat at 25 million a day for a long time. So that's something we're interested in. We're going to try to replicate that with two different rows in our dry gas do the exact same thing.

Speaker #2: But we have no limitations right now. I think you'll see the lateral lengths continue to just go longer and longer.

Michael Kennedy: I think you'll see the lateral lengths continue to just go longer and longer.

Speaker #6: Makes sense. Thanks, guys.

John Annis: Makes sense. Thanks, guys.

Speaker #3: Your next question comes from Subash Chandra with Stonex, please state your question.

Operator 3: Your next question comes from Subash Chandra with StoneX. Please state your question.

Speaker #5: Hey, Mike. I wanted to confirm a couple of things. So, pro forma for everything—the acquisition, the cost reductions—is maintenance CapEx still at that $1 billion?

Subash Chandra: Hey, Mike. I wanted to confirm a couple things. Pro forma for everything, the acquisition, the cost reductions. Is maintenance CapEx still at that $1 billion? Is the growth price, hurdle price for Henry Hub $3?

Speaker #5: And is the growth price hurdle for Henry Hub $3?

Michael Kennedy: I don't know about the second part, but the first part is correct. It is still $1 billion. Subhash, I didn't catch the second part of your question.

Speaker #2: I don't know about the second part, but the first part is correct. It's still a billion dollars. Subash, I didn't catch it—the second part of your question.

Speaker #5: Yeah, so the second part of your question.

Subash Chandra: Yeah, so the second part of the question.

Michael Kennedy: Oh, $3.

Speaker #2: Oh, $3 is our hurdle as well. That would have been at the beginning of the year. Right now, we're liquids prices are I still think $3 generally in a mid-cycle case, but that's more in that 35 to $40 NGL realized price.

Subash Chandra: Yeah.

Michael Kennedy: That would've been in beginning of year. Right now with where liquids prices are, I still think $3 generally in a mid-cycle case, but that's more in that $35 to $40 NGL realized price. NGLs are well above that. I think today our NGL barrel's at $45. Dave's confirming that, so that's good. Currently this morning we're at $45 a barrel, so that would put that a bit lower. Our liquids development's really kind of more on a steady state than maintenance. The true kind of growth capital is more around the dry gas. $3 is probably a good number to think about.

Speaker #2: NGLs are well above that. I think today our NGL barrels are at $45. They've confirmed that, so that's good. But currently, this morning, we're at $45 a barrel.

Speaker #2: So that would put that a bit lower, but our liquids developments are really kind of more on a steady state than maintenance. So the true kind of growth capital is more around the dry gas.

Speaker #2: So, $3 is probably a good number to think about.

Speaker #5: Okay, great. And a follow-up on HG. If you look at it this way, with the second rig, are you still drilling the puds out?

Subash Chandra: Okay, great. The follow-up on HG, if you look at it this way, but with the second rig, are you still drilling the PUDs out? Have you gone into some maybe the 2P that you thought you might have acquired in the acquisition?

Speaker #5: Have you gone into some maybe the 2P that you thought you might have acquired in the acquisition?

Speaker #2: So, on the 1204 and 1217 pad, the 1217 has been elevated. All of them, I think, were in the approved 1203, though 1203 is on the schedule for 27, and that would have been in the 2P.

Michael Kennedy: On the 1204 and 1217 pad, the 1217's been elevated. All of them, I think, were in the approved. 1203, though, is on the schedule for 2027, and that would've been in the 2P. That's now been pushed up just with the performance of the results that we've seen. Right now those have been improved, but 2027 drilling, we'll get some of the 2P into the portfolio.

Speaker #2: But that's now been pushed up just with the performance of the results that we've seen. So, right now, those have been improved, but 2027 drilling will get some of the 2P into the portfolio.

Speaker #5: Okay, great. Thank you.

Subash Chandra: Okay, great. Thank you.

Speaker #3: Your next question comes from Paul Diamond with Citi. Please go ahead with your question.

Operator 3: Your next question comes from Paul Diamond with Citi. Please go ahead with your question.

Speaker #6: Thank you. Good morning, all. Thanks for taking the call. Just a quick one circling back in curtailments. We just talked about the coming quarter, kind of already being baked into guidance.

Paul Diamond: Thank you. Good morning all. Thanks for taking the call. Just a quick one circling back on curtailments. You guys talked about the coming quarter kind of already being baked into guidance. I guess, as we think about the kind of the contract optimization you talked about, how should we think about, I guess, your willingness or ability to do so, or to a greater degree over time? Is this kind of like the level you expect to stay at, this level of modulation?

Speaker #6: I guess, as we think about the kind of contract optimization we've talked about, how should we think about your willingness or ability to do so, or to a greater degree, over time?

Speaker #6: Or is this kind of the level you expect to stay at—this level of modulation?

Speaker #2: Yeah, we'll see. I mean, right now, we do have some legacy pads in that 1,150, 1,160, 1,170 BTU range. Generally, our uneconomic—if you're around that $1.50 to $1.75.

Michael Kennedy: Yeah, we'll see. Right now we do have some legacy pads in that 1150, 1160, 1170 BTU range that generally are uneconomic if you're around that $50 to 75. Those are about the only pads where we have it kind of in that lean gas area right now. That's about it. It's about 50 million a day, 50 to 100 million a day right now of pads that were drilled in that kind of BTU regime, that in years past we still would've produced because it would've had MVCs on it, we no longer have those MVCs. That's about all we have right now. The rest is either 1,200-plus BTU or sub 1,100 BTU, those really wouldn't qualify for this curtailment strategy.

Speaker #2: But those are about the only pads where we have it kind of in that lean gas area right now. So that's about it. It's about 50 million a day—50 to 100 million a day right now—of pads that we've drilled in that kind of BTU regime that in years past we still would have produced, because it would have had MBCs on it. But we no longer have those MBCs.

Speaker #2: So that's about all we have right now. The rest is either 1,200-plus BTU or sub-1,100 BTU. So those really wouldn't qualify for this curtailment strategy.

Speaker #6: Got it. Makes perfect sense. And then, just talking a bit about—you just talked about a shift in your production cadence through time.

Paul Diamond: Got it. Makes perfect sense. Just talking a bit about, you guys talked about a shift in kind of your production cadence through time. I mean, how reactive do you see yourself being in coming years, given, I guess the demand pull scenario from kind of based on variability from that kind of 50/50 split between dry gas or gas and liquids?

Speaker #6: I mean, how reactive do you see yourself being in the coming years, given, I guess, the demand pulse scenario from, kind of, I guess, how much variability from that kind of 50/50 split between dry gas and, or gas and liquids?

Speaker #2: Yeah, we generally have a growth maintenance program. So, we went on more percent of it, but keep the growth volumes. Obviously, if there are incremental projects that come along in-basin locally that don't really meet our transport, we could potentially grow into those.

Michael Kennedy: Yeah, we generally have a growth maintenance program, we want to own more % of it, but keep the growth volumes. Obviously if there is incremental projects to that that come along in basin locally that does not really need our transport, we could potentially grow into those. Generally, what we have planned is three rig program, two completion crew, and then continue to increase our % ownership of the gross. Keeps volumes in the basin flat, overall flat, we just own more of it.

Speaker #2: But generally, what we've planned is a three-rig program, two completion crews, and then continue to increase our percentage ownership of the gross. It keeps volumes in the base flat overall, but we just own more of it.

Speaker #6: Understood. I appreciate the clarity. I'll leave it there.

Paul Diamond: Understood. Appreciate the clarity. I will leave it there.

Speaker #2: Yep.

Michael Kennedy: Yep.

Speaker #3: Your next question comes from Sunil Simal with Seaport Global Securities. Please state your question.

Operator 3: Your next question comes from Sunil Sibal with Seaport Global Securities. Please state your question.

Speaker #2: Yes, hi. Good morning, and thanks for squeezing me in. I just had a big-picture question. When you think about your gas sales, obviously, you have this transportation portfolio, which helped you sell gas in fairly liquid markets.

Sunil Sibal: Yes. Hi, good morning, thanks for squeezing me in. I just had a big picture question. When you think about your gas sales, obviously you had this transportation portfolio which helped you sell gas in fairly liquid markets. Then, as you think about the in-basin demand, how do you think about the counterparty risk as you shift more on the in-basin demand versus selling to more liquid?

Speaker #2: And then, as you think about the in-basin demand, how do you think about the counterparty risk as you shift more to in-basin demand versus selling to more liquid markets?

Michael Kennedy: We think a lot about it, actually. When we say risk-adjusted, probably two of the three parameters that we look at, obviously price being one, but also timing and execution is really around the counterparty. We think a lot about that. If we do do deals, and the credit needs to be there, you'll see us get LCs or some sort of credit assurance. We're not credit agnostic. We have a big credit, actually, a team just around already having significant firm transport for over a decade. We're very cognizant of the credit and the credibility, and the execution of the project really goes into whether or not we participate.

Speaker #2: Yeah, we think a lot about it, actually. That's one of the—when we say risk-adjusted, probably two of the three parameters I would look at, obviously price being one, but also timing and execution—it's really around the counterparty.

Speaker #2: So we think a lot about that. If we do do deals, and the credit needs to be there, you'll see us get LCs or some sort of credit assurance.

Speaker #2: We're not credit-agnostic. We have a big credit, actually—a team just around already, having significant firm transport for over a decade. So we're very cognizant of credit, and the credibility and the execution of the project really goes into whether or not we participate.

Speaker #5: Understood. And then, one clarification on your savings slide that you have: I think you talked about $105 million or so of savings from some of the contracts that are rolling over.

Sunil Sibal: Understood. One clarification on your savings slide that you have. I think you talked about $105 million or so of savings from some of the contracts that are rolling over, you also talked about that number growing. My understanding was that as far as the contract rollovers are concerned, that's essentially a 2028 kind of timeline. Is that correct? I presume that $105 million is kind of split between a number of contracts. Could you talk about that a little bit?

Speaker #5: And then you also talked about that number growing. My understanding was that, as far as the contract rollovers are concerned, that's essentially a 2028 kind of timeline.

Speaker #5: Is that correct? And I presume that $105 million is kind of split between a number of contracts. Could you talk about that a little bit?

Speaker #2: Yes, that's correct. You have that correct. The main one you can think about is the ATEX. That's the one that we always cite. That's, I think, $60 million of the $105 million.

Michael Kennedy: Yes, that's correct. You have that correct. The main one you can think about is the ATEX. That's the one that we always cite. That's, I think, $60 million of the $105 million. That's 20,000 barrels a day of ethane. The price that it charges, I believe, is around $0.24, $0.25. Dave's nodding yes again, that's good. That's ahead of the actual ethane price we received obviously we're not going to sign up for that. We had to do it a decade ago just to get our gas in spec, since that time, a lot of markets have been developed around the Shell or ME2, Mariner East, Utopia. A lot of different ethane markets have been developed over that time frame. We no longer need that. I think we recover 90,000 barrels of net ethane, over 100,000 barrels of gross ethane.

Speaker #2: That's 20,000 barrels a day of ethane. The price that it charges, I believe, is around $0.24, $0.25. Dave's nodding yes again, so that's good.

Speaker #2: That's ahead of the actual ethane price we receive, so obviously, we're not going to sign up for that. We had to do it a decade ago just to get our gas in spec, but since that time, a lot of markets have been developed around the Shell, ME2, Mariner East, the Utopia — a lot of different ethane markets have been developed over that timeframe.

Speaker #2: So we no longer need that. I think we recover 90,000 barrels of net ethane over 100,000 barrels of gross ethane. For our pipeline spec, we can be down in the low 70,000s.

Michael Kennedy: For our pipeline spec, we can be down in the low 70,000, we can easily let that 20,000 ethane go and be within spec, it's completely uneconomic. That's $60 million of the $105 million. The rest is just optimizing our already transport that expires at the end of 2028.

Speaker #2: So we can easily let that 20,000 ethane go and be within spec, and it's completely uneconomic. So that's $60 million of the $105 million. The rest is just optimizing our already-transport that expires at the end of '28.

Speaker #7: But then the other piece that Mike had mentioned earlier there too is beyond 2028, which is not on that slide, is when you have a lot of the gas contracts that come up for renewal, where we think you could add another few hundred million on top of the $300 million.

Justin Fowler: The other piece that Mike had mentioned earlier, though, too, is beyond 2028, which is not on that slide, is where you have a lot of the gas contracts that come up for renewal, where we think you could add another few hundred million on top of the $300 million.

Speaker #5: Understood. Thank you so much.

Sunil Sibal: Understood. Thank you so much.

Speaker #3: Thank you. There are no further questions at this time, so I'll now hand the floor back to Dan Katzenberg for closing remarks.

Operator 3: Thank you. There are no further questions at this time, so I'll now hand the floor back to Dan Katzenberg for closing remarks.

Speaker #8: Yes, I'd like to thank everybody for joining us on the conference call this morning. If you have any follow-up questions, please reach out. Have a great day.

Dan Katzenberg: Yes, I'd like to thank everybody for joining us on the conference call this morning. If you have any follow-up questions, please reach out. Have a great day. Thank you.

Speaker #8: Thank you.

Operator 3: Thank you. With that, we conclude today's call. All parties may disconnect.

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