Antero Resources Q2 2026 Earnings Report

Antero Resources EPS Results

• Actual EPS: N/A
• Consensus EPS: $0.84
• Beat/Miss: N/A
• One Year Ago EPS: $0.50

Antero Resources Revenue Results

• Actual Revenue: N/A
• Expected Revenue: $1.53 billion
• Beat/Miss: N/A
• YoY Revenue Growth: N/A

Antero Resources Announcement Details

• Quarter: Q2 2026
• Date: 7/29/2026
• Time: After Market Closes
• Conference Call Date: Thursday, July 30, 2026
• Conference Call Time: 11:00AM ET

Antero Resources (NYSE:AR) is an independent exploration and production company focused on the development of natural gas, natural gas liquids (NGLs) and oil properties in the Appalachian Basin of the United States. The company’s operations target the Marcellus and Utica shales, where it applies advanced drilling and completion techniques to optimize recovery from its large acreage position. Antero’s portfolio encompasses significant reserves of ethane, propane and other NGLs, alongside dry gas volumes that are positioned to serve both domestic and export markets.

Headquartered in Denver, Colorado, Antero Resources holds approximately 1.8 million net acres of leasehold interests across parts of West Virginia and Ohio. The company’s development strategy emphasizes low-cost drilling, high rates of return and efficient capital deployment. By leveraging pad drilling, directional drilling and high-intensity fracturing designs, Antero has been able to reduce cycle times and per-well costs while increasing productivity in key geological zones.

In addition to upstream activities, Antero Resources supports its operations through an integrated midstream platform—Antero Midstream Corporation—which it previously spun off as a separately listed entity. This midstream business provides gathering, processing, water handling, compression and transportation services to Antero Resources and third-party producers in Appalachia. The close alignment of midstream and upstream assets enhances operational flexibility and cost efficiencies throughout the drilling and production life cycle.

Founded in 2002 by Paul M. Rady and a team of energy entrepreneurs, Antero Resources has grown under Rady’s leadership, with Kenneth J. Lewandowski serving as President and Chief Financial Officer. The company emphasizes environmental stewardship, community engagement and safety in its field operations, aiming to deliver reliable energy supplies while minimizing its environmental footprint. As a publicly traded company on the New York Stock Exchange under the ticker AR, Antero Resources continues to pursue disciplined growth opportunities in one of the most prolific onshore basins in North America.

Antero Resources Q2 2026 Earnings Call Transcript

Key Takeaways

• Positive Sentiment: Adjusted EBITDAX rose 57% year over year despite a 16% decline in Henry Hub prices, while record production exceeded 4.1 Bcfe per day and generated $220 million of free cash flow.
• Positive Sentiment: Antero expects more than $300 million of annual margin improvement by year-end 2028, driven by lower cash costs, expiring royalty and VPP obligations, and optimization of natural gas and liquids transportation.
• Positive Sentiment: The company reported strong initial dry-gas results, including a 67% increase in estimated ultimate recovery and a roughly 30% reduction in cost per foot, supporting development of more than 1,000 dry-gas locations.
• Positive Sentiment: Antero repurchased 1.1 million shares for $38 million and indicated buybacks could rank higher among capital-allocation priorities while the stock remains at what management views as attractive levels.
• Negative Sentiment: The planned shift toward in-basin gas sales is expected to reduce price realizations by approximately $0.35 per Mcfe, while timing and counterparty risk could limit participation in regional power and data-center projects; 2026 growth capital also remains below the $1.2 billion budget.

Presentation

[Operator]

Greetings, welcome to the Antero Resources Corporation Second Quarter 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.

[Dan Katzenberg, VP of Investor Relations at Antero Resources]

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, then we'll 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.

[Michael Kennedy, CEO and President at Antero Resources]

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. 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. 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. The cost reductions we realized during the second quarter was just the beginning of lower costs to come at Antero.

[Michael Kennedy, CEO and President at Antero Resources]

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.

[Michael Kennedy, CEO and President at Antero Resources]

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 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.

[Michael Kennedy, CEO and President at Antero Resources]

The overriding royalty interest transaction return threshold to the counterparty was met in the second quarter, leading to the Martica entity being dissolved on June 30th and resulting in an increase of $60 million of annualized cash flow beginning in the third quarter of 2026. The VPP will expire in July of 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 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. 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.

[Michael Kennedy, CEO and President at Antero Resources]

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. 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.

[Michael Kennedy, CEO and President at Antero Resources]

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. 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. 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.

[Dave Cannelongo, SVP of Liquids Marketing and Transportation at Antero Resources]

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. 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. U.S. liquid 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 a day during the second quarter of 2026, an increase of 170,000 barrels a day compared to the same period last year.

[Dave Cannelongo, SVP of Liquids Marketing and Transportation at Antero Resources]

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. These new highs surpass the previous record by 300,000 barrels a day and demonstrate that the U.S. can reach previously unseen export levels, driven in part by recently added terminal capacity. 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. The record levels achieved for both LPG products since the start of the year illustrate that propane and butane are fiercely competing for terminal space to backfill lost Middle East supply across demand markets worldwide.

[Dave Cannelongo, SVP of Liquids Marketing and Transportation at Antero Resources]

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 U.S. as the Middle East supply remains curtailed and uncertain. China's LPG imports from the U.S. declined last year following the initial imposition of the additional U.S. tariffs, but have rebounded recently due to disruption in Middle East supplies. U.S. 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. Additionally, we are beginning to see a recovery in Chinese petrochemical demand for LPG.

[Dave Cannelongo, SVP of Liquids Marketing and Transportation at Antero Resources]

As shown on slide number 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 U.S. imports into China in the near term. Next, let's turn to slide number eight to discuss shipping dynamics. VLGC freight rates have been elevated since the quarter due to the global resupplying of ships after the closure of the Strait of Hormuz, creating some headwinds for U.S. 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 the second half of 2026 and all of 2027.

[Dave Cannelongo, SVP of Liquids Marketing and Transportation at Antero Resources]

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. 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. With that, I'll now turn it over to our Senior Vice President of Gas Marketing, Justin Fowler, for his comments.

[Justin Fowler, SVP of Natural Gas Marketing at Antero Resources]

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 U.S. 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. Let's look at regional demand in our Appalachian Basin, which is highlighted on slide number 10.

[Justin Fowler, SVP of Natural Gas Marketing at Antero Resources]

The four projects highlighted on this slide represent the projects that have been publicly announced in our region to date and amount to over nine Bcf per day of demand. This does not include additional projects that we have spoken to that add an additional incremental three 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 six 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. 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.

[Justin Fowler, SVP of Natural Gas Marketing at Antero Resources]

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 seven 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.

[Brendan Krueger, CFO at Antero Resources]

Thanks, Justin. I will start on slide 12, which highlights our second quarter 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. 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.

[Brendan Krueger, CFO at Antero Resources]

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 second quarter being our first full quarter incorporating the HG Energy acquisition. Next, let's turn to slide 13, titled Strong Performance in Return to Dry Gas Drilling.

[Brendan Krueger, CFO at Antero Resources]

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. 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, CFO at Antero Resources]

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 four times 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 4.5 Bcfe a day or 36% growth over that time period.

[Brendan Krueger, CFO at Antero Resources]

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.

[Operator]

Thank you.

[Brendan Krueger, CFO at Antero Resources]

Thank you.

[Operator]

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 will pause for a moment while we pull for questions.

[Operator]

Our first question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question.

[Kevin MacCurdy, Director of Research at Pickering Energy Partners]

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. Obviously, you are in the dominant position or the dominant producer in West Virginia. You touched a little bit on this on your prepared remarks. Maybe you can expand a little bit on how you view your gas marketing portfolio in total. What would make you get more aggressive with long-term sales agreements.

[Michael Kennedy, CEO and President at Antero Resources]

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. 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.

[Michael Kennedy, CEO and President at Antero Resources]

When we look at projects, it has to meet all of those three. That one just wasn't attractive to us.

[Kevin MacCurdy, Director of Research at Pickering Energy Partners]

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?

[Michael Kennedy, CEO and President at Antero Resources]

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, EBITDA 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 is very attractive to us at these levels.

[Kevin MacCurdy, Director of Research at Pickering Energy Partners]

Appreciate it. Thanks.

[Operator]

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

[Gabe Daoud, Managing Director and Energy Equity Research Analyst at Truist]

Hey, thanks, guys. It's Gabe from Truist. 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?

[Michael Kennedy, CEO and President at Antero Resources]

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 on the difference between maintenance and growth capital. You will have some capital. Our maintenance case, just to remind everyone, was $1 billion. Our growth is $1.2 billion of capital this year. Right now, we're probably somewhere a bit north of $1 billion, but not to the $1.2 billion. A lot of that will be completion capital in the fourth quarter, and that's yet to be determined whether we deploy that. We 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.

[Gabe Daoud, Managing Director and Energy Equity Research Analyst at Truist]

Okay. If you complete those wells, and that takes 2027, would imagine four six.

[Michael Kennedy, CEO and President at Antero Resources]

Yeah.

[Gabe Daoud, Managing Director and Energy Equity Research Analyst at Truist]

Yeah.

[Michael Kennedy, CEO and President at Antero Resources]

Yeah.

[Gabe Daoud, Managing Director and Energy Equity Research Analyst at Truist]

Okay. Thanks, Mike. Maybe just a follow-up. Curious on the cost optimization plan, the 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?

[Michael Kennedy, CEO and President at Antero Resources]

Yeah, sorry. Some of that's in basin pricing around the dry gas, the majority of it is just the optimization of our FT. 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 FT paths. Justin hit on that slide, too. All of that seven 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, also get us a premium. None of that's baked into this $300 million that we've been talking about. That'd be incremental.

[Michael Kennedy, CEO and President at Antero Resources]

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'll actually do better than that, just getting premiums along that path instead of just having the end user hold that transport.

[Gabe Daoud, Managing Director and Energy Equity Research Analyst at Truist]

Got it. Okay. That makes sense. Thanks, guys.

[Operator]

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

[John Freeman, Managing Director at Raymond James]

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

[Michael Kennedy, CEO and President at Antero Resources]

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

[John Freeman, Managing Director at Raymond James]

That's great. 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 start to have the opportunity to sell more gas in basin. Like rough numbers, how do you see that mix sort of changing versus, if we call it two-thirds out of basin at the moment? How do you see that evolving over the next several years?

[Michael Kennedy, CEO and President at Antero Resources]

Yeah. Right now, we're kind of thinking, a third was FP 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.

[John Freeman, Managing Director at Raymond James]

That's great. Appreciate it.

[Operator]

Your next question comes from Arun Jayaram with JPMorgan. Please state your question.

[Arun Jayaram, Analyst at JPMorgan]

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, but give us a sense of how that will play out over the next couple of years. 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.

[Michael Kennedy, CEO and President at Antero Resources]

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 or a $0.04 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, but we're in significant negotiations around those type of improvements. Think about that's more ratable. Then the $105 million that we're talking on liquids, that's year-end 2028.

[Arun Jayaram, Analyst at JPMorgan]

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.

[Michael Kennedy, CEO and President at Antero Resources]

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 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 arc there, our strategy has been to remain on the spot there. We haven't entered any firm agreements with that price.

[Michael Kennedy, CEO and President at Antero Resources]

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 that along the way, we're not participating in, 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, it's got to compete with our firm transport and liquids production.

[Arun Jayaram, Analyst at JPMorgan]

That's clear. Thanks a lot, Mike.

[Operator]

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

[Doug Leggate, Managing Director and Senior Research Analyst at Wolfe Research]

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. 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.

[Brendan Krueger, CFO at Antero Resources]

Yeah. Sorry, I didn't hear that last part. Doug, could you repeat that?

[Doug Leggate, Managing Director and Senior Research Analyst at Wolfe Research]

Yeah, sorry. Something'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.

[Brendan Krueger, CFO at Antero Resources]

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.

[Brendan Krueger, CFO at Antero Resources]

Seeing on the demand pull, like Mike mentioned, this market where it used to be you have to find a place for your gas, 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?" 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 way.

[Doug Leggate, Managing Director and Senior Research Analyst at Wolfe Research]

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?

[Michael Kennedy, CEO and President at Antero Resources]

Go back. We have two pads in there. We put our first one in Flanigan Pad that Brendan reviewed the results. The next two are Katie and Walter's 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, and 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, then we won't complete them in the fourth quarter.

[Doug Leggate, Managing Director and Senior Research Analyst at Wolfe Research]

That's really helpful. Thanks a lot.

[Operator]

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

[Betty Jiang, Analyst at Barclays]

Good morning. I want to start with a follow-up to Arun's question about cost. This GP&T piece, 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 further dry gas growth above and beyond the base level?

[Michael Kennedy, CEO and President at Antero Resources]

50% is 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. We do sell the majority of those volumes in basin, so those will have lower transport costs associated with them. That has impacted a bit, but the majority of it is just a shift, like we said, to the demand pull and shift to just some dry gas development also with those transactions expiring.

[Brendan Krueger, CFO at Antero Resources]

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 than HG.

[Betty Jiang, Analyst at Barclays]

Got it. Sorry for the on the per unit basis, if you grow the dry gas piece going forward, how much would that improve your GP&T?

[Brendan Krueger, CFO at Antero Resources]

Well, I think on the GP&T front, 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. The other, if you think about it from a cost standpoint, again, we're down $0.70 on cost. 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.

[Betty Jiang, Analyst at Barclays]

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? We're on the 20% currently.

[Brendan Krueger, CFO at Antero Resources]

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.

[Betty Jiang, Analyst at Barclays]

Thank you.

[Brendan Krueger, CFO at Antero Resources]

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

[Betty Jiang, Analyst at Barclays]

Got it. Thanks.

[Operator]

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

[Phillip Jungwirth, Managing Director at BMO]

Yeah. Thanks. Good morning. I know Antero Midstream has a separate call, was hoping you could talk about the East Side Express Pipeline, which is the first intrastate regional line. Just how does this benefit Antero and just confidence in executing a project like this? Separately, what's the interest in 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.

[Michael Kennedy, CEO and President at Antero Resources]

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, it'll cover approximately over 30 miles of our acreage position into 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.

[Michael Kennedy, CEO and President at Antero Resources]

We are the builder of these regional pipelines now in West Virginia, Antero Resources' acreage position and strength and investment grade goes with that over 1 million acres, thousands of these dry gas locations. This will go straight across it, we hope to build more of those at Antero Midstream. 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 to interconnect this 1 million-acre position in Tier 1 Marcellus with all the demand that's been publicized, Antero Midstream will be the pipeline to build it, we will not farm those type of opportunities out anymore.

[Phillip Jungwirth, Managing Director at BMO]

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 a large acquisition. 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?

[Michael Kennedy, CEO and President at Antero Resources]

We think we already have that. We've been the top 10 gas marketer in the U.S. 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 Mariner East 2, pretty much signed up on every single project from an LPG or ethane standpoint, have been marketing around that. A market maker over on the Atlantic Basin side of the liquids marketing. Feel really good about our position there ahead of the game. Others are getting into that monetization of the product being a very important part of the business. We were there over a decade ago.

[Phillip Jungwirth, Managing Director at BMO]

Sounds good. Thanks.

[Operator]

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

[Jack Cavanagh, Analyst at Goldman Sachs]

Morning, team, and 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 and if there's anything you're seeing in the macro set for 2027 that would change your hedging approach year-over-year based off the 60% levels we saw in 2026.

[Michael Kennedy, CEO and President at Antero Resources]

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 $3.84 and then maybe 100 million a day of collars with a $3.50 by $4.50. We said before, we like the 25% swaps and 25% collars, but that's if the collars, if those are attractive levels with a lot of calls queue. 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.

[Michael Kennedy, CEO and President at Antero Resources]

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.

[Jack Cavanagh, Analyst at Goldman Sachs]

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.

[Michael Kennedy, CEO and President at Antero Resources]

Yeah, it does. We have a lot of non-op working interest entities out in our basin. 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.

[Michael Kennedy, CEO and President at Antero Resources]

15 locations, couple pads right on that East Side Express. 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.

[Jack Cavanagh, Analyst at Goldman Sachs]

Thanks, guys.

[Operator]

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

[Leo Mariani, Managing Director and Senior Research Analyst at Roth Capital]

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. Can you give us a sense of kind of how much of the synergies you've captured thus far in 2026? Do you think that there could be more upside to that number over time?

[Michael Kennedy, CEO and President at Antero Resources]

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 local gas markets in the winter when we think there'll be elevated pricing, that's all entered into the decision. Obviously the well results are terrific. We're going to put on the second set of wells from the 1221 pad on August 17th. Those continue to outperform the 1221 North. We'll continue to update that number.

[Michael Kennedy, CEO and President at Antero Resources]

Just for 2026, $80 million is pretty much locked in, but that will go higher in 2027 as we put these new pads on.

[Leo Mariani, Managing Director and Senior Research Analyst at Roth Capital]

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

[Michael Kennedy, CEO and President at Antero Resources]

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, and 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 1150, 1160 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, 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, CEO and President at Antero Resources]

We very much have that flexibility now. That's something positive for us. We're excited about that.

[Leo Mariani, Managing Director and Senior Research Analyst at Roth Capital]

Okay. That's kind of basically baked into the guidance that you've laid out here.

[Michael Kennedy, CEO and President at Antero Resources]

Yeah.

[Leo Mariani, Managing Director and Senior Research Analyst at Roth Capital]

On 3Q.

[Michael Kennedy, CEO and President at Antero Resources]

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

[Leo Mariani, Managing Director and Senior Research Analyst at Roth Capital]

Okay. Thank you.

[Operator]

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

[John Annis, VP at Texas Capital]

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?

[Michael Kennedy, CEO and President at Antero Resources]

No, it's a terrific result for us. This 2,000 pounds of sand and 830-acre spacing is what we've traditionally done in the liquids. That's what we've done kind of our go-to for the last 10 years in a liquid. We can play with that spacing. I know on the HG dry gas pad, we're going 1,000, 1,250 inner laterals 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 inner lateral spacing and have it be over two 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.

[Michael Kennedy, CEO and President at Antero Resources]

I mean, you're increasing proppant by two and a half times, and your well cost is down 30%. That's a lot of lateral length as well. Drilling times and completion times. Feel really good about that. We have 1,000 locations greater than two Bcf. We probably would have had those in our database at 1.8 to 1.9. Above two Bcf is a terrific result for us.

[John Annis, VP at Texas Capital]

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

[Michael Kennedy, CEO and President at Antero Resources]

No, we just drilled that, we haven't put that on yet. That's actually on an HG pad on our 1204 North pad. It's at six 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 six wells going north, six 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 two different rows in our dry gas, do the exact same thing. We have no limitations right now.

[Michael Kennedy, CEO and President at Antero Resources]

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

[John Annis, VP at Texas Capital]

Makes sense. Thanks, guys.

[Operator]

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

[Subash Chandra, Analyst at StoneX]

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?

[Michael Kennedy, CEO and President at Antero Resources]

I don't know about the second part, but the first part is correct. It's still $1 billion. Subash, I didn't catch it, the second part of your question.

[Subash Chandra, Analyst at StoneX]

Yeah. The second part of the question.

[Michael Kennedy, CEO and President at Antero Resources]

Oh, $3. 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-$40 NGL realized price. NGLs are well above that. I think today our NGL barrel's at $45. Dave's confirming that's good. Currently this morning we're at $45 barrel, that would put that a bit lower. Our liquids development's really more on a steady state than maintenance. The true growth capital is more around the dry gas. $3 is probably a good number to think about.

[Subash Chandra, Analyst at StoneX]

Okay, great. A 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?

[Michael Kennedy, CEO and President at Antero Resources]

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 will get some of the 2P into the portfolio.

[Subash Chandra, Analyst at StoneX]

Okay, great. Thank you.

[Operator]

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

[Paul Diamond, Analyst at Citi]

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've talked about, how should we think about, I guess, your willingness or ability to do so, or to a greater degree over time? Or is this kind of like the level you expect to stay at, this level of modulation?

[Michael Kennedy, CEO and President at Antero Resources]

Yeah, we'll see. Right now we do have some legacy pads in that 1,150, 1,160, 1,170 BTU range, that generally are uneconomic if you're around that $1.50-$1.75. 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, 50-100 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, but 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.

[Paul Diamond, Analyst at Citi]

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

[Michael Kennedy, CEO and President at Antero Resources]

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

[Paul Diamond, Analyst at Citi]

Good. Appreciate the clarity. I'll leave it there.

[Michael Kennedy, CEO and President at Antero Resources]

Yep.

[Operator]

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

[Sunil Sibal, Managing Director and Senior Energy Infrastructure/Utilities Analyst at Seaport Global Securities]

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 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-

[Michael Kennedy, CEO and President at Antero Resources]

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 is really around the counterparty. We think a lot about that. If we 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.

[Sunil Sibal, Managing Director and Senior Energy Infrastructure/Utilities Analyst at Seaport Global Securities]

Understood. 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, 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. 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?

[Michael Kennedy, CEO and President at Antero Resources]

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, so it'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, 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.

[Michael Kennedy, CEO and President at Antero Resources]

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, and it's completely uneconomic. That's $60 million of the $105 million. The rest is just optimizing our ready transport that expires at the end of 2028.

[Brendan Krueger, CFO at Antero Resources]

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.

[Sunil Sibal, Managing Director and Senior Energy Infrastructure/Utilities Analyst at Seaport Global Securities]

Understood. Thank you so much.

[Operator]

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

[Dan Katzenberg, VP of Investor Relations at Antero Resources]

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.

[Operator]

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

Participants

Executives

• Dan Katzenberg, VP of Investor Relations
• Michael Kennedy, CEO and President
• Dave Cannelongo, SVP of Liquids Marketing and Transportation
• Justin Fowler, SVP of Natural Gas Marketing
• Brendan Krueger, CFO

Analysts

• Kevin MacCurdy, Director of Research at Pickering Energy Partners
• Gabe Daoud, Managing Director and Energy Equity Research Analyst at Truist
• John Freeman, Managing Director at Raymond James
• Arun Jayaram, Analyst at JPMorgan
• Doug Leggate, Managing Director and Senior Research Analyst at Wolfe Research
• Betty Jiang, Analyst at Barclays
• Phillip Jungwirth, Managing Director at BMO
• Jack Cavanagh, Analyst at Goldman Sachs
• Leo Mariani, Managing Director and Senior Research Analyst at Roth Capital
• John Annis, VP at Texas Capital
• Subash Chandra, Analyst at StoneX
• Paul Diamond, Analyst at Citi
• Sunil Sibal, Managing Director and Senior Energy Infrastructure/Utilities Analyst at Seaport Global Securities