AR

A month has gone by since the last earnings report for Antero Resources (AR). Shares have added about 9.1% in that time frame, outperforming the S&P 500. But investors have to be wondering, will the recent positive trend continue leading up to its next earnings release, or is Antero Resources due for a pullback? Well, first let's take a quick look at its most recent earnings report in order to get a better handle on the recent drivers for Antero Resources Corporation before we dive into how investors and analysts have reacted as of late. Antero Resources Corporation reported second-quarter 2026 adjusted earnings of 76 cents per share, beating the Zacks Consensus Estimate of 75 cents. Revenues of $1.6 billion beat the consensus estimate of $1.5 billion by 4.4% and increased from $1.3 billion in the year-ago quarter. The strong quarterly performance was supported by record production, lower cash costs and benefits from the HG Energy acquisition. Net production averaged 4.1 Bcfe/d, up 21% year over year, while adjusted EBITDAX rose 57% to $595 million. Antero Resources delivered record production in the second quarter, with average net output reaching 4.1 Bcfe/d, including 216 MBbl/d of liquids. The figure is in line with our estimate of 4.1 Bcfe/d. Natural gas production averaged 2,847 MMcf/d, while C3+ NGL production averaged 121,132 Bbl/d and C2 NGL production averaged 86,769 Bbl/d. The company placed 26 Marcellus wells to sales during the quarter with an average lateral length of 13,323 feet. The 21 wells that had been online for about 60 days averaged 25 MMcfe/d per well, including 975 Bbl/d of liquids per well assuming 25% ethane recovery. AR saw year-over-year revenue growth from stronger production volumes and contributions from the HG Energy assets.Total revenues increased to $1.6 billion from $1.3 billion in the prior-year quarter, helped by higher natural gas liquids sales, oil sales and commodity derivative gains. The company’s revenues included $688.5 million from natural gas sales, $587.7 million from natural gas liquids sales and $59.6 million from oil sales. The figures are slightly below our estimates of $705.6 million from natural gas sales, $653.4 million from natural gas liquids sales and $63.1 million, respectively. Commodity derivative fair value gains increased to $160.6 million from $53.4 million a year ago. Antero Resources reported total cash operating costs of $2.38 per Mcfe in the quarter, down $0.29 per Mcfe, or 11%, from the prior-year period. Cash production expenses were $2.22 per Mcfe compared with $2.48 per Mcfe in the second quarter of 2025. The figure is marginally above our estimate of $2.21 per Mcfe Operating expenses rose to $1.18 billion from $1.09 billion a year ago, reflecting higher gathering, compression, processing and transportation costs, as well as increased depletion, depreciation and amortization. The figure is also above our estimate of $1.14 billion. Operating income, however, improved to $375.5 million from $204.9 million. The metric also beat our estimate of $323.3 million. AR completed strategic acquisitions in July for approximately $315 million within its West Virginia development footprint. The properties add about 125 MMcfe/d of net production, 3,500 net undeveloped acres and 15 net undeveloped locations. The company also continued investing in its resource base during the quarter. Drilling and completion capital expenditure totaled $297 million, while land investment reached $29 million, adding approximately 5,000 net acres and 20 incremental net drilling locations. Antero Resources raised its 2026 production guidance to 4.15-4.2 Bcfe/d, citing strong year-to-date performance and the July acquisitions. Third-quarter production is expected to average 4.25-4.3 Bcfe/d, with fourth-quarter production forecast at 4.4-4.5 Bcfe/d. The company lowered cash production expense guidance to $2.20-$2.30 per Mcfe and adjusted its expected natural gas realized price premium to NYMEX Henry Hub to 5-15 cents per Mcf. C2 NGL realized price premium guidance was increased to $2.50-$3 per barrel. AR generated $438.8 million in net cash from operating activities during the second quarter. The adjusted free cash flow before changes in working capital was $219.8 million compared with $156.3 million in the year-ago period. The company also continued its capital return program, repurchasing 1.1 million shares for approximately $38 million during the quarter at an average weighted price of $34.25 per share. As of the earnings release, Antero Resources had approximately $880 million of remaining capacity under its share repurchase program. Antero Resources’ balance sheet reflected total debt of $2.6 billion as of June 30, 2026, including $1.1 billion outstanding under its term loan and $600 million of senior notes due 2030. In the past month, investors have witnessed a upward trend in fresh estimates. The consensus estimate has shifted 18.11% due to these changes. At this time, Antero Resources has a nice Growth Score of B, though it is lagging a bit on the Momentum Score front with a C. Charting a somewhat similar path, the stock has a score of B on the value side, putting it in the top 40% for this investment strategy. Overall, the stock has an aggregate VGM Score of A. If you aren't focused on one strategy, this score is the one you should be interested in. Estimates have been broadly trending upward for the stock, and the magnitude of these revisions looks promising. Interestingly, Antero Resources has a Zacks Rank #3 (Hold). We expect an in-line return from the stock in the next few months. Antero Resources is part of the Zacks Oil and Gas - Exploration and Production - United States industry. Over the past month, Range Resources (RRC), a stock from the same industry, has gained 5.3%. The company reported its results for the quarter ended June 2026 more than a month ago. Range Resources reported revenues of $795.3 million in the last reported quarter, representing a year-over-year change of +8.5%. EPS of $0.79 for the same period compares with $0.66 a year ago. Range Resources is expected to post earnings of $0.67 per share for the current quarter, representing a year-over-year change of +17.5%. Over the last 30 days, the Zacks Consensus Estimate has changed +5.6%. The overall direction and magnitude of estimate revisions translate into a Zacks Rank #3 (Hold) for Range Resources. Also, the stock has a VGM Score of B. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Antero Resources Corporation (AR) : Free Stock Analysis Report Range Resources Corporation (RRC) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Image source: The Motley Fool. Thursday, July 30, 2026 at 12:00 p.m. ET Vice President, Investor Relations - Daniel Katzenberg Chief Executive Officer and President - Michael Kennedy Chief Financial Officer - Justin Agnew Chief Financial Officer of Antero Resources - Benny Krueger Need a quote from a Motley Fool analyst? Email [email protected] Operator: Greetings, and welcome to the Antero Midstream Corporation Second Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to Dan Katzenberg, Vice President, Investor Relations. Please go ahead. Daniel Katzenberg: Thank you for joining us for Antero Midstream's Second Quarter 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 anteromidstream.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 of Antero Midstream; Justin Agnew, CFO of Antero Midstream; and Benny Krueger, CFO of Antero Resources. With that, I will turn the call over to Mike. Michael Kennedy: Thanks, Dan. Good morning, everyone. I'll start my comments on Slide #3. Last year has been an exciting year for growth in Appalachia and more importantly, Antero Midstream. During the second quarter, we gathered over 4.1 Bcf per day of gas, which was almost a 20% increase year-over-year. This growth was driven by the successful integration of the HG Midstream assets. This increased scale, premier footprint and strong balance sheet positions Antero Midstream to capture the abundant opportunities that are beginning to materialize in the region. To this point, we've seen an acceleration of new gas-fired power generation project announcements and supply deals, including a 2-gigawatt combined cycle power plant in Doddridge County, West Virginia, accessed by AM's joint venture pipeline. We expect this trend to continue as final investment decisions and construction start-ups accelerate, providing increased visibility into the Appalachian demand growth story. Looking ahead, we are positioning our infrastructure to support the significant demand growth over the next several years. This starts with beginning construction on our first intrastate regional pipeline called Eastside Express. This large diameter east-west pipeline will enhance the regional connectivity of our dry gas gathering system with several downstream market outlets. We plan to phase in this project over the next several years as new market opportunities arise with the objective of increasing optionality and supporting low-cost dry gas growth. As the industrial builder in the state of West Virginia that gathers half of the gas produced in the state, we view this project as step 1 in positioning Antero Midstream to capture the incremental production needed to fulfill the visible demand growth. In our view, this production growth will have to come from high-quality investment-grade producers with multi-decade inventories like Antero Resources. In addition to this project, the opportunity set ahead of Antero Midstream is larger than ever. In aggregate, we are evaluating several billion dollars of infrastructure opportunities within the region and we'll be selective with projects that are near term, actionable and accretive to our free cash flow and generate attractive rates of return. Before turning the call over to Justin, I wanted to briefly touch on the early results we are seeing on our first return to the dry gas Marcellus in over a decade. As you can see on Slide #4, EURs on our revisit were over 60% higher than offset wells completed the last time we were actively developing the area. This highlights the productivity improvements from enhanced completion designs and validates the decades of underlying resource that underpins the growth outlook at Antero Midstream. With that, I'll turn the call over to Justin. Justin Agnew: Thanks, Mike. I'll start with our second quarter highlights on Slide #5. The second quarter represents the first full quarter of contribution from the recently acquired HG assets, which have been successfully integrated. Adjusted EBITDA for the second quarter was a company record $289 million, which was a 2% increase year-over-year, driven by an increase in gathering volumes. Looking ahead to the third quarter, we expect high single-digit sequential EBITDA growth in Q3, driven by increased volumes, which keeps us on track to achieve our full year EBITDA guidance. Capital invested during the quarter was $47 million, which helped to generate $80 million of free cash flow after dividends. This quarter marks the 12th consecutive quarter of generating free cash flow after dividends, highlighting the consistency and durability of cash flows over the last 3 years. I'll conclude my prepared remarks on Slide #6, which highlights our pro forma balance sheet and maturity schedule. In July, we received over $370 million of damages and interest from Veolia. Pro forma for these proceeds, our leverage was 2.8x as of June 30, below our 3x target and well ahead of schedule. Excess cash on hand and availability -- available capacity under our undrawn credit facility positioned us to call our nearest term 2028 maturity at par. As a result, we have no near-term maturities, and we have converted that debt into lower cost prepayable debt on our credit facility while maintaining significant liquidity. This financial flexibility is critical in today's environment as we position Antero Midstream to execute on the large opportunity that Mike referenced in his remarks. This flexibility and project opportunity set, in addition to our organic growth strategy, position us well to continue delivering shareholder value over the long term and enhance our return of capital to shareholders. With that, operator, we are ready to open up for Q&A. Operator: [Operator Instructions] Our first question today is coming from John Mackay from Goldman Sachs. John Mackay: Let's start on East Side Express. Just wondering if there's a little more you can share with us in terms of CapEx expectations and the contracting side. Is this AR underwriting? Are you looking to get customers on the demand side to underwrite? Maybe just walk us through the spending and the return profile. Michael Kennedy: Yes, it's really AR underwriting, but it's $200 million to $300 million over the next 2 to 3 years. So I think about kind of $100 million each year. I think it has 7 interconnects with long-haul pipelines. Big pipe, 1.5 to 2 Bcf a day. So there will be opportunities, but solely underwritten by Antero Resources and its development plans, but with optionality to get third-party business and connect with all those different pipes. John Mackay: That's helpful. And then maybe just looking broadly, you mentioned the several billion dollars of opportunities. Maybe just walk us through some of the general buckets that could include. Is there anything in there that could kind of dovetail with some of the cost saving initiatives that AR has been talking about? Or should we kind of think about this as pretty separate? Michael Kennedy: Yes. No, I think you've heard about all the different power plant construction, data center construction in West Virginia, that's capturing that from a midstream perspective, building these type of regional pipelines or laterals off of existing pipelines to those type of projects. I referenced it on the AR call, but a decade ago, a good go buy the Stonewall pipeline. We had to farm that out. We didn't have the ability to build that internally, whether from capital or expertise. Now that's not the case. We are the builder in this area of the world. We have 1 million acres dedicated to us from AR. We have all these demand projects and power plants within that acreage or close to it. So we will be building those pipelines and laterals to those type of projects within the state of West Virginia. John Mackay: Appreciate that. And maybe just a clarification. Is there a kind of time frame on that, that you can throw out there? Michael Kennedy: No, this is our first one, the East Side Express. So that's over the next 2 to 3 years of the '28, '29 time frame. We're hopeful to announce more in the near term. Operator: Next question is coming from Jeremy Tonet from JPMorgan. Jeremy Tonet: Just wanted to peel back that several billion of CapEx opportunities that you said there. And it sounds like some of this could be servicing third parties beyond AR here. And just wondering that part of the business, how much opportunity you see to grow as far as servicing other producers or just in general, moving beyond what AR provides? Michael Kennedy: Yes. I'm looking at a project backlog right now there's 15 projects that generally make that up all within the state of West Virginia. So that's what we're looking at. Antero Midstream could be involved solely or more probably probability-wise with AR's gas. So we're way more comfortable with AR as a supplier of that. AR, of course, we know exactly when they drill wells and where the gas goes and very confident in that throughput. So probably most likely associated with AR, but there are 15 projects on this list I'm looking at right now, and AR is probably half of them. Jeremy Tonet: Okay. Got it. And then just pivoting towards water here. Just wondering what opportunities on the water beneficial reuse side you might see there. Given disposal costs much higher in the Northeast versus Texas, does that create more incentive economic benefit to recycling here? Just wondering what that -- any updates there? Michael Kennedy: Yes. For AR, it's terrific to have a closed-loop water system that -- it's in a kind of cost plus 13 versus the kind of the disposal cost that you referenced. That's great for AR. Also great for AM because that closed-loop system is the freshwater distribution where it gets nice returns and both from a freshwater distribution and also from a produced water disposal reuse case. So really a benefit to both parties, also allows AR to complete in that 14, 15, 16 stages range and not have water be a logistics issue. So very beneficial to both. We'll connect the HG system. We're connecting it as we speak. That will be what's responsible, and it could be more than this, but what we've talked about on the high single-digit EBITDA growth for '27, that's just connecting the water systems to get the water down to the HG area. So that will benefit us going forward into '27 with the EBITDA growth on top of what we had this year. Jeremy Tonet: Got it. That's very helpful there. And apologies if I missed the details on the AR call. But with regards to power generation investment, the governor has a 50 by 50 goal. So clearly, a lot of appetite in state to develop new generation there. And just wondering, I guess, Antero's appetite to more fully, I guess, embrace that build-out going further downstream, what have you? Just any thoughts on that side? Michael Kennedy: Yes, we fully embrace that. We're the only investment-grade producer in West Virginia that's focused solely on West Virginia. We are the midstream builder. We've built everything up here over the last decade. So you combine those 2, and we produce about half of the state's gas. So we would be the logical person to benefit or entities to benefit from that initiative governor has. Operator: Next question is coming from Sunil Sibal from Seaport Global. Sunil Sibal: Most of my questions have been hit, but I just had one clarification with regard to the opportunity to contract for the gas to ultimate consumers. So I was curious when you're talking for those contracts, are you contracting with the power producers in the region? Or you're more focused on contracting with the data center entities per se? Michael Kennedy: It's all of the above, both. We're building the East Side Express just knowing Antero's development and where that's going and where the interconnects are and just the opportunity set in front of us. We want to get in front of that and be positioned well. So when these opportunities present themselves, we are positioned to deliver gas to them. Operator: Next question today is coming from Ned Baramov from Wells Fargo. Ned Baramov: Just wanted to go back to the time line for additional infrastructure or intrastate projects you're currently working on. I think you noted you plan to announce potentially other projects soon. We're just wondering if construction of these projects would potentially overlap with that of the East Side Express project? Michael Kennedy: Yes, not in '26, but '27 and beyond, that's probably a good assumption. Ned Baramov: Understood. And then I guess, you mentioned the AR contracts on -- or AR will underwrite the project. I was just wondering if the contracts would be in a take-or-pay type of format? Or will there be volumetric exposure from AM's perspective? Michael Kennedy: It just acreage dedication from AR, but because we know where AR drills and the plants are drilling, there's no need for those MVCs because we know the volumes will be there. Ned Baramov: Understood. And then maybe one more, if I could. It seems that curtailments will be used a little bit more to better align the timing of production at AR with gas prices. Can you talk about the impact to AM's results? And does this imply that volumes going forward will have a little bit more pronounced seasonality? Michael Kennedy: Yes. No, I mean we're talking 50 million a day. I think AM gathered 4.1 Bcf. So that's about 1% for maybe 1 quarter of the year. So maybe you're looking at 0.25%. So that doesn't move the needle for AM. Operator: We reached the end of our question-and-answer session. I'd like to turn the floor back over for any further closing comments. Daniel Katzenberg: Thank you, everyone, for joining the second quarter conference call today. If you have any follow-up questions, please reach out. Have a good day. Operator: Thank you. That does conclude today's teleconference. You may disconnect your line at this time, and have a wonderful day. We thank you for your participation today. Before you buy stock in Antero Midstream, consider this: The Motley Fool Stock Advisor analyst team just identified what they believe are the 10 best stocks for investors to buy now… and Antero Midstream wasn’t one of them. The 10 stocks that made the cut are built for long-term growth and could produce monster returns in the coming years. Consider when Netflix made this list on December 17, 2004... if you invested $1,000 at the time of our recommendation, you’d have $397,405!* Or when Nvidia made this list on April 15, 2005... if you invested $1,000 at the time of our recommendation, you’d have $1,344,091!* That performance is why people listen. With a track record of beating the S&P 500 by 4x, Stock Advisor offers a distinct advantage. Don't miss the latest top 10 list, available with Stock Advisor, and join an investing community built for the long haul. See the 10 stocks » *Stock Advisor returns as of August 7, 2026. This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability. The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy. Antero Midstream (AM) Q2 2026 Earnings Call Transcript was originally published by The Motley Fool

Image source: The Motley Fool. Thursday, July 30, 2026 at 11 a.m. ET Vice President of Investor Relations - Daniel Philip Katzenberg CEO and President - Michael N. Kennedy CFO - Brendan E. Krueger Senior Vice President of Liquids Marketing and Transportation - David Cannelongo Senior Vice President of Natural Gas Marketing - Justin Fowler Operator: Greetings, and welcome to the Antero Resources Corporation Second Quarter 26 Earnings Call. At this time, participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce Daniel Philip Katzenberg, Vice President of Investor Relations. Daniel Philip Katzenberg: Thank you, you may begin. Thank you for joining us for Antero's second quarter 26 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 N. Kennedy, CEO and President Brendan E. Krueger, CFO David Cannelongo, Senior Vice President of Liquids Marketing and Transportation; Justin Fowler, Senior Vice President of Natural Gas Marketing. Michael N. Kennedy: I will now turn the call over to Mike. Thank you, Daniel, and good morning, everyone. I will start on Slide 3 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 4 titled Significant Reduction in Cash Costs. The cost reductions we realized during the second quarter was just the beginning of lower cost to come at Antero. In June, we announced a cost reduction initiative that will significantly improve our margins. We are forecasting our cash cost to decline by over 25% 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 basins 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 direct firm transport is attractive and will be retained. 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. NGLs. Next, on Slide number 5, we provide details on our margin enhancement. $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 basin. 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 3 categories. First, we have 2 financial transactions that we entered into early this decade that come to an end. The overriding royalty interest transaction and the VPP. Overriding royalty interest transaction return threshold to the counterparty was met in the second quarter leading to the Martica entity being dissolved on June 30, and resulting in an increase of $60 million of annualized cash flow beginning in third quarter of 26. 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 28. And third, the remaining $105 million of margin improvements through 2028 will primarily come through optimizing our natural gas firm transportation portfolio increasing dry gas development. 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. 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 am going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, David Cannelongo for his comments. David Cannelongo: Thanks, Mike. I would like to begin by highlighting the strong realized C3+ pricing achieved during the second quarter of this year. Antero's realized C3 plus price was $44.26 per barrel, up $6.41 per barrel compared to the second quarter of last year 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 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 6, U.S. propane exports averaged 2.03 million barrels per day during the second quarter of 26. Increase of 170 thousand barrels per day compared to the same period last year. Additionally, propane exports hit a new weekly high of 2.63 million barrels per day this May, with another weekly export number also above 2.6 million barrels per day reached in July. According to the EIA. These new highs surpassed the previous record by 300 thousand barrels per 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 thousand barrels per day in April, the most recent month of EIA data. Surpassing the previous record of 661 thousand barrels per 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. Going forward, additional LPG terminal expansions through 2027 will add another 1 million barrels per day of 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. 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 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 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. As shown on Slide number 7 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 8 to discuss shipping dynamics. VLGC 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 U.S. LPG exports. However, 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 26 and all of 2027. 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 will now turn it over to our Senior Vice President of Gas Marketing, Justin Fowler, for his comments. Justin Fowler: Thanks, David. I will start on Slide 9 that highlights the strong fundamental outlook for natural gas that we see through 2030. The 2 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 nontraditional 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. 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 demand to our regional profile. We have shown this slide in the past and each time the number of projects and implied regional demand estimate has increased. 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. 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. 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 E. Krueger, CFO of Antero Resources. Brendan E. Krueger: 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 25, we spud 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 increased our net production by approximately 125 million cubic feet equivalent per day and add 15 net drilling locations. I will discuss both of these updates in more detail momentarily. Turning to our financial results. On the right hand side of the slide, Our adjusted EBITDA 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 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. 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 1 thousand to over 2 Bcf per 1 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 thousand dry gas locations, we view this acreage footprint as the largest undrilled Tier 1 dry gas position left in the U.S. Next, Slide 14 looks more closely at the acquisitions we closed. In July, we invested $315 million on assets in our core Western Virginia Marcellus footprint. These transactions immediately add 125 million per day of net production and were acquired at a combined valuation of just 4x EBITDA and a free cash flow yield over 20%. The chart on the right illustrates how we have been able to increase our net production has increased from 3.3 Bcfe per day at the beginning of 25 to an expected 2026 exit rate of 4.5 Bcfe per day. Or 36% growth over that time period. Notably, we have been able to accomplish this net production growth without impacting the basins gross production. Which you can see has remained essentially flat at 35.5 Bcf per day over that time period. To emphasize a point that we have 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 significantly strengthened relative to the beginning of 2026. Further, our share count is down 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. And at this time, we will conduct our question-and-answer session. And our first question comes from Kevin MacCurdy with Pickering Energy Partners. Please state your question. Kevin MacCurdy: Hey, good morning and thanks for taking my question. there is 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 market gas marketing portfolio in total what would make you get more aggressive with long term sales agreements? Michael N. Kennedy: Yes. I think we touched on in our 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. Now we are at the end of that and so we can select the best pass and those paths are competing with the power deals and comparing them. So it has to compete with the broader energy markets. The 1 that was recently in our backyard, I mean, we have been in discussions with them for almost a decade. So we are well aware of that 1. They actually, you know, have a contract on some of our midstream. So in discussions with them, you know, just the uncertainty around the price the timing, the execution, all of that, really did not meet our return hurdles. So when we look at projects, it has to meet all of those 3, and that 1 just was not attractive to us. Kevin MacCurdy: Okay. Appreciate the details there. And 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 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 N. Kennedy: Yes, definitely. You saw that in the quarter. We were not planning on buying back shares in the quarter, but the equity price went, obviously, that was very attractive to us. I think you heard in Brendan's summary comments, production up 20%, cash costs down 10%. Liquids pricing up significantly. EBITDA up 57% and you look at the share price and it is the same as last year. So I would say that you could elevate the ranking of that and that it is very attractive. to us at these levels. Appreciate it. Thanks. Operator: Your next question comes from David Daoud with Truist. Please state your question. Analyst: it is 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. It looks like you are at 4 rigs currently, maybe putting some of that growth capital to work. Could we maybe just get an update there? Michael N. Kennedy: Yeah. So it is 4. 1's in transition. So it will be down to 3 here in the next month. But we are drilling those 3 pads that we talked about, but are on the-- kind of on the difference between maintenance and growth capital. So you also have some capital. So our maintenance case just to remind everyone was $1 billion. Our growth is $1.2 billion of capital this year. Right now, we are 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 we still that is yet to be determined whether we deploy that. We have said in the past, $3+ gas that is probably something that we would deploy but we will just have to determine that when we get there. Okay. And so if you complete those wells, then that takes 2027, I imagine, for-- Yeah. Yeah. Yeah. Okay. Okay. Thanks, Mike. And then maybe just a follow-up. Curious on the cost optimization plan, the $0.35 reduction in realizations obviously being offset by the big move lower on the cost side. Just how dynamic is that plan? Just curious, like, 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 FTE, or is that or is that just simply just recontracting into lower market rates? Yes. So some of that is 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 is definitely you know, coming from the end users it is a demand pull. And so when we came out with this cost presentation, and strategy a couple months back, we received so many reverse inquiries along our firm transport paths in Justin hit on that slide too, all of that 7 Bcf of demand that is 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 is baked into this 300 million that we have been talking about, that would be incremental. But that is something we are looking at. You kind of saw the first sign of that with our guidance, how we reduced our cash costs also reduced the realized price, but we are 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. Got it. 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: Just following up on the $300 million of kind of margin enhancement that you all first unveiled in that presentation last month. Just to clarify, if that was extended a few years kind of beyond that 2028 target, is it safe to say that $300 million number would move materially higher if you just extended the timeline? Michael N. Kennedy: Absolutely. We just focus on 3 years. We thought that was kind of the investment horizon. If you are looking past that, for the 5 years, I think it drove growth of about 6 to $700 million that is great. John Freeman: And then just follow-up, Mike, as you sort of see this play out with 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, like how do you see that mix sort of changing versus if we call it kind of 2-thirds kind of out of basin at the moment? Like just how do you see that evolving over the next several years? Michael N. Kennedy: Yes. Right now, we are kind of thinking a third with FT long-haul, a third is liquids and a third is generally local sales. So if you just put that in natural gas terms, it is about 50-50. The word we like to use you are going to hear a lot of 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 cell of the natural gas, about half on the long haul transport and half local. that is great. Appreciate it. Mhmm. Operator: Your next question comes from Arun Jayaram with JPMorgan. Please state your question. Arun Jayaram: Yes. 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 are halfway or nearly halfway there. The integration of HD, but give us a sense of how that will play out over the next couple of years. And, I am 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 N. Kennedy: Yes. We put in the 3 buckets. We put some timing around that. That first 1 we talked about the override. That starts immediately. That started in July. that is a $0.04 uplift. $0.04 improvement on the cost structure at $60 million And we have the VPP in July 2027. that is an incremental $30 million Throughout that time, you are going to see this optimization of our natural gas firm transport. it is harder to predict the exact timing of that, but we are in significant negotiations around those type of improvements. So that is more ratable. Then the $105 million of total liquids at year-end 2028. Got it. Got it. Great. Arun Jayaram: And my follow-up, Mike, clearly 1 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 and P price taker wondering if you could comment on how you think Antero's positioned for this, call it, shift in market dynamics? Michael N. Kennedy: Yes. We are extremely well positioned. Go back 15 years and we were trying to create markets. There was no local gas markets. So we had to sign up for all the firm transport that came our way. Those are expiring now. So now we get to pick the best ones. Some of it ended up in terrific markets. Some of it did not end up as well as we had hoped. So we will be able to compare those now to the local demand So it is perfect timing for us. that is 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 kind of international. there is an arb there, in our strategy has been to remain on the spot there. So we have not entered into firm agreements with that price. Then local is going to have to compete with that. that is why we are highly selective. You are going to see a bunch of announcements that along the way we are not participating and then you can be assured that is because our opportunity set is greater than what those opportunities were. So highly selective, it is got to be more near term, it is got to be price certain and it is got to compete with firm transport and liquids production. that is clear. Thanks a lot, Mike. Operator: Your next question comes from Doug Leggate with Wolfe Research. Please state your question. Doug Leggate: Thanks guys. I appreciate you having me on. So Brendan, this is maybe for you, but in your deck, you are walking through pretty clearly the reduction or the planned reduction in cash cost, and then it is been beaten pretty well this morning. But My question is, why are you, hold on 1 second. Why are you offsetting that with price realizations? I am trying to understand what this implies for your market view of gas going forward. Brendan E. Krueger: Yes. Sorry, I did not hear that last part. Doug, could you repeat that? Yeah. Sorry. Someone's dialing in my system. Why are you offsetting it with price realizations? I am trying to understand what that signals for your view on the macro. Yes. 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 are willing to take your product in basin You will, of course, have a lower realized price that they are buying in basin. But from a margin standpoint, you are picking up $0.35 a margin. So they are taking on the transport to move it, but they are giving you a premium on the price versus what you otherwise would have sold if you were just selling in basin. So cost coming down $0.70 offset by realizations coming down by about half. So your margins still are getting picked up by $0.35 overall. So we are quite enthused by what we are seeing on the demand-pull, like Mike mentioned. This market where it used to be we have to find a place for your gas, it is 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? We need by this period of time? 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. But all of these factor into our decisions, but they are all should lead to margin improvement on our natural gas in a big, big way. I appreciate that color. Thanks. Doug Leggate: My follow-up is a quick 1 hopefully. Obviously you have drilled your first dry gas pad in quite a while. You have not completed them, obviously, but whether we end up with a squishy winter or not, what is the kind of road map to whether you would go back to growth in 2027? Michael N. Kennedy: Go back-- we have 2 pads in there. Kate-- well, our first 1, the Flanagan pads that Brendan reviewed the results. The next 2 are Katy and Walters right next to it. They will be drilling whether we complete them like you mentioned. Will be natural gas price dependent But I fully anticipate completing them if it is $3 gas plus. And we can hedge that and also hedge local basis at very attractive levels. So right now, based on those markets that we are 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 will not complete them in the fourth quarter. that is really helpful. Thanks a lot. Mhmm. Operator: Your next question comes from Betty Jiang with Barclays. Please state your question. Analyst: Good morning. I want to start with a follow-up to Arun's question about costs. This GP and T piece is there are many drivers lowering that GP and T over time. Could you just unpack like how much of the reduction is coming from a shift towards the HG dry gas assets like whether that is 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? Michael N. Kennedy: No, it is 50% of it-- it is over $50 million this year, I should say, is HG has outperformed our expectations definitely 2 of the 3 rigs that we have running right now the 4 is in transit, but 2 of the 3 are on HT pads. 1 of them those are liquids, 1 of them is a dry gas. So incrementally HG is outperforming and will have more production than we assumed. So there is a little bit of that. But it is not terribly material. HG does sell we do sell the majority of those volumes in basin. 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 demand pull and shift to just some dry gas development also with those transactions expiring? Yeah. Brendan E. Krueger: If you look at that too, if you look at that $300 million that we have laid out there too, Betty, I think about 250 million of that. So all of the liquid 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 driven by that shift to more dry gas and HG. Got it. And then sorry for So on a per unit basis, if you grow the dry gas piece going forward, how much would that improve your GP and T? Well, I think on the GP and T front, so you are like we have said that the $300 million just to break it down, so we have got $0.35 of margin improvement, $300 million is about $0.20. The other $0.15 comes from HG. $0.35 of margin improvement, $0.20 is in that $300 million we talked about, $0.15 is HG. And then the other, if you think about it from a cost standpoint, again, we are down $0.70 on cost. Almost all of that $0.70 reduction is going to come in the form of GP and T coming down I mean, that is the driver of that. 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. Got it. Thank you. And if I could sneak in 1 quick 1. In your scenario, how much do you, does your in-basin exposure grow over the next few years? From the 20% currently? Yes. Mike talked about it. So you will likely go from what today is 2-thirds call it 2-thirds, 1-third in terms of 2-thirds going to the LNG fairway, a third going elsewhere. You will have that be more 50-50 on a go forward basis. Thank you. That will take some time to play out though. That will be over. Call it, a 5 year period for that to play out. Got it. Thanks. Operator: Your next question comes from Phillip Jungwirth with BMO. Please state your question. Phillip Jungwirth: Yes, thanks. Good morning. I know Antero Midstream has a separate call, but I was hoping you could talk about the Eastside Express pipeline, which is the first intrastate regional line. Just how does this benefit Antero and just confidence in executing a project like this. And then just separately, just what is the interest and difficulties in building an intrastate pipeline? Just thinking like shorter distances, like West Virginia to Ohio, for instance, where there should be strong demand pull in the future. Yes. Michael N. Kennedy: No, we are 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 thousand that Brendan talked about. This is our first regional pipeline East West that will cover approximately over 30 miles of our acreage position in the dry gas window, and it will 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, farmed this out Everyone's kind of familiar with that Stonewall Pipeline. that is when we farmed that project out because we just did not have the ability to execute on that. that is no longer the case. We are the builder of these regional pipelines now in West Virginia. And Antero Resources acreage position and strength investment grade goes with that over 1 million acres, 1 thousand 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 1 is probably North South We have 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 in Tier 1 Marcellus with all the demand. that is been publicized. And Antero Midstream will be the pipeline to build it. We will not farm those type of opportunities out anymore. Okay. Great. Phillip Jungwirth: And then Antero has also always been a leader in realizations for your products, whether gas or C3 plus We have seen peers increase their focus on the marketing side of late, 1 with a large acquisition. Just as you look at what they are 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? And if so, how do you go about that? Michael N. Kennedy: Yes. We think we already have that. I mean we have been 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. Think we have 28 pads that we market along. And also with our liquids too, David and his team has been a leader in that. First 1, signing up on ME 2, pretty much signed up on every single project From an LPG or ethane standpoint, I 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. 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. Sounds good. Thanks. Mhmm. Operator: Your next question comes from Jacob Roberts with Goldman Sachs. Please state your question. Jacob Roberts: Good morning, team, and thanks for taking my question. I just wanted to ask on hedging, specifically in 2027. Just curious how your team is approaching the right hedge levels for next year and if there is anything you are 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? Michael N. Kennedy: No, we are in a good position. We are actually ahead of where we were this time last year for 2027. We have got 34% hedged. I think it is 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 is if the collars, if those are attractive levels with a lot of call skew, we have been favoring more of the swaps of late. I think you will see us continue to increase that We are in great position, so we are not going to be rushing into down markets. But if you see upticks in the gas price in 2027, you may see us add a little bit When we do acquisitions like this recent 1, we do hedge it, so you saw an increase in our volumes They are hedged volumes by, I believe, around $100 million today and 26 million and 80 million in 2027. So when we do acquisitions, will hedge them just like we did this 1, these couple of acquisitions we did in July. I appreciate that. Jacob Roberts: And then my follow-up maybe on the $315 million in the Western Virginia property acquisitions for the quarter. 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, you know, the number of opportunities you are seeing in the market? Michael N. Kennedy: Yes, does. We have a lot of non-op working interest entities out in our basin. I mean, you have 1 million acres, you have a large opportunity set, a lot of non-op working interest. We are in discussions with them, and they all tend to have acreage around their non-op position too that they are not able to drill or operate. So as part of the transaction, we want to buy in as much working interest as we can and get the acreage as well. Our goal 1 of our strategies is obviously to increase our production it is really the interest of production that is from the growth standpoint already on our acreage. So gross being flat, but Antero owning more and more of that the interest in that production. And then obviously consolidating the acreage around the Eastside Express, that is where this acreage was. 15 locations, couple pads, right on that Eastside Express. So that was very attractive to us. We continue to see these type of opportunities, and we will continue to look at them. Generally, you know, it is 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 will develop the pads and take advantage of those type of valuations. Thanks, guys. Mhmm. Operator: Your next question comes from Leo Mariani with ROTH Capital. Please state your question. Leo Mariani: 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 how much of the synergies you have captured thus far in 2026. And do you think that could be more upside to that number over time? Michael N. Kennedy: Will be more upside. it is still at that $80 million level. But that is not capturing what I mentioned earlier in my remarks. We actually have 2 rigs of our 3 on the HG acreage. that is well ahead of schedule. We were contemplating when we underwrote the transaction, just 1 rig. So that is going to accelerate the volumes on the HG, which is going to accelerate the transaction value to us. But there is a lot of pad ready there. They have already got all the infrastructure. Being able to put those pads on right into the local gas markets in the winter. We think there will be elevated pricing. that is all entered into the decision. And obviously, the well results are terrific. We are going to put on the second set of wells from the 1.22 thousand pad on 17. Those continue to outperform the 1.2 thousand North. So we will continue to update that number. But just for 2026, the $80 million is pretty much locked in. But that will go higher in 2027 as we put these new pads on. Leo Mariani: Okay. Appreciate that. And in terms of the gas price environment, clearly, it is relatively weak right now. And I guess, we are not too far off from the shoulder season. Are you guys thinking about maybe pushing some of your turn-in-lines kind of over to the winter when pricing is better? Just any thoughts on just trying to manage production a bit, to kind of match price here? Michael N. Kennedy: Yeah. I am glad you brought that up. that is actually the curtailments that we outlined. that is a new feature for Antero. We talked about cost structure coming down in the but we also have a slide out on our in our deck that showed the commitments coming down. Quite dramatically. And some a lot of those commitments around the on the liquids. So we now have flexibility to look at our lean pads in that 61, 71 Btu and we do not have to produce them where in years past we would have because there would have been MVCs with them. We now have ultimate flexibility, so that is a new feature that we are excited about. The ability just forecast, hey. look, September could be weak. We mentioned it is under $2, to shut in or have curtailments on those wells and bring them on more into November, December timeframe when the prices are higher. We very much have that flexibility now and that is something positive for us. So we are excited about that. Okay. And that is kind of basically baked into the guidance you have laid out here. We are hopeful that we continue to add abilities to take advantage of those opportunities. Okay. Thank you. Operator: Your next question comes from John Abbott with Texas Capital. Please state your question. John Abbott: Hey, good morning all. Thanks for taking my questions. For my first 1, 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? 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 have learned to future pads? Michael N. Kennedy: Yeah. No. it is a terrific result for us. So this 2,000 pounds of sand and 38 acre spacing is what we traditionally done in the liquids. that is what we have done kind of our go to for the last 10 years in the liquids. So we can play with that spacing. I know on the HG dry gas pads, we are going 1.06 thousand interlaterals and going up to 2.5 thousand to 3.5 thousand pounds of sand. The water going in between 35 barrels per foot and 50 barrels per foot. So a lot of optimization to occur. But to have a 2,000-pound, 38 interlateral spacing and have it be over 2 Bcf per thousand was a terrific result for us. The lateral length just adds to the economics, brings that dollar per foot on the CapEx at $1.35 thousand. I mean, you are increasing proppant by 2.5 times. And your well cost is down 30% that is a lot of that is lateral length as well. So drilling times and completion times So feel really good about that. John Abbott: We have 1 thousand 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. I appreciate that color. For my follow-up, on the lateral of more than 24 thousand feet, how do the economics compare with your current average lateral? And excluding lease geometry, are there any limits to extend laterals beyond that? Michael N. Kennedy: No. We just drilled that. We have not put that on yet. that is actually on an HG pad. On our 12 o 4 north pad. it is it is 6 wells, average about 19 thousand per well. So it will be terrific for us. So we do not have the results on that yet. But all these longer laterals that we have been drilling obviously, lot of them are now coming from HG because they did a really good job of planning along 1 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. So that is something we are interested in. We are going to try to replicate that with 2 different rows in our dry gas to do the exact same thing. But we have no limitations right now. I think you will see the lateral lengths continue to just go longer and longer. Makes sense. Thanks guys. Operator: Next question comes from Subash Chandra with Stonex. Please state your question. Analyst: Hey, Mike. I wanted to confirm couple of things. So pro form a for everything, the acquisition, the cost reductions, Is maintenance CapEx still at that $1 billion And is the growth price hurdle price for Henry Hub $3? Brendan E. Krueger: I do not know about the second part, but the first part, correct. it is still $1 billion Subhash, I did not catch it, the second part of your question. Michael N. Kennedy: Yes. So the second part is Oh, right. No, it is a real world question would have been in the beginning of the year. Right now, it is where liquids prices are? I still think $3 generally in a mid cycle case, but that is more in that $35 to $40 NGL realized price. NGLs are well above that. Think today, our NGL barrel is at 45 doll dollars. David's confirming that. So that is good. But that is okay. Look. Currently, this morning, we are $45 per barrel. So that would put that a bit lower. You know, our liquids development is really kind of more on a steady state of maintenance. So the true growth capital is more around the dry gas. So $3 is probably a good number to think about. Okay. Great. And a follow-up on HG. If you look at it this way, but it is a second rig, are you still drilling the PUDs out? Have you gone into somewhat maybe the 2P that you thought you might have acquired with the acquisition? So on the 1.2 thousand and 17 pad, the 17 has been elevated All of them I think were in the proved. 1.2 thousand though, is on the schedule for 27, and that would have been in the 2 p but that is now been pushed up just with the performance of the results that we have seen. So right now those have been improved, but 27 drilling will get some of the 2P into the portfolio. Okay, great. Thank you. Mhmm. Operator: Your next question comes from Paul Diamond with Citi. Go ahead with your question. Paul Diamond: Thank you. Good morning. Thanks for taking the call. Just a quick 1 circling back on curtailments. I guess talked about the coming quarter is kind of already being baked in the guidance. I guess as we think about the contract optimization you talked about, how should we think about, I guess, willingness or ability to do so to a greater degree over time, or is this, like, the level you expect to stay at? This level of modulation? Michael N. Kennedy: Yeah, we will see. I mean, right now, we do have some legacy pads in that 61, 71, 81 Btu range. That generally are uneconomic if you are below if you are around that 1.50 to $1.75 But those are about the only pads where we have it in that lean gas area. Right now. So that is about it. it is about 50 million a day, right now of pads that were drilled in that kind of BTU regime that in years past we still would have produced because it would have had MVCs on it, but we no longer have those MVCs. So that is about all we have right now. The rest is either 1.2 thousand plus Btu or sub-1.1 thousand Btu. So those really would not qualify for this curtailment strategy. Paul Diamond: Got it. Makes perfect sense. And then just talking a bit about-- you guys talked about a shift in 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 its own variability from that 50-50 split between dry gas and gas and liquids Yes. Michael N. Kennedy: We generally have a growth maintenance program. So we want to own a more percent of it, but keep the gross 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. But generally, what we have planned is 3 rig program, 2-completion crew and then continue to increase our percentage ownership of the gross, which keeps volumes in the basin flat, overall flat, but we just own more of it. Good. Appreciate the clarity. I will leave it there. Yep. Operator: Your next question comes from Nitin Kumar with Mizuho Securities. Please state your question. Analyst: 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 had this transportation portfolio, which helped you sell gas in fairly liquid markets. And 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 N. Kennedy: Yeah. We think a lot about it. Actually, that is 1 of the when we say risk adjusted, probably 2 of the 3 parameters I would look at, obviously, price being 1, but also timing and execution is really around the counterparty So we think a lot about that. If we do deals, the credit needs to be there, you will see us get LCs or some sort of credit assurance We are not credit agnostic. We have a big credit actually, team just around already having significant firm transport for over a decade. So we are very cognizant of the credit and the credibility of the project really goes into whether or not we participate. Understood. And then 1 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. Then you also talked about that number growing. My understanding was that as far as the contract rollovers are concerned, you know, that essentially a 2028 kind of timeline. 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? Yes, that is correct. You have that correct. Main 1 you can think about is the ATEX. You know, that is the 1 that we always cite. that is I think $60 million of the 105. that is 20 thousand barrels a day. that is saying the price that it charges, I believe, is around $0.24, $0.25. David's nodding yes again. So it is good. that is ahead of the actual ethane price we received. So obviously we are 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, Utopia, a lot of different ethane markets have been developed over that timeframe. So we no longer need that We, I think, we recover 90 thousand barrels of net ethane over 100 thousand barrels of gross ethane. For our pipeline spec we can be down in the low 70 thousand. So we can easily let that 20 thousand of ethane go and be within spec and it is completely uneconomic. So that is $60 million of the $105 The rest is just optimizing our already transport that expires at the end of 2028. And then the other piece that Mike had mentioned earlier there too is beyond 2028, which is not on that slide, when you have a lot of the gas contracts that come up for renewal where we think you could add another $200 million on top of on top of the $300 million. Understood. Thank you so much. Operator: Thank you. And there are no further questions at this time. So I will now hand the floor back to Daniel Philip Katzenberg for closing remarks. Daniel Philip Katzenberg: Yes. I would 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. And with that, we conclude today's call. All parties may disconnect. Before you buy stock in Antero Resources, consider this: The Motley Fool Stock Advisor analyst team just identified what they believe are the 10 best stocks for investors to buy now… and Antero Resources wasn’t one of them. The 10 stocks that made the cut are built for long-term growth and could produce monster returns in the coming years. Consider when Netflix made this list on December 17, 2004... if you invested $1,000 at the time of our recommendation, you’d have $397,405!* Or when Nvidia made this list on April 15, 2005... if you invested $1,000 at the time of our recommendation, you’d have $1,344,091!* That performance is why people listen. With a track record of beating the S&P 500 by 4x, Stock Advisor offers a distinct advantage. Don't miss the latest top 10 list, available with Stock Advisor, and join an investing community built for the long haul. See the 10 stocks » *Stock Advisor returns as of August 7, 2026. This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability. The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy. Antero Resources (AR) Q2 2026 Earnings Call Transcript was originally published by The Motley Fool

Interested in Antero Resources Corporation? Here are five stocks we like better. Antero Resources reported record Q2 production and $220 million in free cash flow. Production exceeded 4.1 Bcfe per day, up 21% year over year, while adjusted EBITDA rose 57% despite a 16% decline in Henry Hub natural-gas prices. The company targets more than 25% lower cash costs by 2028, reaching $2 per Mcfe. Management expects roughly $300 million in annual margin improvement from transportation optimization, expiring contractual obligations and greater dry-gas development, with the longer-term opportunity potentially reaching $600 million to $700 million. Antero is expanding production and maintaining shareholder returns. It acquired West Virginia Marcellus assets for $315 million, repurchased $38 million of shares during the quarter and expects to exit 2026 producing about 4.5 Bcfe per day, while keeping a $1 billion maintenance-capital framework. Oil’s Outlook Looks Ugly—That’s Why These 3 Energy Plays Matter Antero Resources (NYSE:AR) reported record second-quarter production, higher year-over-year adjusted EBITDAX and $220 million of free cash flow, while outlining a multiyear plan to reduce cash costs and optimize its transportation portfolio as regional natural-gas demand expands. Chief Executive Officer and President Michael Kennedy said the company’s structural changes have reduced earnings volatility. Although Henry Hub natural-gas prices were down 16% from a year earlier, Antero’s adjusted EBITDA increased 57%, supported by production growth, product diversity and lower cash operating expenses. → Why SK hynix Could Be the Best AI Chip Stock to Buy Now 3 Emerging Market Stocks to Buy and Hold for 2026 Quarterly production exceeded Antero’s guidance range and averaged more than 4.1 billion cubic feet equivalent per day, up 21% year over year, according to Chief Financial Officer Brendan Krueger. Total cash operating costs were at the low end of guidance and fell $0.29 per Mcfe, or 11%, from the prior-year period. Antero expects cash costs to decline by more than 25% from 2025 through year-end 2028, reaching $2 per Mcfe. Kennedy said the effort reflects a transition from an entirely liquids-focused development program and entirely out-of-basin sales model toward a more balanced mix of liquids and dry-gas development, as well as in-basin and out-of-basin sales. → Microsoft Just Flipped the AI Spending Narrative Overnight Attention Income Investors: This REIT Is on Sale The company expects approximately $300 million of annual margin improvement by 2028. That figure includes: $60 million of annualized cash-flow improvement beginning in the third quarter of 2026 after the return threshold for an overriding royalty interest transaction was met and the Martica entity was dissolved on June 30. $30 million of annualized cash-flow improvement when a volumetric production payment expires in July 2027. $105 million from optimizing liquids transportation commitments, including ethane and LPG transportation, expected by the end of 2028. $105 million primarily from optimizing natural-gas firm transportation and increasing dry-gas development. Kennedy said the $0.70-per-Mcfe cost improvement is expected to be partly offset by approximately $0.35 per Mcfe of lower price realizations as more volumes are sold in basin. Still, the company expects the shift to improve overall natural-gas margins. Management said its $300 million estimate does not include potential premiums from demand-pull projects seeking access to Antero’s transportation routes. → Carrier Earnings Could Send the Stock to a New All-Time High In response to an analyst question, Kennedy said the margin-improvement opportunity could grow to roughly $600 million to $700 million when viewed over a five-year period rather than the three-year horizon through 2028. Management emphasized its ability to choose among local and long-haul markets as firm transportation agreements approach renewal. Kennedy said local power and data-center-related projects will need to compete with returns available in broader energy markets, including the LNG corridor. Justin Fowler, senior vice president of natural-gas marketing, said announced data-center and power projects are forecast to add 19 Bcf per day of U.S. natural-gas demand by 2030, while LNG and Mexico export growth could contribute another 23 Bcf per day. In Appalachia, four publicly announced projects represent more than 9 Bcf per day of demand, with an additional 3 Bcf per day associated with projects the company has discussed but that have not been publicly announced. Fowler said 6 Bcf per day of the regional projects are either under construction or have reached final investment decision. Antero expects its mix of natural-gas sales to move over time from approximately two-thirds along the LNG fairway and one-third elsewhere toward a more balanced 50/50 split. Krueger said that transition could take about five years. Kennedy said Antero is evaluating opportunities based on price, timing, execution certainty and counterparty credit. He said a recently announced local project did not meet the company’s return hurdles because of uncertainty around pricing, timing and execution. Senior Vice President of Liquids Marketing and Transportation Dave Cannelongo said Antero realized a C3+ price of $44.26 per barrel in the second quarter, up $6.41 per barrel from a year earlier and its highest quarterly realized price since 2022. Cannelongo said geopolitical uncertainty surrounding Middle East supply and transit routes has supported demand for U.S. LPG. U.S. propane exports averaged 2.03 million barrels per day during the quarter, up 170,000 barrels per day from the prior-year period. He also cited new weekly export highs above 2.6 million barrels per day in May and July, as well as a record monthly normal-butane export level of 815,000 barrels per day in April. China’s U.S. LPG market share rose from 10% in June 2025 to an average of 51% in the second quarter, based on third-party shipping data, Cannelongo said. He added that Chinese propane dehydrogenation demand increased 40% from April to July and was forecast to rise further in August. The company expects additional LPG terminal expansions through 2027 to add 1 million barrels per day of export capacity. Antero reported results from its first dry-gas pad in more than 12 years. Krueger said the pad produced a more than 67% improvement in estimated ultimate recovery and a nearly 30% reduction in cost per foot. Lateral lengths nearly doubled, sand intensity increased to 2,000 pounds per foot from 800 pounds per foot, and cost per foot declined 28% to about $900. Estimated ultimate recovery exceeded 2 Bcf per thousand feet, compared with 1.2 Bcf per thousand feet previously. The company also closed $315 million of acquisitions in its core West Virginia Marcellus area in July. The assets add about 125 million cubic feet equivalent per day of net production and 15 net drilling locations. Krueger said the transactions were acquired at a combined valuation of about four times EBITDAX and a free-cash-flow yield above 20%. Antero expects to exit 2026 at roughly 4.5 Bcfe per day of net production, compared with 3.3 Bcfe per day at the beginning of 2025. Management said gross basin production has remained essentially flat at 35.5 Bcf per day during that period. The company repurchased 1.1 million shares for $38 million during the quarter. Kennedy said the repurchases were accelerated after Antero viewed its share price as attractive relative to its production growth, lower costs, stronger liquids pricing and higher EBITDA. For capital spending, Kennedy reiterated a $1 billion maintenance capital framework and said 2026 spending is currently expected to be above that level but below the company’s $1.2 billion growth-capital case. Whether Antero completes additional dry-gas pads in the fourth quarter will depend on natural-gas prices and hedging opportunities, he said. Antero Resources Corporation 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. This instant news alert was generated by narrative science technology and financial data from MarketBeat in order to provide readers with the fastest reporting and unbiased coverage. Please send any questions or comments about this story to [email protected]. The article "Antero Resources Q2 Earnings Call Highlights" was originally published by MarketBeat. View MarketBeat's top stocks for August 2026.

In the past quarter, Antero Resources reported Q2 2026 revenue of US$1,559.84 million and net income of US$278.66 million, alongside record production and continued share repurchases under its multi‑year buyback program. Beyond the stronger earnings, the company raised its 2026 production guidance on the back of recent acquisitions and cost‑cutting efforts aimed at materially lowering cash costs by 2028. With Antero lifting its 2026 production guidance after record output, we’ll now assess how this reshapes the company’s investment narrative. Capitalize on the AI infrastructure supercycle with our selection of the 57 best 'picks and shovels' of the AI gold rush converting record-breaking demand into massive cash flow. Antero’s investment case rests on its ability to convert Appalachia gas and NGL resources into efficient, export‑linked cash flows, while returning capital to shareholders. The key short term catalyst is whether higher 2026 production can translate into sustained margins as cost cuts progress; the main risk remains exposure to gas and NGL price volatility and infrastructure constraints. The latest results strengthen the near term catalyst without materially changing that core risk profile. The most relevant update here is Antero’s decision to raise its 2026 production guidance to 4.15 to 4.2 Bcfe/d, supported by record Q2 output of 4,144 MMcfe/d. That higher volume outlook ties directly into the catalyst of benefiting from export‑linked demand and firm transport access, but it also magnifies the existing risk that weak prices or tighter regulation could weigh on realized margins if market conditions soften. Yet investors should also be aware that if regional basis weakens or regulatory costs rise, the impact on Antero’s margin-focused story could... Read the full narrative on Antero Resources (it's free!) Antero Resources’ narrative projects $7.0 billion revenue and $1.4 billion earnings by 2029. Uncover how Antero Resources' forecasts yield a $48.25 fair value, a 34% upside to its current price. Some of the most optimistic analysts were already modeling about US$7.8 billion in revenue and US$2.1 billion in earnings by 2029, and they see Antero’s integrated position and hedge book as a way to turn today’s production beat into even stronger long term upside, which is a far more optimistic stance than the consensus view and one you should weigh against other possible outcomes. Explore 5 other fair value estimates on Antero Resources - why the stock might be worth over 2x more than the current price! Disagree with existing narratives? Extraordinary investment returns rarely come from following the herd, so go with your instincts. A great starting point for your Antero Resources research is our analysis highlighting 5 key rewards and 1 important warning sign that could impact your investment decision. Our free Antero Resources research report provides a comprehensive fundamental analysis summarized in a single visual - the Snowflake - making it easy to evaluate Antero Resources' overall financial health at a glance. Our top stock finds are flying under the radar-for now. Get in early: Explore 26 top quantum computing companies leading the revolution in next-gen technology and shaping the future with breakthroughs in quantum algorithms, superconducting qubits, and cutting-edge research. We've uncovered the 9 dividend fortresses yielding 5%+ that don't just survive market storms, but thrive in them. The best AI stocks today may lie beyond giants like Nvidia and Microsoft. Find the next big opportunity with these 16 smaller AI-focused companies with strong growth potential through early-stage innovation in machine learning, automation, and data intelligence that could fund your retirement. This article by Simply Wall St is general in nature. We provide commentary based on historical data and analyst forecasts only using an unbiased methodology and our articles are not intended to be financial advice. It does not constitute a recommendation to buy or sell any stock, and does not take account of your objectives, or your financial situation. We aim to bring you long-term focused analysis driven by fundamental data. Note that our analysis may not factor in the latest price-sensitive company announcements or qualitative material. Simply Wall St has no position in any stocks mentioned. Companies discussed in this article include AR. Have feedback on this article? Concerned about the content? Get in touch with us directly. Alternatively, email [email protected]

For the quarter ended June 2026, Antero Resources (AR) reported revenue of $1.56 billion, up 20.2% over the same period last year. EPS came in at $0.76, compared to $0.35 in the year-ago quarter. The reported revenue represents a surprise of +4.41% over the Zacks Consensus Estimate of $1.49 billion. With the consensus EPS estimate being $0.75, the EPS surprise was +1.33%. While investors scrutinize revenue and earnings changes year-over-year and how they compare with Wall Street expectations to determine their next move, some key metrics always offer a more accurate picture of a company's financial health. Since these metrics play a crucial role in driving the top- and bottom-line numbers, comparing them with the year-ago numbers and what analysts estimated about them helps investors better project a stock's price performance. Here is how Antero Resources performed in the just reported quarter in terms of the metrics most widely monitored and projected by Wall Street analysts: Average Net Production per day - Oil: 8,330.00 BBL/D versus the six-analyst average estimate of 9,160.65 BBL/D. Average Net Production per day - Natural Gas: 2847 millions of cubic feet per day versus 2829.67 millions of cubic feet per day estimated by six analysts on average. Average realized prices after effects of derivative settlements - Natural gas: $3.18 per thousand cubic feet compared to the $3.23 per thousand cubic feet average estimate based on five analysts. Average Net Production per day - Combined Natural Gas Equivalent: 4,144.00 MMcfe/D versus the five-analyst average estimate of 4,104.26 MMcfe/D. Average realized prices after effects of derivative settlements - Oil: $/78.6 versus $/79.13 estimated by four analysts on average. Production - Natural gas: 259.00 Bcf compared to the 257.32 Bcf average estimate based on three analysts. Production - Oil: 758.00 MBBL versus the three-analyst average estimate of 811.08 MBBL. Average prices before effects of derivative settlements - Natural gas: $2.66 per thousand cubic feet versus the three-analyst average estimate of $2.72 per thousand cubic feet. Revenue and other- Natural gas sales: $688.48 million versus the three-analyst average estimate of $788.5 million. The reported number represents a year-over-year change of 0%. Revenue and other- Marketing: $56.07 million compared to the $31.09 million average estimate based on two analysts. The reported number represents a change of +66.2% year over year. Revenue and other- Oil sales: $59.58 million versus $67.78 million estimated by two analysts on average. Compared to the year-ago quarter, this number represents a +76.8% change. Revenue and other- Natural gas liquids sales: $587.71 million versus the two-analyst average estimate of $623.92 million. The reported number represents a year-over-year change of +22.3%. View all Key Company Metrics for Antero Resources here>>> Shares of Antero Resources have returned -3.6% over the past month versus the Zacks S&P 500 composite's +1.9% change. The stock currently has a Zacks Rank #3 (Hold), indicating that it could perform in line with the broader market in the near term. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Antero Resources Corporation (AR) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Our analysts just identified a stock with the potential to be the next Nvidia. Tell us how you invest and we'll show you why it's our #1 pick. Tap here. Management is transitioning the company from a 'producer-push' era to a 'demand-pull' era, leveraging expiring firm transportation (FT) commitments to select higher-margin sales points. Structural margin improvements led to a 57% year-over-year increase in adjusted EBITDA despite a 16% decline in Henry Hub natural gas prices. The company is shifting toward a more balanced development program, increasing dry gas production to meet surging regional demand from power projects and data centers. Operational efficiency gains were highlighted by the first dry gas pad in 12 years, which delivered a 67% improvement in estimated ultimate recovery (EUR) and a 28% reduction in cost per foot. Antero's position as the second-largest NGL producer provides a unique competitive advantage, allowing the company to be highly selective in partnering with local power projects. The HG Energy acquisition integration is ahead of schedule, with two rigs currently operating on that acreage to accelerate volume and synergy capture. Management targets a 25% reduction in cash costs to $2 per Mcfe by year-end 2028, driven by the expiration of legacy financial transactions and FT portfolio optimization. The $300 million annual margin improvement plan assumes $0.70 in cost reductions partially offset by $0.35 in lower price realizations as more product is sold in-basin. Natural gas demand is forecasted to grow by 37% by 2030, driven by 19 Bcf/d from data centers/power and 23 Bcf/d from LNG and Mexico exports. Future development remains price-dependent; management indicated that completing certain dry gas pads in Q4 2026 will require natural gas prices of $3 or higher. The company expects to move toward a 50-50 balance between long-haul transport sales and local in-basin sales over the next five years. The Martica overriding royalty interest transaction was dissolved on June 30, 2026, which is expected to increase annualized cash flow by $60 million starting in Q3. The VPP (Volumetric Production Payment) is set to expire in July 2027, providing an additional $30 million annualized cash flow uplift. Antero invested $315 million in July for core West Virginia Marcellus assets, adding 125 Mmcfe/d of production at a 20% free cash flow yield. Management introduced a new curtailment strategy, utilizing increased flexibility to shut in lean gas wells during low-price periods (sub-$2) now that legacy minimum volume commitments (MVCs) have expired. One stock. Nvidia-level potential. 30M+ investors trust Moby to find it first. Get the pick. Tap here. Management emphasized that local projects must compete with broader energy markets and LNG fairway pricing to attract Antero's volumes. One specific local project was declined because the pricing, timing, and execution certainty did not meet the company's risk-adjusted return hurdles. Share buybacks have been elevated in priority due to the disconnect between strong operational performance (EBITDA up 57%) and a stagnant share price. The company repurchased 1.1 million shares for $38 million in Q2, despite not originally planning to buy back shares during the period. A significant portion of the $105 million liquids margin improvement comes from letting the ATEX ethane contract expire at the end of 2028. Management stated the contract is currently uneconomic at a price of $0.24-$0.25., and new market developments allow them to meet pipeline specs without it. Antero Midstream will now act as the primary builder for regional pipelines, avoiding 'farming out' infrastructure opportunities to third parties. The Eastside Express will span 30 miles across the dry gas acreage, with potential for future north-south expansions to connect to additional demand centers.

This article first appeared on GuruFocus. Production: Company-record quarterly production averaged over 4.1 Bcfe per day, a 21% increase year-over-year. Adjusted EBITDAX: Increased 57% year-over-year. Free Cash Flow: Generated $220 million of free cash flow. Share Repurchases: Repurchased 1.1 million shares for $38 million. Cash Operating Costs: Total cash operating costs declined $0.29 per Mcfe, or 11% from the year-ago period. Realized C3+ Price: $44.26 per barrel, up $6.41 per barrel compared to the second quarter of last year. Acquisitions: Invested $315 million on assets, adding 125 million cubic feet per day equivalent of net production. Warning! GuruFocus has detected 5 Warning Signs with AR. Is AR fairly valued? Test your thesis with our free DCF calculator. Release Date: July 30, 2026 For the complete transcript of the earnings call, please refer to the full earnings call transcript. Adjusted EBITDA increased 57% year-over-year despite a 16% decline in Henry Hub natural gas prices, driven by scale, product diversity, and lower costs. Announced a cost reduction initiative targeting a 25% decline in cash costs to $2 per Mcfe by year-end 2028, with $300 million in annual margin improvements. Record quarterly production of over 4.1 Bcfe per day, a 21% year-over-year increase, and $220 million in free cash flow. Strong NGL pricing with realized C3+ price of $44.26 per barrel, the highest since 2022, supported by record U.S. LPG exports and rising global demand. Successful dry gas pad results showed a 67% improvement in EUR and a 28% reduction in cost per foot, with over 1,000 Tier 1 dry gas locations. Natural gas prices remain weak, with Henry Hub down 16% year-over-year, and September prices expected under $2. VLGC freight rates are elevated due to geopolitical disruptions, creating headwinds for U.S. LPG exports despite a robust new vessel order book. The shift to in-basin sales is expected to lower price realizations by $0.35 per Mcfe, partially offsetting cost savings. Uncertainty around the timing and execution of regional power and data center projects, with some failing to meet risk-adjusted return hurdles. Growth capital deployment for dry gas development remains contingent on $3-plus gas prices, with potential delays if prices weaken. Q: 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?A: Michael Kennedy (CEO): 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. So we can select the best paths and those pads are competing with the power deals comparing them. It has to compete with the broader energy markets. The one recently in our backyard, we've been in discussions with them for almost a decade. They actually have a contract on some of our midstream. Just the uncertainty around the pricing, the timing, the execution, all of that really didn't meet our return hurdles. So when we look at projects, it has to meet all of those 3, and that one just wasn't attractive to us. Q: I was hoping we can maybe just touch on the growth CapEx and how we should be thinking about that impacting 2026. It looks like you're at 4 rigs currently, maybe already putting some of that growth capital to work. Could we maybe just get an update there?A: Michael Kennedy (CEO): It's 4 rigs in transition. It will be down to 3 here in the next month. But we are drilling those 3 pads that we talked about that are on the difference between maintenance and growth capital. Our maintenance case is $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, $3-plus gas is probably something that we would deploy, but we'll just have to determine that when we get there. Q: Just following up on the $300 million kind of margin enhancement that you 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 time line?A: Michael Kennedy (CEO): Absolutely. We just focused on 3 years. We thought that was kind of the investment horizon. If you're looking past that for the 5 years, I think it grows about $600 million to $700 million. Q: 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 to 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?A: Michael Kennedy (CEO): We put in the 3 buckets with some timing around that. The override starts immediately in July, that's a $0.04 uplift or $0.04 improvement on the cost structure at $60 million. We have the VPP in July of '27, 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, but we're in significant negotiations around those type of improvements. Think about that as more ratable and then the $105 million at year-end '28 for liquids. Q: So Brendan, this is maybe for you. But in your deck, you're walking through pretty clearly the planned reduction in cash costs. I think it's been beating pretty well this morning. My question is, why are you offsetting that with price realizations? I'm trying to understand what this implies for your market view of gas going forward?A: Brendan Krueger (CFO): It goes back to the world shifting from 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 that they're buying in basin. But from a margin standpoint, you're picking up $0.35 of margin. 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. So costs coming down $0.70 offset by realizations coming down by about half. So your margins still get picked up by $0.35 overall. Q: I want to start with a follow-up to Arun's question about costs. This GP&T pieces, there's many drivers lowering that GP&T over time. Could you just impact like 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?A: Michael Kennedy (CEO): 50% is HG. It's over $50 million this year. HG has outperformed our expectations. 2 of the 3 rigs that we have running right now are on HG pads. One of them is liquids, one of them is a dry gas. So incrementally, HG is outperforming and will have more production than we assumed. HG does sell the majority of those volumes in basin. So those will have lower transport costs associated with them. But the majority of it is just a shift to the demand pull and shift to some dry gas development also with those transactions expiring. Q: I know in term mystery has a separate call, but I was hoping you could talk about the East Side Express Pipeline, which is the first interest state regional line. Just how does this benefit Antero and just confidence in executing a project like this? And then just separately, just what's the interest in difficulties in building and interstate pipeline team. Just thinking like shorter distances like West Virginia and Ohio, for instance, where there should be strong demand pull in the future.A: Michael Kennedy (CEO): 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 with 1,000 locations. This is our first For the complete transcript of the earnings call, please refer to the full earnings call transcript.

Antero Midstream Corporation AM reported second-quarter 2026 earnings of 24 cents per share, which missed the Zacks Consensus Estimate of 27 cents by 11.1%. The bottom line declined 7.7% from 26 cents in the year-ago quarter. Revenues of $327.24 million beat the consensus mark of $322.31 million by 1.5%. The top line increased 7.1% from $305.47 million a year ago. Higher gathering and compression volumes supported the top line, while elevated operating and interest expenses weighed on earnings. Processing and fractionation capacity remained fully utilized. Antero Midstream Corporation price-consensus-eps-surprise-chart | Antero Midstream Corporation Quote Gathering and compression revenues from Antero Resources rose to $271.51 million from $248.90 million a year ago. The reported figure was above our estimate of $260 million. The increase reflected stronger system activity and a 3% rise in the average realized gathering fee to 37 cents per Mcf. Average daily gathering volumes increased 19% to 4,124 million cubic feet per day (MMcf/d) from the year-ago level of 3,460 MMcf/d, setting a company record. This exceeded our estimate of 3,587 MMcf/d. The high-pressure gathering volumes declined 7% to 2,986 MMcf/d. Compression volumes rose 17% to 4,036 MMcf/d compared with 3,447 MMcf/d a year ago, aided by 747 MMcf/d of well pad compression. The figure was above our estimate of 3,578 MMcf/d. Centralized compression volumes fell 5% to 3,289 MMcf/d. Water handling revenues from Antero Resources increased to $78.54 million from $73.77 million in the prior-year quarter. The reported figure was above our estimate of $75.5 million. The segment benefited from a sharp increase in other water handling activity, which includes cost-plus services. Other water handling volumes surged 131% to 136 thousand barrels per day (MBbl/d). Fresh water delivery volumes declined 16% to 82 MBbl/d. The average realized fresh water delivery fee increased 2% to $4.44 per barrel from the year-ago figure of $4.37 per barrel, reflecting annual CPI-based adjustments. Total operating expenses rose to $145.34 million from $119.03 million a year ago. Direct operating expenses increased to $84.53 million from $63.11 million, with water handling accounting for $47.99 million and gathering and processing contributing $36.53 million. Operating income decreased to $181.91 million from $186.44 million. Net interest expense increased 16% to $55.68 million, driven by financing for the HG Energy acquisition. Equity in earnings of unconsolidated affiliates declined to $28.53 million from $30.02 million. Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) increased 2% year over year to $288.78 million. Adjusted free cash flow before dividends was $186.43 million, while adjusted free cash flow after dividends totaled $79.63 million. Capital expenditures were $46.68 million on an accrual basis. The company invested $33 million in gathering and compression and $14 million in water infrastructure. As of June 30, 2026, total debt was $3.59 billion, including $341.90 million outstanding under the bank credit facility. The company had no cash, cash equivalents or restricted cash at quarter-end. In July, Antero Midstream received about $371 million in damages and interest from Veolia. The proceeds, together with revolver borrowings, are being used to redeem $650 million of senior notes due 2028 at par. Management expects leverage to fall below its 3.0-times target, while liquidity remains above $600 million with no near-term maturities. Antero Midstream repurchased 400,000 shares for about $8 million and has roughly $310 million remaining under its buyback authorization. During the quarter, AM began construction on East Side Express, its first intrastate regional pipeline. The bi-directional project is designed to improve dry gas connectivity to long-haul and regional pipelines and support future demand growth in West Virginia. Management said water integration projects remain on track and that it expects higher gathering and water volumes to drive second-half EBITDA growth within the full-year guidance range. The company connected 26 wells to its gathering system and serviced 21 wells with fresh water delivery. Antero Midstream currently carries a Zacks Rank #3 (Hold). Some better-ranked stocks from the energy sector are NOV Inc. NOV, HF Sinclair Corporation DINO and Cactus, Inc. WHD. NOV sports a Zacks Rank #1 (Strong Buy), while DINO and WHD carry a Zacks Rank #2 (Buy) each, at present. You can see the complete list of today’s Zacks Rank #1 stocks here. NOV reported second-quarter 2026 adjusted earnings of 31 cents per share, which beat the Zacks Consensus Estimate of 16 cents per share. As of June 30, 2026, NOV had long-term debt of $1.69 billion, and cash and cash equivalents of $1.16 billion. HF Sinclair reported second-quarter 2026 adjusted earnings of $5.31 per share, which topped the Zacks Consensus Estimate of $4.39 per share. As of June 30, 2026, DINO had total debt of $2.77 billion, and cash and cash equivalents of $2.26 billion. Cactus reported second-quarter 2026 adjusted earnings of 93 cents per share, which surpassed the Zacks Consensus Estimate of 71 cents per share. As of June 30, 2026, WHD had cash and cash equivalents of $365 million. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Antero Midstream Corporation (AM) : Free Stock Analysis Report NOV Inc. (NOV) : Free Stock Analysis Report Cactus, Inc. (WHD) : Free Stock Analysis Report HF Sinclair Corporation (DINO) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Antero Resources Corporation AR reported second-quarter 2026 adjusted earnings of 76 cents per share, beating the Zacks Consensus Estimate of 75 cents. Revenues of $1.6 billion beat the consensus estimate of $1.5 billion by 6.7% and increased from $1.3 billion in the year-ago quarter. The strong quarterly performance was supported by record production, lower cash costs and benefits from the HG Energy acquisition. Net production averaged 4.1 Bcfe/d, up 21% year over year, while adjusted EBITDAX rose 57% to $595 million. Antero Resources Corporation price-consensus-eps-surprise-chart | Antero Resources Corporation Quote Antero Resources delivered record production in the second quarter, with average net output reaching 4.1 Bcfe/d, including 216 MBbl/d of liquids. The figure is in line with our estimate of 4.1 Bcfe/d. Natural gas production averaged 2,847 MMcf/d, while C3+ NGL production averaged 121,132 Bbl/d and C2 NGL production averaged 86,769 Bbl/d. The company placed 26 Marcellus wells to sales during the quarter with an average lateral length of 13,323 feet. The 21 wells that had been online for about 60 days averaged 25 MMcfe/d per well, including 975 Bbl/d of liquids per well assuming 25% ethane recovery. AR saw year-over-year revenue growth from stronger production volumes and contributions from the HG Energy assets. Total revenues increased to $1.6 billion from $1.3 billion in the prior-year quarter, helped by higher natural gas liquids sales, oil sales, and commodity derivative gains. The company’s revenues included $688.5 million from natural gas sales, $587.7 million from natural gas liquids sales and $59.6 million from oil sales. The figures are slightly below our estimates of $705.6 million from natural gas sales, $653.4 million from natural gas liquids sales and $63.1 million, respectively. Commodity derivative fair value gains increased to $160.6 million from $53.4 million a year ago. Antero Resources reported total cash operating costs of $2.38 per Mcfe in the quarter, down $0.29 per Mcfe, or 11%, from the prior-year period. Cash production expenses were $2.22 per Mcfe compared with $2.48 per Mcfe in the second quarter of 2025. The figure is marginally above our estimate of 2.21 per Mcfe. Operating expenses rose to $1.18 billion from $1.09 billion a year ago, reflecting higher gathering, compression, processing and transportation costs, as well as increased depletion, depreciation and amortization. The figure is also above our estimate of $1.14 billion. Operating income, however, improved to $375.5 million from $204.9 million. The metric also beat our estimate of $323.3 million. AR completed strategic acquisitions in July for approximately $315 million within its West Virginia development footprint. The properties add about 125 MMcfe/d of net production, 3,500 net undeveloped acres and 15 net undeveloped locations. The company also continued investing in its resource base during the quarter. Drilling and completion capital expenditure totaled $297 million, while land investment reached $29 million, adding approximately 5,000 net acres and 20 incremental net drilling locations. Antero Resources raised its 2026 production guidance to 4.15-4.2 Bcfe/d, citing strong year-to-date performance and the July acquisitions. Third-quarter production is expected to average 4.25-4.3 Bcfe/d, with fourth-quarter production forecast at 4.4-4.5 Bcfe/d. The company lowered cash production expense guidance to $2.20-$2.30 per Mcfe and adjusted its expected natural gas realized price premium to NYMEX Henry Hub to 5-15 cents per Mcf. C2 NGL realized price premium guidance was increased to $2.50-$3 per barrel. AR generated $438.8 million in net cash from operating activities during the second quarter. The adjusted free cash flow before changes in working capital was $219.8 million compared with $156.3 million in the year-ago period. The company also continued its capital return program, repurchasing 1.1 million shares for approximately $38 million during the quarter at an average weighted price of $34.25 per share. As of the earnings release, Antero Resources had approximately $880 million of remaining capacity under its share repurchase program. Antero Resources’ balance sheet reflected total debt of $2.6 billion as of June 30, 2026, including $1.1 billion outstanding under its term loan and $600 million of senior notes due 2030. Antero Resources currently carries a Zacks Rank #4 (Sell). Some better-ranked stocks from the energy sector are Par Pacific Holdings PARR, Valero Energy VLO and Kinder Morgan Inc. KMI, each carrying a Zacks Rank #2 (Buy) at present. You can see the complete list of today’s Zacks Rank #1 (Strong Buy) stocks here. Par Pacific operates an integrated downstream energy business across the United States, with fuel retail operations in Hawaii, Washington and Idaho, refining operations in Hawaii, Wyoming, Washington and Montana, and a supporting logistics network. Its refineries have a combined crude oil throughput capacity of 219,000 barrels per day and produce gasoline, diesel, jet fuel, marine fuels, asphalt and other petroleum products. Valero Energy is a leading refining player with a robust network of 14 refineries and a combined high-complexity throughput capacity of 3 million barrels per day, which distinguishes it from other independent refiners. Valero’s refineries have a combined Nelson Complexity Index of 11.5, which implies that they can process a wide variety of feedstocks, convert them into higher-value products and shift product yields according to market conditions. Kinder Morgan operates one of North America's largest natural gas infrastructure networks, consisting of approximately 58,600 miles of transmission pipelines, 6,800 miles of gathering systems and 1,300 miles of natural gas liquids pipelines. KMI transports nearly 40% of U.S. natural gas production and controls more than 700 billion cubic feet of storage capacity, representing roughly 15% of the nation's total storage capacity. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Antero Resources Corporation (AR) : Free Stock Analysis Report Valero Energy Corporation (VLO) : Free Stock Analysis Report Kinder Morgan, Inc. (KMI) : Free Stock Analysis Report Par Pacific Holdings, Inc. (PARR) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research